Welcome to the Range Resources Fourth Quarter 2024 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risk and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks, there'll be a question-and-answer period. At this time, I would like to turn the call over to Mr. Laith Sando, the, excuse me, 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 2024 Earnings Call. The speakers on today's call are Dennis Degner, Chief Executive Officer, and Mark Scucchi, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we've posted on our website. We may reference certain slides on the call this morning. You'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, let me 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 completed the operational program safely, efficiently, and within budget while generating free cash flow and investing in the long-term development of our world-class asset base. Range's ability to generate free cash flow at trough-level natural gas prices in 2024 allowed us to repurchase shares, distribute dividends, and meet our balance sheet targets, all while making countercyclical capital investments that support the multi-year plans we'll discuss here today. I believe that Range's 2024 results are a testament to the resilience of our business and the financial flexibility we've created over the last several years. Range's low capital intensity is a key component of our through-cycle profitability and is the result of Range's class-leading drilling and completion costs, shallow base decline, large blocky core inventory, and talented team. Another key component of Range's resilience is the diversity of our production stream, and the value of Range's liquids business was on display once again in 2024. Our ability to market ethane, propane, and butane into the international market drove the highest NGL premiums in company history, and we expect premiums versus the Mont Belvieu Index once again in 2025. Looking at the entire production makeup, Range saw an aggregate unhedged price realization of $2.76 per Mcfe for the year, which is a $0.49 premium over Henry Hub natural gas and a clear differentiator versus purely dry gas producers. When you combine our efficient operations, low capital intensity, and liquids revenue uplift, the output was another quarter and another year of positive free cash flow despite challenging natural gas prices. Before diving into Range's 2025 plans and the three-year outlook we announced, I want to briefly touch on some of our results for 2024. For 2024, Range ran two rigs and one completion crew, driving capital investments of $654 million while generating production for the year at approximately 2.18 Bcfe per day. This production level was above guidance and is the result of strong well performance and continued optimization of gathering and compression infrastructure that was mentioned on recent earnings calls. This past year showcased a continued theme of operational excellence. Drilling saw several new efficiency records set for the program while drilling a total combined lateral footage of over 800,000 feet. For context, maintenance production requires approximately 600,000 lateral feet, so the 800,000-plus feet from drilling points to the momentum Range has in the program for future periods. For the year, the team drilled 59 laterals with an average horizontal length over 14,000 feet. 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 footprint and consolidating infrastructure requirements. Completions also saw continued efficiency gains and strong safety performance from the electric fracturing fleet we picked up at the start of 2024, with the team completing 3,300 stages for the year and underpinned by a 6% increase in frac stages per day versus the previous record set in 2023. Now turning to our plans for 2025. Consistent with our 2024 operational plan, we project to run an efficient two drilling rig and one frac crew program for the year ahead. This drives an all-in capital budget of $650-$690 million, which consists of the following: approximately $530 million of all-in maintenance capital, including maintenance land and facilities, an incremental $70-$100 million of drilling and completions capital that will support future growth, up to $30 million for targeted acreage that supports increased lateral lengths and offsets our lateral footage being turned to sales during the year, all while keeping our 28 million feet of Marcellus inventory relatively unchanged. And lastly, approximately $20-$30 million for pneumatic devices and production facility upgrades to further reduce emissions. This is part of an estimated $50-$60 million project, with $10 million already completed in 2024. This capital plan will result in modest production growth in 2025 to approximately 2.2 Bcfe per day, while building additional in-process inventory for increased growth capacity in 2026 and 2027. We expect the first half of the year production to be slightly down before increasing into the second half of the year and carrying into 2026. Looking beyond 2025, we are planning to add approximately 400 million cubic feet equivalent of daily production over the three years. This will put 2027 annual production at approximately 2.6 Bcfe per day, with the capital required to reach this level of production at $650-$700 million per year. This should sound familiar to our investors, as it approximates the two rig and one completions crew program we ran in 2024 and plan to run again in 2025. Importantly, our production plan over the next three years will utilize incremental processing capacity at the MPLX Harmon Creek facility and feed directly into natural gas transportation capacity we have secured to the Midwest and Gulf Coast regions. Range will also be sending incremental NGL production to a new East Coast terminal that is expected to generate the same export premiums that have benefited Range shareholders for many years. Over the three-year period, Range's reinvestment rate is expected to remain well below 50% at a $3.75 natural gas price level, allowing for increasing returns of capital while thoughtfully growing the business into known end markets. And at current strip pricing, the reinvestment rate would clearly be even lower. The resulting 19% increase in production over the three years will modestly improve margins as certain fixed costs improve on a per-Mcfe basis, further strengthening Range's break-even to approximately $2 for NYMEX natural gas. At the end of the three-year period, we also expect to have maintained our 30-plus years of high-quality Marcellus inventory, with modest land spending in line with recent years. Having decades of inventory will support additional growth, as it is called for. Alternatively, at the end of this production profile, Range could maintain 2.6 Bcfe per day of production with approximately $570 million of annual drilling and completions capital, the equivalent of only $0.60 per Mcfe. This required maintenance capital is an improvement versus prior disclosures and is the result of continued strong well performance, operational efficiencies, and continued optimization of gathering and compression infrastructure. We believe this 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. 2024, as in years past, highlighted the strength of Range's business. Throughout business cycles, we intend to generate free cash flow, prudently invest in the business, and return capital to shareholders. Despite low commodity prices in 2024, Range accomplished just that: free cash flow, prudent investments, and returns of capital to shareholders. Additionally, our prudent investments were not constrained by cash flow, such that we were only able to simply maintain the business, but instead, we have positioned the company to strategically take advantage of demand growth. To recap, Range paid $77 million in dividends, invested $65 million in share repurchases at prices well below our view of long-term value, and reduced net debt by $172 million while investing in operations. Range generated $453 million in free cash flow that made those capital allocation decisions possible, executing an operational plan that stands in stark contrast to many industry peers. For upstream producers, quality assets with low full-cycle costs, the ability to reach a diverse set of customers with a variety of price points, and a rock-solid balance sheet to provide flexibility are all necessary to consistently create value. As we sit here in early 2025 with an efficient plan to modestly grow production, we are also carefully positioning the business for evolving domestic and international demand for natural gas and natural gas liquids. In the past, we had stated that we wanted line-of-sight deliverability to growing demand before we would grow production. As incremental demand is materializing today, Range is positioned with its infrastructure and inventory to do just that as a reliable long-term energy supplier that generates strong returns from a resilient business. Over the past three years, Range has reduced net debt by over $1.3 billion while also returning $678 million to shareholders in the form of share repurchases and dividends. In total, that is more than $2 billion in capital returned to stakeholders. With the balance sheet in our target range, we have increasing flexibility to exercise opportunistic use of the $1 billion available under our existing share repurchase plan. In addition, the fixed dividend is something that we expect over time to grow slowly but steadily. It's our expectation to increase the quarterly dividend by a penny per share or 12.5% at the next announcement. Here's a key message we intend to deliver today: we can thoughtfully grow Range's business in order to increase returns of capital to shareholders, a goal that is underpinned by quality, long-duration assets, and a strong balance sheet. With perhaps the lowest decline rate of comparable companies, Range's capital efficiency stands out in terms of costs per Mcfe, full-cycle, break-even costs, and the required reinvestment rate of cash flow to maintain production. As a percentage of cash flow, Range should regularly be near the lowest call on cash for sustaining CapEx. Critical in our assessment of growth potential is our ability to sustain a low full-cycle cost structure, low reinvestment rate, and durable high margins. Like Dennis mentioned, Range could hold 2.6 Bcfe per day of production with approximately $570 million of annual drilling and completion capital or approximately $0.60 per Mcfe. Simply put, the result of efficient production growth by Range is growth in cash flow per share, which we expect to be compounded by a declining share count. In a profitable business, cash taxes are a reality. At year-end 2024, Range had federal NOL carryforwards totaling $1.4 billion. These NOLs will serve to reduce taxable income in coming years. These NOLs can be used to reduce up to 80% of a given year's federal taxable income. In addition, Range had Pennsylvania state NOLs of roughly $770 million. All combined, the value of Range's NOLs and tax planning should enhance after-tax cash flows over the next two years by more than $300 million. For several years, we have spoken about the undervalued option of growth in the Range business. We stated that growth would be appropriate when we had clear line of sight and deliverability to incremental demand. Further, we explained this could be accomplished with either new transportation capacity picking up uncontracted capacity or through increased in-basin end demand. We believe today's announcements illustrate the physical link of Range's inventory through gathering, processing, and long-haul transport directly to growing demand centers, enabling efficient, thoughtful growth to harvest additional value from Range's immense inventory. The consistent capital allocation strategy, carefully executed, we believe has positioned Range uniquely within the industry to capture significant value for our shareholders both today and long into the future. Dennis, back to you. Thanks, Mark. Before moving to Q&A, I'd like to congratulate our team for their accomplishments discussed today and their ongoing dedication to our continued safety performance, operational improvements, and progress toward our stated financial objectives. These results harvested in 2024 and across prior years have laid the foundation for our plans in the years ahead and beyond. Simply put, Range's business has never been stronger, having de-risked a high-quality inventory measured in decades and translated that into a business capable of generating free cash flow through cycles. With that, let's open the line for questions. Thank you, Mr. Degner. The question-and-answer session will begin now. If you would like to ask a question, please indicate by pressing star 11 on your telephone. If you're on a speakerphone, please pick up your handset before asking your question. If you would like to restore your question, you may press star 11 again. One moment while we go ahead and compile the Q&A roster. And our first question from today will be coming from the line of Scott Hanold of RBC. Your line is open. Yeah, thanks. Good morning. Taking a look at your three-year outlook and your plans to grow into 2027, can you give us a little bit of sense on the thought process? First, could have you grown sooner than later? You obviously had some DUCs that, in theory, could have pushed growth a little bit more in 2025. And why the decision to kind of hold back for 2027 versus do it now? And as you look into that 2027 outlook, can you give us a sense of, is there a mixed shift between the gas and the liquids? Yeah, good morning, Scott. I think when you start to look at 2025, a lot of things you've heard us say in the past, and Mark touched on this morning in the prepared remarks, have really started to come together and inform our approach for not only this year, but then what that looks like for 2026 and 2027, and I think we really wanted to see some clear line of sight on some of those demand growth opportunities and also have a home for the production. We know that that is a critical part of the overall equation because it feeds to the top line, and that is our cash flow and our cash flow goals that we're going to have over the next several years, so as you think about 2025, could there have been some utilization of the inventory generation over the past one to two years? Maybe so, but again, we wanted to see that clearer line of sight around those demand growth opportunities and then start to translate that into a trajectory over the following couple of years, but I kind of get back to something you've heard us say as well. We're really running a lean program, and it's operationally efficient with the one completion crew and the two drilling rigs. We feel like that presents that strikes the correct balance of appropriate, modest, healthy growth, gets it to that production to end markets that can utilize that. There are known end markets that we've transacted in and around for the past several decades, and so again, our knowledge level is high in that space, but it also allows us to continue to grow around our efficient operational program. So we think this strikes the right balance, but the inventory will get utilized in how we see is really kind of the best trajectory over the next three years. Got it. And as you look at that growth into 2027, just can you give me your thoughts on, do you hedge some of that to mitigate potential weakness in price? Like what if prices are weak as you build into 2027? Are you willing to kind of hedge into 2027 at the right prices to kind of secure some of that? And/or would you evaluate doing, I guess, end-user kind of transactions you can kind of lock in a price? Hi, I think the answer to your question is kind of yes to all of the above. One of the hallmarks of our program is flexibility that we built into it through diversity of the outlets. Fundamentally, I think it's important to keep in mind the structural hedges, the hedges that are just built into our business by the nature of our production. With 70% gas, 30% liquid, the uplift and the resilience, combined now with where the balance sheet is, the need to hedge is simply greatly reduced. What we do hedge, that philosophical approach to providing some level of insurance for steadiness to protect the balance sheet, to preserve the optionality of being a bit countercyclical in order to create really outsized value, that's the fundamental guiding principle there. So I think the simplest answer is yes, we do intend to continue to hedge a very modest portion of our production, but we do have flexibility. And I think as we look at the macro backdrop on both gas and liquids, the end markets to where we're going to be delivering this production and what that incremental demand, really demand pull is, we feel very good about that. At the end of the day, as Dennis stated, free cash flow generation and growing free cash flow is the goal here. So we can adapt the program based on macro trends that we see, but we're very confident given the low break-even, low capital per unit of production, a low cost for incremental production, and the margin will generate off of where these molecules are being delivered to about what that path looks like. Thank you. Thank you. Thank you. One moment for the next question, please. And our next question will be coming from the line of Jake Roberts of TPH and Company. Your line is open. Morning. Morning, Jake. Morning, Jake. Maybe starting out with the new gas takeaway agreements. I was wondering if you could frame those relative to your current agreements and what you might see on the cost side over time as you start utilizing those, and also if you could disclose the ultimate split between Gulf Coast and Midwest and if there is the ability to kind of move those volumes around if necessary. Yeah, good morning. I think when you look at the transport that we've been able to acquire, it's going to look and feel a lot like what you've seen from our current portfolio. So in a lot of ways, Jake, the percentages really don't move significantly or really materially versus what you've heard us talk about in the past where essentially 80% of our gas gets out of basin and our total 50% gets down to the Gulf. So it's a little bit more weighted in the direction of the Midwest, but there's significant exposure in this transportation that gets us to the Gulf, which we really like. From a cost perspective, it's going to be right in line with what you've seen us in prior cycles on GP&T reporting. So really no change from a cost structure there. But inherently, from a total perspective, we would expect to see some relief as we talked about in the prepared remarks over the course of time as we see efficient use of that infrastructure and also some portions of our contracts in the past that have some cost roll-off over the course of time. So there's still an opportunity for us in the near term to see GP&T look really consistent and in the future continue to see it actually roll off as well. I think when you look at where this transport gets to, one thing that gets us excited is the storylines around the emerging demand that could exist in the Midwest and where this transport essentially terminates at. So there's a real opportunity for us as you think about the utilization of it. Thanks. I appreciate the detail there. And my second question is on the multi-year outlook and specifically the capital that you guys have laid out. Can you frame how we should be thinking about the cadence of that 675 over 2026 and 2027? And then what exactly is falling off the program to get to the 570 in the longer-term environment and what rig count does that contemplate? Yeah, I think the way I would frame this morning would be capital should look really pretty consistent. And I know we framed it with some guardrails for $650-$700 million. And I think ultimately therein lies the variation of what we think the next three years will look like as we deliver on this profile. When you start to get to 2026 and 2027, though, what you start to see is some of those capital dollars on a, I'll just say, allocation basis start to get a little bit more weighted toward completing and completions activity for that DUC inventory that's slowly been building over 2023, 2024, and that will get built over the balance of 2025. So you really get to use that as a tailwind then for those following two years of this three-year outlook that we've communicated. Again, the capital we'd expect to really be consistent in that $650-$700 type level. Thank you. Appreciate the time. Awesome. Thanks, Jake. Thank you. One moment for the next question, and our next question will be coming from the line of Bertrand Donnes of Truist Securities. Your line is open. Hey, good morning, guys. Just wanted to start off, and one of your peers made a meaningful distinction this quarter on the difference between maybe an attractive gas strip price versus what they were actually seeing on the supply-demand side, so just wondering, first, was this decision made using one or the other? And then maybe when we get to early next year and you're staring down that ramp into 2027, are you looking at the strip price at that point or are you looking at maybe there were some hyperscaling deals or maybe in-basin demand? Just which one you're looking at more? Yeah, I'll start this morning on that question. Bertrand, thanks for joining the call. Yeah, I think there's, I'll just say, commodity price alone really wasn't the driver in this conversation as we started to formulate a three-year plan, and I think we touched on a couple of aspects in the prepared remarks, but really it was around our free cash flow goals and objectives over the balance of the next three-year coupled with the demand that we see we have a line of sight on and the transport that it gets us to, again, those known end markets, so when you start to look at the balance of the go forward, you've seen some significant strengthening in strip pricing, no doubt, and it's tied to a lot more than just a conversation around weather and that gas storage levels, which starts to get us pretty excited. It includes LNG commissioning and the run rates. It includes the NGL story for our overall realizations and what that means from a cash flow force multiplier for Range, so I think as we look forward, again, commodity price wasn't the biggest driver. It was really our cash flow outlook and our goals and objectives around that, and as we talked about earlier, the ability to have that production get to demand centers and known end markets. We fully expect that there's going to be, we'll just say, power demand conversations and AI and data center type growth opportunities in basin, but that really doesn't have to be a part of the conversation today for us on this three-year path because of our ability to market this production into those known markets and again, on existing transport. So if other opportunities start to materialize, then we can have an opportunity to help feed some of that growing demand either through future growth outside of what we're talking about today, or it could be through existing production that's sold in basin that could get reallocated to that future growth profile. So very optimistic about the, no doubt, the future of natural gas prices as we start to think about, quite honestly, where things have shaped up over the last several years. Gotcha. And then the second one just, is there room for external growth through maybe acquisitions in this three-year outlook? Maybe you outlined this growth scenario to highlight that you don't need to add any more inventory, or could you maybe grow and still find a way to make it accretive with an acquisition? I'm just not sure if it's an either-or situation. Thanks. Yeah. Sure. This is Mark. I'll jump in. I wouldn't say necessarily it's an either-or. However, this organic growth is so compelling, the quality and depth of our inventory, as we talked about in the past with the quality and 30-plus years. For an acquisition to make sense, it really has to make Range even better than it is today and create incremental value. So I think the phrase we've used before is at the high bar. We study the basin. We study the assets to understand geology and pipeline flows and what the potential opportunities may be. But Range as a standalone entity operating and harvesting the value of the existing inventory with the overlay of our business, our contracts, the marketing prowess of the team is a great path. So we'll be open-minded, but it's challenging. Perfect. Just to clarify, so if you made an acquisition, you wouldn't need to slow down growth or anything to adjust for that? Then, thanks, guys. That would be a hypothetical. So if that were to happen, we'd evaluate it at that time. Gotcha. Thank you. Thank you. One moment for the next question. And the next question will be coming from the line of Kevin MacCurdy of Pickering. Your line is open. Hey, good morning. I appreciate the details on the multi-year production and CapEx plan. I wonder if you could help us bridge the gap between the production 2.2 BCF a day in 2025 and 2.6 in 2027. Will the production ramp up at a measured pace in 2026, or will it be kind of a steeper growth in the back half of the year? And any specifics on when those contracts come online? Yeah, I think if you start to look at the production profile in 2025, I'll start there. It'll look pretty similar characterized to what you've seen in the past, where the front half of the year can be activity-driven. You're going to see some turn-in lines start to then materialize through the back half of the year into, I'll just say, adding that incremental production. So it'll be higher in the back half of the year, a little flatter in the front half of the year. But some of the infrastructure that is in process of being constructed and will get commissioned, some of that gets commissioned in late spring, and some of it's going to be in the fall time period. So as you can imagine, that compression and gathering support for this growth profile will then start to materially move our production profile in that back half of the year and then provide momentum as we start to look into 2026 and 2027. The transport and the processing at the MPLX facility, that all comes together in 2026. So again, further supporting that momentum that we talked about for the production growth in 2026 and into 2027. So it'll be, I'll just say, a slow and steady incremental increase across that back in 24 months. But as we talked about also a little bit earlier, you'll see some of the capital then start to get distributed or weighted more toward the completion side to utilize that DUC inventory that's being randomly built over the balance of the last few years and this year. So it'll just look smooth and steady, I think, from a capital standpoint and activity basis, where it'll look like two rigs and one frac crew, but you'll see a little more completion activity start to materialize and get into the program as you see this infrastructure reach commissioning phase. Got it. Appreciate those details. And then you touched a little bit about the margin expansion on the prepared remarks, but I was curious if you had any more particular details on the contracts. Will you get better margins on the extra gas and the NGL you're producing into 2027, or maybe where do you see those breakevens? I think all in, as we pointed to in the materials, a $2 type break-even. When you factor in the deliverability of all of our production, the uplift from NGLs and so forth, that $2 is a decent frame of reference for break-even for RRC. As far as driving down fixed costs, be it direct operating costs, be it some elements of the GP&T, G&A, continuing to drive down interest expenses, we pay off debt. There's pennies here and pennies there across. There are a variety of discussions on the marketing side and what those contracts look like. So as we have a long history of doing long-term contracts, partners domestically and internationally, those margins can be impacted simply by long-term relationships and the creative ability that we've brought to pricing structures in the past. So it's going to be a variety in all of the above in terms of continuing to control costs prudently and hang on to a durable margin and expand that margin over the next several years as we see this demand come online. Thank you. Thank you, Kevin. Thank you. One moment for the next question. And our next question will be coming from the line of John Annis of Texas Capital. Your line is open. Hey, good morning, all, and congrats on a strong year-end. For my first question, you noted that you've secured additional transport, processing, and export capacity to support your planned production profile. Is the right way to think about growth beyond that 2.6 Bcfe a day level post-2027 requiring additional transport capacity or incremental in-basin demand to support it, and then perhaps if you could also provide some color on the opportunity set to secure additional uncontracted takeaway? Thanks. Yeah, good question this morning, John. Thanks for joining us. I think when you start to think about what's beyond 2027, I think in a lot of ways, we can be patient, and that's really what's happened over the balance of the last couple of years, and there could be opportunities for us to take on transport that goes underutilized by others in the future as well. It's hard to have line of sight on what the volume of that could look like today. But I think when you start to really look at what inventory exhaustion and the role that could play for basin producers and the competition for capital allocation within their given portfolios versus Range, and you certainly heard Mark touch on it a couple of minutes ago. I mean, 30-plus years of inventory in the Marcellus alone really affords us a lot of opportunity to grow the company as demand continues to materialize. And we can be patient and look to add transportation as it comes available in the future. Or we've touched on in prior calls and today to some degree, what future opportunities that are regional or in-basin materialize over the next few years. If you look at the AI and data center forecasting numbers, there's a lot of numbers floating around. But ultimately, if you look at the forecast from PJM here recently, that's been increased. Yet again, ultimately, you're talking about if natural gas plays its lion's share of supplying and consistent with historical supply percentages, that power generation growth, you're talking about the opportunity for another four BCF a day. That's something that Range could play a part in as an example. So again, I'll underline this with a conversation around we have the opportunity to be patient and see what materializes. It could be a combination of holding production flat beyond that. It could be more growth with filling demand that continues to materialize either in our backyard where our assets are or in other markets on transport that goes underutilized by others. Terrific color. As my follow-up, you highlighted how maintenance DUCs continues to trend lower, decreasing around $50 million this year versus last. Could you help us understand the drivers of those savings and tacking on to that? What additional levers do you have to continue to drive that down over time? Yeah, I think the first place I would start is the team has continued to just exceed expectations around long lateral development and the efficiencies that get captured there. I could spend a whole earnings call probably talking about some of those results alone. But ultimately, if you look over the past couple of years, we've seen double-digit% increases in our drilling efficiencies, set several records in the program. And so I think when I start thinking about what the future is going to look like, I would expect us to continue to chip away at further improvements in our long lateral development and the efficiencies there. And that translates into a lower DUC cost per foot or the potential for that. Now, the flip side of that is you also have then the challenge of a pad site that was at the beginning of your following program year gets pulled into your current program year, and so that will result in us thinking about how that translates into production growth over the balance of the three-to-five years as we start to look out, or does that allow us to be more efficient and pull down capital on a given program year? But our drilling and completion efficiencies have just really been great. I think the other areas is we've seen efficiency improvements when we've returned to pad sites with existing facilities, and that's allowed us to reutilize roads and infrastructure. All of that translates into lower cost. We look back at our operational performance and root out non-productive time. That's a big significant portion of this. And so when you have a large continuous acreage position that we have, and I know it's something we talk about often, but the reality is it does translate into the numbers we harvest and the results that we communicate on a quarterly basis. And we would further expect that to see improvement as we go quarter after quarter and year after year in the future. Thanks, guys. Thank you, John. Thank you. One moment for the next question, please, and the next question will be coming from the line of Michael Scialla of Stephens. Your line is open. Good morning, everybody. Obviously, you're pretty bullish on both nat gas and NGL demand growth. If one or the other weren't to materialize like you think, could you talk to your ability to shift the production mix to respond, or is that fairly limited? Yeah, I think if you, well, good morning, Michael. I think if you look at how we've balanced the activity over the last several years from a well-mixed standpoint, it could look really similar on the go forward. So we've typically been somewhere in the 70%-80% on the processable gas side, and then ultimately 20%-30% on the dry gas side. But we've always left some flexibility within the program to allocate capital from one side of our asset base to the other. So we think that affords us some good optionality. But the other part of this is we also can be flexible in how we utilize in-basin gas to basically utilize the transport that we've committed to, coupled with the processing, and again, still harvesting that NGL uplift. I think when you've heard Alan talk about it in the past, but with all of the PDH facilities that have been commissioned over the past 24 months, and those that are remaining, plus the steam crackers in the year or two ahead, the vessels that are getting constructed, there's a real momentum around this NGL side that we feel strongly there's the support there for the future of this profile. And so it's hard for us to see the proverbial what breaks down if one of these doesn't materialize, especially when you couple it with all of the net gas demand conversation. So we do have flexibility in the program. We can change the growth profile if it were required while still utilizing this infrastructure on the wet gas side. We just don't think that's going to be required when you start to look at all the other details. Got it. Obviously, your net gas outlook's heavily dependent upon LNG demand growth. There's been some split views there. I wanted to get your view on some, saying that the LNG market could be oversupplied with all the supply that's coming online next few years. So I wanted to see if you could speak to the demand side for LNG over the next few years. Yeah, I'll kick this one off and then hand it off with more detailed macro thoughts to Alan. But I think what we have tried to be careful as we articulate the Range story is diversification. LNG is a part of the story. And so is power. So is reindustrialization in the Midwest, our NGLs in those end markets. So certainly NGL, the LNG story rather, is the biggest piece affecting U.S. production. But with the diversification and our ultimate end of sales points, it's a linkage to a number of different economic drivers. So that risk of an oversupply global market, while there's obviously the potential in a commodity business, a cyclical commodity business for that to occur, that does not represent too significant a risk to our business profile. Again, it's the production mix of NGLs with our gas, our domestic sales, and Midwest sales, sales into Canada, sales to the Gulf Coast petrochemical and industrial baseload, as well as just power demand. So it's an all of the above, for lack of a better term. But if we want to add anything on the LNG side as well, Alan. No, I would just add that for 2024, I think we averaged around 13 BCF a day of LNG demand out of the U.S. And right now, it's line of sight coming on just over the next couple of years. It's going to have us up to like 26 BCF a day by 2028. And that's all backed by existing contracts. The current administration is supporting fast tracking or approvals of projects that we're not even talking about here yet. And again, these are backed by international demand and contract interest. So we feel pretty strongly around that. Additionally, we've got LNG out of Canada that's starting up soon. That'll add another 2 BCF a day of demand that wasn't in that 26 I was referencing, as well as just expansions of the pipeline to Mexico, adding about another 1.5 BCF a day. So again, just in the near term, we have contracts supporting strong demand that I don't think gives us any pause. Appreciate the call, guys. Thank you. Thank you, Michael. Thank you. One moment, please. And our next question will come from the line of Neil Mehta of Goldman Sachs. Your line is open. Hey, thanks so much, Dennis, Mark, and team. I guess the first question is just around the NGL side. We spent a lot of time talking about dry gas. But one of the hallmarks of your 2024 realization was just how good your differential was in NGLs. I think it was $2.33. So how do you think about that premium as we work our way through 2025? And you talked about a pretty big range here, $0-$1.25. But why would it be sequentially lower? And is there a potential for outperformance once again? Yeah, thanks, Neil. This is Alan. Good question. We like talking about NGLs, or at least I do. Premium last year really was fantastic. And I think it goes back to just our activity in the international markets that started way back in 2016 when we were part of the first-ever export of ethane out of the U.S. The contracts internationally, some of them are priced on international indices. Some of them are just priced on premiums to domestic indices. And they really do make a difference in our returns. And as you saw last year, overall dock capacity in the U.S. on ethane as well as LPG was relatively tight. So when supply and demand of anything gets tight, the value of it goes up. And the value at the dock went up as a result of that. Where we are today, we have quite a bit of new capacity coming online for export docks for both ethane and LPG. In fact, almost a doubling of the export capacity on ethane, providing about 400,000 barrels per day of export dock capacity over the next two years, and roughly call it 500 a day of propane or LPG export capacity coming on over the next couple of years. And what that'll do is it'll really tighten up the U.S. fundamentals because that's going to be a huge pull on U.S. supply of NGLs. So I think when that happens, we'll get the benefit of the higher overall domestic prices, but it could actually result in a tighter arb and maybe a little bit less of a premium on the international. So we win actually typically both ways. When things are tight internationally, we get the benefit from the higher premiums. When things are tight domestically, we get the benefit from just the higher baseload prices in the domestic market. That's really helpful. So thank you. And then flipping back to the gas side, I guess the Range announcement today does represent, I guess, one of the first large producers to talk about shifting back from maintenance to a growth mode and justified certainly by very strong demand fundamentals. But as you think about this, do you see the risk that the industry over-responds to what is a strong demand environment? Or do you see Range's uniquely positioned to grow at this level because of your low costs, good inventory, and takeaway? I guess the genesis of the question is how many times over the last 20 years have we seen strong demand fundamentals that get swamped by an oversupply response? Good morning, Neil. That is the age-old problem of many a commodity industry. I would say that Range is in a somewhat special and unique position. Given the lifespan of our inventory, we are able to underwrite the transport to reach these known growing demand and markets. So while aggregate takeaway capacity out of Appalachia has not changed materially and is expected to change materially in the next several years, we have taken additional capacity on Range's book to move those molecules into known demand growth. So while Range is growing, our concerns around the broader market growing and outstripping demand is really pretty moderated. The trends you've seen, be it rational economic decision-making based on the relative consolidation of the industry, while it's still not totally consolidated, there has been quite a bit of discipline instilled across the industry to be rational, allocate capital to drive free cash flow. Another element that is different that allows Range to be opportunistic here is the fact that we're at or below 50% reinvestment rate at $3.75. We are the only company at or below 50% at $3.75. Other basins that are going to be the primary sources of growth require $4 just to hit 70% reinvestment rates to supply the growth to LNG, so our concern is minimal about the industry being irrational in growing production for production's sake. As we highlighted as we began this discussion today, and Dennis kicked it off, our priority is free cash flow, and I think that that basic principle permeates the industry today, and we collectively will be just rational business people trying to drive returns for our shareholders. Thanks, team. Thanks, Neil. Thank you. One moment for the next question, and our next question will be coming from the line of Betty Jiang of Barclays. Your line is open. Good morning. I want to ask about the improvement in the capital efficiency that's shown in the three-year outlook. If I look at what you guys are saying on 2027 maintenance capital, it's $570 million to maintain 2.6 BCF per day. And then in 2025, you're doing that at $500 million for 2.2. So capital is going up less than production. So wondering if there's any implied improvement in well costs or drivers behind this better capital efficiency long-term versus today? Yeah, good morning, Betty. I would tell you what's really embedded in that outlook of capital spend as you start to get to that $570 million in 2027 time period is it really is on the back of our continued efficiencies of our operation and extending lateral lengths. Again, we've touched on that a lot, but it's on the back of our ability with our contiguous acreage position to extend lateral some of the incremental land spend that we've talked about on a very low level to pick up those open parcels that will again allow us to extend the lateral lengths. I think you saw that this past year where our average drilled lateral length was 14,000 feet as an example. So it's going to be supported by that. But also the other part of this is just the ability to continue to reutilize infrastructure, again, drilling those long laterals and our low base decline. When you start to look at how the field continues to perform over the course of time, our assets really do have a unique base decline profile versus some other basins and some others in our basin. And it allows us to continue to capitalize on that with a strong foundation. Got it. That's helpful. And my follow-up is on the DUC inventory. Could you help us perhaps quantify what is the level of DUC inventory do you expect to have by the end of this year and what that will mean to your incremental activity for 2026 and 2027? Sure thing. When you start to look at the end of 2025 and the capital and activity program that we have in place, what we would expect is to have a DUC inventory of approximately 400,000 lateral feet above our maintenance program. So you're talking about around 30 wells if you just approximate that to a 12,000-foot type lateral as an example or something comparable to what we've been drilling and completing over the last couple of years. Now, as you start to move forward into 2026 and you see, again, some of the compression and gathering get commissioned on the back half of this year, that would then support the utilization of that DUC inventory as we start to look into 2026 and 2027. That makes sense. Thank you for that, C aller. Thank you, Betty. Thank you. One moment for the next question, please. And our next question will be coming from the line of Doug Leggett of Wolfe Research. Your line is open. Good morning. This is John Abbott on for Doug Leggett. Mark, our first question is for you. It's for you on capital returns. I mean, you could probably continue to allocate capital between debt reduction and buyback, but really want to talk more about long-term dividend growth. So how do you think about the ultimate size of the dividend burden of the firm and then to grow that over time via buybacks? You have a 30-year inventory, which is probably greater than what the market is willing to recognize as you're basically an annuity. So how do you look to gain greater market value by growing the dividend over time? Sure. I think you're highlighting a distinction we've tried to make, and hopefully we can continue to beat that drum that the value of Range is in the longevity of the story, that long duration of the inventory, the repeatability, and at the appropriate times when growth is appropriate, investing in a business to drive incremental cash flow. So to your point, returns of capital are a key part of that. The reality is we are an upstream natural gas and NGLs company. It's a commodity business with cycles. We are not a regulated utility, and we are unlikely to be valued based on a dividend yield. So the dividend yield, we think, is an important commitment by the business. It is an important element to demonstrate the durability of the story through cycles to pay out a steady, slowly growing modest dividend. So expect, or rather our intent would be to regularly, but very rationally, modestly grow that dividend where the share repurchase will be opportunistic, but the lion's share of the return of capital. What that means is that we would certainly hope and expect to have a declining share count where even a growing per-share dividend in the aggregate may not grow that much in the total cash call on dividend payouts. So to say it more briefly, the dividend we expect to be a more modest piece, but a steady, slowing, slowly growing element of the return of capital program. Follow-up. In your remarks, it sounds like you're going to get a $300 million benefit from your NOLs over the next two years. How do cash taxes look in 2027 and beyond? Yeah, we would expect over the next two years at current prices to pretty much fully utilize those NOLs. So you'll move from a low, very low single-digit type effective cash tax rate to in 2027 and beyond, you're likely high teens. You still have IDC deductions and other tax planning options. So think high teens cash effective tax rate 2027 and beyond. Thank you very much for taking our questions. Thank you. We'll close out the Q&A this morning. We appreciate everyone joining us for the call this morning, listening to our exciting plans and news that we've got for the next three years ahead. If you have any questions, please follow up with our investor relations team as always. We look forward to talking about our plans on the road and the months ahead. We'll see you on the next call.