Diamondback Energy Inc (FANG) 2018 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy Second Quarter 2018 Earnings Conference Call.

(Operator Instructions) 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 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 multizone 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 2 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 into 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-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 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 we have made across our positions, mainly on our Delaware Basin acreage, are beginning to show benefits via higher realizations and lower LOE.

We have the majority of all oil and gas, fresh and saltwater, on pipe across both of these positions, and full-field electrification will lower our ESP power generation costs by up to $60,000 per month per well when in place throughout the second half of 2018.

Turning ahead to Slide 23.

Diamondback continues to focus on growing per share earnings and maximizing corporate level returns.

Our cost structure and disciplined approach to investment facilitates greater per share EBITDA and earnings growth, as reflected in our industry-leading return on average capital employed.

We believe our current acquisition of Ajax will help facilitate this strategy further.

Slide 26 shows that Diamondback completed a record 465,000 lateral feet across our portfolio this quarter, up 72% from 2Q 2017.

We continue to maximize long laterals and efficient pad development across our acreage.

Longer laterals improve capital efficiency and pad development reduces cost for both drilling and completions.

We also believe that efficient pad development aids in maximizing ultimate recoveries and reduces PD F&D.

With these comments now complete, I'll turn the call over to Tracy.

Thank you, Mike.

Diamondback's second quarter 2018 net income was $2.22 per diluted share, and our net income adjusted for noncash 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 completion and nonoperated properties, and $88 million on infrastructure and midstream investments.

For the first half of 2018, we generated $20 million of free cash flow, excluding acquisition, and have now cash flow at the 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 1.3x 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 minerals interest 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 per 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 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 have 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 on 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 the 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.

(Operator Instructions) Our first question comes from the line of Neal Dingmann of SunTrust.

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 are 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 is already a potentially of 6-well or soon to be 12-well pad?

And as well as, kind of, how many rigs you plan on running down in the area?

Yes, Neal.

Good question.

When you look specifically at the assets and what's going on right now, there's 1 rig that's operated by Ajax.

Again, we don't close the acquisition till the 31st.

And working with the Ajax team, they are on the 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 in potentially picking a second rig up on this acreage depending on the 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 if -- even if you look in some of your Delaware areas in Pecos and Reeves or Ward, could you talk about maybe plans?

I know previously or 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?

Yes.

I laid out in my prepared remarks for Ajax, we're going to immediately begin developing 3 zones: the Middle Spraberry, Lower Spraberry and Wolfcamp A. On the legacy assets, on the Midland Basin side, we've been developing multi-zones in the Lower Spraberry and Wolfcamp A, and we 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 and now we're drilling multi-wells, certainly, per pad, but they're really focused right now on the Wolfcamp A to address lease obligations.

And our next question comes from the line of John Nelson of Goldman Sachs.

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

Travis, while the midpoint of 2018 CapEx guidance moved up, it was pretty modest relative to some of your peers and seemed to actually be more kind of midstream-focused.

Can you speak to what kind of pricing pressures you are seeing in the field?

And if you think that it'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 costs 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 on the -- in the Delaware Basin side also on the regional sand.

So on the -- 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 are 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 the efficient execution of our development plan and holding costs.

So we feel very comfortable about our cost projection.

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 have in the basin day to day.

Could you just speak to kind of how congested or tight both the labor and service pool market kind of feel down in the Permian today?

Yes.

The guys that are a little closer to that and on -- our 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 that's -- 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 planned out a 12th and 13th rig in 3Q.

I'm guessing 1 of those 2 is the Ajax rig.

Just where is the other rig go to?

Yes -- no, that doesn't include the Ajax rig.

That rig, we'll just assume that rig on 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 seventh rig in the Delaware Basin right now and just getting ahead of some of obligations we have in 2019.

But from a cadence perspective, we're going to stay at 5 crews.

We added our fifth crew in Q2 and we're going to stay at that 5-crew pace for the rest of 2018.

And the next question comes from the line of Asit Sen of Bank of America.

On the addition of the 2 rigs in 3Q, it looks like, Travis, you talked about the reasoning for that.

Now, previously, you have 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 '18 on average pad size?

Yes, I will answer those in reverse.

We've not really provided any color or commentary on 2019 yet.

Those comments will be coming.

But in general, more -- we said in each quarter that we're seeing more and more wells per development unit.

It 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 have 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 have seen that is we have had some downstream processing plant to do some upgrades and some line moves, so I think that's generally the only time we will 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.

And our next question comes from the line of Mike Kelly of Seaport Global.

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 in the potential debt raise to fund this.

Are you contemplating any equity alongside that, too?

We've gotten that question this morning.

Yes.

Mike.

No, we are not contemplating any equity associated with this trade.

You've heard me say multiple times that in the business development and 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 is 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.

And if you look specifically at the Ajax trade, the geos, 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 by 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 service facilities that get included in their toolbox.

And then this wasn't a broker a deal, and as I mentioned, we're not doing equity.

So everybody loves it because there is not going to be any banker fees associated with this trade.

So it's just -- 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, a lot of good slides here to lay out that opportunity.

Maybe you could just kind of frame this up for us a little bit in terms of the ultimate value proposition to paying shareholders and really kind of what the playbook is here going forward?

Yes.

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.

We are 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.

And our next question comes from the line of Gail Nicholson of KLR Group.

Just talking 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?

Yes, Gail.

So over the Delaware side, we pound put more foot -- 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 tasks coming up where we'll try it.

We've got a bunch -- or several offset operators that we're watching and working with and have done it as well.

So the dataset is coming is it's looking very favorable to be able to do that.

But you will have a bigger effect over the Delaware than you do 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 a 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, Gail.

And we've scaled the business pretty significantly in the last year as well.

But in general, on the Midland Basin side, we completed -- or we drill roughly 22 wells per rig per year, and we drilled longer and longer laterals on the 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 are actually drilling in.

On the completion side, Midland hitting on all 8 cylinders as they have been for several years, and we're always adjusting size of the jobs slightly.

So that has an effect on how many stages you can get to at the end of the 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 are probably in the fifth inning on the basin side and probably third or fourth inning over on the Delaware side.

So there is 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 -- for part of the Ajax acquisition.

When you look at just where you are in the portfolio with the incremental high-quality inventory pick-up for 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?

Yes, 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 cleaning 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.

And our next question comes from the line of Jeff Grampp of Northland Capital.

Was curious on the Ajax's acquisition at that area overall.

It looks like that represents, kind of, I guess, the majority of your Midland inventory now.

So can guys just kind of talk about rig allocation?

I think you mentioned 1 to 2 rigs.

But can you clarify that just on the Ajax piece?

Or is that the entirety of that kind of Northeastern Andrews, Northwestern Martin area for you guys?

Then, can you also touch on any infrastructure investments that might make sense on the Rattler site as you integrate Ajax?

Yes.

So the comment on 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 wells because it has -- 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 freshwater 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 freshwater side.

We can connect the saltwater disposal system 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 3 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 will be adding 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 is there any maybe plans in the medium term to add another frac crew?

Jeff, basically, the rigs that we're picking up today, we're drilling multi-well pads.

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 are not going to appreciably change our DUC count.

But picking up early, again, these wells come in late in fourth quarter is when we tee-in to move off the pad.

So again, wouldn't change production in 2018.

And our next question comes from the line of Juan Jarrah of TD Securities.

Great acquisition.

Obviously, 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, JJ, that this was an area that we were probably most familiar with.

We -- I think we had an information advantage.

We had been looking at this area pretty hard for, really, the last couple of years.

And they participated in a couple of our wells.

And we have had some data exchanges up there and we are really interested in the work that they were doing, and particularly in 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 with their 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 good read-through to where you think your oil production could go to by, say, year-end 2019 or 2020?

I can't comment on 2019 or '20 production, but certainly, we are taking enough takeaway that our asset base will not have to deal with the issues that we are dealing with today by taking the space ourselves.

It looks to me like we will be covered for a long time and protecting the growth plan while limiting our downside.

Half of that is 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 to Limelight appraisal back to 2019.

Just curious as to what factors went into that decision?

And that's it for me.

Yes.

With 95% of our oil on pipe and Limelight not being on pipe, and with trucking costs where they are and dips where they are, it's just not a priority at this time.

So sometime in 2019, the geos will get their wish and we will do our tests.

But, certainly, from an economics perspective, we have our better money to put elsewhere in the basin right now.

And our next question comes from the line of Derrick Whitfield with Stifel.

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 of your risk and assumptions for this interval across your legacy position and speak to what degree the geologic data suggest that there's upside to your inventory assumptions?

Yes, certainly.

Changes in our inventory assumptions in the Northeast Andrews and 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 have seen some testing further east.

But certainly, on the west side, we're testing it in Midland County, actually kind of in full development now in Midland County.

And this pushes the Middle Spraberry further north into a northern portion of the play.

And just 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.

Our next question comes from the line of Michael Hall of Heikkinen Energy.

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 fit, plus the other locations that are on our legacy assets.

So one of the other 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 will probably maintain about the cadence that we have got -- or the location that we've got now with the 6 rigs we have got going.

Okay.

And yes, I guess, it's my follow-up kind of relating to that.

As you think about ramping to the higher rig count, I guess, kind of 17 to 20, I guess, kind of indication there.

How do you think about inventory depths in the 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 said 1 to 1.5 rigs.

And that's going to give me with those locations that we call 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 this -- in our press release.

The Reeves County stuff along the Reeves Ward border, we are still early in the game there, but we have 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 how quickly you think you could get to that rig cadence given the current strip?

Right now, it's a rig every 5 or 6 months.

Certainly, when dips come in and we start getting another $10 or so of realizations, that will move down to the 3 or 4 months' range.

But we want to maintain our efficiencies and not try to grow too quickly.

So somewhere in the 3- to 6-month range depending on realizations.

And our next question comes from Jeoffrey Lambujon of Tudor, Pickering & Holt.

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 to the same level of capital efficiency as the rest of your portfolio?

Yes, their oils are 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 own any oil gathering on lease.

That will come straight to the battery.

Got it.

And then on the location count.

I appreciate the split by target horizon for the top part 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's written in for Martin and Andrews thus far?

It looks like there's at least a little bit of Middle Spraberry potential in Dawson there based on Slide 12.

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

And our next question comes from the line of Jason Wangler of Imperial Capital.

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?

Yes, I would expect the production to bleed off a little bit into the close of the transaction.

They just brought a 4-well 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 the 12-well pad coming on sometime in Q2 of next year, the ramp will be significant.

(Operator Instructions) Our next question comes from the line of Charles Meade of Johnson Rice.

I wonder if you could help us -- I like these stoplight maps you put on slide 11, 12 and 13.

And I think that the name helps with the interpretation.

But I wonder if you could guide us a little bit more in what you're representing with these colors and how it interacts with the inventory.

My understanding is that the thermal maturity goes through a pretty rapid transition right around that Dawson Martin line.

And is that really what we're seeing represented on this map?

Yes, 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 have shared these stoplight maps with the market.

But this is one of the things that we look at, of course, across the whole Permian Basin that our geoscience teams have put together that allows us to high-grade our business development opportunities.

Got it.

And then talking about some of the reasons, you mentioned that Ajax is -- has kind of expanded the prospectivity in the Wolfcamp A. And you mentioned in the slides that you could, perhaps, push back to the southwest for the Wolfcamp A. What do you need to see here or what do you need to learn to expand to that -- to expand that perspective zone in that direction?

And is that the same sort of thing that you would have to see or learn for the Wolfcamp B?

Yes.

It’s just time.

It's just going to take time.

We've seen, referencing the B, there has 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 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 at Slide 13 on our slide deck, that's the Wolfcamp A well performance.

And that's 300 -- over 365 days where it has gained 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 a little over 6 months there.

That's also well above the type curve.

So we're very -- we like to think very conservatively in terms of our type curves.

But outperformance certainly drives future capital allocation.

And we have a follow-up question from the line of Juan Jarrah.

Just following on to 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.

Yes.

I'd say, of the 12,000, 5 or 6 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 would say it's the majority of the flush production is coming from multizone pads.

They did a lot of -- they did 2 or 3 well stack pads in the A, MS and LS throughout the first part of this year.

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.