Good day ladies and gentlemen, and welcome to the Diamondback Energy Second Quarter 2018 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will be given at that time. As a reminder, today's conference is being recorded. I would now like to turn the call over to, Adam Lawlis, Director, Investor Relations. Sir, you may begin.

Thank you, Mark. Good morning and welcome to Diamondback Energy's second quarter 2018 conference call. During our call today we will reference an updated investor presentation which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, CEO; Mike Hollis, President and COO; and Tracy Dick, CFO. 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 on 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. Welcome everyone, and thank you for listening to Diamondback's second quarter 2018 conference call. The second quarter was another strong quarter for Diamondback as we continued our operational excellence by growing production 10% quarter-over-quarter and maintaining a cash margin of over 82%. Separately, I'm excited to announce the acquisition of all the assets of Ajax Resources for $900 million in cash and 2.5 million shares of Diamondback stock. This acquisition adds over 25,000 net acres physically adjacent to our existing acreage in Northwest Martin and Northeast Andrews county, and more than doubles our Tier 1 inventory in this area with the addition of 220 net locations with IRRs of 100% or greater at $60 oil. In addition to outstanding well results in the emerging zones for the area across this acreage block, Diamondback's operations will benefit from multiple synergies from this transaction. We currently operate about 1,000 net acres of Ajax's acreage, and our existing position is physically adjacent to 6,500 acres of the Ajax acreage allowing for operational efficiencies via existing and shared infrastructure assets. Also, net revenue interest above 75% provides a potential future drop-down opportunity for Viper. Lastly, the acreage is almost 90% held by production, which will allow for efficient development with large-scale multi-zone pads. This acquisition checks every box we look for at Diamondback: a sizable, blocky acreage position with inventory in the top quartile of our existing portfolio; wells that are set up for long lateral development with existing production and infrastructure, allowing for immediate development. Also, the existing production and anticipated development plan makes the acquisition accretive on all per share metrics. Slides 8 through 13 lay out the details of the acreage position, and the impact on our existing inventory in the area. Ajax tested the Middle Spraberry and the Wolfcamp A, both emerging zones for the area, and the results show these two zones competing with the Lower Spraberry for capital immediately. As a result, and due to the held-by production nature of the acreage, we are planning to develop the acreage with 12-plus well pads, targeting the Middle Spraberry, Lower Spraberry, and Wolfcamp A, simultaneously. With these comments now complete, I'll turn the call over to Mike.

Thank you, Travis. I would like to start-off by congratulating all the Diamondback employees and our strategic business partners for another great quarter. They make our job easy in telling the Diamondback story. It's truly a privilege to work alongside such a professional and hard working group. Moving ahead to slide 16 through 18, we give an update to our takeaway strategy. In terms of in-basin transportation, we currently have over 92% of our total production on pipe moving to 95% or higher by the end of the year, removing the risk of rising trucking costs from our forward operating plan. Now, in terms of out of basin transportation, for the remainder of 2018, we have firm transportation agreements in place that cover the majority of our gross production at fixed discounts to Gulf Coast pricing. These arrangements provide a true flow assurance for our barrels and provide insulation from differentials that may continue to widen. Effective for the full year 2019, we will still have the majority of our gross production covered by firm transport deals, but the pricing terms will become more favorable than in 2018. These agreements will continue into 2020 and beyond when we will have 100% of our oil production protected via firm transportation to Gulf Coast markets. We see this as a true wellhead to water solution that eliminates risk of illiquid onshore U.S. market volatility. On the gas side, as shown on slide 18, we have dedicated gatherers and processors that have secured downstream firm and/or Diamondback has take-in-kind rights. Although, our gas will remain exposed to the WAHA basis, we will continue to have flow assurance. It is important to highlight that gas production represents less than 5% of our total revenue. As seen on slides 20 and 21, the infrastructure investments…

Thank you, Mike. Diamondback's second quarter 2018 net income was $2.22 per diluted share, and our net income adjusted for non-cash derivatives and other items was $1.59 per diluted share. Our adjusted EBITDA for the quarter was $370 million, up 9% quarter-over-quarter, with our cash operating costs of $8.83 per BOE. During the quarter, Diamondback spent $338 million on drilling and completion in non-operated property, and $88 million on infrastructure and midstream investments. For the first half of 2018, we generated $20 million of free cash flow excluding acquisitions, and have now cash flow to business in aggregate for the past 14 quarters. As shown on slide 29, Diamondback ended the second quarter of 2018 with a net debt to Q2 annualized adjusted EBITDA ratio of 1.3 times, and roughly $760 million of liquidity. We intend to fund the cash portion of the Ajax acquisition with a combination of cash on hand, proceeds from the previously announced drop down of mineral interests to Viper, and a combination of borrowings under our revolver, and capital market transactions which may include a debt offering. As a result of continuing volume outperformance and a small production contribution from our acquisition of Ajax, which is expected to close at the end of October, we have decided to raise our full year 2018 production guidance to a range of 115,000 boe to 119,000 boe a day. At the midpoint, this represents a 4% increase over our prior guidance, and implies over 45% year-over-year growth. Finally, Diamondback's Board of Directors has declared a cash dividend for the second quarter of $0.125 per common share payable on August 27, 2018 to shareholders of record at the close of business August 20, 2018. I'll now turn the call back over to Travis.

Thank you, Tracy. Diamondback was able to deliver another great quarter as a result of our continued commitment to execution and low cost operations. We are increasing production guidance while maintaining our capital budget, and look forward to integrating our latest accretive acquisition. Diamondback will remain proactive in all aspects of our business, including leveraging our size and scale to secure smart marketing agreements that position us well for both the near and the long-term. Operator, please open the line for questions?

Thank you. And our first question comes from the line of Neal Dingmann of SunTrust. Your line is now open.

Good morning, all. Travis, a question for you, and the team, on the Ajax deal, when you're talking about the accretion behind this, can you talk about how you're thinking about besides the 12,000 barrels a day of existing production, could you maybe talk about some color about how quickly you all intend or believe you can ramp production around this, as I believe you said there was already a potentially a 6-well or soon to be 12-well pad and – as well as kind of how many rigs you plan on running down the area?

Yeah, Neal, a good question. When you look specifically at the asset, and what's going on, now there's one rig that's operated by Ajax. Again, we don't close the acquisition till the 31st. And working with the Ajax team, they're on fourth well of the pad, and we're going to get them to continue drilling up until you get a 12-well pad. So this rig will stay operating through the first quarter on that pad of 2019, and we'll look into 2019 and potentially picking a second rig up on this acreage depending on rest of our capital allocation decisions based on our cash flow. So the volume impact ramping from here will be a 2019 event.

Very good. And then just one follow up. Either in the Ajax or maybe even if you look at some of your Delaware areas, as in Pecos and Reeves or Ward, could you talk about maybe plans? I know previously even up to this point, you've been doing mostly sort of single-zone, focusing on the Bs and such. Can you talk about plans for more upcoming multi-zone pads either for Ajax or some of these other areas?

Yeah, as I laid out in my prepared remarks for Ajax, we're going to immediately begin developing three zones, the Middle Spraberry, Lower Spraberry and Wolfcamp A. On our legacy assets on the Midland Basin side, we've been developing multi-zones in the Lower Spraberry and Wolfcamp A and will continue to push that envelope to do more rather than less. And on the Delaware, again, we're still primarily drilling obligations that are satisfied through the Wolfcamp A. Now, we're drilling multi-wells certainly per pad, but they're really focused now on the Wolfcamp A to address the lease obligations.

Very good. Thanks very much. Congrats on the deal.

Thanks, Neal.

And our next question comes from the line of John Nelson of Goldman Sachs. Your line is now open.

Good morning. Congratulations on the Ajax deal and the Rattler's progression.

Thank you, John.

Travis, while the midpoint of 2018 CapEx guidance moved up, it was pretty modest relative to some of your peers and seem to actually be more kind of midstream focused. Can you speak to what kind of pricing pressures you're seeing in the field, and if you think that's sustainable for Diamondback to continue to hold the line on cost relative to peers?

Well, certainly Diamondback always maintains pressure on costs, whether it's relative to peers or not, that's just the way that we operate our business. But when you look specifically at what happened in the quarter, on the Midland Basin side, our cost quarter-over-quarter were actually down $50 to $60 a foot, primarily on the completion side due to the full scale implementation of regional sand. And that's going to continue in the back half of this year, and we're beginning testing in the Delaware Basin side also on the regional sand. So even though, quarter-over-quarter in the Delaware, costs are flat. If regional sand continues to work in the Delaware, we could probably see some downward pressure on pricing. Also, I know that just from a surplus availability, primarily on the pressure pumping that we're certainly not dialing in any cost increases on the back half of this year, and I think, our operations organization continues to push the envelope on efficient execution of our development plan and holding costs. So we feel really comfortable about our cost projection. And you're right, it was – 2Q was heavily dominated by infrastructure costs, and that's not an equally quarter-loaded event. So we've taken all that into account in our latest CapEx guide.

I guess, just to build on, some folks have kind of commented on labor. You guys are in the basin day-to-day; can you just speak to how congested or tight both the labor and service pool market kind of feel down in the Permian today?

Yeah, the guys that are a little closer to that on a business partners on the service side probably can give you the best commentary on that. I can just talk from a macro sense that, labor is tight here in the Permian, and that usually translates to the higher wages. And we're seeing that, but the wages as a percent of the total well is actually a pretty small piece. So wages are going up, that's a good thing for workers out here. That allows us to attract more and more workers. But in terms of how that affects my overall economics, it's a pretty de minimis effect.

That's helpful. And then the release just highlighted that you plan to add a 12th and 13th rig in 3Q; I'm guessing one of those two is the Ajax rig. Just where does the other rig go to?

Yeah. No, that doesn't include the Ajax rig. That rig – we'll just assume that rig in November 1 when we take over operations. What we're trying to do is, get a jump on some obligations in the Delaware. So that 13th rig is the 7th rig in the Delaware Basin right now, and just keeping ahead of some obligations we have in 2019.

So, from a cadence perspective, we're going to stay at five crews. We added our fifth crew in Q2, and we're going to stay at that five-crew pace for the rest of 2018.

Great. Congrats again. I'll let somebody else hop on.

Thanks, John.

And the next question comes from the line of Asit Sen of Bank of America. Your line is now open.

Thanks. Good morning, guys. So on the addition of the two rigs in 3Q, it looks like, Travis, you talked about the reasoning for that. Now, previously you've talked about the optimal level of roughly 16 to 18 rigs on your acreage. Could you update on your thought process there? And then, average pad size clearly is going to go up; any thought of 2019 versus 2018 on average pad size?

Yeah, I'll answer those in reverse. We've not really provided any color or commentary on 2019, yet. Those comments will be coming. But in general, we've said in each quarter that we're seeing more and more wells per development unit seems to be best for EUR and best for cost efficiencies as well. So I think you'll continue to see that trend move up. And then, we've typically guided – historically guided to kind of that 16 to 18 rig cadence, and notionally without accounting for efficiency improvements, that would move up by 1 to 2 rigs with the addition of these 25,000 acres associated with the Ajax acquisition.

Great. And Travis, one of your peers noted higher line pressure issues in the Midland Basin, are you seeing similar issues?

Asit, the only time we've seen that is, we've had some downstream processing plants to do some upgrades and some line loops. And that's generally the only time we'll see any kind of changes in line pressure. In general, these guys are staying out in front of us, so not really seeing an issue at this point.

Great. Thank you.

Thank you.

And our next question comes from the line of Mike Kelly with Seaport Global. Your line is now open.

Hey, guys. Good morning. Travis, curious post the Ajax deal here, do you look to hit the pause button on the M&A front? Are you still very, very active assessing deals there? And then just, you laid out too that there might be some transactions here, a potential debt raise to fund this. Are you contemplating any equity alongside that too? We've gotten that question this morning. Thank you.

Yeah. Mike no, we're not contemplating any equity associated with this trade. You've heard me say multiple times that in the business development, in the M&A world, you're either in the game or you're out of the game. And I think it's fair to say that Diamondback's going to remain in the game. And if we can find acquisitions like this Ajax trade that touches all the levers we care about, we're going to continue to bring that value forward to our investors. I mean, if you look specifically at the Ajax trade, the geos or geoscience team, they loved it because there's a sweet spot for the Wolfcamp A and the Middle Spraberry in addition to the Lower Spraberry, which we already knew about it. The operations guys love it because it's the easiest drill in our portfolio, and it's physically adjacent to 6,500 acres of our stuff, which makes all the facilities easier. The Viper guys love it, because not only do they have a new playground to go buy minerals underneath Diamondback now, there's also a couple of percentage points above the 75% that represent additional drop down. And the Rattler guys love it because there's new surface facility that get included in their toolbox. And then this wasn't a brokered deal, and as I mentioned, we're not doing equity, so everybody loves it because there's not going to be any banker fees associated with this trade. So those are the type of things that we're going to continue to look for.

Got it. Checks a lot of boxes except that broker fee part. But, Travis, switching over to the Rattler, I mean, lot of good slides here to lay out that opportunity. Maybe you could just kind of frame this up for us little bit in terms of the ultimate value proposition to FANG's shareholders and really kind of what the playbook is here going forward? Thanks.

Yeah, Mike, I'd love to talk chapter and verse about the Rattler Midstream, but we filed that publicly with the SEC and all the information is in that S-1, and we're in that quiet period and I really can't comment on any of the details. But I encourage you to hit the SEC website and look at all the information in the box that we included.

Yeah, fair enough. Thanks a lot, guys. Bye.

And our next question comes from the line of Gail Nicholson of KLR Group. Your line is now open.

Good morning. Just help in going to the regional sand testing in the Delaware, how much data do you guys need to collect before you kind of make that switch if you choose to make that switch? And do you think that the cost savings would be similar to what you guys saw when you guys made that switch into the Midland?

Yeah, Gail. So over in the Delaware side, we pump more pound per foot of the sand. So if we were able to go to a full-scale local sand usage, you'll actually get a higher dollar per foot change on the Delaware than you do on the Midland side. We're pumping local 100 mesh. We're already pumping that in the Delaware. We've got a couple of tests coming up, we will try it. We've got a bunch -our several offset operators who are watching and working with that have done it as well. So the data set is coming, and it's looking very favorable to be able to do that. But you'll have a bigger effect over the Delaware than it'd be in Midland.

And then, you guys just continue, I think to get more and more efficient. Can you just talk about where you guys are today from the standpoint of, how many wells per rig per annum you drill versus where you guys were 12 months ago, and also from the standpoint of completion, how quickly you complete a well today versus 12 months ago, just so we can kind of conceptualize those efficiency gains?

You bet. And we've scaled the business pretty significantly in the last year as well. But in general on the Midland Basin side, we complete or we drill roughly 22 wells per rig per year, and we drill longer and longer laterals on average each year, so that 22 is a good number for now. On the Delaware side, it's closer to 13 to 15. Again, it depends on length and which area we're actually drilling in. On the completion side, Midland hitting on all eight cylinders as they have been for several years, and we're always adjusting size of the job slightly so that has an effect on how many stages you can get in at a day. So again, you move over to the Delaware where we have a larger loading of fluid and sand per foot. So there we do a little bit less footage per day per frac crew, but again that continues to accelerate every quarter. So from a baseball analogy, I would say we're probably in the fifth inning on Midland Basin side and probably third or fourth inning over on the Delaware side, so still a lot more to come.

Great. And then you guys talked about potentially doing a debt offering in order to pay for a portion of the cash part of the Ajax acquisition. When you look at just where you are in the portfolio with the incremental high-quality inventory you picked up before Ajax, is there any thoughts about any portfolio optimization on your existing asset base, and maybe selling some lesser quality areas in order to fund the Ajax?

Yeah, that's certainly something that's always part of our portfolio decisions, and really irrespective of the Ajax acquisition, we think that we want to always try to high grade our inventory, whether it's in the form of creaming off the stuff that has very little present value because it's late in time, and whether we use those proceeds to fund an acquisition or not. I think that's just good prudent capital allocation.

Great. Thank you.

And our next question comes from the line of Jeff Grampp of Northland Capital. Your line is now open.

Good morning, guys. Was curious on the Ajax acquisition, that area overall. It looks like that represents kind of, I guess, the majority of your Midland inventory now, so can you guys just kind of talk about rig allocation there? I think, you mentioned one to two rigs. But can you clarify that's just on the Ajax piece or is that the entirety of that kind of Northeastern Andrews, Northwestern Martin area for you guys? And then can you also touch on any infrastructure investments that might make sense on the Rattler side as you integrate Ajax?

Yeah, so the comment of 1 to 2 rigs was just on the newly-acquired acreage. We're going to run 1 to 2 on our legacy acreage up there. So something in that 2 to 4 rig on a go-forward basis for that portion of our inventory. And look, as I already mentioned the economics of that really dictates that it draws rigs because it has such a high rate of return on an individual well basis. And on the infrastructure side, luckily the asset comes with enough SWD infrastructure and fresh water infrastructure to support our existing needs. We have a good amount of fresh water and SWD infrastructure already up there. So the synergies are very present with this trade. It gives our operations team a lot of flexibility on the fresh water side. We can connect the saltwater disposal systems to flow barrels where we need to flow them, and it also sets up well for – as Travis mentioned earlier the 12-well pad development across three zones both on the existing inventory and now the new pro forma inventory with Ajax.

All right. Great, that's helpful. And then can you guys talk a little bit more about, you're behind a couple of rigs here, but electing not to add a frac crew. Is that – I guess seeing some more efficiencies on the frac side where you can – those can keep up with the increased rigs? Or if there's any maybe plans in the medium-term to add another frac crew?

Jeff, basically the rigs that we're picking at today, we're drilling multi-well pad. So really between now and the end of the year, we're not going to have a lot of DUCs that would come from those additional rigs. So again picking up that frac crew, and again whether it moves a month here or there, we're not going to appreciably change our DUC count. But picking it up early, again these wells have come in late in fourth quarter is when we move off the pad. So again, wouldn't change production in 2018.

Okay, great. That's helpful. I appreciate the comment, guys.

Thanks, Jeff.

And our next question comes from the line of Juan Jarrah of TD Securities. Your line is now open.

Great. Thanks for taking my question, gentlemen; great acquisition. Obviously, it looks like it fits like a glove. Didn't pay a whole lot for it, which is awesome. A question to you is that, is this a read-through to future M&A in the Basin in terms of metrics? Was it just a good deal? And do you think there are more deals to be had like this one, maybe given some of the infrastructure bottlenecks?

Well, I certainly think J.J., that this was an area that we were probably most familiar with. I think, we had an information advantage. We've been looking at this area pretty hard for really the last couple years, and they participated in a couple of our wells, and we've had some data exchanges up there, and we're really interested in the work that they were doing in particularly the Middle Spraberry and the Wolfcamp A. So like you said, this one fits hand in glove, but it does kind of describe the characteristics that we look for in additional deals. And my track record is to never comment on deals until we have a deal. But this is a good example of what we're looking for. So to the extent there's other deals like that out there, Diamondback is going to continue to be in the game of building through accretive acquisitions.

Great. Appreciate that. Second question is on long-term takeaway. You're talking about call it 225,000 barrels of oil a day in the 2020 timeframe. Is that a good read through to where you think your oil production could go to say by say, year-end 2019 or 2020?

I can't comment on 2019 or 2020 production, but certainly we are taking enough takeaways that our asset base will not have to deal with the issues that we're dealing with today by taking the space ourselves. It looks to be like – we'll be covered for a long time and protecting the growth plan while limiting our downside. Half of that's going to be take or pay, which is about what we're doing today on a gross barrels basis, so a lot of flexibility for us to scale up.

That's helpful. Last question, I did notice the last slide in your slide deck, you pushed back the Limelight appraisal back to 2019. Just curious as to what factors went into that decision? And that's it from me.

Yeah, with 95% of our oil on pipe and Limelight not being on pipe, with trucking costs where they are and diffs where they are, it's just not a priority at this time. So sometime in 2019 the geos will get their wish and we'll do our tests, but certainly from the economics perspective, we have our better money to put elsewhere in the basin right now.

Appreciate your time. Thank you.

And our next question comes from the line of Derrick Whitfield of Stifel. Your line is now open.

Good morning, all, and congrats on a strong quarter and great acquisition.

Thanks, Derrick.

Reading between the lines, it seems that you guys are incrementally positive on the Middle Spraberry following this acquisition in your geologic work. Can you remind me the de-risking assumptions for this interval across your legacy position and speak to what degree the geological data suggests there is upside to your inventory assumptions?

Yeah, it certainly changes our inventory assumptions in the Northeast Andrews and the Northwest Martin area, for the Middle Spraberry, it moves up the list. I think we see a lot of Middle Spraberry potential along the western portion of our acreage in the Midland Basin, and we've seen some testing further east, but certainly on the west side, we're testing it in Midland County, actually it's kind of in full development mode now in Midland County, and this pushes the Middle Spraberry further north into a northern portion of the play.

Thanks. And as my follow up, referencing page 27 of the PowerPoint, could you comment on the strength of the State Biggs well? That's one of the most productive wells in that group, and also has the highest oil composition. Did you guys test a new landing zone within the lower Wolfcamp A?

No, it's just a really good well.

Got it. Thanks. Thanks for taking my questions.

You bet. Thank you, Derrick.

And our next question comes from the line of Michael Hall of Heikkinen Energy. Your line is now open.

Thanks. Good morning, guys. Appreciate the time. I guess, just on the – as you think about capital allocation after Ajax, and just kind of – if you were to try to rank across the portfolio, I guess, how do you think about relative returns across the portfolio, and in that context, how should we think about rig allocation across the portfolio as we move forward post-Ajax?

Well, certainly the commentary that I've been using that this fits in the top quartile of our portfolio gives you a pretty good idea of where the Ajax 225 locations sit plus the other locations that are on our legacy assets. So one of the earlier questions was getting up to that 16-plus rig cadence, and we still intend, Michael, to have pretty equal capital allocation between the Midland Basin and the Delaware Basin side. And when you get inside the Midland Basin with half our rigs, we'll probably maintain about the cadence that we've got or the location that we've got now with the 6 rigs we're running.

Okay. And yeah, I guess as my follow up to – kind of relating to that, as you think about ramping to the higher rig count, I guess, kind of 17 to 20, I guess is kind of the indication there, how do you think about inventory depth in that framework? Like, how would you quantify how long you could run at that level?

Well, if you just look at what we did with this last acquisition, I've said, 1 to 1.5 rigs and that's going to give me with those locations that we called, that's super tier 100% rate of return. That gives me 7 to 10 years of drilling just on this newly-acquired acreage. So with the continued good results we're seeing in Pecos County, we listed several wells in our press release. The Reeves County stuff along the Reeves border, we're still early in the game there, but we've just got outstanding well results. So I think we've got a long runway of inventory even at a higher rig cadence.

Okay, got it. And then how quickly you think you could get to that rig cadence given the current strip?

Right now it's a rig every five or six months, certainly when dips come in and we start getting another $10 or so of realizations, that will move down to the three or four month range. But we want to maintain our efficiencies and not try to grow too quickly. So somewhere in the three to six month range depending on realizations.

Okay. That's helpful. Thanks, guys.

And our next question comes from Jeoffrey Lambujon of Tudor, Pickering, Holt. Your line is now open.

Good morning. Thanks for taking my questions. Just a follow up first on the infrastructure question on the acquired acreage, anything in mind from an oil gathering standpoint that I guess might be beneficial towards bringing the assets the same level of capital efficiency as the rest of your portfolio?

Yeah, their oil is already on pipe with – gathered by Reliance, and we're on the Reliance system up in that same area as well. So we won't call in any oil gathering on lease. That will come straight to the battery.

Got it. And then on the location count, appreciate the split by target horizon for the top quartile locations but just hoping to get a little more color at the county level as well. Of those top quartile locations are any of those in Dawson or is that potential upside versus what is written in for Martin, Andrews thus far? It looks like there's a little bit of Middle Spraberry potential in Dawson based on slide 12?

Yeah, there's a little Middle Spraberry potential, but it's certainly not in the top quartile inventory number, the 100% IRR number.

All right. Appreciate it.

And our next question comes from the line of Jason Wangler of Imperial Capital. Your line is now open.

Good morning. Wanted to just ask on the acquisition, it sounds like they're drilling with one rig and on some pretty significant pads. Will there be any more wells coming online there or should we kind of think about where that production should be around the timing of the actual closing of the acquisition?

Yeah, I would expect the production to bleed off a little bit into the close of the transaction. They just brought a full oil pad on that hasn't quite peaked yet, but it's getting close to its peak. And then – so at the time of close, it will probably be a little lower than the 12,000 boes a day today, and with a 12-well pad coming on sometime in Q2 of next year, the ramp will be significant.

Okay. That's helpful. Thank you.

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

Thank you. Good morning, Travis, to you and your team there.

Good morning, Charles.

I'm wondering if you could help us – I like these stoplight maps you put on slides 11, 12, 13. And I think the name helps with the interpretation. But I'm wondering if you could guide us a little bit more in what you're representing with these colors and how it interacts with the inventory. And my understanding is that the thermal maturity goes to a pretty rapid transition right around that Dawson Martin line. And is that really what we're seeing represented on this map?

Yeah, that's one of the parameters that our geoscience group uses when they put these stoplight maps together. I believe this is the first time that we've shared these stoplight maps with the market. But this is one of the things that we look at across the whole Permian Basin that our geoscience teams have put together that allows us to high grade our business development opportunities.

Got it. Thank you. And then talking about some of the recents, you mentioned that Ajax has kind of expanded the prospectivity in the Wolfcamp A and you mentioned in the slides that you could perhaps push that to the southwest for the Wolfcamp A. What do you need to see or what do you need to learn to expand that prospective zone in that direction? And is that the same sort of thing that you'd have to see or learn for the Wolfcamp B?

Yeah, it's just time. It's just going to take time. We've seen referencing the Wolfcamp B, there's been some really good results recently moving north from some private operators in the Wolfcamp B as well. So we kind of like to fast follow and certainly we anticipate the Wolfcamp A to continue to move. These stoplight maps change over time, and in this area, they've gotten better.

And Charles, if you look specifically to slide 13 on our slide deck, that's the Wolfcamp A well performance, and that's over 365 days where it's came over 350,000 barrels of oil only. So significantly above the type curve. And so those are the type of indicators that we look at to push development. And you can see even the second well that's been on for little over six months, there's also well-above the type curve. So we like to think very conservatively in terms of our type curves, but outperformance certainly drives future capital allocation.

Got it. That's helpful, Travis. Thank you.

You bet, Charles.

And we have a follow-up question from the line of Juan Jarrah. Your line is now open.

Thanks, guys. Sorry about that. Just following up the Ajax acquisition, just curious as to the 12,000 barrels currently being produced; A, what formation is that primarily coming from? And B, can you quantify how many horizontals are currently producing? Just want to get a sense of the land versus the inventory versus the existing wells.

Yeah, I'd say of the 12,000, five or six wells, horizontal wells make up 33%, 35% of it. There's a lot of legacy horizontal wells drilled by an operator prior to Ajax that just aren't very good wells. There's also some vertical production on the acreage. So very early in its development, I'd say, it's the majority of the flush production is coming from multi-zone pads. They did a lot of – they did two or three well STACK pads in the A, MS and LS throughout the first part of this year.

Very helpful. Thank you.

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

Thanks again to everyone participating in today's call. If you have any questions, please contact us using the information provided. Thanks.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a great day.