Good day and thank you for standing by. Welcome to the Diamondback Energy Second Quarter 2024 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Adam Lawlis, VP of Investor Relations. Please go ahead.

Thank you, Steven. Good morning, and welcome to Diamondback's second quarter 2024 conference call. During our call today, we will reference an updated investor presentation and Letter to Stockholders, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, Chairman and CEO; Kaes Van't Hof, President and CFO; and Danny Wesson, COO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Thank you, Adam, and I appreciate everyone joining this morning. I hope you continue to find the Stockholders Letter that we issued last night to be an efficient way to communicate. We spent a lot of time putting that letter together, and there's a lot of material contained in the text. Operator, would you please open the line for questions?

Yes, thank you. Our first question comes from the line of Neal Dingmann with Truist. Your line is now open.

Good morning, Travis and nice results. Travis, my first question is on sort of the leading capital efficiencies you all continue to highlight. Specifically, you talked about the latest announcement and I think you guys talked about dropping to 10 from 12 rigs and I think what that's even versus 14 a few months ago. And I'm just wondering, are the drilling efficiencies so good that you're able to maintain the pace from nearly 30% fewer rigs than just a few months ago? And just wondering how you anticipate or if you anticipate the same type of efficiency as once you take over the Endeavor assets?

Sure. Good question, Neal. The first half of the year was really characterized by us doing more with less. And you gave some numbers there, but just to repeat some of those, in January of this year, we estimated that we could get 24 wells per rig per year and now we're up to 26 wells per year for the rest of the year. And you see a similar efficiency gain on the completions, where we previously signaled 80 completions per year per crew, and now we're up to over 100 completions per crew per year. Those are simul-frac crews. And look, as we look into the future, one of the things that excites me is that these efficiencies are things that we don't get back. And so as we incorporate the new assets from Endeavor after closing, I fully anticipate our operations organization combined with Endeavor's operations organization will be able to continue these results. When we talked to the market on February 12 regarding this deal, one of the biggest synergies we talked about was being able to apply Diamondback's current D&C costs on a larger asset. I'm pleased to say today we are significantly below where we were in February. This just accrues benefits to our shareholders and really supercharges the delivery of the synergies that we were discussing. So yes, Neal, I'm very confident that we will be able to continue this leading-edge capital efficiency on a larger asset base.

Great to hear. Then I want to ask just quickly, on shareholder return plans, maybe just on sort of broad strokes, specifically, how would your plan vary? I mean, obviously, oil prices are jumping around. It could be anywhere from $90 to $70 environment. I'm just wondering, given your market sort of leading costs that we see on Slide 9, depending on where oil prices go, is that just a matter of having more free cash for buybacks and variable dividends or would there be any other changes we see in a high oil price environment versus a lower price environment?

Yes Neal, I mean, I think the key point here is we've always had a very flexible return of capital program. Since the very beginning, when we put this in place in 2021, we've said we'd like to be able to flex between buying back shares and paying a variable dividend, and we take that capital allocation decision very seriously. We're set up in a way where if you have periods of weakness, like we've seen over the last week or two, that's when the buyback kicks in. If it continues to be weak, we'll continue to buy back more shares. That's the benefit of having a low break-even on your capital program, low break-even on your base dividend, and continuing to generate free cash flow down to much lower numbers than peers or than what the market is used to. If things do stay weak, we'll flex that buyback and be aggressive there. If things improve and we have a good quarter in the $80s or $90s for crude, then we'll pay a substantial variable dividend. I think that flexibility has been very advantageous to our shareholders over the last three years.

How low has that breakeven gotten down to?

Listen, we were very focused on looking at our base dividend breakeven at $40 crude, so mid-cycle capital costs of $40 crude. We could keep production flat. I don't think in a $40 crude scenario we would do that. I think kind of lessons learned from what we've seen through the cycles over the years is that it's okay to let production decline if we were in a very weak commodity price scenario. But in that scenario, we should be allocating 100% of our free cash flow or even more to buying back shares, because in that situation, your share price is likely to be very weak. We're really trying to move the capital allocation decision from the field and the assets to what do you do with your free cash flow, and I think that's a good place to be.

Thank you so much.

Thank you. Our next question comes from the line of Neil Mehta of Goldman Sachs. Your line is now open.

Yes. Good morning and congrats again on very strong execution here. You've talked about getting that net debt level lower post transaction case. Kaes and Travis, how do you see yourself doing that? Is it through asset sales or through organic free cash flow generation? Just your perspective on the asset sale market recognizing you did some small deals here in the quarter?

Yes, Neil. I mean, I think when we announced the deal, we were very conscious of the cash stock mix that we put in place for the Endeavor merger. I don't think we put in so much cash in the deal that we had to be a seller of assets. But as you've seen, we sold multiple assets over the last couple of quarters. We sold a little bit of our Viper ownership to take some risk off the table and bring some cash in the door. We sold our interest in WTG West Texas Gas to Energy Transfer, which will bring in some cash. Additionally, our small mono sale last quarter, all this kind of adds up to nearly $1 billion, which on top of free cash flow generation between January 1 and today is going to reduce the cash outflow burden for the Endeavor deal. I think we planned on looking at the deal as a delevering process through free cash flow, but the asset sales are a kicker that accelerates that. We're highly focused on getting to $10 billion as quickly as possible. It will likely slow down from there, but I don't think you'll see us being forced to sell assets post-deal close. We're going to be very stingy about keeping operated properties in the Permian because they're currently quite valuable.

Yes. Makes a ton of sense. And then just your perspective on managing gas price volatility, first of all, what are your latest thoughts on Matterhorn and when that comes in? Secondly, how do you mitigate some of the risks around gas prices so you can really earn the margin that you deserve on the oil side?

Yes, that's been a significant topic recently and obviously, we need to start making more money on our gas in the Permian and at Diamondback specifically. If you look back at Diamondback's history, we've grown through acquisition. Many of the deals we've done have come with marketing contracts where we don't control the molecule much further than the wellhead. Over the last five years, as contracts have rolled off, we've taken advantage of that and obtained additional rights on those molecules. We started with our commitment to Whistler and have grown that. Combined with Matterhorn, we'll have a bit of gas on both of those. We also saw our press release last week that we're going to be participating in the next pipeline from those guys, the Blackcomb Pipeline. This fits the strategy of taking control of our molecules and seeing what we can do with them. It's on us to continue to improve that portfolio, and I believe that with size, scale, and time, we'll be able to do that.

Thanks, Kaes.

Thanks, Neil.

Thank you. Our next question comes from the line of Arun Jayaram of JPMorgan Securities. Your line is now open.

Yes. My first question is just on the efficiency gains you highlighted in the letter. It looks like you're pushing your drilling cycle times to 26 wells per rig and on the completion side, pushing 100 wells per frac fleet, simul-frac fleet. I was wondering, Kaes and Travis, if you could describe what the drivers of those efficiency gains are and perhaps help us think about what's underwritten in the pro forma $1 billion to $4.4 billion guide for Endeavor for calendar 2025?

Sure. On the rig side, we specifically talked about bit and bottom hole assembly improvements. This isn't necessarily the adoption of some emerging new technology, but rather an example of what our team does really well, which is maintaining a laser-like focus on every decision made. They measure nearly every attribute of drilling the well and seek improvement, and they compete against one well versus the other. We incentivize the crews out there when they perform exceptionally. On the completion side, there have been design changes where we've increased rate and continued to optimize equipment mobilization. We've made changes on some downhole pipe that allow for greater rates with less friction loss. It isn't a marquee item, but it's our intense focus on execution that has always been part of this business.

Yes, listen Arun, all these things have indeed accrued to us since we announced the Endeavor merger in February. As Travis mentioned earlier in this call, these improvements are permanent items that will not go away due to service cost inflation or deflation. We probably anticipate running closer to 18 to 20 rigs next year compared to 22 to 24 previously and around four to five simul-frac crews instead of five plus. We're modeling these improvements accruing to the good guys, and it gives us a head start on the promises we made regarding 2025 numbers.

Great. My follow-up question is on the raised production guidance. You increased your oil guide at the high end by close to 1.5% and then you adjusted CapEx up. Kaes, one thing that wasn't quite intuitive is that you're completing 7% more feet on a net basis. One of the questions that has come in is, would you have thought maybe the oil increase would have been a little bit higher based on that level of completed footage? Could you help reconcile that for us this morning?

Yes. I mean, I don't think wells are completed in a straightforward manner as they may appear in the spreadsheet. In 22 well pads, we moved one pad from 2023 into 2024, and we added about 22 extra wells. We effectively moved around 30 wells from 2023 into 2024. So our well count is a little higher than a true level loaded run rate would be. More importantly, we are preparing room for a major acquisition to close. We are doing everything we can to hit the ground running and achieve numbers right away. It’s about more drilled lateral footage for less CapEx that provides flexibility in the second half of the year and carries that momentum into 2025.

Makes total sense. Thanks, Kaes and Travis.

You bet. Thanks, Arun.

Thanks, Arun.

Thank you. Our next question comes from the line of David Deckelbaum of TD Cowen. Your line is now open.

Hey, Travis, Kaes, Danny and team, thanks for taking my questions. I wanted to follow up on some of the earlier questions. You've obviously seen a lot of field efficiencies, particularly on the drilling side. You've lowered the Midland footage costs down, I guess, 20 some dollars to midpoint. But I'm curious, as you approach the 3Q or 4Q Endeavor closing, are there any parts of the efficiencies that you're seeing that you don't think that you could accomplish synergistically here? Because it would seem like that $300 million or so of synergies that you apportioned to just CapEx savings is increasing by the day.

Well, that's why I highlighted, David, that where we are today is much better in performance and execution than where we were just in February when we talked to you about this deal. These cultural elements, this attention to detail and focus are things we look forward to bringing on our new partners from Endeavor. From what we hear from them anecdotally, they are also experiencing similar efficiency gains. When we combine the two cultures, I expect it to add rather than detract when we integrate the two companies here shortly.

I appreciate that. Another follow-up, you've also seen the benefits of longer lateral progression, relative to your original plan this year. I know one of the things you highlighted with the Endeavor deal was the potential increase of lateral lengths to beyond 15,000 feet given the 100,000 plus number of acres. How do you see the progression into next year and then 2026 concerning lateral lengths relative to where we're at today? Or is this something that's a longer-term endeavor?

Well, first we need to get the two assets combined, which we obviously can't do yet. I'll let Kaes answer the synergy question specifically, but I wanted to highlight something we mentioned in our earnings release and our stockholder letter: we drilled a 20,000-foot lateral well in under eight days, seven to eight days. Longer laterals won't be a problem; we just need to ensure we have the right geology to drill even longer wells.

Yes, I think, David, with the plan, we can't finalize anything until post-close. The priority for the teams is to determine what the plan looks like by the end of 2024 into 2025 post-close and what the projects look like as we start reflecting back on 2025 and into 2026, beginning to extend laterals. Holding the level we have this year, almost 12,000 feet on average for 300 wells is impressive; we should probably aim to maintain that. Longer drilling for a full program of 500 plus wells a year will be challenging, but the team is not afraid of drilling 20,000 feet, and if we have those opportunities, we will take advantage of them.

I appreciate the color, guys.

Thanks, David.

Thank you. Our next question comes from the line of John Freeman of Raymond James. Your line is now open.

Good morning, guys. First topic I wanted to follow up on is on the return of capital framework. When you look at Slide 6 and think about again the efficiency gains that are impressive, should we perceive that the initial evolution of your return of capital framework will create a bigger wedge that can go toward that base dividend? Is that likely rather than perhaps increasing the overall 50% going to shareholders?

Yes, John. I think those are two separate decisions, but you hit the nail on the head. As efficiencies accrue and our decline rate shallows over time and your balance sheet improves, that should create room between your breakeven and your $40 dividend breakeven. We see $40 on the E&P side as a well-protected number. We are buying put options currently at $55 to $60 crude, but eventually we will likely reduce the value of our put buying down to around $50 just to protect against extreme downside scenarios. The remainder of the free cash flow allocation was adjusted from 75% to 50% of free cash going to equity, but that doesn't mean that number won't increase in the future during times of stress. In difficult times, it should be higher than 50% of free cash going back to equity. Conversely, when things are going well, it will hover closer to 50%, allowing us to build a fortress balance sheet. I've been very pleased with our large shareholders' responses to reducing that number as they want us to maintain a stronger balance sheet than anticipated pre-deal.

A good way to visualize the Board's commitment to a sustainable and growing dividend is found on Slide 7. Going all the way back to 2018 when we initiated the dividend, we are showcasing the growth rate. On the bottom half of that slide, you can see that our commitment has translated into almost $8 billion capital returned to our shareholders. It is a significant lever we have as a company, and the Board is dedicated to continuing a sustainable and growing dividend.

That's great. One more follow-up: considering these efficiency gains that have allowed you to reduce rigs and frac crews in the second half without compromising the original production plan, is there an environment where you'd choose to simply maintain that pace and accelerate production growth?

Yes, looking forward, that's not a likely scenario for the next six months to four quarters.

Historically, we've prioritized free cash flow generation over growth post-COVID, and you've seen that trend continue here in 2024.

Thank you. Our next question comes from the line of Scott Hanold of RBC Capital Markets. Your line is now open.

Yes, thank you. There has been a lot of discussion about operational efficiencies. Could you pivot and address what you're seeing in terms of well performance and productivity over the last year? Is it pretty much status quo on an apples-to-apples basis, or are you seeing gains there as well?

I think we've had a few really strong years of well performance. We're always striving to push performance, but I believe this year has been more characterized by cost gains rather than well performance gains. There's significant inventory expansion happening across our portfolio currently.

Thanks for that. As a follow-up, you've highlighted the drilling efficiencies again, mentioning the project where Midland footage costs decreased, and I'm curious about the performance of Endeavor. Based on your understanding, is there still work to get Endeavor to where Diamondback currently is, or is it pretty much just hitting the ground running?

It's going to require hard work for sure. It's our job to make the hard work look easy. There are decisions we will need to make soon after we merge, particularly around using clear drilling fluids and transitioning more frac operations onto simul-frac. Those are two significant levers for quick change. However, we will also ensure to understand what the Endeavor team is already doing well, as historically that process has yielded better results.

From a numbers perspective, we envision the pro forma business will begin with approximately 21 to 22 rigs and then by 2025, we will likely be averaging closer to 18 to 19 combined.

That's good color. Thank you.

Thank you. Our next question comes from the line of Bob Brackett of Bernstein Research. Your line is now open.

Good morning. Following up on the operational efficiencies you've discussed, can you share what the pace-setting rig or crew looks like? Is it significantly ahead of that, or is there a substantial opportunity to improve?

Hey Bob, it's Danny. The crews and rigs are generally performing within a margin of error of each other. We've been active in fleet management over the past few years and continue to optimize where we see dwindling performance. Collaboration among teams on sharing best practices across rigs ensures consistency in performance. We do have pace-setting rigs, but those typically shift as we share successful strategies and the others catch up, so we don’t have just one standout rig driving that number.

There's a healthy competition internally, and we also benchmark ourselves externally. Recently in the Midland Basin, our drilling team achieved over 20,000 feet with a single bit run, which represents a record in the basin. I expect this record to be broken again, as such competition drives our organization.

That's very clear. A quick follow-up along that line: how do you think about the relative price between improving ROP versus reducing non-productive time or reducing mob/de-mob time? Are they roughly equal, or is one more obvious?

It can vary, but we are getting to the point where little things now are our focus for efficiency drivers. The guys were focused in the last call about makeup speeds for pipe, as this was the main area for NPT time on a well. We're continuously assessing dead spaces in these jobs and attacking them all simultaneously. NPT time has been a focal point following the aggressive activity levels we experienced in 2023, and we've done well in reducing it, but there are always areas to improve uptime and maintain performance.

When we look into these details, we perform assessments quarterly. While I emphasize our competitive drive, it's the collaborative aspect that truly matters. When one team discovers a solution, it is promptly shared with all other teams internally. It works similarly for external solutions.

Very clear, thank you.

Thank you. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open.

Yes. Thank you, good morning.

Good morning, Roger.

Congrats on another solid quarter, guys. Just a couple of operating-focused questions here. If we look at the production beat here in the second quarter, you got it on NGL and gas. We're curious if you may have stripped more liquids out of gas; then you would have lower gas production. Could you provide some insight on what's lifting the NGL side and maintaining gas production?

Yes, I think on the NGL side, we try to extract as much ethane as possible from the NGLs to get them out of the basin. Throughout the second quarter, we observed significant gas price weakness, so we took down a few of our highest GOR wells for a month or two to alleviate pressure. Even so, the gas curve continues to outperform expectations. We curtailed some oil to ensure our gas production was lower this quarter, which we've continued to do into the third quarter. Thus, we have substantial gas production originating from this basin, which is why we now focus on creating more value from the gas we produce, either in-basin or out of basin.

To add to that, a strong emphasis on environmental performance has led us to make many decisions to not burn gas in the field for energy but to convert that energy demand to electrical needs. Consequently, more gas that would have otherwise been flared is reaching the pipeline and is recorded as production, contributing to the increase seen across the basin.

Okay, that's helpful, thanks. Regarding the drilling efficiencies and completion efficiencies, you're completing 24 to 26 wells on our completions. Can you give us an idea of where the upper 10% or upper quartile is? In other words, if 24 went to 26, is the best at 30, and is that where you can ultimately go, or are you looking at a much tighter dispersion so it's 26 or 28, and that would be the best?

It depends, but we have a few rigs that are drilling around 30 plus wells a year. It varies based on zones and lateral lengths, but our focus lies in reducing pad cycle times, as these large pads necessitate driving flexibility in our plans by decreasing that cycle time. If a rig performs exceptionally in one zone, we analyze what that rig does and share those insights with the other rigs to ensure everyone benefits.

Got you. And if I can clarify on that, in terms of three-mile laterals versus shorter ones, can you provide the percentage of longer laterals versus the total?

I think our 15,000-foot laterals accounted for around 25% of our development this year.

The rig per year number stems from drilling 300 wells in a year. If we’re drilling more in the Wolfcamp D zone with a particular rig, that rig will have a slower pace. The general assessment of our Wolfberry development is pushing upper limits, but we view the rig count as an output that aligns with our production guidance.

Thanks for being so accommodating with my questions, guys.

No problem.

Thanks, Roger.

Thank you. Our next question comes from the line of Geoff Jay of Daniel Energy Partners. Your line is now open.

Hey, guys, just one quick one from me. I'm just curious about your thoughts on the potential for trimul-frac in your portfolio, especially after Endeavor closes.

Yes, we've looked closely at trimul-frac. The challenge for us lies in the infrastructure we would need to implement for trimul-frac across our portfolio. We need to analyze if that additional infrastructure cost offers a return on investment through the efficiency gains that come with a trimul-frac approach. It is a path we will pursue in areas where we have existing infrastructure and enough development to justify a dedicated trimul-frac crew. You would see us move in that direction quickly.

Excellent, thank you.

Thank you. Our next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.

Good morning, Travis, Kaes, and the rest of the Diamondback team.

Hi, Charles.

Travis, thank you. I appreciate the clarity regarding the metrics, specifically the 24 wells a year to 26 wells per year. Kaes' observation is also interesting, as I have focused on that. I believe the output is more of an indication than a driver. With the other components of your guidance reflecting slightly raised lateral lengths and well counts, could we conclude that the delta in drilling is perhaps a bit larger than the 24 to 26 would suggest?

Yes, I think that is accurate, Charles. The point I was trying to convey is that as a public company with public guidance, we work backward from that guidance. Although output appears straightforward on the surface, it is complex beneath that. We need to remain nimble, and this harmony is what makes us unique, especially since we're working in one basin. Drilling improvements this year have exceeded completion improvements, which is noteworthy.

I appreciate those comments. Go ahead, Kaes.

That puts some pressure on our fracing teams for next quarter.

Have a great day.

Thanks, Charles.

Thanks, Charles.

Thank you. Our next question comes from the line of Paul Cheng of Scotiabank. Your line is now open.

Thank you. Good morning, guys.

Good morning, Paul.

Good morning, Paul.

Travis and Kaes, we appreciate your insights on the great improvement in your results. Over the next two or three years, do you see productivity improvement in drilling and completion as the areas with the greatest potential for quantification? Also, in maintaining flat production post-Endeavor, how many wells would that require? Approximately 500, 520, 550? And do you know where Endeavor's gas pricing exposure lies currently, specifically within the Waha basin?

For your two to three-year outlook, I believe the driving factor is down-hole sensing technology that allows the bit to stay in the best rock for the highest duration. On the completion side, understanding how to efficiently use down-hole sensing to place the most frac energy creates the largest stimulated rock volume. These sensing technologies are rapidly evolving; I believe we will soon be able to sense ahead of the drill bit and drill towards a target rather than past it. This seems minor, but the advancements in sensing technology on the horizon could greatly impact our industry.

On your well count question, low 500 is a solid starting point. As efficiencies accumulate, longer laterals, and flattened decline rates will require fewer wells to maintain the same production levels. If the market allows for growth, that will shift our projections.

Great. Do you have insights on Endeavor's gas exposure to Waha?

Yes. We've assessed Endeavor's exposure, and there are many opportunities for both our companies to enhance gas exit strategies from the basin. However, we need to close the deal first before making decisions.

Okay, thank you.

Thanks, Paul.

Thank you. Our next question comes from the line of Leo Mariani of ROTH. Your line is now open.

I wanted to follow up on your comments about share buybacks. You’ve leaned more towards the variable dividend in recent quarters, but it seems that given the pullback in your stock and sector, buybacks are looking more appealing. Can you clarify if you're able to start executing on buybacks here and if there are restrictions due to the Endeavor deal that would limit that until the deal closes?

Yes, Leo, I don’t believe there are any Endeavor-specific restrictions now. We are currently in a blackout, having just reported earnings. However, we prepare for buybacks during every blackout. If we notice continued weakness, we'll have opportunities. We possess greater flexibility if those windows are open versus closed.

I appreciate that. In your guidance for the rest of the year, it appears CapEx is decreasing versus Q2. Activity will likely drop in the second half, and some OFS cost reductions are also coming through. Do you see CapEx continuing to drop without Endeavor, and do you expect activity in 4Q to be the low point on a standalone basis?

Yes, Q3 is likely the low point for spending since we report cash CapEx. Activity during Q3 will be the lowest, but we will probably bring back our fourth simul-frac crew late this quarter or early next quarter. We'll bring back a rig or two, but nothing beyond that. So, Q3 will be the low for activity; Q4 will be the low for CapEx.

Okay, thanks.

Thank you. Our next question comes from the line of Kalei Akamine of Bank of America. Your line is now open.

Hey, good morning, guys. Thanks for taking my questions. A lot of focus on field efficiency, so I'll leave that alone. I want to ask you about Deep Blue. The team over there has been very active, growing about 20% year-over-year in terms of capacity. Can you discuss growth outlook for that business, especially after including Endeavor, and what potential scale could look like as that business matures?

Yes, we're very impressed with what the Deep Blue team has achieved in a short time. This is precisely why we engaged them. They've secured numerous third-party wins, which would be unavailable to Diamondback if we were gathering someone else's water. Additionally, their ability to acquire to enhance capacity and reduce costs has been commendable. We view Endeavor's water system as an impressive candidate for merging with Deep Blue. Of course, the price must reflect the value for Diamondback shareholders, and that's our priority. Deep Blue is indeed building a substantial water business, and with the volume of water required to operate multiple simul-frac crews concurrently, this translates into moving hundreds of thousands of barrels of water daily at a low cost. We're truly impressed and believe this is a long-term investment.

Could this potentially double the size of that business?

It would probably be under double but about two-thirds the size of the existing business. It adds a significant amount of capacity and connects efficiently to the Western Martin or Eastern Martin County region.

Thanks for that. To follow up on your comments regarding Wolf D and the Upper Sprayberry, can you elaborate on that program for this year? How are these zones layered into your development plans, are they co-developed with other zones, and is there insight from this 2024 program?

Yes, we added the Upper Sprayberry as a test well in the North Martin area, as Kaes mentioned, and we are pleased with its performance. This year, we have tested it with a co-development approach and observed that there's no significant degradation in this strategy. We plan to integrate this into our development zones for the North Martin area moving forward.

We have some tests that are co-developed and some that are standalone. In certain areas, the Wolfcamp D is significantly deeper than the Wolfcamp B, and we are not observing communication. In some instances, it is more efficient to develop it alongside the stack, considering above-ground efficiencies.

The Wolfcamp D has been effectively tested in the North Martin area and has not shown communication with the Wolfcamp B. We view it as a zone we can revisit for capital allocation decisions, where it makes sense to include it in the stack.

That's awesome. I appreciate that, guys.

Thank you.

Thank you. I am showing no further questions at this time. I would now like to turn the call back to Travis Stice, CEO, for closing remarks.

Thank you again for everyone participating in today's call. If you have any questions, please reach out to us using the contact information we’ve previously provided. Thank you and have a great day.

Thank you for your participation in today’s conference. This concludes the program. You may now disconnect.