Range Resources Corporation (NYSE:RRC) Q2 2024 Earnings Call Transcript

Range Resources Corporation (NYSE:RRC) Q2 2024 Earnings Call Transcript July 24, 2024

Operator: Welcome to the Range Resources Second Quarter 2024 Earnings Conference Call. [Operator Instructions] Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker’s remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Laith Sando, 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 Second 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. Range’s Second Quarter plan was executed successfully and consistent with our strategy for the year, which remains unchanged, 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 second quarter results reflect the ongoing advancement of these objectives and demonstrate the resilience of Range’s business through cycles. Our operational and financial updates highlight Range’s high quality, low breakeven inventory and liquids optionality, which drove another successful quarter while generating free cash flow.

Our low capital intensity continues to be on display in quarters like Q2 and 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 through our diverse transportation portfolio. Bolstering Range’s profitability and durability is our liquids contribution. As seen in the Second Quarter results, liquids revenue provided an uplift to natural gas prices. With NGL price realizations providing a substantial premium relative to Henry Hub natural gas.

When we roll all of that together, our liquids revenue uplift our low capital intensity. Along with a thoughtful rightsized hedging program, you get a unique story, generating the lowest breakeven among natural gas producers and the most resilient organic free cash flow as evidenced by our second 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. As we look back on the second quarter, all-in capital came in at $175 million, with a total capital for the first half of the year totaling $345 million. Capital spend for the quarter reflected our base level of activity along with a spot rig and frac crew we had in early 2024.

For the remainder of the year, we will be running 2 dedicated horizontal rigs and single base frac crew, which will generate our planned $30 million to $45 million of in-process well inventory, very similar to what Range did last year. Also consistent with prior years, we will see capital spending decrease across the second half of the year, while production is set to modestly increase aligning with expected improvements in natural gas prices heading into 2025. Production for the second quarter came in at 2.15 Bcf equivalent per day, driven by continued strong well performance from long laterals and ongoing optimization of gathering systems that enhance performance. Range’s second quarter liquids were approximately 30% of production, slightly lower versus Q1 as a result of a propane cargo that was delayed into early July.

Liquids production is back up to 32% today, near recent highs, reflecting our increased focus on liquids-rich activity in the first half of the year. We turned to sale of 17 wells across our wet and super-rich acreage, but 7 of these wells on pads with existing production. As we’ve discussed for years, returning to existing pads is a durable, repeatable part of our program. Returning to pads allows us to minimize our operating surface footprint, and reutilize existing infrastructure while also supporting efficient, nimble operations. Combined, this results in a normalized well cost per foot for Range that is differentiated versus peers. Year-to-date, well performance and production has also been strong, aided by gathering system optimization efforts that have included compression expansions in Southwest PA.

These type of expansions are a normal course of business as the team continually works to optimize field level performance and support production from our long lateral development. Production for the second half of the year is expected to be approximately 2.2 Bcf equivalent per day, placing us near the high end of our previously communicated production guidance. Turning to operations. Drilling activity during the quarter added 10 laterals with an average horizontal length of just over 14,300 feet per well, but several over 15,000 feet. And we have now drilled nearly 90 wells in the program’s history with lateral lengths greater than 15,000 feet. For completions, the team continued to successfully operate with the new build electric frac fleet that was onboarded at the start of the year.

We saw continued strong performance from the equipment and personnel across 3 different pads in the second quarter. Frac efficiencies finished at just over 9 stages per day while completing approximately 800 stages for the quarter, showcasing the consistent repeatable nature of our program and placing us on track for the activity plans we’ve communicated for the year. Supporting our frac efficiencies is Range’s water sharing program, which contributed approximately $1 million in cost savings above levels a year ago. Looking forward, we believe we will see similar savings from third-party water utilization given our blocky acreage position and existing water infrastructure. Cash lease operating expenses finished the quarter better than anticipated at $0.11 per Mcfe shaped by strong well performance from optimized gathering and efficient water logistics.

As we look forward to the second half of the year, we project a similar level of expense performance, and are, therefore, improving our previous guidance for lease operating expenses down to $0.11 to $0.13 per Mcfe. Turning to marketing and starting with NGLs. Range’s flexible transportation portfolio continued to access premium export markets during Q2. As one of the only U.S. producers with access to international LPG upside, we generated another fantastic quarter in terms of Range NGL price realizations. Looking at the NGL macro, international propane demand continues to grow. Chinese propane imports reached an all-time high in the second quarter as they continue to add PDH capacity to consume more propane. At the same time, limited growth in non-U.S. propane supply has led to tightened international fundamentals and an improved arb for U.S. exporters.

Range’s flexible marketing and transportation portfolio allowed us to take advantage of this international opportunity, exporting the vast majority of propane produced during the second quarter. Simultaneously, Range demonstrated its ability to optimize sales by pivoting butane volume into the domestic market to maximize margins. As a result, Range NGLs received $24.35 per barrel in the second quarter, $1.26 per barrel premium to the Mont Belvieu equivalent. Looking ahead to the balance of 2024 and into early 2025, we expect domestic stock tightening to combine with export demand to support absolute and relative NGL pricing and we expect Range’s NGL price realizations will remain a positive differentiator. On the natural gas side, Range’s pricing relative to NYMEX was right in line with our expectation as we sold the vast majority of our gas into the Midwest and Gulf Coast regions.

On the macro front, we have seen U.S. natural gas production declining year-over-year, driven by maintenance or lower activity levels from industry, alongside durable demand for natural gas that can be observed in areas such as LNG exports and increased gas power burden. So we believe the fundamentals continue to be in place for improving natural gas pricing going forward. Before handing it over to Mark, I wanted to quickly touch on our most recent corporate sustainability report that was published last week. This report continues to showcase the company’s resilience as a safe low-cost natural gas producer with an enviable emissions profile. Range had a great year for safety with 0 employee incidents for the year. Range also continued its strong environmental performance, driving a 67% reduction in methane emissions intensity over the past 5 years, reaching just under 0.2% and or more than 90% below the EPA’s methane fee threshold.

We look forward to discussing these and other results during future meetings. So where does that leave us as we’re more than halfway through 2024? As stated, we remain constructive on the outlook for natural gas and NGLs, but importantly, even in the presence of relatively high natural gas storage levels and the current commodity backdrop. The resilience of Range’s business is on full display. Our ability to generate free cash flow through the cycles 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 remain strong and we believe Range is positioned well to generate substantial value for shareholders in the years ahead.

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

Mark Scucchi: Thanks, Dennis. With the first half of 2024 behind us, Range is making steady progress, executing a disciplined investment program prudent for this year and forward thinking for next year. Range’s most fundamental objective is to safely and consistently generate cash flow for its stakeholders. Our program for 2024 was designed to successfully navigate fluctuating commodity prices while continuing to generate free cash flow, pay dividends, buy back shares and repurchase debt. While investing in the long-term development of our high-quality assets. As mentioned during our last call, Range has an efficient plan to maintain steady production this year with the flexibility to 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 further downstream, Range has the cost structure, inventory and infrastructure to remain a reliable long-term energy supplier. Results of the second quarter continue to highlight the business strength generated by Range’s production mix and transportation portfolio. Realized price per unit of production before NYMEX hedging was $0.51 above NYMEX Henry Hub prices is a byproduct of our diversified mix and production and sales outlooks. Including hedges, Range realized $3.10 per Mcfe or $1.22 above NYMEX Henry Hub prices. Resilient pricing yielded second quarter cash margins per unit of production of $1.22, a healthy 37% margin, resulting in cash flow before working capital of approximately $237 million.

Cash flow for the quarter was allocated to $175 million in capital investments. The repurchase of $48 million in senior notes, along with roughly $19 million in dividends and $20 million in common shares repurchased. Cash margins were generated by diverse sales and a rightsized hedging program, but also by continued deliberate focus on unit costs. During the second quarter, total cash unit costs were $1.88, down $0.07 from the first quarter, decreases in interest expense and G&A are a byproduct of reduced debt and thoughtful spending. Gathering, processing and transport for the second quarter declined $0.05 from last quarter and is a function of prevailing commodity prices and timing of NGL cargos. Second quarter NGL market prices declined, reducing processing costs and with lower natural gas prices, we also experienced lower fuel and electricity costs, all right way risk contract elements that maintain margins.

Range’s NGL sales benefit from direct access to international markets out of the East Coast. One cargo loading occurred in the first days of July. As such, the volumes to be loaded were inventory at quarter end with the GP&T costs and revenues being recognized in July, which should bring third quarter GP&T back towards the midpoint of guidance. Right after safety and sound environmental practices capital allocation is among the most important corporate responsibilities. As you can see during the second quarter, we continue to carefully balance funding of prudent investments in the business with returns of capital, while maintaining financial strength. Prudent investment to us is responsive to both the near-term realities of commodity prices while also investing in the future to be prepared for the approaching growth in natural gas demand.

With low full cycle costs, Range has been able to generate free cash flow while investing in modest inventory to enable efficient growth when the market calls for it. At the same time, we prioritize financial strength so that we can make opportunistic decisions. That financial strength enables Range to execute what has been a very efficient share repurchase program. And it’s a program we have greater flexibility to execute as we remain within our target debt levels. Looking at the balance sheet briefly. The notes due 2025 mature in less than 1 year. Those notes are easily covered by cash on hand, cash to be generated in coming quarters and an undrawn revolving credit facility. Suffice it to say that we believe there is ample liquidity to efficiently retire this debt as the maturity date approaches.

With the ratings upgrade from S&P this quarter and a positive outlook for Moody’s, we believe the strength of Range’s business is being recognized. One significant element of our financial strategy that provides a stabilizing effect to better enable efficient funding and investments is our thoughtfully constructed and carefully executed hedging program. We believe added predictability from appropriately sized hedging provides exposure to improve long-term natural gas market dynamics while also increasing confidence in near-term forecasted cash flow. A stable financial foundation enables better planned, more consistent, efficient operations while protecting the balance sheet and can also create opportunities for reinvestment and shareholder returns.

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 second half 2024 natural gas hedged with an average floor price of $3.70. And in 2025, approximately 35% hedged with an average floor price of $3.90, providing Range a stable base to consistently generate free cash flow through market cycles. 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 most others in the industry. And at our capital efficiency, low full cycle cost, 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 can provide durable cost reductions or low-cost lateral extending inventory enhancing land, among other attractive alternatives.

When comparing capital efficiency on a per unit of production basis or any similar metric, a year of depleting inventory can enhance optics in the short run for some. We believe lasting efficiency, particularly in the face of expected growing demand provides Range shareholders greater leverage to improving markets. Range’s business plan continues to be executed on what we believe is the largest per share exposure to core Appalachia inventory, paired with the 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.

Dennis Degner: Thanks, Mark. The first half of the year results for Range reflect a consistent theme communicated in past quarters. Execution of another maintenance plus operational program as planned. consistent advancement in our overall efficiencies, generating free cash flow and prudent allocation of that cash flow, balancing returns of capital, further balance sheet improvements and the optimal development of our world-class asset base. 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 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 up the line for questions.

Q&A Session

Operator: [Operator Instructions] The first question is from Roger Read of Wells Fargo.

Roger Read: Congratulations on the quarter. Mark, I’d like to come back on some stuff you were saying there at the very end. Some of the opportunities you listed to, let’s call it, enhanced margins, improved returns, et cetera. If we were to think about those in terms of magnitude of what they can do for you, but also sort of the time line of achievability. How would that list of opportunities shake out?

Mark Scucchi: Yes. It’s a good question, and it’s a broad question just because of the breadth of opportunity Range has ahead of it. I think Dennis and I both have touched on various ways in which we can continue to drive down our cash unit cost structure as well as the capital efficiency. You’ve seen the team be very efficient on direct operating costs, LOE continued mindful execution out in the field. Water handling is a topic we consistently discussed, which touches on both improvements in LOE and our capital efficiency. So that’s a day-to-day exercise by the team in the field, but it’s also some modest capital investments. As you know, that was part of our capital allocation process for this year. Something we hadn’t done in any size or consequence for roughly a decade.

That blocked-up nature of our acreage position is really a lot of efficient handling and use of that infrastructure and expanding that this year became timely, and with — what we expect to be about a 1 year or better payback on that investment, it should pay back many years into the future. As you work your way down, the cost structure, I think, GP&T being a larger line item, it’s clearly an area of focus. That’s a focus for cost, but I think more importantly, it’s about margins. It’s about maintaining and enhancing that portfolio of sales outlets we have. So today, it’s a great outlet moving 80% of our gas out of the basin. But over time, we think that Range will continue to have the opportunity to sell its molecules into strong end markets, be it today with our existing production profile or when the market calls for it, and there’s incremental production.

We think that we will have the ability to move those molecules to strong end markets as well, be it natural gas or natural gas liquids. And then on the capital front, again, the common topics that come to mind are extending lateral lengths, which again, you’ve seen us allocate a little bit of capital to the land to be able to do that as well as just efficiently running crews this year, running 2 rigs and 1 frac crew, for example, is all it takes a Range to execute this program this year, the steady efficient maintenance program and potentially running those for a full 12 months to generate very modest growth into next year, given the inventory that we’ve built up over the last few years. So all those factors together plan to not just one specific area of improvement, but whittling down across the cost structure and the capital efficiency.

Roger Read: No, I appreciate that clarification. And then the other question I had more sort of what is the tripwire or whatever. But as you think about setting up your hedging for 2025, I mean, obviously, you’re 35% there. But if we think about getting kind of equivalent to this year, is there — is that something that’s going to be episodic? Or is there a price level you’d feel more comfortable with? Or as you think about the macro potentially 25 and a little better supply-demand balance across the country do you want to be more patient on hedging? How are you thinking about that?

Mark Scucchi: Yes, I’ll start with we feel very good about where the 2025 book stands today. Just backing up to the philosophy, we’re running an enterprise a going concern, 30-plus years of drilling inventory. So this is about managing risk in the business prudently while not hedging away the upside in the cash flow. So to that end, the philosophy is to try to cover the fixed cost to maintain steady operations, picking up and dropping crews and things is extremely inefficient and costly. So having more stable predictability of that cash flow, we think, adds a lot of value. So with that in mind, how do you shape 2025. Well, we feel like the book was designed to do that at the prices we were able to lock in. It’s also shaped based on the fundamentals as we see them unfolding over the next 12 and 18 months.

LNG in service is clearly a focus in the headlines. Some facilities are early and some facilities may be delayed. So as we see those opportunities becoming reality late this year and early next year, the incremental positions that were added are really front-end loaded the first half of 2025 and they’re in the form of collars, so that we can provide some downside protection while retaining positive exposure to improved gas prices in the first half of the year. So that’s really how we think about next year.

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

Michael Scialla: Dennis and Mark, you both mentioned you see the improving natural gas fundamentals moving forward and your ’24 production guidance is moving to the high end of the Range. If that doesn’t play out, just curious what changed to your plans, you’re contemplating? Or do you feel like with the natural gas liquids revenues that you’re really not the company that would need to adjust your plans, be it curtailing production or delaying any more turn-in lines?

Dennis Degner: Michael, I’ll start by really maybe reiterating a bit of the approach that we communicated for this year’s program. And we’re at a very lean what we would call base level type activity level and program for ’24, which we think is kind of a base level way of thinking about the business on the go-forward there or what we’ll call it somewhat maintenance plus. So the 2 rigs flat plus the 1 base frac crew. And so it’s generating that $35 million to — $30 million to $45 million of in-process inventory this year, very similar to last year. And so to answer your question, as we start to think about 2025, we wanted to set ourselves up with flexibility and really good options. And so by setting it up that way, we have the ability to take some of that inventory and reshape our production profile for 2025.

And ultimately, we know that will have an impact for ’26 in the go forward. But if we also see further delays in LNG facilities or anything else that puts commodities at risk, we could consider how to use that inventory differently. But I think when we look at the capital program for this year, at that $620 million to $670 million level, I mean, clearly, there are going to be some aspects like the water infrastructure that Mark touched on just a few moments ago that are going to be more onetime one-off capital investments in nature once a decade, if you will. But really, that’s a decent way of thinking about our program and then the ability to toggle and use that inventory based upon what we see from a commodity standpoint. There’s a lot of reasons to believe that this is going to look better, I think, in 2025, though.

There’s too many demand components that you can point to. And I think power is clearly one of them. And even when you just look at the incremental $1.5 billion a day on the power burn side that’s played into natural gas’s contribution just year-to-date. And so we think there’s a lot of reasons to be excited about 2025. We’ve got the right inventory set up and program that’s lean to allow us to reshape production in ’25 based upon what we see from the market.

Michael Scialla: Appreciate that. Just want to get your thoughts on kind of political front with the federal judge blocking the pause on LNG facilities and it bring court to return the Chevron doctrine. Does that make you any more optimistic on the regulatory environment? Anything specific you might think could be done within Appalachia that would improve maybe take away capacity or anything along those lines?

Dennis Degner: Well, I think when you look at the demand component, I’ll maybe start with the way we ended maybe the prior question. But I think when you look at all the variables that are playing into the demand conversation on the go forward, we’ve said and maybe in smaller group meetings, it’s hard to see how you — when you think about the political avenue, you almost feel like you get to the same place, maybe through a different path with regardless of what happens with the administration here and the go forward, meaning if you’re going to further bolster the grid, electrify what we do here in the Lower 48, if you’re talking about data centers and AI, you have to see natural gas playing a more prominent role in that conversation for low-cost, reliable power generation.

So when we look at — and that then follows with a real serious conversation about permit reform. So I think it was encouraging to see just within the last day or 2 here, the announcement from Senator Manchin and Barrasso over some permit reform language that’s being moved forward. And we think those are the right signals. So we would look at that as there are others, clearly, both in D.C. and also on the home front here like companies like Range that see that there’s a real need for us to play an expanded role. When you look at our inventory, we have the ability to do that, especially with our asset base, having the ability to feed supply gas into the PJM market, which serves of around 65 million people. So we see a lot of positive outlook, but it’s going to really need to be supported by some permit reform for sure.

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

Doug Leggate: So I guess, Mark, my first question might be for you or whoever wants to take this, it’s relating to takeaway capacity. Our understanding is that both some of the publics and the privates are not renewing term takeaway or fixed takeaway, as things kind of roll around for renewal and I’m wondering how that opportunity sits for a company like yourself, given your inventory depth and why you think that might be the case? In other words, why those folks are not taking the takeaway. Any kind of magnitude you can offer on timing would be really helpful. And I’ve got a follow-up, please.

Mark Scucchi: Doug, that’s a good question because the most common understanding, which is accurate, is that in aggregate, the pipeline is coming out of Appalachia or [indiscernible]. We’re focused on what Range can access and over time, what Range can utilize. So today, we have a great portfolio, but we think there’s a lot of opportunities for Range to use even existing capacity coming out of the basin even before we think about what eventually will be Brownfield expansions and eventually even perhaps some new pipelines. But just to start out, there’s capacity that’s either underutilized, was not signed up for firm transport, so it’s just used on shorter-term nature. There’s capacity that some companies did sign up under firm and through various proceedings to projected those contracts or remarketed them and lay it off.

So the pipeline exists. So it really comes down to a market share question. And then that leads you down the road of who has the inventory to use it for the next 5, 10, 15-plus years, to be able to stand behind it to underwrite that capacity and fully use it for an extended term. So that’s clearly an opportunity for Range at the appropriate time to grow and utilize capacity. It’s not only a question of what capacity Range has to take on or chooses to take on itself, but our end customers have their own capacity. So you can sell 2 end markets anywhere across Lower 48 essentially, to those customers that have their own, be it utilities or marketers or you name it. So MVP, while we don’t have capacity on it, holders of MVP capacity, a number of them are existing customers via other paths, so we can expand those relationships and sell to them.

And like I said, eventually, to Dennis’ point earlier, the simple needs of the population of industry, of reindustrialization in the Lower 48 increased power demand, electrification across industries, there’s going to have to be expansions, both on the electric side, whether you’re talking distribution, power generation and pipelines to get there. So Brownfield expansion is potentially a new pipeline at some point. And then bringing it closer to home for Range, the in-basin and near basin as we term it sometimes is significant demand, again, to the power side of the equation or industrial that represents a tremendous opportunity, even leveraging our existing portfolio where 1/3 of our gas goes to the Midwest, for example, to areas where there’s significant construction of industrial demand and plans of various types in nearby states.

So great opportunity here, really underpinned by inventory and duration of Range’s story.

Doug Leggate: Mark, forgive me for asking for a quick clarification. This is not my second question, but can you offer any kind of magnitude and timing is a very quick, here’s the number, here’s the timing, how it impacts Range.

Mark Scucchi: I think perhaps it’s a little bit early as we get a little closer to 2025 and think about and refine what that capital budget may look like. As we’ve said, growth is an option. It’s a question of when, not if. So coordinating infrastructure, be it gathering, processing, compression and longer-term transport layered in with the marketing to the end customers and those relationships is all part of the process.

Doug Leggate: Okay. My follow-up is really a balance sheet debt question. You’ve obviously done a tremendous job rightsizing the balance sheet. But I think the one certainty that we can see with the forward curve and the demand supply situation for gas is significantly higher volatility, which means breakeven and balance sheet capital structure becomes a big part of your equity volatility. So my question is, you have a couple of fairly sizable bond maturities over the next 3 to 5 years. Will you refinance those? Or will you pay them down? How do you see the right capital structure in an extraordinarily volatile environment for Range?

Mark Scucchi: Well, I’ll start with the target debt range is net debt of $1 billion to $1.5 billion, which we are within, giving us a lot of options, both in returns of capital and further deleveraging. So we certainly plan to stay within that and optimize the balance sheet to your point, it reduces cost of capital, hopefully brings out some of the risking, if you will and brings out some of the volatility. So to that point, the ’25, as I mentioned during the opening comments, we’ve got ample liquidity to take care of those. We have the revolver, lots of cash on the balance sheet and cash flow to be generated in the coming quarters further deleveraging is likely. We’ll balance that with returns of capital. And capital markets are open as well.

So there’s clearly options there as we roll forward through the next few quarters. There is a step down in the call price on the 2029, the 8.25% notes early next year. So that presents a possible time to consider after that passes of what a refinancing might look like. So at the highest level, I’ll say, fortunately, we have a lot of good options ahead of us to optimize the balance sheet further deleverage while also achieving our return of capital objectives.

Operator: Our next question comes from Jake Roberts of TPH & Company.

Jake Roberts: I was curious on the — getting some more granularity on the TIL cadence in the second quarter and being aware of that the current mix is at 32%. But just wondering if that liquids weighting is going to push that number higher in Q3? And then ultimately, what it may shake out in Q4 with the dry well line, just to get to that more than 30% for the year.

Dennis Degner: If I take a step back, the way we’re looking at our turn-in-line cadence for the year, I mean right now, we’re approximately 50% of our turn-in-lines having been sent to the sales line. But over the bulk of those clearly we’re in Q2. By nature, that’s going to then carry a lot of weight as you start to think about that modest, but ratable production increase that we’ll see between Q3 and Q4, very much similar to the profiles that we’ve seen over the last several years, because the turn-in-lines have all been 100% on the wet side, and a lot of that is going to also be consistent in Q3 as well, we would expect to see a similar liquids contribution in percentage weighting factor in the back half of the year to what we’ve seen here through the first half as well.

The dry gas TILs, clearly, we’re still keeping those, we’ll say, under evaluation. When you look at how the gathering system has really performed with some of the optimization efforts that have been ongoing over the last 6 to 9 months, we’re — it’s still a little early, but we’re really seeing that pay dividends in a way where it’s allowing us to think in a very flexible way about how deep into the year do we want to push those dry gas TILs. So ultimately between the flexibility there, the way the liquids turn-in-line cadence is shaping up and on top of it, just the production profile and the base decline being low, we’re really seeing that we should have a consistent liquids contribution through the balance of the year.

Jake Roberts: Okay. And then my second question, I know you spoke earlier about some of the flexibility as we look at 2025, particularly around natural gas pricing, but I’m wondering if the forecasted tightness in the export — LPG export capacity in 2025 is also factoring into that conversation and how we should we might think about that side of the program? And then I’m also curious if you could offer any thoughts on the potential for that export capacity utilization to remain closer to 100% following the additional capacity in late 2025 and 2026.

Dennis Degner: Yes. I think the export utilization has been really a great story in a lot of ways for the past probably 12 months plus now. But you’re spot on. I mean we consistently see that it’s running in the high 80%, almost bumping 90% range on a — we’ll just say a month in and month out basis out of the Gulf. For us, it really presents a unique advantage, and we’ve said this a number of times, but our ability to get our products to the water and not only to the water, but also in Philadelphia out of the Northeast has really proven to be a differentiator for us. And so when you start to think about the go forward, we would expect to see some ongoing congestion from time to time in the Gulf and as that continues to persist and raise its head, our relative value that we harvest by getting out versus Mont Belvieu will continue to really shine for us in the go forward.

So you’re right, that export capacity in ’25 and beyond is going to continue to grow. But when you start to think about the demand component and the supply that probably follows with that out of other basins in the South, Again, we expect to see our relative value versus Mont Belvieu to continue to shine on the go forward, being able to get our products to the water in the Northeast.

Operator: Our next question comes from Scott Hanold of RBC.

Scott Hanold: Just out of curiosity, you all talk about obviously delivering your maintenance kind of plus activity level and building a little bit of a optional DUC backlog. Can you give some color around when you look at that, are you doing it more for gas C-type wells? Or is there really an opportunity also, given your constructive liquids outlook to build that more as a liquids-oriented backlog that gives you some better pricing optionality.

Dennis Degner: Yes. Scott, I think the best way to think about our inventory and the way that we’ll just say what that looks like, it will mirror a lot of what you see in our activity base on a program year kind of year in and year out. But by nature, it’s inherently going to lean more toward the liquids-rich side of our asset base. Program year in and year out, we run around 65% to 70% on the liquid side. So between our wet and super-rich inventory. And then the other, we’ll just say 30% is going to be more on the dry side. So I would expect on the go forward when we build some inventory, it’s primarily going to be leaning towards the liquid side. Inherently, by the way, we shape our program where our inventory lies, where we see infrastructure capacity as well, but we always leave some flexibility in how we look at our inventory and what we — where we drill and based upon what we’re seeing going on in the market.

And our ability, I know we touch on this a lot, but it’s a real differentiator for us. But our ability to move back to pads with existing production allows us to just really be nimble and be able to react to what we’re seeing and what we think is going to be most helpful for the go forward. So inventory balance and mix should look real similar to the rest of the program, but it will lean towards the liquid side.

Scott Hanold: So when I think about that, should I — when you think about like executing potential growth when it makes sense, is that more of — well, as much as improving dry gas prices, but also whether there’s NGL — just export capacity as well? Is that — is it sort of a balance of that?

Dennis Degner: I think it’s in all of the above. And clearly, when you look at the realization uplift that comes with our NGL contribution, inherently, we’re going to lean toward over the course of time, just like you’re seeing in the balance of this year, I would expect to see a small improvement in our liquids contribution just over the course of time. So it could be a small number, but it’s going to be inherently because of the way our inventory is laid out, I would expect to see that to be a small improving percentage factor over the course of time. And going into that is our ability to get to the water. Again, what we see that’s going on with the global markets and our ability to take advantage of that revenue uplift and how it impacts our free cash flow.

Scott Hanold: Okay. That’s clear. And then my follow-up is probably for Mark. You obviously hit the buybacks on both the debt as well as the equity, can you give us some sense of like how do you think about the balance in doing that? Like what makes most sense to create incremental shareholder value at this point? Is it the debt or is it the buybacks? Or is it a combination? Just give us a sense of how you think about that.

Mark Scucchi: Yes, it’s a fair question, and we’ve shied away from giving a purely formulaic approach to it because commodity prices change, cost of the field may change, demands may change and that growth is a question again of when. So First and foremost, our job is to have safe, efficient operations and provide energy, natural gas and natural gas liquids to our customers and sell this profitably. So that’s the first thing. Underpinning that is the strong balance sheet, which we’re there within our target range. So from here forward, we like the optionality of leaning in one direction or another. So I’ll just leave it as the balance sheet is within the target and continues to get stronger, we can kind of turn that restate up or down on the returns of capital as we see appropriate to provide the greatest returns, the strongest driver of free cash flow and cash flow per share over time.

So I can’t give you a specific number. We prefer the flexibility in executing the programs. But suffice it to say that our behavior will not be that dissimilar from what you’ve seen from us over the last few years. One year, we bought back $400 million in shares. Commodity prices came in, and we became a little bit more conservative. So we’re just responsive to cash flow, prices and changes in relative value over it. But again, I’ll just leave it with the punchline of as we stay within and move further into our target debt range, we’ve got greater flexibility.

Operator: Our next question comes from Neil Mehta of Goldman Sachs.

Neil Mehta: I had a couple of questions on NGL macro, but also your price realization. So the first question on Slide 35, your price calculation. You guys have done a great job realizing above the equivalent Mont Belvieu barrel, just be your perspective on how do you continue to get towards the top end of the $0.75 to $1.50? What are the headwinds? What are the tailwinds? And what are you doing to get the best netback.

Alan Engberg: Neil, this is Alan Engberg. I managed a marketing program at Range. So I’ll take a stab at answering your question. We — it’s not all that magical. A lot of what we do is we’ve got diversity in the portfolio, and we’ve managed to set up the portfolio such that we’re not overly exposed to Mont Belvieu. In fact, we’ve weighted a lot of it, whether it’s ethane, propane or butane towards international markets where we saw significant growth. So going forward, I think the macro looks really good still internationally. We’ve got tremendous growth in ethane demand, particularly out of Asia, but also out of Europe. Ethane going into ethylene steam crackers. Most of them are seeing that if they’re operating using feed other than ethane, they’re disadvantaged.

So they’re shifting a lot of their feed capacity towards ethane and that is creating just continued ethane demand growth. So we feel that for our contracts that are priced internationally on ethane, given that demand growth, we’re just going to continue to see good realization relative to the domestic benchmarks. Similarly, on LPG, you’ve heard the story, I’m sure quite a bit about just PDH growth, particularly in Asia, and that is still continuing to go on. We’re operating at relatively low capacity utilization internationally, which some people view as a negative, but really, I view that as a positive because as that capacity growth slows down, we’re going to start getting a tighter market and the capacity utilization is actually going to be increasing.

So we’re going to see a runway of continued demand growth for multiple years on the international front for LPG. We’ve got exposure to that currently. And it’s worked out really well, again, for Range, relative to the domestic market indices. So going forward, we like our position. We’re very happy to have an 80% of our portfolio on the LPG side capable of into the export market, but also being a very flexible portfolio that allows us to pivot when the time is right or when the seasonality is right between domestic and export markets.

Neil Mehta: Yes. That kind of builds into the follow-up, which is Slide 24. We share your constructive NGL view, but we get a lot of pushback on the propane side, particularly on China, given the challenge of the economy out there. So I’d love your perspective real time of what you’re seeing on the ground in Asia from a demand perspective? And can propane perform in the face of what seems to be a soft Eastern demand picture.

Alan Engberg: Well, so I agree with you, everything we’re reading as far as the economy in China has been less than stellar. But it’s still — it’s massive, right? And the demand growth has still been there. In fact, I think Dennis referenced it in his remarks, his prepared remarks that during the second quarter, we actually hit the U.S. that is hit another record in terms of exports to China. We — I’m trying to see what that number was. I don’t have it in front of me, but suffice it to say, the — here it is, 843,000 barrels per day is what China imported during the second quarter from propane standpoint. So it’s been massive. The operating rates that I was talking about for the PDH units despite the economy not really performing as strongly as a lot of people were hoping it would, those operating rates have actually increased.

During the second quarter, we got into the mid-70% utilization rate. And again, that’s against a weak economic backdrop. So the feeling is once — if the economy starts improving and the government is making efforts to stimulate the economy. Once that happens, those utilization rates are going to continue to grow, and that demand will continue to grow as well. And then I’ll add further that international supply of LPG has actually been relatively flat. OPEC actually during the second quarter was down 8% year-on-year from an export standpoint. So it just emphasizes that the U.S. is the source of supply into that demand. And that demand from our standpoint, continues to look quite strong.

Operator: Our next question comes from Arun Jayaram of JPMorgan.

Arun Jayaram: I wanted to ask you around just how you’re thinking about kind of 2025. I know you touched on this earlier in the call. So in the — going into 2024, you had about $30 million of capital that you used kind of to build some well inventory. And then this year, I think the number is $45 million. So you have about $75 million of capital, which is call it in well inventory. As you look at the macro picture today, is the plan to maybe move to a maintenance CapEx and to deliver a lower CapEx number for 2025 or with the strip, call it, around $340 million would you plan to maybe grow a little bit given your attractive returns at those types of gas prices?

Dennis Degner: Yes. I think when we start to think about the 2025 program, I mean, I think where we see today, we wanted to set up the flexible options so that we have the ability to reshape our production profile for the ’25 or we have the ability to stay at a maintenance plus level type activity until you get to the back of ’25 or into 2026. If you have a scenario this year, as an example, where you’re blowing down your inventory and you’re running a program that doesn’t set you up for flexibility. That presents a unique challenge then as you start to lean into the market improvements, whether it’s early ’25, middle of ’25 or if it’s leading into 2026. So we like the in-process inventory that’s been generated. It gives us that ability to either utilize it and think differently about our capital maybe on the low end or it allows us to then use that as a, we’ll say, again, keeping it at a maintained level?

Or do you grow that from there based upon what kind of rig and frac crew program we have. our lean 1 frac crew program, these 2 rigs really kick out just a little bit more inventory than the 1 frac crew consumes. And we feel like by the time you aggregate that impact, it has the ability to reshape the production for the first half of the year. If you think about our maintenance program in the last several years, we’ve always had — the production character has had a bit of a sign wave, where the back half of the year sees a modest, but ratable increase. And then when you get to the first half of that following year, you’re always going to see a bit of a dip until you then pick your activity and turn in lines back up from the early on half the year activity levels.

So we feel like we have the ability to reshape that and change the way we think about feeding into growing demand in the market and what it presents to us. So a little early for us to define exactly what that looks like, but we like the options that we have at our disposal and the ability to utilize that inventory to keep ourselves at also the leading edge of a capital-efficient program.

Arun Jayaram: Got it. And just my follow-up, Dennis, I was wondering if you could highlight where you think your leading-edge D&C cost per foot are in Appalachia, maybe relative to your initial guide, and you highlighted averaging 9 stages per day, which is a very, very efficient kind of frontier there. And maybe comment on some of the efficiency gains you’re seeing from the zoos fleet? And how much do you see is there to go on the drilling versus the completion efficiency side of the equation?

Dennis Degner: Yes, a really good question. When we look at our drilling performance, the drilling team has done a fantastic job. Last year, we saw a little over a 40% improvement in our drilling efficiencies through basically utilization of some upgrades on our super-spec drilling rigs, there were some testing that we did last year. And there’s always a, we’ll just say, an ongoing testing type nature to the program, very KPI-driven and looking back on performance. And so that’s translated into an ongoing efficiency that we’re seeing this year as well. So very consistent from year-to-year. The frac side on completions, the team continues to see improvements when we return to pads with existing production. I think we touched on it a few months ago.

But ultimately, when we return to a pad with existing production we see that it could be as much as a 30% improvement in efficiencies. You route out nonproductive time, you look for ways to more efficiently manage ingress, egress, et cetera. And it all translates into the numbers that you’re seeing. So the zoos fleet has really performed well for us. And I would say, it’s as good or better than where we’ve been in the past few years. So hard to imagine, but in 2010, when I joined the organization, industry standard was around 3 stages a day for a 24-hour frac crew. And here we are doing 3x that amount and it’s just unbelievable. So hats off to everybody on the service side plus our team there in South Point. I think when you translate that into the cost per foot side, Arun, what you get is something that with current cost, you’re probably seeing somewhere in the $800 to $900 per foot range.

We have seen some deflation that’s helped along with the efficiencies that start to kind of materialize. But on a very limited basis, as you would imagine.

Operator: We’re nearing the end of today’s conference. We will go to Paul Diamond from Citi for a final question.

Paul Diamond: Just a quick one, kind of piggyback in a bit on the deflationary expectations into kind of the tail end of this year and into 2025. Just wondering if you could put a few numbers around how you’re seeing the market really playing out?

Dennis Degner: Yes. Paul, when I think about where we’re seeing deflation play out, it’s kind of a — it’s different than historically where maybe commodities up, service cost up, commodities down, service costs down. And what I mean by that is now you’re seeing in some regards, I’ll use the electric fleet as an example. E-fleets on the completion side are at 100% type utilization level across the Lower 48 and many of those are structured around multiyear contracts. And so on one hand, that may not present a significant deflation exposure. But in our case, what it does, it also has a natural protection against prices going up in ’25 and ’26 through the term of the contract when you could see activity levels go the other way.

Similar type storyline on some of our drilling rig exposures, where we are starting to see some opportunity is when you start to see relief in areas like oil prices, you start to see potential relief in diesel fuel, frac sand and some of your other consumables. It may not be — by the time you look at an individual line item, maybe they may not have a lot of, I’ll just say, a large impact. But in aggregate, it starts to become meaningful dollars. So it’s a little bit early. And I think part of we’ll just say deflationary savings that could transform or be a part of our program. We’re going to most likely be a part of our RFP process we roll out in the fall, and then that will translate into our D&C per foot for next year.

Paul Diamond: Understood. And just one more quick follow-up. You talked about your water sharing program and kind of it being a bit more of a longer-term opportunity set. Just wondering if you could put some numbers around that. I mean, how big do you see that opportunity set over in the medium and the longer term.

Dennis Degner: The water sharing program has been really a great story, and it all started with our team there in South Point and their creativity to reach out to other producers several years ago now and look for the ability to utilize their produced water as a part of our operations space. So it’s — we think across the board, it’s a win-win. Looking back, we’ve routinely now for several years, recycled approximately 140% to 150% of our annual produced water volumes. So it’s 100% of ours plus the remainder coming from other producers in the area. When you look at water costs and what that could translate into, and again, we’ve seen a range of somewhere plus or minus $10 million in potential savings on an annual basis because of the ability to take low-cost water.

And also, it really complements our environmental stewardship efforts that you’ll see in our CSR report kind of year after year. When you look at the investments that we’re making into our water infrastructure this year, that’s to support long-term, low capital efficiency and also that low water cost. So we think this is something that for decades to come, we can continue to repeat, and again, with our development runway with our inventory, it sets us up well to be able to capture those cost savings.

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 thank everyone for joining us on the call, as always, in the healthy Q&A. If you have any follow-up questions, don’t hesitate to reach out to our Investor Relations team, and we’ll see you on the next call in October. Thank you.

Operator: Thank you for your participation in today’s conference. You may disconnect.