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 Scucchi, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we've posted on our website.

We may reference certain slides on the call this morning. You will also find our 10-Q 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, Lafe, and thanks to all of you for joining the call today. Range is off to a great start in 2026.

We continued steady operational progress in the first quarter towards our multiyear 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 Bcfe 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 Bcfe equivalent per day by year-end, all in line with our previous guidance. Capital for the quarter came in at $139 million as Range was running one rig and one completions crew.

Completions 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 0.5 million lateral feet by a single drilling rig.

The team also had 8 days where they drilled over a mile in the horizontal, with 2 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. 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 and is a key contributor to Range's peer-leading capital efficiency.

This combined level of efficiency in drilling and completions continues to support our operational plans through 2027 and beyond as we maintain a resilient DUC inventory for future optionality on capital and production. Range's winter operations program also had a very successful first quarter and kept production volumes flowing through the harsh winter conditions ushered in by Winter Storm Fern.

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 run time 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 prepurchase of production casing in late 2025. Fuel pricing will obviously be elevated due to diesel prices moving higher, though we expect no changes to our capital plans given the efficiency gains and contractual certainty around the rest of our program.

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 buildout 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.

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 sells. 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 bidweek in late January when Henry Hub NYMEX settled over $7 per MMBtu, 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 at $0.18 premium to Henry Hub for the first quarter. Turning to liquids, Range's 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 Belvieu 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 Belvieu. The low end reflects the potential for improved Mont Belvieu pricing through strong U.S.

exports, while 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 multiyear, 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 the infrastructure slated to come online midyear, 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 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 share repurchases 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 cost.

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.

While the GP&T 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 Mcfe, 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 Range's 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 multiyear plan, consistent free cash flow generation, and prudent allocation of that cash flow, balancing returns of capital, balance sheet strength, and the optimal development of our world-class asset base.

As we sit here today, our multiyear plan is on track, and years of disciplined planning have placed us in the strongest position in our company history, having derisked 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.

Good morning.

Morning, Jake. ): Hey,

Mark, you mentioned the link-floating contracts for the European and Asian markets on the propane and butane. Can you frame on a percentage of volume basis which each market received in Q1 and how you see those amounts moving into Q2 and beyond?

Maybe if I could ask if you could disclose those contract terms?

To answer the last question first, no. There is some competition in this business, as you'd expect.

Our marketing team has done an outstanding job over the years building relationships, managing exports out of the East Coast cargo by cargo. Those relationships, the understanding of timing, of the fact that what you're seeing on the screen may not be what is on the physical side of things when these cargo loadings are planned a month, 2 months, 3 months in advance.

I guess to take a step back, as 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.

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 petchem, heating, consumer demand on U.S. molecules on the water.

Terms of those deals, no, 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 Mont Belvieu. ):

I appreciate that. 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. Maybe for Mark, could you opine on how you're thinking about the marketing strategy given the 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 go ahead and try and unpack this here.

From the data center perspective, we're still seeing what I would say is regular and really, quite honestly, a good cadence of a dialogue around that particular Fort Cherry location and that opportunity. 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.

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-linked-type structure into the Midwest 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. We think there's a lot more to come.

We also point to things like the NextEra announcement. Clearly, that power gen facility is going to go into the Southwest PA, Appalachia region.

We think there's a real opportunity for 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. We think there's a lot of opportunity for us to continue to see this expand.

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. 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.

A lot of activity in this space by our marketing team to try and find good opportunities that will align with Range. We know that these are multidecade 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 assurance of supply and inventory like we do.

We'll certainly provide updates as we see more come forward and look forward to doing so. ):

Thanks, guys. I appreciate the time.

Thanks, Jake. Thank you.

Please stand by for our next question.

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 midyear.

Is that June or July? Just trying to think through any commissioning or ramp-up period post that.

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?

Good morning, Gabe. As we start to think about really the months ahead here in 2026, our production character should look really similar to what you've seen and others over the last few years under a maintenance to maintenance-plus-type program.

Actually looking at Q1 production, it's almost an ideal overlay, character-wise, to what we had a year ago. Several of the turn-in-lines that occurred toward the back end of Q1 will now start to pack the system of available infrastructure that we have.

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. 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 midyear point, which, again, we think with this looped 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. Think about it being kind of fairly ratable across Q3 and Q4 as we start to end the year at 2.5 Bcfe 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 and the DUC inventory that it will start to turn into sales through the next 6 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 Bcfe a day type number in 2027.

Everything's on track from an infrastructure standpoint for this year. When we think about what's beyond 2027, I think we have to go back to maybe how we started the first question here today, and that is it's 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. 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.

We really think it has an opportunity to be very steady as she goes in beyond 2027. If not, we have the ability to pull capital down, and it could be somewhere in the $570 million 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.

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. That's really clear.

Thanks, Dennis. Then maybe just my second question, back to the LPG side.

Appreciate all the prepared remarks and the answer to the earlier question. Curious if you could maybe put a little bit of a finer point on updated thoughts on the macro given all the domestic and international moving pieces and even maybe elevated shipping costs.

Neches River comes on around midyear, U.S. propane exports grow to 2 million barrels a day plus.

Does that clear the inventory glut, in your mind, domestically? Then from an international standpoint, thoughts on China PDH run rates and maybe any other puts and takes that could ultimately impact the premium that you expect over Belvieu?

Thanks, guys.

You betcha. Thanks again, Gabe.

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, that was incredibly helpful when you think about starting to chip away at the current stock levels.

Look, I think it's commonly known that the stock levels are elevated. We're talking somewhere roughly 70% above where we've seen historical averages.

We added 150,000 barrels a day in export capacity last year. That's been at a high end of utilization.

I think one of the 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 lifted off.

We find that really encouraging when you start to think about pulling down stock levels over the balance of the year. 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.

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 0.5 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 as we're all trying to navigate these particular moments, the reality is the business has actually been as resilient as we've seen, as really demonstrated by the quarterly numbers that we just communicated.

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 you've heard Mark talk about, 80% of our LPG on a waterborne export out of Marcus Hook.

Also, I would be remiss not to point out the Repano terminal that will go into service in January of 2027. That's going to allow us to have more access to waterborne exports.

All that to say, we've got demand growing, run rate showed 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.

Thanks, Gabe.

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.

Just can you spend more time talking about what drove the magnitude of that beat? 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?

Good question. This is Alan.

I manage the marketing group, I'll take a stab at answering your question there. When we look back at realizations during the first quarter on the NGL side, really three main drivers.

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 ethane recoveries, so that we'd be better on gas.

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. 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, and we were able to realize good prices with sales within the U.S. during January and February.

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 events in Iran with a terminal that went down in Saudi Arabia.

That spiked the international prices, which then spiked better returns at the dock for us. You add all those three things together, it was a good quarter.

Things aligned very well. We're positioned with flexibility so that we could move from domestic markets to international markets and capture the best overall netback 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. When you get into shoulder months and even summer months, sometimes, 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, let's say international propane mid-March, it was up, call it, 80% relative to pre-crisis levels. That is now somewhere around, call it plus-30% or plus-40% relative to pre-crisis levels.

Still very attractive, but not quite what we were seeing in the middle of March. We would expect that, going forward, even if there is a solution, let's say in the Strait of Hormuz in the next couple of weeks, it's still going to take months to get flows back to normal.

There's millions of barrels' worth of inventory that have been consumed internationally. 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 $3.75 mid-cycle view.

One of the pushbacks we get often is the weakness in Permian, specifically Waha now trading $6 under zero, right? The question is, as those molecules move down to the Gulf Coast, what could that mean ultimately for the whole North American pricing system?

Just how are you guys thinking about that, the Permian gas risk, the associated gas supply risk, and how that could put a depressing impact on price?

Neil, I'll jump in here. 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 several years.

When I think about what's going on, really rig count hasn't changed appreciably since the beginning of the year. A few rigs just kind of look at those dynamics.

Stepping in with additional rig activity to create a, I'll just say, significant amount of growth really hasn't really shown up yet. Clearly, there's been an increase in completion crews.

I think roughly that number is up across the board, probably around 12 to 15 in magnitude. That's also kind of similar in character to what you see when you look at the falloff at the end of a prior year and then to kind of start off at the beginning of this year.

It's still below pre-year-over-year-type levels from a standpoint of activity. Then, of course, I think what that means is you're seeing a bit of a DUC draw.

DUC inventory is down across the Lower 48 by about 20%. 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 the Permian.

When you look at, 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 1 at Golden Pass.

That's been a long-awaited and now encouraging as well. We kind of look at it as 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.

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 of about 37 days. That's about 5 days below the 5-year average.

Again, what we really think that sets up is more volatility, which we've now seen occur over the past couple of years. 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. Thanks, team.

Thank you.

Oh, sorry. Blanked out there for a second.

Good morning, all. Thanks for taking the call.

Just wanted to touch on your OpEx and numbers a touch. It's historically been that every dollar move in NGLs is about $0.01 in GP&T, and then about $0.02 to $0.03 per dollar movement on gas side.

Does that hold in current market dislocations? 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 and 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, and as all of us are studying, greater volatility on the gas side, particularly with the winter weather in the first quarter when we saw $4.69 in January gas, $7.46 in February, back down to March at $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.

If you want to say $0.02 to maybe $0.03 per dollar on the gas side, that's a reasonable ballpark estimate. It still holds for Range specifically.

A dollar move per barrel on NGLs is about a penny in GP&T. I think the key point here is that, as I mentioned in the prepared remarks earlier, is that right-way risk scenario where the margins are expanding.

If that line item goes up, it's because we are realizing higher prices and expanded margins. 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.

The margins do expand, and, of course, they shrink in commodity price downcycles as well, it's a right-way risk. Hopefully that answers your question.

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.

Just talking a bit more about as you guys bring down the DUCs part of the growth prospects, I guess what level of reactivity in the production split do we expect to see? Do current conditions shift this, any kind of leaning towards more wet versus dry gas, or pretty much set for the coming quarters?

Paul, good question. I think as you think about the DUC 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 70% to maybe 65% on the liquids activity, and then the remaining more on the dry gas side. That's for a varying reasons, but clearly utilization of gathering systems that we have in place, keeping our costs at a low level, but also those are good returns on the dry side as well for when you look at the comparable across our asset base.

With the infrastructure that's going into service at the midyear point, it's focused on the liquids side. Our activity of turn-in-lines and completions will be 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 Repano terminal capacity that I mentioned a little bit earlier that will go into service roughly around the first of the year.

Think along the lines of our DUC inventory being more weighted heavily toward the liquids-rich activity, much like you've seen over the last few years. Then the last piece that I'll share with you is, look, we've got around 500,000 lateral feet that we've built up over the last couple of years.

What you would expect to see with a consistent activity from our base electric hydraulic fracturing crew, but also the spot activity that we'll have over the next 6 months in this year and the activity that we'll have next year, will allow us to ratably utilize around 400,000 lateral feet over the balance of the next 18 to 24 months. Then we'll reevaluate what's the right plan for beyond 2027.

Got it. Appreciate all the clarity.

I'll leave it there.

All right. Thanks, Paul.

Hey, guys. I wanted to see if you could be a little bit more specific on kind of the change that you expect on production into 2Q as well as CapEx into 2Q.

I heard in your prepared comments it sounds like production's only up slightly, then you get a big jump in 3Q. Anything you can do to quantify, and it sounds like CapEx will also be up a decent amount here in 2Q.

Good morning, Leo. I think from an activity standpoint, if you look back on Q1, we had one rig and one frac crew.

Ultimately, that was $139 million in capital spending. A way of thinking about it for maybe a little bit more color, roughly it's a two-third, one-third roughly split.

Completions is roughly two-thirds of the equation. 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, I would just say, think about what you've seen, also from our efficiency standpoint, the ability to, of course, move water in an 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. That's how I 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 there very well may also be an opportunity for us to not need a second crew as much as you would expect with the kind of 17 stages per day type efficiency levels that the team's been able to capture. Second quarter, third quarter, we'll have that second completion crew and still be the one drilling rig.

From a production standpoint, I would expect to see us kind of take an uptick, that basically will be more stronger toward the very tail end of the quarter. As you think about that back end of the year, think about it kind of ranging somewhere from a ramp of roughly 2.3 Bcfe equivalent per day toward the midyear point that gets us up to 2.5 by the time we get to the end of the year.

Okay. Appreciate that.

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? 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?

Leo, I'll take those. 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 Range's accumulated NOL that gains and profits of the next couple of years will be able to utilize.

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 Range 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 share repurchase program.

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.

There is that reality of exercising and running an opportunistic program. 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.

What that means is as you see a pullback or 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.

Hey, good morning, guys. Thanks for taking my question.

My first question is on NGLs. Really appreciate the macro commentary that stronger dock utilization could lift Mont Belvieu 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.

Curious how you guys explain why this market is different and why there could be better connectivity in global prices.

This is Alan, Kalei, and good question there. I'm thinking, you're asking how this market is different from in the past.

I guess I'd say that the biggest difference this time around is the closure of the Strait of Hormuz 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, roughly 30%.

That has been roughly I would say 70% of that, a million barrels per day, has been absent from the market for the past 6 weeks. It'll probably take a while if things get resolved at the end of April.

We're still probably looking 2 to 3 months depending on damage assessments, evaluations, and repairs before that flow can come back. 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 olefins down to feedstocks such as LPG and ethane. You're consuming that inventory, and it's going to need to get replenished.

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. That's one of the big differences.

Fortunately, from a U.S. perspective, we're in the mode of building out export capacity.

Dennis already referred to that. We've added quite a bit in '25.

We have new capacity that just came up last week. We have more capacity coming on at the end of next year.

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.

The setup overall is it's really just improved for the long term as a result of all those changes. Hope that answers your question.

I'll add in here, Kalei. I think you mentioned TTF and 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 in 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% type expansions where you're talking 30% to 40% of the U.S. market is now exported.

You're also not seeing expansions in Europe. In fact, you've seen storage facilities shut down.

The U.S. is now de facto storage and supply for Europe and for the rest of the market.

To your point, today, there is a disconnect between TTF and Henry Hub. The exports are running full out, you don't have the ability to swing that marginal molecule to create that connectivity today.

As you continue to add in and commission the new facilities, whether it's Golden Pass and all these other facilities, and continue to grow quite substantially another 50% in LNG, you reconnect to those international markets. 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 molecules away. Does 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?

I think this, while that sounds to be competitive tension, it is. The U.S.

market has the capacity. Appalachia specifically has the capacity to provide that gas.

You do need the Permian 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.

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. 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 the East Coast dock.

Can you share anything about the split of those products, whether it's ethane or LPGs, and should we expect anything different from this vintage of contracts versus what you currently have?

Good question. I think the way to think about our our volumes, as as you point out, and what that looks like in the future, really from an NGL perspective, when we think about the the C3+ side of the equation, you should expect to see, character-wise, very similar contractual and commercial terms like you've seen us communicate in the past.

Alan and the team have really done a good job over the last few years of working through really what 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 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. As we think about the expansion at Repano and our ability to put more barrels on a waterborne export, character-wise, think about it should look very similar to what you've seen in the past on the C3+ 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. 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 a run in ethane prices and the ability to basically take advantage of price signals during a given month or quarter, but we're 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.

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.

Thanks. Good morning.

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 flow?

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'd expect to be in 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 downcycle, you could see 100%.

You could see far more than 100% of cash flow. Let's put that in perspective.

To use just art of possible, $1 billion in debt is less than a turn of leverage. I'm not suggesting we're going to relever.

I'm just pointing out the amount of dry powder available. In a downcycle, 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.

It's those disproportionate-sized investments that generate long-term gains for a corporation. 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 with greater balance sheet strength, look for larger, more impactful opportunities.

Hey, great. 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 there fair amount of complexities involved in just taking the strip like 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 think about the rest of the year, just considering how much you outperformed in 1Q here.

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. It's simply taking the forward strip in those various markets, whether it's FEI or whether it's ARA or whether it's Belvieu-based.

We've got a good feel for that. Naturally, those forward markets are going to be backwardated.

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've felt like that was the right approach to take. Then like Dennis mentioned, on the low end, or plus $1.25, that's in a world where Mont Belvieu prices improve for all the reasons that we've talked about today.

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.

I'd like to thank everyone for joining us on the call this morning and for 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. 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.

Thank you.