Range Resources Corp Q4 FY2025 Earnings Call

Thank you for standing by. Welcome to the Range Resources Fourth Quarter 2025 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. 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 length 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 types 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 ramped back up to pre-storm levels just as quickly. This weather also provided for strong bid-week pricing for the month of February, which settled at over $7 per MMBtu. The gas marketing and operational teams did a superb job coordinating a production and sales plan, locking in strong free cash flow by selling nearly all of Range's natural gas during 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. 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 enabled growing shareholder returns. Range paid $86 million in dividends, invested $231 million in share repurchases, and reduced net debt by $186 million while investing in operations that support our growth plans through 2027. Over the last several years, Range has reduced debt by a total of roughly $3 billion. With a strong balance sheet, we have increasing flexibility to make opportunistic investments. As of year-end, Range has purchased over 33 million shares since the program's initiation in 2019, investing $744 million during that time frame. To position the share repurchase program for the future, our Board has increased the currently available capacity to $1.5 billion. In addition, the fixed per share dividend is something that we expect over time to grow slowly and reliably. We expect to increase the quarterly dividend by $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 than ever. With that, let's open the line for questions.

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 look ahead to 2026 and consider the production schedule, we anticipate that the first half of the year will resemble what you’ve seen from us in previous years, with a ramp-up towards the end of the year as we execute turn-in lines and complete wells. This momentum is expected to lead to improved commodity prices during the winter months, as you've noted. For context, our Q4 production was about 2.3 Bcf equivalent per day, and we expect Q1 to be around 2.2 Bcf per day, influenced by fluctuations in ethane extraction. We had the opportunity to capitalize on ethane pricing recently and plan to adjust extraction levels as prices change. Overall, we foresee production of about 2.2 Bcf in the first quarter. Between now and the first half of the year, as we commission additional infrastructure, we expect our production to range between the Q4 and Q1 levels, maintaining high utilization of our current infrastructure. By midyear, we anticipate adding about 300 million per day of processing capacity, setting the stage for a significant ramp-up at the end of the year, which will carry forward into the winter of 2026-2027 and into 2027. Our internal forecasts suggest a year-end production level of approximately 2.5 Bcf equivalent per day, with considerable growth anticipated in the latter part of the year due to midyear investments and the introduction of a second frac crew in Q2 and Q3. We expect an exciting year ahead as we enhance our production profile and increase activity.

I appreciate that. That's helpful. As a follow-up question, I understand that you signed a power contract for the Midwest. You mentioned that there are other opportunities you will continue to evaluate. Can you provide some insights on the premium you were able to capture? What benchmark should we consider, and how much of an uplift was there? Do you anticipate more opportunities like this, and what is your outlook for the next one to two years?

We are quite excited about the recent announcement and have been discussing these opportunities for nearly a year. We've had many conversations between Range and end users who need a reliable supply for their long-term infrastructure investments. We believe this could be the first of many opportunities for Range to engage. Our extensive inventory and diverse transportation capabilities position us well to meet energy demand not just locally, but also regionally. We feel there are numerous reasons for optimism, which you can probably hear in my voice today. Regarding what we have planned beyond this announcement, while we can't disclose the specific confidential terms of our recent deal, we believe it is scalable. We are also exploring additional conversations on how we can expand this infrastructure in the region. Additionally, we're making reasonable progress on the Fort Cherry project, focusing on narrowing down an end user that can utilize gas from our production assets at the site. There are several ways for us to succeed, whether by using our transportation resources or seeing someone build facilities directly in our production area for our NGLs and natural gas. Furthermore, it was encouraging to hear the recent State of the Union comments supporting the idea of end users generating their own power. This aligns well with companies like Range, which has high-quality Marcellus inventory capable of meeting future demands for many decades.

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, 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 nat gas 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 a 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. Looking at the remainder of the year and the timing for when the infrastructure will start to come online, which we expect around the end of Q2, we believe the timing aligns well with the wells that will come into production and the portion of DUC capacity that will be completed in the second quarter. This should allow us to see production converting into sales during the latter half of 2026. We think the timing supports improving prices as we approach the end of the injection season. Based on a typical weather forecast for summer, we anticipate around 3.6 to 3.7 Tcf in storage. With this in mind, along with the infrastructure timing, we feel everything is coming together as planned. We aim to have approximately 900,000 lateral feet transitioned to sales over the remaining months of 2026. However, similar to previous years, we maintain some flexibility in our program to respond to varying commodity price signals. For instance, some of our dry gas production is scheduled for the end of the year to capitalize on better fundamentals as we enter winter from our Northeast PA asset. We believe we have the right strategy in place but can also defer some of those TILs further into the year if necessary. Overall, considering current commodity prices and how we've managed the program, we believe the cash flow we’ve outlined will be realized, and we expect the reinvestment rate to remain quite low moving forward. The fundamentals supporting us are solid today.

I appreciate that. I guess it's somewhat of a curtailment strategy, but not entirely. I'm trying to understand the dynamics here. My follow-up is, if I could put it this way, your balance sheet is in excellent condition. You don't really need to hedge since your breakeven point is quite low. My question is, we have all been accustomed to the industry norm of selling midweek over the last 20 to 30 years just because that's how it has always been done. However, it seems like you are missing out on several opportunities in cash market pricing. I might be oversimplifying it, but why does Bidweek dictate the pace when your capital structure is in such a strong position? Why not allow for more flexibility in the cash market? I'll stop 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 involves some of the same expertise that is a part of our hedging committee to also our operations team. And how are we viewing let's just say, what lies ahead. From weather, from a macro perspective, also to any operational maintenance that we would expect and new well 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, as I consider the next couple of years, I believe we've incorporated a lot of flexibility and options regarding the timing of our turn-in lines and how we approach our liquid contributions throughout the year. So, in short, yes, we definitely want to identify the most optimal approach for our turn-in-line schedule as we progress. Regarding service costs, we've projected a low to mid-single-digit reduction in service costs while planning for 2026. Some of these costs will be fairly stable due to multi-year agreements, while others will be more variable on a 12-month basis. Given the efficiencies we've observed, particularly at Range with respect to drilling and completion, we can achieve growth with only 1 to 2 frac crews or drilling rigs, generating about 20% growth over a multi-year program, which is exciting. Overall, I don't anticipate service costs decreasing significantly from here; it seems we are nearing a bottom level. Instead, we are realizing additional savings through operational efficiencies like water recycling, multiple stages per day, and improvements in surface equipment design. In summary, we expect these savings might allow us to consider either not utilizing all our capital in a given year, reflected in the $50 million capital range, or potentially reinvesting in another strategic growth initiative depending on future demand.

That's super helpful. I wanted to revisit the supply agreement you signed, which I see as very positive. I'm curious if the $75 million allocation to the specific facility is just a starting point. Is there potential for increasing those volumes? And if not, could this specific counterparty be someone you consider for additional projects in the coming years?

Yes, Jake, I think the short answer is yes. This is a facility that will require more than 75 million dollars 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. This aligns with some of the transport we’ve picked up that will start in service in 2027 as part of our multiyear plan, but it could also be served through other transport or additional capacity we have on that same route. Yes, it's a great counterparty, a really high-quality one at that. We believe it establishes a strong foundation for structuring deals that promote growth while also enhancing margins in the future.

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?

When we examine our inventory, we have dry gas stock that will be important for our future plans. Historically, this has fluctuated between 20% to 35% of our program annually, and we can adjust that higher if necessary. An example is our recent activities in Northeast PA, where we've successfully drilled high-quality, lower Marcellus wells, utilizing existing infrastructure to add production. We have the option to increase our dry gas focus if we choose. Our Harmon Creek processing expansion set to start this year will maintain a strong momentum through 2027 and into 2028. We're also working on improving capacity with our midstream partner MPLX at the Majorsville facility, which will help us grow production without needing to build a new processing plant. Given our extensive inventory, we believe we can optimize underutilized capacities that others might miss. In the short term, we are looking at ways to enhance current processing and gathering efficiencies. This approach allows for future growth, and if the timeline for bringing additional capacity online shortens, it provides us with even more options.

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 petchem margins are 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 market has been a key focus as we consider the latter half of 2025. I will approach this from several perspectives. Stock levels have remained high in 2025 for both propane and ethane, each with its own narrative, yet also sharing similarities. Specifically for propane, there was weak demand last year, coupled with a production increase that was unexpectedly sustained by associated gas contributions. Additionally, despite lower demand and resilient supply last year, the improvement in run rates for some recently commissioned infrastructure was somewhat delayed. Export capacity expansions out of the Gulf have significantly enhanced our ability to transport an additional 200,000 to 300,000 barrels per day. We're now seeing strong figures, with propane reaching around 2 million barrels per day. Looking ahead to 2026, we anticipate greater utilization of current dock expansions and additional dock capacity that will come online by the end of the year, thanks to the same midstream providers who added infrastructure last year. Furthermore, companies like INEOS and SINOPE will add nearly 200,000 barrels of incremental demand over the next 12 to 18 months. We remain optimistic that stock levels will decrease and stabilize through 2026, with run rates improving on infrastructure commissioned in 2025 and late 2024. However, we do expect a slower growth rate for NGL contributions from the Permian and associated gas, due to some downward pressure related to current oil prices. This provides clarity on the situation, though it remains a complex issue. We anticipate by year-end, stock levels will stabilize and pricing will improve to a healthier level.

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.

Thanks for joining us this morning, Kevin. When we compare the situation now to a year ago, some aspects stand out. I previously touched on this, but I'll keep it brief. We adjusted our program with future pricing in mind. While prices have dipped slightly, the overall structure of our risk assessment is intact, reflecting the cash flow we anticipated the business would generate. We designed the program based on existing capacity rather than assuming new demand. Specifically, we are leveraging Energy Transfer's Rover incremental capacity of about 250 million a day, which connects us to both the Midwest and Gulf markets where we are actively marketing. This strategy enables us to capture market share rather than seeking growth for growth's sake; we need to ensure we have an outlet for those molecules. We believe capturing this market share demonstrates our capacity to maintain a solid inventory as a foundation for our commitment to this pipeline, which also reaches markets expected to see increased demand in the future. This provides us with good options and flexibility as we advance. As we look towards 2028 and beyond, the conversation about growing demand will become increasingly relevant. Our marketing deal reflects this and signifies the first of several opportunities we can explore regionally, which will be critical for our next phase of growth, contingent upon actual demand materializing. We are focusing on increasing market share as part of our current strategy and believe the pricing environment still supports our execution of the plan over the next several years. Moving forward to 2028 and beyond will depend on ensuring there is a market for that production in the in-basin region as demand develops.

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. As I mentioned earlier, we begin by looking at market indicators. The information available and the forward curves are not perfect, but they serve as our best starting point for predictions. Our guidance reflects an improvement of about $0.05 year-over-year compared to the initial baseline. Considering the start of 2026, we have had a strong beginning. It's worth noting that over 90 percent of what we project for the first month holds significant value. Variations from quarter to quarter and the seasonal factors that influence them, as well as year-over-year changes, can be influenced by weather. However, the reliability of our narrow differential and the premium we achieve compared to the Henry Hub realized price per Mcfe is attributed to our transportation strategy. To summarize, our guidance is consistent, as Mark pointed out, and we will continue to enhance it through the expertise of our marketing team throughout 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.

Thank you for joining us, Neil. Regarding your question, we were able to effectively manage our pricing at a $7 level during Bidweek, which significantly impacted our cash flow after that cycle. As we've discussed previously, we anticipate increased volatility moving forward, whether due to weather or other factors. I'm proud of our operating team who performed exceptionally well under challenging conditions with sub-zero temperatures. Throughout that time, we only had one or two pad sites down, and they were restored quickly. This success results from years of planning and collaboration between our field team and our midstream providers. We continually review our winter operations and enhance our production facility designs to minimize downtime, ensuring a consistent flow from the wellhead to processing plants and ultimately to our essential end users. This has proven especially crucial during winter storms, like the one last week that affected some in the Northeast, where the flow of natural gas has been vital for power generation in homes. Our team did a fantastic job, and as I mentioned earlier, we have a multidisciplinary plan to capture value during Bidweek and optimize daily operations to seize upside opportunities throughout the month. We do expect more volatility moving forward, and our multidisciplinary team will be engaged regularly.

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.