Welcome to the Range Resources Fourth 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 risk 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 the time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead, sir.

Thank you, Operator. Good morning, everyone, and thank you for joining Range’s year-end 2023 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’ll also find our 10-K 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.

Thanks, Laith, and thanks to all of you for joining the call today. Range’s 2023 plan was successfully executed with a consistent theme throughout the year: operating safely while driving continued operational improvements, generating free cash flow with peer-leading capital efficiency and prudent allocation of that free cash flow, balancing returns of capital to shareholders with further debt reduction and the long-term development of our world-class asset base. I believe our fourth-quarter results are a great example of continued advancement against those key objectives and showcase the resilience of Range’s business at a low point in a cycle. Likewise, our year-end reserves update and 16th consecutive year of positive performance revisions point to the repeatable nature of our Marcellus inventory. As we look towards the year ahead, you’ll hear those themes repeated, and I believe the resilience of our business in a lower price environment will be a key differentiator for Range. Maintaining a flexible hedge program to cover fixed costs and capital commitments is clearly beneficial in periods of price weakness like we find ourselves in today. However, the real value proposition over the long run is underpinned by Range’s low sustaining capital requirements. Our low capital intensity results from Range’s class-leading drilling and completion costs, shallow base decline, large blocky core inventory, and talented team. Altogether, these results in a required reinvestment rate that is lower than that of any of our peers, which provides Range with a solid foundation for consistently generating significant free cash flow and returns to shareholders. Further bolstering Range’s durability is our liquids contribution, which is approximately 30% of our total production volume. Our liquids revenue is expected to provide an uplift to natural gas prices, and using today’s strip pricing, it’s very meaningful. For context, Range’s NGL barrel is currently priced around $24 per barrel using strip prices for 2024. That is equivalent to a $1.60 per MCF premium to recent Henry Hub pricing. When we roll all of that together, our liquids revenue uplift, our low maintenance capital, and a thoughtful hedging program provide the lowest break-even among natural gas producers and the most resilient organic free cash flow as evidenced by our 2023 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. Turning to our near-term plans, for 2024 Range expects to generate healthy free cash flow at strip pricing with all-in capital spending between $620 million and $670 million. This capital plan consists of approximately $575 million to support our base-level maintenance production plan similar to the past few years, along with additional investments in three categories. The first category is additional acreage spending above maintenance levels, which not only allows for longer laterals but actually offsets most of our lateral footage being turned to sales, keeping our 28 million feet of core Marcellus inventory relatively unchanged. The second category is an investment in expanding our water infrastructure which provides a very quick payback and supports low drilling and completion (D&C) and lease operating expenses (LOE) costs in the future. Lastly, we will have flexible drilling and completion capital, like we had in 2023, which increases our year-end inventory of drilled and/or completed lateral footage, providing us optionality and flexibility as we evaluate the optimum setup for following years. The overall number of drilling rigs and frac crews will be the same as last year, with the additional inventory generated as a result of simply retaining the equipment. This maintains operational efficiencies and provides flexibility for 2025 and beyond given the macro backdrop. Range is planning a maintenance production profile that is similar to recent years, at 2.12 BCF equivalent per day to 2.16 BCF equivalent per day. Approximately three-quarters of the lateral footage that will turn to sales this year will be located across our wet and super-rich acreage positions, providing the added benefit of our NGL uplift to overall cash flow and price realizations, with the remainder of our program focused on our dry gas footprint. Our operational cadence for 2024 will consist of two horizontal drilling rigs operating throughout the year, resulting in a total combined footage of approximately 750,000 lateral feet being drilled, or about 100,000 feet more than what we will turn to sales. 2024 completions will be executed utilizing a single new electric fracturing fleet operating through the year as well. Consistent with a maintenance production program, approximately 640,000 lateral feet from 50 new wells is expected to go into production in 2024, with more than half of the new wells being drilled on pads with existing production. Returning to pads with existing production has been a repeatable part of the Range story for many years and supports both our capital and operational efficiency. Similar to prior years, our activity and capital will be weighted towards the front half of the year, while our quarterly production profile is expected to be back-half weighted as the new turning lines materialize in the back half of 2024. First-quarter production is expected to be around 2.1 BCF equivalent per day before building into the second half of the year. Our operational review for the past year showcased a continued theme of execution excellence, starting with our drilling highlights. 2023 saw several new efficiency records set for the program while drilling a total combined lateral footage of nearly 700,000 feet. The team managed to drill eight of the top 15 longest laterals in Range’s program history, with 40% exceeding 15,000 feet laterally. Four of the wells had lateral lengths greater than 20,000 feet, with the longest two laterals extending four miles. Our large contiguous acreage position affords us the ability to drill these types of long laterals, increasing efficiencies and allowing us to access more reserves from a single location, all while reducing our overall footprint and consolidating infrastructure requirements. In addition to the new horizontal length records set by the team, we also set new benchmark rates for daily drill footage. The average daily lateral footage drilled in 2023 was more than 4,600 feet per day, a step change increase of 38% over the previous year, with the fastest drilling day exceeding 7,450 feet drilled in a 24-hour period. The efficiency gains we see from longer laterals and faster daily drilling rates are key to the program’s success, but equally important was that the team managed to simultaneously improve its pinpoint accuracy when in zone. Over the years, our drilling and geoscience teams have set an extremely precise standard for our horizontal targeting, typically with a tolerance of less than 20 feet. In 2023, with all the long lateral and high drilling rate successes the team had, they did it while staying within their high-graded targets for more than 93% of the lateral footage drilled in the year—a noteworthy achievement by the team. This type of laser focus plays a role in the positive performance revisions and consistent reserve reporting that investors have come to expect from Range. Moving to completions, several new completion efficiency records were established during the year to include the following; increasing overall efficiencies to nine stages per day—a 10% improvement over the prior mark which was just set in 2022; achieving our highest pad average of 13.4 stages per day, a mark set during the fourth quarter; successfully completing Range’s longest well to date with a total measured depth of 29,500 feet and setting a new record of 17 stages completed in a 24-hour period. These incremental gains in operational efficiency could not have been accomplished without reliable logistics supporting each stage, and the Range water operations and logistics team played a critical role in supporting these efforts. But these operational results are incomplete if we can’t execute safely. In addition to the highlights shared today, the team also delivered one of our best safety and environmental performances in the company’s history. We look forward to sharing more on these results in our upcoming Corporate Sustainability Report in the months ahead. Turning quickly to marketing. During the quarter, Range’s weighted average NGL price was $24.91 per barrel. This is a $2.42 per barrel premium to the Mont Belvieu Index and the highest quarterly premium in company history. This performance was driven by Range’s flexible LPG export program and strong seasonal butane values during the quarter. Full year 2023 saw a $1.24 per barrel NGL premium, which was also a company best on an annual basis. We expect Range to maintain a differential to the Belvieu Index of $1 minus to $1 premium for 2024 by leveraging our export capacity and flexible transportation options. To the extent that export dynamics remain tight in the Gulf Coast, as they were in the second half of 2023, we would expect our access to the East Coast to be advantaged, pushing us toward the premium side of our guidance. And as I mentioned at the beginning of these remarks, Range’s NGL barrel is currently priced well above natural gas prices, supporting our durable free cash flow profile. Turning to natural gas, near-term prices are obviously incredibly challenging for the industry, and we expect these historically low price levels to help keep a lid on natural gas production across the U.S. We’re encouraged by reduced industry activity in the Haynesville and Tier 2 basins, along with maintenance programs being planned in the Marcellus. This moderated industry activity, along with LNG project startups expected in the second half of 2024 and continued strength in gas power generation, provides the potential for the domestic market to rebalance later this year. While beyond this year, continued growth in global demand for U.S. natural gas, combined with domestic power and industrial demand and Tier 1 well inventory exhaustion, all set up a strong outlook for long-term U.S. gas fundamentals. Before handing over to Mark, I’ll reiterate a message we’ve shared previously. We believe the future of natural gas and NGLs is strong, and the Range team remains focused on generating free cash flow while advancing our overall efficiencies and delivering repeatable well performance across our large contiguous inventory. I believe the positive results we generated in 2023 and plan to build upon in 2024 are a reflection of that focus and show the resilience of Range’s business. I’ll now turn it over to Mark to discuss the financials.

Thanks, Dennis. 2023 highlighted the strengths and weaknesses of companies in the energy sector. For upstream producers, quality assets with low full cycle costs, the ability to reach a diverse set of customers with a variety of price points, and a rock-solid balance sheet to provide flexibility were all necessary to create value. Range has each of these key attributes, and through sound execution by the team, the company generated strong free cash flow, reduced debt, paid dividends, bought back shares, and reinvested in operations—not only for maintenance but to prudently position the company for the future. As we sit here in early 2024 with an efficient plan to maintain steady production, we are also carefully positioning the business for evolving domestic and international demand for natural gas and natural gas liquids. Let’s start with capital allocation in 2023. Cash flow before working capital of approximately $1.1 billion funded our capital investments of $614 million, a reduction in debt net of cash of $292 million, along with roughly $96 million in dividends and share repurchases. This allocation demonstrates the fact that in a low commodity price setting, Range comfortably maintained base production that drove strong cash flow on the back of cash margins equating to greater than 40% of realized price per unit. This resilient margin, attributable to an advantageous commodity mix paired with a diverse sales portfolio and competitive unit costs, allowed prudent investments in the business and cash returns from the business while further strengthening the balance sheet. Over the past two years, Range has reduced net debt by an aggregate of $1.2 billion and returned capital to shareholders in the form of share repurchases and dividends totaling $535 million. In total, that is more than $1.7 billion in capital returned to stakeholders. With a balance sheet in great shape and a reduced share count, continued resilient value generation is the goal. Driving 2023 strong financial results was the tireless operating team focused on safety and efficiency. The team delivered planned production at a competitive drilling and completion capital cost, which included building a few wells for inventory. With perhaps the lowest decline rate of comparable companies, Range’s capital efficiency stands out in terms of cost per Mcfe, full cycle break-even costs, and the required reinvestment rate of cash flow to maintain production. As a percentage of cash flow, Range should regularly be near the lowest call on cash for sustaining CapEx. We expect this to be true of this asset base for many years. Focusing on the fourth quarter for a moment, operating results achieved cash flow before working capital of $300 million. Cash flow was a result of realized price per unit of $3.25 per Mcfe. Margin benefited from lower expenses with an $0.11 reduction in unit costs compared to fourth quarter last year, driven primarily by lower GP&T and lower interest expense. Fourth-quarter cash margins per unit of production were $1.42, a healthy 44% margin despite lower commodity prices. As we often mention, Range’s gas processing cost is linked to NGL prices such that gathering, processing, and transportation expense decreased during the fourth quarter, serving as a right-way risk relationship between costs and pricing. Also reducing costs in Q4 were lower fuel and electricity costs. Taxes have become a relevant topic with company profitability. In 2023, Range’s cash taxes are only at the state level for a total of roughly $1.5 million for the year. At year-end 2023, Range had federal NOL carryforwards totaling $1.8 billion. These NOLs will serve to reduce taxable income in coming years. For some added understanding, the first layer of federal NOLs totaling approximately $158 million can be used to reduce up to 100% of taxable income. The approximate remaining $1.7 billion of federal NOLs can be used to reduce up to 80% of a given year’s taxable income. At current strip pricing and Range’s expected profitability, we believe we will benefit from the full utilization of these NOL carryforwards in coming years. Turning from 2023 accomplishments to where the company is headed in 2024, given the strong foundation provided by high-quality assets and low financial leverage, we intend for Range’s strategic focus to remain consistent: maximize the value of a multi-decade project inventory, generate free cash flow, prudently return capital, and reinvest in the business. With a thoughtfully constructed hedging program, we seek to participate in improved long-term market dynamics while increasing confidence in near-term forecasted cash flow, all to support consistent efficient operations, preserving the balance sheet and creating additional optionality around capital allocation. We believe Range’s results demonstrate a successful hedging philosophy that has served the company well and will continue to do so in the future. Presently, Range has approximately 55% of 2024 natural gas hedged with an average floor price of $3.70, and in 2025, approximately 25% hedged with an average floor price of $4.11, providing Range a stable base to consistently generate free cash flow through market cycles. Range’s business plan continues to execute on what we believe is the largest high-quality asset in Appalachia, paired with a transport and sales portfolio delivering production across the U.S. and internationally, all underpinned by a strong financial foundation. We have the team, assets, and balance sheet to succeed through price cycles, and we believe the Range business can and will continue to deliver significant value to investors. Dennis, back to you.

Thanks, Mark. Before moving to Q&A, I’d like to congratulate our team for their accomplishments discussed today and their dedication to our continued safety performance, operational improvements, and progress towards our stated financial objectives. 2024 looks like it’s going to be a challenging year for the industry, but Range’s business has never been stronger, 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.

Thank you, Mr. Degner. Our first question is from Doug Leggate with Bank of America. Your line is open. Please go ahead.

Thank you very much, indeed. Dennis, thanks for all your comments, and obviously, a tremendous asset base that you’ve spelled out in spades every quarter that certainly, in our book at least, is not yet recognized in your stock. But I do have a more macro question to kick off, if I may. You’ve obviously seen what happened to gas prices and indeed, your own share price in the sector in the last couple of days in response to one of your large peers making some decisions about the timing of when to produce. So I’m just curious about your thinking on that topic. Obviously, with one frac crew, you can’t exactly control productivity, but you could curtail the timing of completions, perhaps, into a better gas market. So I’m just curious if you could walk us through how you think about that?

Yeah. Good morning, Doug. I think the way you’ve asked the question is something we’ve given a lot of conversation and thought to over the past several weeks. We like the flexibility, and I know we’ve used that word a lot in our prepared remarks today, but we like the flexibility this program sets up. If you look back at our ability to basically shape the curve of when our wells will turn in line this year, when you look at the past several years, there have been times when clearly we’ve chosen to look at shut-in economics, and we’ve looked at dry gas portions of the field, and we know where, let’s just say, that gas curtailment could take place and have a commensurate cost reduction that goes along with it while supporting, really, our price realization uplift associated with our NGLs on the wet side of it. So as we look kind of on the program going forward in the inventory build that would support our setup for 2025, we see that we’ll have the flexibility to basically adjust timing for turning lines based upon what the macro is telling us and what the basin fundamentals are looking like. With our transport and the ability to get gas, 80% of our gas out of the basin and virtually 100% of our NGLs out, it does change the calculus for us quite a bit, but we will remain absolutely very sensitive given the flexibility that we’ve baked in and the cash flow that the business will generate this year. We like our flexibility to shape those turning lines with what makes sense for the business.

I appreciate that. I know it’s a tricky one to navigate, and it’s easy for us to opine on it, but you’ve got to execute, so thank you for that. My follow-up is also a kind of high-level question. I mean, the operations, the quarter, obviously look great, productivity continues to be very predictable and credit to Laith and the team for helping us see that, if you like, but you’re already the most capital-efficient gas producer, frankly, in the country. My question is, others are not, and with that in mind, I’m curious how you see your role in the consolidation wave, if any, on what’s going on in the sector right now. Putting good assets behind great management is a pretty easy way to create value. I’m curious how you think about that?

Well, I think as we look at M&A, our view today isn’t a whole lot different than the way we’ve looked at it in the past. We know what some of the in-basin opportunities look like. Whatever we would embrace from an M&A standpoint, it has to look a lot like Range and it has to make Range a better company and keep us on the path of the objectives that we’ve been talking about kind of quarter-after-quarter and somewhat staying the course. When you look at the team that we’ve put in place, the successes they’ve been able to accomplish, there’s no doubt the capital efficiency that Range has harvested is something that we think could be replicated, if you will, in other parts of the basin. But we also know that, again, we remain focused on the large inventory that we have, and we haven’t even talked about the inventory below the Marcellus with the Utica or even the Upper Devonian. So, in a lot of ways, we feel like we can take this, what we’re doing today, replicate it year-after-year and decade-after-decade and not have to necessarily look at an M&A possibility to further, let’s just say, enhance capital efficiency. But size and scale is something that certainly we’ve been asked about a number of times, and it’s a common question. There could be some positive benefits whether it’s leveraging cost of services, let’s just say, combining transport and other processing and gathering-type cost structures. So, we see that there are those opportunities, but when you look, as you pointed out, Doug, where we’re at with some of our metrics, it would have to look a lot like Range or we go the other way. So, we like where we’re at. We feel like we’ve got the team and the inventory, as Mark and I both touched on today, to kind of keep forwarding the path that we’re on.

Almost like an annuity to that is what we think about. Thanks so much, Dennis. I appreciate the answers.

Thanks, Doug.

Thank you. And one moment while we move to our next question. Our next question comes from the line of Nitin Kumar with Mizuho Securities. Your line is open. Please go ahead.

Good morning, guys, and thanks for taking my question. I’m going to start off, Mark, in your prepared remarks. You talked about returning cash to shareholders, but over the last couple of years, you favored debt reduction as a primary source for deploying free cash flow. Now that you’re at least within the range of the targets for your debt, how should we think about cash returns going forward? Is this a year—2024—a year where we could see some more cash return for shareholders directly?

Good morning, Nitin. I think as Dennis has highlighted in a couple of his responses, and both of us in our comments this morning, flexibility and resilience are a couple of the hallmarks of the Range business and how we’re trying to build it and have built it over the last couple of years. I’ve been paid off north of $2.5 billion in debt. We’ve come a long way and repositioned the balance sheet. So one of the key principles that we have laid out in the return of capital program is, again, flexibility, optionality, rather than a hard and fast approach. You’ve seen us tilt over the last couple of years to larger share repurchase programs, and as prices come down, we favored the debt reduction. At the end of the day, as I mentioned in my opening comments, debt reduction is still a return to the equity holders. You think about enterprise value and shifting that value in favor of the equity holders. So where I’m headed with that is the balance sheet is essentially at the high end of our target range. We have positioned the balance sheet directionally where we want it, and we’ll continue to do so over the years, but we have added flexibility. So the starting point for 2024 is our program generates free cash flow. Therefore, we have optionality and will lean in and be opportunistic in those share repurchases. We certainly have latitude to make those decisions. We do favor share repurchases given the disconnect in intrinsic value we see between the underlying asset and share price right now versus a more heavily weighted dividend-type program, though a modest based dividend makes sense to us as well. So, a long-winded answer to your question, but we will remain opportunistic. If you saw a major disconnect or a major pullback for some reason, I think we certainly would look very closely at leaning in harder. So, it’s good in a free cash flow-positive program to have that optionality and have the balance sheet where we are to be able to make those decisions and respond to market conditions.

Great. Thanks for that detail. I guess my second question is also around financial, so maybe for Mark, but you talk about having hedged about 25% of your 2025 volumes, very attractive floor, north of $4. Can you talk a little bit about, now that you are kind of at that high end of your leverage targets, you certainly have a low-cost structure, how should we think about hedging going forward? Is it a formulaic 50% of volumes or does that or 25%, whatever it is, or do we see less hedging from Range because your balance sheet’s in a much stronger position?

So there’s a more philosophical objective we’re trying to achieve. We like, as a starting point, considering what it takes to cover your fixed cost of your capital program. That obviously varies by year, varies by what price is available to you, and so forth. So 2025 is a pretty good example. That hedged floor of $4.11 for 2025 at about 25% of natural gas essentially covers that fixed cost element of our cost structure, and that can be an example going forward. So it’s not so much hard-coded to that percentage, it’s what it takes to achieve that philosophical risk mitigation strategy.

Great. That sounds good. Thanks, guys.

Thank you.

Thank you. And one moment as we move on to our next question. Our next question is going to come from the line of Bertrand Donnes with Truist. Your line is open. Please go ahead.

Hey. Good morning, guys. Just want to clarify a previous answer. In your prepared remarks, you mentioned the slightly lower first quarter production level, which using your full-year range sets you up for a pretty good ramp into the end of the year. I just want to understand if that’s what we should expect in 2025, just a similar drop-off in Q1 again, with kind of that seasonal peak or do you envision maybe using the wells in process to level that out going forward or is the decision for the wells in progress just purely based on where gas prices are at the time?

Yeah. Good morning, Bertrand. We—I think the way to think about 2025 is very similar to 2023, 2022, and I would expect our production profile to look very similar in 2024. When you think about the way the maintenance program gets shaped, it does have more activity and capital in the front half of the year, and then you see those turning lines come to fruition in the back half of the year. So 2024 should look a lot similar to that, and the way we’re planning. Look, I think the way we think about 2025 today is the program starts with a base maintenance production-type scenario. So what that would present is clearly the opportunity to complete some wells early in the year that we have built up in inventory through that in-process inventory in 2024, but similar to our conversations in prior cycles, it would just translate then into some turning lines that would be more toward the midpoint of the year and into the back half of 2025.

That makes sense. And then the second one is, you outline on your full-year guide a greater than 30% liquids cut in the full guide. I just wasn’t sure if there were any moving parts on that. Is it maybe lower in Q1 and then higher in Q4, and then does that set up the next year for a higher average percentage?

Yeah. I think what you should expect from a percentage of liquids should be really similar to what we’ve conveyed. I wouldn’t expect there to be a lot of variance in quarter-over-quarter, and part of it is because the weight of our production and activity this year will be on the liquids-rich side. So we don’t tend to overcorrect. I’ll just say, the program a lot through the balance of the year, so what you will see is, I will just say, again, to that back half-weighted type turn in line profile, you’ll see our liquids contribution be very consistent with what we’ve reported in prior quarters.

I appreciate the consistent program. Thanks, guys.

Thank you.

Thank you. And one moment as we move on to our next question. Our next question is going to come from the line of Paul Diamond with Citi. Your line is open. Please go ahead.

Thank you. Good morning. Thanks for taking my call. A quick question on guidance. You guys talked about $15 million to $20 million being deployed around water infrastructure and some other kind of operational expenses. I want to get an idea of how you guys see that being deployed, whether it’s consistent over time or you see that being more summer-weighted or kind of how to think about the directionality of that when you’d expect it to be deployed.

Yeah. Good morning, Paul. I think a good way to think about how that capital would get deployed would be really fairly evenly through the balance of the year. We’re talking about small capital and really small projects in the grander scheme of things, but the majority of that’s going to be on the water infrastructure build-out. It allows us, as we’ve continued to get to this place where we’ve got 1,500 producing drilled and completed wells, you can imagine we’ve moved farther and farther from our core water infrastructure that we invested in a little over a decade ago now at this point. As we’re building that out through the balance of this year, we’ll be able to start utilizing it in the second half or the back half of the year. So I would expect that expenditure component or that bucket of spend to really be more spread across fairly evenly through the year.

Understood. Thank you. And just a quick follow-up and just touching on your guys’ philosophy surrounding those 100,000 feet of wells in progress. How do you envision those being deployed over time? Is that purely an economics-based on the fundamental pricing on the ground, or is it something you anticipate holding inventory to some level or how are you guys thinking about the eventual deployment of that excess?

Yeah. Paul, I think this is one of the—I’ll go back to kind of the fundamental thought. It really gets back to what’s the macro and the basin fundamentals, international macro, what do we—what signals are we seeing from the market that would suggest how we utilize that in-process inventory? I know we keep using the word flexibility, but we do believe that’s the right setup for us. It’ll either allow us to think about getting a head start into 2025 depending upon what pricing looks like, or it allows us to be even more capital efficient through that 2025 program, as maybe I think you’re pointing out. We could utilize that inventory without having to be in a blowdown mode, like we’ve seen maybe from some other reports.

That is the color I was looking for. Appreciate your time. I’ll leave it there.

Awesome. Thanks, Paul.

Thank you. And one moment as we move on to our next question. Our next question is going to come from the line of Jacob Roberts with TPH & Co. Your line is open. Please go ahead.

Good morning.

Good morning, Jake.

We were hoping to, if you were able to provide some commentary or even percentages as to where the wells in progress inventory sits in terms of a spud to a waiting turning line timeline.

Could you repeat the question one more time for me?

Sure. I’ll try to simplify it. Perhaps just at the end of 2024, the wells in progress inventory, can you frame if these are ducks or deferred turning lines in the mix there?

Okay. Thanks, Jake. Sorry about that; it was a little hard to hear on my end. I think as a good way of thinking about that inventory at the year end, it will be a bit of a mix. So as you can imagine, by retaining, we’ve got a really lean program. And so by having two horizontal rigs that we’re going to maintain through the balance of the year of which we would need those for a maintenance-level type program for 2025, some of the inventory that gets generated, they’re horizontal wells that basically are not getting completed, but they’ll be ready for completion right out of the gates to start the year. Some of this spend that we’ve outlined is retaining our keeping good efficiencies with our one dedicated frac crew. So if you think about it, it’s kind of a low-level program where two rigs are generating enough activity for that one base-level frac crew day-in and day-out, and it’s really as a function of the efficiencies that we’ve talked about really through our prepared remarks, 10% improvement in frac stages per day last year, and then, of course, the 38% improvement on daily drill footage on the drilling side. So it’s kind of all a byproduct of that, but we’ll have some extra fracs that we’ll complete this year, but there will be, let’s just say, in composite, there’s going to be somewhere between seven to 10 wells in total aggregate that will basically be carried into next year.

Great. Thank you. My second question is on the incremental land spend. Your comments about replacing the lateral feet drilled every year against what is a very long inventory. We’re curious how aggressive Range will be in spending these dollars, and then perhaps, in subsequent years, what the runway looks like to continue that sort of replacement rate of 500,000 versus the 650,000 kind of base case?

Well, Jake, I think the way we would think about it is; we put that framework in there from a land spend, and we view it as an opportunistic kind of view. When you think about 2023, and I’ll kind of back up for a half second, if you look at 2023 at this very time a year ago, we were communicating a plan that had an average lateral length of 10,500 feet. But by the time we got to the end of the year, and you look at the turning lines and the drilling activity, the average was just under 13,000 feet. So by nature of what we did through the year by extending laterals, some of that resulted in some opportunistic, we’ll call it open track leasing that we deployed through the year to extend those laterals, providing some of our most capital-efficient wells in the numbers that we report on. So this is a way of framing it where we think we can do this year-over-year in a lot of portions of our field, but we also have a lot of it that’s also secured that’s HPP as well. So we see line of sight for the next few years to continue to do this, and there’s also leasing opportunities we’ll just say within the heart of the field that we haven’t fully expanded on, whether it’s some of the state parks or other areas that could also provide future opportunities for us. So we see a decent runway here yet.

Thanks. Appreciate the time.

Thanks, Jake.

Thank you. And one moment as we move on to our next question. Our next question is going to come from the line of Michael Scialla with Stephens. Your line is open. Please go ahead.

Good morning, guys. I just wanted to ask about the decision to spend on some of these other things above the maintenance capital level. Are you really looking for, I guess, the main question is, why now? It’s obviously you’re looking at things in the future, but with gas prices where they are and so many of your competitors trimming budgets, what was the compelling force to spend those dollars today or this year, rather?

Yeah. Good morning, Michael. I think I’d start this by saying, look, the water infrastructure is—we’ve had a very low ongoing investment into the water infrastructure, but as an example, it’s been a significant piece of our story that supports our low capital efficiency. So this felt like the right time for us to invest in expanding that infrastructure as we think about what the future could hold for additional activity, again, as we continue to move back to pads with existing infrastructure. This really supports, again, that low-cost dollar per foot or dollar per barrel-type basis. Quite honestly, it supports recycling of water from other producers, which is a key component for low-cost water to our doorstep on location, if you will. I think the other part from a land perspective, I think we just talked about it a little bit, but we kind of see some of this as lease management but also allowing us to extend these laterals and the ability to deliver some of our most capital-efficient wells. The additional activity that’s in that bucket that’s really just not picking up three rigs, going down to one at the end of the year, and then trying to pick those other two rigs up in January. It’s utilizing existing drilling rigs. We’ve got relationships with these service partners that deliver some of our best efficiencies, which we’ve highlighted this past year. We couldn’t be happier with the direction that we’ve been moving with both the crews, the service partners, and our team. It feels like this is the right time to continue to maintain that momentum as you think about 2025. And look, we can make decisions to make changes based upon what the setup is for 2025, but we’ve got one base frack crew, and one drilling rig alone will not supply enough, we’ll just say, wells, to keep that one frack crew busy. So this is a very lean program—something that we’ve reinforced now time and time again. When you look at also some of the investments we’re making now, I guess, the other part would be this probably in a lot of ways, depending upon how you think about 2025 and 2026, could be lower-cost investments at this moment versus what we could see in the future years. We feel like it’s a good window; these are low dollars in the grander scheme of the overall value of the program, and we think it sets up a really nice story. I’ll hand it over to Mark real quick.

Sure. I think Dennis obviously just highlighted the key operational reasons and drivers. So just zooming back out to the financial point of view: Is now an appropriate time to do it? I think the simple answer to the question is yes. If you look at what the program is, we’re achieving our core objectives to generate free cash flow, fund the maintenance program, strengthen and bolster the balance sheet, return capital to investors, and prudently invest in the company. I think we check each of those boxes quite comfortably. So if you look at our reinvestment rate into D&C activity for the year for the maintenance program, it’s peer-leading. There’s a slide on page seven of our deck that highlights that. If you look over the last couple of years, Range is in the 25% to call it 50% of cash flow for reinvestment and maintenance program, depending on the prevailing price environment. Industry is at 75% to greater than 100% call on capital to hold their production flat. So for Range, Dennis’s point, this is an opportunity when we think costs are appropriate in advance of what they could be in the coming years as demand eventually does materialize and grow. We can build, again, very modest investments. Just-in-time inventory works fine most of the time, but if you can make very modest investments and have a small inventory of wealth, that’s far more operationally efficient and friendly from a cost perspective, and creates that flexibility to repeat something Dennis said earlier for 2025. Do we maintain the inventory? Do we build it, or do we have the option of using some of that if for some reason prices remain subdued? That’s the resilience and the flexibility of the Range story—why we generated cash flow last year and will do so again in 2024; we fully expect.

That makes a lot of sense, and I appreciate all the detail on that. You mentioned, Dennis, I heard you write it 29,000, and you’re a little over 29,000 for the lateral. You keep pushing these things further and further. I guess, as you do that, does the infrastructure there, does that create any infrastructure requirements for the longer laterals, and do you see any—have you had any issues producing these longer laterals over the longer term?

Yeah. We’ve actually seen good repeatable performance out of the wells, no issues on the operational front from—I’ll just say the ability to complete these wells. Also, production facilities at the surface haven’t; we’ve upgraded some of our design over the course of time, but what we haven’t done, Michael, is tried to design them for peak production. So, we keep the infrastructure fully utilized, and we basically keep our cost structure as low as possible by doing so. I think we have the ability to continue to do this for quite a while, so it’s pretty encouraging the way we’ve set up the design. So, it keeps us from basically spending, I think, too much money inefficiently on the facility design by trying to reach that peak performance out of the gates, knowing that, whether it’s in the months that follow, we’re going to basically be well within the limitations of that equipment.

Thank you. Appreciate the answers.

Thanks, Michael.

Thank you. And one moment as we move on to our next question. Our next question is going to come from the line of Leo Mariani with ROTH MKM. Your line is open. Please go ahead.

Hi, guys. I want to just hit on a couple of the numbers here. I appreciate some of the detail on the taxes. I think that’s always helpful for the analyst community, but just to kind of maybe dumb that down a little bit for me here. Did I hear that you guys are maybe expecting around 80% shield on your cash taxes on the federal level in 2024?

In 2024, I think you’re going to be better than that. We’ll defer taxes. The first layer of the federal NOL, call it, $160 million, lets you offset 100% of your pre-tax income, and you still have the annual deductions for that year. Then there’s the next layer that allows you to offset up to 80% of taxable income. So in 2024, at the federal level, I would expect minimal taxes. The effective tax rate probably looks quite similar to where we were in 2023, and for the next couple of years, you might slowly, as you move into that second layer of NOLs, where you’re shielding or deferring taxes on 80% of your income, you would still have several years to work through, a couple more years in any event, 2026 and probably into 2027, before you start to see any material sort of uptick.

Okay. That’s nice to hear for sure. And I just wanted to follow up a little bit on what you guys were saying on kind of cadence of capital in production. Appreciate you giving that first quarter production number. It sounds like it’s down about 5% versus the prior quarter. You did mention that you are looking at potentially deferring some turning lines with the weaker gas prices here. I’m not sure if that’s a factor in the first quarter or maybe it’s just fewer turning lines here and perhaps some maintenance. And then just on the CapEx side, you did say it was a little more front-end weighted. So, any help on that? Should it be like 55% in the first half, just trying to get a little sense of the cadence on the production and the CapEx here in the near term?

So I think a good way to think about our production is it’s going to feel very consistent in, I’ll say, a normal profile to what we delivered actually last year. So you might see that character move a little bit where our low point is going to be more; I think it’s going to look like Q1 instead of last year, it was more Q2. But if you look quarter-over-quarter, the profile is very consistent. Having the one frac crew, again, as we’re kind of churning through our turning lines, you’re going to start to see that production profile then start to manifest itself through Q2, Q3, and Q4, and with the peak being clearly in Q4 as we get ready to walk into the winter of 2024 and 2025. But it’ll be really consistent with the profile that we’ve delivered the last couple of years. It’ll look kind of business as usual for us.

Okay. No, that’s helpful. And then just any comment on the capital? I know it’s front-end weighted, but is it significantly front-end weighted or maybe just a little bit because I know you guys are talking about some of that extra capital, which might happen late in the year this year?

Yeah. I would expect the capital to look, again, real similar to last year. All-in-all, service cost on a quarter-over-quarter basis, service costs really have moved down a little. You would expect to see, I’ll just say, mid-to-low single-digit relief in that front. But as you look through the year, our quarter-over-quarter capital reporting from 2023 should look pretty similar.

Okay. Thanks, guys.

Thanks, Leo.

Thank you.

We are nearing the end of today’s conference. We will go to the line of Noel Parks with Tuohy Brothers. Your line is open. Please go ahead.

Hi. Good morning. Just had a couple of things. You were touching on the service cost cycle just now, and I wonder if you—this last cycle of inflation was pretty unusual with kind of everybody coming back online after COVID. I just wonder kind of where we have some operators talking about slowing their rig activity, rig and frac activity. Do you have any sense of where we are or might be headed in the service cost cycle? Are we headed back to, say, 2019 levels, do you think?

Yeah. Good morning, Noel. I think I would start off by saying it’s early, and it’s tough to kind of frame, I think, at this point what the math and the calculus could really look like. I do think that you’ve probably heard me say this in the past when service costs have come up, and I do think that this environment that we’re in could look and feel a little different than past cycles where you have traditionally, let’s say, commodity prices up, service costs up; commodity prices down, service costs down. I think it’ll be a blend of those, and I think we’ve already seen that through the balance of 2023, where we’ve seen relief in areas like tubular goods, as an example, and maybe some of the other consumables that we’ve had or that we utilize in some services. However, as you would imagine, on the electric fracturing fleet side, those fleets are in very high utilization, so it’s certainly created its unique demand, if you will. So drilling rigs, we’ve all coalesced to kind of a similar super-spec rig configuration where we’re all drilling along laterals across multiple basins. That’s provided, even though some rigs will certainly come out of the mix based upon some of the recent reporting, I would expect there to be some relief potentially there. But it’s got to play out with some other rigs that could potentially drop out of the mix in the next three months to six months. I think we look at last year as a trend. It took a while for us to see some relief, and it probably came more at the mid-year point than it did in Q1. So, we could see some relief, but I think it’s still early, and know that as you look at our capital efficiency numbers, and really just the overall cost per foot values that we’ve reported in the past, because of our strong relationships and history with our service providers and our service partners, know that we’ll look to basically take opportunities when we can to work together and reduce costs, because we know at some point in time it will probably go the other way.

Got it. And I just was thinking about the commodity price environment and weak winter weather and a weak heating season is a movie we have seen before. We’re still pretty much everyone focused on the uptick, or I should say, the step-up in demand that we’re going to see in the next couple of years with LNG capacity. It kind of seems like we have the speeding trains headed to each other where you have seasonality having its traditional effect this year. But we know that there’s a big ramp-up of demand coming. Do you think we are getting to the last years or the last innings of having things be so heavily impacted by winter weather as far as demand? Because it just seems like at some point—and I don’t know if it’s really in the strip yet—at some point, these factors kind of have to collide, it seems to me. So any thoughts you have on that would be great.

Yeah. A good question is something we talk about, as you can imagine, pretty frequently here in the shop. I think when you start to think about LNG demand that’s going to be coming online through the balance of this year between now and 2028, when you look at ResCom Industrial, you look at exports to Mexico remain really resilient. You start to factor all of that in and plus power burn, what we saw last year. In my mind, a little bit of an underappreciated story on the repeatability of that as you start to see at times underperformance by some of the other alternative power sources. When you start to factor all of that in, we really see that you’ve got to get to 126 BCF, 125 BCF of overall demand by 2028, and where we stand today, there’s a significant delta there. LNG is going to play a role in this, but LNG is not going to be the only factor as you start to consider demand growth on the go forward. We think infrastructure is going to need to play a really key part to this, and so whether it’s advancing permit reform or other conversations around utilization and brownfield expansions, it’s going to be key to meet some of this growing demand. I haven’t even touched on coal retirements and other sources. When you look at some of the infrastructure that’s going in from a manufacturing standpoint, it’s associated with some of the chip development and other processes. We kind of see there’s a real opportunity for us to continue to move toward trading like a global commodity and less being influenced by weather alone.

Great. Thanks a lot.

Thank you, Noel.

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

I’d like to thank everyone for joining us on the call this morning and walking through the results from Q4 and the plan that we have ahead. If you have any questions, feel free to follow up with our Investor Relations team. We’ll see you in the next quarter. Thank you.

Thank you for participating in today’s conference. You may now disconnect.