Range Resources Corporation (NYSE:RRC) Q3 2023 Earnings Call Transcript

Range Resources Corporation (NYSE:RRC) Q3 2023 Earnings Call Transcript October 25, 2023

Operator: Welcome to the Range Resources Third Quarter 2023 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in forward-looking statements. After the speakers’ 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 third quarter 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 of those 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 reconciliation 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.

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Dennis Degner: Thanks, Laith, and thanks to all of you for joining the call today. As we finish out our 2023 program, Range’s business plan is on track and we’re making steady progress on the following key objectives we’ve shared with you throughout this year, operating safely while driving continued operational improvements, generating free cash flow through the cycles with a peer-leading full cycle cost structure, and prudent allocation of that free cash flow, balancing a strong balance sheet with returns of capital to shareholders, and the long-term development of our world-class asset base. I believe our most recent quarters are a great example of consistent advancement against these objectives, and the results reflect the resilience and durability of Range’s business.

During the third quarter, we successfully delivered on our operational plans safely with peer-leading efficiencies, and Range’s competitive cost structure, low capital intensity, liquids optionality, and thoughtful hedging, allowed us to generate at healthy full cycle margins despite a lower commodity price environment. These results are underpinned by Range’s multi-decade inventory and brought to fruition by a talented technical team that continues to innovate. Walking through some of our quarterly results. All-in capital for the third quarter came in at $151 million, with year-to-date capital spending totaling $478 million or approximately 80% of our annual plan. This front-loaded capital spending is right on track and follows the activity cadence we outlined earlier this year.

As previously discussed, we ran two frac crews for most of the third quarter, which aligns with our back halfway to turn-in line count and production trajectory. The second spot crew was released in early Q,4 and as of today, we’re back down to one dedicated horizontal rig and one dedicated frac crew as planned. Production for the quarter came in at 2.12 BCF equivalent per day, adding an average of approximately 40 million cubic feet equivalent per day versus the prior quarter, and placing us on track for a fourth quarter production increase that aligns favorably with the current shape of the forward commodity curve. Supporting our production profile, we turned to sales 19 wells during the third quarter. 13 of these wells are located in our dry acreage position, with the other six located in our wet and super rich acreage, all in southwest Pennsylvania.

As has become a hallmark of our operations, over three quarters of the wells are located on pads with existing production, minimizing our operating surface footprint, supporting nimble operations, and driving Range’s cost-efficient development approach and peer-leading capital efficiency. Looking at operations, just under 1,100 frac stages were completed on 18 wells during the quarter in southwest and northeast Pennsylvania. Demonstrating a continuation of our operational efficiencies, we averaged over nine frac stages per day for the quarter, representing a 17% increase versus the same time period in 2022. A second spot frac fleet was utilized during the quarter and completed a return trip to an existing producing pad in our northeastern Pennsylvania acreage, adding three new wells to the pad site.

Consistent with what we’ve seen this year in southwest PA, our completion metrics for this pad improved dramatically versus our initial development. This was accomplished through our continual learnings and improvements, which drive Range’s best practices in logistics planning, water operations optimization and service partner KPIs. Altogether, this resulted in an increased number of frac stages per day, a reduced cycle time to complete this pad site, and drove an 80% improvement in overall completion efficiency. Also, during the quarter, Range successfully completed two of the longest laterals in Range’ Marcellus program history, with both lateral lengths exceeding 21,000 feet. And when factoring in the total drilled footage from surface to the end of the lateral, the total distance succeeded five and a half miles per well.

As a result of the team’s success in increasing lateral lengths in the 2023 program, we’re able to complete this year’s program with fewer turn-in lines than originally planned. We still plan to turn to sales approximately 650,000 lateral feet. However, we’ll be doing this with 51 wells turned to sales or 16% fewer than what we had planned at the start of the year. This will drive a 4Q production increase of approximately 40 to 60 million cubic feet equivalent per day over the third quarter. And given the flatter production profile of these long laterals, it sets us up well heading into early 2024 and to what we expect will be improved pricing. I congratulate our team on this tremendous accomplishment as we continue to advance efficient long lateral development for Range’s assets.

Of course, record completion efficiencies aren’t possible without an integrated water operations and logistics group. In the third quarter, the team continued to build upon Range’s ongoing water recycling effort through strategic partnerships with other producers and third-party treating facilities, resulting in water savings of over $2.4 million in Q3. As mentioned earlier, the team operated in both our southwestern and northeastern PA acreage during the quarter. Even while concurrent operations were being performed over 200 miles apart, the team maximized efficiencies across these jobs to achieve our highest recorded water volume delivered in over five years by moving over 200,000 barrels of water on multiple days, while establishing a new Range record of handling over 800,000 barrels in four days.

This is an outstanding achievement. It demonstrates the team’s focus on peer-leading capital efficiency and supports our overall financial results that Mark will touch on in just a moment. Before moving back to marketing, I want to touch briefly on service cost. We recently launched our annual RFP process for services needed in 2024. The process is in the initial phases, but early indications suggest prices are softening for certain services and consumables versus the start of 2023. Most notably, we’ve seen a reduction in tubular goods pricing this year, and as a result, we’ve locked in steel pricing for our 2024 program at approximately a 30% discount to what we saw in 2023. For sand, we’ve seen similar signs of cost reduction and anticipate those savings could remain in place throughout 2024.

Other consumables like diesel fuel have moved higher and could remain elevated for next year. While we have a natural hedge against diesel prices with our condensate production, we’ve secured pricing for a portion of our 2024 development plan, further mitigating pricing risk. Similar to our 2023 development program, Range will continue to utilize a super-spec drilling rig and an electric frac fleet in 2024. Day rates for rigs in 2024 are showing signs of decline versus peak levels seen over the past 12 months, certainly influenced by the current US rig count, but super-spec rigs remain in high demand. Similarly, for completions, electric frac fleets are operating at a high level of utilization, resulting in comparable year-over-year pricing despite this year’s overall rig count reduction across the US.

To secure this portion of our program, Range has contracted and electric fleet for two years that is scheduled to commence operations on January 1st, 2024. In aggregate, we anticipate our RFP process will generate a modest year-over-year cost savings across various services. We’ll have the numbers formalized by year-end. And at the end of the day, we fully expect to remain at the leading edge of capital efficiency when compared to our peers and other basins. We look forward to sharing our 2024 plans with you on the next call. Turning to the NGL macro and pricing, the third quarter saw prices increase across the board for both NGLs and condensate. Overall, liquids pricing was supported by upward trending crude values, and lifted further by strengthening supply-demand fundamentals for NGLs, as these fundamentals strengthened on increased domestic demand and third quarter exports that were up 19% year-on-year, while LPG balances improved on stronger domestic propane demand, and exports that increased 16% versus the prior year’s quarter.

At the same time, third quarter global LPG balances tightened 14% year-on-year. As a result of improving NGL fundamentals, Range was able to realize $24.44 per barrel in the third quarter, a 14% increase over the prior quarter. This realized price represents a $0.63 per barrel uplift versus the Mont Belvieu Index, reflecting Range’s advantage portfolio of NGL contracts and access to international markets. And as a reminder, each $1 per barrel increase in Range’s NGL per barrel price represents $30 million in incremental cash flow generated. As we enter the winter months, we expect fundamentals to remain strong and our NGL price realizations to remain in the $1 minus to $1 per barrel premium for the fourth quarter, generating a strong premium to Mont Belvieu for the year.

On the natural gas front, incremental gas demand for power generation we touched on during the last quarter proved resilient in the months that followed as the summer expired. This incremental power demand, coupled with industrial demand growth, exports to Mexico, and continued LNG commissioning, sets the tone for the domestic natural gas market to gradually rebalance, particularly when considering the meaningful rig activity reductions we’ve seen in the Haynesville. To follow, we then see further strengthening with increased LNG exports next year and beyond. We are excited about the future of natural gas and NGLs, but regardless of the macro backdrop, the team remains focused on advancing our overall efficiencies, delivering repeatable well performance across our large contiguous inventory, while bolstering a strong balance sheet with returns of capital to shareholders.

These are the building blocks that underpin the resilience of Range’s business through the cycles, and I believe the positive results we’ve seen year-to-date are a reflection of that. I’ll now turn it over to Mark to discuss the financials.

Mark Scucchi: Thanks, Dennis. As we turn to the financial results, I think some context is helpful to frame upstream companies’ results in relation to the macroeconomic backdrop. During the first nine months of 2023, NYMEX natural gas prices averaged $2.71 per MCF compared to $6.77 for the same period of 2022. WTI oil prices were roughly $77 per barrel in the first nine months of 2023 compared to $98 in 2022. These price declines have led to a natural gas-focused rig count drop of 27% since April with new US natural gas production now stabilizing. The read-through is that prices experience year-to-date are below maintenance levels, at least for marginal producers. With a market that is at low tide when truths are revealed, hopefully the investor task of comparing upstream companies is a bit easier.

Lower prices highlight the quality of assets, the durability of business models, and identify those that not only survive, but thrive through cycles. Despite commodity prices experienced in 2023, Range is having a successful year focused on creating value today, while also positioning the company for long-term value creation. What does that mean? It means Range has reduced debt and paid cash dividends while fully funding a capital reinvestment program that efficiently sustains production, while also positioning the company for the long term as a responsible, reliable supplier to growing global demand for US natural gas. Putting Range’s success in numbers. Third quarter analyst cash flow totaled $240 million, funding $151 million in capital investments and the $19 million quarterly dividend, while maintaining balance sheet strength.

Cash flow was driven by strong (production multiples), achieving pre-NYMEX hedge realization of $2.79 per MCFE during the third quarter. This realized unit price is $0.24 above NYMEX Henry Hub, demonstrating the value of Range’s diverse sales outlets for natural gas, and the pricing uplift from natural gas liquids and condensate. During the third quarter, Range’s realized NGL price was $24.44 per barrel, or $4.07 on an MCF equivalent basis. Range’s portfolio of transportation capacity and customer contracts supported differentials, delivering roughly 80% of natural gas out of basin, virtually all natural gas liquids out of basin, generating roughly 90% of revenues from diverse, growing premium markets. In addition, Range’s approach to hedging provided additional support to per unit realizations for a hedged realized price of $3.09 per MCFE.

Hedged cash margin per unit of production was resilient, $1.23, benefiting from a persistent focus on efficiency and the right way risk of certain price-linked costs. Total cash unit costs improved by $0.29 versus third quarter last year. The change from prior year primarily relates to savings and processing, fuel, and power costs, which are related to NGL and natural gas prices, and demonstrate the resilient full cycle cost structure of Range’s business. Cash interest expense declined by $8 million for the quarter compared to Q3 last year on reduced debt balances. Range’s financial hedging program supported realized prices for the third quarter, with approximately $59 million in NYMEX-related gains. Looking forward, Range’s natural gas is approximately 50% hedged for the balance of 2023, with an average $3.40 floor, providing continued confidence in Range’s free cash flow profile.

For 2024, we have hedged approximately 50% of natural gas at an average floor price of $3.68, using a combination of $4 swaps and collars retaining upside to roughly $5.30. A modest 2025 hedge position on natural gas, with an average price of $4.12, did not materially change quarter-over-quarter. The objective of this program is essentially to cover fixed costs at attractive levels, enabling consistent free cash flow while maintaining exposure to a market poised, we expect, to positively respond to new LNG facilities coming online, alongside rising domestic demand, with US natural gas supply flattening as a result of significantly reduced industry activity. Turning to the balance sheet, at the end of Q3, we held cash balances of $163 million, which is essentially unchanged from last quarter.

We will continue to manage our cash balance to retain flexibility for efficient working capital management, bond redemption, and share repurchases. This cash balance, combined with future free cash flow, and $1.2 billion available on our undrawn revolving credit facility, provide ample liquidity to efficiently operate our business and take advantage of opportunities the market may present. We’ve been focused on a target capital structure for several years, and as of quarter-end, we have reduced debt net of cash by roughly $2.5 billion since its peak in 2018. This places us very close to our target range of $1 billion to $1.5 billion in net debt. With current leverage of roughly one times debt to EBITDA and close proximity to our balance sheet targets, we believe the company is in great shape to continue value creation on a stable financial base throughout the business cycle.

Successful results this year, combined with a positive industry backdrop for Range going forward, support our confidence in the return of capital program discussed on previous calls. We believe a reliable, fixed cash dividend is appropriate at this time and in this market, while remaining opportunistic in our share repurchases, with capacity available totaling $1.1 billion. As we look to 2024, with an expected even stronger balance sheet, we will be in a position to evaluate the size and speed at which we deploy free cash flow. We believe that will provide greater flexibility around our capital allocation priorities of balance sheet strength, returns of capital, and growth at an appropriate time. Fundamentally, we will prioritize financial strength and remain responsive to market conditions, project returns, and prudent reinvestment.

In the commodity business, prices will fluctuate. Designing a business to be successful in both high prices and lower prices is challenging. It requires quality assets and a creative, dedicated, disciplined team. The Range team across every facet of the business think and act like owners of the business, striving to make the best decisions for the safest, cleanest, and most economic results. A few commonly used words apply to our story, unique, differentiated, peer-leading, among other superlatives. Instead, I’ll point to the data, low base decline, low full cycle cost structure, largest quality acreage position, and more than a decade of positive performance revisions of proved reserves, a combination that we believe creates an E&P company built for the long haul.

With a strong financial foundation and the largest portfolio of quality inventory in Appalachia, paired with transportation to deliver points across key US and international markets, we seek to continue this trend of disciplined value creation for our shareholders. Dennis, back to you.

Dennis Degner: Thanks, Mark. Before moving to Q&A, I’ll reiterate a message we’ve shared previously that is as important today as ever, given the current world events. As the world continues to move towards cleaner, more efficient fuels, natural gas and NGLs will be the affordable, reliable, and an abundance supply that helps power our everyday lives, while also helping billions of others improve their standard of living. We believe Appalachian natural gas and natural gas liquids are positioned to meet that future demand. And within the Appalachian basin, Range has de-risked a large inventory of high quality wells across our half million net acre position, and translated that into a business capable of generating free cash flow through commodity cycles, all while leading the way on capital efficiency, emissions intensity, and transparency. With that, we’ll open the line for questions.

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Q&A Session

Operator: Thank you, Mr. Degner. [Operator Instructions]. Our first question will be coming from Scott Hanold of RBC Capital Markets. Your line is open.

Scott Hanold: Yes, thanks. Good morning. I thought it was pretty interesting the ability for you guys to reduce the well accounts so dramatically this year with the longer laterals. Can you give us some color and context around the overall capital efficiency? What do you think like on an annual basis you could save with drilling less top holes? And how does that manifest into, or how and when does that manifest into stronger free cash flow?

Dennis Degner: Yes, good morning, Scott. I’ll start and this may be something that Mark and I both tag team across this discussion here. But when you look over the past several years, I’ll take about a half step back first, year-over-year, we’ve continued to see the team demonstrate the ability to advance our efficiencies, and what that’s transitioned into is the ability to drill longer laterals. I think you heard us talk about it not only in today, but in some of the prior quarters where not only were we drilling our longest laterals, but our fastest stays where we saw an improvement at the mid-year point of a 40% improvement in our drilling efficiencies just for the first half of the year versus 2022’s full year average.

Completions are seeing the same thing. They’ve seen approximately a 20% to 25% improvement in completion efficiencies this year versus last year. Some of it’s with procedures, rooting out non-productive time, and then having the ability to reduce overall cycle time as you basically execute these pad sites. So, it’s a multi-variable type of assessment when you start to then translate that into our capital efficiency. If you just do a spreadsheet exercise and you compare a 10,000-foot program with 61 laterals, like we originally communicated, something more like we’re seeing today for the year, it really changes our capital efficiency by as much as $15 to $20 per foot. So, pretty exciting about it when you think about it from that perspective.

But what that also does at the same time is it pulls activity that would’ve been executed in, let’s just say the first half of Q1, it has the ability to pull that into the back half of Q4. And so, when you think about our guidance that we provided early on this year from a capital window perspective, and we’re looking at both land and other aspects to this, part of that was us looking forward and anticipating some of these capital or these operational efficiency improvements and what that could set us up for in 2024. Having these longer laterals is going to present a flatter production profile that carries into the early part of 2024. So, we really like the setup and seeing how this then translates into year-over-year further improvements. And then the last thing I’ll certainly throw out is, again, congratulations to the team for all their hard work on this.

It is – as a old supervisor of mine used to say, success begets success. And so, the momentum I think behind everyone in what we’ve been able to accomplish by returning to pad sites is now what we’re seeing in our peer-leading capital efficiency, the ability to maintain that $0.76 per MCFE for that replacement molecule this year, last year $0.64. So, however it shapes up with what pulls in this year, we fully expect that to be another component that allows us to be on that peer-leading edge.

Scott Hanold: Okay. And just specifically on the cost savings, are those – if we’re looking at 10 less wells this year for example, like what does that save you if we were to look at that in isolation, just as a reference point?

Dennis Degner: Well, again, from a simplistic standpoint, I would say ultimately you could – if you start to remove top holes out of the program and you start to look at savings for facilities construction, that could represent approximately $10 million. But when you start to think about that activity that pulls in, then at the end of the year, essentially that gets redeployed to drilling rigs, frac activity, that ultimately when you have that operational fork in the road of it doesn’t make a whole lot of sense to release the rigs to come for December 1 to only then pick it back up in January 1, as an example. So, it maintains that ability to continue on with your operational efficiencies. But at a high-level spreadsheet exercise, it would be around $10 million, but it really provides us the flexibility year in and year out to make that judgment call when we reach the year end.

Scott Hanold: Yes, no, I appreciate that. As you know, we do a lot of spreadsheet exercises on the side of the table. But my second question and it’s going to be along the same lines. Look, it sounds like then you’re going to have more DUCs at the end of the year. And can you talk about having that larger DUC build set up for 2024 and maybe into 2025, how you look at potentially utilizing that more aggressively or just as a lower kind of free cash or a free cash flow buffer into 2024?

Dennis Degner: Well, I’ll start off with this, and when we think about the, again, at a high level, what it does allow us from a flexibility standpoint is to deploy a completion crew January 1 instead of maybe waiting to see that DUC inventory build that’s more “just-in-time” or then that completions activity starts, let’s just say a little bit later into the first quarter. So, it really does provide a nice setup for us and how we then see that production come online hopefully at more favorable pricing opportunities. I think the activity that not only gets pulled forward in 2024, but at the end of this year, also then makes that that equivalent impact. From a cash flow perspective, I’ll just frame it at a high level as to say, we see that helping us then take either capital pressure off for next year, or depending upon the setup that we’re going to consider for 2025 that we’ll communicate at the next earnings call, along with our 2024 budget, we think it provides a really healthy optionality for us to either think about growth when that opportunity persists, or how it further supports our maintenance level program, whichever path is most prominent.

Scott Hanold: Appreciate the color. Thank you.

Operator: One moment for our next question. And our next question comes from Doug Leggate of Bank of America. Your line is open.

Doug Leggate: Thank you. Good morning, everyone. Dennis, I appreciate all the details this morning there. There’s obviously – Scott hit a couple of the key issues that are obviously going to impact your outlook for 2024. So, I have a simple question to try and summarize all the moving parts. What do you think has happened or will happen to your corporate level breakeven gas price? And the reason I’m asking is, it looks to us that you are pretty close to breakeven ex-hedges in third quarter 2023, but at 250 Henry Hub gas price, we’ve got a forward curve north of four. Seems to us the market continues to grossly underestimate the free cash flow capacity of the portfolio. So, I’m trying to understand what you would – where you would draw the line in terms of what you think your 2024 corporate breakeven can look like. And I’ve got a quick follow up, please.

Dennis Degner: Sure. Good morning, Doug. Thanks for the questions. I think as we think about the breakout of our inventory on Slide 5, it’s something we’ve walked through a number of times with folks, but we’ve made the transition from really talking about wells from an EUR per thousand foot perspective and really starting to talk about the breakevens, which you’re addressing. We basically look at it from a standpoint, we’ve got the 2,500 locations that basically have a breakeven of 250 or less. With further improvements in our capital efficiency, now you’re always going to have fluctuations in service costs that are going to take place just given what’s going on in the market, we’d expect, A, that to be incredibly stable and, B, opportunity to further improve that as we look at expanding areas like water recycling as an example, and further translating some of the record efficiencies that we’ve been talking about this year into more repeatable performance.

Certainly, it’s fun to talk about the records, but really in order to be successful, we know it’s important that we be repeatable. So, how do you translate that then into repeatable format? We think that has the opportunity to further improve our overall breakeven cost from that inventory bidding perspective.

Doug Leggate: Hey, Dennis …

Mark Scucchi: Good morning, Doug, this is Mark. I’ll …

Doug Leggate: Yes, sorry to interrupt. I’m at the corporate level, the corporate level, not the well level. Sorry, Mark, go ahead.

Mark Scucchi: Sure. I think stepping back and look at the corporate level cash flow, third quarter this year is really an exemplary example of what this asset can do. We generated greater than $90 million in free cash flow. We intentionally reinvested and deployed that, maintained the balance sheet strength, pay the dividend, continued to maintain and improve the balance sheet because this asset in one sense can be viewed like an annuity. I know that’s one lens which you use to value a company is we fast forward and look at what this company can do. There’s a few scenarios in our deck to talk about free cash flow hypothetical scenarios. As we approach $4, you’re generating what we think is a reasonable, perhaps conservative estimate of $1 billion per year corporate level of free cash flow and greater.

And I think it’s notable also that that incorporates an assumption, a fairly conservative NGL realization. So, there’s basically an option, an upside option embedded in that as well. So, if we’re thinking about a maintenance scenario, that represents an enormous annuity of cash flow range. As we’ve talked about before, and as Dennis has already said, we are very mindful of positioning the business to be resilient if prices are soft, but also to position ourselves to participate in growing demand, whether that’s 2025, pick your timeframe, Range has the capacity, the willingness, and the ability to grow efficiently and generate what we think will be some of the most competitive margins out there. So, I think the repeatability of that also to Dennis’ point is key.

This inventory depth, multiply that out across a couple decades times $1 billion of free cash flow annually at the corporate level and improving as we pay off debt and other corporate costs reduce on an MCFE basis, expanding your per unit margin, that I think really does represent a unique opportunity in this space.

Doug Leggate: Mark, thanks for the clarification, guys. You’re right. I mean, I don’t think too many companies can claim the inventory depth, so I don’t know whether I’d say we look at everything in as annuity, but it’s certainly inventory depth is a big constraint on valuation for sure. So, thank you for that clarification. Quick follow up guys. If your inventory depth is defined on 10,000 foot laterals, which I believe it is, but you’re drilling significantly longer laterals and improving capital efficiency, how much longer do you think – I mean, how long do you think the program can continue to step up into those longer laterals? And I guess what’s the inventory for the longer lateral, is the question, so, and I’ll leave it there. Thank you.

Dennis Degner: Yes, thank you Doug. I think there’s a lot of running room when you think about the ability to further extend our laterals and what that means to our overall program. If you look back over the past, let’s just say three years, I’ll pick something reasonably near term, year-over-year, we’ve seen a continued theme of incrementally increasing our overall lateral links. And I know we’ve talked about this on previous calls, but also while returning to pad sites with the existing production. So, this isn’t necessarily what we would call clean sheet development where you’re moving out into the fringes of your asset base. This is in and around prior producing wells and taking the learnings from those historical executions and translating that into more efficient execution and planning.

So, we see the 21,000-foot laterals that we drilled this year as a good reflection of that. We’ve got in excess of 60 wells that are at 15,000 foot in horizontal lengths. So, again, we’ll move methodically through equipment upgrades, procedures, KPI tracking and make sure that we’re extending our laterals in the most efficient and prudent way. And look, at the end of the day, we’ve got an inventory runway, even with extending of these laterals, that’s greater than 30 years, with breakevens that are in the $2 range or better. And so, we think this is going to bode well as we think about the runway of this inventory development process.

Doug Leggate: Gentlemen, thanks for your time. Appreciate the answers.

Operator: And one moment for our next question. And our next question will go me from Jean Ann Salisbury of Bernstein. Your line is open, Jean.

Jean Ann Salisbury: Hi. good morning. One more follow-up on the drivers of the longer laterals and fewer turned in line wells. How material is the shape of the forward curve in that decision? For example, if the forward curve goes into backwardation, would that kind of push you to stop extending lateral length or even potentially go to shorter laterals?

Mark Scucchi: I think maybe from an economic standpoint, I’ll start this one off, the shape of the forward curve won’t drive – won’t be the primary driver in that decision making process. As we look at efficiency and driving the lowest maintenance capital number possible, it is optimizing those capital reinvestments. It is creating a company with a, call it 40% or better reinvestment rate to hold production flat, and that $0.70 some per MCFE capital expenditure to hold production flat. So, the shape of the curve, as we think about the overall economics, it’s also impacted by the flat decline rate that Range had, that 19% of decline rate. So, as you flatten that out over time, we’re looking at a price three years through the seasonality, what the sustainable price levels are, and of course, that’s also bolstered by the hedging program.

So, prices will move. They will move erratically. Our balanced program that generates significant contribution from the liquids cut as well, combined with the natural gas cut, along with sales points across the US. The shape of the curve doesn’t necessarily impact us deciding to drill a 12,000 to a 15,000 foot lateral. Really, it comes back to, what’s the economics? What’s the space in the existing system? Where are we placing that to optimize the use of the existing surface facilities, existing compression, gathering and long-haul transport. So, not to talk around the question, but it’s just a multifaceted equation and evaluation we do to make sure we can get the most out of each reinvested dollar.

Jean Ann Salisbury: Yes, no, that makes sense. Thank you. And then your differential guidance for the year moved – it was slight, but moved slightly to the $0.40 to $0.45. Can you give any more color around whether that was specific in markets getting a little bit worse or in basin pricing?

Mark Scucchi: Laith can add some details to that, but I think the short version is, we all know in shoulder seasons and where storage levels were in the third quarter, there were some soft spots in the in-basin markets, in particular in Appalachia, but fortunately, 80 plus percent of our gas is out of basin, and basically all of our liquids, over 90% of our revenue is out of basin. So, that’s a reflection of that minority of the production that’s sold in basin. It is bolstered by a basis hedging program, and effectively a basis hedging program embedded within the physical sales and diversity of customers we have. But that’s the long and short of it. There’s been no substantial change to our portfolio of customers. We still sell across greater than 30 different natural gas pricing points, and we’ll look to keep optimizing that program over time, that portfolio over time.

Jean Ann Salisbury: Great. Thanks. That’s all for me.

Operator: And one moment for our next question. Our next question will be coming from Umang Choudhary of Goldman Sachs & Company. Your line’s open.

Umang Choudhary: Hi, good morning and thank you for taking my questions. My first question was on the NGL macro. Appreciate all the details on your slide deck. Prices have been weak this year, especially for LPG, and you’ve seen a pickup in exports recently, but the freight prices have been high too. So, would love your thoughts around the LPG outlook heading into next year.

Dennis Degner: You bet. Good morning, Umang. I think as we start to think about – I’ll start with propane first. When you think about what we’ve seen, clearly stock levels have been elevated. We’re running around 100 million barrels in inventory levels. That’s clearly on the back of a weaker winter from this past year. And also, maybe a little bit of a slower progression to the chemical markets than what had originally been anticipated. I think if you start to think about 2024, which was the crux of your question, a couple of things I see or we see is underpinning a positive movement going forward, and one is the PDH infrastructure and cracker infrastructure that’s been in the process of being commissioned, seeing improving run rates month over month, but also additional infrastructure that will get commissioned.

So, it’s around 400,000 barrels a day in infrastructure this year, and next year it’s in excess of 400,000. So, you’ve got back-to-back years of what we’ll call incremental needs and in infrastructure that’s going to get commissioned, that’s going to help with this stock level perspective and view. Other side of this equation is, you’ve got really strong exports. If you look at year-to-date values, we’ve seen a range of 1.5 to 1.7 million barrels a day. Average is a little over 1.5 for the year. A few years ago, that would’ve been a peak moment and a record to point to, but now it’s good, strong repeatable performance month in and month out. So, that’s certainly helping with the equation. When you think about days of supply though, and you translate that back to where we’re at today, we’re really 3% below the five-year average.

So, when you think about all the demand component and getting through the winter setup that we have ahead of us, we see stock levels starting to renormalize as you get into through the first half of 2024. Ethane is tighter. Days of supply on that side is around 18 days and storage levels are just below 50 million barrels. And we continue to see strong interest from our traditional counterparties on additional ethane opportunities. And so, we would expect to see some spikes at times in pricing like we’ve seen over the past three to six months. It’s been reflective in how the market has been tightened. We would expect to see some ongoing volatility as we move forward. And of course, once we start to see net gas storage levels get renormalized as well, you would expect to see further improvements in ethane trading then on the back of what’s happening on the gas front as well.

Mark Scucchi: I’ll join in here as well. As we think about the valuation impact of that commentary in the backdrop that creates, today we’re seeing NGL realizations in the 35% type zip code, mid-30 relative to WTI. As we think about a more normalized level that we would fully expect to be well in excess of 40%, what you’re seeing is an embedded option value within Range for that re-rating for the normalization of propane inventories. And while nominally they are high on a days-to-cover basis, like many of the other commodities, they’re not that far off of five-year averages. So, with these high export levels, growth and demand, the speed at which they can recover to normalize levels nominally and actually become tight in reality, really highlights the value of that embedded option of NGLs within the Range story.

Umang Choudhary: Another option which you have is also on growth given your differentiated inventory. Anything you would like to see on local demand or anything you’re seeing on gas marketing which can unlock that potential heading into next year, or in the next few years?

Dennis Degner: Yes, I think when you start to think about the opportunity for growth, and we’ll just say in-basin demand, clearly a shell cracker is a good example of it’s ongoing commissioning, getting to higher run rates over the course of time, and it is working through what we would kind of view as normal greenfield startup type challenges, but also successes in the same breath. So, I think that’s a good example. I think the other part is, is you’ve got coal retirements that are going to be taking place over the balance of the next few years, opportunity for nat gas in Range to backfill those opportunities for power generation. I think if we learned anything this past summer, nat gas really stood strong for that backfill of power generation, adding 2.5 BCF roughly in incremental power generation, and occupying that space when at times wind and others were below forecast.

So, we see those as kind of more in the near term. I think once you start to get past 2024, you really start to have the question of, what additional power generation is going to get put into place from a combined cycle standpoint? I think you’re seeing a lot of dialogue now around the grid reliability, how you expand that. We’re going to have further electrification and bolstering of the grid. That’s going to come with a reliable fuel source, which we think Range and nat gas is going to play a huge role in that. And I think the second thing I would throw out on the future is EV battery, industrial type development, manufacturing, if you start to look at where some of this incremental and future manufacturing and industrial demand is pointing to be constructed, it’s not too far away from some of the transport that Range has in our portfolio that gets us to the Gulf, to the Midwest.

So, again, we really see this as being a bright future for not only nat gas and NGLs, but the role that Range could play in that as you start to see inventory exhaustion by others, and also then underpinned by the quality and runway of inventory that Range has. So, we think it’s a bright future. It’s a multi-variable perspective as you look forward.

Umang Choudhary: Very helpful. Thank you so much.

Operator: And one moment for our next question. Our next question will be coming from Michael Scialla of Stephens. Your line is open.

Michael Scialla: Hi. Good morning, guys. Dennis, you gave some detail on the savings you anticipate for steel and sand, maybe on rig costs as well. It looks like you kept your well costs in your investor deck unchanged from last quarter. Can you say where you think 2024 costs will be relative to 2023? Do some of those savings get offset elsewhere? I know you mentioned the new frac fleet. Is that going to offset those savings, or do you anticipate lower costs next year?

Dennis Degner: Yes, good morning, Michael. I think I would start off by somewhat saying, we’re super early in the process of our RFP rollout that we just deployed here over the last several weeks. So, what I’m sharing with you is kind of some of those early indications in the prepared remarks this morning. I think we’re going to have a lot better view once we get toward the end of the year, we get that process wrapped up, and we start to communicate how that translates into our execution for our plan for 2024. So, I think we’ll have a lot better view at that point. The numbers in the back of the slide deck haven’t changed because ultimately we’re still in the middle of that evaluation of that process. And once we know what our full cost structure will look like, then we’ll have, again, better updates.

You are seeing, in our opinion – I’ll share one final thought. You are starting to see, I think a – maybe costs are going to look differently than the traditional rig count up, service cost up, rig count down, service cost down, across the board. And we tried to share some of that this morning in the prepared remarks, because you’re still seeing a high level of utilization for services as an example, like super-spec drilling rigs and also the electric fracturing fleets. We think that could present some stabilization in that cost structure, maybe even some slight relief, but it’ll be other areas that we may see, again, more relief, whether it’s some of the consumables like tubular goods where we’re seeing that 30% relief for next year and have done a job of securing that, but also in areas like diesel fuel, more stabilization on the frac sand side as well.

So, we’ll have better numbers for everyone at the next call, but we would expect to see some modest level of savings. It could be single-digit type savings mid-level, but we’ll have a better answer once we get to February.

Michael Scialla: Understood. Thanks. And I guess given the longer laterals, the improved capital efficiency, sounds like your base decline rate is continuing to shallow. Can you say where maintenance CapEx, or maybe if it’s easier maintenance activity level, would need to be next year relative to 2023?

Dennis Degner: I think a way of thinking about our program for 2024 in a maintenance type scenario is around $600 million. You could see that be slightly less depending upon the setup we’re thinking about for 2025 once we start to get to February, see what kind of winter we’ve got. LNG infrastructure buildout, how that’s further progressing along. So, I think there’s several variables that we would want to take into account, but I think the way to think about our program in a maintenance scenario is about $600 million, and it would be around 50 to 60 wells. I think historically, we would’ve said 60 wells kind of year in and year out, but with the advancement in our lateral links, it could be somewhere closer to 50 depending upon what kind of inventory we would like to carry into the setup for 2025.

Michael Scialla: Very good. Thank you.

Operator: And one moment for our next question. Our next question will be coming from Jacob Roberts of TPH & Company. Your line is open.

Jacob Roberts: Morning. I think you touched on this in response to Doug earlier, but I’m just curious if you could remind us the percentage of activity that has been on prior pads in recent years and where you expect that percentage to shift to over the next, let’s say 12 to 24 months.

Dennis Degner: Yes, good morning, Jacob. Historically, we have been moving back to pads with the existing production for somewhere as low as 30%, but it’s more closer to about 50% of our activity each year. This past quarter kind of represents some of that fluctuation of what we see quarter in and quarter out where actually three quarters of our wells that we executed were on pads with existing production. But I think a good way of thinking about our program year in and year out is about half of our activity would be on pads with existing production. And again, part of that is to complement something Mark touched on a few minutes ago, and that is utilization of the gathering system, compression, pipes, and also our processing where we see those opportunities. So, moving back to those pads not only provides capital efficiency improvements, but it also translates in our ability to keep our gathering system fully utilized and our cost structure as low as possible.

Jacob Roberts: Okay. Appreciate that. And then as a second question, could you refresh us on where the understandings are on the Utica and Devonian and maybe where you hope to be and that understanding into 2024, whether it’s via your own pursuits or by peers in the area?

Dennis Degner: Well, when we think about the Utica, I’ll start off by saying, we’re awfully excited about the future potential of that asset. But when we think about our inventory runway on the Marcellus, the repeatability, we’ve got 1,500 wells that we’ve drilled and completed. We understand that, the formation incredibly well. And again, as I mentioned earlier, it’s very repeatable for us. And so, the improvements that we’ve made have really kind of underpinned the resilience of our business. When you think about the future of the organization and the inventory bidding that we have, the low breakevens that we touched on earlier, our focus is clearly on the Marcellus as we go forward. In many cases, you’re going to see others focus on the Utica because of potentially limitations they have either in their Marcellus inventory or the quality of that inventory they have.

We think we can be patient. We can sit back. We can do industry surveillance, watch what others are doing, and then translate that into how we would advance the technical model in the years that follow for the opportunity when we would like to pull that into the program on more of an active basis. But again, we’re highly focused on the Marcellus and for obvious reasons when you look at the cost associated with it, the efficiencies, and on top of it, just the depth and quality of inventory that we have.

Jacob Roberts: Thank you. Appreciate the time.

Operator: And one moment for our next question. Our next question will be coming from Arun Jayaram of J.P. Morgan Securities. Your line is open.

Arun Jayaram: Yes. Good morning. Dennis, I wanted to start with maybe a housekeeping question. The fourth quarter guide on volumes that you provided on the call, looks to be a touch shy of the Street and what we’re modeling, and maybe we’re a little surprised just given kind of the pull forward of activity, but any drivers of that that you could point to?

Dennis Degner: Yes, good morning, Arun. I think what I would point to is really the extended laterals that we’ve been completing. I think if you look at Q3, good example is the 21,000 foot laterals and having that maintenance level program, coupled with a gathering system that we’re keeping full. So, what it’s going to do is, it’s going to allow us to keep production flatter as we start to transition into Q1. If you think about the past several years and what maintenance has looked like, we tend to have our highest production in the back half of the year. But then you’re going to see some decline in the first portion of the year as we start to then catch back up with that higher activity cadence in the first half that translates into the uptick in production in the back half.

We think this is going to actually translate into a little bit more of a level-loaded production profile as we come out of Q4 through the winter months where we have improved pricing, and then through not only the first part of Q1, but then at the start of Q2. So, a little bit differently what we’ve seen the past couple of years.

Arun Jayaram: That’s helpful. Maybe next one is for Mark. Mark, you’re really approaching your debt reduction or your leverage target or your gross debt target. Pardon me. And I just wanted to see if you could kind of give us a sense of, from a timing perspective, when you expect to get there, and thoughts on cash return as we move into a better part of the gas cycle.

Mark Scucchi: Sure. That’s a tough question to answer, given the month in which we pass it, the target range. If I had a perfect crystal ball for the weather and the pricing this winter, we’d be able to do that. But I think what you’re pointing to is the fact that we are right there on the doorstep of entering the target threshold. We think we’re in a great spot already with the balance sheet, and that gives us flexibility today, but even more flexibility, we fully expect next year to use free cash flow and redeploy it, whether it’s through incremental share repurchases, whether there’s a modest increase in the dividend, whether there’s other forms of reinvestment directly into the business, that gives us additional latitude.

We have available under board approved buyback program, $1.1 billion. I’ll point to our activity last year where we repurchased $400 million in shares. This year, obviously prices came off. So, we backed off a little bit. So, we’re just balancing that reinvestment. Our program, we intentionally shied away to date from giving a formulaic approach. We like the optionality of being able to take advantage of opportunities in the market to reinvest it at opportune times. So, just to give extreme examples, if we saw a huge pullback in the stock, we would consider hard whether it’s time to put more of our cash flow sooner rather than later back into the buyback program. Alternatively, prices are soft. We’ll remain conservative and focus on the balance sheet.

So, we’re so close to that target balance sheet range that we like the flexibility to get today. And I’ll just highlight again, and I think that gives us even greater latitude as we get into 2024 and after.

Arun Jayaram: Thanks, Mark, for the thoughtful response. Talk soon.

Operator: Thank you. And that will be our last question. This concludes today’s question-and-answer session. I would like to turn the call back over to Mr. Degner for his concluding remarks.

Dennis Degner: I’d like to say thanks for everyone joining us on the call this morning. If you have any follow up questions, please don’t hesitate to follow up with the Investor Relations team. Thank you.

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