RRC - NYSE

Hello. Welcome to the Range Resources First Quarter 2024 Earnings Conference Call. [Operator Instructions] Statements made during this conference call that are not historical facts are forward-looking statements. Statements -- such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. [Operator Instructions] At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead, sir.

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

Thanks, Laith, and thanks to all of you for joining the call today. Range's first quarter was executed successfully and consistent with our strategy communicated earlier this year. By operating safely while driving continued operational improvements, generating free cash flow with a peer-leading capital efficiency and prudent allocation of that free cash flow balancing returns of capital to shareholders with further debt reduction and the long-term development of our world-class asset base. I believe our first quarter results reflect the ongoing advancement in line with these key objectives. And showcased the resilience of Range's business, while navigating the current commodity environment. Today's operational and financial updates should feel consistent, highlighting Range's high-quality low breakeven inventory and liquids optionality, which drove another successful quarter with meaningful free cash flow. Beyond a quarterly view, the long-term value proposition is underpinned by Range's, low sustaining capital requirements. This low capital intensity is the result of Range's class-leading drilling and completion costs, shallow base decline, large blocky core inventory and talented team. These key attributes result in a required reinvestment rate that is among the best in the industry, providing Range of solid foundation for consistently generating significant free cash flow and returns to shareholders, while positioning Range to help meet future energy demand. Whether that is through exports to international markets, or serving our needs closer to home for further electrification of our economy related to power generation needed for AI and data centers or increased domestic manufacturing. Bolstering Range's profitability and durability is our Liquids contribution, which is over 30% of our total production volume. As seen in the first quarter results, Liquids revenue provided an uplift to natural gas prices, with NGL price realizations equating to a premium of over $2 relative to Henry Hub pricing. When we roll all of that together, our Liquids revenue uplift. Our low capital intensity and thoughtful hedging program, you get the lowest breakeven among natural gas producers and the most resilient organic free cash flow, as evidenced by our first quarter results and 2024 projections. Importantly, with our vast inventory of derisked high-quality Marcellus wells, we have the ability to compound our per share growth in free cash flow for decades to come. Looking back on the quarter, all-in capital came in at $170 million, with production of 2.14 Bcf equivalent per day. This capital spend aligns with our operational cadence detailed on our previous call and places us squarely within our stated capital guidance for the year. During the quarter, 9 wells returned to sales with an average laterally exceeding 10,000 feet per well. These wells were located in the liquids-rich portion of our operating footprint, supporting the highest Liquids production profile that Range has had in many years at 32% and providing the revenue uplift touched on just moments ago. Additionally, all of these wells are located on pads with existing production, minimizing our operating surface footprint, supporting nimble operations and driving Range's cost-efficient development approach. Production during the quarter was aided by strong well performance and continued optimization of our dry and wet gas gathering systems. These consistent quarter-over-quarter results demonstrate the repeatable nature of our large contiguous acreage position and the benefit of returning to pad sites for our ongoing development. Turning to operations. 2 super-spec horizontal rigs operated during the quarter, adding 13 laterals with an average lateral length of just under 16,000 feet per well. This was a new quarterly record for Range and is the type of performance that underpins the improved well cost Range expects for 2024. For completions, the team successfully onboarded our new build electric frac fleet that will be utilized throughout 2024. The new fleet provides a smaller operating footprint, which complements operations when moving back to pads with existing production. The fleet also includes state-of-the-art process control and power distribution technologies. And is coupled with a larger natural gas-fired turbine, which aids our continued efforts to electrify operations and reduce emissions. Performance of the new fleet thus far has been excellent. As evidenced by the new program records set during the first quarter with a 15% increase in the number of stages per day completed versus the same time period just a year ago. Supporting the completions performance was efficient water operations and logistics, as the team recycled 100% of Range's produced water, while taking incremental third-party water to further support our operations. Looking at activity levels for the remainder of 2024, we will continue to run 1 electric fleet on completions and 2 horizontal rigs, but we have further refined the timing of our turn-in-line activity and have pushed all of our TILs for the dry window deeper into the back half of the year. Despite pushing these productive dry gas wells later in the year, our annual production guidance remains unchanged with a slightly higher liquids cut expected in the first 9 months of the year, when NGLs are particularly advantaged relative to natural gas based on current forward prices. Before moving on to marketing, I'll briefly touch on service costs. So far in 2024, we've seen full utilization of high-spec equipment in the region, such as high torque top drive drilling rigs and electric frac fleets with service costs remaining relatively in line with our prior call. There is potential for service cost to ease during the year as operators complete or curtail their programs in response to the current commodity environment, especially for higher cost dry gas basins. In the event, service costs softened during the year, Range will be positioned to capture savings and further complement our Lean program and capital efficiency for the year. Shifting over to marketing. Similar to our messaging in February, Range utilized the flexibility built into our NGL transportation portfolio to capture some of the highest market premiums in company history during the quarter. This winter's market dynamic suggested that domestic butane prices offered the best returns, while international propane netbacks were set to exceed local values. As a result, Range directed more butane to U.S. Northeast markets, while exporting the vast majority of its propane production. This resulted in some of the highest premiums to the Mont Belvieu index that we've seen. In total, the realized NGL price for the quarter was $26.24 per barrel, $1.91 over the Mont Belvieu equivalent, which contributed to our overall corporate realizations of $3.54 per Mcfe, a significant premium to natural gas. Going forward, we expect continued growth in U.S. propane exports, as 18 new PDH units come online this year and next, adding the capacity to consume another 500,000 barrels per day of propane at full utilization rates. To the extent Gulf Coast NGL export capacity continues to tighten, Range's firm transport on Mariner East to the Marcus Hook export facility should continue to provide advantaged NGL price realizations. As a result of this dynamic and the strong start we've had to the year, range is improving its full year guidance for NGLs to a differential to the Mont Belvieu index of $0.25 per barrel discount to $1.25 per barrel premium. Despite current natural gas storage levels and the current commodity backdrop, the resilience of Range's business is on full display in quarters like Q1. This is underpinned by our large contiguous high-quality acreage position, operational efficiencies, NGL uplift, diverse marketing portfolio and talented team. We believe the future of natural gas and NGLs is strong, and the Range team remains focused on generating free cash flow. While advancing our overall efficiencies and delivering repeatable well performance across our large contiguous inventory. I'll now turn it over to Mark to discuss the financials.

Thanks, Dennis. In the first 3 months of 2024, Range has kicked off what we expect will be a disciplined and promising year. Range's most fundamental objective is to safely and consistently generate cash flow for its stakeholders. Despite commodity prices seen in early 2024, Range continues to generate healthy free cash flow, pay dividends, reduce debt, while maintaining the ability to thoughtfully reinvest in our operations. As mentioned during our last call, Range has an efficient plan to maintain steady production this year, adapt to near-term commodity prices and resulting economics, while also positioning our long-term business for eventual growth as demand increases from domestic and international customers. As incremental demand materializes in basin, near basin and farther downstream, Range has the cost structure, inventory and infrastructure to remain a reliable long-term energy supplier. Results of the first quarter highlight the strength of Range's production mix and transportation portfolio. Realized price per unit of production before NYMEX hedging was $0.70 above NYMEX Henry Hub prices, a byproduct of our diversified mix in production and sales outlooks. Including hedges, Range realized $3.54 per Mcfe. First quarter cash margins per unit of production were $1.59, a healthy 45% margin, resulting in cash flow before working capital of approximately $308 million. Cash flow funded capital investment for the quarter of $170 million, a reduction in debt net of cash of $150 million, along with roughly $19 million in dividends and $24 million paid for common shares withheld for taxes on equity compensation. Financial results rely on safe, efficient operations and the Range team executed another successful quarter, delivering planned production on budget. As a reminder, the plan we announced for 2024 differs slightly from others in the industry and our capital efficiency, low full cycle costs, paired with advantaged marketing of our production generates meaningful margin at current commodity prices. Meaning Range has options, options on how we redeploy capital into the drill bit, infrastructure like water facilities that provide durable cost reductions or low-cost lateral extending land, among other attractive alternatives. With a thoughtfully constructed hedging program, we seek to participate in improved long-term market dynamics, while increasing confidence in near-term forecasted cash flow that support consistent, efficient operations, while protecting the balance sheet and creating additional optionality around capital allocation. Range's hedging philosophy has produced successful results that have served the company well, and we expect will continue to do so in the future. Presently, Range has approximately 55% of 2024 natural gas hedged with an average floor price of $3.70. And in 2025, approximately 25% hedged with an average floor price of $4.11, providing Range a stable base to consistently generate free cash flow through market cycles. Our comments this morning may sound familiar, and that is a good thing. We intend to share our corporate goals and to deliver on those plans. Range has transitioned over the years from a start-up in a manner of speaking. When we drilled the discovery well at the Marcellus to a rapid growth commissioning phase for a decade to a successful business generating value from a massive well-understood asset. The options ahead for Range are attractive, particularly given the balance sheet within our targeted debt levels. LNG is a well-known evolution for the industry, linking the U.S. with international customers. What is perhaps less appreciated and still developing are domestic opportunities in the form of reindustrialization, be it semiconductor manufacturing, EV battery plants, data centers and electric generation. With modest investment in inventory this year, we believe Range is creating valuable future optionality to participate in that growing demand as it comes online. Range's business plan continues to be executed on what we believe is the largest per share exposure to core Appalachia inventory, paired with a transport and sales portfolio, delivering production across the U.S. and internationally. All underpinned by a strong financial foundation. We have the team, assets and balance sheet to succeed through price cycles and we believe the Range business can and will continue to deliver significant value to investors. Dennis, back to you.

Thanks, Mark. Our 2024 program is off to a solid start. And I believe the first quarter results communicated today showcase that Range's businesses in the best place in company history, having derisked a high-quality inventory measured in decades and translated that into a business capable of generating free cash flow through these types of cycles. With that, let's open the line for questions.

[Operator Instructions] Our first question comes from the line of Michael Scialla with Stephens.

Dennis, you mentioned the strong domestic butane and international propane markets. So like the dynamics there are more than seasonal and caused you to raise your '24 realization guidance? Do you have any visibility on those markets longer term? I know everybody is bullish on gas longer term, but I haven't really heard views on those NGL markets for the '25 and beyond period.

Yes. Good morning, Michael. I'll kind of take a step back and kind of starting at a high level, and then we have Alan Engberg here with us this morning, and so I'll look to hand off to him to maybe take a bit of a deeper dive on this topic. But I think, if you look back on the past several years, we tend to see some seasonal effects associated with both propane and butane and just the different components of the NGL stack itself. And that's one of the reasons why we've always had the flexibility that we've webbed into the way we look at our sales and also our transportation options where we can put barrels on waterboard, and export or leave them here on a domestic basis when we see those fluctuations. The gasoline blending season, no doubt played a role in how we looked at the different pricing for both of them. But as we take a step back and look at propane, a big driver was no doubt getting stock levels back to a place more renormalized in the back half of last year and then getting into what we felt like was more something normalized for this past Q1, and the presence of winter that we did have. I'm going to hand it over to Alan though, and he can add some additional color.

Yes. Michael, this is Alan here. I guess, part of your question also was around what we see coming forward. And I guess, I could say right now where we're at on propane, we've got days of supply, as of the end of winter or the end of March at around 19 days. So that's about 10% under the 5-year average. Pricing. We saw that improve during the first quarter, just market price went to $0.86 per gallon on average and 46% accrued, and that compares to the fourth quarter, which was at $0.67 per gallon and 36% accrued. Going forward though, over the next 2 years, so this year through 2025, we still see tremendous new demand coming on stream internationally. That's LPG crackers, that's res/com growth and it's 18 new PDH units that are going to come on. In that 620 day of new demand, that's taking PDH utilizations down to 65% this year, 70% next year. So we think it's a pretty conservative estimate. Overall, U.S. supply so far this year, if we look at the weekly EIA stance, it's up about 6%, and that matches the supply growth that we saw in 2023. So it's a relatively decent number to work with. Internationally, though, they're kind of like we saw last year, there really isn't a whole lot of international supply growth. In fact, during the first quarter, OPEC Plus, if you look at them as a whole, their LPG exports relative to the first quarter, '23 were down 2%. And, so what that means is that there's going to be -- going forward, a continued strong call on U.S. supply to the international markets. During '23, the U.S. captured 90% of the international growth in LPG demand. And I'm going to just conservatively cut that to 80%, and it still means a call on U.S. supply of 500,000 barrels per day this year and next year. And that's going to -- it's more than what our supply is. So that means that we're probably going to be pulling from inventory. That means U.S. fundamentals are going to improve. That means dock premiums are going to get higher. Range has dock capacity or export market capacity that's equivalent to roughly 80% of our LPG production. That exceeds any of our wet peers. And it's a good position to be in. So we're quite pleased with that. Dock capacity is getting tighter, particularly in the U.S. Gulf Coast. There's more capacity available on the East Coast. And I think we're in a very good position to continue to use our flexibility to place products to the markets that give us the best returns.

Well, it sounds very promising. I appreciate all that detail. I want to ask Mark. Mark, your cash balance increased for the quarter above $300 million. Should we assume you want to maintain a higher cash balance now than you have in the past to take advantage of opportunities to purchase notes like you did in the quarter in the open market? Or do you expect that cash balance to come down over the year?

I think you'll just see it fluctuate based on how we choose to allocate within a given quarter. The 2025 notes is clearly very high priority that we make sure we comfortably handle and very economically handle. So chipping away at those in the open market, being able to buy those in at a discount is certainly a compelling option. But our return to capital program, as well as just funding our working capital needs, intra month, it's most efficient to use that, especially since interest rates are where there are. There's a decent return in holding that versus quickly redeploying and some other areas are moving too quickly on buying back, some bonds or paying a premium at the moment. That said, we'll take a conservative and risk appropriate strategy to continue deleveraging and paying off that debt. But I guess the long and short of it is having some cash on the balance sheet, I think, is prudent at this time and an effective -- cost-effective way to manage our working capital.

And next question comes from the line of Bertrand Donnes with Truist.

Just wanted to brush on the topic of shifting some of your dry gas wells to later in the year. Is this a moving target if gas prices remain depressed, would these move into 2025? Or would they be replaced with liquids locations? Or is there some motivation maybe lease lines or something like that where you need to get these wells turned in the next 12 months?

Yes. I'll tackle that from kind of a various set of angles. But I think what -- when you look at where prices are today, I mean, these are still profitable wells. We think we have the flexibility by pushing these turn-in lines deeper into the year. And there is the potential they could even go a little bit further, depending upon what signals that we see in the market. We ultimately feel like pushing them to a time that's more optimized makes a lot of sense for us. And as you heard us touch on in the prepared remarks, this is all coming on the back of not changing our production guide for the year. Pricing will just be one really one component that we'll look at. I think we'll want to keep a close eye on when those wells turn in line. Well, considerations will involve, what kind of decline do we see in U.S. production. We're starting to see a dip below 100 Bcf a day now. We find that encouraging. Rig count seems to be stable and down in some basins. What kind of decline rate do we see further materialize in the Haynesville, as an example. So I think those are just some of the aspects we'll keep a close eye on, along with the commissioning for the next 2 facilities on the LNG side between Golden Pass and Plaquemines, certainly encouraging result -- encouraging information of late on the timing for those facilities. But all of that will kind of come into play as we think about the timing at which we would bring those wells back into the mix. They'll be drilled, completed and ready to go. And so our timing to be nimble -- our ability to be nimble and timing to turn that production in the line should be relatively short and have the ability to put those wells to sales, when we see pricing improvement and stable pricing improvement, not just in a spot market type basis.

That's great color. And then I think I heard you mention some potential cost reductions on the service side. Are you seeing these reductions track more so with lower gas prices? Or is this a function of the activity cuts by the gas group? Or is this maybe a push by a market share grab by some of the service companies? Just anything -- any patterns you're seeing out there?

Yes. Good question. I think you've probably heard me touch on this in the past. But service cost adjustments feel a little different today, and they have even somewhat through the last 12 months than maybe prior peer cycles of commodity prices up, service costs up, commodity prices down, service cost out. And what I mean by that is you're seeing, let's just say, electric frac fleets, at a still a relatively high level of utilization, super-spec rigs are at a high level of utilization. In our case, we have some of that under contract, and so there's optionality that we baked-in as a part of that. But ultimately, as you'd imagine, some of that is secured for the year. We do see that they are starting to have -- we're starting to have some conversations around what will end of your activity levels look like, what will service costs then do in response to that. So we very well like we saw in the last year to see some relief associated with maybe some consumables and other respective items that start to see some relief, but it's early. And that's -- we would expect if there are some service cost relief type variables that most likely, they'll start to materialize in the back half of the year as you see programs start to reach their close or you see further activity get shuttered because of let's just say, poor returns for those other high-cost basins. So again, it's early, but we -- wherever the service cost equation lands for the industry this year, and particularly in Appalachia, we like our opportunity to be on the leading edge of capturing those costs if they further come down.

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

I just wanted to touch base real quick on -- given current market conditions and expectations, how are you guys thinking about '25 hedging? You have 55% for this year, 25% hedged or locked up for next. If I were to thinking about where that right level should be? Or is that more of a function of next 6 months or so?

Paul, I think I'll start with our philosophical approach and how we think about hedging, particularly where the balance sheet is today within our targeted net debt levels. The basic principle that we use to back calculate and figure out where we're most comfortable as a starting point is just to cover the fixed cost. While we're in the commodity business, this is not just a pure simple commodity, but they are fixed costs built into the business, be it the technical of the people, the safety and so forth to just prudently safely, efficiently, continue to run the company through a cycle. And to do that while preserving the balance sheet and being better able to maintain a steady cadence, to use and fully utilize -- effectively utilize equipment that we'd like to contract for that we know is productive and the most efficient the safety and the repeatability of that over time, having some stability in your maintenance capital spend or other, the ability to weather it shoulder season or a surprise poor winter weather, that sort of thing. Having some financial foundation there support from a hedge book makes sense to us cover those fixed costs. So all of that as a backdrop, that 25% at $4.11 in 2025, we think gets us there. Stress it down to an extreme low $2 type pricing, of course, with our NGL uplift, that provides us with a high degree of comfort and confidence in where the company can land financially for 2025 and going forward. The flip side of that is, we like the 25% hedge and the 75% or a significant portion unhedged in 2025, just because of the fundamentals. Significant demand coming online. As we look at production trends that Dennis just touched on, across the U.S. declining production levels, rig count deployed across various basins, basin-wide decline rates outside the Marcellus and even within the Marcellus are certain producers, we are set up for what we believe is a really compelling shift in the supply-demand equation, both for natural gas and natural gas liquids in 2025. So as we look at the fundamentals and compare that risk-reward scenario, we like having the downside production while having exposure to what we think is a positive setup for '25, '26 and beyond. So as you play that out in '26 and beyond, I think the basic philosophy continues. How do we continue to maintain that nice base of protection. So of course, the percentage hedged depends on what price we can hedge, but that 25% is a good example of what you may see going forward.

Understood. And just a quick follow-up to kind of portend into some of the stuff you said. So on Slide 17, you talk about a potential 16, the toll over the next few years and incremental call on gassy -- on gassy basins, from that number, does that shift your thought process on Slide 9, so the kind of the locational destination of where you want to see or where you want to end up in the product? Is there any shift there? Or is that still going to remain relatively consistent?

Yes, Paul, I think your -- to think that it's going to be consistent, I think, is a good starting point. The transportation portfolio and options that we have, have a lot of long-term optionality for us. And so there's the ability for us to continue us to say, stand in the exposure to those different markets that we've had a luxury being a part of and participating in for the past decade now. So, there is an opportunity in our opinion in the future for capacity to go underutilized by other producers as you start to see conversations like inventory exhaustion become more material, as you start to see capital allocation maybe look differently for different producers as they think about different basin exposure. And I think all of that starts to point to a really good complement to our ability to put additional production, when the call on that is appropriate. And get more exposure to those same and similar respective markets. Clearly, on the NGL side, we've already got a lot of exposure to both the Gulf and also to water board export capacity, out of markets in Philadelphia and we would expect that to be consistent as well.

Our next question comes from the line of Nitin Kumar with Mizuho.

Dennis, I want to start on Slide 17. Obviously, AI the demand growth for gas from AI adoption is a big topic out there. In your outlook, you only bake in about a Bcf a day of incremental demand growth. Obviously, you mentioned there are others that have higher expectations. I just want to see like, is there a difference in assumptions? Or are you seeing something on the ground that's making -- maybe making you more conservative than some of the expectations that are out there?

Yes, good morning. The power demand piece has no doubt been more and more topical every time we get around the table with investors these days. And also internally, as we have these conversations about the future of our industry. I think we wanted to take a conservative view on the outlook from a standpoint of we know that -- it's going to require some conversations around further probably permit support, infrastructure development. But if you had to, I guess, pin us down on a respective range or a number, we think a Bcf a day is a very conservative outlook. And we think there's a lot of opportunity when you look at gosh, if you just look at PJM alone, they came out with a forecast here recently that suggested that in a nutshell, 20 additional gigawatts is going to be required in that power market alone by 2030. That's going to represent somewhere between 2 and 3 Bcf a day at opportunity. So that's kind of narrowing it down. We'll stay a little bit closer to home for us. And again, we even think that's conservative. When you start to think about the exposure to further coal retirements is another 2 Bcf a day approximately that's going to get retired in that similar time frame in the Northeast. And clearly, you've got some other facilities that may be facing retirement conversations, either regulatory driven or economics-driven. So all that to be said, we really think there's a key opportunity here. Our diverse portfolio gets us to several of the markets that could have exposure to this AI and power demand equation. And you can start to even -- I'll just say, take a step back and say, even though the data center concentration is clearly in a place like Virginia, I think one of the questions that we're starting to raise is, does this now change -- because of the reliable and cost-effective clean part of our supply equation. Does that start to challenge and relocate some of the data center development, as Mark touched on, reshoring of industrialization and manufacturing expansion, all of that confined, let's just say, new concentration centers closer to that reliable supply, which aligns with us. It aligns with Range in the long-dated inventory that we have and that runway and the quality of it. So Yes. I think a Bcf a day is a conservative estimate. But as you've probably seen from several of the research pieces today, that Range can be wide and a little bit all over the place. But I think it's clearly pointing to there's a really good opportunity here. And one that we could play a part of.

Great. My second question is perhaps related, but you started talking about the 200,000-odd acres you have in the Northwest Pennsylvania. Perhaps closer to the Midwest area and some of your peers have been testing it. Can you talk a little bit about this acreage? And is this -- does this asset play any part in your capital plans for the next 2, 3 years? Or is this just option value for you at this stage?

Yes, it's probably more the latter than the prior. That's -- the Northwest Pennsylvania footprint represents a part of our legacy activity from years and years ago. And it is a part of our asset base that is held by -- the deep prices are held by production. And so there's not an at-risk component associated with the land. And so we feel like our focus for the next several years is going to be the bread and butter of what we've reported on in this quarter and the prior, and that's the Marcellus and continuing to harvest the value of that portion of our asset base. But the reason why we still retain Northwest PA is it's a stacked hydrocarbon charged column in that part of the basin, much like other parts of Appalachia. And so we're watching what's taking place in places like Ohio with others that our acreage is on trend for a portion of that, and we'll kind of sit back and watch. We have the luxury of doing so instead of needing to prospect on that part of our asset base while we continue to harvest the cash flow and the returns associated with the Marcellus.

Our next question comes from the line of Jake Roberts with TPH & Company.

Just wanted to circle back and topic of your AI here. But I think your view of Virginia, we tend to agree with. And we're just curious if you could frame ultimately what you think that back half of the decade growth or demand outlook looks like in basin or out of basin? And do you think there's a general perception that pipelines will be getting built out in the Northeast on a lot of these forecasts?

So I'll jump in here. I think to start with, this is still very early in how both the power markets and the data centers and all of this has developed the cadence, the energy sources and so forth. But again, looking at some recent third-party research and just -- if you think about in the U.S. gas market share being north of 40% or right at 40% and roll that forward, make that a simple assumption through 2030. And then even think closer to home for Range, where in the Northeast, think Virginia, Ohio, New York, just general Northeast type markets, that data center market share is about 35% of the U.S. market. So if you back-sold for that, you get anywhere from 2.5 to 5.5 Bcfs equivalent of natural gas demand for power. So we just see this as an early but very compelling source of incremental demand over and above the demand that's already been baked in PJM, but Dennis mentioned earlier, is revised upward of their expectations. Other grid operators have as well. We can just zoom back out to the general concept of reindustrialization and reshoring in the U.S., be it the Intel plant in Ohio, while EV sales and production are slowing down a little bit, there is incremental demand in form of multiple EV battery plants, be it in Indiana from the Stellantis Samsung plant or in Ohio from the GM LG plant. And these are just a couple of examples of a whole host of other industrial projects, which ultimately pull you back to power to the grid and how that gets built out, be it distribution networks and generation and pulling back to gas. So we think proximity to that is important. You need Appalachia, you need the Marcellus, that low decline, clean base foundation of supply and it's cost competitive. So while we can't give you a high degree of confidence on what those other industries, the speed and permitting and construction cadence will be, we do have a high degree of confidence that we can play a fundamental role in making that economic and reliable and continuing that build out now through the end of the decade.

Yes. And I'll just tack on one quick thing, Jade, to maybe close this topic out. I think when you start to look at the supply-demand piece, really in-ground storage, as you probably well know, has really not changed in a material way over the past decade. And so as you start to think about in-ground storage not really changing as you think about now, even if -- let's just say this wide range of variability is 2 to 3 Bcf or 5, as Mark points out, who knows where it fully lands, but it's hard to imagine us going forward in this -- in the Lower 48 without further electrifying what we do. And that's going to require infrastructure, pipes and wires to be able to get low-cost, reliable, clean, effective energy to basically power what we do. And so the equation starts to break down at that point, if you're going to meet the supply without additional pipeline infrastructure and wires to support that power getting to those underserved markets or critical markets. So infrastructure is going to play a real part of this, in our opinion.

I appreciate the color. And as you -- I know you want to close the topic out, maybe just one more. As infrastructure does appear, the time lines are longer, permitting becomes more difficult. Is there a more compelling case to be a multi-basin operator in the back half of this decade to perhaps take advantage of where this onshoring or data center facilities ultimately come online?

Yes. Really good question. I kind of think I would take a step back on this and say, look, when you look at where a lot of the power demand and some of the manufacturing that Mark touched on, it's going to be regional for our asset base. And so I think whereas maybe a year ago, the question may have revolved around multi-basin exposure advantages tied specifically to LNG. In our case, we don't really feel like that has to be a driver. We've got the inventory to basically deliver repeatable results on the transport we have 2 LNG type outlets. And now is this data center demand opportunity further materializes, grows and develops we feel like it's going to be more regional to an Appalachian producer like Range. So we feel like this takes -- it further supports developing our Marcellus and then the decades to come or Utica and then later after that, the Upper Devonian. So I think it puts us in a great position to not need to have other basin exposure.

Yes, I'll join in on that. I would say that Range effectively is economically is a multi-basin company. 90% of our revenue is outside the basin. The transportation portfolio moves north of 80% of the gas out of the basin and virtually all of the liquids. So we have the best marriage of the most efficient asset with the business overlay and the infrastructure to transport that production and connectivity to end markets. The proximity is actually an advantage, I would say, being concentrated in the Northeast for all the reasons we just touched on, in the form of incremental power and the sheer population density and data center and other sources of future demand that's going to manifest itself in the next few years. So from an operational standpoint, no, we don't feel that driving need or compelling need to have another operational footprint. And from an economic perspective, we think the overlay of the transport accomplishes the goals, the risk mitigation and the capture of opportunities in other basins, both domestically and internationally.

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

Wanted to just follow up a little bit on what you're thinking on production trajectory for the rest of the year. Obviously, a good start in the first quarter. You mentioned kind of moving some tills back. I mean normally Range sees kind of higher production in the second half. But maybe this is not happening, maybe 3Q dips a little bit and then 4Q stronger. Just trying to get a high-level sense of how you see production trending over the next handful of quarters?

You bet. Good question Leo. I think when you look at this year, it really should look and feel very similar to prior years under this maintenance type profile. The one -- a couple of differences maybe this year that you'll feel when you start to see the numbers quarter-over-quarter. And we've somewhat touched on this in prior -- some, probably one-on-one conversations, but as long lateral development has -- long lateral development has continued to materialize for us. And clearly, we talked about that a lot last year. Our original plan was 10,000 feet for an average horizontal. By the end of the year, it was approaching 13,000 feet, took some of our TIL count down while we still had a similar, if not slightly up turn-in-line footage versus the original plan. All that starts to influence the production shape throughout and profile, throughout that following program year. So Q4, we saw some of our long laterals turned to sales. They're demonstrating not only really strong well performance, but they're also continuing to basically keep parts of the gathering system at a high level of utilization. So all of that to say, maybe in prior years under maintenance where you've seen us have a Q1 to Q2 dip in production and then see a stronger ratable increase in the back half of the year, you could see that, that shallowing potentially this year, where maybe that Q1 to Q2 time frame is a little bit less, and you're actually going to see something a little flatter. And that kind of makes sense when you look at 2 flat drilling rig programs for the year, very lean with the one completion crew supporting that. And on top of it, you're seeing some of this long strong well performance from our long laterals.

Okay. No, that's helpful for sure. And then just wanted to touch base, on the share buyback. Obviously, you folks haven't done quite as much over the last few quarters despite pretty robust free cash flow here and a nice cash balance. I get you've got the debt maturity coming up in roughly 12 months, but it seems like you could easily refinance that. You're kind of at your net debt target under $1.5 billion. So maybe just talk about how you're kind of thinking about the buyback going forward in terms of kind of allocating between debt paydown as well?

Yes, we work our way and have worked our way into the net debt target range. We certainly have a lot more latitude and flexibility. It has been an opportunistic program by design from the very beginning. And 1 year, 2 years ago, we repurchased $400 million. The year after, it was something like $19 million. As I mentioned, some shares are repurchased in cash effectively related to equity compensation. So there's some decent purchases that way. So again, to your point, since we're in the debt target range, we certainly have a latitude. The debt refinancing. Again, there's a lot of choices. That's been kind of a repetitive theme today is us creating options and choices. We never want to be in a situation where we have to do something. So with the ability to simply use undrawn revolver in addition to the cash we have on the balance sheet to deal with refinancing, again, that frees us up as we evaluate movements in the market. Certainly, the way I would put it is, if we see a pullback in the stock price, we would certainly be more apt to lean in and repurchase more aggressively. In the meantime, that certainly remains part of our plans going forward. We have ample capacity under the existing Board authorization greater than $1 billion right now. So it will be a part of the plan. But again, we're not locked in on a specific formula. The idea is to not simply execute a procyclical program, but to make this an efficient value-generating exercise to maximize returns for the shareholder.

We'll now go to Noel Parks with TUI Brothers investment research, for our final questions.

Just a couple of things. I wondered, just in your broad thoughts about what you're seeing in the industry. With the lower prices, people probably being a little bit more conservative in spending overall. As far as what you're seeing from maybe your non-operator partners and other peers, what do you think as far as continue to work on emissions control? Just wondering if that's continuing as it has been or if you've seen any shifts in people's attention to that?

Yes. I appreciate you joining the call. Emissions management has not -- I'll just say, philosophically, has not changed for Range, and we've continued to maintain the same course that we charted a few years ago. At this time, last year, we transitioned over to, as an example, a new facility installations we're getting -- we're moving away from traditional pneumatic conveyors in for controllers and using basically modern technology. So something that's more air conveyed and also using nitrogen. We've now also gone transitioned to a retrofit program, again, as an example where we're going back to other sites and making those upgrades as well. Coupling it with, looking at field run time, making sure that we've got the best design in the field that's supporting our overall both economic and operational approach. So just using those 2 examples, but nothing has changed on that front. We got MIQ certification last year. LDAR program still remains at 8 times a year, where our leak detection program is as robust as ever. And we've even looked at, we'll just say, a beta test of a top-down survey, and we're in the process of analyzing that data as well and how it complements our ground level inspection process. So certainly, from a Range perspective, we're still remaining focused on reducing missions tangibly further in an economic and responsible way.

Great. I'll be interested to hear about the results of that survey. And just trying to cross for a second. The outlook, looking ahead for materials, thinking about steel, in particular, for the longer term. Is that still looking pretty constructive? Or are you seeing any issues on the horizon there?

Noel, are you speaking specifically to service costs?

I think it's specifically about steel, materials overall.

Sorry about that. I didn't quite hear that. So from a tubular goods perspective, we have seen some softening in that cost through the back half of last year. And a similar strategy, you've heard us talk about probably before, but we procured a significant portion of our tubular good needs for this year's program last year, when we saw a positive window for us to do so. But we have seen some fluctuations this year. But I would expect, as you start to see inventories get to a place where they've renormalized based upon rig activity, you could see some further relief in tubular good prices.

Thank you. Ladies and gentlemen, this concludes today's question-and-answer session. I would now like to turn the call back over to Mr. Degner for closing remarks.

I'd just like to thank everyone for joining us this morning on our Q1 call. If you have any follow-up questions, don't hesitate to reach out to our Investor Relations team. We look forward to seeing you on the next call. Thank you.