Thank you for standing by. Welcome to the Range Resources 4th 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 incentives, 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. Leit Sando, SVP Investor Relations at Range Resources. Please go ahead, sir.

Thank you, Operator. Good morning, everyone. 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 Skucke, 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 also find our 10 K on ranges website under the investors tab or you can access it using the SEC's Edgar system please note we'll be referencing certain non-gap measures on today's call our press release provides reconciliations of these to the most comparable gap 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 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 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 frack stages. Completion efficiencies for the fourth quarter approached 10 frack stages per day per crew, pushing our 2025 totals to nearly 3,800 total stages and setting a new yearly frack 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 continue 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 percent year on year and 24 percent 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 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. 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 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, or we can maintain a similar operational cadence with $650 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 frat crew while picking up a spot crew for the second and third quarter to harvest some of our duck inventory. This drives an all-in capital budget of $650 to $700 million, which consists of the following. Approximately $500 million of maintenance DNC capital. An incremental $120 to $140 million of DNC growth capital that is primarily allocated to a second completions crew. $15 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 links, 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 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 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 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 strengths 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. It provides 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 three times 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 ranges 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 US 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 multi-year 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 multi-year plan communicated just one year ago is on track and generating the results you've come to expect from range years of discipline 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. And we have more opportunity in front of us more than ever. With that, let's open the line

for questions. Thank you, Mr. Dagnon. The question and answer session will now begin. If you would like to ask a question, please indicate by pressing the star key, then 1-1. If you are on a speaker phone, please pick up your handset before asking your question. If you would like to withdraw your question, you may do so by pressing star 1-1 again. The first question is from Scott Hanold of RBC Capital Markets. Yolanus Madelman. 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 um what's needed to get there in terms of infrastructure ads and and just more broadly on on your typical cadence um you know do would you guys ever you know look to you know effectively you know drive higher production in in sort of the first quarter um versus say the mid-year given that you know you you do see much more premium pricing especially in Appalachia during the

winner. 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 turn to 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 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 then 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 a i'll just say at a high level of utilization at the meteor point we've got some processing that comes online that's around 300 million a day of capacity uh processing capacity that will go into service then on the back end of the year that's where you'll see the ramp really takes 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 frack crew for Q2 and Q3, and then kind of carrying that momentum into 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, you know, obviously you all signed 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 what is the benchmark we should be thinking about and how much of an uplift and and you know do you see a lot more of these opportunities um you know like this uh and and you know what what do you kind of see that um you know maybe through the next year or two yeah 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 had between it's just range it 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 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 what's out there that's in addition to this and 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 so 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 and then 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 a end user that could utilize gas that's right out of our producing assets that the facility would be able to 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 NGOs 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 a significant backstop to those future

needs. Appreciate all the color. Thanks again. Thank you, Scott. Thank you. And the next question

is from Jen Ennis of Texas Capital. Your line is now open. Good morning, and 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 per 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.

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. And when you think about how lean the operation is with one and a half drilling rigs or one and a half frack 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 you know clearly you know we feel like commodity pricing back to the cash flow statement is in place both on the NatGas 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 transfers 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, 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 and 28 and beyond with something that's in the neighborhood of, you know, sub 600 million dollars in CapEx or think about it differently, less than 60 cents per MCFE or we can continue to have a thoughtful wedge of growth depending upon future demand and deals that are worked on 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. 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've come to expect from us.

I appreciate all that, Caller. 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 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? 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. So it's what the market-indicated levels are at the myriad of sales points we have across the U.S. So 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 Ranger'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. 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 it's sometimes a little bit less. I would also layer into that something Dennis mentioned a moment ago, that we can alter ethan extraction levels. and increase 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 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 sake.

Makes sense. I appreciate the time. Thank you.

Thank you. The next question is from Douglas Gates of Wolf Research. Yolanda is now open.

Thank you. Good morning, everyone. Dennis, I wonder if I could ask you about the cadence of the duck capacity. I mean, you're giving 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 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, 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 duct 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 so we feel like the timing is set up complementary to improving pricing as you start to get into the end of 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 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 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 signals. 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 assets. So 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 tills 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'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 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 what I mean. It's in terms of, you know, you're selling into the strength of the market. I was 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 break-even 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 bid week 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 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. And 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. But 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. 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-turned-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 bid week 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 bid week 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, meaning new well turning lines may not always be accounted for in that bid week 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, you know, best returns.

Appreciate it, guys. Thanks so much, Dennis.

Thanks, Doug.

Thank you. The next question is from Jacob Roberts of TP8s and Company. Your line is now open.

Good morning. Good morning, Jake. Dennis, I appreciate the color on kind of the 2027, 2027 plus timeframe. I was wondering if you could opine on where you view service costs over that same time And really what I'm getting at is their willingness to convert some of that duck backlog into 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? Yeah, good morning, Jake. I think when I start to think about the upcoming 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-mixed, how we would think about uh you know our liquids contribution at what time of year of course so 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 in the prepared remarks but we we've kind of seen what i would call is uh you know low to mid single digit kind of relief and service costs as we're kind of planning for 2026 some of the costs are going to be fairly secured with multi-year 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 and 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 frat crews and 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. So 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 we're just kind of reaching a 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 those savings to be an opportunity to think about either not spending all of our capital in a given year thus the 50 million dollar 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 thank

you that's super helpful i did want to circle back to the supply agreement uh you guys signed which you know i agree is very positive to see i'm curious um if the 75 million to this specific facility is a starting point for this facility is there the potential to grow those volumes and maybe if not is this specific counterparty someone you could view as um someone you you pursue additional projects with over the coming years yeah jake i think the 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 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. 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 multi-year 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. Thanks. I appreciate the time. Thanks, Jake.

Thank you. The next question is from Philip Jungberg of BMO Capital Markets. The online

is now open. Thanks. Good morning. Coming back to the question around growth beyond 2027, and 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 take in basin

pricing yeah good morning phil when we 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 So I know looking at this year and prior years, it's tended to fluctuate somewhere between probably 20 to 30, 35 percent 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 one to two pad sites, and incrementally utilized existing infrastructure and incrementally added some nice production to the profile. So we do have, I'll just say, quote, 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, you know, the Harman Creek 3 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 de-bottlenecking that is underway with one of our midstream partners, MPLX, at the Majorsville facility. So, quote, we're ringing out more with the same infrastructure to look for incremental capacities there. And it 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 de-bottlenecking 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 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. And then you also had a new macro slide on global NAFTA 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 that Petkin 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?

Yeah, the NGL macro has been clearly a hot topic as we think about the back half of 2025. And so I'm going to attack this from a couple of different angles, but clearly stock levels have been elevated through 2025, five, both on the propane and also on the ethane side. And, you know, 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, 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. And then 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 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 two, 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. So 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 bounce of the end of the year with some of the same providers that commissioned infrastructure last year. And then on top of it, you've got, I'll just use Ineos and Sinepec 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, re-normalized 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 I would 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 this gives you the color you're looking for but it's a 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, Bill. Thank you. The next

question is from Kevin McCurdy of Pickering Energy Partners. Helen 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 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 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 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. So we didn't really build it around the premise of new demand that might come. Instead, it was taking on the energy transfers 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'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. 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 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 could consider more in-basin or regional that allows us to think about that next wedge 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 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 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? Yeah, 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 five cents better year-over-year versus the starting points 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 of a 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 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 Mike Polchella with Stephens.

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 proved reserves, which is less than a five 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 given a formula quite intentionally. We think if you're formulaic and programmatic, you can end up with just a pro-cyclical and buy-high type program. So we think the flexibility of being opportunistic generates a much better return in buying when you see pullbacks and, 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 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, But for perspective, you know, 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 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 seven, 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. 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 wringing 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 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. 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.

Appreciate it. Thank you.

Thank you. And we are nearing the end of today's conference. We will go to the lineup 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. 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.

Yeah, I think the, first of all, thanks for joining us, Neil. When I think about that week, or 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. 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, you know, 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-zero 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. So, the 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 looks back 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 the summit in the Northeast I'm sure they're they're feeling the effects and comfort of having natural gas flow into generating power for their homes these days so a 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 is more of upside opportunity through the balance of that upcoming month but But, yeah, we'd expect more volatility going forward, and that multidisciplinary team will get leaned on 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. February looks to be one, if not perhaps the best free cash flow and realizations month in perhaps company history.

That's a great caller. 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 send 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.