Range Resources Corp Q2 FY2023 Earnings Call

Welcome to the Range Resources Second 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 the 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.

Thank you, operator. Good morning, everyone, and thank you for joining Range’s second 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 slides on the call this morning. You will also note that our 10-Q can be found on Range’s website under the Investors tab, or you can access it using the SEC’s EDGAR system. We'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliation to 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. As we pass the midpoint of the year and shift our focus on the remainder of 2023, Range's business plan is on track, while we continue to make steady progress on key objectives. I believe this quarter's results reflect the resilience and durability of Range's business. Range's competitive cost structure, low capital intensity, liquids optionality, and thoughtful hedging allowed us to generate healthy full cycle margins despite cyclically low commodity prices. During the second quarter, Range successfully delivered on our operational plan safely and with peer-leading efficiencies. We generated free cash flow, despite low commodity prices, and retired a portion of our debt maturing in 2025. We also published our latest corporate sustainability report last week, showcasing our low emissions intensity and ongoing safety and environmental leadership, all made possible by our dedicated team. As we walk through the results of the quarter, each highlight underpins the durable and repeatable nature of our program that starts with the quality and quantity of Range's inventory along with our talented team. Looking forward, our objectives remain consistent with us keenly focused on areas discussed on prior calls, peer-leading capital efficiency that supports our low breakeven costs, a program that generates free cash flow through the cycles, continued return of capital to shareholders, and prudent capital allocation that balances further debt reduction, opportunistic share repurchases, and the long-term development of our world-class asset base. Whether discussing the results during upcoming calls or today, our results and initiatives align and support these strategies. As we look back on the second quarter, all-in capital came in at $175 million, while capital spent for the first half of the year totaled $326 million, placing us firmly on track versus our stated plans. During the early part of Q3, activity was reduced to a single horizontal rig, where we will maintain for the remainder of the year. Our base track crew will also remain with us through the end of the year, with a second spot crew slated for release late in the third quarter. As previously discussed, this will result in a decreasing capital spend across the second half of the year, while production radically increases, which aligns favorably with today's shape of forward commodity prices. Production for the second quarter came in at 2.08 BCF equivalent per day, which is slightly ahead of guidance provided during our prior call. The scheduled infrastructure maintenance and upgrade projects were completed on or ahead of schedule, providing uplift to the quarter, versus our prior guide. Supporting our production profile, we turned to sales 11 wells located across our dry, wet, and super-rich acreage, with the bulk of these wells on pads with existing production, creating some of our most capital-efficient operations. Turn-in-lines for the year are expected to peak in Q3 with turn-in-lines weighted towards the back half of the quarter in conjunction with the commissioning of additional wet gas compression. They should drive sequential growth of approximately 30 million cubic feet to 50 million cubic feet a day in the third quarter and aligns with our production plan for the year, while generating an end-of-year production level of approximately 2.2 BCF equivalent per day. And to reiterate an earlier message, we see this production profile as a complementary setup as commodity prices improve after the shoulder months and into the winter. Looking at operations, the drilling team continued to improve efficiencies and set new program records during the second quarter. 24 wells were drilled in our Southwest Pennsylvania dry and wet acreage positions while returning to pads with existing production for the majority of our activity. The average drilled lateral length during Q2 was approximately 12,400 feet or a 5% increase versus the 12,000 average. As part of Q2, the team also added four wells with lateral length exceeding 20,600 feet. These represent the longest laterals drilled in the program's history with the longest measuring just under 22,000 feet. In addition to drilling our longest lateral, the team also showed great efficiencies, with 24-hour periods in excess of 6,000 feet. As a result, our average daily lateral footage drilled exceeded 4,700 feet per day in Q2, representing a 42% increase versus the 12,000 full-year average. This was driven by rig equipment changes that could benefit future development programs. Completions also improved efficiencies and set new program records as the team averaged over 10 stages per day throughout the quarter, including a 24-hour record of 17 stages. As a result, the first half of the year averaged 9.3 frac stages per day, representing a 13% increase versus the 12,000 full-year average. Supporting this accomplishment was the utilization of our improved completion surface equipment configuration, enhanced logistics, and the benefit of returning to existing pads. On our previous call, we mentioned a pad that was being completed during the first quarter and was projected to be one of Range's most overall efficient pads. This particular operation consisted of four wells located in our wet acreage and was completed and turned to sales during the second quarter. On this pad, operations were able to capture two of our top-fastest days drilling in the lateral and the highest overall completion efficiency for a wet area completion, with the water and logistics team setting new records for water handling by eliminating unnecessary wait time. Overall, the pad cycle time from spud to first sales was just over 180 days, for 65,000 lateral feet of combined wellbore, more than a 50% improvement versus a similar area pad developed in 2021. This ongoing improvement is a byproduct of the use of new technology and the hard work from our operational groups in Pennsylvania. I congratulate the team on this accomplishment and know that they will continue to look for ways to further support our peer-leading capital efficiency. Turning to supply chain, in the last few months, rig count started reflecting signs of decline in the basin as activity decreased under the current commodity environment. Range has also observed some softening in other OFS categories. As we work through Q3 and deploy our annual bid process, we will continue to follow the market and pursue savings opportunities. As we look towards 2024 and beyond, we expect Range to remain at the low end of the capital cost curve. On NGL macro, we believe the historically low prices we saw in the second quarter are set to improve later this year. LPG exports out of the U.S. have been robust as the three-month rolling average reached a new record exceeding 2 million barrels a day in April, connecting U.S. LPG supply with recovering petrochemical demand and increasing propane capacity in China. This growth in exports, coupled with moderating supply growth out of the U.S., is expected to bring storage levels back into balance later this year. Looking at ethane, prices are off their lows. And fundamentals remain supportive as the U.S. has set records for both domestic and export demand with year-to-date 2023 averaging 2.5 million barrels a day or 62,000 barrels a day higher than this time last year. For Range, our uniquely positioned NGL portfolio positions us well to capture opportunities both international and domestic and supports our 2023 NGL guidance range of $1 per barrel discount to $1 per barrel premium relative to the Mont Belvieu index. This liquids optionality is a positive contributor to Range's resilience through cycles as was the case this quarter. On the natural gas front, we are encouraged by continued gas power generation strength this summer. When paired with minimal dry gas production growth expected from the Haynesville and Permian over the next several quarters, we see the domestic natural gas market gradually rebalancing later this year before further strengthening with increased LNG exports next year and beyond. As we have discussed on prior calls, Range's successes are rooted in a culture focused on safety and the environment. During the quarter, Range completed the MIQ certification process and received an A grade with a third-party audit covering our Southwest PA assets. Range's LDAR inspection program, which increased in frequency to 8 times per year at the end of 2022, and source-level production facility design, detection and mitigation practices were recognized by the audit and helped us maintain one of the industry's lowest emissions intensities. For safety, we observed further improvements in our safety performance in the field in Q2 with zero OSHA incidents for the quarter. You can find more details on these accomplishments and others in our corporate sustainability report that was released last week. As we clear the midyear point and focus on the second half of 2023 and beyond, our program is on track. After drilling over 1,500 Marcellus wells, the team continues to advance our overall efficiencies. Delivering on repeatable well performance across our large contiguous inventory and marketing our production to diverse outlets providing enhanced margins. As I mentioned on the prior call, the resilience of Range's business is being demonstrated in today's challenging price environment, as we're still delivering on stated objectives and generating free cash flow for 2023. I'll now turn it over to Mark to discuss the financials.

Thanks, Dennis. The second quarter was successful operationally and financially, with solid execution across the business. Cash flow totaled $187 million, funding capital expenditures and the quarterly dividend while maintaining balance sheet strength and a trajectory to our target capital structure despite what we expect are near cyclical lows in commodity prices. 2023 commodity prices have obviously been softer than last year and are below the level that can sustain industry production levels. Fortunately, Range is equipped with one of the lowest full cycle breakeven costs in the business. The benefit of going through a period of low prices is the visibility into the economic durability of assets across the E&P space. Given the economic resilience of Range's portfolio, our goals and expected plan for 2023 are consistent with last year despite different prices. We'll develop high-quality assets, generate free cash flow, return capital to investors, strengthen our business, and enhance our position to participate in continued demand growth through our low-cost, long-life inventory. This is in stark contrast to higher-cost, shorter-life assets where operators are seeking ways to reduce outspend, in many cases, by allowing production to decline. Taking a closer look at Range's second quarter results, cash flow of $187 million was driven by strong production levels, achieving pre-hedge realizations of $2.47 per Mcfe. This realized unit price is $0.37 above NYMEX Henry Hub, receiving the benefit of Range's diverse sales outlets for natural gas and the pricing uplift from natural gas liquids and condensate. During the second quarter, Range's realized NGL price was $21.51 per barrel or $3.58 on an Mcfe basis. Range's portfolio of transportation capacity and customer contracts supported differentials, such that the total per unit price received by Range remains a strong premium to Henry Hub Natural Gas. In addition, Range's approach to hedging provided an improvement to per unit realizations of $0.41 for a hedged realized price of $2.88 per Mcfe. Hedged cash margin per unit of production was a resilient $0.97, benefiting from a persistent focus on efficiency and the price-linked nature of certain costs. Total cash unit costs improved by $0.32 versus second quarter last year. The change from prior year primarily relates to savings in processing and power costs, which are related to NGL and natural gas prices, with variations in other line items relating to labor cost inflation or the timing of planned workover projects. Cash interest expense declined by $9 million for the quarter compared to Q2 last year on reduced debt balances equating to $0.05 per Mcfe in savings. These improvements more than offset slightly higher LOE as we wrapped up planned annual workover projects early in Q2. Looking quickly at gathering, processing, and transportation costs, we have improved our annual guidance for that line item by approximately $0.05 at the midpoint. As mentioned on previous calls, processing costs tend to move about $0.01 per Mcfe for every $1 per barrel move in our realized NGL price. For context, since the start of the year, NGL strip prices for 2023 are lower by about $4 per barrel, and that is being reflected in our improved GP&T guidance, showing the right way risk and the natural hedge that our processing contract provides. Range's financial hedging program supported realized prices for the second quarter with approximately $90 million in NYMEX related gains. Looking forward, Range's natural gas is approximately 50% hedged for the balance of 2023 with an average $3.42 floor, providing further support to Range's free cash flow profile. For 2024, we've hedged approximately 50% of natural gas at an average floor price of $3.70 using a combination of $4 swaps and collars retaining upside to roughly $5.50. During the quarter, we initiated a modest 2025 hedge position on natural gas at an average price of $4.12. The objective of this program is essentially to cover fixed costs at attractive levels, enabling consistent free cash flow generation, while maintaining exposure to a market poised we expect to positively respond to new LNG facilities coming online alongside rising power demand with the current backdrop of reduced industry drilling activity. Turning to the balance sheet. At the end of Q2, we held cash balances of $162 million, with the change from last quarter primarily deployed to repurchase bonds due in 2025 at a modest discount to par, totaling $62 million in principal. 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 it peaked in 2018. This places us very close to entering our target range of $1 billion to $1.5 billion net debt. With current leverage of 0.9x debt to EBITDAX 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 business cycles. Successful second quarter results, 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 stable, 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, alongside our primary objective of reaching target debt levels, we will remain flexible and adapt to market conditions, project returns, and prudent reinvestment. Range's story for a long time has been about innovation, translated into reality through dedicated teamwork, hard work, focus, and swift but precise adjustments to our business plan without varying from our core objectives for demonstrating the value of Range's portfolio and business. This focus and dedication will continue as Range's business is strong and is primed for impending demand growth domestically and internationally for natural gas and natural gas liquids. With a strong financial foundation and the largest portfolio of quality inventory in Appalachia, paired with transportation to delivery points across key U.S. and international markets, we seek to continue this trend of disciplined value creation for our shareholders. Dennis, back to you.

Thanks, Mark. Before moving to Q&A, I'll reiterate a message we've shared previously. As the world continues to move towards cleaner, more efficient fuels, natural gas and NGLs will be the affordable, reliable, and abundant supply that helps power our everyday lives by also helping billions of others improve their standard of living. We believe Appalachia natural gas and natural gas liquids are positioned to meet that future demand. And within Appalachia, Range will be among those leading the way on capital efficiency, emissions intensity, and transparency. Range has de-risked a large inventory of high-quality wells across our 0.5 million net acreage position in Appalachia and translated that into a business capable of generating free cash flow through commodity cycles. We are in the best position in the company's history, and I look forward to our next many calls together as we continue to demonstrate our dedication to safe, efficient operations and consistently generating sustainable and competitive returns for our shareholders. With that, we'll open the line for questions.

Our first question comes from Bernard Don with Truist. Your line is open. Please go ahead.

Hey. Good morning, guys. Just wanted to talk about the turn-in-line disclosure versus the percentage of CapEx so far this year. I'm assuming there's something in there about how much capital you may have put towards wells that are ready to be turned to mine or completions, but that aren't captured in your turn-in-line schedule. So just maybe you could address the lower percentage of turn-in-line so far versus the higher CapEx.

Thanks for the question. In the first half of the year, we began with a couple of drilling rigs and added a third horizontal rig as we approached the end of Q1. Looking at Q2 in terms of drilling activity, it became our most active period. On the completion side, we maintained a base frac crew throughout the first half of the year, and this crew will continue to support our program for the remainder of the year. We also brought on a spot frac crew in the final weeks of Q2. As you consider the spending percentages between completion and drilling, you can see a shift in our capital profile because of the different activity rhythms. A significant portion of our turn-in lines from drilling is set to generate sales and production starting in Q3, particularly toward the latter part of the quarter. About one-third of our turn-in lines are scheduled for Q3, with most occurring in the last few weeks of the quarter. This outlines the activity layout for the rest of the year. In Q4, we expect activity to decrease, similar to what we experienced in Q1 and Q2.

Great. And then the follow-up is kind of on that point. If you do have a very light maybe end of the year, maybe the last 1.5 months or so, program, we're looking at a pretty attractive strip maybe 1Q, 2Q of next year? Is there some discussion going on internally on whether or not you might want to pull some of that capital from '24 to '23 if the commodity environment suits it?

Yes, good question. I think those are questions we always have internally to make sure that we're optimizing not only this year's program, but we're thinking about what's best as we start to look forward as well. We've got a history of demonstrating to be at or below our communicated capital guidance. But one of the reasons why we added some of our capital flexibility this year for some of the inventory that was at $30 million that we communicated as part of our annual plan was to allow for that kind of optionality. Maintenance is really below the 615 level, which is the upper end of our guide. But having that flexibility to be at the upper end of that capital guide allows us to consider what's the proper setup for 2024. What does it look like to maintain activity or a particular rig that maybe you're going to retain for that last month or 1.5 months? So it's all part of optimizing that end of your portion of your program and setting up for 2024. So we'll absolutely have those conversations internally. They'll be necessary in both not only this year but in future years to come.

One moment for our next question. Our next question comes from the line of Umang Choudhary with Goldman Sachs & Company. Your line is open. Please go ahead.

My first question was on cost inflation. Any color you can provide on leading-edge material, labor, and service costs and the implication of lower costs heading into 2024?

I'm going to expand on the response we provided during the last earnings call. It's still a bit early to determine what 2024 will look like. The positive news is we're observing a reduction in the number of rigs. Comparing the end of December 2022 to last week, we have around 110 rigs that have been decommissioned. The Haynesville area is now operating at about 45% to 46%. Similarly, Appalachia is at a comparable level, with other rigs removed from different basins that had activity in the past two years under varying pricing conditions. This situation has sparked discussions about rig availability for 2024. We're noticing initial signs of relief in areas like tubular goods, influenced not just by rig activity, but also by supply catching up with previous demand and inputs in the supply chain normalizing. Additionally, there's some availability emerging in supporting equipment for our daily operations. As we prepare for the bidding process this fall, we anticipate a much clearer picture of what 2024 could entail. Overall, we are optimistic about the relief we are seeing, but we recognize that certain equipment, such as e-fleets on the frac side and high-spec equipment for long laterals, will continue to be in high demand. While we expect some pricing relief from service perspectives, the complete materialization of this is still pending. We're also continuously witnessing adjustments in the total U.S. rig count. Lastly, concerning service perspectives, we aim to be at the forefront of capital efficiency alongside service costs. Historically, as we've discussed in previous meetings and calls, Slide 7 illustrates where we currently stand. When examining the cost per Mcfe for molecule replacement on a declining annual basis and factoring in our low base decline along with our record-setting efficiencies, we find ourselves at $0.76 per Mcfe replacement compared to a peer average of $1. This indicates that, regardless of how the situation unfolds, we believe we will remain at the forefront thanks to our team's performance and the strategic position we are developing.

Got you. That's very comprehensive. My next question was on hedging. You are now 50% hedged for next year at a $3.70 floor. This is very in line with the past commentary of covering fixed costs and capital commitments given your bullish outlook for 2025, how are you thinking about hedging for 2025? Do you plan to hedge more to cover the fixed cost and the capital commitments or are you happy with the low 20% exposure that you have right now?

I'll start this one off. I think you've touched on the theme, the philosophy behind our hedging program, and that is largely essentially to cover the fixed costs and maintain exposure to a strong market. Obviously, with LNG facilities being commissioned over the next year and two, we expect a significant re-rating in the commodity price. One of the best places to be as a corporation is in a position where you don't have to do something. Having paid off $2.5 billion of debt places us in a position where hedging is not necessarily something we have to do, certainly not to levels that are extremely high, like the 70, 80-plus percent levels you might have seen 5 and 10 years ago across the industry and at Range specifically. So where we sit today, we've got just a tiny bit to do on the balance sheet before we enter our target net debt level. So as you look at the '23 hedge position and approximately 50% of gas, and you look at 2024, we've got just a little bit, as I said, of progress work yet left to do. You also have the construction of the in-service timing into 2024 of the new facilities and that re-rating of demand, making its way into the forward curve. So as you look into 2025, it's a modest foundation. We think that current position is sufficient to cover fixed costs. So as I started, we're in a position where we don't have to do anything. We like the hedge book where it is. We think that meets our risk management objectives and to turn it around. That means while we are encouraged by the way 2024 is set up, we're 50% hedged, but we're 50% unhedged. And for 2025, we have a good foundation, but we're 80% unhedged, and we'll be responsive to market development between now and then, we'll monitor the cadence of construction in service and demand and what the forward market may offer us. But having said all that, again, we like the book where it stands. It covers our basic philosophical objectives.

One moment for our next question. Our next question comes from the line of Leo Mariani with ROTH MKM. Your line is open. Please go ahead.

I was wondering maybe you could just talk a little bit about sort of capital allocation here. Obviously, you decided to buy back some bonds in the open market at a discount, which always seems to be a good use of proceeds. But as a result, we didn't really see anything on the share buyback side. And maybe you could just kind of give us a little color in terms of how you're kind of thinking about using that free cash flow for the balance of the year and how you kind of decide between debt paydown and buybacks.

Sure. Liam, I think where I would start with our waterfall of capital allocation really is all based on the assets. When you're talking about an asset base that's got 30 years of drilling activity, producing a 50-plus year type productive horizon, you're trying to make sure that you have a financial foundation of a company that will comfortably navigate through cycles and capitalize on the opportunities that are presented to it. As I said, the best place to be from a corporate perspective is to not have to do something. So where we are today is we've made great progress on the balance sheet, but that does remain a priority. As we've talked about before, funding our key objectives: one, maintenance capital; two, debt reduction; three, shareholder returns, be it the dividend or the share buyback; and four, growth when appropriate. So where we sit today, obviously, commodity prices are lower and by definition, cash flow is a little bit lower. As we sit and look at the performance of the various securities and where the prices are and being able to pull in bonds, the use of our free cash flow this year to reduce debt and enhance equity owners' value through that path, sees them as fruit. Now having said all of that, one of the keys to our capital allocation plan and our return of capital program is the opportunistic element. The reason it's not purely formulaic is that the market moves, interest rates are obviously moving around, and commodity prices are moving around. That we want to be able to allocate capital in a nimble and prudent fashion. So debt is certainly the priority, but that waterfall of capital allocation, as I said before, is not mutually exclusive. If we were to see a big pullback in the market, for example, recession fears, obviously, are being chatted about what happens to the economy more broadly. If there's a broad-based pullback in the equity markets, Range has $1.1 billion available on our current program, and we believe that the balance sheet strength would certainly give us the opportunity to step in and buy back shares if we were to see any sort of retracement. So for the time being, we're comfortable with that methodology. That approach to debt is the priority, but we clearly will make use of the share repurchase program just as we have for the last two years.

Okay. And then just as a quick follow-up. Obviously, Range has sort of been in maintenance mode on production for quite a few years now. Obviously, you guys talked about the upside expected in both gas and NGL markets as we get into '24 and even more so in '25 on gas. What's kind of the latest thinking in terms of that sort of maintenance mode on production? Is that something you think is likely to continue in '24 and then maybe it's '25 perhaps there can be a slightly different decision on that with just higher LNG exports and potentially MVP coming on in '24? Just any color around that would be appreciated.

You bet, Leo. As we think about 2024, I think a good starting point is to always think about maintenance for our program. That's about 60 to 65 wells kind of year in and year out to hold our assets flat in our current infrastructure utilized. But as we start to look forward, I mean, there are several reasons to have a positive outlook. Some of them we've touched on either through Q&A or through prepared remarks today and in prior calls, LNG clearly being one of them. We're still optimistic that MVP reaches a place where it's commissioned, and all of that starts to have a positive outlook. But the other part is inventory exhaustion. And I think as you start to look more and more around not only Appalachia but other basins, you're starting to see that conversation get elevated along with degrading well performance year-over-year. We think that all is positive when you think how it aligns back with Range's long runway of inventory and our ability to potentially grow in the future. But growth is going to really come back to a point of what both the basin fundamentals point to and also the macro. So we'll be patient. We'll look at what the best program is for '24 and beyond. But the way to think about it today is to consider our program to start from a base of maintenance.

Our next question comes from the line of Roger Read with Wells Fargo. Your line is open. Please go ahead.

Thank you. A couple of questions. On your capital efficiencies, you talked about cutting spud to first production to 180 days, obviously, pretty impressive as we think about your outlook for the latter part of '24 and '25, which I don't think we have any disagreement with. As you increase activity, what things can you do now? What best practices or learnings have you put in place that are going to allow you to maintain capital efficiency as rig counts go back up as spending goes back up in the space and presumably, you'll want to add production as well?

Yes, Roger, I think we can approach this conversation in a couple of ways. One way is to examine our efficiencies and service costs in relation to overall capital efficiency. Our Q2 results clearly demonstrate the team's capability to achieve significant efficiencies, as evidenced by a 13% increase in completion, frac stages per day in the first half of the year compared to last year's full-year average. Additionally, the accomplishments in drilling footage, primarily around previously producing activity and returning to pad locations with production, highlight this progress. As an old supervisor once said, "success begets success," and the teams are continuing to build on that momentum. We anticipate further advancements in our efficiencies in '24 and '25 as we move back to those pad sites. The second aspect is our ongoing efforts to minimize non-productive time. Returning to pad sites provides us the opportunity to improve our logistics management, such as through our water recycling program. This not only brings cost savings but also enhances overall efficiency, acting as a force multiplier. We see potential for improvements in this area as well. Moreover, our long lateral development is crucial, with our latest drilled laterals exceeding 20,000 feet this past quarter. We are eager to see these wells come online in the coming quarters and evaluate their performance, as we believe they will play a significant role. However, capital efficiency will vary as we discuss potential low-level growth in the future and the type of inventory that may be included. Nevertheless, we expect to remain at the forefront in terms of cost-per-foot as we implement our programs moving forward.

I appreciate that. The other question I had is about the best way for you to respond. We have seen a significant increase in pricing recently, especially for ethane over the past month or so. You provided a generally optimistic outlook for the NGL sector, so I’m curious if there’s anything specific that explains the strength in the pricing recovery.

Yes, thank you, Roger. This is Alan Engberg, and I oversee our liquids marketing business. I’d like to provide some context on the recent strength in ethane. Ethane fundamentals have been quite tight for some time. Last year, the days of supply dropped to five-year lows, and we have maintained those low levels throughout this year. In such a tight market, there’s minimal room to absorb changes in supply and demand, which has been evident in June and so far in July. There are several factors driving this situation. First, let's talk about costs. We saw a significant increase in pipeline costs this year, which raises the baseline for ethane recovery within the industry, leading to more ethane rejection and a decrease in supply in June. Additionally, extreme heat during this time incentivized rejecting ethane and selling gas locally instead. This heat also impacted fractionation efficiencies, especially since ethane is the lightest molecule and requires substantial cooling, resulting in a loss of about 5% to 8% efficiency. Moreover, fractionation capacity in the U.S. Gulf has become increasingly tight, similar to patterns we observed in 2018. Presently, it's difficult to quantify the impact, but we believe that the level of unprocessed ethane, referred to as Y-grade, has increased compared to processed ethane. The ethane inventory includes both processed products and other mixtures, but due to limited fractionation capacity, there’s been less availability of pure ethane. As we moved into late June and early July, following the ethylene maintenance season, demand rose while supply shrank, which caused ethane prices to surge. Looking ahead, we expect continued tightness in the market, and while the outlook appears positive, we’re hesitant to predict that prices will remain in the 40s. This caution stems from anticipated relief in fractionation capacity in the latter half of the year, as two major midstream companies will add a fractionator of about 150,000 barrels per day each. Nevertheless, we anticipate that ethane inventories will remain near the lows due to increased operating rates and new demand, keeping the market tight throughout this year and into the next.

Our next question comes from the line of Michael Scialla with Stephens. Your line is open. Please go ahead.

Denis gave a lot of detail on OFS costs. I guess based on what you're seeing right now, is it fair to frame it that you would expect to see some savings on rig day rates and ancillary costs, but not really on frac crews? And can you talk about the cost of that spot frac crew that you added versus your contracted rates and maybe how the efficiency compared as well?

Absolutely, Michael. The spot crew we recently brought on is more aligned with current pricing structures, which has its advantages and has proven to be very efficient. We are pleased with the results so far. The first pad has been completed, and it aligns well with the performance of our base frac crew, which will be responsible for most of the year. This demonstrates not only the repeatability of the procedures our teams have implemented, but also the improved efficiencies many service providers have achieved through routine operations and maintenance. The pricing for the spot crew matched our expectations for the current available equipment, allowing us to secure competitive spot pricing. This crew will work on another pad site for us in the latter part of the quarter before being released, after which we'll return to our base frac crew for the rest of the year.

Okay. So if I heard you right there, you are seeing some improvement in prices even on the completion side as well.

There are some small signs of relief. But again, I'll phrase this as small only because that was a spot crew utilization versus being able to leverage that pricing into a full year of, we'll call it, day-in and day-out activity for 12 months. So though it was small, I would say it was difficult to quantify a bigger picture.

Understood. And you mentioned your new sustainability report. I guess I want to see what needs to happen for you to get to net zero scope on two by 2025. And can you say how much will be through offsets versus actual abatement and maybe any targets beyond the '25 goal that you're thinking about?

Yes. As we start to think about the next couple of years, we've got a keen focus on how we can continue to directly reduce our emissions from our operations efficiently, economically, and responsibly, like we've really executed the rest of our programs, whether it's drilling and completing a well, producing or reducing our emissions. It's the same culture, the same approach regardless of what the topic may be. So we've got still a keen focus on further reductions in that regard. We're looking at ways that we can look at reducing emissions associated with combustion of fuel on our particular operations. As you can imagine, it's small incremental bolt-ons, but it could be as little as switching over to electrified power plants on location for lights and ancillary power versus traditional diesel or gasoline fuel type equipment, coupled with our E fleet, of course, on the fracking side. Carbon offsets will play a role, and it is something that we communicated for the first time in our sustainability report to start outlining Range's approach. What we don't want to do is really, I will just say, we want to bridge the gap effectively with those carbon offsets with good quality offsets but remain at the same time, keenly focused on how we can directly, economically, and efficiently reduce our emissions off-pad.

Our next question comes from the line of Paul Diamond with Citi. Your line is open. Please go ahead.

Just a quick question regarding the specific pad and wet acreage that contributed to your highest overall efficiency. How should we consider the application of those techniques and that level of efficiency to some of the dryer acreage? Should we view that as a direct correlation, or is there some variation to consider?

Thank you for your question. At this point, I would say we don't see an immediate way to apply this across the entire basin, but we will move in that direction. This includes redefining staging areas and optimizing trucking routes for water transportation. It's a process that can evolve quarter-over-quarter, leading to improved efficiencies. Over time, we believe this could become a new standard and a repeatable metric, which is part of what we're communicating today. However, we may not fully achieve this standard by 2024, as we recognize the diversity in access and drilling methods across the field and the variability in lateral lengths. Our average program has typically been around 10,000 to 12,000 feet, but we occasionally see lateral lengths of 18,000 to 20,000 feet depending on asset development locations. We anticipate that these approaches will eventually be applicable to the dry gas and super-rich areas. It will take some time to incorporate our recent learnings into future development.

Understood. I have a follow-up question about the overall market. You mentioned a decrease in nationwide activity. Given the current strength of the 2024 and beyond projections, when do you anticipate that activity will start to recover? Do you think prices need to increase significantly, or do you expect a plateau in the run rate throughout 2024?

I think as you think about '24 today, I mean, I think you're going to have to see a little bit more from, let's just say, development of the LNG infrastructure. Again, I'll kind of start off with base for us is the starting point. But as you start to think about '24, the LNG infrastructure that's coming online, all signs point to it being on time, I think, which is clearly encouraging. But to get to the other side of inventory levels that we're going to have at the end of the injection season, seeing what kind of winter that we have, we see this being as more of a constructive outlook as you start to get into the bulk of 2024. So that's when I think you start to see us have the flexibility of the program to then assess what level of activity best aligns with both those basin fundamentals and the macro and then setting us up for 2025.

Thank you, and one moment for our next question. Our next question comes from the line of Jacob Roberts with TPH & Co.

Just curious on the GP&T guide, looking at where Q2 came in and kind of the expected prices, I believe, on Slide 34 in Q3 and Q4, it looks like that guide has the ability to head even lower. So just I'm curious on the assumptions being baked in there.

Yes, this is Mark. I'll start with that. We have six months of experience with NGL prices and current gas prices, as well as factors such as electricity costs related to compression. When we analyze the future trends for each product and consider the processing and transportation costs along with estimated power costs for the second half of the year and into winter, we anticipate seeing some higher prices once we move past the injection season and gain a better understanding of the upcoming winter. So, to answer your question, prices can fluctuate in either direction, which means the GP&T numbers can also vary. This characteristic of the contract is designed to manage risk effectively and provide us with beneficial exposure to rising prices or protection against declining prices.

Great. My follow-up question is regarding the DUCs currently in the system. Will they play a larger role in Q3 or Q4? Also, more details about the activity expected in the fourth quarter would be appreciated.

Thanks, Jacob. From a Q3 and Q4 perspective, I know we tried to briefly touch on this a moment ago, but to expand on it, we'll have the one spot crew that's going to complete another pad site for us plus our base crew. And then, of course, the turn-in lines are going to quickly follow. So in the back half of Q3, we'll see our bulk of our Q3 turn-in line start to reach first sales. And then you'll see also in the early part of Q4, you'll see some of that turn-in lines from the Q2 and Q3 activity start to manifest themselves into production in that back half of the year. Production into Q3, we touched on it briefly, but should be around $30 million to $50 million a day, up from where we were on average but we should be on average in Q4 2.2 Bcf equivalent per day. So the ramp will be a little more significant, and we like the shape of that curve as you start to see that activity cadence turn into turning lines and sales volumes that more align with where the curve as we see it today is on commodity prices. So we think it will align with a much better output as we start to think about back half of the year cash flows and set up for 2024.

We are nearing the end of the conference, and we will go to Doug Leggare with Bank of America for our final question.

Thank you, everybody. Note to self, don't hit star 1 more than once. So thanks for moving me to the back of the queue. But anyway, Dennis, this is your first call as CEO. And I wanted to ask you about one of the slides in your deck, your share performance and the market's obvious lack of confidence in the forward curve that you've spent a lot of time on. And I want to refer specifically to Slide 6. So you're basically saying you've got a 30-year to 50-year drilling inventory to hold production flat between $2 and $3. Obviously, your stock is materially undervalued if you believe the strip. So my question is, why not monetize some of that and bring forward some of that take advantage of the weakness in your stock price? And I'm just asking the question, as you're now in the CEO, what can you do to drive market recognition of this value that you clearly see in your stock?

Yes. Thanks for the question, Doug. I think when I start to think about that value proposition that you're raising, as we start to look forward, we see inventory exhaustion playing a real role in the conversation as you start to get through '25, '26 and beyond. You're seeing it in research pieces today from analysts who are looking at and even internal work that we've done as well where you start to see degradation in well performance of some of these other basins. We see that as being constructive long term for Range in the run rate of inventory that we have as we have the ability to continue to repeat performance. When you look at Slide 6 and how the inventory that we have has been, it's got a really low-cost breakeven. And we're not just targeting the lower end of that sector today; we're drilling in and around all of those respective bids that you see on that graphical profile. So we think that bodes well for us. We also want to maintain control in our development program going forward. Moving back to these pad sites with existing production plays a significant part of our story, our efficiencies, our low-cost environment, and our capital efficiency. And so maintaining control in that environment would be very important for us as well. So as we start to think about what this future looks like, we think that there will be a greater appreciation for Range's share value. We'll have that ability to return that value to shareholders, either through expansion of the dividend in the future, additional share repurchases, or further debt reduction based upon the ability to throw off free cash flow through these cycles in the future, while maybe some of the other peers or other basins have a difficult time doing so.

Absolutely.

Okay. All right. My follow-up is maybe for Mark. Mark, I apologize, it's a hedging question. I know someone asked this earlier. But just looking at 2025 and your comments about the curve which I think is becoming consensus. Should we anticipate any additional hedges? Or are you happy with where the hedge book sits now? Is this a new normal in terms of proportion volumes?

Doug. So we are happy with where the position is and I'm not going to lock us into a specific number and codify that, that 20% to 25%, assuming a maintenance program is the specific right answer because the market moves. So I think between now and then, what we will do is monitor the progress for the construction and expected service dates of LNG liquefaction facilities and other demand, be it in-basin demand, of which there are some pretty substantial incremental pieces coming online, be it in Pennsylvania, Ohio, Indiana, just Midwest type in-basin demand. Be it power or more industrial. Extra transport where we can move gas out of the basin. Maintenance is clearly our baseline, but growth will be appropriate, and we'll be able to accelerate the value of our DP inventory at the right moment. So all of that and the timing of that will play back into what our hedge profile looks like. So the 2025 hedge book is a nice foundation. It's enough for the way we see the cards being laid out and the way we expect them to be laid out over the next year or so. But it does present optionality if we see significant prices that change, that we like, and you can de-risk a small portion of that that may support expanded shareholder returns. That may support accelerated deleveraging. Those are great outcomes. But at the end of the day, we don't have to add any more, and we like where this book is as of today.

Thank you. This concludes the question-and-answer session. I would like to turn the call back over to Mr. Degner for his closing remarks.

Yes. Thank you for everyone for joining us on the call this morning and talking to our Q2 results. We look for the next call coming up for Q3. If you have any questions, don't hesitate to follow up with our Investor Relations team. Thank you.

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