Diamondback Energy Inc (FANG) 2017 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy Second Quarter 2017 Earnings Conference Call.

(Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to introduce your host for today's conference, Adam Lawlis, Director, Investor Relations.

Sir, you may begin.

Thank you, Demetria.

Good morning, and welcome to Diamondback Energy's Second Quarter 2017 Conference Call.

During our call today, we will reference an updated investor presentation, which can be found on our website.

Representing Diamondback today is 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 2017 Conference Call.

In the past 12 months, as commodity prices recovered, we've more than doubled production and doubled our Tier 1 inventory.

We can grow at a differential rate within cash flow for multiple years even in today's volatile commodity price world because of the quality of our asset base and our commitment to being the lowest-cost operator.

Well results continue to improve across our asset base, and we're particularly pleased with our first set of operated wells in the Southern Delaware Basin, including the second Bone Spring result that can compete for capital with a high rate of return Wolfcamp A in Pecos County.

Our relentless focus on capital efficiency and low-cost operations was prevalent this quarter with less than $8 a barrel cash operating cost and positive free cash flow, excluding acquisitions, for the second quarter in a row.

Because of these capital efficiencies, we're increasing full year production guidance while lowering CapEx guidance and decreasing both LOE and G&A guidance.

We are operating 9 rigs today; 6 in the Midland Basin and 3 in the Southern Delaware Basin as well as operating 3 dedicated completion crews.

At current commodity prices, we plan to maintain this 8 to 9 rig cadence for the remainder of 2017.

As shown on Slide 5, our strategy has not changed.

We are well positioned to change activity as operational cash flow allows with over 4,300 locations economic at $50 oil and today's capital costs.

We believe our combination of best-in-class efficiency and history of accretive acquisitions of Tier 1 assets has consistently driven shareholder value and will allow us to continue to generate industry full leading -- full cycle returns.

I'll now turn the call over to Mike.

Thank you, Travis.

Turning to Slide 8. We have new data from multiple well results across our Southern Delaware Basin assets.

Including 3 Wolfcamp A 30-day IPs and recent data from our first 2 landed, drilled and completed Pecos County Wolfcamp A wells.

We are also particularly pleased with the result of our first completed lower second Bone Spring well on our Pecos asset with an IP30 in oil cut comparable to our best Wolfcamp A wells.

We are currently running 3 rigs in the Southern Delaware Basin with 1 dedicated completion crew.

Additionally, we are maximizing netbacks by building and upgrading infrastructure across our asset base.

Slide 10 shows the performance of our Southern Delaware Basin wells at or above our expected type curves for the area.

Early time results in Pecos County suggests that a stack and staggered approach has the potential to increase recovery factors in the area.

Slide 12 expands on our success in the second Bone Spring formation in Pecos County.

The Kelley state well, which targeted reservoir rock about 300 feet deeper than previously targeted second Bone Spring wells in the area, had an IP30 of 190 BOE per thousand feet of lateral compared -- comparable to other Wolfcamp A wells in the Delaware Basin.

This target is almost 1,000 feet shallower than the Wolfcamp A with less pressure, significantly reducing drilling and completion cost.

Turning to the Midland Basin.

Slide 14 shows encouraging results from our first 500-foot interlateral spacing test in Andrews County, compared to 660 foot-spaced offset wells.

We are currently, running 6 rigs in the Midland Basin and 2 dedicated completion crews and plan to stay at this pace for the remainder of 2017 at current commodity prices.

Slide 15 shows our continued improvement in Howard County, especially in the Wolfcamp A and Lower Spraberry as we have optimized landing points, spacing and completion design over the past 12 months.

Turning to Slide 16.

Controlling capital and operations cost -- operating cost have remained a core tenet of our company strategy as we continue to optimize DC&E cost while expanding cash margins even in a low commodity price environment.

We have recently signed a deal with a local sand provider that will enable us to save around 5% on current total well cost in the Midland Basin as well as secure low cost supply for multiple years.

We expect to begin using this product in the Midland Basin and potentially shallows on in the Delaware Basin in early 2018 as the mine comes online.

Turning to Slide 18.

At $50 oil and current capital and cash costs, the Lower Spraberry and the Midland Basin and the Wolfcamp A and the Southern Delaware Basin continue to display exceptional Tier 1 economics, which will compete for capital in our portfolio for years to come.

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

Thank you, Mike.

Diamondback's second quarter 2017 net income was $1.61 per diluted share and our net income adjusted for noncash derivatives was $1.25 per diluted share.

Our adjusted EBITDA for the quarter was $218 million, up 25% from Q1 2017 due to increased production and lower costs.

During the quarter, our cash operating costs declined 18% relative to Q1 to $7.66 per BOE.

This includes LOE of $4.14 and cash G&A cost of $0.82.

With our exceptional performance on cash operating expenses, we are lowering LOE guidance by 19% and cash G&A by 33% from prior midpoint.

During the quarter, Diamondback spent $157 million on drilling and completion and $18 million on infrastructure and non-operated property.

As a result of continued efficiencies and execution, we are lowering our CapEx guidance to $800 million to $950 million from $800 million to $1 billion previously.

As shown on Slide 20, Diamondback ended the second quarter of 2017 with a net debt to Q2 annualized adjusted EBITDA ratio of 1.3x and $681 million of liquidity.

Our full year 2017 production guidance presented on Slide 21 was increased 5% from prior midpoint while reducing CapEx guidance.

Additionally, we will have decreased LOE, G&A as well as gathering and transportation guidance.

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 decreasing capital spend and cash operating costs for the year.

We have the ability to differentially grow within cash flow for many years at nearly any commodity price given the strength of our Tier 1 inventory.

Operator, please open the line for questions.

(Operator Instructions) And our first question comes from John Nelson with Goldman Sachs.

The press release mentioned a determiner of future production growth will be returns to shareholders.

Travis, I just wondered if you can maybe elaborate on what that really means to you and how the team considers shareholder returns during the capital allocation process.

Sure.

Well I think the first metric that we look at is -- certainly go within cash flow.

And as we allocate capital within our ability to use operational cash flow, we look at the returns metrics as we compare different projects one to another and we try to always allocate to those projects, which generate the highest rate of return.

And we also take a more of a corporate look at it as well, certainly when we do M&A activities, the way we look at returns on a full cycle basis as well where we include the cost of everything that's embedded in the investment decision.

And it's just a commentary that we're having internally, and it's one that we think is the right way to continue to drive shareholder value.

Just maybe to follow up on that.

As you continue to kind of mature as a company, is there a certain inflection point where you think it might make sense for Diamondback to start paying a dividend or buying back shares?

Or is it just something that's always contemplated...

Yes, certainly, John.

We look at the way that we can grow within cash flow and we look at what the future years look like.

And those type of conversations, while we might have them internally, are still premature.

We've got a lot of really outstanding wells to convert into cash flow, and we look forward to doing that for many years to come.

And to the extent we have those opportunities in the future, we'll have the conversation at that time.

That makes a lot of sense.

And I guess as my second question.

Last night, one of your peers highlighted the need for a fourth string of casing on the Midland Basin, particularly in Midland and Martin County as in areas where there's more vertical depletion.

I was wondering if you could just speak to if that's something that you're seeing, or what kind of the standard design is for some of your Midland Basin horizontal wells?

John, across the Midland Basin, we run a 3 string design.

But again, as we drill through several of these counties in different zones, we encounter similar issues with losses and pressure.

Again, it's just what we do each day.

It's blocking and tackling.

So again, we just -- we have our plan, and we execute the plan in each one of the areas.

And each one of the areas are slightly different as to where we set casing and whatnot.

But currently, the 3 string design is what we run across the entire Midland Basin side as well as the Delaware Basin side at this time.

Yes, John, all of our plans are 3 strings design.

All the wells we've done historically have been 3 strings.

And as we plan the future going forward, there's 3 string designs as well.

And our next question comes from Neal Dingmann, SunTrust.

Travis, question.

I think that it's obvious that, that long-term agreements you guys signed and talked about here on the proppant supply looks very positive to save about 5%.

Could you talk about the potential for -- I mean, I guess, number one, what percentage of just overall Midland production will that -- will this particular contract encompass?

And is there prospects for more of these?

Neal, this is Kaes here.

I don't want to give specific contract details, but I will say that we have the ability to flex up and down with the amount of spreads that we're running in the Midland Basin today as well as our projected use over the next couple of years.

So I think, one, this grants us a secure supply for almost as much as we need on the Midland Basin side.

And two, it locks us in at a price that we're very happy with compared to current well costs today.

Got it.

And one just last one.

Somebody already asked on as far as what the 4 string case.

And I guess my question either, Travis, for you, or Mike, when you just look at sort of what the GUR, you all tend to continue to be a bit more stable than what I see from other companies in the area.

Is there anything particular on what you're doing on the operations side, just your particular rocks that you're in?

Or anything you can just talk about on your GUR expectations and what you've seen so far?

Yes, Neal.

Just a couple of points.

We're very confident in how we forecast our business, whether it's reserves or CapEx, production, that's what we do.

We spent a lot of technical time forecasting our wells, studying our type curves, understanding the reserves and how they're going to be produced, and we vet those externally with our reserve auditors.

We believe we're going to continue to deliver on our growth and production forecast in the future because we execute.

That's what we do.

And we're very confident in our future forecast.

And I know there's a lot of questions out there, but I can't stress enough that it's -- that we're confident in how we execute on our forecast, it's what we do.

And our next question comes from Drew Venker with Morgan Stanley.

I was hoping you could talk a little bit more about capital allocation decisions as we head into 2018, where you're thinking the most attractive areas of your Southern Delaware are, and any changes in priority in the Midland Basin?

I guess you talked about multiple core areas on both sides of the Permian, but any updated thoughts there would be appreciated.

Sure.

So we took over operations in March, and we're still trying to understand exactly what the return profile is going to look like for the Southern Delaware wells.

As we underwrote the acquisition, we demonstrated, based on the data we had at hand, that the Wolfcamp A competed for capital from some of our better investment opportunities on the Midland Basin side.

And so with -- if that holds true and we expect it will, then you'll see us migrate more towards an equal allocation of activity on the Midland Basin side and the Delaware Basin side.

But again, back to the question that John was asking earlier, we're going to continue to monitor the returns review, and then we're going to allocate capital to the highest rate of return projects that are going to ensure that we generate the greatest corporate return.

But as we understand it right now, we're going continue to allocate pretty equally on both sides of the basin, recognizing that we're still early in the game on the Delaware and it's going to take us a while to ramp up rig activity to equal what we have on the Midland Basin side.

That's helpful color, Travis.

Appreciate that.

And a little bit more on the Delaware Basin, if we could stay on that.

Can you give us a sense of how much additional learning you think you could really benefit from in the Delaware Basin, because it's, obviously, still fairly new to a couple of those assets?

And how much time you think you need to really hone in the design?

Obviously, understanding that it's never going to be 100% there to perfection, but how much additional time do you think you need before you've kind of settled on the design?

Yes, I'm pretty confident that we've got over 4,500 wells in our inventory.

I'm pretty confident that, that 4,500th well, we're going to be doing something different than what we're doing today.

The laboratory that we're in, we continue to evolve on a well-by-well basis, and we do that in the form of continuous learning.

And that's -- I think anytime you find an organization that demonstrate an excellence, you'll see continuous learning.

So every well, there's a laboratory.

In every well, we plan it, we understand the results, we change our behaviors if necessary, and we do it again.

And we continue that cycle over and over again.

We're much more confident on the Midland Basin side because we've been there now for over 5 years.

We've just moved into the Delaware Basin and we're trying to do that same process.

I'll tell you though, Drew, just to give you an example, we talked about it in our release, that 2nd Bone Spring well.

Now that was a well that was drilled and completed -- drilled by Brigham and completed by Diamondback.

And it was a zone that we ascribed as virtually no value to in the acquisition when we underwrote it, but yet it comes on now at a rate that's competitive, as Mike explained, because of lower capital cost.

It's competitive as we allocate capital.

So that was something that is just, I would say it's more than a nice surprise, and we've got still some work to do to define how much running room we have exactly in front of the Bone Springs.

But we're always in a process of learning.

And the advantages that we've had in operating in the Midland Basin now for over 5 years, we believe that we can transfer that into the Delaware Basin, whether it's on the cost or the completion or any of the technical aspects of developing this reservoir, we're going to transfer that over to Delaware, and we intend to operate the Delaware best-in-class, like we do on the Midland Basin side.

And our next question comes from Michael Glick with JPMorgan.

In Pecos County, could you talk a bit about ESPs, and specifically, when you're putting new wells on pump.

And just on new wells, when do they typically reach peak production after flowing back?

Well, we've got a program underway right now.

We've put a dozen or so ESPs in the ground there and we saw quite a bit of success in the Midland Basin side.

When we did that on a early base -- or early time flowback characteristics, and we're testing that right now.

It's still too early to say exactly whether or not it's going to be successful or not.

But I'll tell you, we like the early returns on what we're seeing there.

Okay.

And then it looks like you guys have already reduced drilling days in Pecos County.

Can you talk about some of the drivers there?

Michael, yes, drivers on the Delaware side are no different than they are or they were on the Midland Basin side.

It's just the daily bid selection, mud selection, it's one of the thousand decisions that are made daily that go into that.

So it's just natural blocking and tackling what we're doing on the optimization front.

So again, it's just new rock.

It's spatially very large over here with 100,000 acres.

So there's little interest -- intricacy differences between each one of the areas.

But again, that's something that we do every day on the Midland Basin side.

So we expect to see those same kind of improvements on the Delaware side.

Michael, when you look at our history of moving into a new area, typically, it's always been in the Midland Basin side.

But when -- we were first movers into the Martin County and start developing that horizontally, we took the initial well very strategically, and we took it down substantially.

When we moved into Howard County, we did the same thing on our execution, we drove days down in the same way on the Glasscock County where we drove days down.

And again, if you go back to that continuous learning that I was talking about earlier, that's what we do, we focus on execution with a laserlike focus, and we learn from the things that we do in the way that it manifests itself in things that can be viewed externally, our lower well cost, higher cash margins, lower LOE and lower days to TD, and the question that you just asked.

And then just lastly for me, on the 2nd Bone, any quantification on how you see cost shaking out in that zone, given it’s relative depth versus the Wolfcamp?

Rough -- being 1,000 foot shallower and lower pressure, we're roughly $1 million cheaper on the lower 2nd Bone Spring wells versus the Wolfcamp A.

And Michael, that 2nd Bone Spring's interval is about 400 to 500 feet thick, and I think it runs pretty much as we've got it mapped across the whole position.

So again, we can't get out front of this thing, but it has -- it certainly has us pretty excited about the future development opportunities in that zone.

And our next question comes from Gail Nicholson with KLR Group.

LOE continues to be impressive, but when you look at that, the forecast being lowered this quarter, what is the biggest surprise there?

Are you achieving better LOE over in the Delaware?

Is that more Midland-driven?

Can you just provide a little bit more color regarding that?

Sure, Gail.

Let me just tell you how proud I am of our operations organization for continuing to push the ball down the field on lower and lower cost.

They've heard me say numerous times that we're not going to quit pushing until we can produce these wells for free.

But really, we took over a new operations area this year in the Delaware Basin with 100,000 acres, and I'm just really proud of what we've been able to do to continue to drive cost down there.

I'll say we probably were a little cautious in our early forecasting of expenses there because it was an unknown area, but they've done a really great job.

And on the Midland Basin side, the guys have continued to do the things that you've got to do to execute as a best-in-class operator.

We continue to monitor every month our well failure rates, whether they're on the rod pumps or the ESP.

And the guys have done a great job of continuing to reduce well failures, which ultimately drives lower cost as well.

And then the other thing, when you're doing a ratio like dollars per barrel, really, the best way to drive that lower is to work on the numerator and the denominator at the same time.

And I think if you look quarter-over-quarter, our total cost on LOE, even after acquiring an additional 100,000 acres in the Delaware, our total cost on LOE only moved up about 3% while our volumes quarter-over-quarter moved up 25%.

So when you do -- when you're working on the numerator and the denominator at the same time, you get really good -- you get really good results.

And like I said, I couldn't be more proud of our operations organization for their continued diligence and relentless focus on cost and expenses.

And then just jumping over to the Andrews County is the downspacing well.

You guys talked about those last quarter, and they were impressive, and the 30-day rates continued to compare favorably, when you

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across the system and Andrews County maybe elsewhere, do you feel like you -- that's the migration that you guys are going to move to?

Or kind of where are you in that downspacing infill game?

Yes, I mean, that was the first 3-well pad we've done at 500-foot spacing kind of in that northern area.

We've got another downspacing test planned.

So we'll just continue to monitor the results and just see where it checks at.

Our next question comes from Asit Sen from Bank of America Merrill Lynch.

So 2 unrelated question.

First, very interesting slide on Slide #5, and thanks for the color on the scenario analysis.

My question is, how does the frac crew cadence change for Slide 5?

And could you remind us, regarding your exposure to spot versus dedicated crew.

And on that slide, are we assuming cash flow neutrality?

Yes, so from a frac group perspective, it typically takes -- for a 6-rig program, it's going to take roughly 2 frac spreads.

And so you can kind of do that ratio of there, 3:1, 3 rigs to 1 frac crew.

And so if we're running on rigs, you pretty much just assume we'll run a 3 frac spreads.

And then specifically, Kaes, do you want to answer that?

Yes.

For the cash flow neutrality, I mean, really, this is kind of a look into the back half of our year this year and, lightly, into 2018 without giving formal guidance for 2018.

Depending on your oil price for 2018, we can accelerate or decelerate as needed.

So that's kind of our target rig counts at today's environment with our current asset base.

Okay.

And the second question is, you just kind of touched upon it earlier.

The opportunity to transfer Midland Basin best practices to Delaware Basin.

And particular interest in the cost side of the business, it looks like if I'm looking at the midpoint of completion cost per unit lent, Delaware Basin, 550 is roughly about 30% higher than Midland.

Could you highlight the moving parts and the early opportunities that you see?

Yes, certainly, the early opportunities are the things that Mike highlighted, just doing the blocking and tackling as he executes a continuous program, and that's taking days out of how long it takes just to get to TD.

A typical day is somewhere between 50 to maybe $70,000 a day, so saving days makes a big difference.

But really, when you look at the depth of the Delaware Basin, some of the pressure issues that Mike also highlighted earlier, that depth and pressure will always cause more dollars to be spent than what you're going to spend on an equivalent well on the Midland Basin side.

So it's going to be more expensive drilling on the Delaware, but as we've highlighted on numerous calls, the fact that you have greater EURs per foot and the rate of capture of those reserves associated with higher pressure still generates an equivalent rate of return.

Great.

And then my last question here.

On Infrastructure spending 2017, I think it's $175 million.

How should we think about 2018?

2017 is still going to stay in that $150 million to $175 million range.

We've spent about $30 million so far year-to-date.

The back half of this year will be pretty evenly weighted on that remaining $120 million to $150 million.

And then going into '18, we're going to revert to more back to our traditional 10% of total capital allocated to infrastructure with -- just in time building of tank batteries, saltwater disposal, fresh water systems, etc.

as the large capital projects are completed in 2017.

And our next question comes from Jeff Grampp with Northland Capital Markets.

Just more on the topic of infrastructure there, can you guys maybe talk a little bit about the status of those buildout projects?

I guess it sounds like they're a little bit more back half-weighted?

But can you just kind of give us a sense for how those are expected to roll out?

And then if we should expect any material change to your cost structure as a result of those investments?

Jeff, a lot of work in progress has already been done.

It's the lag in the invoices coming in is what's driving it more the back half-weighted.

Of course, we got the assets in March, so we've got to work almost immediately on getting these infrastructure projects put in.

It's just more of a timing of that cash flow out the door is what you're seeing.

But there's nothing coming later in the year, it's just the process of getting all the pipe in the ground.

And then from a netback perspective, you'll see a little bit of a difference as these oil systems are in the ground and they'll improve our Delaware netbacks.

Okay, that's helpful.

And then on the low cost side, it looks to us that there was a bit of an uplift sequentially in Midland Basin well cost on a per foot basis.

I was wondering if you guys can maybe give us a sense for what the main drivers are, and I'm assuming it's on the pressure pumping side, but didn't know if that's maybe just kind of based on the completion methodologies you guys are rolling out and if that was kind of expected within the budget.

It seems like costs were maybe expected to kind of level out there, and just was hoping to get some color on how you guys are seeing cost playing throughout the remainder of the year there?

Yes.

I mean, Jeff, the way we see it, if you look at our cost per lateral foot in the Midland Basin, we're still well below the midpoint of our guidance for the year, $5 million to $5.5 million for a 7,500-foot lateral well in the Midland side.

Really, the majority of that is pressure pumping, and the pressure pumping industry has recovered in the past couple of months and a couple of quarters and especially the last quarter.

And I think there will be a lot of pressure pumping equipment coming online, and we'll see where that pricing shapes out in the back half of the year.

But from a guidance perspective, we guided conservatively beginning of the year, anticipating some increases on the pressure pumping side.

And our next session comes from Jason Aschenbeck with Seaport Global.

A lot of the good ones have already been addressed, but did have one question in terms of organic leasing opportunities in the Southern Delaware.

I noticed in the slides, you added about 3,200 net acres during the quarter.

I was wondering what the remaining opportunity set looks like in the area and how much further you think you can grow your acreage footprint there.

And then kind of building on top of that, was curious if you're essentially buying out working interest partners, or are you actually expanding your gross acreage footprint?

It's really a combination.

I think in the reWard area, we did some add-ons.

Also note that via trades, we've increased net working interest in the reWard area from about 49% to almost over 75% today.

So really bringing value forward there.

Down in the Brigham acreage in Pecos, buying out some working interest owners, and that's what really what our land teams are driven to do, is the blocking and tackling, so we can drill 10,000-foot laterals ideally with as high working interest as possible.

Got it, appreciate that.

And is it fair to think that 3,000 a quarter is a good run rate?

Or is there potential to boost that a little bit higher maybe?

Any opportunity that creates some reasonable value for Diamondback shareholders, we will try to take advantage of.

All right.

Fair enough.

And then one more for me.

In terms of upcoming tests on the Brigham acreage, I was just curious if you have any additional completion scheduled from that southeastern-most block in Pecos?

And if so, when should we expect the timing of those?

Yes.

On the Southeast block, we don't have anything planned until those leases are due to come up in the next couple of years.

So you'll see us drilling in the main block, primarily Wolfcamp A wells.

And our next session comes from Jason Wangler with Imperial Capital.

Was just curious on the well counts as you look at the horizontal wells completed, it moved down a little bit, just the function there.

And then as you look at the drilling side of it, do you still expect to have quite a few wells then waiting on completion at the end of the year?

I think if you look at our cadence, we drilled 34 for the quarter, completed 35.

Back half of the year, if you look at the midpoint of our new guide, really, we're going to complete about 30 to 35 wells a quarter for the next 2 quarters.

So we'll probably maintain very close to the pace that we had in Q2, maybe a little bit of acceleration in Q3 and Q4 as we picked up the ninth rig in May and we'll start completing some wells there in this quarter.

Okay.

And just on the sand contract, can you just talk about how much of the regional sand you guys have been using historically in the Midland or even Delaware.

It sounds like that's early days.

And obviously, it sounds like you're pretty much going to shift entirely to that as you move to 2018, just kind of the experience you've had there?

We haven't used any of it yet.

The plant comes online that we're going to be working with in Q1 of next year.

We've done a significant amount of third-party testing.

And all indications point towards this being a sand that's capable of being run in anything in the Midland Basin and everything shallow in the Delaware.

So we'll dip our toe in the water as we always do in Q1 of next year, and all indications are pointing towards this being a cost-saving and high quality product.

And our next question comes from Tim Rezvan with Mizuho.

All my questions have been addressed, so I'll step off.

And our next question comes from Jeb Bachmann with Scotia Howard Weil.

So I guess the last answer to address my question is this is the Monahan mine that you guys were referring to earlier with the sand deal with Black Mountain?

Correct.

And then I guess up in Howard County, just curious how the design implementations to lower the dewatering time period, how that's helped you guys in the quarter and your chances to improve that going forward?

Jim, again, we've done a lot of things as far as landing of the wells, spacing, stack stagger as well as the completion casings, how we complete, whether it's staggering of the A and the B and the lower Spraberry completions as we're fracking these wells.

We're doing a lot of things right now to try to eliminate or reduce some of the water that we have up in Howard County.

And even -- with that said, the water content is typically up in the 2x the oil ratio, so again, still not excessive water.

So but again, everything that we've done has increased the oil production and reduced some of the water -- oil water ratio that we're seeing up in the Howard County area.

And our next question comes from Geoff Jacques with Iberia Capital Partners.

Just to elaborate on a prior question.

With the reduction in those wells with the updated guidance, is a majority of the change coming from Midland or the Delaware?

Geoff, the -- most of the changes just come from not picking up our -- when we set guidance early in the year, end of last year, it was a 6 to 10 rig kind of range.

And as we've gone through the year, we've picked up the ninth rig, and that looks like the cadence that we're most likely going to run at this commodity price.

So moving out that tenth rig and not bringing it in earlier in the year, which was kind of what built that upper end of the cadence range for us, that's really all that drove that.

Yes, you'll see us around 6 rigs and 3 rigs at today's cadence in the Midland and Delaware, respectively.

I also think average lateral length is going to be a little bit longer in the back half of the year as we completed some DUCs on the Brigham acreage that was -- that were under 5,000 feet.

So everything in the back half of the year is closer to that 9,000 foot lateral length on average, which is going to benefit.

Got it.

Got it.

That makes sense.

And then Howard, was there something about the bullfrog design that is causing it to outperform some of the other wells that you guys have laid out?

I mean, we completed those wells in a similar fashion to the other wells.

I mean, we actually think there's something geologically going on in that area that enhanced the results from those wells.

And the next question comes from Michael Hall with Heikkinen Energy Advisors.

I was just curious on the Pecos side, and sorry if any of this has been addressed.

I had some phone issues, I had to drop off.

But the dual zone development in the Wolfcamp A on the Neal Lethco wells, like, what's the game plan in terms of moving forward?

Is that kind of the development plan for the Wolfcamp A, moving forward to come at it with dual development in the A?

Or what additional tests do you have on the horizon to continue to pursue that?

Yes, I mean, we've got a couple of pads that we're drilling right now in Pecos that we're doing that stagger as well.

And so we're testing the results with the idea that we can tighten down the spacing between wells with that stagger.

So ultimately, we have more wells and higher recovery out of the oil out of that Wolfcamp A. And so we'll continue on with the testing and, hopefully, it will work out and our inventory will go up.

Fair enough.

So just to make sure I understand.

So like, you've got a couple of pads for the rest of the year, and maybe we'd get data early next year, let's say.

But the kind of the rest of the development program in Pecos is on a kind of single well in the zone?

And have you identified like the landing zone that you think is most optimal?

I know that's been a question in the past in the Pecos asset.

Just kind of wonder where you're at in that learning curve.

Yes.

So I mean, really, all the -- essentially, all the upcoming wells in all of the Pecos acreage are multiwell pads.

Depending on lease obligations, some leases, a few leases, we'll be drilling on Wolfcamp B wells on old acreage.

So there will be a Wolfcamp A and a Wolfcamp B. But the majority of them are going to be 2 wells in the Wolfcamp A. And as we test different areas of that large acreage block, not everyone will be the same.

But in general, early on, we'll do the -- do the staggered pattern to get some better early time results on that pattern.

Okay.

That's helpful.

Understood.

And I was just curious, in the quarter itself, I know you don't necessarily -- have quarterly guidance per se, but it's a very, very strong quarter relative to estimates, and it just seemed like a -- I would think a solid quarter internally as well.

So how would you kind of attribute the performance in the quarter across the assets and within the various factors on the assets, well performance, downtime, timing of wells, et cetera.

Just kind of curious how you attribute the well, the quarterly performance.

Yes, Michael, at the end of -- or actually, it was in the third quarter, end of third quarter of 2016 when we started ramping up our activity levels, and we actually entered into 2017 with all the high-spec rigs we needed.

We had all the frackers that we wanted, and we were really coming in, executing at the very top of our game.

And I think you've seen that over the last couple of quarters, is that we're not -- we didn't guide for the year of a back-half weighted activity levels.

We've said, "Hey, we're kind of -- we're good and we're steady and we've got exactly what we want." And I think what you're seeing in our quarterly performance is a direct result of us, our ability to execute.

And it -- we touched just about everything this quarter and we still have work in front of us and we still got challenging wells to drill and -- but I'm very confident in Diamondback's organization to be able to execute.

And I don't think you've ever heard me speak privately or publicly without some direct reference to our ability to execute at low-cost operations because in a commodity-based business like we're in, that's how you win the game.

And that's what we talk about multiple times a day here and we're going to continue to talk about that going forward in the future.

That makes sense.

And I guess in that framework or in that context, I can't help but think about M&A.

You guys have, as you said, proven yourself time and again, to be a superior operator in the basin, which suggests you should be able to be a superior acquirer, which you have been in the past.

You've had some time to digest these Delaware assets.

I'm just curious what the appetite is from Diamondback for additional acquisitions or M&A from this point forward?

We've said before that if we can do accretive deals that create reasonable value for our shareholders, we're going to continue to do that because we believe we can assimilate -- we believe we can assimilate and we believe our track record shows we can assimilate acquisitions into our indoor inventory and continue to execute on them.

So as long as deals are out there, we're always going to do accretive deals and we're always going to do smart deals that make a lot of money for our investors.

(Operator Instructions) And our next question comes from Jeff Robertson with Barclays.

Just one question on the infrastructure in the Delaware Basin, can you talk about how the completion of that will affect your 2018 program there, if at all?

I think that you said the target's going to be the upper and lower Wolfcamp A. But also, can you talk to the direction of cost in the Delaware Basin that, that infrastructure will have?

Yes.

On the infrastructure side, the SWD systems are in place right now to handle all the activity that we need on a go-forward basis.

And we'll keep drilling saltwater disposal wells as more of a just-in-time type deal.

On the oil gathering side, oil gathering system should be in place by the end of this year, early next year.

And that will improve netbacks, but it's not going to impact our plans over the next 12 months to continue accelerating in the Delaware Basin.

And we have no further questions in queue.

I would now like to turn the call back over to Travis Stice, CEO.

Thanks again to everyone participating in today's call.

If you have any questions, please contact us using the contact information provided.

Thanks, again.

Ladies and gentlemen, thank you for attending today's conference.

This does conclude the program, and you may all disconnect.

Everyone, have a great day.