Range Resources Corp Q1 FY2024 Earnings Call

Hello. Welcome to the Range Resources First Quarter 2024 Earnings Conference Call. Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements.

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 the 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 peer-leading capital efficiency and prudent allocation of that free cash flow balancing returns to 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 a 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 lateral 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. Two 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 one electric fleet on completions and two 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 nine 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 costs 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 soften 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 three 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 business is 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.

Our first question comes from Michael Scialla with Stephens.

Dennis, you mentioned the strong domestic butane and international propane markets. So 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 starting at a high level, then we have Alan Engberg here with us this morning, 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 woven into the way we look at our sales and also our transportation options where we can put barrels on a 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 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 two 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 and 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 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 be 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 are clearly a 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, intramonth, it's most efficient to use that, especially since interest rates are where they 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?

I'll address that from several perspectives. Currently, prices are still favorable for profitable wells. We believe we have the flexibility to push the turn-in lines deeper into the year, and they may extend even further based on market signals. Timing them for optimal conditions seems wise. As mentioned in our prepared remarks, we're not changing our production guidance for the year, and pricing is just one factor to consider. We’ll monitor when those wells come online closely. Factors like the decline in U.S. production are important; we're seeing it dip below 100 Bcf a day, which is encouraging. The rig count appears to be stable or declining in some areas. We'll also assess the decline rates, particularly in the Haynesville. Additionally, we'll keep an eye on the commissioning schedules for the next two LNG facilities, Golden Pass and Plaquemines, as recent timing updates have been positive. All these factors will play a role in deciding when to bring these wells into production. They will be drilled, completed, and ready, allowing us to respond quickly and put them into service when there’s stable pricing improvement, beyond just short-term market fluctuations.

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 any patterns you're seeing out there?

Yes. That's a good question. I think I've mentioned this before. Service cost adjustments feel somewhat different today compared to previous cycles where commodity prices increased and service costs rose, followed by a drop in both. Right now, we see electric fracturing fleets and super-spec rigs still being utilized at relatively high levels. We have some of that capacity contracted, which provides us with flexibility. However, a portion of this is secured for the year. We're starting to discuss what year-end activity levels may look like and how that will affect service costs. There is a possibility we could see some relief in costs related to consumables and other items, but it's still early to tell. If there are variables that lead to service cost reductions, we expect those to become evident in the latter half of the year as projects wrap up or if there’s a decline in activity due to poor returns from high-cost areas. Again, it's early, but we believe we are well-positioned to take advantage of any potential decrease in costs, particularly in Appalachia.

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

I just wanted to quickly check in on how you are thinking about hedging for 2025 given the current market conditions and expectations. You have 55% hedged for this year and 25% locked in for next year. What do you think is the appropriate level for this, or is that something that will depend more on the next six months?

I will begin by discussing our approach to hedging, especially considering the current state of our balance sheet and our targeted net debt levels. Our main principle is to cover our fixed costs. Although we operate in the commodity business, it's essential to recognize that there are fixed costs involved, including personnel, safety, and other factors that allow us to run the company effectively and prudently. This strategy helps us preserve the balance sheet and enables us to utilize our equipment effectively while maintaining a steady operational rhythm. It also provides us with the financial foundation needed to manage unexpected situations, such as seasonal fluctuations or adverse weather conditions, through our hedging strategy. Based on this understanding, we believe that hedging 25% of our production at $4.11 for 2025 positions us well. Even if prices drop to an extreme low of $2, the uplift from our natural gas liquids gives us confidence in our financial standing for 2025 and beyond. On the other hand, we're comfortable with having 25% hedged and keeping a significant portion unhedged for 2025 due to the favorable fundamentals we see, including the strong demand expected and the declining production trends highlighted by Dennis. Given the reduction in rig counts and production across various basins, we anticipate a significant shift in the supply-demand balance for natural gas and NGLs in 2025. Therefore, we prefer this balance of downside protection while also benefiting from what we see as a positive outlook for 2025 and onwards. As we think about '26 and beyond, our fundamental philosophy remains the same: we will aim to maintain a solid base of protection. The percent hedged will depend on the prices available for hedging, but using 25% as a benchmark is likely indicative of our approach moving forward.

Understood. As a follow-up to your comments, on Slide 17, you mention a potential 16 and the impact over the next few years regarding gassy basins. Does this change your perspective on Slide 9 about where you want to focus your efforts with the product? Is there any change in direction, or will it remain largely the same?

Yes, Paul, I believe it's reasonable to expect consistency. Our transportation portfolio offers significant long-term possibilities. We have the opportunity to remain engaged in various markets that we've been part of for the past decade. In our view, we foresee a future where other producers may underutilize capacity, particularly as discussions about inventory exhaustion gain traction and capital allocation strategies evolve for different producers exploring various basins. This situation highlights our potential to increase production when appropriate and to enhance our presence in similar markets. On the NGL front, we already have substantial exposure to both the Gulf and export capacity from Philadelphia, and we anticipate this will remain steady.

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

Dennis, I want to start on Slide 17. The demand growth for gas due to AI adoption is a significant topic right now. In your outlook, you only account for about a billion cubic feet a day of additional demand growth. You mentioned that there are others with higher expectations. I’m curious if there’s a difference in assumptions, or if you are observing something that might make you more conservative compared to some of the prevailing expectations.

Good morning. The topic of power demand has increasingly been a central discussion during our meetings with investors and internally as we consider the future of our industry. We have opted for a conservative outlook, understanding that it will necessitate discussions about further permit support and infrastructure development. If we had to provide a specific estimate, we consider a Bcf a day to be a very cautious expectation. There seems to be significant opportunity, especially considering PJM's recent forecast, which indicated that about 20 additional gigawatts will be needed in that market by 2030. This could translate to approximately 2 to 3 Bcf a day in opportunity. Focusing on our home markets, we believe this estimate remains conservative, particularly when we take into account the expected retirement of about 2 Bcf a day of coal in the Northeast over the same timeframe. Additionally, other facilities may also be facing potential retirements due to regulatory or economic pressures. Overall, we see a substantial opportunity. Our diverse portfolio positions us well to tap into various markets affected by this dynamic in AI and power demand. Notably, while data centers are mainly concentrated in Virginia, we are beginning to question whether the reliability and cost-effectiveness of our clean supply could influence the location of future data center developments. This relates to broader themes of reshoring industrialization and the expansion of manufacturing, ideally situated closer to dependable supply sources, which aligns with our long-term inventory and its quality. Therefore, while we believe a Bcf a day is a conservative figure, research suggests there is a broad range in expectations, but the outlook certainly indicates promising opportunities that we can contribute to.

My second question is related to the approximately 200,000 acres you have in Northwest Pennsylvania. With a focus on the Midwest area and considering that some of your peers have been testing it, could you provide some insights about this acreage? Additionally, will this asset factor into your capital plans for the next two to three years, or is it primarily just an option value for you at this time?

Yes, it seems more likely to be the latter rather than the former. The Northwest Pennsylvania area is part of our legacy operations from many years ago. It constitutes an asset within our portfolio where the deep prices are maintained through production, meaning there is no at-risk element linked to the land. Our primary emphasis for the coming years will be on the core activities we've discussed this quarter and previously, specifically the Marcellus and continuing to maximize the value of that segment of our assets. We still hold onto the Northwest PA area because it features a stacked hydrocarbon-charged column similar to other regions in Appalachia. We are monitoring developments in areas like Ohio, where our acreage aligns with those trends, and we can take a step back and observe. This allows us the advantage of not needing to actively explore that segment while we focus on generating cash flow and returns from 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?

I think it's important to note that we're still early in seeing how the power markets and data centers are evolving, including energy sources and their development. Recent third-party research suggests that gas market share in the U.S. is above 40%. If we extend that assumption through 2030 and consider the Northeast, particularly in states like Virginia, Ohio, and New York, data center market share represents about 35% of the U.S. market. This indicates a demand for natural gas for power ranging from 2.5 to 5.5 Bcfs. We view this as a promising source of incremental demand, beyond what has already been included in PJM's upwardly revised expectations, as well as those of other grid operators. Furthermore, the idea of reindustrialization and reshoring in the U.S. is relevant, illustrated by projects such as the Intel plant in Ohio. While electric vehicle sales and production are slowing, there is still incremental demand from several EV battery plants, including those in Indiana and Ohio. These projects underscore the need to connect back to the power grid and the necessity of developing distribution networks and generation, returning to the topic of natural gas. Proximity to resources like Appalachia and the Marcellus is crucial, given their low decline rates and cost competitiveness. While we can't predict with certainty the pace of development and construction in other industries, we are confident in our ability to contribute to a reliable and economical energy framework as we continue to build out through the end of the decade.

I would like to add one more point, Jake, as we wrap up this topic. When examining the supply-demand aspect, in-ground storage has not significantly changed over the past decade. As we consider in-ground storage and the variability it may have, whether it's 2 to 3 Bcf or even 5, as Mark mentioned, it's challenging to envision how we can progress in the Lower 48 without electrifying our operations further. This will necessitate infrastructure, including pipes and wires, to deliver low-cost, reliable, clean energy to power our activities. The situation becomes complicated if we aim to meet the supply demands without additional pipeline infrastructure and electrical wiring to support energy delivery to underserved or critical markets. We believe that infrastructure will play a crucial role in this scenario.

I appreciate the insights. I understand you want to wrap up this topic, but I have one more question. As infrastructure developments take longer and permitting becomes more challenging, is there a stronger argument for being a multi-basin operator in the latter part of this decade to potentially benefit from the timing of onshoring or the establishment of data center facilities?

That's a great question. I think it's important to take a step back and consider that the power demand and manufacturing Mark mentioned will be regional for our assets. A year ago, we might have focused on the benefits of multi-basin exposure related to LNG. However, we don’t believe that is necessary for us now. We have the resources to achieve consistent results with our two LNG-type outlets. As the demand for data centers continues to grow, we believe it will be more beneficial for producers like us in the Appalachian region. This reinforces our plans to develop the Marcellus, and in the coming decades, we’ll also focus on the Utica and Upper Devonian formations. Overall, this positions us well without needing exposure to other basins.

Yes, I'll join in on that. I would say that Range effectively is economically is a multi-basin company. Ninety percent 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 TILs back. I mean normally Range sees kind of higher production in the second half. But maybe this is not happening, maybe a 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?

Absolutely, great question, Leo. This year should feel quite similar to previous years under our maintenance profile. However, there are a couple of differences that you might notice when looking at the numbers from quarter to quarter. We've discussed this in some one-on-one conversations. Long lateral development has continued to progress for us, and we talked extensively about that last year. Our initial plan was for an average horizontal length of 10,000 feet, but by the end of the year, it was nearing 13,000 feet, which reduced our TIL count while still maintaining, if not slightly increasing, the in-line footage compared to the original plan. This influences the overall production shape and profile for the following program year. In Q4, we turned some of our long laterals into sales, showing not only strong well performance but also helping to keep parts of the gathering system well-utilized. To sum up, in previous years under maintenance, we typically experienced a dip in production from Q1 to Q2 followed by a stronger, more gradual increase in the second half of the year. However, this year, we might see that dip be less pronounced, resulting in a flatter trend during that Q1 to Q2 period.

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 one year, two 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 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 an 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, thank you for being on the call. Our approach to emissions management at Range remains unchanged, and we are following the same strategy that we established a few years ago. This time last year, we began transitioning to new facility installations by moving away from traditional pneumatic conveyors and adopting modern technology, including air conveyance and nitrogen use. Additionally, we have started a retrofit program to upgrade other sites as well. We are focusing on optimizing field run time to ensure the best design supports our economic and operational goals. While I shared those examples, I want to emphasize that we have not altered our commitment in this area. Last year, we achieved MIQ certification and maintained our LDAR program at eight inspections per year, ensuring a robust leak detection process. We're also testing a top-down survey approach and analyzing the data to see how it complements our ground-level inspections. Overall, Range is committed to further reducing emissions in a responsible and economically viable manner.

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.

Thank you for your participation in today's conference. You may now disconnect.