Q2 2023 Range Resources Corp Earnings Call
Participants
Alan Engberg
Dennis L. Degner; CEO, President & Director; Range Resources Corporation
Laith Sando; VP of IR; Range Resources Corporation
Mark S. Scucchi; Executive VP & CFO; Range Resources Corporation
Bertrand William Donnes; Associate; Truist Securities, Inc., Research Division
Douglas George Blyth Leggate; MD and Head of US Oil & Gas Equity Research; BofA Securities, Research Division
Jacob Phillip Roberts; Associate of Exploration and Production Research; Tudor, Pickering, Holt & Co. Securities, LLC, Research Division
Leo Paul Mariani; MD; ROTH MKM Partners, LLC, Research Division
Michael Stephen Scialla; MD; Stephens Inc., Research Division
Paul Michael Diamond; Research Analyst; Citigroup Inc., Research Division
Roger David Read; MD & Senior Equity Research Analyst; Wells Fargo Securities, LLC, Research Division
Umang Choudhary; Associate; Goldman Sachs Group, Inc., Research Division
Presentation
Operator
Welcome to the Range Resources Second Quarter 2023 Earnings Conference Call. (Operator Instructions)
Statements made during the 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.
Laith Sando
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 reconciliations of these to the most comparable GAAP figures.
We've also posted supplemental tables on our website that include realized pricing details by product, along with calculations of EBITDAX, cash margins and other non-GAAP measures.
With that, let me turn the call over to Dennis.
Dennis L. Degner
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 plans safely and with peer-leading efficiencies, 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 dictated 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 spend 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 frac 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 decrease in capital spend across the second half of the year, while production ratably 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 for 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.
This should drive sequential growth of approximately 30 million 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 2022 average. As part of Q2, the team also added 4 wells with lateral lengths 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 laterals, 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 2022 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 2022 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 4 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 2 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 3-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 PDH 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 third-party audit covering our Southwest PA assets. Range's LDAR inspection program, which increased in frequency to 8x 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 whether the industry's lowest emission intensities.
For safety, we observed further improvements in our safety performance in the field in Q2 with 0 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.
Mark S. Scucchi
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 the 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 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.
Dennis L. Degner
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 derisked 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 shareholders.
With that, we'll open the line for questions.
Question and Answer Session
Operator
Thank you, Mr. Degner. The question-and-answer session will now begin. (Operator Instructions) Our first question comes from the line of Bertrand Donnes with Truist.
Bertrand William Donnes
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 be 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?
Dennis L. Degner
Yes, thanks for the question. As you look at the first half of the year, we started off with a couple of drilling rigs and then bolted on a third horizontal rig as we started to get toward the back half of Q1. So when you look at Q2 from a drilling activity perspective, it really became our highest drilling activity.
And then on the completion side, we kept a base frac crew operating through the balance of the first half of the year, and it will remain with us through all of this year's program, but we picked up the spot frac crew in the last weeks of Q2 as well. And when you think about the completion versus drilling percentages of spend, it starts to clearly change the capital -- that activity cadence starts to change the capital profile at that point.
A lot of our turn-in-lines from that drilling activity that are getting kicked out are going to then see first sales and production start to come together in Q3, especially more weighted to the back half of the quarter. Where -- I think, approximately 1/3 of our turn-in-lines are in Q3, and then you're going to see the majority of those actually be in the last weeks of the quarter. So that's from an activity cadence standpoint, how it will shake out for the balance of the year. And then once you see Q4, it will be actually a tail off, not too dissimilar to what you saw in Q1 and Q2.
Bertrand William Donnes
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 pass for it?
Dennis L. Degner
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 of being 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.
Operator
And one moment for our next question. Our next question comes from the line of Umang Choudhary with Goldman Sachs & Company.
Umang Choudhary
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 cost heading into 2024?
Dennis L. Degner
Yes. I'm going to somewhat build upon, I think, the response that we've shared at the prior earnings call and I'll start off by saying it's still a little bit early to frame what that will look like for 2024. Encouraging thing is we're clearly seeing some rigs come out of the mix. If you look at where we were at the end of December in 2022 versus where we were in total rig count last week, I think we've got around 110 rigs approximately that have come out of the mix.
The Haynesville is now down in the 45%, 46% range. Of course, you're seeing Appalachia at a similar level also with other rigs coming out of other basins that saw activity over the last 24 months during different pricing environments. All of that started to manifest itself into some conversations around rig availability, what that will look like for 2024. We've seen some early signs of relief on areas like tubular goods, where you've seen not only rig activity influence that, but also just the supply catching up with what was the demand in the past and also inputs as a part of that supply chain start to normalize.
And then, of course, we're starting to see some availability, and I'll just say some relief when it comes to some of this supporting equipment as a part of our day in and day out operations.
As we get ready to go into the bid process this fall, we fully expect to have a lot better way of framing what this could look like for 2024. But I'd say, all in all, we're encouraged by some of the relief that we're seeing -- but we also know I'll say this, there will be certain equipment like maybe the e-fleets on the frac side, maybe some of your hiring specification equipment for the long laterals like we talked about in our prepared remarks today. So we would expect that equipment to remain in pretty high demand. And though there could be and we'd expect to see some relief on pricing from a service perspective come along with that, that's part of what still needs to materialize. And of course, we're also seeing week in and week out some additional adjustment of the total U.S. rig count.
The last thing I would say is where everything shake out from a service perspective, we really expect to be on the leading edge of what that capital efficiency looks like, coupled with our service cost. I think we've talked about it in prior one-on-one meetings and on these calls. But when you look at Slide 7 and where it ranges, cost per Mcfe for that molecule replacement on a decline basis each year, you take our low base decline, you factor in our efficiencies that some of which we set new records on and talked about today, it puts us in a position of even in today's pricing to be at $0.76 per Mcfe replacement versus our peer average of $1.
So however it shakes out, we really see that still being on the leading edge based upon our team's results and also with our contiguous position that we had that we're developing.
Umang Choudhary
Got you. That's very comprehensive. My next question was on hedging. You are now 50% hedged for next year at 370 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 -- are you happy with the low 20% exposure that you have right now?
Mark S. Scucchi
I'll start this one off. I think you've touched on the theme, the philosophy behind our hedging program, and that is largely and essentially to cover the fixed costs, and maintain exposure to a strong market. Obviously, with LNG facilities being commissioned over the next year and 2, we expect a significant rerating 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 ranges 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 it 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 rerating of demand, making its way into the forward curve. So as you look into 2025, it's a modest foundation. We think that, 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 actually 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 developments 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.
Operator
One moment for our next question. Our next question comes from the line of Leo Mariani with ROTH MKM.
Leo Paul Mariani
I was hoping 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?
Mark S. Scucchi
Sure. 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, it's got 30 years of drilling activity, production 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 in 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 for the 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 seems the most prudent.
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, obviously, are moving around, 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 and 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 chattered 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 buyback 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 2 years.
Leo Paul Mariani
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 a '24 and then maybe it's '25 where 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.
Dennis L. Degner
You bet, Leo. This -- 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. And 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 it will not -- 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.
Operator
Our next question comes from the line of Roger Read with WFS.
Roger David Read
Roger Read, Wells Fargo. Sorry, I just typed in WFS on the registration page. Thanks for having us on, couple of the questions. I don't want to repeat. So I'm going to come at this a little differently.
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 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.
Dennis L. Degner
Yes. Roger, I think there's maybe a couple of ways of bifurcating this conversation. And I think one is how we kind of view our efficiencies and our service costs versus overall capital efficiency. And if anything, demonstrates the team's ability to continue to deliver on leading efficiencies, I think our Q2 results have clearly demonstrated that.
For the group to be able to basically have a 13% increase in completion, [frac seizures] per day in the first half of the year versus the full year average of last year, some of the drilling footage accomplishments, all in and around prior producing activity, returning to pad sites with production. It just as an old supervisor once told me "success begets success, and the teams continue to build upon that momentum". So we would expect to see further progress -- progression in our efficiencies in '24 and '25 as again, we continue to move back to those pad sites. So that's one arrow in the quiver.
I think the second one is, as we continue to root out nonproductive time. When you move back to these pad sites, you have the ability to look for ways to more efficiently manage our logistics, whether it's the water recycling program that we have and not only the cost savings measures that, that brings to the table, but also just overall the efficiency enhancements. It really becomes a force multiplier. So we see areas of improvement there as well.
But I'll say this. Lastly, our long lateral development always plays a role in this, with us now having drilled our longest laterals this past quarter, exceeding 20,000 feet. We're excited to see those wells come online here in the quarters ahead and monitor those results. We think those play a significant part. But capital efficiency will no now fluctuate as we start to have conversations about is it some low level of growth in the future? What kind of inventory gets added as a part of that? But from a cost per foot basis, we would expect to still be on the leading edge of how that -- how those numbers are manifested and how we basically execute the programs going forward.
Roger David Read
Okay. Appreciate that. The other question I had, best way for you to answer or best opportunity for you to answer it. We have seen quite a resurgence in -- I mean, I guess you could say some commodity prices in general, but particularly ethane here over the last call it, 4 to 6 weeks. I was just -- you gave a fairly positive outlook for what's going on the NGL front. So I was just curious if there's anything you've seen in that to explain some of the strength in the pricing recovery.
Alan Engberg
Yes. Thanks, Roger. This is Alan Engberg, I manage Liquids Marketing business. I'll give it a shot, give you some background on what's been behind some of the recent strength that we've seen in ethane.
I think I would start by saying ethane fundamentals have been pretty tight for a while now. We've mentioned it in prior calls, but the days supply hit 5-year lows last year, and we've been hugging those 5-year lows all through this year as well. So when the market is tight like that, there's really not a lot of cushion to manage changes or tightening, let's say, in the supply-demand fundamentals.
And really, that's what we've seen in June and so far in July. So the drivers of that list about 5 different ones. But first one, I'll list actually is the cost driver. So we've got -- someone asked earlier about inflation, we had PPIs of reflecting about a 13% increase in pipeline costs come into effect this year. So that effectively raises the floor for ethane recovery for the industry and that led to probably more ethane rejection. So we had less supply, we believe, during the month of June.
At the same time, we had a tremendous amount of heat as we're all aware of. That again led to, let's say, in some of the further out basins, more of an incentive to reject ethane and to sell the gas locally. Added to that, the heat also affects fractionation efficiencies. As you can imagine, ethane is the lightest molecule needs the most cooling. So it's the one that gets affected the most when it comes to fractionation efficiencies in the heat. And there, you lose, call it, 5% to 8% of efficiency.
The other thing that has become I guess, more to the -- it's come more to the forefront is that fractionation capacity overall in the U.S. Gulf is actually kind of tight. We saw it back in 2018 and ethane ran up to in the 60s for a short while back then. I think it was third quarter of 2018. But ethane -- or sorry, fractionation capacities in the Gulf are just plain tight. And as a result of that, what we believe is happening -- and it's hard to really quantify because it doesn't get reported, but we believe that the ethane inventory that you see reported by the EIA, the fraction of that, that is unprocessed, that's what we call Y-grade has actually increased relative to the fraction of that, that is processed or what we call a purity ethane molecule. So again, the ethane inventory is a mix of process (inaudible) and even stuff that we call EP mix, but we believe that due to fractionation capacity tightness, there's just been less purity ethane available.
As a result of that, when we got into late June, early July, the end of ethylene maintenance season. Demand increased for the reasons I already talked about, supply decreased and the ethane price spiked. Now going forward, what we see is continued tightness, the market actually looks good. But I'm not sure we'll see prices continue like in the 40s. And the reason for that is we do have some relief coming in fractionation capacity in the second half of the year to the major midstream companies in the U.S. Gulf Coast are each adding a fractionator about 150,000 barrels per day each.
Nevertheless, we do see ethane inventories on a day supply basis, continuing near the lows because operating rates have increased, new demand has come on and the market will continue to be snugged this year and next year.
Operator
Our next question comes from the line of Michael Scialla with Stephens.
Michael Stephen Scialla
Dennis, 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?
Dennis L. Degner
You bet, Michael. The spot crew that we brought on recently I would say, is more in line with kind of current pricing structures. So it had some advantages that came with it, very efficient. We're really happy with the results that we've seen. First pad has been completed, and it was actually in line with what we were seeing with our base frac crew that we'll have for the bulk of the year.
So in a lot of ways, I think it's shown the repeatable nature of not only the procedures that the teams put in place, but also the efficiencies that -- in a lot of cases, several service providers have also elevated their respective performance through just routine operations, maintenance, et cetera. But pricing for the spot crew was very much in line with what we would expect for I'll just say, current equipment that's been available that we were able to get spot pricing for. That crew will then frac another pad site for us here in the back half of the quarter and then get released and then we'll be back to our base frac crew for the remainder of the year.
Michael Stephen Scialla
Okay. So if I heard you right there, you are seeing some improvement in prices even on the completion side as well?
Dennis L. Degner
There are some small signs of relief. But again, I'll phrase this as small only because that was a spot crew of 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 no, it was small. I would say it was difficult to quantify in a bigger picture.
Michael Stephen Scialla
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 2 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?
Dennis L. Degner
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 I'll just say responsibly, like we've really executed the rest of our programs, whether it's drilling and completing a well, producing a pad site or reducing our emissions. It's the same culture, 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 it is 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.
Operator
Our next question comes from the line of Paul Diamond with Citi.
Paul Michael Diamond
Just a quick one, talking about -- you had mentioned a specific pad and wet acreage that really helped you out with your highest overall efficiency. How should we think about the extrapolation of those techniques and that level of efficiency more to some of the dryer acreage? Should we think about that as one for one on trend? Or is there some variation there?
Dennis L. Degner
Yes, thanks for asking that question. I think it's -- at this point, I would say it's not something that we see immediately that we can translate across the entire basin, but we will progress in that direction, meaning staging areas get redefined, trucking routes for hauling water, all of this is, I'll just say, a progression that can occur quarter-over-quarter that translates into those improved efficiencies.
Over the course of time, do we see this being the new standard that turns into a repeatable metric, we do. And that's part of us communicating it today. But do we see this being the new standard for 2024. We may not be quite there yet because we also recognize there's diversity and I'll just say ingress and egress across the field and how we're drilling it from a perspective of lateral lengths. There is some variability.
As you can tell, our average program for the past several years has been kind of 10,000 to 12,000 feet in average lateral length. But we will have those moments where we'll have 20,000 to 18,000-foot type laterals depending upon where we're developing assets. So we see this as translatable to the dry gas and super-rich areas. It will take some time as we take these, I'll just say, more recent learnings and translate that into future development program execution.
Paul Michael Diamond
Understood. Just one quick kind of more macro follow-up. You guys talked a bit about seeing just nationwide activity reducing -- with the current strength of the kind of '24 beyond curve, I guess, at what point do you see that activity kind of reverting? Is it a pricing needs to be materially higher? Or is it -- are you guys expecting more of just kind of a run rate flattening through '24?
Dennis L. Degner
I think as you think about '24 today, I mean I think we'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 maintenance 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 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.
Operator
And one moment for our next question. Our next question comes from the line of Jacob Roberts with TPH & Co.
Jacob Phillip Roberts
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.
Mark S. Scucchi
Yes. This is Mark. I'll lead off on that. I mean you've got 6 months down and the experience of NGL prices to date and gas prices today, other things that are going into -- in there, are your electricity costs that are behind compression and other things. So as we look at the forward curves for each of the products, the respective processing and transportation costs of those estimated power costs in the latter half of this year and heading into winter, you likely and hopefully see some higher prices as we would expect once we're outside the injection season, and there's a little more understanding of what this winter may look like.
So the answer to your question is prices can go either direction. Therefore, the GP&T number can go either direction. So it's just a great feature of that contract by design to be right way risk and give us good exposure to improving prices or insulation when we see lower prices.
Jacob Phillip Roberts
Great. And then my follow-up would be just in terms of the DUCs you guys have in the system right now, are those going to be more of a feature in Q3 or in Q4? And then perhaps -- any more details on the cadence activity within the fourth quarter would be helpful.
Dennis L. Degner
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 for Q2, 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 turn-in-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.
Operator
We are nearing the end of the conference, and we will go to Doug Leggate with Bank of America for our final question.
Douglas George Blyth Leggate
Thank you, everybody. Note to self, don't hit star 1 more than once. So thanks for getting me (inaudible) moves you 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 talking about. And I want to refer specifically to Slide 6.
So you're basically saying you've got a 30- to 50-year drilling inventory to hold production flat between $2 and $3 gas. 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 value, take advantage of the weakness in your stock price? And I'm just asking the question, as you're new as CEO, what can you do to drive market recognition of this value that you clearly see in your stock?
Dennis L. Degner
Yes. Thanks for the question, Doug. I think when I started 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 that runway 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 of 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 either 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 either peers or other basins have a difficult time doing so.
Douglas George Blyth Leggate
Okay. So you're not -- you're happy with the portfolio as it stands today is the bottom line?
Dennis L. Degner
Absolutely.
Douglas George Blyth Leggate
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?
Mark S. Scucchi
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 deep 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 25 book is a nice foundation. It's enough for the way we see the cards being laid out, 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 changes, changes that we like, and you can derisk 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.
Douglas George Blyth Leggate
I'm sure we'll have the growth discussion some other time, but thanks so much, guys. I appreciate you taking my questions.
Operator
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.
Dennis L. Degner
Yes. Thank you for everyone for joining us on the call this morning and talking to our Q2 results. We look forward to 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.
Operator
Thank you for your participation in today's conference. You may now disconnect.
