Hello. Welcome to the Range Resources First Quarter 2026 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 or 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. Leif Sandow, Senior Vice President, Investor Relations at RANGE Resources. Sir, please go ahead.

Thank you, Operator. Good morning, everyone, and thank you for joining RANGE's first quarter 2026 earnings call. The speakers on today's call 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 will also find our 10Q 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 hedging details by month, realized pricing by product, along with calculations of EBITDAX, cash margins, and other non-GAAP measures. With that, let me turn the call over to Dennis. Thanks, Laith, and thanks to all of

you for joining the call today. Ranges off to a great start in 2026. We continued steady operational progress in the first quarter towards our multi-year plan that was launched over a year ago. The first quarter also saw strong realized pricing for range as winter weather drove natural gas prices higher while international NGL prices spiked in March following supply disruptions in the Middle East. Range's strategic marketing portfolio paired with safe steady operations allowed range to capture this opportunity leading to free cash flow for the quarter of approximately $400 million. This free cash flow supported an increased dividend, additional share repurchases, and the strongest balance sheet in company history. Looking at the operational results for the first quarter, production came in at 2.2 BCF equivalent per day. Range expects production to increase slightly in the second quarter before jumping meaningfully higher at the midpoint of the year as gas processing and related infrastructure is put into service. This will push production to 2.5 BCF equivalent per day by year-end, all in line with our previous guidance. Capital for the quarter came in at $130 million as range was running one rig and one completions crew. Completion spending will step up in the second quarter as we add a spot completion crew to begin working through the drilled uncompleted inventory we've built up over the past 24 months as a result second and third quarter are expected to be the high point for capital with this operational cadence placing us squarely within our previous stated capital guidance during the first quarter our single horizontal rig drilled approximately 143 000 lateral feet annualized this is well over half a million lateral feet by a single drilling rig. The team also had eight days where they drilled over a mile in the horizontal, with two of those 24-hour periods exceeding 9,400 feet. This level of operational efficiency advancement continues to reflect the team's hard work and drive to deliver on peer-leading drilling and completion costs per foot. For completions, Range's electric fracturing fleet set a program record by completing a total of 874 stages during the quarter annualized this is approaching over 700 000 lateral feet being completed in a year by a single crew on multiple days the team reached a record level of 17 stages per day and despite challenging weather conditions the team achieved a new record during winter operations averaging over 10 stages per day achieving this level of efficiency takes critical coordination between completions and water operations as we delivered up to 120,000 barrels of water per day for those wells. This is quite an accomplishment for our team. It is a key contributor to Rage's peer-leading capital efficiency. This combined level of efficiency and drilling and completions continues to support our operational plans through 2027 and beyond as we maintain a resilient duck inventory for future optionality on capital and production range's winter operations program also had a very successful first quarter and can and kept production volumes flowing through the harsh winter conditions ushered in by winter storm firm production facility design enhancements strategic staging of backup power and working in concert with our gathering partners are just a few aspects of the program that the team continued to focus on all of this resulted in the team maintaining strong field runtime and supported record-free cash flow for the month of february hats off to the team for their dedication to safely keeping our production flowing before moving on to marketing i'll briefly touch on service costs we anticipate the cost of our electric hydraulic fracturing fleet to remain unchanged given a long-term contract that was signed earlier this year. Additionally, we have day rates locked in place for our horizontal activity for 2026. Steel market prices appear to be moving due to geopolitical events, but range is mostly insulated from these increases due to our pre-purchase or production casein in late 2025. Fuel pricing will obviously be elevated due to diesel prices moving higher, But we expect no changes to our capital plans given the efficiency gains and contractual certainty around the rest of our program. And as mentioned already, we believe RANGE's low capital intensity provides an additional level of stability versus our other producers. Shifting over to marketing, the current disruption of global energy supply has reshaped markets since the beginning of March. We believe America's ability to provide reliable, affordable supply to meet global demand has been highlighted, now more than ever. The ongoing build-out of LNG and NGL export capacity positions the U.S. to meet an increasing percentage of the world's energy needs. At the same time, the industry is continuing to supply energy for Americans during critical periods of peak demand, as demonstrated this past quarter. given the clear call from the rest of the world for more U.S. energy. We expect exports for LNG, ethane, propane, and butane to increase further throughout 2026, above already record levels. This should result in improved U.S. storage levels, particularly on a days of supply basis, across all of these products, providing an expected tailwind to absolute pricing levels. For natural gas, LNG exports are now approaching 20 BCF per day, up 20% versus last year, and further supported by the recent startup of the Golden Pass LNG terminal. For ethane, waterborne exports were estimated at 665,000 barrels per day for the first quarter, up over 47% year-on-year, supported by new export terminal capacity that went into service during the second half of 2025. And lastly, for propane and butane, exports are up 5% year-on-year and are expected to increase significantly throughout 2026 as additional U.S. export capacity comes online. We expect these growing exports will tighten storage balances and improve fundamentals across the various products range sales, looking at the quarter results for marketing and starting with natural gas. Strong winter weather provided a window of improved natural gas pricing from a significant spike in demand to feed power plants and to heat homes in late January. Range's marketing team, in coordination with operations and planning, was able to sell nearly all of our natural gas during bid week in late January when Henry Hub NYMEX settled over $7 for MNBTU, supporting strong first quarter differentials. In addition, the marketing team further enhanced revenue and margins by optimizing ethane extraction timing with commodity price movements. Combined, this resulted in Range's best quarterly natural gas differential in over a decade, an 18 cents premium to Henry Hub for the first quarter. Turning to liquids, range of strategic access to international markets for ethane, propane, and butane generated a significant uplift in NGL pricing in the month of March as international prices decoupled from U.S. markets. When combined with strong Northeast NGL pricing during January and February, along with the ethane optimization I just mentioned, range realized an NGL premium for the first quarter of $4.41 per barrel above the Mont Bellevue Index, the largest NGL premium in company history. As a result of this strong start to the year, we have improved our full-year 2026 NGL differential guidance to a premium of $1.25 to $2.50 per barrel over Mont-Bellevue. The low end reflects the potential for improved Mont-Bellevue pricing due to strong U.S. exports. All the high end reflects current strip pricing in the various domestic and international markets that our contracts are tied to. In both cases, price realizations are expected to be substantially higher than our initial guidance communicated this past February. We are truly excited about how the company is positioned today, with financial and operational flexibility that allows us to efficiently align production growth with known demand, 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. With the first quarter of 2026 successfully completed, RANGE continues steady progress along the multi-year disciplined growth plan we announced last year designed to capture market value enabled by the depth and quality of RANGE's portfolio. When we announced the three-year plan at the beginning of 2025, we described the integrated approach from wellhead to customer that underpinned modest production growth to fulfill increasing natural gas demand. That plan is unfolding as expected with infrastructure slated to come online mid-year, enabling the completion and turn-in line of lateral footage generated in recent quarters. We're using the power of Range's high-quality and long-duration inventory to underwrite targeted transportation and midstream contracts that enable Range to tie into premium markets with visible demand growth. This plan builds on RANGE's operational and financial strengths and illustrates the positive outcome of an evaluation we continuously perform. This evaluation is really a simple question. How do we maximize long-term free cash flow netbacks on a per share basis? As a key metric, durable free cash flow per share drives how we evaluate sales contracts, drilling activity, infrastructure, share repurchases, essentially all major capital allocation decisions. The results of the first quarter highlight not only Range's operational strengths, but the quality marketing strategies implemented over many years to access premium markets. During the quarter, Range generated 545 million dollars in cash flow from operations before working capital, driven by realized natural gas price of $5.18 per MCF before hedging and $26.62 per barrel of NGLs. Participating in rising prices requires thoughtful marketing, timely execution, an experienced, nimble team, and a transportation portfolio that reaches premium points. These elements of success apply to both natural gas and natural gas liquids. The range marketing and operations teams executed superbly on our natural gas portfolio to capture strong January and February prices while delivering reliable supply to our customers. This was also true of NGLs, where roughly 80% of our propane and butane are exported out of the East Coast and a significant portion is sold under medium-term contracts with floating links to European and Asian LPG indices, a linkage driven by our long-term positive view of those markets. With strong cash flow and a capital reinvestment rate of less than 30% in the first quarter, free cash flow was approximately $400 million. That free cash flow funded our growing dividend totaling $24 million in Q1 and modest sherry purchases totaling $27 million. The end result was net debt of $834 million, or half a turn of leverage, an investment-grade style balance sheet comparable to our strongest peers. Turning to unit costs for a moment, we have a permanent focus on driving down unit costs with the objective of maintaining and enhancing margins. Over the years, we've talked about the right-way risk construct embedded within our gathering processing and transportation expense line item. The cost of Range's infrastructure portfolio has links to prices for natural gas via electricity and pipeline fuel costs, and natural gas liquids via a percentage of proceeds processing costs. So, the costs are aligned with sales, such that as we experience some increase in electricity or processing costs, it's because we are realizing higher prices and expanded margins. Critically, in periods of commodity price weakness, we also experience the proper linkage where we incur lower expenses when realized prices decrease, enhancing range's resilience through cycles. So while the GPNT per unit increased for the quarter, it was on the back of strong pricing as range realized its highest premium for natural gas in over a decade, and the highest NGL premium in company history. Together, this translated to improved margin per unit of production of $2.77 per MCFA, up 38% from the same quarter last year, reflecting the strategic right-way risk embedded in our contracts. Looking ahead at the balance of 2026 and beyond, we will continue to critically evaluate investment opportunities in ranges, business and shareholder returns, with an unwavering focus on sustaining and further enhancing Range's core objective, durable and growing free cash flow per share. To achieve that objective, we seek to enhance our low full-cycle cost structure, low reinvestment rate, and premier marketing portfolio, all with a focus on maximizing durable margins. Here's a key message we repeat today. We can thoughtfully grow Range's business alongside increasing 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. We see lasting tailwinds in our business as the U.S. and global natural gas markets continue to integrate with commissioning of LNG facilities, while at the same time domestic natural gas demand grows substantially, primarily from the need for additional electric generation, and the world is again reminded of the critical importance of reliable energy supply. We believe RANGE's long-life inventory stands to provide enormous option value by serving an integral role as a dependable long-term energy provider. Our durable free cash flow, evidenced through cycles, Positions range to consistently deliver value to shareholders.

Dennis, back to you. Thanks, Mark. Today's results continue to demonstrate range's strong operational performance against our multi-year plan, consistent pre-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 is on track, and years of disciplined planning have placed us in the strongest position in our company history, having de-risked a high-quality inventory measured in decades and translated that into a business capable of generating significant free cash flow through cycles. With that, let's open the line for questions.

Thank you, Ms. Stegner. The question and answer session will now begin. If you would like to ask the question, please indicate by pressing star, then 1-1. That's star 1-1 to ask the question. If you are on a speakerphone, please pick up your handset before asking your question. If you would like to withdraw your question, you may do so by pressing star 1-1 again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Jake Roberts with Tudor Pickering Holt & Company. Your line is open.

Good morning.

Good morning, Jake.

Mark, you mentioned the linked floating contracts for the European and Asian markets on the propane and butane. Can you frame on a percentage or volume basis which each market received in Q1 and how you see those amounts moving into Q2 and beyond? And maybe if I could

ask if you could disclose those contract terms. To answer the last question first, no. No. There is some competition in this business, as you'd expect. So our marketing team has done an outstanding job over the years building relationships, managing exports out of the East Coast, cargo by cargo. So those relationships, the understanding of timing of, you know, the fact that what you're seeing on a screen may not be what is on the physical side of things when these cargo loadings are planned a month, two months, three months in advance. So I guess to take a step back, as you know, roughly 80% of our propane is exported out of the East Coast. Of that, I would say the majority, well over half, is linked to what I'll term as a medium-term contract that has ties to ARA and FEI. So we export out of the East Coast and therefore with those molecules on the water can benefit from international demand and the need for those molecules, given the dependence on international head chem, heating, consumer demand on U.S. molecules on the water. So, terms of those deals, no, we can't go into, we don't wish to go into specifics of them, but just that they are very strong netbacks as evidenced by the $4 plus

corporate average premium to Montbelly. Yeah, I appreciate that. You know I had to try. Dennis, I want to touch on Fort Cherry. Last call, you framed it as making reasonable progress towards finding an end user. I was hoping for an update there. And maybe for Mark, could you opine on how you're thinking about the marketing strategy? Given the, I see kind of more clear line of sight to LNG type of opportunities, given the ongoing demand versus these power center or data center projects that seem to require a bit more negotiation to get across the finish line.

You bet, Jake. i'll i'll go ahead and try and unpack this here you know from from the data center perspective we're still seeing what i would say is regular uh and and really quite honestly a good cadence or a dialogue around that particular fort terry location and that that opportunity but in addition if i were to put some context around it there's probably a little over a dozen projects that we're having a similar level of dialogue around and i think the announcement that we made just as a kind of a reminder for everyone, the announcement we made this past quarter earnings process for the $75 million a day of supply that's going to go into a power link type structure into the Midwest, you know, transport that we have. I think that's a sign of something that was a good indication of what was going on in the background while we were still working on this Fort Cherry type opportunity. So we think there's a lot more to come. We also point to things like the next Terra announcement. Clearly, that PowerGen facility is going to go into the southwest PA, Appalachia region. We think there's a real opportunity for a range to participate in a facility like that as details continue to get, I'll just say, sussed out on location and then who could, of course, have connective pipelines to get into that facility. So, we think there's a lot of opportunity for us to continue to see this expand. And I would even say, Lastly, we've even seen some dialogue with the same counterparty that we made the announcement around this past quarter for some potential additional supply. So that's positive on two fronts for us. One, the ability to potentially, and I'll underline potentially, expand our volumes into that future infrastructure. But it also provides another confidence shot in the arm, if you will, that this is serious, that these are moving forward. and it's not just a $75 million a day commitment, but you can actually see the serious commitment around putting shovels in the ground and getting this infrastructure built. So a lot of activity in this space by our marketing team to try and find good opportunities that would align with Range. We know that these are multi-decade financial commitments and decisions by these end users and counterparties, and we think it's perfect alignment with a company like Range that's got a long-term assurity of supply and inventory like we do. So we'll certainly provide updates as we see more come forward and look forward to doing so.

Thanks, guys. I appreciate the time.

Our next question comes from the line of Gabe Dowd with Truist. Your line is open.

Hey, thanks. Morning, guys. If we could maybe start with a production trajectory on the back of Harmon Creek entering service. I guess you noted mid-year. Is that June or July? and just trying to think through any commissioning or ramp-up period post that. And beyond this year and, I guess, even 27, what are maybe some updated thoughts around that 2.6 BCFE a day? What will ultimately govern the decision to either toggle that up or down or keep it flat?

Yeah, good morning, Gabe. As we start to think about, you know, really the months ahead here in 2026, you know, our production character should look really similar to what you've seen in others over the last few years under a maintenance to maintenance plus type program. So actually looking at Q1 production, it's almost an ideal overlay character-wise to what we had a year ago. Several of the turning lines that occurred toward the back end of Q1 will now start to pack the system of available infrastructure that we have. And what you'll see is then our ability to step into this commissioning of infrastructure that's going to occur toward the end of Q2 and in the beginning of Q1. So we have some gathering and compression that's going to go into service toward the end of Q2, and the processing will be right there at the mid-year point, which, again, we think with this loop gathering system that we produce into, it's got a lot of optionality as we think about the efficiency around moving molecules around the field. Back half of the year is where we really start to see the increase in production take off. And so think about it being kind of fairly ratable across Q3 and Q4 as we start to end the year at 2.5 BCF equivalent per day. The second completion crew that we mentioned in our prepared remarks that will start in Q2 or has started actually here in the second quarter, the activity of the duck inventory that it will start to turn into sales through the next six months is really going to be I'll just say the tailwind that generates that production ramp in the back half of the year it's going to utilize that processing and gathering infrastructure addition and then it's going to also provide some really significant momentum as we then work toward that 2.6 bcf a day type number in 2027 you know kind of answer your and everything's on track from an infrastructure standpoint for this year. And when we think about, you know, what's beyond 2027, I think we have to go back to maybe how we started the first question here today. And that is, you know, what is going to start with a conversation around what kind of demand and opportunity further materializes. If there is an opportunity for range to participate in additional growth, we think there's a really strong opportunity for that to take shape, but it's got to take shape. And so once that occurs, we think there's a really capital efficient and thoughtful way for us to add another wedge of growth and doing so with a very similar capital investment that you've seen us commit to over the past 24 months. So we really think it has an opportunity to be very steady as she goes beyond 2027. If not, we have the ability to pull capital down and it could be somewhere in the 570 to $600 million type range where we can hold that 2.6 b equivalent type level flat until we see again that next step up with demand that materializes so we're really optimistic about the future especially as you get closer to the end of the decade but we'll be able to have another thoughtful wedge of growth as we see

more demand take shape got it okay that's really clear thanks dennis um and then maybe just my second question back to the lpg side and appreciate all the prepared remarks and the the answer to the earlier question, but curious if you could maybe put a little bit of a finer point on our updated thoughts on the macro, given all the domestic and international moving pieces and even maybe elevated shipping costs. Natchez River comes on around mid-year, so U.S. propane exports grow to, you know, 2 million barrels a day plus. Is that clear the inventory glut in your mind domestically? And then from an international standpoint, thoughts on China, of PDH run rates and maybe any other puts and takes that could ultimately impact the premium

that you expect over Bellevue. Thanks, guys. You betcha. Thanks again, Gabe. So I'll kind of start here on the macro side by really saying, look, exports, and I think you pointed to it, have really remained strong. If you look at the dock capacity expansion that took place and went into service last year, I mean, that was incredibly helpful when you think about starting to chip away at uh the current stock levels look i think it's commonly known that the stock levels are are elevated we're talking somewhere roughly 70 percent above where we've seen historical averages but we added 150 000 barrels a day in export capacity last year that's been at a high end of utilization but i think one of the more i'll just say today's stories is flex capacity that's gone into service out of the Gulf, that adds another 360,000 barrels a day of LPG export capacity. I think that was originally earmarked for more ethane service, but it's now been put into LPG service, and the first vessels have actually left the dock. So we find that really encouraging when you start to think about pulling down stock levels over the balance of the year, and then, of course, there's another 300,000 barrels of additional capacity that's going to go into service on the export side by late 2026. So you're talking about meaningful impacts when you think about the ability to pull down stock levels. Of course, from a demand perspective, when we think a little bit more broader terms over the next 24 months, there's another half a million barrels of demand that's going to go into service on, as you pointed out, the PDH type infrastructure. We think that all kind of goes hand in glove as you think about the ability for us to get more barrels on a waterborne export as an industry and then also meeting growing demand that's going into service over the next 24 months look the dynamics of late have been very unique and i think it's it's uh as we're all trying to navigate these particular moments you know the reality is is the business has actually been as resilient as we've seen as as really demonstrated by the quarterly numbers that we just communicated but as we think about the future exports we expect to remain strong. There's going to be a call and a need for future LPG barrels out of the U.S., which we think plays really well to our ability to get, as we heard Mark talk about, 80% of our LPG on a waterborne export out of Marcus Hook. And also, I would be remiss not to point out the Rapano terminal that will go into service in January of 2027. That's going to allow us to have more access to waterborne exports. So, all that just said, we've got demand growing. Run rates show to be improving, and we would expect in the longer term stock levels to get re-equilibrated over the balance of the year.

Fantastic. Great answer. Thanks, Dennis. Thanks, everyone.

Thank you. Please stand by for our next question. Our next question comes from the line of Neometta with Goldman Sachs & Company. Your line is

open. Yeah, great. Thanks, team. I want to stay on the NGL question. The $4.41 differential that you achieved in the first quarter, I think, was robust by any modeling standpoint. And just, you know, can you spend more time talking about what drove the magnitude of that bead? And then I saw you guys came out in the guide now talking about a $24 sort of mid-cycle view of NGLs. We've been realizing above that for the last couple of years. Do you think there's an upward bias relative to that number?

Yeah, good question. This is Alan. I manage the marketing group. so I'll take a stab at answering your question there for when we look back at realization during the first quarter on the NGL side really three main drivers so we'll go back to January winter storm fern we had high gas prices that allowed us to actually realize better gas returns we actually pulled back on epine recoveries so that we can do better on gas. But flipping back to NGLs with your question, it also allowed us to realize better numbers on our ethane because we do have roughly a third of our contracts on ethane that are priced off of natural gas. So that was one item that drove the premium. Second item, again, along with the weather and the cold, the demand for LPG in the northeast domestically was strong we were able to realize good prices with sales within the US during January and February and then the third item the one that I think most people are focusing on is the international export that really came into play actually roughly a week or two before the before the events in Iran with a terminal that went down in Saudi Arabia and that spiked the international prices in which then spiked better returns at the dock for us so you had all those three things together it was it was a good quarter things aligned very well we were positioned with flexibility so that we could move from domestic markets to international markets and capture the best overall that back for range. When we look forward, yeah, we're going to be a little bit conservative in our view, but you have to remember there's seasonality in that premium, and when you get into shoulder months and even summer months, sometimes, you know, just from a pure seasonal perspective, you don't do quite as well. Also, if you look at where prices went, let's say mid-March compared to where they are today on average if you look at you know let's say international propane mid-march it was up call it 80 percent relative to pre-crisis levels that is now somewhere around you know call it plus 30 or plus 40 percent relative to pre-crisis levels still very attractive but not quite what we were seeing in the middle of March and we would expect that you know going forward, even if there is a solution, let's say, in the straight-over moves in the next couple of weeks, it's still going to take months to get flows back to normal, and there's millions of barrels worth of inventory that have been consumed internationally. So with that, we are expecting good returns through the rest of the year on the export netbacks.

That's great. Staying on the macro, just natural gas, we share your 375 mid-cycle view, but one of the pushbacks we get often is the weakness in Permian, specifically Waha, now trading six under zero, right? So the question is, as those molecules move down to the Gulf Coast, what could that mean ultimately for the whole, you know, North American pricing system? So just how are you guys thinking about that, you know, the Permian gas risk, the associated gas supply risk, and how that could put a depressing impact on price? Yeah, Neil, I'll jump in here. You know, I think when you

start to think about the Permian gas dynamics I don't think this is a place that we haven't seen I'll just say the character of this play out over the past now you know several years but when I think about what's going on really recount hasn't changed appreciably since the beginning of the year if you were just kind of look at those dynamics so you know stepping in with additional rig activity to create I'll just say a significant amount of growth really hasn't really shown up yet clearly there's there's been an increase in completion crews. I think roughly, you know, that number is up across the board, probably around 12 to 15 in magnitude. But that's also kind of similar in character to what you see when you look at the fall off at the end of a prior year, and then to kind of start off at the beginning of this year. But it's still below pre-year-over-year type levels, you know, from a standpoint of activity. Then, of course, I think what that means is you're seeing a bit of a duck draw. Duck inventory is down across the lower 48 by about 20 percent so when we think about the nat gas macro and you start to cobble together all of those fun facts i think our view is there will be some gas growth out of out of the permian but when you look at you know clearly we're at 20 bcf a day now from an lng perspective that's pretty encouraging you're seeing meaningful commissioning gas go through train one at golden pass that's been long awaited and now encouraging as well And so we kind of look at it as, you know, where production levels are today and the dynamics, I don't think quite reflect where the front month pricing really should be. You get to the end of the injection season, we kind of view this as being more of a 3.8 to maybe 3.9 TCF storage level. That's where we've been the last couple of years, and then couple that with all of the demand that's taking shape right in front of us. You're talking about being on a days of supply basis about 37 days. That's about five days below the five-year average. So, again, what we really think that sets up is more volatility, which we've now seen occur over the past couple of years. And when those moments happen, like we just saw over the past quarter, you can expect range to really have an opportunity to capture the kind of cash flow that you heard Mark walk through this morning.

Awesome. Thank you.

Our next question comes from the line of Paul Diamond with Citi. Your line is open. I'd like to see if you're on mute, Paul.

Oh, sorry. Blanked out there for a second. Good morning. Thanks for taking the call. I just wanted to touch on your OPEX and numbers of touch. It's historically been that every dollar move in NGL is about a cent in GP&T, and then about two to three cents per dollar move in the gas side. Does that hold in current market dislocations? I mean, is the right way to think about that as linear, or should there be some, I don't know, parabolic effect given the volatility?

you were just talking about? Good morning, Paul. I think as a rule of thumb, those are probably good estimates to use. Historically, as NGL prices have moved around, we've talked about fluctuations in GP&T. We've really focused on the NGL side because that's where you've seen the greater volatility. As we've already talked about, as all of us are studying, greater volatility on the gas side, particularly with the winter weather. In the first quarter, when we saw 469 in January, gas, $7.46 in February back down to March of $2.97, you've got a situation that made it more apparent what costs the industry as a whole carries as it relates to cost of electricity and fuel for transportation of gas through interstate pipelines. So if you want to say two to maybe three cents per dollar on the gas side, that's a reasonable ballpark estimate. It still holds for range specifically. A dollar move per barrel of NGLs is about a penny in GP&T. I think the key point here is that, as I mentioned in the prepared remarks earlier, it's that right-way risk scenario where the margins are expanding. So if that line item goes up, it's because we are realizing higher prices and expanded margins. So I wouldn't say it's parabolic in terms of the cost line item. But if you're thinking about the two, you're going to get a wider spread because there's a fixed component in the cost structure as well. So the margins do expand. And of course, they shrink in commodity price down cycles as well. So it's a right way to risk. So hopefully that answers your question. But we like this structure a great deal because it gives us flexibility, as Alan spoke to, in the portfolio. It builds that portfolio and participation and access to key markets with a structure that allows us to capture enhanced margins when we see these points of volatility and opportunity. Understood. Makes perfect sense.

And just talking a bit more about the, as you guys bring down the ducks part of the growth prospects, I guess how much, what level of reactivity in the production split do we expect to see? Do current conditions shift this? Any, like, kind of leading towards sort of more, you know, wet versus dry gas, or is it all pretty much set for the, you know, coming quarters?

Yeah, Paul, good question. I think as you think about the duct inventory that's been built over the last 24 months and what you would expect to see going forward, maybe two things I'll share this morning. One, really the composition and makeup of the activity should look really similar to what you've seen from our program over the last few years where again approximately you could expect to see some combination of you know 70% maybe 65 on the liquids activity and then the remaining more on the dry gas side and that's for varying reasons but you know clearly utilization of gathering systems that we have in place keeping our costs at a low level but also those are good returns in the dry side as well for when you look at the comparable across our asset base but with the infrastructure that's going into service at the mid year point it's focused on the liquid side so our activity of turn in lines and completions will be more more heavily focused on the liquids rich activity thus feeding not only the processing capacity and gathering that's going into service but also that Rapano terminal terminal capacity that I mentioned a little bit earlier that will go into service roughly around the first of the year. So think along the lines of our duct inventory being more weighted heavily toward the liquids-rich activity, much like you've seen over the last few years. And then the last piece that I'll share with you is, you know, look, we've got around 500,000 lateral feet that we've built up over the last couple of years. And what you would expect to see with a consistent activity from our base uh electric hydraulic fracturing crew but also the spot activity that we'll have over like the next six months in this year and the activity that we'll have next year will allow us to rapidly utilize around 400 000 lateral feet uh over the balance of the next 18 to 24 months and then we'll reevaluate what's the right plan for beyond 2027. got it appreciate all the clarity

All right. Thanks, Paul.

Please stand by for our next question. Our next question comes from the line of Leo Mariani with Roth. Your line is open.

Hey, guys. I wanted to see if you could be a little bit more specific on the kind of the change that you expect on production into 2Q as well as CapEx into 2Q. I've heard in your prepared comments it sounds like production is only up slightly, then you get a big jump in 3Q. but anything you do to quantify, and it sounds like CapEx will also be up a decent amount here

in 2Q. Yeah, good morning, Leo. So, I think from an activity standpoint, you know, if you look back on Q1, we had one rig and one frat crew. You know, ultimately, that was $139 million in capital spending. So, a way of thinking about it for maybe a little bit more color, you know, roughly the completion side is going to be it's a two-third, one-third roughly split. So, completions is roughly two-thirds of the equation so when you ratio that and add a second completion crew that's how I would think about a step up for the second quarter efficiencies always play a part in that so I would just say you know think about what you've seen you know also from our efficiency standpoint the ability to of course move water and efficient manner all of those things returning to pad sites allow us to be let's just say on the lower end of sometimes what expectations could look like and we're excited about that capture so that's how would think about capital for the second and to some degree the third quarter look the completions team has really hit a home run with some of the stages per day that they've accomplished during some pretty tough winter weather and they're very well may also be an opportunity for us to not need a second crew as much as you would expect but the kind of 17 stages per day type efficiency levels that the team's been able to capture so but yeah second quarter third quarter we'll have that second completion crew and still be the one drilling rig from a production standpoint you know i would expect to see us kind of take an uptick uh you know that basically will be more stronger toward the very tail end of the quarter and so as you think about that back end of the year so think about it kind of ranging somewhere from a ramp of of roughly 2.3 bcf equivalent per day toward the mid-year point that gets us up to 2.5 by the time we get to the end of the year.

Okay, appreciate that. And then just on the financial side, do you guys expect any impact on cash taxes this year or next from kind of higher liquids pricing here? And your buyback program was a little bit more limited in 1Q. Should we expect that to maybe step up in subsequent quarters throughout the year, given how good shape the balance sheet is in?

Yeah, Leo, I'll take that. on the cash taxes, I think I would look towards and still anticipate 2028 is probably the first full cash tax paying type year as we work through new tax laws and ranges accumulated in OL that gains and profits over the next couple of years will be able to utilize. So I would still think single digit type, low single digit type cash flow or cash taxes for 26 and 27. As we think about shareholder returns, our model, our goals, our objectives are still the same. We think there's tremendous value in buying back in range of shares. Modest growth as the market calls for it is compounded where single-digit growth becomes double-digit cash flow per share growth quite easily with the Shared Purchase Program. And you can see that we're opportunistic and very targeted in how we buy back the shares with repurchases in the first quarter, averaging less than $34 per share repurchase price. Now, in the first quarter, the reality is you are limited on the number of days we can be in the market because as you prepare the financial statements, you are blacked out. So there is that reality of exercising and running an opportunistic program. But where that leaves us today with $834 million in debt and a refreshed share repurchase program with a full $1.5 billion available is we have accumulated a tremendous amount of dry powder and have a great deal of flexibility to lean in and continue to be opportunistic. We are intentionally not formulaic on this. We think we have been able and will continue to be able to buy in shares at better pricing by being somewhat picky in when we lean in. But what that means is, as you see a pullback or a disconnect in relative performance, we've got a significant capability to buy back shares. What I would say, if you just want a plumb line, is a very basic expectation is that year over year, we would expect for share counts to go down. That is an objective. Can't say that's going to happen every single quarter, but year over year on any 12-month period, we would certainly hope and expect and plan for share count to go down.

Thank you. Thank you. Our next question comes from the line of Kalei Eichelman with Bank of

America. Your line is open. Hey, good morning, guys. Thanks for taking my question. My first question is on NGLs. So, really appreciate the macro commentary that stronger dock utilization could lift Mount Bellevue prices. The theory makes a lot of sense. I guess the concern is that the market is more like dry gas, where hub and TTF remain decoupled. So, curious how you guys explain why this market is different and why there could be better connectivity in global

crisis. This is Alan Clay, and good question there. I'm trying to, I'm thinking, so you're asking how this market is different from in the past, and I guess I'd say that the biggest difference this time around is the closure of the straightforward moves and the damage that's been done in the Middle East. LPG of the Middle East, roughly 1.5 million barrels a day in a global waterborne LPG market of about 5 million barrels a day, so roughly 30%. That has been roughly, I would say, 70% of that, so a million barrels per day, has been absent from the market for the past six weeks it'll probably take a while if things get resolved at the end of April we're still probably looking two to three months depending on damage assessments evaluations and repairs before that flow can come back so you've really created a bit of a hole here that is unprecedented add to that that during this period we're consuming inventories throughout the chemical chain from widgets to polymers to oil fens down to feedstocks such as LPG and FA. So you're consuming that inventory and it's going to need to get replenished. So those two items there extend, I think, the demand that we were seeing pre-crisis and really add to that demand significantly. And we'll be feeling the impacts of that, I believe, through the rest of this year and into next year. So that's one of the big differences. Fortunately, from a U.S. perspective, we're in the mode of building out export capacity, and Dennis already referred to that. We've added quite a bit in 2025. We have new capacity that just came up last week. We have more capacity coming on at the end of next year. And then we still have significant new capacity coming on in 27, 28, and early 29 that will be used really to supply the shortfall globally and will keep a strong pull on U.S. supplies. So the setup overall is it's really just improved for the long term as a result of all those changes. I hope that answers your question. And I'll add in here,

Kalei, I think you mentioned TTF is the gas side of the equation as well. I think as we think about all of these markets, whether it's the NGL markets or the gas markets, the integration continues. You've gone from essentially no exports to currently running 20 BCF. We see the potential to reach 30 BCF exports LNG by 2028 and potentially 36 by 2030. Now, layer that in with the complexities and the flows of limited storage capacity expansions in the U.S. Some have been announced in FID, but you're talking to the tune of 10 to 15 percent type expansions where you're talking 30 to 40 percent of the U.S. market is now exported. You're also not seeing expansions in Europe. In fact, you're seeing storage facilities shut down. So the U.S. is now de facto storage and supply for Europe and for the rest of the market. So to your point today, there is a disconnect between TTF and Henry Hub. The exports are running full out. So you don't have that marginal the ability to swing that marginal molecule to create that connectivity today but as you continue to add in and commission the new facilities whether it's Golden Pass and they all these other facilities and continue to grow quite substantially another you know 50% in LNG you reconnect to those international markets so as we look at that and again as I mentioned earlier in the prepared remarks at the same time you've got domestic power demand you're effectively going to create once you have one spare molecule of export capacity, you create a situation where the markets have to bid the molecule away. So does the U.S. power need it? Do we need it for heating domestically? Does Europe need it? Does Asia need it for heating, manufacturing, you name it? So I think this, while that sounds to be competitive tension, it is, but the U.S. market has the capacity, Appalachia specifically has the capacity to provide that gas. You do need the permeant molecules as well, so that's not a fear factor for us. We see this as a great tailwind for the industry to provide reliable capacity, reliable energy supply domestically and globally, a place where range can grow as that demand pull occurs. And as a side note, a clear evidence of the fact that we do need some permitting reform, both for power lines, pipeline, and all forms of energy transportation. So, you know, today, you're right, there's a bit of a disconnect, but that's going to ebb and flow quarterly over the next couple of years as the rest of LNG under construction comes

online. Guys, that's excellent. That's a very thorough explanation. And thank you for the comments on the natural gas. My second question is on the growth program. You're now midway through your 400 million cubic feet gas equivalent target where 20,000 barrels of the NGLs will be sold from that new East Coast stock. Can you share anything about the split of those products, whether it's FAN or LPGs, and should we expect anything different from this vintage

contract versus what you currently have? Yeah, good question. I think the way to think about our volumes, as you point out, and what that looks like in the future, really from an NGL perspective, when we think about the C3 plus side of the equation, you should expect to see character-wise very similar contractual and commercial terms like you've seen us communicate Kate in the past. Alan and the team have really done a good job over the last few years of working through really what you saw were the results generated this past quarter, putting in both, we'll just say, medium-term type contract structures that have connections to ARA and FEI, markets that we really feel like have some durability to them and indices that we like, but also the flip side is we also have short-term type contract structures where it allows us to take also advantage of what's taking shape in more of a near-term type fashion so as we think about the expansion at Rapano and our ability to put more barrels on a waterboard export character wise think about it should look very similar to what you've seen in the past on the c3 plus side from an ethane perspective as you would expect there will be an uptick in ethane extraction just by nature of having more wet gas go through the system but however we tend to I'll just say extract down the middle of the fairway. What we don't do is try and get on the high end of extraction for a lot of reasons. It gives us some ability to be opportunistic when you see running ethane prices and the ability to basically take advantage of price signals during a given month or quarter. But we also have the ability to turn down that extraction just like you saw the team do during Q1 when it made more sense financially to basically put those molecules back into the gas stream. So there will be a step up as we have more growth over the balance of time in ethane extraction, but know that it's going to be character-wise very similar to what you've seen us execute in the past.

Thank you, Dennis. Much appreciated. Thank you.

Thank you. Ladies and gentlemen, we are nearing the end of today's conference. We will go to Philip Youngworth with BMO for our final question. Your line is open.

Thanks. Good morning. I know you don't want to be formulaic on capital returns, but with net debt now below the historical target range, just wondering if there's a minimum you'd look to get to? Are you comfortable being net cash, or do we kind of get to a point where we could see range consistently returning about 100% of free cash loans?

Very good question. In terms of the art of the possible, could you see range go to a net cash position? The answer is yes. If you have strong commodity price window, if you have a run-up beyond mid-cycle pricing and cash flow is above what you would expect to be a mid-cycle business, you can and should likely expect us to likely tilt towards accumulating some dry powder because I would expect the stock to be significantly outperforming in that type of a window. whereas in a pullback and a return to a mid-cycle or even down cycle, you could see 100%, you could see far more than 100% of cash flow. I mean, let's put that in perspective. I mean, to use just as hard as possible, a billion dollars in debt is less than a turn of leverage. I'm not suggesting we're going to re-lever, I'm just pointing out the amount of dry powder available. In a down cycle, if the stock price is pulling back and we have continued resilient free cash flow and the balance sheet strength to do it, there are periods of time, and this is just art of the possible, where you could easily buy back 10, 15, 20% of the company in a relatively short period of time. So it's those disproportionate sized investments that generate long-term gains for the corporation. So we'll continue to execute, again, look for range to seek to reduce share count year in and year out as a steady baseline, but to, with greater balance sheet strength, look for larger, more impactful

opportunities. Okay, great. And then on the NGL premium, I know we've hit on this a little bit, but when you say you're taking the strip at the high end for the annual guidance, just wondering how straightforward of a calculation this is given your marketing contracts, or are a fair amount of complexities involved in just taking the strip like um freight rates or just if you could kind of talk a little bit about the other variables that we should keep in mind as we as we think about uh the rest of the year um just considering how much you outperformed on on in one

queue here yeah there's a number of different contracts that go into that but we've got good line of sight as to the markets that we're going to be selling to so it's simply taking the forward strip in those various markets whether it's fei or whether it's ara or whether it's bellevue based we've got a good feel for that naturally those forward markets are going to be backward dated so i think we would view that as a conservative way to look at guidance but just given the volatility that there's been in the market in the near term we felt like that was the right approach to take and then like dennis mentioned on the low end or plus a dollar and a quarter, that's in a world where Mont Bellevue prices improve for all the reasons that we've talked about today. So even in that lower end, we're looking at absolute prices that are higher

than where we've been. All right. Thanks, guys. Thank you. Thank you. Thank you. This concludes today's question and answer session. I'd like to turn the call back over to Mr. Decker for his

concluding remarks. Yeah, I'd like to thank everyone for joining us on the call this morning and all of the thoughtful questions around our great results from the quarter. If you have any follow-up questions, please follow up with our investor relations team. They'll be happy to address any follow-up calls you may have. And then, of course, lastly, we look forward to seeing many of you on the road in the weeks and months ahead to visit more about the range story and on our next call.

Ladies and gentlemen, that concludes today's conference call. Thank you for your participation. You may now disconnect.