Range Resources Corp Q1 FY2026 Earnings Call

Hello. Welcome to the Range Resources First Quarter 2026 Earnings Conference Call. 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. 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 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 in company history. Looking at the operational results for the first quarter, production came in at 2.2 Bcf equivalent per day. Range expects production to increase slightly in the second quarter before jumping meaningfully higher at the midpoint of the year as gas processing and related infrastructure is put into service. This will push production to 2.5 Bcf equivalent per day by year-end, all in line with our previous guidance. Capital for the quarter came in at $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, the 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 in drilling and completions continues to support our operational plans through 2027 and beyond as we maintain a resilient DUC inventory for future optionality on capital and production. Range's winter operations program also had a very successful first quarter and kept production volumes flowing through the harsh winter conditions ushered in by winter storm Fern. Production facility design enhancements, strategic staging of backup power, and working in concert with our gathering partners are just a few aspects of the program that the team continued to focus on. All of this resulted in the team maintaining strong field run time and supported record free cash flow for the month of February. Hats off to the team for their dedication to safely keeping our production flowing. Before moving on to marketing, I'll briefly touch on service costs. We anticipate the cost of our electric hydraulic fracturing fleet to remain unchanged given 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 pre-purchase 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 positively impact storage balances and improved fundamentals across the various products. 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 provide 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 generation and prudent allocation of that cash flow, balancing returns of capital, balance sheet strength, and the optimal development of our world-class asset base. As we sit here today, our multiyear plan is on track and years of disciplined planning have placed us in the strongest position in our company history, having derisked a high-quality inventory measured in decades and translated that into a business capable of generating significant free cash flow through cycles. With that, let's open the line for questions.

Our first question comes from 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 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. Our marketing team has done an outstanding job over the years building relationships and managing exports from the East Coast, cargo by cargo. These relationships and the understanding of the timing—what you see on a screen may not reflect the physical situation, as cargo loadings are planned one to three months in advance—are crucial. To take a step back, roughly 80% of our propane is exported from the East Coast. The majority, over half, is connected to medium-term contracts tied to ARA and FEI. We export from the East Coast, benefiting from international demand for U.S. molecules on the water, which are needed for chemicals, heating, and consumer demands. Regarding those deals, we cannot go into specifics, but they are very strong netbacks, as shown by the $4-plus corporate average premium to Mont Belvieu.

I appreciate that. I wanted to ask about Fort Cherry. In the last call, you mentioned that progress was being made in finding an end user. Could you provide an update on that? Additionally, Mark, how are you considering the marketing strategy with the clearer opportunities in LNG given the ongoing demand, especially compared to the power center or data center projects that seem to need more negotiation to finalize?

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 an analyst 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?

As we look ahead to 2026, our production patterns should resemble those from recent years under a maintenance-to-maintenance plus program. For Q1 production, it closely aligns with what we experienced a year ago. Several turn-in lines that were established at the end of Q1 will now help us utilize the available infrastructure. We expect to engage in the commissioning of infrastructure towards the end of Q2 and into the beginning of Q1. Additional gathering and compression will come online toward the end of Q2, and processing will coincide with the midyear point. The loop gathering system we operate provides us with various options for efficiently moving resources throughout the field. We anticipate a significant increase in production during the latter half of the year, with a steady output projected through Q3 and Q4, culminating at 2.5 Bcf equivalent per day by year-end. The second completion crew, which has commenced in Q2, will work through the DUC inventory, transforming it into sales over the next six months and driving the production growth in the second half of the year. This will leverage our processing and gathering infrastructure while also building momentum toward our target of 2.6 Bcf per day in 2027. Everything is on schedule regarding our infrastructure for this year.

Got it. Okay. That's really clear. Now for my second question regarding the LPG side, I appreciate all the prepared remarks and the answers provided earlier. I'm interested in your updated thoughts on the macro situation, considering all the domestic and international factors and the elevated shipping costs. With the expectation of U.S. propane exports growing to over 2 million barrels a day by midyear, do you believe this will address the domestic inventory surplus? Additionally, from an international perspective, what are your thoughts on China's PDH run rates and any other factors that could influence the premium you anticipate over Belvieu?

Thank you, Gabe. I'll begin by discussing the macro perspective. Exports have remained strong, particularly thanks to the DUC capacity expansion that was implemented last year, which has helped reduce current stock levels. It's widely recognized that stock levels are high, approximately 70% above historical averages. However, we added 150,000 barrels per day in export capacity last year, which has been utilized effectively. Importantly, there is also a new flex capacity from the Gulf contributing an additional 360,000 barrels per day that has recently started operations; this was initially intended for ethane but is now in service, with the first vessels having departed the DUC, which is promising for lowering stock levels moving forward. Furthermore, we anticipate another 300,000 barrels of capacity to come online on the export side by late 2026, which should significantly impact stock reduction efforts. From a demand perspective, over the next two years, an additional 500,000 barrels of demand will arise from the PDH infrastructure. This aligns well with our goal of increasing waterborne exports while also addressing rising demand. The current market dynamics have been unique, and despite challenges, our business has proven resilient, as highlighted by our recent quarterly numbers. Moving forward, we expect exports to stay robust, with ongoing demand for LPG barrels from the U.S. playing to our advantage, particularly since we export about 80% of our LPG from Marcus Hook. Additionally, the Repauno terminal, set to begin operations in January 2027, will enhance our access to waterborne exports. In summary, we're seeing growing demand, improving run rates, and we expect stock levels to stabilize over the remainder 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, winter storm Fern. We had high gas prices. That allowed us to actually realize better gas returns. We actually pulled back on ethane recoveries, so that we could 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 pre-crisis levels. That is now somewhere around, call it, plus 30% or plus 40% relative to pre-crisis levels, still very attractive but not quite what we were seeing in the middle of March. 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 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 mid-cycle view. But one of the pushbacks we get often is the weakness in Permian, specifically WAHA, now trading under $6. 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. When considering the dynamics of Permian gas, this isn't new territory for us; we've observed similar trends over the past several years. The rig count has not changed significantly since the beginning of the year, indicating that increased rig activity has not led to substantial growth yet. There has been an uptick in completion crews, approximately 12 to 15 more, but this trend mirrors what we typically see at the end of a prior year as we begin a new one. However, activity levels remain below what we've experienced in previous years. This situation correlates to a decrease in DUC inventory, which is down about 20% across the lower 48 states. In terms of natural gas, we believe there will be some growth from the Permian. Currently, we are at 20 Bcf a day for LNG, which is encouraging, especially with the meaningful commissioning gas moving through Train 1 at Golden Pass. However, production levels do not seem to align with current front month pricing. As we approach the end of the injection season, we anticipate storage levels of around 3.8 to 3.9 Tcf, similar to the last couple of years, combined with the demand we see emerging. This places us at about 37 days of supply, which is 5 days below the 5-year average. We believe this sets the stage for more volatility, as we've witnessed in recent years. During such times, as we saw last quarter, Range has the potential to capture significant cash flow.

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. That makes perfect sense. Regarding the DUCs and their impact on growth prospects, how much do we expect current conditions to affect the production split? Are we leaning towards more wet versus dry gas, or is everything pretty much set for the upcoming quarters?

Yes, Paul, that's a great question. Regarding the DUC inventory accumulated over the past 24 months and what to expect moving forward, I have a couple of points to share this morning. First, the composition of our activities should resemble what you've seen from our program in recent years, where we anticipate approximately 70%, or maybe around 65%, for liquids activity, with the remainder focused on dry gas. This is due to various reasons, including the effective utilization of our gathering systems, which helps keep costs low, and the solid returns we see on the dry gas side when compared across our assets. With the infrastructure that will be operational around mid-year, we are focusing more on liquid activity. Consequently, our turn-in lines and completions will prioritize liquids-rich activities, benefiting from the new processing capacity and gathering systems, as well as the Repauno terminal capacity we expect to be operational by early next year. Therefore, our DUC inventory will likely be skewed more toward liquids, similar to what you've observed in previous years. Another point to mention is that we have built up around 500,000 lateral feet over the last couple of years. With consistent activity from our electric hydraulic fracturing crew, along with additional spot activity in the next six months, we expect to utilize approximately 400,000 lateral feet over the next 18 to 24 months, at which point we'll reassess our strategy 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. If we look back on Q1, we had one rig and one frac crew, which resulted in $139 million in capital spending. To give more context, completions account for about two-thirds of our operations. If we add a second completion crew, that will contribute to our expected increase in activity for the second quarter. Efficiency is always a factor, and our ability to move water efficiently helps us meet or even exceed expectations. So, that's how I see our capital spending shaping up for the second and third quarters. The completions team has excelled in completing stages per day, even under challenging winter conditions, and we might find that we don't need a second crew as much as initially thought given the efficiency we've achieved with 17 stages per day. So, for the second and third quarters, we will maintain one drilling rig along with the second completion crew. As for production, I anticipate an uptick towards the end of the quarter, leading to an increase from about 2.3 Bcf equivalent per day around mid-year to approximately 2.5 Bcf by 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 lift Mont Belvieu prices. The theory makes a lot of sense. I guess the concern is that the market is more like dry gas where hub and TTF remain decoupled. So curious how you guys explain why this market is different and why there could be better connectivity in global prices?

This is Alan, and that's a good question. You're asking how this market differs from the past. The main difference this time is the closure of the Strait of Hormuz and the damage in the Middle East. The region typically contributes around 1.5 million barrels a day to a global waterborne LPG market of about 5 million barrels per day, meaning it usually accounts for about 30%. However, roughly 1 million barrels per day has been missing from the market for the past six weeks. If the situation starts to resolve at the end of April, it might still take 2 to 3 months for that flow to return, considering damage assessments and repairs. This creates an unprecedented gap. Additionally, during this time, we're depleting inventories across the chemical supply chain, from widgets to polymers to olefins, and this inventory will need replenishing. These factors contribute to heightened demand compared to pre-crisis levels, and I believe we will continue to see the effects of this through the rest of the year and into next year. That's one of the significant differences. Fortunately, from a U.S. standpoint, we are expanding export capacity. We've provided a lot of guidance for 2025, with new capacity coming online recently and more expected next year, as well as additional significant capacity in 2027, 2028, and early 2029 to help address the global shortfall and maintain strong demand for U.S. supplies. Overall, the situation has improved long-term due to these changes. I hope that 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. Thank you for your comments on the natural gas. My second question is about the growth program. You're currently halfway to your target of 400 million cubic feet of gas equivalent or 20,000 barrels of NGLs that will be sold from the new East Coast stock. Can you provide any information about the product split, specifically whether it's ethane or LPGs? Additionally, should we anticipate any changes in the current flow of contracts compared to what you have now?

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?

That's a great question. Regarding the possibility of Range moving to a net cash position, the answer is yes, especially during periods of strong commodity prices. If we experience a significant increase beyond mid-cycle pricing and our cash flow exceeds expectations in the business cycle, we might consider accumulating liquidity. In such scenarios, I would expect our stock to perform very well. Conversely, during a downturn or a return to mid-cycle pricing, we could see substantial cash flow, potentially exceeding 100%. To put it in perspective, having $1 billion in debt represents less than one turn of leverage. I'm not suggesting we will take on more debt, but just highlighting that there would be ample opportunity to invest during a downturn if stock prices decrease, while we maintain solid free cash flow and a strong balance sheet. There are times when buying back 10%, 15%, or even 20% of the company in a short time frame is feasible. It’s these kinds of significant investments that yield long-term benefits for the company. We will continue to operate with the goal of reducing share count consistently over the years, while also looking for larger, more impactful opportunities given our strengthened balance sheet.

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.