Range Resources Stock

Hello. Welcome to the Range Resources Second Quarter 2026 Earnings Conference Call. [Operator Instructions]

Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Laith Sando, Senior Vice President of Investor Relations at Range Resources. Sir, please go ahead.

Thank you, operator. Good morning, everyone, and thank you for joining Range's second 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, Laith, and thanks to all of you for joining the call today. Today marks a unique milestone as we reach the midpoint of our multiyear growth plan that was announced early last year. Range's results today continue to showcase the durability of the business as a leading full cycle cost structure, consistent well performance and a differentiated marketing portfolio are delivering significant free cash flow while growing the business. At the same time, we are seeing operational efficiencies [indiscernible] Range as a result of our large [ blocky ] acreage position and talented technical team. This quarter's record operational results support Range's peer-leading drilling and completion costs that will benefit Range shareholders for decades to come.

Looking at the results for the second quarter, efficient operations in the field and strong well performance drove production of 2.3 Bcf equivalent per day. Consistent with our previous calls, Range expects production to continue to ratably increase across the remainder of the year, underpinned by gas processing and related infrastructure that is in the early phases of commissioning. This will push production to 2.5 Bcf equivalent per day by year-end and is consistent with our previous guidance and setting us up well for 2027 and strengthening natural gas fundamentals.

Capital for the quarter came in at $222 million as we added a second completion crew to begin working through a portion of the drilled uncompleted inventory, we have built up over the previous 24-months. The second quarter also included a spot horizontal rig that was added for a single pad development that will turn to sales later this year. We expect to return to a single horizontal rig and single frac crude operation for the fourth quarter, putting our capital plans right on track with prior guidance.

With the activity mentioned earlier, we drilled approximately 190,000 lateral feet during the second quarter. Continuing the operational momentum reported during the prior quarter, the team had 19 days where they drill over a mile in the horizontal, with one of those 24-hour periods exceeding 10,500 feet. This level of operational efficiency advancement continues to reflect the team's ongoing hard work and drive to deliver on Peer-Leading Drilling and completion cost per foot after over 2 decades of activity.

Moving to completions. The team achieved the best quarterly performance in Range history utilizing the 2 frac crews I mentioned previously. Combined, the 2 crews completed nearly 1,900 frac stages, including downtime for moving between pad sites, this equates to completing over 10 stages per day per crew or an annualized rate of over 750,000 lateral feet for a single crew. And when looking at our base contracted electric frac fleet, efficiencies were nearly 14 stages per day. Additional completion records by the team for the second quarter included: the most frac stages performed in 1 day for a single crew at 20, and the highest pumping hours in 1 day at 22 hours. To achieve these records, the logistics management team kept pace, ensuring execution remained on track. I'd like to congratulate our team on reaching these levels of operational efficiency while doing so safely.

To accommodate this increased completion activity and efficiencies, we have moved a portion of our second half 2026 drilling activity into 2027. This sequencing keeps us right on line with the 2026 and 2027 capital spending and development plans we have discussed previously.

Now shifting over to marketing. The ongoing disruption of global energy supply has showcased Americas and Range's ability to respond to ever-changing global supply and demand balances. We believe this period has once again highlighted United States pivotal role in providing energy supply to the world. The ongoing build-out of LNG and NGL infrastructure to supply export markets, has positioned the country to continue to meet this demand going forward, all while providing abundant, affordable energy to American residents as well as commercial and industrial customers.

As we expected going into the second quarter, U.S. exports of LNG, ethane and LPG delivered tremendous growth relative to the same time period last year. For natural gas, LNG feed gas in the second quarter averaged over 17 Bcf per day or 17% higher compared to the same time period in 2025. We expect this momentum to be carried forward into 2027 and beyond as additional construction is completed. For Natural Gas Liquids, U.S. waterborne ethane exports were estimated at 658,000 barrels per day for the second quarter, which is up 40% year-on-year and set a record high in June of nearly 750,000 barrels per day. Our propane and butane, waterboard exports reached over 2.6 million barrels per day, which is also up 19% versus the first quarter and 30% higher year-on-year.

LPG exports are expected to grow further into 2027 as an additional 360,000 barrels per day of LPG capacity becomes available via 2 new terminals early in the new year. Looking ahead, we expect growing U.S. exports across natural gas, NGLs and crude oil to strengthen domestic market fundamentals and support pricing across the products Range produces. Through the first half of this year, our marketing team has successfully navigated this rapidly evolving global market and capitalize on opportunities to generate incremental cash flow. As we emphasized during our first quarter call, Range's access to international markets for ethane, propane and butane continues to generate differentiated margins for Range's NGLs. Our marketing team capitalized on strong international prices through the flexibility built into our export program, supporting another strong NGL premium of $3.49 per barrel over the Mont Belvieu Index for the second quarter.

While international FX have normalized this June, Range still expects to capture premiums to Mont Belvieu in the coming quarters, given our proximity to Europe, and the price structures embedded within our physical sales agreements. As a result, we have improved our full year NGL guidance to $2.50 per barrel over the Mont Belvieu Index. At the same time, we are improving our full year natural gas guidance to $0.35 to $0.40 per Mcf versus Henry Hub, reflecting a strong start to the year.

As we enter the second half of our multiyear growth plan, we are excited about how the company is positioned 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 half of 2026 behind us, the year is unfolding as a success, both operationally and financially. Our 2026 operational plan is focused on disciplined development of our asset while capturing additional future value from growing demand. This plan was designed to deliver value from both future growth and to deliver returns to shareholders today. So let's dive right into what Range has delivered to shareholders in 2026.

In the second quarter, we repurchased $78 million in shares, bringing the first half of the year total to $105 million. We paid $24 million in dividends in the quarter bringing year-to-date total to $47 million. Year-to-date, we've reduced debt by $337 million. In aggregate, this brings year-to-date enterprise value returned to equity holders to $489 million, roughly 5.5% of Range's market cap in just 6-months. Since initiating the share repurchase program, Range has acquired 35.9 million shares, a reduction of nearly 10%. These are tangible results delivered to shareholders through commodity price cycles and indicative of what range can continue to do on a growing scale as natural gas prices respond to rising domestic and international demand.

With a strong balance sheet, roughly 0.5 turn levered Range's ability to return capital and pursue investments in the business is not delayed by balance sheet needs but are being carefully evaluated and opportunistically executed. In early 2025, we announced a 3-year plan charting a path of 20% growth in production to approximately 2.6 Bcfe per day in 2027. Further, we estimated that Range can maintain 2.6 Bcfe per day of production for less than $600 million of annual drilling and completion capital or approximately $0.60 per Mcfe. Let's put the resulting cash flow potential in perspective.

Exiting this growth plan, averaging 2.6 Bcfe per day using a hypothetical mid-cycle natural gas price of $3.75, free cash flow would exceed $2.5 billion over a 3-year period, approaching 30% of Range's current market cap. Alternatively, cash flow in this scenario could repay all debt and still acquire a significant percentage of Range's shares outstanding. This illustration is a compelling result from any business, especially considering it's a baseline that assumes no further growth. We successfully reached the halfway point of our current multiyear plan and are on track to deliver. But the Range business doesn't stall there. Range is a growth business, growth in cash flow per share, driven by demand pull production growth that improves margins, compounded by a declining share count.

With the Marcellus inventory of 30-plus years, this asset can meet higher demand and sustain that production for decades. This is rare in our industry, which can produce more gas over time, but at an increasingly higher cost. From the perspective of a range shareholder, this means Range is a consistent and durable business through commodity price cycles. And from a customer perspective, it means affordable, clean, reliable supply.

In summary, Range is in a strong position to continue capitalizing on strategic advantages across several key areas, maintaining superior full-cycle margins through operational efficiency, delivering strong capital returns to shareholders and exploring business opportunities that position us for long-term growth in the evolving energy market. As natural gas market continues to evolve, range will remain nimble, responsive to market signals and focused on creating sustainable value for our shareholders. We're excited about the opportunities ahead and remain confident that our strategy will continue to deliver superior financial and operational performance.

Thanks, Mark. Today's results continue to demonstrate Range's strong operational performance against our stated multiyear plan, consistent free cash flow generation and prudent allocation of that cash flow, balancing returns of capital, balance sheet strength and the optimal development of our world-class asset base. As we review our results, our 2026 and multiyear 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.

[Operator Instructions] Our first question comes from the line of Jacob Roberts with TPH & Company.

Dennis, I wanted to start on the lateral feet -- DUC lateral feet backlog. I think you had 0.5 million feet entrance this year. And given some of the, frankly, pretty impressive efficiency gains you guys have seen on the completion side to start this year. Where are those balances today? And how you think about flowing that down for lack of a better term, over the course of 2026 and 2027. Has that changed at all?

Thanks for the question and for joining us. I think when we take us back and we start to look at the dynamics of the program over the remaining 18 months, you're right, the efficiencies have really allowed us to pull a little bit of that DUC inventory forward. But when you think about '26 and '27, the plan was really to utilize the 400,000 lateral feet that essentially we had built up over the prior couple of years, over the balance of '26 and '27. We're still on track for that. So we're a few wells ahead. I think just a kind of a high level of estimation, it has allowed us to pull down a little bit of our drilling needs here, and then we'll toggle that to a little bit drilling activity next year, all within the same capital that we've communicated as a part of our materials and guidance.

So think about it in some ways, a little bit of a dynamic that's a little bit different than where we were under the Maintenance Plus-type program where we had a consistent 2-rig program and we had maybe completions that was kind of oscillating as we build inventory. Now we're on the other side of that. And so we're able to have our completions activity remain more consistent. The efficiencies are allowing us in a great way to pull some activity forward, but we're going to then oscillate some of that drilling activity, all while optimizing that DUC inventory that's needed while staying on track with our program as we then start to produce and fill the new infrastructure that's in process of being commissioned. So great place to be in, and we're excited about the team's accomplishments.

Perfect. And -- when we think about this longer term, but I'm talking about growth. And so when we think about what the company looks like exiting 2027 as you guys have laid out the growth plans, we'd agree that your inventory would include you in a subset of operators that can participate in what the industry broadly sees as growth in the 2028 time frame you guys laid out on Slide 20 there, the different avenues you might take. So I'm curious, not only from your perspective about the pace of growth that [indiscernible] might contemplate to meet this demand, but really how you view the industry and being able to respond to this in the Northeast, let's say, over the next 5 years?

Yes. As we start to think about 2028 and beyond. The position that we're in we really have the ability to continue to grow at a similar -- I won't say identical, but a similar growth rate that you're seeing right now with a very similar capital investment, all of the similar resources of drilling and completions activity and with the same team. So if you look at what we've been able to accomplish with efficiencies and also just the ability to move back to pad sites with existing infrastructure, for incremental phases of development, it's allowed us to really be nimble and react more quickly, I think, to the ability to grow.

So when we think about '28 and beyond, I think we will have the ability to grow similarly to what you're seeing now with a very similar capital investment, again, team resources and -- but it's going to start with a home for that production. And as you point out in Slide 20, we're awfully encouraged by what we're seeing with the incremental few Bcf that we've added to the in-basin high side case with takeaway and also in-basin demand for power and data centers. But as we see that further materialize, we feel like we'll be able to step right into that, just again, given our nimbleness in the program our large blocky acreage position. And then on top of it, just the depth of inventory we have in the Marcellus. So I think that will be rare compared to maybe some others that will have the ability to do so. But again, it's going to start with having a home for that production.

Our next question comes from the line of Doug Leggate with Wolfe Research.

Mark and Dennis, I guess one of your peers last night put out a very detailed a synopsis of all the potential growth data centers and so on, quite material, especially in the Appalachia area. So my question is, where do you see Range positioned to compete on some of those supply agreements? Because obviously, we've talked about this before, but your balance sheet is pristine, but yet you still have a sub-investment grade credit rating. I'm wondering if that's an issue. And any kind of line of sight you could provide that? That's my first question. My follow-up is 2027 is right around the corner. You laid out the 3-year plan. What's next as it relates to capital and growth aspirations? I'll leave it there.

This is Mark. Maybe I'll start with the balance sheet and just some of Ranges past accomplishments and deals to help frame what our balance sheet allows us to do as compared to what others do. So our balance sheet mix are higher than our investment-grade peers, meaning stronger, meaning lower leverage, gaining higher liquidity all proportion to our business. We have had 15-plus year international export deals on the liquid side. We've done 5, 5-plus-year deals with Japanese utilities on the LNG side and have cycled through multiples of those. We've already announced a 10-year deal in the Midwest to a power plant.

So I will tell you that in our commercial discussions, the balance sheet and credit rating has never been a topic of discussion. Now that rating and achieving that rating will come as a byproduct and at the appropriate time for the business to enable Range to continue to execute commercially and maximize the value of its inventory, whereas we're not handcuffed in operating the business by ever-changing guidelines from the rating agencies. It will be important and potentially useful at some point. But I think if you look at even the spread to our bonds today at just over 100 basis points to the index, we're trading at investment-grade models. So the market has seen through that and our customers do as well. That is not to say we're by any means opposed to it. It will come, and we'll get there. But for the time being, certainly, not a need to have, and the team is already meeting with success on the commercial side.

Yes. And I'll take it from here, Doug. I think you asked a good question is how is Range is going to compete for some of these deals. I think if you look back over the last, we'll just say roughly 12 to 18 months, the build-out of data centers and power demand opportunities in the region have really continued to evolve. And I think it's been a very, very active and busy space. Our marketing team has been incredibly engaged with a lot of the counter-parties that you've seen even major announcements from that could have other producers providing supply into them. Those entities have now had conversations with Range to look for incremental supply as they think of scalability of their facilities, and also how they're looking to diversify, let's just say, operational and commercial risk within their organization.

So maybe to dovetail on to what Mark is saying, we're not seeing any flags or questions around Range's ability to participate. I think what it's coming down to is a host of variables and a couple of them being proximity, diversity and also inventory. And when you look at our marketing portfolio, what really brings the phone to ring on our desk a number of times is those three variables and probably most importantly, the last one. The marketing portfolio that we have and the ability to not only produce in-basin, but actually touch infrastructure regionally, we think, is really important as well. Thus, the Ohio announcement that we made earlier this year, I think you could see us participate in other announcements similarly in the future.

But again, really busy space. We're optimistic about the future of what this could look like for Range and also the -- as we talked about earlier under the prior call, and I think your secondary follow-up question is, what does it look like beyond 2027?

And again, we feel like we're in a really unique position that we will have grown our production by 20% over the balance of a 2-year period, by the time we get to the end of 2027, we feel like we could if we wanted to, to continue that momentum with a very similar capital investment. But even thinking on a, let's just say, a higher, I won't call it blue sky scenario, but let's just say the high-case we feel like instead of running 1.5-type drilling rigs and 1.5-type frac crew programs, you could run a consistent 2-rig program and 2 frac crew program with a very similar capital program you're seeing now and even have a little more growth. And so in the future, with our inventory and our team's ability to continue to also execute, we could see the ability to double the size of the organization's production just in a matter of a few years. So very exciting for us. We're going to continue to engage on the marketing side. But again, I'll just put a pin in it by saying this, these opportunities have to compete with the other options that we have in the portfolio, and we know that they will.

Our next question comes from the line of Michael Scialla with Stephens.

Dennis, you talked about the growing U.S. exports of LPG and ethane, pushing the Mont Belvieu price closer to international prices, but you also increased your -- for your guidance for the premium you expect over Mont Belvieu. So I want to see if you could talk about what you're seeing there, if you expect that premium to last into next year due to some of the deals you've done with European pet chems? Or do you expect the macro to kind of pushed that reversion back into place.

ATL dynamics have been no doubt exciting this year for us, and I think that's probably a consistent theme you probably hear from us and beat one-on-ones and also in earnings calls. I think if you look at where propane stocks are now, clearly, they've been elevated. Ethane, a little bit of a different story. It's been very similar, a little elevated, but very similar to where stock levels were 1 year ago. We've seen ethane pricing improve as you've seen long-haul transport start to go into service out of the Permian and thus change the extraction rejection dynamics clearly out of that basin.

As you switch over to LPG, clearly, the expansion of some DUC capacity earlier this year, I'll say, in the spring time frame, that flex capacity that went into service to move 360,000 barrels a day has really reshaped the curve as we think about -- as we entered into build season from an inventory perspective, and to put some color around that, that's reduced the build rate by 57% over last year and 40% versus the 5-year average. So very meaningful numbers. And when you think about what's going on from a global dynamic standpoint right now and the need in some of the global market demand centers, it's really been helpful that out of the Gulf Coast range, the industry as a whole has been able to step up, if you will, and fill some of that global need.

As we kind of look forward and look towards the 2030 time frame, you're really seeing on both the ethane and the propane side more demand growth. So propane, for an example, there's going to be approximately 1 million barrels of incremental demand growth that's going to take shape over the next 4 years through 2030. And the DUC capacity is also under construction that would also or is planned that would support that for 950,000 barrels. So it's all what I'd say, hand in glove from an LPG perspective and on the ethane, same story, another 750,000 barrels of incremental demand that should be coming online by the end of the decade, shifts, stock capacity all in line to support that. So we feel like the vehicle is there. And when you look back again to Ranges' inventory and what liquids will represent as we continue to move forward with the [ Repauno ] DUC capacity that we will see go into service in 2027. It really allows us to have a unique dynamic with access to the international market off the East Coast that we continue to expect to see premiums versus the Belvieu Index.

But even when we see moments where that may tighten because you see congestion lift out of the Gulf Coast, then absolute price goes on the uptick. And then I think we -- you see Range continue to win in a different way and remain competitive and have that leading gauge. So we'll have [indiscernible] answer this morning, but we're excited about the future of NGLs, and it goes far beyond what we're seeing just in the current dynamics globally.

I appreciate that. I wanted to ask you, it looks like you drilled a Utica well here recently. A little surprised given the high-quality inventory depth of the remaining Marcellus locations you have. I just want to see if you could talk about what you're seeing in the Utica that encourage you to drill that well and what your plans are for that play?

Yes, I'm glad you asked about our Utica well. I think if you look back over the course of time, what you're seeing is Range is going to most likely drill and complete a Utica well about every 3, 4, 5 years. And its to continue to evaluate the subsurface, advance our geological model, just continue to chip away at the learnings for that particular portion of our asset base. 99%, if not 100% of our focus will continue to be on the Marcellus. But with all of the conversations we've already had just this morning about growing demand, optionality and the ability to meet let's say, growing needs for power and energy for the Lower 48. We see that this just adds another wrinkle and opportunity for Range to think about, whether it's years or decades down the road. So wouldn't we have a possibility to see Range again in a few years, drilling it and complete another well but to continue on with that gathering of data and observation and comparing ourselves to what we see as the high watermark and advance that in the future from the Utica perspective.

I think simply put, the day we decided to make that a part of our development program, we want to have a similar confidence level with our Utica program that we would that we've conveyed with our Marcellus program. So we'll slowly chip away at it. We're really encouraged by the well results we're seeing right now. It's really early. We're only a couple of months in, but look forward to sharing some of the details in the future.

Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

To follow up on the comments about your liquid [indiscernible] growth to be weighted towards NGLs or gas? Or do you expect kind of a similar liquids mix in 2027 and beyond?

Yes, Kevin, there was a brief moment where you cut out, but I'm going to -- I think I understand the gist of your question. And if I missed something, please circle back to us here. When we think about the production growth over the next -- really through our current multiyear plan, it's weighted pretty similarly to what you've seen us execute in the past where the liquid side of our production profile has been -- and activity has been somewhere around, let's just say, plus or minus 65% to 70%. And then the remaining 30% to 35% would be on the dry gas contribution. That should be and feel very similar going forward as well. It's aligned well with our infrastructure, our inventory, but I will say this, over the course of time, I think you're going to see us evaluate where our activity would be most located to fill future demand growth and what's economically advantaged focusing on margins.

But the liquids component will continue to play a strong part of our story going forward. No big divergence from what you've seen us execute in the past.

Great. I appreciate that. And then maybe coming back to your comments on some of the drilling moving from 2025 to 2027. Can you kind of bridge the gap on however you like to describe whether it's turning lines or net lateral footage that you originally planned to drill in 2026 that has moved to 2027. And was that just a capitalization based on drilling wells faster?

So I guess taking a step back to the numbers for 2026. I think just at a very high level, you're talking about a pad site of wells approximately. So we're not talking about a huge number of incremental activity on the DUC inventory versus the TILs. And part of that just comes down to the capital that gets allocated roughly to one side of the the operation versus the other. So pulling down drilling activity allows us to no doubt redistribute that sequencing in capital, but it's also not the bigger part of the overall equation. So think about next year being a minimal -- probably an incremental pad site that we would then think about shifting that capital over to 2027. But as we looked at the DUC inventory by the time we get to the end of '27, I will just say it's only it's not in high demand and high need. It's really setting us up for how we're thinking about capital and activity for 2028.

Our next question comes from the line of Leo Mariani with ROTH.

I was hoping you provide maybe a little bit more color on how you see third quarter production and CapEx trending. Obviously, you spent about 1/3 of your CapEx budget in 2Q. So can you give us a little flavor of how that may change in the next couple of quarters? And you mentioned kind of ramping production nicely and in the second half as you're filling some of the new infrastructure. Could you provide a little bit of color in terms of how you see the growth trajectory there in 3Q and 4Q?

You bet. Thanks for joining us, Leo. When I -- I think the way to think about the second half of the year for us is -- I'll kind of describe it on what we're going to execute and then maybe relative to the first 2 quarters. And hopefully, that will help provide some color.

First quarter, we had essentially a couple of drilling rigs, and we had 1 completion crew. And by the time we got to the second quarter, we started right out of the gate with a second completion crew, and we maintained a -- a second rig for some spot activity. We tried to cover some of that I know in the prepared remarks. So there's your -- I'll just say your dynamic of how activity and capital were somewhat tied together through the changes in the first half of the year. We're down to essentially 1 completion crew right now. We've got a second completion spot crew that will execute one pad site for us sometime toward the back half of the quarter. And then in Q4, we'll be down to 1 drilling rig and 1 completion crew. So to put it plainly, you're going to see from an activity basis, us kind of get slower towards the end of the year because of all of the turning lines that will then come out of this activity from Q2. It will underpin our production growth as we go through the back half of the year. But capital is going to, at least for Q3, should look something similar between what you saw in Q1 and Q2. So you'll see that come down in line. And then again, Q4 is going to be probably more in line with what you saw in Q1.

Production wise, clearly, for Q2, we reported 2.3 Bcf a day. We're still on track with what we communicated at the prior call, to see a production level get to 2.4 Bcf equivalent for Q3 and then end the year at 2.5 Bcf, of course, next year's plan is we'll get more further refined as we get closer to the end of the year, but that's still on track for 2.6 Bcf equivalent per day. Infrastructure -- i was going to say infrastructure that is needed to deliver on that is all on track. So from a gathering and compression standpoint, that infrastructure has gone into service already. And from a processing standpoint, we're actually seeing commissioning has already initiated for for the processing infrastructure that's going to support this or it's in process. So by the time we get into August, we should see meaningful volume start to flow through, let's just say, the incremental additions. So everything is on track.

Okay. Very thorough. I really appreciate that. You talked about this already on the call a couple of times in some of your prepared commentary in the release. Clearly, Range has tremendous optionality as we had out of '27 to '28. Just to kind of simplify it, is it fair to say if there is a -- that demand pull for Appalachian gas materializes in 2028 as many people expect that investors should expect Range to grow that year, recognizing that you've got plenty of time to decide on that. Is that how people should think about it?

This is Mark. I think at a high level, that is a simple summary of the situation. I mean Range sitting on 30-plus years of Marcellus inventory alone. This is a growth company. But as I framed in my prepared remarks, it's a growth company to meet customer demand. We will feed that as it comes online. So there's nothing to say that Range doesn't double production. I mean even in that case, 30-plus years of Marcellus inventory, hypothetically, it's still 15-plus well over 15-years of inventory still industry-leading. There's nothing in the inventory. There's nothing operationally and there's nothing on the infrastructure side that would prohibit us from pursuing that opportunity provided we were comfortable and confident in those -- in the margins related to those end sales points that was the demand pull scenario.

So it's a little bit early, but we want to keep working through this growth plan we've announced this current growth plan. But as we get a little bit closer to '28, '29 and '30 you could expect us to begin [indiscernible] a little bit more guidance on how we see that unfolding as we see the additional takeaway from the basin come online, the power plants and data centers that we've run through, come online as well as declines from some producers that we're able to step in and either take market share or increase in the absolute as the market needs. So I think you summarized it well, growth is a question of when and how much for Range.

Our next question comes from the line of Paul Diamond with Citi.

I just want to quickly touch base on Slide 10. You guys talked about $5 million to $15 million in spend for future inventory. Can you talk about the opportunity set you see around those the kind of small ball acquisitions given recent volatility. Are the bid-asks widening out? Or is there still kind of a decent clip of opportunity there?

Paul, I think as we start to think about the opportunities in the basin, I think there's probably a number -- from an M&A perspective, I think that list gets smaller. And when you look at some of the activity that's occurred over the past number of years and especially those that could have some industrial logic to really connect with an organization like Range. But as you've heard us say a number of times, one of the beauties of our story is, is we're really not in a position where we have to be, I think, aggressive on an M&A type front.

Instead, we can continue to organically grow. We can double the size of the company. By doing so organically through activity in the years ahead. We've got growing demand that's headed our way. And so the depth of our inventory, just in the Marcellus alone continues to I'll just say, shine in a way that changes the dynamic around the need for M&A versus others. I think there's other opportunities "in-basin" where we see there's some -- still some acreage that could be acquired, that could be complementary and probably more smaller-type components, but there still is some of that, that we could consider investing in. And I think lastly, as you've heard us kind of walk through in the past, we think there are other ways that we can "invest" in the business with cash flow that we generate one being investing in the midstream infrastructure, the other could be other complementary components that allow us to think differently. So anyway, M&A is probably going to be on the lower end of the scale for us. we can continue to chip away our inventory and grow organically.

Got it. And then just one more quick follow-up. You guys talked about the ability to return to pad sites. Just the infrastructure providing kind of a competitive advantage. I think you provide a bit more color on that opportunity set, how much of the acreage is in a similar vein? And how much did the -- I guess can you quantify a bit on what that actually improves on the notional well costs?

When we start to look at the number of pad sites that we have for operations in the basin I'm going to approximate some numbers here, but roughly, it's approximately 250 pad sites. When you look at the number of pad sites that we returned to for incremental phases of development, it's approximately 1/3. And so that when you start to kind of ask the question, I think, around what's the opportunity set, I think one is it's large.

And I think when you look at how lateral links have extended over the last few years, and I know we -- we tend to showcase some of those operational results quarter-over-quarter. But with 20,000-foot laterals now being drilled by Range. Our average is now approaching something that's between 12,000 feet to 15,000 feet on a daily basis. with some of those longer opportunities, touching 18,000 to 20,000 feet it really -- I'll just say, expands how much going back to a pad site can really mean for your ability to drive some of your lowest capital efficiency operations going forward. So we see this as being something that, A, we've now done for I'm going to say probably a decade, if not a little bit longer. And you should expect to see that to continue to be an important component of our overall operation.

Efficiencies when you look back on returning pads with incremental phases of development, we've seen efficiencies improve as much as 30%. That's not on every pad side, but we have seen that on some. And as you would expect, with a very talented team that focuses on efficiencies and rooting out nonproductive time, it really gives us the ability when we go back to that pad site to study what went right and what could be better. And the team does a great job of, I'll just say, further building upon the prior execution and trying to be, I'll just say, execute quicker. And I think you've seen that in the results that we reported this past quarter.

Difficult to frame exactly what that means on a cost per foot basis. I know we've talked about that some, but it's impactful. I'll just say overall, it's not uncommon for it to be a double-digit cost per foot savings on a program a year, but it depends upon which phase of the operation is harvesting that that value. But I think at a high level, you can always make the assumption that we're getting a chance to reutilize the pad site, the production infrastructure and also the roadways, and that's cost that really just comes off the top.

Our next question comes from the line of Phillip Jungwirth with BMO.

A couple of years ago, you guys had shown some slides showing contractual GP&T costs declining through 2030. I think this is mostly on the gathering side, but you'd also referenced some transportation optionality, just on renewal of certain contracts. Just wondering if you could update us on any potential GP&T savings that we could still see between now or 2025 and 2030?

Yes, Phil, thanks for the question. GP&T is obviously a significant investment to underpin our portfolio of transportation options to get to all over the country and internationally. So to your point, an element of our Gathering had and does have declining costs over time. If you think about the full stack of your gathering and transportation, you've got your wellhead gathering system, you've got what I call intermediate transport and your interstate pipelines and the pipeline tariffs. Pipeline tariffs have inflation factors built into them based on various inflation factors and are adjusted for all shippers on those annually. So everyone is subject to an inflation re-rate.

So what you've seen with us holding GP&T relatively flat and improvement over time. And again, for the moment, I'm setting aside the percent of proceeds processing costs related to NGL prices. If you're just looking at the fixed cost or throughput costs, you've seen inflation on the interstate to transport largely offset by the declines on our gathering system. So we have realized those and that's why we've been able to keep a very competitive and stable GP&T over a period of years. So that decline is still embedded in there, and it's helping offset inflation re-rates you'll see in interstate pipelines.

As we look ahead at future opportunities, here recently and over the years, the marketing team does a great job of always trying to optimize what we have. On an annual basis, it tends to be relatively small pieces. It could be 10,000 a day type packages. So if we're releasing or picking up capacity that others are not using. As we approach 15-year marks from, let's call it, inception from the bigger development phase moving into development in earnest horizontally, into Marcellus on the liquid side and on the gas side. We have renewal options on transportation, and those are certainly under evaluation.

As we look at transportation, we always say, we like diversity and outlets. We like having access to markets across the U.S. and getting our liquids on the international market. What it comes down to is we are looking for durable high margins. So that does not always mean purely reducing cost. It's about the strength, durability and growth of those end markets. So with each renewal, we evaluate what the strength of that market with any opportunity to pick up transport, we evaluate the durability, the growth option and the expansion of margin or as we sit here today and talk through power in-basin power demand, be it just general risk on industrial or data centers. And we have contracts, for example, in the Midwest that we announced to a power plant. We look at the value of that transport to see what the growth and the margin opportunity is, and we will certainly have the ability to renegotiate and evaluate releasing some of it based on in-basin -- in-basin demand.

What I would also say is you're seeing a bit of reversion to historical status in the industry as to who owns and who holds transport. [ Range launched], 30 years ago, utilities and others needed surety to supply so they reached out and help transport so that they could pull that supply to their needed markets and fulfill their obligations. You've seen that in newer pipelines, look at MVP. That was largely underwritten by utilities in the Mid-Atlantic region and Southeast. As we look at projects that are being talked about today, newer expansions or new pipelines, it is likely in our assessment that those are underwritten by liquefaction capacity holders or utilities who need that gas, be it down in the ERCOT region, Midwest or Southeast. So I think that gives us additional choices to make, where we already sell into their transport, if they pick it up in basin, but you could also see us as an industry and Range specifically given the significant valuable portfolio we hold, release that and still sell to the same customers, but someone else has that on their balance sheet.

So long-winded answer to your question, we're focused on expanding margins and grow our margins reaching growth opportunities over time. And we certainly have a lot of choices to improve those costs as these contracts reach maturity.

Yes. That's really helpful. And then I was also hoping you could just elaborate by what you mean when you say growth volumes beyond '27 needing a home. Are we specifically talking about supply deals that Range has secured. Do you need more long-haul FT in place, optimization on the NGL marketing side? And how should we think about any additional processing capacity or appetite to sell gas with in-basin pricing?

I guess maybe I'll start this one and Dennis and/ Alan may jump in. But let's start from the end market. We're talking about demand pull and how we think about this. We want a home for the molecules. So take the Midwest example we had at the power plant, that's a clear bilateral agreement that was put in place. But if we can look to a sales point, a sales hub and see and quantify the growth and we can meet some of that growth, we will supply into that growth. It doesn't necessarily have to be bilateral contracts, locking it up, but you do want to know that there's incremental demand.

Said differently, we're not just going to grow a sell it in-basin and hope that finds a home, so hopefully, that gives you a little bit of clarity. As far as then solving backwards from that end market and the customers, of course, there will be some transportation, either in our portfolio already, the customer's transportation or potentially taking market share on existing pipeline to get there much as we did and announced 1.5 years ago with this 20% growth plan. That said, you keep working your way backwards, you'll need access to some processing and some in-basin gathering and compression. That's just as you increase well count, you'll need those types of things. The good news is there is quite a bit of processing capacity in basin, and inventory is not evenly distributed across upstream companies. So we think there's a significant opportunity there for Range to again step into underutilized facilities.

Our next question comes from the line of Neil Mehta with Goldman Sachs & Company.

Dennis and team, I just want to go back to the macro here specifically around dry gas. As I think about the '27 calendar year, I think it surprised us at least to the downside because the demand has been really robust from both data centers, power and then obviously, LNG, but the curve softened by probably 15% this year. And just trying to make sense of it all. Is it -- is it people concerned about Permian production coming into the market? Is it lack of discipline among maybe some of your competitors in other regions because we have agreed with that [ 375 ] mid-cycle view, but I guess the market is starting to say something different. So I'm curious on how you make sense of it?

You bet. Thanks for joining us, Neal. I think when we look at the pricing that you see in the front month, I think there's a lot of reason to see that there is a disconnect between what we think long term the pricing should look like and where we're at today, meaning you're pointing to probably the same things we're looking at. I mean LNG was at around 18 Bcf a day for you're seeing volumes start to go through Train 1 at Golden Pass. Clearly, there's opportunity for that run rate to further improve as the months kind of move forward. And power demand has been pretty resilient from our perspective. I think -- if you look over the past several years, natural gas has continued to play just a real strong role, notwithstanding some fluctuations from time to time with pricing driving some of that change. But ultimately, we're up roughly 0.7 [indiscernible] year-over-year natural gas utilization. And we're seeing the thermal share reach 71% year-to-date.

So I think there's a lot of reasons to be encouraged. I think there's some question marks that probably leave -- I would expect the market to wonder what's around the corner and the proverbial, what are we missing? It does feel like there's a small connection still through a perceived in-ground injection storage level to where we think pricing should be. And we just think as LNG domain continues to grow and other, again, residential manufacturing use, et cetera, that disconnect is -- needs to take place. So I think put differently internally, we would expect in-ground storage levels to reach 3.9 Tcf roughly by the end of the year. That's just an internal view from Range, and that would put you at a days of supply of 38 days. That's 2 days less than where we were last year and even again below where we were the year before that.

If you kind of start to go back to a time frame where over the last few years, where we saw a significant run in price through the summer of 2022, that's kind of right in line. So I do think that presents more volatility. I think that provides some advantages for low-cost producers like Range when those moments happen, much like we saw this past winter. So then I'll just step into those improving environments. LNG is going to continue to grow. It has reached 24 Bcf by the end of 2027. And even though we would expect Lower 48 production to continue to increase. We think by the end of the year, you're probably at 110 Bcf to 112 Bcf per day. But again, there's still going to be an ongoing call for gas. And so I think the big question, Mark, is what commodity price will need to be seen to incentivize growth out of the higher-cost basins, and that puts a downward pressure in our mind to some of this future growth outlook from other basins.

That's great color. We always appreciate your views on the macro. And then the follow-up is on Midstream. I think you alluded to the fact that maybe it's an area that you'll take a look at. I mean, one of the advantages of the range model is you are so capital-light and you've got some great midstream partners. So like what is the right size of midstream investment in the context of the portfolio? And what would be the advantages of leaning in versus staying or a third party like you are right now?

Well, I think as we -- as you heard Mark talk about what the future growth looks like, I know I weighed in on that as well. If you start to think -- I'll just play out a scenario here, what it could look like is, let's just say you wind up with a supply deal that involves some volume of incremental gas and production, say it's [ 200 million barrels ] a day plus or minus, it would allow us the ability to think differently about, let's just say, the full cycle economics of those incremental molecules instead of looking across the blended GP&T structure alone. So it allow us to think about what is the economic benefit if we were to invest in, let's just say, the gathering and compression for that respective incremental set of molecules versus following the traditional feed-based structure alone. So it's a great position to be in because of the durability of the business and the cash flow that it will throw off, we can tie that to the pricing that would be received -- and so I think there's a way that we can think differently about go-forward growth instead of just looking at it as [indiscernible] that incremental fashion versus looking at is it a blended component over the overall production profile.

So I think that's the way we would start to think about it. And even in a fashion of how do we basically look at how we even have competition across our inventory base where, is it dry gas or is it going to be provided with a liquids-rich component. So adding that competition component in there, we think both internally and externally to some of our service partners, we think, will play a strong role.

Thank you. Ladies and gentlemen, we are nearing the end of today's conference. We will now go to Gabe Dow of Truist for our final remarks.

Dennis was hoping maybe just for clarification, I suppose, on this year and next year's CapEx just given some of the movement on the drills that you highlighted. So I guess if you still turn on 900,000 lateral feet in '27, is it fair to still think about CapEx as being $700 million for next year? Or is CapEx flies higher next year to gear up for '28 growth like you alluded to?

Yes, Gabe, thanks for joining us. The capital should be the same as what we've communicated. The only difference that you could see from the program that, in my mind, would be is, is there something that gets announced that will require some other, let's just say, investment for a larger growth profile than what we've communicated. But as it stands today, there's really no changes. There's just been a small re-sequencing of some of the activity, but it should have a similar capital program for next year that you've seen in 2026.

Okay. Very clear. And then I guess, hypothetical question, but for '28, if things align, you maybe get a co-sales agreement. If you were to run 2 rigs to crews or turn in line another 900,000 feet, what's the growth magnitude relative to '27? I'd imagine you're over 3 Bcfe a day. Is that fair?

I think that is a very possible scenario when you look at what the company could deliver within that following 12- to 18-month type time frame.

This concludes today's question-and and answer session. I'd like to turn the call back over to Mr. Degner for his concluding remarks.

I'd just like to thank everyone for joining us on the call this morning. Again, it's been an exciting quarter for us, and we look forward to the second half of the year when our production growth profile really starts to shine. We look forward to the next call and visiting with many of you on the road in the months ahead. If you have any follow-up questions, please don't hesitate to reach out to our Investor Relations group. Thank you.

Thank you for your participation in today's conference. You may now disconnect.

Good morning, and thank you for joining the Range Resources Corporation Annual Stockholder Meeting. I am Erin McDowell, Corporate Secretary for Range Resources, and I want to welcome you to our annual meeting. Our annual meeting will consist of a short formal meeting. And if you have questions about the matters addressed at this meeting, please reserve those for the end, and we will do our best to respond during the meeting or follow up with you as needed. For any other questions about the company, our Investor Relations team is, as always, available to speak to you.

At this time, I will turn the meeting over to Greg Maxwell, Chairman of the Board.

Thank you, Erin. Good morning, and welcome to the 2026 Annual Meeting of the Stockholders of Range Resources Corporation. I'm Greg Maxwell, Chairman of the Board. With us today are my fellow Board members, Brenda Cline, Margaret Dorman, Charles Griffie, Chris Kendall, Reggie Spiller, and Dennis Degner, our President and CEO.

Also joining us today is Cameron Darden with our independent auditing firm, Ernst & Young. On behalf of the entire Board, I want to thank you for voting your proxy this year, and I assure you that the Board carefully considers the results of each year's proxy vote and making decisions about the company. Erin McDowell, who is our Corporate Secretary, will serve as Secretary and record the minutes of this meeting. Aaron has also been designated to serve as the inspector of election of this meeting, and she has confirmed that a quorum is present. Erin?

Thanks, Greg. Under the company's bylaws, the Board of Directors set March 16, 2026 as the record date. Notice of this meeting was sent on March 30, 2026. There were [ 235,484,929 ] shares of common stock outstanding on the record date. On request, we will make available an affidavit related to such notice and a certified list of the company's stockholders as of the record date, compiled by the company's transfer agent.

Each outstanding share of common stock is entitled to 1 vote on the matters presented for a vote at this meeting. If anyone has a proxy for a stockholder or wants to vote at this meeting, please e-mail a copy of your proof of stock ownership and your vote to [email protected] at this time.

The proposals to be considered at this meeting are as follows. The first item will be the election of 7 directors to serve on the Board until the next annual meeting. Since it is an uncontested election, the stockholders will elect directors by a majority of vote as provided by the company's bylaws. The second matter will be to consider and vote on a nonbinding proposal regarding executive compensation. The third item is a proposal to ratify the appointment of Ernst & Young as the registered public accounting firm for our 2026 fiscal year.

Now turning to the voting results. There are 217,918,195 shares of common stock represented at this meeting, equal to 92.56% of the outstanding common stock of the company. In voting for directors, the vote in favor for is as follows: Brenda Cline, 98.93%; Dennis Degne, 99.25%; and Margaret Dorman, 98.89%; Charles Griffie, 98.72%; Chris Kendall, 98.95%; Greg Maxwell, 99.01%; and Reggie Miller 96 -- I'm sorry, Reggi.e. Spiller, 96.52%.

In the advisory voting on the executive compensation proposal, it was approved with 98.61% of the votes cast. With approval of 98.28% of the votes cast, Ernst & Young LLP was ratified as the company's registered public accounting firm for 2026.

Thank you, Aaron. There being no further formal business to conduct, the meeting is now adjourned. If you have any questions, we will take them now. As I mentioned before, we would appreciate you directing your questions to the matters addressed in our meeting.

Mr. Chairman, we have no questions.

Very good. Thank you, Aaron. There being no further questions, I would like to thank you for attending our stockholder meeting and for your interest in and support of the company.

This concludes today's conference call. Thank you for participating, and you may now disconnect. Everyone, have a great day.

Hello. Welcome to the Range Resources First Quarter 2026 Earnings Conference Call. [Operator Instructions]

Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements.

[Operator Instructions] At this time, I would like to turn the call over to Mr. Laith Sando, 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 Scucchi, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we 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 at your 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. 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 and 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 $139 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 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 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 cost 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, and it is a key contributor to Range'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 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 continue 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 the 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 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 time ] storage balances and improved 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 midweek in late January when Henry Hub and 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 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 continued 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 3-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 strength 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 strength 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 cost 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 linked to prices for natural gas via electricity and pipeline fuel costs and natural gas liquids via a percentage of proceeds processing cost. So the costs are aligned with sales, such that as we experienced 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 experienced the proper linkage where we incur lower expenses when realized prices decrease, enhancing Range's resilience through cycles. So 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 degeneration 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.

[Operator Instructions] Our first question comes from the line of Jake Roberts of Tudor, Pickering, Holt & Company.

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 [indiscernible] 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.

For the last question first. 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 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, 2 months, 3 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 tied 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 chem, heating, consumer demand on U.S. molecules on the water. So in 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 Mont Belvieu.

Yes, 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 [indiscernible]

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. But in addition, if I were to put some context around it, there's probably a little over a dozen projects that were 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 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 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. 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 will 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 surety 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.

Our next question comes from the line of [indiscernible] with Truist.

If we could maybe start with the 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?

Yes. 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 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 characterized to what we had a year ago. Several of the turn-in lines that occurred toward the back end of Q1, we'll now start to pack the system of available infrastructure that we have. And what you'll see is has been 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 into service towards the end of Q2, and the processing will be right there at the midyear 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 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 Bcf a day type number in 2027.

And to kind of answer your -- and everything is on track from an infrastructure standpoint for this year. And 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 what -- 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. 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 will -- 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 million to $600 million type range, where we can hold that 2.6 Bcfe 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 wage of growth as we see more demand take shape.

Got it. Okay. That's really clear. And then maybe just my second question back to the LPG side, and I appreciate all the prepared remarks and the answer to the earlier question, but curious if you could maybe put a little bit of a finer point or updated thoughts on the macro, given all the domestic and international moving pieces and even maybe elevated shipping costs. [indiscernible] comes on around midyear. So U.S. propane exports grow to 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 PDH run rates and maybe any other puts and takes that could ultimately impact the premium that you expect over Belvieu?

You bet you. 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 DUC 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 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. 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 story is flex capacity that's gone into service out of the Gulf that adds in at the 360,000 barrels a day of export capacity. I think that was originally earmarked for more ethane service, but it's now been put into [ OPG ] service, and the first vessels have actually left the DUC. 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 take 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 it's -- as we're all trying to navigate these particular moment, the reality is that the business has actually been as resilient as we've seen as has 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 Repauno 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 to say, we've got demand growing, run rate show to be improving, and we would expect in the longer term stock levels to get re-equilibrated over the balance of the year.

Our next question comes from the line of Neil Mehta with Goldman Sachs & Company.

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

Yes. Good question. This is Alan. I manage the marketing group. So I'll take a stab at answering your question there. When we look back at the realization during the first quarter on the NGL side, really 3 main drivers. So we'll go back to January, winters 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 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 1/3 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, and we were able to realize good prices with sales within the U.S. 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 events in Iran with a terminal that went down in Saudi Arabia, and that, despite the international prices, which then spike better returns at the DUC for us.

So you add all those 3 things together, it was a good quarter. Things aligned very well. We are 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, yes, 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 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 precrisis levels. That is now somewhere around, call it, plus 30% or plus 40% relative to precrisis levels, still very attractive but not quite what we were seeing in the middle of March. And we would expect that going forward, even if there is a solution, let's say, if the Street ever 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 of 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 [ 6 under 0 ], right? So the question is, as those molecules move down to the Gulf Coast, what could that mean ultimately for the whole North American pricing system? So 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?

Yes, 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 now several years. But when I think about what's going on, really rig count hasn't changed appreciably since the beginning of the year if you were to just kind of look at those dynamics. So 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 been an increase in completion crews. I think roughly -- 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 falloff 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 from a standpoint of activity. And 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%. So when we think about the nat gas macro and you start to couple together all of those fun facts, I think our view is there will be some gas growth out of the Permian. But 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. And so 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 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 at about 37 days. That's about 5 days below the 5-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.

Our next question comes from the line of Paul Diamond with Citi.

Just wanted to touch on your OpEx and numbers you've touched. It's historically been that every dollar moved in NGL is about a cent in [ GP&T ] and then about $0.02 to $0.03 per dollar movement 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.

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, in particular with the winter weather in the first quarter when we saw [ 469 ] in January gas, [ 746 ] in February, back down to March at [ 297 ], you've got a situation that made it more apparent what cost the industry as a whole, carries as it relates to cost of electricity and fuel for transportation of gas or interstate pipelines. So 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 of NGLs is about $0.01 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. 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 shrunk in commodity price down cycles as well. So it's the right way risk.

So hopefully, that answers your question, but we like the structure a great deal because it gives us flexibility that 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 burn in the DUCs or bring down the DUCs part of the growth prospects, I guess how much -- is what level of reactivity in the production split do we expect to see the current conditions shift this? Any like kind of leading towards sort of more wet versus dry gas? Or is it all pretty much set for the coming quarters?

Yes, 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%, it's maybe 65% on the liquids activity and then the remaining more on the dry gas side. And that's for 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 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 heavily focused on the liquids-rich activity thus feeding not only the processing capacity and gathering that's going into service, but also that Repauno terminal capacity that I mentioned a little bit earlier that we'll go into service roughly around the first of the year. So 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.

And 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. And 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 like the next 6 months of 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, and then we'll reevaluate what's the right plan for beyond 2027.

Our next question comes from the line of Leo Mariani with ROTH.

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 in the 2Q. I 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.

Yes, Leo. So 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. So a way of thinking about it for maybe a little bit more color, roughly, the completion side is going to be -- it's a 2/3, 1/3 roughly split. So completions is roughly 2/3 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, think about what you've seen 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 I'd 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, but the kind of 17 stages per day type efficiency levels that the team has been able to capture. So -- but yes, 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 towards 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 roughly 2.3 Bcf equivalent per day towards the midyear point that gets us up to 2.5 Bcf 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?

Yes, 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 over the next couple of years, we'll 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's shares, modest growth as the market calls for it. It has compounded where single-digit growth becomes double-digit cash flow per share growth quite easily with the share repurchase 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're 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 we'll continue to be able to buy in shares at better pricing by being somewhat picky and when we lean in. But what that means is as we 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 to 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. I 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.

Our next question comes from the line of Kalei Akamine with Bank of America.

My first question is on NGLs. So really appreciate the macro commentary that stronger DUC utilization could life 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. So 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 trying to -- I'm thinking -- so you're asking how this market is different from in the past. And I guess I'd say the biggest difference this time around is the closure of the Straight 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. So roughly 30%. That has been roughly, I would say, 70% of that, so 1 million barrels per day has been absent from the market for the past 6 weeks. It will 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. 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 olefins down to feedstocks such as LPG and ethane. 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 precrisis 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 guided quite a bit in '25. We have new capacity that just came up last week. We have more capacity coming on into 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 we'll 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. Hope answers your question?

And I'll add in here, Kalei. I think you mentioned TTF is in 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 Bcf 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 the 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. 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 margin or 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 all these other facilities and continue to grow quite substantially, another 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 and 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 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. 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 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.

That's excellent. That's a very thorough explanation. And thank you on 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 or 20,000 barrels of the NGLs will be sold from the new East Coast stock. Can you share anything about the split of those products, whether it's ethane or LPGs? And how -- and should we expect anything different from [indiscernible] of contracts versus what you currently have?

Yes, 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+ 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 you saw where 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 that 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 Repauno 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. But however, we tend to, obviously, 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 characterized very similar to what you've seen us execute in the past.

Thank you. Ladies and gentlemen, we are nearing the end of today's conference. We will go to Phillip Jungwirth with BMO for our final question.

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 would expect to be in the 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 -- or if 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 down cycle if the stock prices 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 the calculation this is given your marketing contracts are, are there a 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?

Yes. There's a number of different contracts that go into that, but we've got a 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 Belvieu-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 and 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, we were plus $1.25. That's in a world where Mont Belvieu 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.

Thank you. This concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Degner for his concluding remarks.

Yes. 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. Thank you.

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

Thank you for standing by. Welcome to the Range Resources Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions]

Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks, there will be a question-and-answer period.

At this time, I would like to turn the call over to Mr. Laith Sando, SVP, Investor Relations at Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, everyone, and thank you for joining Range's year-end 2025 Earnings Call. With me on the call today are Dennis Degner, Chief Executive Officer; and Mark Scucchi, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we've posted on our website. We may reference certain slides on the call this morning. You'll also find our 10-K on Range's website under the Investors tab or you can access it using the SEC's EDGAR system.

Please note, we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. We've also posted supplemental tables on our website that include realized pricing details by product, along with calculations of EBITDAX, cash margins and other non-GAAP measures.

With that, I'll turn the call over to Dennis.

Thanks, Laith, and thanks to all of you for joining the call today. In the fourth quarter, Range continued its steady progress on key themes that we have discussed over the past year. We executed on our plans safely and efficiently, delivering consistent well results, free cash flow, returns to shareholders and steady activity levels that support Range's multiyear development plans we previously communicated. All-in capital came in at $183 million, while generating production of 2.3 Bcf equivalent per day for the quarter.

For full year 2025, we invested $674 million in capital, placing us squarely within the previously improved guidance while generating production for the year at approximately 2.24 Bcf equivalent per day. This production level was a result of strong well performance and continued optimization of gathering and compression infrastructure that was mentioned on our previous calls.

Diving into the quarter. Range operated 2 horizontal rigs, drilling approximately 225,000 horizontal feet across 15 laterals, averaging 15,000 feet per well. For the year, the team drilled 69 laterals with an average horizontal leak of 14,800 feet with our total activity exceeding 1 million lateral feet drilled. Our large contiguous acreage position affords us the ability to drill these type of long laterals, increasing efficiencies and allowing us to access more reserves from a single location, all while reducing our overall development footprint and consolidating infrastructure requirements. For completions, the team ended the fourth quarter completing approximately 1,200 frac stages. Completion efficiencies for the fourth quarter approached 10 frac stages per day per crew, pushing our 2025 totals to nearly 3,800 total stages and setting a new yearly frac efficiency benchmark of 9.7 stages per day.

While we are proud of these achievements, we are equally proud that the team accomplished this while delivering on one of our best safety performance levels for the company. During the quarter, our supply chain team also completed the annual RFP for services process. The result was pricing for 2026 drilling and completions materials and services, that are flat to slightly lower than 2025 levels. In addition, multiple long-term agreements are in place to provide service pricing stability throughout the year, including the continued use of a base electric hydraulic fracturing fleet, which began a new 2-year term agreement on January 1, 2026. Our RFP results, coupled with our operational efficiencies, should continue to provide a strong foundation for peer-leading well costs and capital efficiency while creating options for future growth.

Shifting over to marketing. Consistent with themes we highlighted on the last call, U.S. energy exports continued to set new records in the fourth quarter of 2025. We are seeing this across both natural gas and NGLs as global demand for reliable, affordable supply continues to support growing exports from the U.S. for multiple products. For context, LNG exports averaged over 17 Bcf per day in the fourth quarter, which was up 10% from the previous quarter.

Waterborne ethane exports were estimated at 622,000 barrels per day for the quarter, up over 40% year-on-year and 24% sequentially. And lastly, LPG exports were up modestly year-over-year and are expected to benefit significantly in 2026 from new U.S. export terminal capacity. We believe this will be helpful in improving propane storage levels over the course of 2026, particularly on a days of supply basis.

In January, winter storm Fern proved to be a meaningful demonstration of the energy security provided by America's position as the world's leading energy exporter, as demand for natural gas to feed power plants and heat homes increased rapidly for several days in late January. Approximately 5 Bcf per day of LNG feed gas was redirected to serve the needs of U.S. citizens. Then when temperatures warmed closer to normal levels, LNG feed gas exports ramp back up to pre-storm levels just as quickly. This weather also provided for strong bid weak pricing for the month of February, which settled at over $7 per MMBtu.

The gas marketing and operational teams did a superb job coordinating a production and sales plan, locking in strong free cash flow by selling nearly all of Range's natural gas during midweek. At the same time, the liquids marketing team picked up additional revenue by optimizing ethane extraction and selling more BTUs locally as natural gas. During the quarter, Range also executed a long-term sales agreement that will lead gas from our planned processing expansion to a new power plant in the Midwest. The plant is expected to start up in late 2027 with the transaction set at an attractive premium relative to a Midwest Index.

In addition, we continue to support the development of a number of prospective projects in the power generation and data center space. While many of those projects are concentrated in our backyard, we are also seeing interest in other regions where we have transportation capacity as evidenced by the deal just mentioned. We believe there will be several near- and medium-term opportunities for Appalachian Energy to meet the growing demand for energy in North America and around the world. We look forward to reporting on more Range specific opportunities as they progress.

Now turning to our go-forward plans. Range's strategic multiyear operational plan has built up more than 500,000 lateral feet of growth-focused inventory to support future development. This is approximately 100,000 more lateral feet in inventory than previously discussed, as a result of the continued strong drilling performance mentioned earlier. This additional DUC inventory provides Range added flexibility to align our future reinvestment plans with market fundamentals. Simplistically, we can reduce our previously communicated 2027 capital. It still produced 2.6 Bcfe per day next year. Or we could maintain a similar operational cadence with $650 million to $700 million in capital for 2027 and set up continued growth into 2028. So we are in a great position to see how demand shapes up over the next 24 months and respond accordingly.

Looking more closely at 2026, we expect to continue an operationally efficient program that utilizes a single full-time super-spec drilling rig paired with a second rig utilized throughout the second half of the year. On the completion side, we anticipate running a single full-time electric frac crew while picking up a spot crew for the second and third quarter to harvest some of our DUC inventory. This drives an all-in capital budget of $650 million to $700 million, which consists of the following: Approximately $500 million of maintenance D&C capital, an incremental $120 million to $140 million of D&C growth capital that is primarily allocated to a second completion crew, $15 million to $35 million in land for targeted acreage. This acreage capital is less than prior years as we have held more acreage with production, allowing maintenance land spend to decrease.

Also included in the acreage budget is capital that supports increased lateral lengths, which can offset some or all of the lateral footage being turned to sales during the year.

And lastly, we also plan to invest $15 million to $25 million for software and production facility upgrades to further reduce emissions. And by year-end, we will have completed the pneumatic retrofit project that was started in 2024.

This total capital investment plan of $650 million to $700 million is consistent with prior discussions and will result in production of 2.35 to 2.4 Bcfe per day, while carrying significant momentum into 2027. Looking at the year ahead, the shape of our production profile is expected to look similar to prior years as we project first quarter production to be down versus Q4 of last year.

As we commission sizable gathering and processing expansions at midyear, you will see production step up meaningfully in the second half of 2026 and continue into 2027. We are excited about how the company is positioned today with financial and operational flexibility that allows us to efficiently align production growth with sales to known end markets while generating free cash flow and returning capital to shareholders. We believe our robust inventory and relatively low capital intensity provides Range a differentiated foundation for generating through-cycle returns for our investors.

I'll now turn it over to Mark to discuss the financials.

Thanks, Dennis. 2025 again demonstrated the strength of Range's business. Throughout commodity cycles, we intend to generate free cash flow, prudently invest in the business and return capital to shareholders. Range accomplished just that generating cash flow from operations before working capital of $1.3 billion, and over $650 million in free cash flow, while priming the business for future growth, enabling an operational and reinvestment strategy that maximizes our competitive advantages to enable value capture from increasing long-term demand across the U.S. and internationally.

Consistent with prior years, Range's free cash flow was enhanced in 2025 by realizing a price greater than NYMEX Henry Hub. NYMEX natural gas prices averaged $3.43 for the year, while Range achieved an average hedged realized price of $3.60 per unit of production, a $0.17 premium created by commodity mix, hedging strategy and our advantaged portfolio of transportation and sales contracts that provide access to geographically diversified sales points linking Range to customers in key U.S. and global markets, delivering roughly 90% of revenue from outside Appalachia.

Alongside higher realized prices year-over-year, Range expanded its margins, growing per unit of production cash margin by roughly 20% to $1.64 per Mcfe or approximately 3x our maintenance drilling and completion capital per Mcfe. Premium pricing, strong operational execution and competitive full cycle costs generated enhanced free cash flow and enable growing shareholder returns.

Range paid $86 million in dividends, invested $231 million in share repurchases and reduced net debt by $186 million while investing in operations that support our growth plans through 2027. Over the last several years, Range has reduced debt by a total of roughly $3 billion. With a strong balance sheet, we have increasing flexibility to make opportunistic investments. As of year-end, Range has purchased over 33 million shares since the program's initiation in 2019. investing $744 million during that time frame.

To position the share repurchase program for the future, our Board has increased the currently available capacity to $1.5 billion. In addition, the fixed per share dividend is something that we expect over time to grow slowly and reliably. We expect to increase the quarterly dividend by $0.01 per share or 11% at the next announcement.

We critically evaluate investment opportunities and shareholder returns with an unwavering focus on sustaining and further enhancing Range's core objective, durable and growing per share free cash flow. To achieve that objective, we seek to enhance our low full cycle cost structure, low reinvestment rate and durable margins. Like Dennis mentioned, Range could hold 2.6 Bcfe per day of production with less than $600 million of annual drilling and completion capital or less than $0.60 per Mcfe.

Here's a key message we repeat today. We can thoughtfully grow Range's business in conjunction with increasing market demand, allowing us to grow the value of the business and deliver additional returns to shareholders. This is a consistent long-term strategy underpinned by quality long-duration assets and a strong balance sheet.

As the U.S. and global natural gas markets continue to integrate with commissioning of LNG facilities, while domestic demand grew substantially, primarily from the need for additional gas-fired electric generation, we believe Range's long-life inventory, creates enormous option value by serving an integral role as a long-term energy supplier. Our durable free cash flow, evidenced through cycles, positions Range to consistently deliver value to its shareholders.

Dennis, back to you.

Thanks, Mark. Range's results continue to reflect a consistent theme. Strong operational performance against our stated multiyear plan, consistent free cash flow generation and prudent allocation of that cash flow, balancing returns of capital, balance sheet strength, and the optimal development of our world-class asset base. As we sit here today, our multiyear plan communicated just 1 year ago is on track in generating the results you've come to expect from Range. Years of disciplined planning have placed us in the strongest position in our company history, having derisked the high-quality inventory measured in decades and translated that into a business capable of generating significant free cash flow through cycles, and we have more opportunity in front of us more than ever.

With that, let's open the line for questions.

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

Could you give a little more color on the cadence of production you're expecting in 2026. I know you said there's a step up in the kind of the mid part of the year. But give us some context on the size of the step up. What's needed to get there in terms of infrastructure adds. And just more broadly on your typical cadence. Would you guys ever look to effectively drive higher production in sort of the first quarter versus, say, the midyear, given that you do see much more premium pricing, especially in Appalachia during the winter?

Scott, thanks for joining our call this morning. As we start to think about 2026 and the production cadence, I know you heard us touch on this during the prepared remarks, but really the character will look in the first half of the year pretty similar to what you've seen from us over the prior several years where you see a ramp at the end of the year with turning lines that get executed and wells completed in term of sales, let's just say, during the mid part of that prior year. And then that carries momentum into improving commodity prices, which you're pointing to and in the winter months. And so that's what you'll kind of see from us through this cycle as well. So on a relative basis, Q4 was roughly 2.3, you'd expect Q1 to look roughly like 2.2 Bcf equivalent per day, with some of the fluctuation also being driven by ethane extraction fluctuations, where we had a real opportunity to take some rejected into the gas stream, take advantage of some pricing opportunities during the last few months and then turn that back into ethane extraction when you see prices that fluctuate back the other way. So all in all, about 2.2 Bcf in the first quarter. Between now and the first half of the year, when we see the next wave of infrastructure get commissioned, you would expect to see us be kind of between that Q4 level and Q1 as we continue to utilize existing infrastructure at -- I'll just say at a high level of utilization. At the midyear point, we've got some processing that comes online. That's around 300 million a day of capacity -- processing capacity that will go into service. Then on the back end of the year, that's where you'll see the ramp really take shape that carries momentum at the back end of '26 into improving commodity prices for the winter of '26-'27, and then through '27 as well.

So what should the end of the year look like? Our forecast internally has us at a year-end type production level of 2.5 Bcf equivalent per day. So plus or minus around that level. So significant ramp at the end of the year on the back of turn in lines in the middle of the year, second frac crew for Q2 and Q3 and kind of carrying that momentum in 2027. So it should be an exciting year for us as we think about our production profile and activity.

I appreciate that. That's helpful. And then as my follow-up question. Obviously, all signed that -- a power contract for the Midwest. And you talked about potentially some other things out there that you'll continue to evaluate. Can you give us a little bit of color on what kind of premium you were able to capture there? Like what is the benchmark we should be thinking about? And how much of an uplift? And do you see a lot more of these opportunities like this? And what do you kind of see that maybe through the next year or 2?

Yes. As you can imagine, we're pretty excited about the announcement, and we've been really talking about this for the better part of a year now around these kind of opportunities in the background, lots of discussions being had between -- just Range -- between Range and end users that are needing a surety of supply for a multi-decade investment decision for infrastructure. So we think in some ways, this is the first of many opportunities you could see Range participate in. Again, as you've heard us talk about, given our are really depth of inventory and the quality of it and the diverse transportation portfolio that we have that allows us to not only consider building or supplying for energy demand in the basin, but also kind of in the region. So we think there's a lot of reasons for us to be excited about as you can probably tell from my voice this morning.

So what's out there that's in addition to this? I mean I think the deal that we signed, though it's difficult for us to share the confidential terms of that arrangement today just given some ask we have from the counterparties associated with it. This is also something that's scalable. So we see there's additional conversations around how we could participate in the scalability of not only this particular infrastructure but also what builds out in the region.

And then, of course, you've got closer to home the Fort Cherry project, which we're continuing to see what I would say, reasonable progress to narrow down to an end user that could utilize gas that's right out of our producing assets that the facility would be built right on top of us. So I think there's a lot of ways for us to win is what I would point to, whether it's utilizing our transport or building direct -- or seeing someone build directly behind the meter right in the heart of the field where we produce our NGLs and our natural gas. And I think it was encouraging last night during the state of the union to also see some commentary around the willingness to encourage end users to, I'll just say, bring their own power. And so we think that aligns really well with companies like Range, which again, are going to have multi-decades of Marcellus high-quality inventory that can provide us significant backstop to those future needs.

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

For my first one, you laid out optionality beyond 2027, where you can either continue growing production or hold at that 2.6 Bcf a day level. Can you walk us through what signposts or criteria will ultimately drive that decision? I know there's a lot of time between now and then, but I was just curious whether this decision would be driven by a view on the commodity or more demand-led like tying growth volumes to additional gas supply agreements?

Yes. Thanks for joining us. When I think about the next couple of years, really the production profile that we've laid out really starts with a couple of things and primarily it's generating free cash flow. And when you think about how lean the operation is with 1.5 drilling rigs and 1.5 frac crews, you're really talking about a low capital-intensive business for us that allows us, due to the inventory and productive capacity that we've built over the last couple of years, it allows us to really generate that thoughtful wage of growth through the next couple of years and doing so in a capital-efficient manner that would be difficult, we believe, to replicate by others in the sector.

And then I think when you think about the other drivers, clearly, we feel like commodity pricing back to the cash flow statement is in place both on the side and on the NGLs that would support this production profile. And we also have transport that goes along with it to feed future growing demand. We were able to pick up some capacity on Energy Transfer's Rover system a year ago. That capacity is not an expansion, but it's actually taking on market share out of the basin. So think about it as being growth for Range, but not necessarily growth for Appalachia. And again, we think that was part and parcel because of our ability to have a longer-term view for demand and also our inventory and getting our inventory and production to that in demand use. So -- as I think about the next 24 months, if I kind of take a step back, we've got the infrastructure in place. We've got the inventory and very capital-efficient program to help deliver that into that expansion of infrastructure and growing demand over the next 24 months.

The exciting thing is, we really have the ability when you start to think about beyond 2027, we've got really a theme that you've heard us say over the past few earnings calls. We've got a lot of flexibility built into the program where we could pull down capital and maintain a production profile that's in excess of 2.6 Bcf equivalent per day in '28 and beyond, with something that's in the neighborhood of sub $600 million in CapEx or think about it differently, less than $0.60 per Mcfe. Or we can continue to have a thoughtful wage of growth, depending upon future demand and deals that are worked on, on our end, as evidenced by our announcement today on the marketing side, we would have the ability just to continue this momentum with a capital profile that looks very similar to what you've heard us communicate for 2026. So we really think we've set the business up for the right kind of optionality as demand continues to materialize, and we would be able to deliver into that space in a very capital-efficient manner that you'd come to expect from us.

I appreciate all that color. For my follow-up, your 2026 gas differentials are roughly in line with where you've been running. I wanted to get your views on at what point would you expect structural in-basin demand growth to begin compressing Appalachian basis differentials? And does the current guidance already embed any early benefit from the mid 2026 takeaway additions? Or is that a '27 and beyond story?

Yes, this is Mark. I'll kick that one off. As we begin the year with guidance, really, it's driven by the significant portfolio of transportation options that we have, where we're delivering gas outside the basin. So it's what the market indicated levels are at the myriad of sales points we have across the U.S. So that also baked it into account the seasonality that is a natural part of the business and a natural part of prices across the U.S. for those differentials. Now as we set that guide based on market levels at the beginning of the year, also keep in mind over the course of the year, that Range's marketing team has been at this for a long time, optimizing that sales portfolio, optimizing around opportunities to present themselves based on weather or other needs or interruptions in service by some parties and our extremely high levels of uptime and being able to capture market runs, be it weather generated opportunities or otherwise. So those numbers do get refined over the course of the year, but it does all come back to the portfolio of transportation options we have.

And then one other piece I would say is the team's ability to provide some stability and predictability in pricing that's realized. It's been Range's practice for a long time to take pricing at first a month for about 90% of our production volumes. So that has proven to be a very successful way of capturing strong prices when they present themselves, providing stability and predictability in your realizations.

The other piece of it is based on the fundamental research we do internally, of course, supplemented with outside research, we can shape that a bit. Sometimes it's more than 90% perhaps, but sometimes a little bit less. I would also layer into that something Dennis mentioned a moment ago that we can alter ethane extraction levels. and increased natural gas sales or ratchet up the extraction levels of ethane prices and net margins are better. So there's a whole host of factors that play in there to that basis differential. But again, what it all comes back to is the business that has been built on top of Range's assets and that footprint that allows us to access a host of markets across the U.S. and maximize the value of each molecule we produce. It's about growth and cash flow. It's about growth in cash flow per share, not just about growth or production or scale for scale's sake.

The next question is from Doug Leggate of Wolfe Research.

Dennis, I wonder if I could ask you about the cadence of the DUC capacity. I mean you've given a little bit of color here, but you obviously have a lot of options here. Gas prices have weakened again. So what would cause you not to bring on DUC production if gas prices did indeed prove to be softer for the balance of the year?

Yes. Doug, I think when you look at the balance of the year and the timing at which the infrastructure, let's just say, basically starts to come into service, which would really be end of Q2 type time frame, we kind of feel like the timing really works well when you start to think about the wells that will get turned in line or a portion of that DUC capacity that starts getting completed in the second quarter and then our ability to basically then start to see that production turn into spending the sales meter through the back half of 2026. So we feel like the timing is set up complementary to improving pricing as you start to get into the end of of injection season, which internally, our view is depending upon just a normal weather outlook for the summer, we would anticipate to really see a number of around 3.6 to 3.7 Tcf. So -- in the ground. So with that in mind and the infrastructure, the timing, we feel like it really is kind of coming together as expected.

We'll have around 900,000 lateral feet that gets turned to sales in the balance of 2026. But just like you've seen in the past few years, there's always some flexibility that we leave in the program to, we'll just say, take advantage of different commodity price signal. So as an example, some of our dry gas is right now planned to turn in line toward the end of the year, as you would expect, to take advantage of improving fundamentals as we start to go into the winter out of our Northeast PA asset.

So we think we've got the right playbook in place for now, but we always leave some flexibility that we can also take some of those TILs, push them deeper into the year if the signals warrant. But when you look at where we are from a commodity price standpoint, how we risk the program, we feel like the cash flow we've communicated that would be delivered from the business is intact. We also feel like the reinvestment rate will remain really low going forward. So we feel like the fundamentals are all really there for us today.

I appreciate that. I guess it's kind of a curtailment strategy, but not quite, if you know it. I mean, it's -- in terms of selling into the strength of the market. I was just trying to understand the physics of it. My follow-up is, if I could kind of play it to you like this, your balance sheet is in terrific shape. You don't really need to hedge because you're breakeven is as low as it is. And I guess my question is we're all used to the entire industry for the last however many years we've been doing this [ 20, 30 ] years selling into midweek just because that's the way the industry works. But it seems that you leave an awful lot of spikes on cash market pricing. Now I might be oversimplifying it, but -- but I guess my question is why Bidweek sets the pace given how good a position your capital structure and so on is in at this point? Why not let more float on the cash market? And I'll leave it there.

Yes, a really good question. I think what I would do is take a step back and really just spend a couple of seconds here talking about how we view Bidweek. And I think if you were to ask the question or look back at when we talked about Bidweek and our participation, I think roughly what you've seen us commit to is roughly plus or minus 90% to be committed in the Bidweek process. But what goes into that is really a I'll just say, utilizing internal resources, a multidisciplinary team. It's very talented that imbues some of the same expertise that is a part of our hedging committee to also our operations team. And how are we viewing let's just say, what lies ahead. From weather, from a macro perspective, also to any operational maintenance that we would expect in new well turn-in lines.

What that does mean is that we do toggle as we walk into the bid week based upon what pricing we see at that time versus what we believe to be most reflective of what the next 30 days reflects. So you do see us toggle that percentage contribution into the Bidweek that's committed. As you think about February, as an example, we kind of walked into that time frame with a much stronger view on the pricing on the front side. So we put 97% of our gas into the Bidweek process to try and capture what we believe was strong pricing and turned out to be excellent pricing. But there are other times when we back off of that to also have more exposure into what we believe is fluctuations in commodity price.

And then, of course, lastly, some of our new production may not always go into meeting new well turn-in lines may not always be accounted for in that Bidweek process. So again, we could capture pricing through the balance of that 30-day cycle. So shortly or just put simply, I think we try and balance both, but it really is a complicated process that we try and walk through to make sure that we're delivering the best returns.

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

Dennis, I appreciate the color on kind of the 2027-plus time frame. I was wondering if you could opine on where you view service costs over that same time period. And really what I'm getting at is their willingness to convert some of that DUC backlog into a more of a deferred till approach, if you do expect service costs to rise over the coming years and also potentially to be a little bit quicker to the market with volumes potentially in a better pricing scenario?

Yes. Jake, I think when I start to think about the upcoming couple of years, I think the reality is, is we have baked in a lot of flexibility and options for us to think about timing of turn-in lines well mix, how we would think about our liquids contribution at what time of the year, of course. So I think the short answer is, yes. We would absolutely want to factor in what's the best in most optimum way to basically think about our turn-in-line cadence as we kind of move forward. From a service cost perspective and the role that, that would play. I know we touched on it in the prepared remarks, but we've kind of seen what I would call as low to mid-single-digit kind of relief in service costs as we're kind of planning for 2026. Some of the costs are going to be fairly secured with multiyear agreements. As you can imagine, that's been a part of our program on an annual basis. And then some are going to be more on a 12-month type structure where you're going to see more float in what's taking place year-over-year.

It does feel like just given the efficiencies that we've all seen and especially range with some of the numbers we've talked about on the drilling and completion side. It's lended itself to really maximum utilization of 1 to 2 type frac crews or drilling rigs to still see the kind of growth that we're talking about, where you can generate 20% over a multiyear program, which is kind of exciting. So I say all that to say I don't know that I expect service costs to really go down a whole lot more. We're kind of -- it feels like we're reaching a bit of an asymptotic trend on the bottom end here where we're just kind of reaching the close bottom, if you will, and we're bringing out those additional dollars through other operational efficiencies. Water recycling, multiple stages a day, improvements in surface equipment design. So long-winded answer to say we would fully expect those savings to be an opportunity to think about either not spending all of our capital in a given year, thus the $50 million capital range. Or again, as we think about '27 and beyond, is that get invested into another thoughtful wage of growth, depending upon demand that continues to emerge and materialize.

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

Yes, Jake, I think the short answer is yes. This is a facility that will require more than 75 million a day in gas feedstock to generate power. So this was a good starting point. There is scalability to the infrastructure, both at this site and in the region that we could help meet going forward through the same transport that we have. So this is all in line with some of the transport that we've picked up that will start in service in 2027 as a part of our multiyear plan, but also could be served through other transport that we actually have or other capacity we have on that same piece of transport. So yes, it's a great counterparty. It's a really high-quality counterparty on top of it. So we really think it sets up a strong foundation for how deals could get structured that allow growth that's also margin enhancing going forward.

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

Coming back to the question around growth beyond 2027. Just wondering how you would consider allocating capital across liquids versus dry gas acreage. And when would you need to commit to additional processing capacity or other infrastructure if you decide to grow? Or is there any willingness to focus more on the dry gas side and taking basin pricing?

Phil, when we start to look at the inventory, we do have dry gas inventory that will continue to play a role in our program on a go-forward basis. So I know looking at this year, in prior years, it's tended to fluctuate somewhere between probably 20% to 30%, 35% of the program on an annual basis. There is the ability for us to flex that higher if warranted. I think a good example is just seeing some of our activity in Northeast PA, where we've had some high quality, lower Marcellus wells that we've been able to drill on an annual basis where we've taken a rig, drilled 1 to 2 pad sites and incrementally utilize existing infrastructure and incrementally added some nice production to the profile. So we do have, I'll just say, more of that, that we can do if we wanted to flex into a direction of being drier.

As far as an infrastructure commitment standpoint, the Harmon Creek processing expansion that goes into service this year really carries a significant amount of momentum through '27 and to the back as we start to think about getting into 2028. There is some debottlenecking that is underway with one of our midstream partners MPLX at the Majorsville facility. So we're bringing out more with the same infrastructure to look for incremental capacities there. And gives us the option of growing production in the future without having to consider a new processing plant construction alone, which we think that's where we're at from a maturity of the business standpoint. And I know you've heard us, Phil, talk about it in the past where we think given our depth of inventory that we have, it's going to afford us the ability to step into capacities that others could let go underutilized in the future. So in the near term, maybe it's more also debottlenecking and bringing out some capacity that can be more efficiently utilized in existing processing plants and gathering.

So that's how we're thinking about future growth. And we think the near-term or the time frame it would take to actually see those molecules go into service is -- if that time frame gets truncated, which again gives us more flexibility.

Okay. That's helpful. And then you also had a new macro slide on global naphtha cracking rationalization. I was just hoping you could touch on this. Is it incremental to what you're also showing as call on U.S. supply for NGLs? And then just given the pectin margins or historical lows, how do you think about operating rate assumptions or is what you're showing here a little bit more reflective of something closer to mid-cycle margins?

Yes. The NGL macro has been clearly a hot topic as we think about the back half of 2025. So I'm going to attack this from a couple of different angles. But clearly, stock levels have been elevated through 2025, both on the propane and also on the ethane side. And I think each has a different story to tell. But in some ways, they've got a similar story. And the different part of the story is for propane, you had weak demand last year. And of course, there was an increased level of production that was a little stickier, I think, through associated gas contribution, than maybe was somewhat anticipated.

And then on top of it, you did have -- on top of the demand being down a little bit in supply being pretty resilient last year, you also were a little bit lagged in seeing run rates improve on some of the infrastructure that was commissioned in '25. Export capacity, maybe the common ground is the export capacity expansions out of the Gulf have been really helpful to see the ability to move another 200,000, 300,000 barrels a day. You're seeing that materialize now in the numbers as we've started to get out of fog in the ship channel and other operational hiccups that have transpired, and you're really seeing strong numbers now in the 2 million barrels per day type level on the propane side as an example.

So as we think about rolling the take forward for 2026, you really start looking at more utilization of the current dock expansions. You've got additional dock capacity that will get also commissioned through the balance of the end of the year with some of the same midstream providers that commissioned infrastructure last year. And then on top of it, you've got -- I'll just use neos and Sinopec, as an example, you've got close to 200,000 barrels of incremental demand that goes into service here over the balance of the next 12 to 18 months.

So we're still optimistic and really as we're thinking about stock levels getting pulled down renormalized through the balance of 2026, and then run rates continuing to improve on infrastructure that was commissioned in 2025 and through the balance of the back end of '24. But I'd say this, we would also expect to see a lower growth rate with some of the NGL contribution out of the Permian and associated gas, just given some of the downward pressure to their growth associated with oil price today that we see. So hopefully, this gives you the color you're looking for. But it's definitely a complicated math problem, but we see at the end of the year that the stock levels get renormalized and pricing return to a healthier place.

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

Dennis, at the end of your prepared remarks, you mentioned that Range had initiated this growth plan a year ago. I wonder if you could take a step back and compare the in-basin demand and supply outlook today compared to when you initiated this growth plan and maybe your confidence on that outlook. I guess the context of this question is that although we've had a lot of price volatility over the past few months, as it sits today, the curve is pretty materially lower than it was a year ago.

You bet. Thanks for joining us this morning, Kevin. I think when we start to think about what's different between a year ago versus today, in some regards, the way we -- I think I may have touched on this a little bit already, but I'll try not to be too repetitive, but we did try and risk the program as we were thinking forward around what pricing could look like. Yes, it is down a little bit today. But I would say, by and large, it's really kind of intact to what -- how we had risk the program and the cash flow that we felt like that the business would throw off. The way we also structured the program was around using existing capacity though. So we didn't really build it around the premise of new demand that might come. Instead, it was taking on the Energy Transfer's Rover incremental capacity of around 250 million a day. It would get us to both the Midwest and also the Gulf markets, which we're marketing at on a regular basis through existing capacity as we speak. So we felt like it allowed us to take on market share instead of thinking about growing for growth sake. That's not a part of the equation for us as we go forward. We have to have a home for those molecules. And so we felt like taking on that market share was indicative of our ability to have a depth of inventory that would be the backstop for a commitment to this pipe. And we also felt like those -- that pipe capacity got us to end markets that would see growing demand in the future. So good optionality and flexibility as we move forward, and we were able to step into that capacity at a great time in our program.

When we think about 2028 and beyond, I think that's where the growing demand piece really starts to become a bigger topic for us. And I think that's evidenced by the marketing deal that you're hearing us talking about. We think it's the first of many options that we can consider more in-basin or regional that allows us to think about that next wage of growth, but it also has to materialize. So more market share as a part of our plan now. We feel like pricing is still intact that allows us to continue to execute the current plan that we have for the multiple years, '28 and beyond, it will be based upon a home for that production in the in-basin region demand it materializes.

That's a really good answer. Maybe as a follow-up, I wanted to dig into your differential guidance a little more. Your fourth quarter realizations were strong, but your guidance for differentials are pretty similar year-over-year. If we saw first quarter gas prices strong in the Northeast relative to Henry Hub. Can you kind of square why the guidance is the same year-over-year? And give us any comments on how realizations will look throughout the year?

Yes. I think as I started a minute ago, we start with just the market indications. Information content and forward curves is what it is. It's not perfect, but it's the starting point, the best predictor we have. Our guide is about $0.05 better year-over-year versus the starting point. And as we think about how 2026 has begun, we're off to a great start. I think it's important to note that 90-plus percent we take into first month capturing extremely high value. So variation quarter-over-quarter and the seasonality that drives that, variation year-over-year, again, is somewhat weather dependent. But ultimately, the consistency of our tight differential. And our premium to Henry Hub realized price per Mcfe is a function of the transportation portfolio. So I'll just leave it at that. The guide is -- Mark indicated and we'll continue to improve that through the experience of our marketing team as we do every year over the course of the year.

The next question is from Michael Scialla with Stephens.

Just wanted to ask on your return of capital. It's been heavily weighted to buybacks. You are increasing the dividend this year. Do you expect any inflection going forward? Or how are you thinking about allocation between the balance sheet and dividends and buybacks going forward?

Sure, Mike. I think as we evaluate what the current trading levels of the stock price versus an NAV, what the fundamental value is of an inventory measured in decades versus a stock that trades close to just your proved reserves, which is less than a 5-year development plan, we see tremendous value in buying back those shares. So I would expect us for the foreseeable future to continue favoring buybacks. As you look at the trend, I would also expect us to slowly steadily grow the cash dividend. I think there's a discipline and a real tangible total shareholder return element there. It's a commitment to return capital. It's a commitment to maintain a balance sheet that can do that through a cycle and to steadily slowly grow that persistently.

As you think about the share repurchases, the scale, scope, timing, again, we have not done a formula quite intentionally. We think if you're formulaic and programmatic, you can end up with just a pro-cyclical and by high type program. So we think the flexibility of being opportunistic generates a much better return in buying when you see pullbacks and just lower points, lower entry points in the stock price. That is to say we still see tremendous value and where the stock is trading today. And I think you can look at our track record over the last number of years and the percentage of cash flow that we have deployed in returns of capital as compelling. Again, we're not going to provide a framework for perspective, we've been in the 20% to 30% range the last couple of years. This year approached 50% of free cash flow in returns. So as the best sheet, as you stated, is in a great place. We have a lot of flexibility in how best to reinvest in Range's business and continue improving it.

Yes, makes a lot of sense, Mark. I wanted to ask on Slide 7, your free cash flow forecast for the next couple of years. you've given the assumptions there for production growth, prices and CapEx. I wanted to see what you're assuming for op cost. Do those stay flat? Or are there any efficiencies built in there going forward?

They're flat. We've tried to shoot this straight, be pretty conservative. And as Dennis said, we are approaching the lower limits in many situations on how far you can push costs down. So our focus, of course, is on ringing every penny out of the cost structure that we can contractually and strategically. But for purposes of modeling here, it's essentially flat.

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

The team always finds ways to get a few more stages a day done on average, more lateral footage per day each rig that's in operations. We certainly shoot for and plan for a certain amount of that. And every year, we are fortunate with a strong and safe execution by the team and continuously surprised by what the range team can do. So I would certainly think that there's a little bit more there, the team can ring out.

And we are nearing the end of today's conference. We will go to the line of Neil Mehta of Goldman Sachs for our final question.

I just wanted to circle back, Dennis, on Fern. It looks like you guys were able to run well through that period of time and sell into Bidweek. But I don't know if there's any quantification you could provide around the cash flow uplift around the storm. Any lessons learned around it because I'm sure volatility is here to stay in the gas markets, and just any perspectives on how your marketing can perform during that period of time.

Yes, I think the -- first of all, thanks for joining us, Neil. When I think about that, we are -- sorry, Bidweek and also the operating plan we were able to really lean into the pricing of that $7 type level, which was really significant when you think about the cash flow that gets thrown after that kind of cycle. And as you point out, this is something that we've talked about now for a few years, we expect to see more volatility going forward, whether that's weather-related or driven by other factors. So the team really did a great job and I kind of have to congratulate the operating team because they were in some pretty rough conditions with sub-0 temperatures. And at any 1 point in time, we didn't have more than a pad site or two that was really down that then didn't get restored in pretty short order. So team really did a phenomenal job. And I think this is years of planning and teamwork between our team in the field and also our midstream providers, just from the standpoint, we continue to do winter operations look backs and improving our production facility designs rooting out downtime and sources of that downtime, so that we can preserve that flow from the wellhead all the way through the processing plant and get downstream to those critical end users, which as we saw from winter storm firm that was really important.

And even in this last week for some in the Northeast, I'm sure they're feeling the effects and comfort of having natural gas flow generating power for their homes these days. So team did a really great job. And as you heard me touch on earlier, it's a multidisciplinary plan on how we think about capturing the value uplift or Bidweek or leaving more in the daily to try and capture what we think is more of upside opportunity through the balance of that upcoming month. But yes, we'd expect more volatility going forward and that multidisciplinary team will get leaned on a monthly basis.

I think, Neil, we're not going to give any forward guidance on it specifically, but just conceptually, I'll say this, that February looks to be one, if not perhaps the best free cash flow and realizations a month and perhaps company history.

This concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Degner for his concluding remarks.

You bet. I'd just like to thank everybody again for joining us on the call this morning. Really appreciate your support. If you have any questions, as always, please follow up with our Investor Relations team. We look forward to catching up with you on the road in a one-on-one or in our next call. Thanks, everyone.

Ladies and gentlemen, thank you for your participation in today's conference call. You may now disconnect.

Good day. Welcome to the Range Resources Third Quarter 2025 Earnings Conference Call. [Operator Instructions] Staements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks, there will be a question-and-answer period.

At this time, I would like to turn the call over to Mr. Laith Sando, SVP, Investor Relations at Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, everyone, and thank you for joining Range's Third Quarter 2025 Earnings Call. With me on the call today are Dennis Degner, Chief Executive Officer; and Mark Scucchi, Chief Financial Officer. Hope we've had a chance to review the press release and updated investor presentation that we posted on our website. We may reference certain slides on the call this morning. You'll 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 realized pricing details by product along with calculations of EBITDAX, cash margins and other non-GAAP measures.

With that, I'll turn the call over to Dennis.

Thanks, Laith, and thanks to all of you for joining the call today. As we report on the progress made during the third quarter and focus on the execution of the remainder of our 2025 program, the results remain consistent with what we've shared in prior cycles. During the quarter, Range executed on our plans safely and efficiently, delivering consistent well results, free cash flow, returns to shareholders. and steady activity levels that support the growth plans we've previously communicated. All-in capital came in at $190 million, while generating production of 2.2 Bcf equivalent per day for the quarter.

Year-to-date, we've invested $491 million in capital, putting us right on track with the previously improved guidance of $650 million to $680 million for the full year. Our year-to-date operational savings come from several differentiated aspects of our business, which include returning to pad sites for incremental development, utilization of existing infrastructure, extended reach horizontal development and the team's dedication to continued operational improvements. I'll touch on a few of our operational highlights driving this in just a moment.

As we look ahead, our previously announced growth [audio gap] will begin to gain visibility in Q4 and as strong field level performance is expected to deliver production of approximately 2.3 Bcf equivalent per day in the quarter and growing towards 2.6 Bcf equivalent per day in 2027, an increase of approximately 20% from current levels. Importantly, Range's incremental production will be transported to known end markets. as our depth and quality of inventory allowed Range to secure transportation capacity that was going underutilized by others.

We believe our plans align well with increasing demand in the Midwest, Gulf Coast and global LNG markets in the years ahead, while having the flexibility to meet future in-basin demand as well. And lastly, we will add our planned 400 million cubic feet equivalent per day of growth very efficiently with relatively flat annual capital over the next 2 years and supported by investments in additional work in progress inventory since late 2023. This will keep Range's reinvestment rate at the low end of the peer group, allowing significant capital returns to shareholders while -- diving into the quarter Consistent with prior quarters, Range operated 2 horizontal rigs, drilling approximately 262,000 lateral feet across 16 letters, averaging [indiscernible] feet per well. This adds to Range's planned, drilled uncompleted inventory and places us on track to exit 2025 [indiscernible] [Audio Gap] look back from prior pad executions. Our Northeast PA operations continue to deliver incredibly efficient results and strong returns, utilizing existing infrastructure on our occasional return trips to the area.

Cash operating expenses for the third quarter finished at $0.11 per Mcfe, firmly within our previously improved guidance for the year. The team continues to see efficiencies within the field, especially when focusing on multi-operational project scheduling to improve production downtime, reduce spending and maximizing field run time from the wellhead to the burner tip.

Shifting over to marketing. The third quarter of 2025 was an exciting time for U.S. Energy Marketing. As we saw the commissioning of new NGL export capacity, the ramp-up of recently commissioned LNG export capacity and strong interest in new natural gas supply for power generation within the Appalachia Basin. Highlighting some specifics, starting with natural gas. The U.S. exported record volumes of LNG in the third quarter as new capacity continue to be commercialized, and international demand for clean, reliable American Energy remains strong. Three additional LNG projects reached FID in the third quarter, with additional projects recently sanctioned bringing the year-to-date total to approximately 9 Bcf per day of incremental feed gas demand, making this a record-breaking year for FIDs in the U.S.

Based on projects under construction, LNG feed gas demand is expected to exceed 30 Bcf per day by 2031, more than doubling the export capacity versus current levels. We are confident of the world's strong appetite for U.S. natural gas as long-term global gas demand is underpinned by rising incomes and population growth.

Looking at in-basin opportunities. We continue to be encouraged by early phase activity in Pennsylvania toward gas-fired powder generation data center projects. Numerous projects are progressing, and the past few months have provided us with even more conviction that consensus estimates for approximately 2.5 Bcf per day of Northeastern demand potential from data centers by the end of the decade is becoming more real. We are continuing to make progress on the Fort Cherry joint venture project with Liberty and Imperial announced earlier this year.

In addition, ranges in conversations with multiple other potential projects that could benefit from Range's asset location in Southwest PA, our pipe access across the U.S. Our marketing acumen and importantly, our depth of high-quality inventory and financial strength that can support long-term supply agreements that end users are looking for. As we look forward, we believe there will be a clear call for Appalachia to play a key role in supplying U.S. markets with affordable, reliable natural gas supply. And we believe that expanding infrastructure from Appalachia and sourcing more power demand within Appalachia is the most effective way for America to fuel its long-term energy needs.

We remain very constructive on the setup for natural gas with storage levels at or below average and last year in terms of days of supply. And as we move into 2026, a further 4 Bcf per day of LNG export capacity is expected to come online, leading to tightening gas marketing fundamentals.

Turning to NGLs. Similar to our outlook for natural gas. We're encouraged by the fundamental setup for ethane and LPG Ethane and propane are both expected to see substantial increases in export capacity out of the Gulf Coast into continuing strong international demand. And we expect this to improve NGL pricing relative to WTI in the coming quarters. Specific to range, our geographically advantaged access via exports to the European market continues to support a premium versus the Mont Belvieu index. We see continued strong demand for Northeastern U.S. LPG as Europe continues to secure long-term supply from reliable producers.

During the quarter, Range once again leveraged its flexible transportation and marketing portfolio to respond to market dynamics and enhance margins. These optimization efforts for Range led to a strong seasonal natural gas price differential of minus $0.49 per Mcf versus the NYMEX index, coupled with a continued premium on our NGLs. And we have improved our full year guidance accordingly. The future of natural gas and NGLs is strong with significant demand continuing to materialize in the near and medium term, both globally and within Appalachia. Range is poised to help meet this future demand while creating outsized value for shareholders with the strongest financial position in company history. A large contiguous inventory measured in decades and a proven track record of delivering through cycle returns of capital, while investing in the long-term success and the optionality of the business.

I'll now turn it over to Mark to discuss the financials.

Thanks, Dennis. The first 9 months of 2025 have underscored the stability and profitability of Range's business. During this period, NYMEX natural gas prices averaged $3.39, while range achieved an average realized price of $3.59 per unit of production, a $0.20 premium created by our diversified commodity mix and sales strategy. Strong pricing realizations combined with low full cycle costs, that provided range the ability to continue progress along our 3-year growth plan while returning capital to shareholders.

Year-to-date, we have repurchased $177 million in shares, paid dividends of nearly $65 million while reducing net debt $175 million since year-end. Each of these actions, reinforcing our commitment to delivering on our stated capital allocation priorities. While front month gas prices fluctuate, our business model sitting atop a high-quality resource base has consistently generated free cash flow, enabling capital allocation options of executing a market-driven, growth-oriented operational plan alongside current capital returns to investors.

Range is proving the free cash flow resilience of its business and enhancing that resilience through targeted capital investment. The specific attributes of Range's business that provide a stable base and enable through cycle investments and returns include a high-quality, long-duration inventory that enables a low reinvestment rate, a strong balance sheet to allow value-capturing opportunistic investments. A diverse portfolio of natural gas and natural gas liquids transportation that links range to customers in key U.S. and global markets. delivering roughly 90% of revenue from outside Appalachia.

While building cost-effective DUC inventory to meet future demand, our opportunistic investments and returns in 2025 have grown from prior years. in the form of share buybacks and dividends, given the strength of Range's balance sheet. In other words, while investing at a maintenance plus level, we are generating healthy free cash flow and diligently redeploying that capital to harvest value from Range's resource base. As the U.S. and global natural gas markets continue to integrate with commissioning of new LNG facilities alongside substantial domestic demand growth primarily from electricity. We believe Range's long-life, low-cost inventory creates enormous auction value to play an integral role as a key supplier. Our durable free cash flow, evidenced through cycles in recent years, position Range to consistently deliver value to its shareholders.

Dennis, back to you.

Thanks, Mark. Ranges year-to-date results reflect a consistent strong operational performance against our stated multiyear plan, consistent free cash flow generation. and prudent allocation of that cash flow, balancing returns of capital, balance sheet strength and the optimal development of our world-class asset base. You've heard us state this before, but we continue to believe the results communicated today to case that Range's business is in the best place in 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.

[Operator Instructions] And our first question will be coming from Jake Roberts at TPH & Company.

I wanted to spend some time on the work in progress inventory. So can you speak to what you think that 400,000-foot number looks like at the end -- and if you could, I know it's early for 2026 discussions, but is there any consideration on timing of that drawdown we should be thinking about?

Yes. I'll try and help provide some color on what 2016 looks like. As you start to kind of think about from a capital, I'll start there at a high level, capital is going to look really similar in 2026 to what you've seen us executing here in the program year for 2025. The difference is between the 2 years is an allocation of the capital that will then start to lean more heavily on the completion of the DUC inventory that's been building over the last couple of years and through 2025 and our ability to start to work through that, coupled with some timing of some infrastructure that will come online that I'll touch on here in maybe just a moment.

So maybe more simply put where you've seen us have 2 drilling rigs over the last couple of years. We've talked about that as being kind of a maintenance plus kind of a program. So over 3 years, we will have added 400,000 lateral feet, and roughly that translates into around 30 wells. So I'll put some context around the last 3 years between '23, '24 and '25 from that perspective. Then when you start to shift into 2026, and that's also with 1 completion crew. So that maintenance plus inventory that gets built is clearly more than 1 frac crew can consume.

For 26, we'll take that drilling activity down throughout the balance of the year. We'll still maintain at least 1 rig for the balance of the year, and there will be portions of the year where there may be a little bit more activity, but the completions activity will go on an uptick. So you'll see a single frac crew for portions of the year. And then instead of like what you've seen in '24 and '25, where there's been a spot crew to complete maybe 1 or 2 pad sites, you'll see some continuous activity with a second crew that then starts to work through that inventory.

So what does it look like at the end of 2026. We're still kind of working through the refinement of those numbers, and we'll have some better guidance for you on what that lateral inventory looks like. They expect it to be a very linear utilization trend over the balance of '26 and '27. That also translates into the production that we've talked about where roughly we'll be at 2.4 Bcf a day then going to 2.6 by 2027. So it will be a fairly ratable increase over the [Audio Gap].

Great. That's really helpful. And staying on the same topic, as we think about that shift or the balance perhaps of [indiscernible] capital here in 2026 you guys have spoken a lot about returning to pad sites and things like that as drivers of efficiencies over the past quarters and years. I'm wondering if you've already spoken that you see capital is similar, but I'm wondering if there's anything we could be thinking about maybe on the OpEx side of things, that as we progress through the drawdown of this inventory that might move the needle in either direction on some of those line items?

When I think about the breakout of, let's just say, capital and operating expenses, we're -- from a -- I'll just say, you've come to see us really remain at a very low level from a cash operating expense basis. So from an LOE perspective, we've typically run somewhere between $0.10 to $0.12, depending upon seasonality and winter influence. I wouldn't expect that to move a whole lot because we're already starting from a really, really low base. There's always an opportunity for a little more improvement there.

And then as you point to returning to pad sites with existing infrastructure, that is something that we factor in year into year out from a perspective of it represents roughly about half of our activity on a year-in and year-out basis. You can expect to see that fluctuate a little bit. But again, I would say, all in all, what you're seeing in our historical efficiency gains on completion on the drilling side, drilling as you've heard us say, our fastest and longest laterals, all while staying within greater than 90% within a tight target window, we would expect that momentum to continue into '26 and '27.

So we're refining those goals right now as we speak on what that could look like for '26. So we'll have more to share at the February call, but I would expect us to continue to be on that leading edge of what cost per foot looks like, with our ability to move back to these pad sites, drill really long laterals that continue to be very efficient with our operating capital.

[Operator Instructions] Our next question will be coming from Kalei Akamine of Bank of America.

Dan, it's Mark. I wanted to follow up on 2026 as well. So this year, you're pretty much on track with your plans, and that's great because it's effectively year 1 of 3 as you think about that ramp through 2027. But as you continue here, given your strong execution this year, where do you see upside to your plan? Is there opportunity to outperform on the capital or volume side in the next couple of years?

Yes. Good question. Thanks for joining us, Kalei. When I think about '26 and '27, we really think we have, I'll just say, opportunities to perform. It's really what you've seen us talk about in many, many cycles, and that is the efficiencies from an operations perspective in the field. And what we've seen and the ability to drill long laterals. I'll just say we drilled against some of our fastest wells and again staying in a tight target. Our completion efficiencies continue to show improvement there. So I think that's a way that you could see some potential upside in the numbers.

And then I think the other part, when I think about '26 and '27 is infrastructure utilization that comes online with our midstream partners like MPLX. They've really done a good job working closely with us, and they've demonstrated the ability to remain on schedule and also move pretty quickly to commissioning of that infrastructure. So I would say field run time performance, especially as it pertains to new infrastructure and then our ongoing operational efficiencies.

For my second question, I want to see if you guys could opine on the NGL macro. You had a couple of interesting slides in your deck last night. So maybe some green tooth on both the propane on the ethane side. So maybe I can simply see the floor and maybe you can tell us what you're seeing in that market for 2026?

Yes. I'll start here, and if we need to take a deeper dive and others may jump in. But ultimately, when we start to take a look at the macro for NGLs we're as optimistic on that front as we are really from an at gas perspective. And I know you've heard us really dive into the nat gas side a number of times. And really, it starts with the really 2 components: one, the demand growth side. There continues to be increasing run rates on previously commissioned infrastructure. And then, of course, on the LPG side, you've got another 700,000 barrels per day of demand growth by year-end of 2026.

So the demand side, we feel like is still continuing to show really good strength. And by the end of the decade, it looks like at least from what we can see in Cali, it's a total of 1.4 million barrels per day of incremental demand. So that really, in our mind, points to a strong call on LPG demand growth and really a supply pool that's going to be important out of the U.S.

So how do you get it there? Well, there's been a lot of export capacity expansions that have been in progress of either being constructed in process of being commissioned, and we'll also see an increase in their run rate over the balance of the next months ahead. So we're excited about the ability to see, I'll just say, the lower 48 move the barrels, the demand growth side continuing to materialize. And we really think for Range, as an example, our ability to have access to East Coast export capacity continues to be a differentiator for us. And so that will be not only in the next -- as we think about the next 12 to 24 months. But really, as we're thinking about that 1.4 million growth demand by the end of the decade as well.

Ethane, I think a little bit different story, but it's very similar, more export capacity growth and also more demand growth as you're starting to, in a lot of ways, see in the next -- by the year-end 2026, there's roughly another 400,000 barrels of growth there and by the end of the decade at incremental 260 on top of that. So again, continuing to show good positive signs for demand growth and also the ability to export those barrels. And some of the counterparties that are actually representing that demand growth for counterparties that we currently do business with today.

So we know that there are good calls coming in for how we could potentially participate in that growth in the future, if needed and warranted. And we think that's exciting for Range.

On the demand side, do you see that demand on the export side pulling volumes out of the Rockies and driving ethane to natural gas parity in 2026?

I don't think -- I guess at a high level, I don't know that I see that, that is -- there's a need for that. I'll let Alan kind of jump in that runs our marketing effort.

Yes, I'd say what we see going forward with that demand is that you're going to be pulling -- recovering as much ethane as you can out of the Permian, Mid-Continent, it's going to be pulling out of Aplasia as well. So we see the ethane spread to natural gas actually improving. In fact, the month of September was interesting. We set an all-time record in terms of exports. It was over 600,000 barrels per day of ethane exports, supported by some of the new infrastructure that Dennis was talking about.

And with that, we saw the spread between ethane and natural gas improved as a result of that demand pull. So with the ethane exports pretty much doubling by the end of next year with the capacity of export. And that's -- you've got new crackers that are starting up in Europe as well as in Asia as well as in China. And then you've actually got roughly 130,000 barrels per day of new demand domestically that will be starting up late '26, early 2027. All that combined leads us to believe that ethane fundamentals are going to get stronger, inventories are going to come down, day supply is going to come down and the price will improve relative to natural gas.

And our next question will be coming from Michael Scialla of Stephens.

Want to see if I get an update on your conversations you've been having for supply agreements and -- are those limited to Pennsylvania? Or are you discussing anything outside the state and any of those with end users or more like the Imperial type of conversations that you've been having so far?

Michael, I'll jump in here. I think in a lot of ways, our update is going to feel similar to what we shared at the July call, and it's still a very dynamic space. So I'll kind of start there where Alan and the team have seen a number of inbound phone calls and engagements with household names. I think that a lot of us on the call would know as end users for potential facility. I think right now, it's that phase of trying to look at site selection, where is the best location to put one of these facilities to have, I'll just say, access to long-term supply.

And so that's part of the reason why we think we've been on the front end of many of these conversations. Again, inventory is playing a huge role in this conversation and also the diversification of gathering and regional transport that would allow our ability to help supply one of these facilities, again, with long-term reliable supply.

I think it's still narrowing down on like in Liberty and Imperial as an example. We're seeing a lot of positive movement there in narrowing down to a final couple of potential end users. So it's hard to see at this point in time what that announcement time frame could look like, but know that, that's being actively worked really hard. I think once you see at that point, an end user truly get defined, then we'll be able to move forward with more party conversations around what a pricing structure could look like, both from a term and framework standpoint of whether it's tied to something that's a normal index? Or is it something that's got a floor and ceiling type structure that allows us to have some long-term support and then also provide some upside protection for those other end users striking that right balance.

So more to come on this. We look forward to sharing more details as we get closer to announcement type time frames, but know that it is a very dynamic and busy space and Allan and the team at Range has been very active in a lot of that space.

And Dan, all those are pretty much inside of Pennsylvania at this point? Or are you looking outside of Pennsylvania at all?

Yes. I would say the focus has been primarily within our producing region directly. But we also have seen, as you would imagine, with many of these potential offtake users, the willingness to talk about expansions. Expansions could both be there in the existing footprint that they would be planning on, and it could be outside the area. So Again, given the transport that we have and the areas of the U.S. that it gets to and reaches, we've got some durability there once we start to put a framework in place that supports, I guess, again, that 5 9s of reliability, strong labor pool, all of the things that make the Pennsylvania region or Pittsburgh region a really advantaged area. We could see this starting to shift into other areas of their -- and regions of their business, again, given our transport diversification. .

And I wanted to do my second 1 to ask about capacity out of the basin. You mentioned you picked up some FTE that became available. With that 3-year plan, does that require you to take on any additional takeaway? Or are you set there? And -- you mentioned MPLX keeping up with you. Any other infrastructure that needs to be put in place for you to execute on that 3-year plan?

So as it stands today, I'll start with the MPLX question. The infrastructure that we've disclosed and that capacity -- those capacity additions that we've disclosed over the balance of the last year that is what is needed to deliver on our 3-year plan. So we're -- I'll use your word, we're set. Now it's just moving forward with construction and also commissioning of that infrastructure. So we're feeling really good about the time lines that we've communicated the production profile. And again, MPLX's history of demonstrating they can execute and direct these facilities.

The transport is also complementary to our growth profile. Nothing else is needed at this point to deliver on that. And as you've heard us say a number of times, Michael, we can really be patient once we start to look beyond 2027 and either look to supply, create more growth that's thoughtful to address demand that's in basin or if there's other transport that becomes available because it's underutilized, we can be thoughtful about do we take on more transport or not. So we love the optionality and the patients factor that we can execute because of the inventory that we have.

And our next question will be coming from Arun Jayaram of JPMorgan Securities LLC.

Dennis, I was wondering if you could provide maybe a little bit more details on what's going on with Liberty and the Imperial land kind of project in Washington County?

Arun, thanks for joining us. I tried to touch on this a little bit here just a few minutes ago. But I think at the end of the day, we're seeing that the conversations are very fruitful. We're seeing that the counterparties are getting down to our partners in this JV are getting down to what I would say is a lightning bonus round of the final few end users that could utilize the facility there and that footprint, along with thoughts around how they would expand in the future.

So really difficult to date to nail down a time frame on when we think an announcement could further materialize. But ultimately, we think that it's going to take a few months to still kind of grind through these details. But the good news is it's a great location where Imperial has their surface development opportunity. And I think to maybe shed a small piece of light on the seriousness of this project, we've heard us talk about in prior meetings about the sites project at the state level and the regulatory climate, the governor's willingness to really put some dollars to work to help support some of these projects going from, we'll say, concept into reality.

And this year, over the last several weeks, you saw Liberty announced that they were 1 of the early on and initial recipients of some of those funds to help support this project. And so we think that's a great sign, not just from a, we'll call it, conceptual planning phase, but also the state's willingness to support this as well. And ultimately, our supply of gas being right under the footprint of this particular site is just really ideal. So we think this is going to translate into expansion into other projects as well because of all the complementary components we've talked about, but it's a very busy space. I'll just say this, Alan and the team continue to have a number of conversations and helping support this along. So we're awfully optimistic.

Yes. We cover Liberty and they were pretty optimistic, Dennis, about inking some power deals relatively soon. So it would make sense. Maybe one question for you guys on what you're seeing in the global LPG market, right now, we're seeing an environment where Far East propane and butane prices are below what we're seeing in Europe in the U.S. So I was wondering if you could maybe give us some thoughts on how you see the international LPG market trending next year? Obviously, and perhaps implications of a Trump the kind of trade deal, which could happen in the next few days or so and thoughts could that be something that opens back up U.S. exports to China?

Arun, this is Alan Engberg. I head up the marketing piece at range. So I'll take a stab at your question. We're -- overall, as Dennis mentioned earlier, we're pretty optimistic on the setup for going into next year. There's obviously been a lot of volatility and a lot of back and forth in terms of international dynamics on the political front, and we can't -- we can't predict what's going to happen there. Recent news this morning, this week has been positive. I think we're going to get to a good place. But in the meantime, I think it's important to note that from, let's say, an ethane side, exports are up year-on-year despite all the turbulence.

And from an LPG standpoint, September year-to-date, exports are actually up, not up that much, but it's a few percentage points. When we look forward, going into just this year, next year, as Dennis had mentioned earlier, we see 700,000 barrels a day of LPG demand growth. And just to get into a little bit more granularity, that's 23 new PDH units that are still coming up and granted those are primarily in China. But it's also 127,000 barrels a day for LPG demand going into ethylene steam crackers.

And then we've always got that [ res com ] piece, which is pretty inelastic and is growing at around 2% to 2.5% a year. So you add all that up, and that is good strong demand. And if we look back just over the past year, 1.5 years out of the U.S. there's actually been constraints from an export capacity standpoint. We've been bumping up against the limit. And what we're going through right now is major export capacity expansions. So we're adding between now and the end of the decade, 42% to the U.S. export capacity for LPG.

And in numbers, it's a big number. It's just under 1 million barrels per day of new capacity. We're confident, again, looking at the demand that we see set up for the rest of this decade being 1.4 million to 1.5 million barrels per day that export capacity is going to be well utilized. And as a result of that, as we mentioned in a prior call, we've taken on additional export capacity out of a new terminal in the Northeast, the Repauno terminal we'll have access to that probably starting late '26, early 2027.

So overall, that lends itself to just, I think, strong demand pull on U.S. NGLs, ethane and LPG and for LPG in particular, we see propane relative to crude continuing to gain strength as we go through the period. Right now, we're at about 45%. That's higher than where we were last year at this time. Long-term averages have been around 60%. I think that's within the realm of possibility. So good overall for Range.

And our next question will be coming from Doug Leggate of Wolfe Research.

Gosh, there's a lot of moving parts in these supply agreements. So I wonder if I could take 2 pieces of them. The first is the prognosis for your realizations, whether you want to benchmark it, I look at it as a percentage of benchmark or in-basin discounts, whatever. What's kind of in my mind is you guys have got a lot of takeaway, obviously, out of the basin. But there's also, I think, a growing concern perhaps that the 2 lowest cost areas of the country are going to be the primary sources of supply for a lot of the onshore stuff specifically the Permian the Marcellus.

So I guess my question for you is, as you look to your growth story, how do you see your basis changing? My follow-up is specifically for Mark. Some of your peers have suggested that range hasn't had any very large long-term supply agreement signed yet because you're not investment grade. And my question to you is your balance sheet is pretty pristine at this point. What's the holdup? What's it going to take for you guys for the credit indices to move you to investment grade?

Doug, it's Mark. I'll start with both parts of those questions, and no doubt that will all chime in as well. So -- as we think about the supply agreements, I'd like to pull back and kind of highlight a couple of comments that Dennis and Alan have both made so far. And as we look at even this morning's call and the amount of time spent appropriately on the hot topics of the day, which is data center and in-basin demand and so forth. I think it's important to put that in context of Range's overall current portfolio and our marketing strategy. .

For everyone newer to the Range story, it's important to remember that 90% of our revenue essentially comes from outside the basin, half of our gas goes to the Gulf Coast, 30% goes to the Midwest. We've already entered into and completed 2 long-term 5-year plus deals with Japanese utilities LNG exports out of the Gulf Coast. We've already done multiple 15-year-plus term deals with petrochemical partners, be the Canadian and European these use pricing structures that could be NYMEX length. It could be Northwest European [ NASA ] length. It could be ARA or FEI linked depending on the liquids components. So international marketing, term deals, deals of size, deals of duration, spread across the U.S. and global markets with long-term customers is nothing new to range.

So as we look at these deals and negotiate with customers for in-basin demand, be it industrial, be it data centers, be it power with traditional customers like utilities, it's the same mindset. What is going to bring Range the best margin over the long haul. What is the best visible demand -- [ dual ] demand that underpins growth and profitability for Range, as we highlighted in our scripted comments earlier.

So realizations, pricing, that's clearly our priority. And while we may not have announced the first deals out there, the quality of discussions and the number of discussions that are ongoing in our marketing team are very encouraging, be it with the Liberty Imperial joint marketing effort or be it our other discussions and project initiatives that we have underway. So these -- as we evaluate these deals, it comes back to what is additive to our portfolio. They will clearly be positive additions, and we'll get there when the right deal comes along.

So as it relates to sources of supply, you're commenting on the lowest cost versus of supply, whether we want to talk in the Lower 48, whether we're talking to Haynesville, whether we're talking to Permian, quite frankly, the market needs all of it. And at the end of the day, you fast forward just a couple of years and you look closer to 2030, well, by '28, we should be at -- by 2028, we should be at '28 Bcf exports be gas into LNG and quite a bit higher than that by 2030. So where is it all going to come from? And how does the U.S. managed cost of supply specifically domestically for the consumer. Quite frankly, you need additional supply out of Appalachia and out of Southwest Pennsylvania.

So that will happen. You're already seeing a lot of discussion around infrastructure expansions and demand pull. The dynamic is shifting. You've already seen now on some recent announcements of who's subscribing to midstream capacity, and we also do that demand pull because of the recognized need for low-cost, long-duration gas [indiscernible] Pennsylvania. So bringing that all the way back to range and your question of why haven't we announced a deal and does investment grade have anything to do with the current state of announced deals.

I'd say as best as we understand it has absolutely nothing to do with it. Our credit rating has not come up at a single conversation with customers. Our leverage is below that of investment-grade peers and our bonds trade at investment-grade levels. As I mentioned earlier, we've already done long-term deals, multiple 5-year deals with Japanese utilities, international deals at 15-year term deals with international pet chems. So again, marketing for us is about maybe getting the best deal, not necessarily the fastest deal.

Yes, Doug, real quick. I'll just maybe close out with a couple of comments on basis and the view there. I mean, look, if you look at where base has really landed every since MVP came into service and you see now the conversation about growing demand, really, we see some durability in where basis is as it stands today. We've got in-basin. Our view is that there's roughly 5 to 8 Bcf a day of incremental demand that's going to materialize by the end of the decade. You've heard Mark and I touched on this a few different times I'd realize.

But as we think about the go forward in our mind, really the demand is outstripping the supply. From a standpoint of you need to have infrastructure, it's going to play a huge part and we think at the end of the day, without incremental infrastructure this could be -- I'll just say, you could continue to see demand outstrip supply and further adding some strength to basis.

However, we also know there is a willingness to -- with this current administration and at the same level to look at how you can support this in-basin demand growth. We think that balances out over the course of time. And again, what we're seeing at this $0.70 type level is something that's got durability, you could start to see some further strengthening in the future. That will remain to be seen, though.

Guys, I appreciate the detailed answer. I wonder if I could just take it back, Mark, very quickly to the second part of my question. What do you think is going to take for the credit agencies to move you to investment grade, even if it's not an issue clearly from what you've said, but still, your balance sheet is better than most of your peers and you're still sub-investment-grade. Is that a scale issue? Or what do you think is behind that?

Yes. I think if you look at the publications from the rating agencies over the last several years, they have worked to keep up the evolution of the industry and their targets have moved somewhat. And you've touched on it, scale, just sheer production side. several years ago was the focus for them. If you look at their most recent commentary, basically, we're checking all the boxes. I think with the growth plan we've already laid out there just organically. We should be checking all the boxes in the not-too-distant future. I'm not going to try to predict exactly when it may or may not happen, what I'll say is it will be a good byproduct of the quality of our assets, our breakevens, our full cycle or recycle ratios and so forth.

So when we clear that hurdle in investment grade, I think we can clear that bar quite high and it will just come naturally from our operations and growth and production that we've laid out. So there's no -- there's nothing that's an encumbrance or a specific issue for them. So said differently, it will be a nice to have, but I don't think it's a need to have for marketing or other purposes.

Great stuff, guys. I'm sure we'll get into this, and then I'll have more detail in a few weeks. Appreciate it.

And our next question will be coming from Paul Diamond of Citi.

Just wanted to quickly touch on your kind of thoughts on a couple of duties across the market. curtailments in production modulation have seen this additional chatter as of late with some of your peers choosing that avenue to kind of address pricing volatility is how should we think about ranges kind of overall strategy towards that type of modulation or whether it's plus or minus or curtailments or is it more a steady state?

Yes. Paul, thanks for joining us. If you were to look back over the balance of, let's just say, the past 3 to 5 years, I think what you would see is a couple of different strategies that Range has deployed. And one has been -- we have actually looked at shut-in economics and we've curtailed some production when we felt like pricing warranted. And there was also a supportive reduction in cost associated with that production restriction or shut-in that we basically deployed several years ago.

The other strategy you've seen us utilize is what you saw last year. And to some degree, what you've seen in this year's numbers as well, where last year, you saw us reshape the program where we had more of our liquids-rich activity and turn in lines in the first to 9 months of the year, you saw us push our dry gas TILs deeper into the year, as you started to see fundamentals improve for the winter season. You see a little of that as well this year in 2025. If you look at the first half of the year, much of our focus has been more on the liquids rich side of our business.

But again, that's on the being supported by the NGL uplift that you've come to see with that NYMEX plus type realization type impact that we see really becomes a force multiplier in our cash flow in our numbers that we report. And now what you've seen is us again, shape this year's program where the dry gas TILs are going into the second half of the year. Now balance of those went in, in Q3, but they were deep enough in Q3. You're really going to see more of the production effects show up in our Q4 numbers, which again, I know we touched upon in our prepared remarks today as we start to look at finishing the quarter and the year really strong here.

So I would say we have looked at some shut-ins. We've done those over the years past. That's been more a little bit on a limited basis. What you have seen us do is think about shaping of our program where we think pricing signals would warrant the timing of that production to turn to sales. Q3 for us this year was business as usual. And so again, because of that shaping effort that we put in place, we feel like we were able to continue to execute, turn those wells in line and then get ready for the upcoming improving pricing markers, which we're already starting to see signs of that.

And Paul, just to emphasize a couple of things that Dennis said, I think there's 2 key points and differentiating factors of Range's business that makes that calculus of curtailments will be different than our peers. First, 80% of our gas leaves the basin. So the curtailments of dry gas in basin that would have otherwise been sold at in-basin pricing. That math is different than our math when it's going out of basin to stronger markets.

Second, as Dennis said, the NGL uplift. You can see it in our realized price year-to-date, ranges realized prices is $0.20 greater than Henry Hub. So our dynamic of marketing sales outlets combined with the mix of production, changes that calculus for us. So we certainly are very mindful and do the math just as Dennis said, but it's just the factors in that equation are somewhat different and give us a great setup.

Understood. Makes topic sense. And just 1 quick modeling follow-up. So keeping with the narrative of the $400,000 and excess inventory by year-end works out to 30 or so wells, many your fashion over the next subsequent 2 years. Is the right way to think about that, like true linearity. You have 4 wells, a little under 4 wells per quarter and kind of tranching out and just building that into the till count or should there be more, I guess, seasonality or any other lumpy issues?

Yes. Good question. I'm only chuckling at the lumpy comment because I think ultimately, when you start to go from the model to reality, there will be some dynamics. And one, we tried to touch on a little bit earlier, but that is with some of the new processing and gathering infrastructure goes into service towards the midpoint of 2026. So activity-wise, when you think about activity cadence and you think about capital, it will be a really consistent program of execution and then when you start to see that next step in production, it will be more toward the midpoint when you see that Herman Cree processing bolt-on start to go into service.

So activity wise, you're going to see the utilization of that inventory look pretty linear. What you're going to see on the production side is some slight increase and then you're going to see, as you would expect a step-up when you see the next wave of Harmon Creek processing come into place. But it's going to be influenced by the infrastructure expansions that we've announced and how they come into service in the balance of '26. But think about '26 and '27 is a fairly linear utilization of that inventory.

And our next question will be coming from [indiscernible] of Goldman Sachs. .

I just first wanted to start on the fact that given you are now well within your target net debt range, how are you evaluating allocation of free cash flow between share repurchases, further debt reduction or book marketing cash for potential other investment opportunities?

Brent, I'll take that one. So as we think about future allocation of capital and how we will elect to reinvest in the business, I think we can first look back at historical trends in what we have said we will do and what's borne out in the numbers. So first, the priority a number of years ago is deleveraging to your point, we're quite comfortably within the target range. .

And as you think about the cycles in the business, you can likely expect us to fluctuate and delever at some point in a particularly strong point of the cycle. You could expect some further deleveraging. And then another point in the cycle, we think about how best to use that balance sheet to create outsized value and opportunistic times. So again, to look backwards as perhaps an analog. In 2022, prices ran and range bought back in $400 million in shares. But it was about 28% of free cash flow, softer prices, while we were still working on the balance sheet 2023 about 19% of cash flow -- free cash flow went to returns of capital in the form of both repurchases and dividends.

As we got within our target and towards the mid and lower end of that, you've seen us lean more into those share repurchases and increase our returns of capital, while investing in the business, building the inventory and developing this growth plan. So 2023, 2024 and year-to-date this year, you've seen returns of capital be 19%, 31% and about 50% year-to-date this year. So those are just examples of the trends, what the business is capable of expect us to continue to do all of the above and try to execute in an efficient, opportunistic manner.

When we see signs of weakness, we certainly have the willingness and capability of leaning in and buying shares. But most fundamentally, we have an extremely attractive inventory and highly profitable projects and a really exciting growth plan that's tied directly to market-driven demand and we'll continue to focus on that as well.

And I also just wanted to get your latest thoughts on M&A as it also continued to be a prevalent topical theme in upstream space here, acknowledging that you have significant low-cost inventory depth as you've outlined so far and on Slide -- are there any acreage packages potentially available that you believe could be accretive to Range's portfolio?

Yes, Greg, I'll tackle that one. I think when you look around the acreage position that we have really the efforts to block up all of the acreage has really limited some of that opportunity. However, we do see some opportunities to pick up some what I'll call white space acreage that's in and around our footprint. Some of that's in the capital numbers that you see us reported on this year, where there's roughly up to $30 million in incremental spend above maintenance type levels to manage your land program where we have the ability to pick up some of that, I'll say, the Open Track leasing that allows us to very efficiently add some inventory and also extend lateral lengths in many of those cases. .

We think that's going to continue to exist for the next few years. Of course, as you would imagine, over the course of time, that gets -- that opportunity to get smaller and smaller. There's a few other parcels that -- in areas that we've got our eyes on that are right in the, I'll just say, the operating window of our footprint. Some of them are state parks. And -- no doubt that could present a little bit of a challenge to -- given where the state may be viewing leasing today.

But you've seen a willingness from like Ohio as an example to consider leasing under their state parts. We think that's a good sign. And then on top of it, we have the surrounding operating footprint where we would be able to drill in or need maybe those type areas without having any service access. So there are some further opportunities right in and around where we operate today, high-quality inventory, and we think there will be those opportunities that surface in the future.

And we are nearing the end of today's conference. We will go to David Deckelbaum of TD Cohen for our final question.

Let me be the caboose here, guys. I just wanted to get your thoughts on -- you've commented a lot about your optimism -- excuse me, optimism around NGL markets and obviously in the natural gas markets. Just given the amount of international demand capacity that's coming online, particularly for markets like ethane, should we expect to see that percentage of your portfolio that you're directing internationally to increase? Should we anticipate that we're going to see some commercial agreements into and as new volumes are commissioned with '28? Or how do you think about, I guess, that marketing strategy and perhaps outlook for premium relative to Bellevue in the next couple of years?

David, this is Alan. So yes, I appreciate your comments, and I'm glad you see it similar as we do. There is a tremendous amount of new demand coming on. We're going to be growing our business at the same time. So we're going to be able to supply into that. The proportion of our business on the LPG side, we're involved in international exports has been roughly around 80% of our production, which puts us at the highest level relative to our peers. And what's good about the additions to that capacity that we talked about that I referenced earlier is that, that percentage is going to stay about the same.

So it will be growing, but it will be staying roughly 80%. And it will continue to have a fair amount of flexibility built into it, so that we can optimize between domestic and export markets, depending on the highest overall return. On the ethane side, similar type thing. There's -- as was mentioned previously, I believe by Mark, some of the expansions that we're seeing internationally are with people that we already have relationships with. So I wouldn't be surprised to see some more commitments in that space as we move forward.

Appreciate that. And just, I guess, to close out as a follow-up to that. As we think about the balance between gas and liquids, anything just in terms of area or geologically that would otherwise target like a mix shift over the next couple of years?

Yes. I'll close this out for us today, David, on that one. I think if you look at our program, roughly our activity level should look very similar in the next few years to what you've seen on that allocation of a portion of the field to what you've seen over the last couple of years. But over the course of time, it's very reasonable to think that our production mix will continue to get slightly wetter. Our inventory is more weighted on the liquid side. You can see where the processing capacity that we have, getting commissioned and gathering. It's also focused on the web side. coupled with the optimism that we've shared about the future of NGLs and what that demand growth looks like, we think it's all kind of hand in glove complementary to each other. .

So I would expect a similar production mix where you're going to see somewhere in the neighborhood of probably 65% to 70%, let's just say, approximate range of wet to super rich type activity. But then with an underlying 30 roughly percent of dry activity that also continues to keep that gathering system at a high level of utilization, very competitive returns, very comparable and allows us to continue to grow our NGL business as well over time.

This concludes our question-and-answer session. I would like to turn the call back to Mr. Degner for concluding remarks.

Yes. I'd just like to thank everybody for joining our call today. It's always exciting to share the results from our prior quarter. And so really appreciate everyone joining the call. As always, if you have any follow-up questions, please don't hesitate to follow up with our Investor Relations team. and we look forward to sharing our 2025 full year results and plans for 2026 at the next call. We appreciate you joining. Thanks, everyone. .

And thank you for your participation in today's conference. You may now disconnect.