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Operator: Hello. Welcome to the Range Resources Third 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 risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speakers’ remarks, there will be a question-and-answer period. [Technical Difficulty] Vice President, Investor Relations at Range Resources. Please go ahead, sir.

Laith Sando: Thank you, Operator. Good morning, everyone, and thank you for joining Range’s Third Quarter 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 also find our 10-Q on Range’s website under the Investors tab or you can access it using the SEC’s EDGAR system. Please note, we’ll be referencing certain non-GAAP measures on today’s call. Our press release provides reconciliations of these to the most comparable GAAP figures. We’ve also posted supplemental tables on our website that include realized pricing details by product, along with calculations of EBITDAX, cash margins and other non-GAAP measures. With that, let me turn the call over to Dennis.

Dennis Degner: Thanks, Laith, and thanks to all of you for joining the call today. Consistent performance has been a key part of the Range story this year, and our third quarter results reflect our repeatable execution in areas such as operating safely, driving continued drilling, completion and production improvements, generating free cash flow, and the prudent allocation of that free cash flow, balancing returns of capital to shareholders and the long-term development of our world-class asset base. I believe our third quarter results reflect the ongoing advancement of these objectives and the resilience of Range’s business through cycles like we’re experiencing today. 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 full display in the third quarter. Our ability to market ethane, propane and butane into the international market drove the highest NGL premium in company history at over $4 per barrel above the Mont Belvieu Index. Looking at the entire production make-up, Range saw an aggregate unhedged price realization of $2.61 per Mcfe for the quarter, which is a $0.45 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, along with a thoughtful right-sized hedge program, the output is another quarter of positive free cash flow, despite challenging natural gas prices.

During the third quarter, Range invested $156 million, running two rigs and one completion crew, and placing us on track with our full year capital guidance we’ve communicated. Range’s third quarter production came in at 2.2 Bcf equivalent per day, and we expect fourth quarter production will be near similar level, resulting in an annual 2024 production of approximately 2.17 Bcfe per day. This is roughly 30 million cubic feet per day above the previous midpoint of guidance, and is the result of strong well performance and continued optimization of gathering and compression infrastructure that was mentioned during our last call. Range can maintain this higher level of production with just one electric frac crew. I think this message is worth repeating.

Range can hold nearly 2.2 Bcfe per day of net production flat with one completion crew. This is a true testament to both the quality of our asset base and the quality of the team, reflecting two decades of innovation and collaboration in the Marcellus between Range and its service providers. While we are still finalizing our capital and production plans for 2025, we expect that running one continuous completions crew is a reasonable baseline from which we will be fine tuning our plans over the next few months. As has been the case for the last two years, running at this one crew activity level is slightly more-than-required for maintaining production, which we would consider as maintenance plus. This countercyclical investment provides Range an operational tailwind for future periods as takeaway capacity becomes available in Appalachia and in-basin natural gas demand increases in the years ahead.

When there is a fundamental call for additional production in the future, Range will be able to generate a very efficient wedge of modest growth. Turning to marketing and focusing on NGLs. International demand and pricing for NGLs remained robust in the third quarter, leading to near maximum U.S. export capacity utilization. Simultaneously, improving Panama Canal throughput access and a growing global fleet of LPG ships improved waterborne freight rates. These factors combined to drive export price premiums to new levels relative to the Mont Belvieu Index. As in prior quarters, Range’s portfolio of transportation and sales contracts provided reliable access to these premium markets. Looking ahead to 2025, many of these dynamics are expected to remain in place, as international demand for NGL products continues to grow, while U.S. Gulf Coast export capacity does not increase materially until the second half of 2025 and into 2026.

This provides a constructive setup for Range’s go forward price realizations and margins. I believe the last couple of years are positive proof that Range’s business capable of generating free cash flow and returns through cycles. Like many of the listeners today, we see the demand for natural gas and NGLs increasing substantially in the years ahead. As one of the lowest-cost producers in North America, we believe Range is well-positioned for thoughtful growth in the years ahead when called upon. Whether that’s in the year ahead or beyond, in the long run, we believe Range’s competitive full cycle cost structure and through cycle profitability, provide a unique investment opportunity for long-term investors given our multi-decade inventory runway.

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

Mark Scucchi: Thanks, Dennis. With three quarters of 2024 behind us, it’s a sensible time to take stock of the state of our business, to examine what we’ve accomplished in the absolute and on a relative basis, and what this may imply for the future. For the first three quarters of 2024, NYMEX natural gas averaged $2.09. Despite the low commodity price year-to-date, Range has paid $58 million in dividends, invested $44 million in share repurchases at prices well below our view of long-term value, and reduced net debt by $136 million while investing in operations. Range generated the free cash flow that made those capital allocation decisions possible, while executing an operational plan that stands in stark contrast to much of this industry.

Range’s program is slightly above maintenance capital in 2024, strategically investing in land and water infrastructure to enhance capital efficiency, while also building modest well inventory to provide options for future capital spending and resulting production profile. Range is both proving the free cash flow resilience of the business and reinforcing that resilience through targeted capital investment. That free cash flow resilience allows us to be successful throughout commodity price cycles and to pursue a comprehensive capital allocation strategy that returns cash to shareholders, reinforces our strong balance sheet and invests in the business. There are a number of unique aspects of the Range story that allow us to achieve these results, including our peer-leading reinvestment rate, our diversification across products, transport and end markets, customers, contract structures and our solid financial position.

Range’s reinvestment rate through the first three quarters of 2024 was 63%. In other words, while investing at a maintenance plus level, we generated healthy free cash flow margin even with low commodity prices. Our low required reinvestment rate is driven by a peer-leading base decline rate of production. The benefits of our high-quality contiguous acreage position and the efforts of an experienced and motivated team. Range’s resilient cash flow is supported by the diversification of revenue. Roughly 30% of Range’s production is liquids, which have accounted for more than 50% of pre-hedge revenue in five of the last six quarters. Further, we have achieved a strong premium to domestic NGL pricing, averaging a $2.42 per barrel premium versus Mont Belvieu year-to-date in 2024, driven by our advantage takeaway and Marcus Hook dock access as well as our ability to market cargos of propane and butane on a vessel-by-vessel basis.

That has benefited realizations by allowing Range to largely avoid domestic points of NGL product congestion and instead price at attractive international indices. Gas revenues are supported by a broad portfolio of transportation contracts and customers, reaching a diversified set of advantageous end markets, markets of growing power, industrial and LNG demand. In addition, Range has employed a flexible and persistent goal-oriented hedging framework, where we look to create a portfolio that covers fixed costs, and as a byproduct enables us to capture market opportunities, be it share buybacks, debt reduction, dividends, countercyclical capital investments and other alternatives. That approach has helped to support attractive full cycle margins, end markets as varied as seen in 2022 and 2024.

Range ended the third quarter with net debt of $1.44 billion within our target range of $1 billion to $1.5 billion. The nearly $2.7 billion of net debt reduction Range has achieved over the last several years not only reduces interest expense, it pairs a world-class asset with a world-class balance sheet, supporting a global business. This financial position and asset pairing, allows an efficient longer-term strategic approach to investments in the business, alongside durable returns to shareholders. As a whole, we view Range as uniquely-positioned to benefit from and take advantage of what we expect will be continued secular demand growth for both natural gas and NGLs. Our durable free cash flow story, along with the investments we have made in the business over the last two years, position Range to sustain and grow its presence as a reliable provider of energy to its customers, while consistently delivering value to its shareholders.

Dennis, back to you.

Dennis Degner: Thanks, Mark. Before moving to Q&A, I’d like to acknowledge that, today marks the anniversary of an important day, not only for Range Resources and our industry, but also for the energy independence of our country. 20 years ago, on this day in 2004, Range Resources completed the RINs number one, the first commercial Marcellus well. At that time in 2004, the United States was the net importer of natural gas, with total imports exceeding 4.3 Tcf or over 11 Bcf per day. Today, the Marcellus and Utica produce over 30 Bcf per day and account for approximately one-third of gas production in the United States. The U.S. is not only a net exporter of natural gas, but has also surpassed Russia as the leading supplier of natural gas around the globe, with total exports last year exceeding 20 Bcf per day, including exports to Mexico.

During the same 20 year time period, total U.S. energy emissions declined approximately 20%, driven by a 40% decrease in emissions from power generation due to the increased utilization of natural gas. This has been a tremendous achievement by our industry, and we are proud of the role that Range has played and continues to play in providing safe, clean, economic energy to the world. You’ve heard us state this before, but we continue to believe, the results communicated today showcase that Range’s business is in the best place in company’s history, having de-risked a high quality inventory measured in decades and translated that into a business capable of generating free cash flow through these types of cycles. It all started with a successful well test 20 years ago.

We look forward to the next decades of developing Range’s inventory and the milestones we’ll achieve. With that, let’s open the line for questions.

Operator: Thank you, Mr. Degner. The question-and-answer session will now begin. [Operator Instructions] Our first question comes from the line of Scott Hanold with RBC.

Scott Hanold: Good morning. You all had some pretty strong production performance, and I know you did highlight the midstream optimization. Could you give a sense on what has that really added? Do you have just a sense of just in terms of like volumes that it’s added in? What has it done to your base decline rate on your asset base going forward?

Dennis Degner: Yes. Good morning Scott. Appreciate the question around the production. It’s something we’ve been awfully pleased with on the performance this year. I think for us, it really starts with some of the long-lateral performance that we saw from the back half of last year, and then really through the front half of this year is that, compression and gathering infrastructure expansion started to go into service. One of the projects was at the end of Q3, beginning of Q4 of last year, and the other was in the early part of this year, some in across areas of the well mix, both from dry to our wet and super-rich impacts. When we think about what we’ve seen so far, it’s still a little early on some of the trends and how it’s, you could say, benefiting some of the wells across the field.

What we have been able to see is that, in areas where you might see, let’s just say, some constrained production on a smaller level, we’ve seen some small upticks. Where we’ve got longer laterals that are producing at a high level, we’ve actually seen the ability to move more through that system and keep it at a higher level of utilization. We’ll have more that we can probably share, as we think about setting up our plans for 2025. But, I think if you look at how the business is performing this year as an example, it kind of shows what it’s capable of. When you look at, we’re on-track to grow roughly 2% this year or maybe just right below that, and that’s the byproduct of what we’re seeing from that compression and, again, those long laterals.

Our base decline being at 19% is something we’re also proud of. I think it reflects the quality of the asset and the team’s hard work, but we expect that, over the course of time we could continue to see that decline shallow even further from where it is today.

Scott Hanold: Yes. Life is a lot easier when you have the shallow decline. My follow-up question is on 2025, then. You talked about running one frac crew, and that gets you to that, I guess, modest growth pace to continue. Can you talk regarding the DUC optionality to grow? Like, what do you right now need to see to kind of do that? Would that require getting a partial frac crew, if you were to decide that at some point? Do you have the firm takeaway to get your volumes to market?

Dennis Degner: Yes. Good question. I think when we start to ask ourselves what signals that we need to see in order to think about utilizing that productive capacity, I think it’s some of the basics. What kind of winter weather are we going to see come together as we get from one pattern of weather to the other from La Nina to El Nino and back and forth. I think the other thing we need to see is further commissioning and utilization of the LNG infrastructure. There’s a lot of reasons to be optimistic about Plaquemines and reaching that 1.7 Bcf a day of capacity utilization early in 2025. You’ve got Corpus Christi Train 3. We think that’s going to — all signs are, it is ahead of schedule and it could see gas start to roll through that infrastructure end of this year and then reach full utilization next year.

That’s another B and a half. You’re talking about 3 Bcf a day in those two pieces of infrastructure alone, before you even get to potentially Golden Pass Train 1 at the end of 2025. So I think we’d like to see what comes together with weather, LNG infrastructure and then what kind of price responses that we’re going to see, we’ll stay more in the short-term as a part of that. The good news is with the inventory that we generated between 2024 and ’23, we have the ability to pick up a spot crew and add that production, when we think the fundamentals are pointing to it, and they’re calling for that additional incremental gas. When you look at how our transportation is set up, we feel like, we do have the right takeaway to handle that incremental production.

If you think about our production profile under maintenance in the past, it’s looked like more a sine wave, where we’ve had more of a decline in the early part as you come out of the end of the year, heavy activity focus and then a ratable increase in the back half of the year. This year we’ve seen that shallow quite a bit with a flat two rig program in this one frac crew approach. So next year what we think we could see is, good utilization of our transport. When the right signs materialize, we could add a spot frac crew and utilize some of that inventory again when the right signs call for it. But, if not, we feel like just like this year we could add that incremental inventory. We could respond when the market calls for it, whether it’s back half of ’25 or thinking about being more efficient than into 2026.

It all becomes the byproduct of a good lean-based activity program.

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

Neil Mehta: Yes. Good morning, team. Really strong results here and that’s where I kind of want to start-off on Slide 38, where the price realization for the NGL differential was super strong. I know you talked about your ability to get to that international market, but maybe you could break it down for us a little bit more and talk about what your marketing teams are doing. You mentioned you think this is sustainable, but it is a big step-up from historical levels of price differential strength. And so, help us to understand how you keep that momentum up.

Dennis Degner: Yes. Good morning, Neil. I think you’ve heard us probably say this in a lot of our prepared remarks and in other meetings that we’ve had together, but our ability to — we’re celebrating the 20th anniversary of the RINS well, but with that came our ability to start with a different development approach and that is setting up purity product processing in Appalachia for our production, and it allowed us to be able to market those products out of different outlets, mainly to getting exposure to a waterborne export out of Marcus Hook, Philadelphia. And as you start to look at this year, we point to the premium opportunity that exists out of the Northeast for us, and we think it all starts back to again 20 years ago and how this setup really began.

But when you think about what we’re seeing today, clearly exports have been at an extremely high level out of the Gulf. We’re running over 2 million barrels a day in export as an industry, and dock utilization is running right around 90%. And so the congestion that has occurred there has really presented an opportunity for us to capture a premium out of the Northeast, where we’re seeing a strong utilization rate, but we’re below those kind of congestion levels that could present an issue. All at the same time, you’re seeing demand continue to grow. When you look the PDH infrastructure that continues to be commissioned, clearly a bulk of that is in the Asian market. But, when you see what’s been growing both in ’23 and commissioned in 2024, utilization rates continue to go on the uptick, and there’s more coming when you start to think about again that additional infrastructure for 2025.

We remain really optimistic that, if you think about the dock capacity congestion infrastructure expansion there really doesn’t take shape until the back half of 2025 and pretty deep into ’25 at that and into ’26. So we think there’s a set of fundamentals that are in play here that could be very much structurally repetitive in ’25 for our NGL realization to what we’ve been able to harvest in 2024. Look, at the other end of that dock capacity expansion, will that same premium level exist? Maybe not. But, as you start to see — but, we believe a premium still continues to be present for us in the Northeast and demand continues to grow, and with that will come price improvements as well.

Neil Mehta: Okay. Thanks for that. And then, just a follow-up just on the ’25 plan as it relates to capital. Again, we’re going to get more perspective on this, I’m sure, in the next couple of months. But, given that you’re running close to a maintenance level, is it fair to use ’24 as a good proxy for how you’re thinking about ’25 as it relates to capital? Are there efficiencies that you can capture or the moving pieces that we need to take into account?

Dennis Degner: Yes. I think that’s a good question, Neal. We’re still refining what ’25 is going to look like. Clearly, I’m sure a lot of other producers are doing the same at this time of year. But ’24 is a good way of thinking about how our business could look in 2025. I think it starts with our dedicated frac crew and then the drilling activity that efficiently feeds that process, if you will. If you look at this year, we have two horizontal rigs that are continuing to feed that frac crew. It does generate a little bit of that in-process inventory next year. Again, if you’re constructive on ’25 and ’26, clearly maintaining the operational efficiencies with the two rigs could make a lot of sense for us. But there is a point in time, where no doubt we’ll have the operational and program flexibility to think about do you reduce rig activity in the future if the fundamentals call for it or do you maintain that same level of cadence and instead utilize that productive capacity with some kind of spot frac crew.

I think thinking about our capital program in ’24 in activity is a good way of, I’ll just say, starting to think about how our 2025 could look.

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

Doug Leggate: Thank you. Good morning, everyone. Thanks for having me on. Dennis, you kind of walked into the mails from a little bit, by talking about takeaway capacity and in-basin demand. Very topical on both fronts, particularly the in-basin demand, I guess, data centers is topical. But I just wonder if I could ask you to elaborate a little bit as to what you’re seeing opportunity might be for Range? And I have a quick follow-up.

Dennis Degner: You bet. Good morning, Doug. Thanks for joining us. I think when we start to think about demand regionally, I’ll just say more in the near-term, we added a new slide to the slide deck this cycle to try and put some color around that. It’s Slide number 18. But really when you start to think about near term demand, a couple of things that we see clearly is, there is the industrialization expansion process that’s starting to take shape with some of the legislative acts that have been approved over the last few years. So when you think about the next few years, clearly, there’s going to be the Intel Semiconductor fab facility and also the Micron facility as well. We have the ability to, I’ll just say, through our transport, have access to that kind of growing demand and others that clearly that will continue to materialize.

You’ve got clearly coal retirements that are going to take shape over the next 12 to 24 months, approximately a Bcf a day in displacement there that could take shape. I think if you look over the last 24 months, we’re now on back-to-back years of seeing incremental power burn on the nat gas side of around 1.3 to 1.4 Bcf a day. You’ve probably heard me say this before in one-on-one conversations, but I feel like that’s been underappreciated when we enter each year just because of the wild card factor around that. But, now you’ve got nat gas again playing a role that’s really unique and we’re 74% of the thermal share through the first half of 2024. That’s all while wind is actually up year-over-year. That’s I think shows again the durability of what nat gas will play in the role there.

So I mean, clearly, from a takeaway standpoint, MVP has been beneficial. That pipeline has been running sub Bcf a day at this point, but clearly there’s the ability in the next few years as we see that Transco activity and expansion take place to reach its 2 to 2.2 Bcf capacity. In the near-term, we think those are the line-of-sight type projects, but we also know there are a lot of conversations that are starting to materialize around data centers, future power demand. I think the PJM auction that was recently conducted probably shed some light on the critical movement that will need to take shape around power in the future, when you saw it go from somewhere in the mid-$20 range to $2.70 per megawatt day. So there’s some early indications that movement has to take shape.

That’s how we’re seeing the future demand kind of take place regionally, but we also know that LNG is also going to be the big pin in this as well.

Doug Leggate: That’s very helpful. Thank you for the color. I guess my follow-up. This might be for Mark. You guys are best-in-class capital efficiency. No question, it’s been an extraordinary story, frankly, in terms of the longevity you have in your business at the current spending level. But I guess my question is, you’ve benefited from returning to, I don’t want to clumsily walk through how you described this, but you benefited from going back to plants that you previously drilled but hadn’t fully utilized certain provisions. And I’m trying to understand what the running room is for that, that you can maintain this capital level, given that that’s been an in-built on each other and can that continue?

Mark Scucchi: Sure. I think as we try to explain the longevity of Range’s program and how consistent the performance can be from a capital productivity standpoint, I think, it’s important as you point out that, roughly half of wells in a given year are put on existing pads. I mean, those are still new locations. If we rewind all the way back to the beginning in terms of how Range worked with partners to build up the gathering system, the gathering system is built across essentially the entire footprint. While roughly half of our wells in a given year go on existing pads and use some existing infrastructure, half are on new ones. You’re getting what is in essence a slice a sample perhaps not a perfectly statistical sampling, but a sampling nonetheless across the entire acreage position, so an averaging effect.

What that means is, we’re not focused on one specific area, exhausting it, moving down the road to another area. That’s one of the reasons why you get a very consistent result on a program level year-in and year-out. It’s also why you see benefits, the things like Dennis spoke about earlier, optimization of the existing gathering system. It’s because you didn’t exhaust a particular area, used all the locations available in a particular area and then moved down the road, meaning you’re underutilizing a portion of the gathering system. We use and reuse and continue to attempt to fully-utilize the gathering system, the existing ones. Optimization like attic compression and return in the past for parts of our locations at a given year gives production uplift of the existing base and adds new production from existing wells.

To pull back all the way to your question of how long can we keep that up, what does it look like, that pulls you back to one of the very first slides we have. The inventory is measured in decades, before we would expect at a program level to see even at that point expect to see any material change in the productivity. The team’s efficiencies that they learn year-in and year-out, whether it’s better targeting, landing, completion, stages per day on the drilling side, lateral footage per day, getting more and more accurate. It’s not just drilling and how fast they’re drilling, it’s how accurately they’re drilling and placing that lateral in the targeted interval. We think that Range’s story is truly unique in that perspective in terms of the efficiency combined with how long we can hold it.

Doug Leggate: Thanks for that, Mark. Just a quick clarifications. Is it fair to say then that, the partially-utilized pads, if you like, you’re kind of replenishing those as you go, because half your program is still drilling new pads? Is that a fair way to think about it?

Mark Scucchi: I think that’s a fair way of thinking about it, yes.

Operator: Our next question comes from the line of Jacob Roberts with TPH & Company.

Jacob Roberts: Good morning. I wanted to touch on the incremental land spend. I think the indication there is that, you’re effectively replacing 75% of the drilled lateral feet for a given year for $25 million or $30 million. I was hoping you could maybe elaborate on what’s being acquired there and how you see that as enhancing the near-term opportunity set relative to perhaps just adding another year to, as you’ve noted, a decade’s long inventory?

Dennis Degner: Yes. Good morning, Jake. I think when you ask about the opportunity set, if you look across our acreage position, there are very unique open space parcels that can’t exist. It’s more the exception than the rule. It represents a really, really small part of our acreage position that’s well blocked up. Sometimes it can involve extending laterals at the perimeter of our acreage position as well. And so, when we think about the opportunity set, this year, it could represent as much as essentially 500,000 feet of lateral inventory that wasn’t factored into our total numbers, but allows us the opportunity to capture those open parcels and extend laterals, which we know then will translate into our most capital efficient wells.

Our ability like if you look on 2023 as an example. We started off the program at the beginning of the year with an average of around 10,000 foot laterals. By the time we got to the end of the year, we were almost at 13,000 feet, all predicated on the optimization of our development plan throughout the year and the ability to pick up some of those open parcels that you see. It does add that incremental inventory. It adds our most capital efficient wells and ties to something that you’ve heard us talk about this morning, efficient use of the gathering system as well. When you look at the drilling and completion efficiencies that we’ve touched on quarter-over-quarter that also dovetails into it because that becomes, we’ll just say, pennies on the dollars type investments, when you think about the grander scheme of the production add for the year.

Jacob Roberts: Great. Thank you. And then maybe for Mark, kind of a clean-up question, how should we be thinking about your approach to the remainder of the 2025 notes? Just trying to get a sense of, if we see interest come down throughout the year next year or when those might ultimately exit?

Mark Scucchi: Yes. We’ve worked hard to be in a position where we are today to have a good deal of options in front of us. That’s both the reality of the business, and where we positioned it as well as just the economic backdrop right now. We’re in a declining interest rate environment. Capital markets are open. That said, Range has reduce debt. The need to do a transaction is not there at the option, if that’s the most economically prudent way of managing them. I would say, the baseline start with the cash we have on hand today plus cash we’ll generate before the maturity date early next year. We have a completely undrawn revolving credit facility for any tail amount that maybe we don’t have cash on hand for at that point. That said, if rates continue to come down, you could see optionality and Range looking at taking care of the ’25 certainly, but also at the 8.25% those present some optionality in terms of how we want to approach those pull and part of those refinance at a better rate.

We’re in the great spot of having net debt in our target zip code and being able to just optimize and drive down interest expense over time.

Operator: Our next question comes from the line of Kevin McCurdy with Pickering Energy Partners.

Kevin McCurdy: Good morning. I wanted to follow-up on an earlier question about the wells in progress. Are you able to quantify how many DUCs you do plan to have at year end?

Dennis Degner: Yes. Good morning, Kevin. At this point, I don’t think we’ve defined exactly what that number is, and part of it is because the drilling efficiencies that we’ve captured throughout the year and sometimes we’ll just say the dynamics of moving the activity around in our development program as we get to the end of the year. When you think about though, from a capital investment standpoint, it’s really been around $60 million to $75 million between last year and this year. Ultimately, just I’d say it’s going to be an approximation number I’m going to give you, but it’s going to be somewhere in the neighborhood about two pads worth of wells. So, think kind of 8 to 10 in number. But, again, we’ll have a better refined number as we get closer to the end of the year and see what good work the team has harvested through their efficiencies.

Kevin McCurdy: Great. Thank you for that detail. And just to clarify, when you decide to utilize that productive capacity, are you kind of envisioning a permanent step-up on your 2.2 Bcfe a day collection level, or would you consider completing those wells opportunistically to kind of take advantage of temporary price spikes?

Mark Scucchi: I’ll chime in here. I think we could go either way. That’s going to be driven by the fundamentals. When the in basin demand combined with our exposure to LNG, that’s slated to come online next year, that work in process can just represent a steady state of what you’re turning in line on a given year. So it’s your just in time inventory. It could be one time opportunistic depending on how fundamentals shape-up the steadiness of that whole and call on range production. So it’s an either or that’s the beauty of the optionality in it. But I think when you pull back to what Range’s story is, what the capital efficiency means that full cycle cost and that dollar D&C capital per Mcfe stays at the leading edge. This just represents further efficiencies and tailwind whether you’re in a maintenance mode or whether you’re stepping into some growth when that fundamental is there.

Even if, there is a reset to some higher level or said differently when there is a reset to a higher level based on the fundamentals, the efficiency is going to drive still an extremely strong free cash flow generation level that’s sustainable with that low base decline rate and a really, really strong comparative D&C per Mcfe.

Operator: Our next question comes from the line of Roger Read with Wells Fargo Securities.

Roger Read: Yes, thanks. Good morning. I guess one question I’d like to come at. Given the benefit to the NGLs keeping production flat around the two-and-change production level. As we think about adding new wells, decline of existing wells, kind of that it’s one question with two parts. Base decline rates, what are those? Have they been changing at all? And then, as we think about the mix of production with NGLs versus dry gas, any changes there? I’m just trying to think about if we remain stuck in a position here of flatness for a while, what does that look like in terms of production and in terms of any, let’s say, potential changes in type of well or CapEx?

Dennis Degner: Yes. Good morning, Roger. I’ll tackle this one. I think when you look at our base decline, it should look very consistent, if not continuing to shallow over the course of time. I think today you’ve heard us mention it and in prior calls, but typically our base decline is running around 19%. Few years ago, it was around 20%. We would expect over the course of time it to continue to just slightly shallow. Ultimately, still very resilient. We’ve got 1,500 producing wells. It represents, we’ll just say, a strong data set that comprises that base number that we provide. When you think about the production mix changes, I think this year versus last year is a good way to think about what the future could look like for us, meaning, just on a — when you look back over a few quarters, just seeing a slow and steady incremental wetting of the production stream.

I think we were right at 30%. You’ve seen us get a little bit above that level. But across the course of time, you’d expect to see our production stream continue to have a little bit more of an NGL contribution. And it’s where clearly a large portion of our inventory resides and where, again, we have some of our most capital efficient wells. When you look across the inventory though, they’re all very economically competitive with each other. But over the course of time, we’d expect the production mix to look pretty similar, about two-thirds of it in the wet side, one-third on the dry side.

Operator: Our next question comes from the line of Bertrand Donnes with Truist.

Bertrand Donnes: Good morning, guys. Just wanted to follow-up on the ability to add some modest growth. I just want to clarify how you see it playing out logistically. Are you waiting for prices to move up, then you hedge those prices, then you begin to accelerate, or is it maybe a supply-demand forecast that you see and then you try to increase production in prop months and in the strip? And the second part of that is just do you need to hedge into that or does your NGL pricing kind of create a natural hedge?

Mark Scucchi: Good morning. Let me start with this quarter. Even if prices where we are today, we’re generating free cash flow today. The pricing is certainly a factor clearly. But what we’re looking at is the fundamentals, the demand pull, the in-service of new demand, whether it’s the power demand, whether it’s the LNG, whether it’s re-industrialization, all those things we’ve mentioned and referred to in the slide deck as well. As you think about the timing and how that manifests itself, we already have great exposure on existing transport to get into those markets with growing demand. There’s also some underutilized capacity on various pipelines that we can step into either in the form of selling to customers with that capacity, picking it up short-term, picking up remarketed capacity by others who do not use it, don’t have the inventory to fill it and maximize its utilization.

There’s a host of ways for us to step into that over time. As far as the hedging goes, that’s somewhat of an exercise done in parallel to grow the company, to make capital investment decisions. They’re certainly related, but the hedging philosophy is to try to cover our fixed costs. I guess by extension if you’re stepping-up your capital, you might need to think through what that implies for your hedge book. But I think next year’s program is a really good example of a go forward type level. It’s given the mid-30% type hedging range with a forehand on the front of it that covers your fixed costs and generates free cash flow, covers your dividend and keeps good exposure to a positive setup on the commodity front. I wouldn’t say the two are hard-linked necessarily.

They certainly influence and shape each other. But really the first decision as far as capital goes is just that fundamental call on supply for from Range and how we deliver it to those growing markets.

Bertrand Donnes: That makes sense. Appreciate it. And then maybe just want to hit on the data center demand question again real quick. Obviously, nuclear is getting most of the headlines and obviously gas is a large part kind of playing the generation. Are the players in the space gearing up to sign fixed agreements in 2025, obviously not for 2025 gas, but just signing agreements, or is your sense that’s way too early for any kind of data center related agreements, or are the counterparties there asking or are we still kind of in the just a conversation space?

Mark Scucchi: I think the conversations are being had rapidly, a lot of conversations, a lot of different counterparties in different ways of servicing that need whether it’s directly with utilities, whether it’s with independent power producers, whether it’s behind-the-meter and directly with data centers or other industrial type demand. So all those conversations are being had. Keep in mind that these investments by those companies are multi-decade type investments for themselves. So these are not discussions that are going to be had and arrived at in a series of months. This is probably over the course of ’25 that market, the nature of those conversations will develop, the tenor and pricing structures of those types of agreements and how they manifest itself.

Now it’s going to be a mix of traditional just directly into the utilities, two independent power producers, probably some behind-the-meter and some less conventional like you’re seeing in the nuclear. But if you pull back and look at what the potential displacement of incremental demand for natural gas is for the nuclear deals so far, it’s something on the order of 1 Bcf a day potential. That’s assuming it gets regulatory approval and meets all the required clearances to re-commission the nuclear power plant. Those are certainly encouraging in terms of the creativity and the recognition by data centers and industrial demand that they need reliable 24/7 clean power. That’s something that we, the natural gas industry, can do reliably 24/7.

Dennis Degner: Yes. I’ll just bolt-on two quick things. I think if you to further support Mark’s comments, if you look at again, I’ve referenced it earlier, but just the increase in power price in the recent PJM auction, I think there’s an indication that, it’s going to — costs are going up and ultimately conversations will accelerate to quickly figure out how you have an expansion of the, I would imagine, the grid, how do you add power, how do you meet this future growing demand, and all balance cost at the same time to whether it’s the residents or end users and consumers of that power. But, I think, lastly, we’re encouraged to see that the state of Pennsylvania, through their recent budget approval process, earmarked $400 million through something they’re calling a Sites Program to basically look at site readiness in preparation for future demand.

That’s inclusive to many things, whether it’s manufacturing or, again data centers, et cetera. But, I think it’s showing the willingness for the State of PA to be on the front of their foot, so to speak, to support industry jobs. They understand, I’m assuming that, we actually can supply very long-term, low-cost energy source that helps be the feedstock for these, that kind of job generation. Anyway, pretty encouraging from our view.

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

Michael Scialla: Yes. Good morning everybody. I want to follow-up on natural gas liquids markets. Do all of your NGLs go out of Marcus Hook now? Is there any capacity constraints there that you see coming up? Wondering if some of those NGLs could end up going to the Gulf, if you see the congestion there that you talked about being alleviated?

Alan Engberg: Good morning, Michael. This is Alan Engberg. I manage our marketing business. Quick answer to that is, the majority of our NGLs that are exported go to the Gulf. In fact, on the LPG side, I’m sorry, go through Gulf. In fact, on the LPG side, we’re able to export up to 80% of our production, which is actually the highest level relative to production of any of our competitors. Marcus Hook is typically running, I’d call at, 5% to 10% lower on capacity utilization than what the U.S. Gulf is. Hence, what Dennis referenced earlier, there’s still an opportunity for range to actually ramp up exports as we optimize the sales of our products. We do have some ethane that goes down to the Gulf. That indirectly gets exported through Gulf Coast export facilities. But for the most part, what we do is out of Marcus Hook.

Michael Scialla: That’s helpful. Appreciate that. I wanted to ask on the CapEx guide. I know you moved the low end up for the year. Can you just talk about what was the driver there?

Dennis Degner: Yes, Mike. I’ll touch on that. Quite honestly, I’ll say the starter kit is, we’re still within the guide that we had provided during the beginning of the year. But, we did provide some ranges for areas like the land side, where it was adding up the white space, open parcels that are ability for us to pick up that allow us to extend laterals, and I think that was up to essentially $30 million. We’ve now been able to, based upon the drilling activity this year, capture some of those open parcels. It’s basically driven by that land spend that we’ve had year-to-date, but that’s it. Everything else on the drilling completion side is all well within guide and on track that we had communicated for the year.

Operator: Our next question comes from the line of Leo Mariani with Roth.

Leo Mariani: Yes. Hi. Just wanted to follow-up a little bit in terms of the share buyback here. It certainly looks as though free cash flow is going to start to increase here in the fourth quarter and throughout ’25. We recognize that, you guys have a bond payment potential redemption coming up as you already elaborated on. But just trying to get a sense, as that free cash flow ramp, should we expect a commensurate increase in the share buyback? You folks obviously described the fact that you feel your stock is still undervalued at this point.

Mark Scucchi: Yes. Good morning. I think our principles that we’ve laid out over the last couple of years is get the balance sheet within the target zip code and then we’d have a lot greater latitude on how and the cadence at which we’re returning capital to shareholders. So I think the answer to your question is, yes, the balance sheet is in the target zip code. We have a lot greater latitude now to return capital to shareholders, whether it’s share buybacks or slow, ratable, durable increases in dividend over time. Certainly given the significant disconnect we see in the value of the shares even to simply-proved reserve value on a per share basis, the share buybacks we see is very, very compelling. We certainly have plenty of capacity under the existing approval and that’s certainly a possible outcome.

Leo Mariani: Appreciate that. You folks obviously discussed capital efficiencies and continuing to move faster in the program and drill longer laterals. Wanted to see if maybe you can quantify any of those efficiencies. Are you seeing like D&C costs per lateral foot come down for the company? Is that mostly a function of efficiencies if it is coming down? And any comments on what you’re seeing leading edge service costs? I know you’re not using a ton of equipment, but do you expect there could be any improvement on rig prices as oilfield activity has kind of softened here in 2024?

Dennis Degner: Yes. I think from a service cost standpoint, Leo, it’s early. We just launched our RFP process for the fall. We’ll have a lot better answer for you, I think, when we get to the beginning of the year and we see what the results bear from that process. I mean, we have seen and we touched on it. We have seen some relief in areas like some of the consumables, maybe frac sand, some of the tubular goods sides as well. But, there are other areas that remain pretty resilient at current price levels. When you think about rig rates, we’ve all, as an industry, kind of coalesced to a similar super spec rig configuration. With drilling long laterals, similar depths, et cetera, it’s provided some, I’ll just say, some support to some of those rig rates that you see today.

It’s going to be a balance. Regardless of how this plays out from a service cost perspective, what we do anticipate is the ability to hold 2.2 Bcf equivalent per day with 1 frac crew and with the efficiencies the team continues to harvest, we’re seeing 9 to 10 frac stages a day on a quarter-in, quarter-out basis now. Water recycling and efficiencies there continue to look strong. We drilled some record days on the drilling side in the lateral this past quarter. So we just, I guess, in the spirit of a phrase, I’ve once heard success begets success. And so the team continues to build upon that momentum. And I would expect for the next year, again, us to hold 2.2 Bcf flat with the one frac crew, and wherever we land from a service cost standpoint for us to continue to be on the front end of that low capital efficiency standpoint.

Operator: Ladies and gentlemen, we are nearing the end of today’s conference. We will go to Paul Diamond of Citi for our final question.

Paul Diamond: Thank you. Good morning all. Thanks for taking my call. Just wondering if I could get a quick one on kind of capital plan going forward and the opportunity set around inventory infrastructure and kind of the incremental land spend. Is that something we should think about as pretty flat run rate in coming quarters and years? Are there any, low-hanging fruit for any of those categories that might see those bump up?

Dennis Degner: Yes. Good morning Paul. I’ll start here. I think over the course of time, we would expect that, land incremental spend that you saw us break out this year for some visibility. We’d expect that to be a lower exposure in the years ahead, and mainly because it represents just a really small part of our overall program. But as you imagine, the more — we’re in excess of 90% of our acreage is held by production or what we classify going to be captured in the next few years. So we would expect this to be a decrease in exposure in the years to come for sure. There are some land opportunities that exist in and around our producing footprint, and some of them are the two state parks that are in our Southwest PA area that could present a future land opportunity.

But, for just the raw mechanics of how you’re seeing us execute and operate today, I would expect that exposure to look lower and lower over the course of time. As far as capital, in general going forward, again, this year, I think, is a really good way to visualize how our business could look from a capital and activity standpoint going forward. I think it’s also a good way of thinking about the production capacity and production output that could come from the business. I mean, we essentially had a pretty flat activity program versus prior years, but yet, here we are with the ability to add some low percentage incremental production throughout the process. We’ve got the DUCs that we’ve added over the past two years. As Mark said earlier, we don’t think it’s if, it’s when.

The fundamentals come together and the demand starts to materialize that results in low cost operators with high-quality inventory like Range to help participate to fill that growing demand. And when that happens, no doubt, I’m sure our program will look a little bit different, but we’ll have that inventory to be able to be on the front of our foot, so to speak, and help participate in that growing demand and fundamentals.

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

Dennis Degner: I’d just like to say thank you for everyone for joining us on the call today. We appreciate all the thoughtful questions. If you have anything to follow-up on, please follow-up with our Investor Relations team, and we look forward to the next call and talking about 2025. Thank you.

Operator: Ladies and gentlemen, this concludes today’s conference call. Thank you for your participation. You may now disconnect.