Parsley Energy (PE) Q2 2017 Results – Earnings Call Transcript

Parsley Energy, Inc. (NYSE:PE)

Q2 2017 Earnings Call

August 03, 2017 11:00 am ET

Executives

Brad C. Smith – Parsley Energy, Inc.

Bryan Sheffield – Parsley Energy, Inc.

Matthew Gallagher – Parsley Energy, Inc.

Ryan Dalton – Parsley Energy, Inc.

Neal D. Dingmann – SunTrust Robinson Humphrey, Inc.

Analysts

Scott Hanold – RBC Capital Markets LLC

Charles A. Meade – Johnson Rice & Company L.L.C.

Drew E. Venker – Morgan Stanley & Co. LLC

Asit Sen – Bank of America Merrill Lynch

Daniel Eugene McSpirit – BMO Capital Markets (United States)

Jeff Grampp – Northland Capital Markets

Joseph Allman – FBR Capital Markets & Co.

John A. Freeman – Raymond James & Associates, Inc.

Michael Anthony Hall – Heikkinen Energy Advisors LLC

John Nelson – Goldman Sachs & Co. LLC

Kashy Harrison – Piper Jaffray & Co.

Chris S. Stevens – KeyBanc Capital Markets, Inc.

Michael A. Glick – JPMorgan Securities LLC

Gail Nicholson – KLR Group LLC

Operator

Good morning, ladies and gentlemen, and welcome to the Parsley Energy Second Quarter 2017 Earnings Call. My name is Michelle, and I’ll be your operator today. As a reminder, this call is being recorded. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation.

And now, I’m pleased to turn the call over to Brad Smith, Parsley Energy’s Senior Vice President of Corporate Strategy and Investor Relations. Thank you. You may begin.

Brad C. Smith – Parsley Energy, Inc.

Thank you, operator, and good morning, everyone. With me this morning are Parsley’s CEO, Bryan Sheffield; COO, Matt Gallagher; and CFO, Ryan Dalton. During this call, we will refer to an Investor presentation that can be found on our website and our remarks may contain forward-looking statements, so please see our earning release for a discussion of these statements and associated risks including the fact that actual results may differ materially from our expectations. We also make reference to non-GAAP measures, so please see the reconciliations in the earnings release.

After our prepared remarks, we’ll be happy to take your questions. And with that, I’ll turn the call over to Bryan.

Bryan Sheffield – Parsley Energy, Inc.

Thanks, Brad. The second quarter was exciting for Parsley Energy as we validated several resource expansion concepts that will translate to a lot of value for our shareholders. As fast as we’ve grown, we’re still just scratching the surface of the resource potential associated with our first class acreage.

Q2 was typical for Parsley and that we created value in three ways. The first is by growing production at healthy rates of return; the second is by optimizing our acreage position through trades that yield higher value drilling inventory; the third is by squeezing more value from this optimized acreage by proving up new targets and tighter spacing configurations; and also by identifying design changes that promise to increase productivity per well. These hurdle paths enabled us to create value across market conditions. Around half the wells, we brought online in the second quarter were in new targets or spacing configurations. Even so, we grew production by 18%, or almost 10,000 barrels a day compared to last quarter, as we can see on slide 4.

Once again, we’re raising both our fourth quarter production guidance and our full year production guidance. Full year net production moves from a range of 65,000 to 71,000 Boe per day to a range of 67,000 to 73,000 Boe per day. And Q4 increases from a range of 78,000 to 88,000 Boe per day to a range of 80,000 to 90,000 Boe per day. At the midpoint, this translates to year-over-year production growth of 83% and even higher fourth quarter to fourth quarter growth of 88%.

Turning to slide 5, we think the growth of this magnitude should only come from profitable and capital efficient operators. And when you look across the E&P landscape, Parsley is clearly among the lead on these dimensions. Only a couple of operators share a more value per Boe than Parsley does. The same holds for our recycle ratio, as we generate almost four times as much operating profit per Boe as a cost to find and develop each Boe last year. These things don’t mean that we will grow no matter what. They do mean that given our positioning at the low end of the cost curve, and the top end of the margin spectrum, it has made sense for everyone to grow, it should make sense for Parsley.

Turning to slide 6, we continue to create value though acreage trades. We announced at our Q1 update in May that since the Double Eagle acquisition, we had added more than 900,000 net lateral feet to our drilling inventory through trades. Since then, we’ve added another 500,000 net lateral feet. Combined, this translates to well over a year of inventory at our current drilling pace. This is all net of what we traded away and it’s hard to overstate how significant this is.

We’re trading away leasehold that is better owned by other operators and trading for leasehold is best owned by us. That creates and extends laterals, that increases working interest, that leverages existing operations and where we are the operator in control of the drilling schedule. We’re especially excited about the development unit and what we call the Four Corners areas in the center of the map. We now have around 85% working interest in this acreage and are hopeful that subsequent trades may fill in the rest of the leasehold, which would greatly increase the associated inventory.

Framing the footage, we added – in terms of the more familiar acreage metric, we added an equivalent of around 2,000 net acres in Q2 and have added more than 5,000 net acres since announcing Double Eagle. When you think about what core acreage is going for these days, the fact that you can add meaningfully to your portfolio without spending $1 is remarkable.

I want to touch on a couple more items from the quarter before turning to the outlook. One is the slightly lower oil percentage in Q2, which has been fairly common among operators that have reported so far. For Parsley, there are a couple of primary drivers. One is a seasonal increase in plant efficiencies that boosted NGL recoveries. So while our oil percentage ticked down in Q2, our liquids percentage actually tied our previous high at 85% for the quarter. Another factor is that we inherited some gassier vertical production when the Double Eagle acquisition was closed in April. And a less significant factors is that the Taylor Wolfcamp C well is producing a ton of oil, but a lot of gas as well, which has an impact on product mix.

Delays on our 8-well Wolfcamp B downspacing test costs of close to 1,000 barrels of oil per day on the quarter. Given the high oil-cut associated with flush production, these delays impacted our mix as well. More broadly, as others have noted, we’re finding that our horizontal well simply make more gas sooner than we anticipated. Oil volumes are in line with expectations, so the extra gas is truly additive. To account for this phenomenon and the unusual second quarter circumstances and with the number of Wolfcamp C wells in process and on the schedule, we’re reducing our guided range for oil percentage for the year to 67% to 70%. We think this should be a good estimate for next year as well.

I also wanted to touch on our CapEx run rate. Our plan had been to add a rig per quarter through the end of the year. However, with the supply of the best rig is dwindling, we made a technical decision to go ahead and secure our first choice rigs. At this point, we’ve come away with the pick of the litter and have already reached our terminal rig count for the year. This meant more drilling activity than previously budgeted in Q2, but we’ve reached equilibrium now and anticipate more balanced spud to completion ratio through the rest of the year. That said, slower cycle times in the Delaware earlier this year as we ramped up our activity on those assets mean some Delaware completions are going to be pushed into 2018.

Looking ahead, we’re well positioned for the rest of the year and beyond. We’re prepared to play offense or defense depending on the macro backdrop. So let’s think about a downside case first. Several things would help us withstand a period of depressed oil prices. For one thing cash flows are protected to a significant extent by an ample hedge position. We own three of our rigs and a couple more are on spot rates. So we could lay any of those down quickly if we choose. And our contracted rigs have staggered explorations facilitating an orderly rig count roll off if necessary. Leaseholding obligations aren’t material and it wouldn’t pose a significant constraint on activity levels. We don’t have any take or pay commitments and we’re starting from a position of financial strength with low leverage, no near-term debt maturities and ample liquidity, including $0.5 billion of cash on hand. This liquidity is also crucial in more constrictive oil price scenarios enabling us to fund acceleration as desired.

Likewise, in a more favorable macro context, the drilling inventory we’ve assembled is sufficiently large and strong that we can pull as hard as we want without introducing reinvestment risk. In fact, based on this year’s well count, we have more than 12 years in long lateral drilling locations with at least 9% working interest in our primary development zones. We have firm capacity of 75,000 barrels of oil per day, so whatever barrels we produce will certainly find their home. And we have a diversified pricing on these barrels in case of tightness on any particular benchmark price.

All these means we’re abundantly flexible. We’re frequently asked about activity trends at various oil price thresholds. We don’t really think about it that way as we’re more attune to changes in leverage and liquidity. But as of now, as a general rule, below $40 oil, we’re likely to slowdown relative to the pace we anticipated for the rest of the year. Above $50 oil, we’re likely to speed up. But what we do between $40 and $50 oil depends on the cost environment and the state of our balance sheet and hedge position among other things.

In any case, acceleration or deceleration is likely to be incremental, not abrupt. So we really like where we stand. Over the second half of the year, we expect our production momentum to continue and are spending per completion to moderate. And we’ll continue to pursue value along three paths I mentioned earlier.

With that, I’ll hand it off to Matt for more detail on operations.

Matthew Gallagher – Parsley Energy, Inc.

Thanks, Bryan. I’m going to focus on the third value driver, Bryan mentioned. We’ve been very focused on how the squeeze as much value as possible from our acreage. This was an ambitious quarter in many ways and we’re proud of what we’ve accomplished and excited to apply what we’ve learned.

As Bryan mentioned, half of the wells we brought online this quarter targeted new zones or were drilled in new spacing configurations. We spotted several of these on slide 7. Specific projects include 330 foot spacing in the Wolfcamp B formation, a second target in the Wolfcamp A formation, and two new Wolfcamp targets in the Delaware.

Before I get to these projects, I want to first give a quick update on the Wolfcamp C. As you can see on slide 8, our first Wolfcamp C well continues to flow at very robust rate, having produced 215,000 barrels of oil in 150 days, and now tracking at more than double, our 1 million Boe type curve. Meanwhile, our second Wolfcamp C well located on our Paige lease in Reagan County is producing more than 1,300 barrels of oil per day and still climbing after being online for about a week. We’re very excited about this well and encouraged by initial reports. By all indications, the Wolfcamp C is going to move the dial for Parsley and we’re aggressively moving the Wolfcamp C forward in our schedule.

Turning to slide 9. Initial results on our Wolfcamp B downspacing pilot in Reagan County are encouraging. We drilled and completed eight Wolfcamp B wells at 330-foot spacing, four in the Upper B on top four in the Lower B. So far, seven of the eight wells have hit 30-day peak rates. And the average peak rate came in roughly 15% below the area average for 660-foot spaced Wolfcamp B wells, which we consider a strong result. We completed these wells with a standard frac design that we used on 660-foot spacing.

Tracer suggests that a smaller frac might work just as well, but for our first test, we really wanted to isolate the effect of tighter spacing and the interplay of the fraction networks. So this time, our cost savings were limited to facilities and pad related efficiencies that translate to about 5% savings relative to single well development or roughly $250,000 per well. Even so, based on 15% lower recoveries and 5% cost savings, we project a net present value uplift of more than 30% from the 8 wells at 330-foot spacing versus drilling four wells at 660-foot spacing. The PV uplift rises rapidly with additional cost savings, so we’ll likely trim the size of the fracs with our next test. Naturally, there’s a lot of upside here, given the size of our Wolfcamp B inventory and its thickness and quality across our acreage.

Turning to slide 10. We’re also quite pleased with initial results on our first Upper Wolfcamp A well. We drilled and completed two stack Wolfcamp A wells on our Elwood lease in Upton County. And after the 30 days of production, the average is tracking in line with our 1 million Boe type curve. So we definitely have another productive target in the Wolfcamp A horizon, which is 350 to 400 feet thick and nearly half of our Midland Basin acreage. Again, abundant upside that’s not yet counted in our inventory.

We’ve emphasized the differentiated thickness of our Wolfcamp complex on much of our acreage and we plan to showcase this thickness in an upcoming test by stacking four wells in the Wolfcamp A and B zones, with two in the A and two in the B.

It’s a similar story in the Southern Delaware where we successfully delineated two additional Wolfcamp flow units in Pecos County, as you can see on slide 11. Our vertical appraisal wells and an analysis of proprietary 3D seismic data indicated substantial thickness and oil in place in what we previously referred to simply as the Upper Wolfcamp. And an intent to conform to industry convention, we’ll now distinguish the Upper Wolfcamp A, the Lower Wolfcamp A and the Wolfcamp B. Our first objective was to crack the code on the Lower Wolfcamp A, which is the most pervasive of these three targets across our acreage.

Having established a good baseline, we’ve now begun to stack and stagger with the other two targets. So far, we have results from two tests, one where we completed wells in the Upper and Lower Wolfcamp A in a staggered configuration and one where we completed wells in the Lower Wolfcamp A and Wolfcamp B in a stacked arrangement. Both these tests are performing well.

After around 40 days, the A/B pad average is tracking in line with the previous average for the Lower A alone. And keeping in mind that this average consists of wells completed on a standalone basis and therefore unaffected by interference. The test with two Wolfcamp A wells targets is also looking good at around 20% below the single well average for previously drilled Wolfcamp wells on our Trees Ranch acreage. So very encouraging initial data points confirming abundant resource potential, as we suspected.

Turning to slide 12, we continue to see strong productivity trends even in the midst of an intensive delineation program. Excluding the downspaced Wolfcamp B wells discussed earlier, normalized IP rates increased again in the second quarter and we continue to establish new productivity records as well, including a Wolfcamp A record 30-day rate north of 2,200 Boe per day. We are optimistic we can continue to drive productivity even higher. One reason for this very optimism is the favorable results from our first test in a compressed stage completion design.

As you see on slide 13, we increased our stage count on one well of a 2-well Wolfcamp B project in Upton County. Both wells are very strong so far and the well with additional stages is outperforming the well with standard design by 20% over the first 120 days. We accomplished this result with reduced proppant loading, which limited the incremental cost to $150,000 and represents a compelling cost benefit relationship when paired with a 20% productivity increase.

Looking ahead, we feel good about our ability to execute moving forward. The biggest execution risk comes at activity inflection points and we’re largely through those for the year. It’s worth mentioning that we recently TD’ed a well in Delaware at 15 days, so we’re rapidly ascending the learning curve in that area.

And our Midland Basin cycle times are good and getting better. In addition, while we’re constantly learning, the pace of the delineation work is going to slow over the next couple of quarters as we consolidate and apply our learnings. It’s exciting to see these concepts validated and we’re looking forward to reaping the benefits of lots of hard and smart work by our teams.

I’d like to take a moment to thank our teams across the board for responding to a material activity increase and closing our largest acquisition to-date all in a one quarter.

And now, I’ll turn over to Ryan to review our financial performance and outlook.

Ryan Dalton – Parsley Energy, Inc.

Thanks, Matt. I’ll start by saying that we continue to work from a position of financial strength with abundant liquidity and a favorable debt maturity schedule. In fact, as you can see on the bottom left of slide 14, we have more cash on hand and overall liquidity than our small- and mid-cap peers.

Turning to slide 15, we’ve been aggressive with our hedging program and now find ourselves in an advantaged position. After adding to our hedge position, we now have roughly 80% of guided volume hedged over the second half of this year, and more than 70% of consensus volumes hedged next year, which again is well ahead of our peers.

Slide 16, shows our updated 2017 guidance and I’ll talk through some of our cost and activity trends as we work down the table. But first, as Bryan mentioned, we’re raising production guidance for the fourth quarter and the full year. We’re also narrowing our percent oil guidance as discussed earlier.

We reported $295 million of CapEx in Q2. As noted, we’re running ahead of schedule on drilling activity. Consequently, we spud 49 horizontal wells in the second quarter compared to 27 horizontal completions and our CapEx run rate reflects this inflated spud count. We’re maintaining our CapEx guidance for the full year. While we’re running ahead of the plan on the drilling side, we’re expecting fewer completions in the Delaware in particular and probably at the low end in the Midland Basin as well.

We’re also maintaining our various unit cost guidance ranges. LOE per Boe, which has been running at a peer leading rate, increased this quarter as we got to work bringing acquired wells up to Parsley standards. We also incurred meaningful non-op LOE for the first time as a result of recent acquisitions. A good portion of the LOE increase should be transitory and we expect LOE per Boe for the rest of the year to fall within our annual guidance range, which would put the full year operating cost in the same range.

G&A per Boe increased in Q2 in tandem with the early rig additions and post Double Eagle hiring, which is now substantially complete. We expect volume growth to outpace G&A growth over the remainder of the year, leading to lower cost per Boe.

So to conclude, production growth is intact on a stable budget and we expect Q2 unit cost increases to reverse next quarter. We enjoy an advantaged balance sheet and hedge book and we’ll continue to create value on different pads with plenty of flexibility to adapt to market conditions as necessary.

With that, we’ll be happy to take your questions.

Question-and-Answer Session

Operator

Thank you. We will now be conducting a question-and-answer session. Our first question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed with your question.

Scott Hanold – RBC Capital Markets LLC

Yeah. Good morning, guys. Thanks for taking my call and question. Can you all discuss – obviously, there’s a lot of concern out there regarding GORs in the Permian here recently. And certainly, you have seen better gas cuts in some of your wells. Can you just provide us some more clear thoughts on what are you seeing on individual wells and how your PDP basis is changing all in time?

Matthew Gallagher – Parsley Energy, Inc.

Yeah. I think we can – this is Matt, we can just re-hit on our quarter, which was a two pretty simply facts about the acquisition barrels as well as our 8-well density pad came on towards the end of the quarter. And that was about 1,000 barrels of crude that didn’t get to contribute on the quarter. And then looking forward for Parsley, obviously, as we see in the Wolfcamp C, there’s tremendous capital efficiency and strong production. We want that to be a larger mix and we’ve already pulled forward aggressively our drilling campaign there. So it will be a larger component going forward. But it’s pretty clear that it has a lower oil cuts, but high – equal to higher oil volumes and then the additional gas. So that’s Wolfcamp C specific. As far as our PDP and our individual wells, every well in our base, we have an increasing GOR forecast. This is a relationship that is known. It’s a standard for these types of reservoirs, solution gas drive. And we’re seeing predictable gas production on that front.

Scott Hanold – RBC Capital Markets LLC

Okay. Okay. I love the clarity. Thanks a lot for that. And the compressed stage test that you all did -conceptually based on what you’ve seen, is this show you that you’ll probably be able to space wells a little bit tighter based on what you’ve seen, if I’m hearing that right, or is that not part of what you proved up?

Matthew Gallagher – Parsley Energy, Inc.

These are two separate tests, a huge delineation quarter for us and to be able to deliver 14% oil growth. We’ve been doing this for 13 quarters, these double-digit oil growth production quarters. And this was a delineation quarter. So, we’re really proud of that. But specifically the stage spacing, that’s intra-well reducing down to 100-foot stage spacing where we’ve seen very encouraging early results of 20-plus percent.

And then, separately in our density test, these were the amounts – number of wells we drilled per section. So they are two separate tests and encouraging on both fronts. We would look immediately to apply the denser inter stage completion deigns to our program and we’re encouraged about that, so that will be rolling out. And then, the 330 test, that is a new – it’s not ascribed in our inventory, but it’s a placeholder that there is an economic price here, 30% uplift on an NAV basis. And so now we have another tool on our tool kit as we decide going into development mode how we want to fully space our wells going forward.

Scott Hanold – RBC Capital Markets LLC

Yeah. I appreciate that and maybe just to clarify my question. So did the frac-wings on the compressed test, were they much shorter and do they breakup more rock around the wellbore? And just kind of wondering how that translates into maybe that 330 test you mentioned. Could that further enhance that some of those recoveries?

Matthew Gallagher – Parsley Energy, Inc.

Sure. Got you. Thanks for the clarifying. And yes, you would see that interplay exactly. So, you have additional near wellbore complexity and shorter half-lengths in this 100 foot stage spacing, which would be a direct application that you could apply to the density test that was not applied on the 330 spacing. As we mentioned, we just applied the standard – our standard full size 660 job tracers and downhole bottom gauges. We know kind of exactly where the size cutoff was on our stage volumes for that density test. And then, in addition applying this shorter stage spacing would have a positive effect. That’s exactly right.

Scott Hanold – RBC Capital Markets LLC

Okay. Thank you for the clarification. Thanks.

Operator

Thank you. Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Charles A. Meade – Johnson Rice & Company L.L.C.

Good morning, Bryan, and to the rest of your team there as well.

Bryan Sheffield – Parsley Energy, Inc.

Good morning.

Charles A. Meade – Johnson Rice & Company L.L.C.

I’m wondering if I could ask you to elaborate a little bit more on the Wolfcamp C. And I think you talked in your prepared comments, and Matt just mentioned that you guys have just slotted a few more of these wells into your program and I guess we’re already seeing that now with Paige well. But can you talk about just the magnitude of that? How much you’ve – how many locations you’re going to a test for at the end of year? And I guess, part of that bigger context and maybe if you could talk about this, right now, what seems to me, you guys own this play in the sense of data flow at this point because you’re the only ones who’ve been giving us. But also, you seem like you have a – because you own that data flow, you have a big advantage in that Wolfcamp C window. So maybe you can talk about whether you agree with that or what you might do with that advantage?

Bryan Sheffield – Parsley Energy, Inc.

Yeah, it’s – first of all, it’s a slight challenge because Wolfcamp C, yes, it’s a lower oil cut, but should be the same amount of oil as our original type curve, but we’re going to get a lot more gas. This Wolfcamp C bench is actually competing against our all other benches, our highest return benches. The first Wolfcamp C well paid out in six months and the second well is now making 1,300. Now, I’m hearing even today of the 1,500 barrels of oil per day. So, we have our – everyone is focused on Wolfcamp C. C is going to compete for capital and fall and going into 2018, I kind of compare it as like maybe a Reeves County, Delaware on steroids and half the costs, so think of it that way.

Also, in the locations, where I did – we’re seeing about 900 locations being proving up. And just imagine all those locations kind of just moving up on the queue over the next couple of years.

Charles A. Meade – Johnson Rice & Company L.L.C.

Got it. Got it. That’s helpful. That’s helpful color, Bryan. And Matt, perhaps, this is a best one for you. I wanted to follow-up on Scott’s earlier question about these reduced cluster stage or rather reduced stage spacing because that really looks like one of your big wins this quarter in these kind of delineation or appraisal or science project. I think what I heard you say is that you’ve already decided that you’re going to roll that out. And if that’s the case, can you talk about to what extent you’re going to roll it out? And is this going to be 20% of your second half 2017 program or is it going to 100% of your 2018 program? Can you just put some parameters on that?

Matthew Gallagher – Parsley Energy, Inc.

Sure. So, right now, we have it penciled in for about nine additional projects in the back half of the year, obviously, can toggle that in real time as we continue to get additional results from it. So it’d be on the order of $150,000 increment in those wells, which we’ve modeled to, and we’ll just continue to watch productions from these projects. And that will also dictate how large of a component of the 2018 program it’s going to garner.

Charles A. Meade – Johnson Rice & Company L.L.C.

Got it. That’s helpful detail. Thank you, Matt.

Matthew Gallagher – Parsley Energy, Inc.

Thanks, Charles.

Operator

Thank you. Our next question comes from the line of Drew Venker with Morgan Stanley. Please proceed with your question.

Drew E. Venker – Morgan Stanley & Co. LLC

Good morning, guys.

Bryan Sheffield – Parsley Energy, Inc.

Good morning.

Drew E. Venker – Morgan Stanley & Co. LLC

I just want to follow up on the – and I don’t want to beat dead horse on this oil mix issue. But can you just kind of help quantify how the oil mix changes in a typical Midland Wolfcamp well, say an A, B well from IP to second, third, fourth this year?

Matthew Gallagher – Parsley Energy, Inc.

Yeah, over the life of the well, if you’re just looking at the cut number, it should gradually change by about 10% in that timeframe that you mentioned, from 30-day IP out into the three to five year range. And then, if you split by benches, maybe it’s a little bit lower than that in the A, maybe will be higher than that in the B.

Drew E. Venker – Morgan Stanley & Co. LLC

Okay. That’s really helpful, Matt. And as you’ve seen more and more data more recently, have the gas declines been shallower than you had previously anticipated?

Matthew Gallagher – Parsley Energy, Inc.

Yes. Yes. So, you model each stream individually by product and the oil is right on the chili and you are seeing a more resilient gas declines.

Drew E. Venker – Morgan Stanley & Co. LLC

Okay. That’s helpful. And just on industry-wide, we’ve obviously gone to a much higher activity level today than we were at a couple of quarters ago and a lot of your peers have reported missing expectations due to permitting, completion delays, et cetera. What you guys have within your plan, what you’re doing differently to mitigate those potential issues going forward, now that it’s not just your own potential execution challenges, it’s facing pressure of everyone else competing for services at the same time?

Matthew Gallagher – Parsley Energy, Inc.

Right. We think we’ve grabbed those services aggressively in the first half of the year, starting with the rigs. You have to start there, but we’ve already secured all the equipment required for this. We’ve already done long-term front-end planning. You can probably publicly search permit count that has gone up dramatically for us, so we’re in place on that effort. And then also, any time you go through an activity inflection point, that is the time breaking out new crews, et cetera, where you really have to put extra focus on activity. And we feel we’ve done that. We are past that phase. As we mentioned, 49 spuds in the quarter, with those new rigs really got on the activity throttle, saw no drilling issues in the Midland Basin. That has not been an issue for us. And also evidenced by the 49 spuds in a very timely manner also with new rigs, new crew. So it’s only going to continue to get better from here.

Drew E. Venker – Morgan Stanley & Co. LLC

Okay. That’s helpful, Matt. And just as a follow up to that, as we’re thinking more about next year’s plan, at a high level at least. Do you need to build out a significant amount of midstream yourself to kind of lay the foundation for that growth in 2018 or is that probably done by third-parties that’s already in place?

Bryan Sheffield – Parsley Energy, Inc.

Hey, it’s Bryan. We’ve always focused on the drill bit and we are pros at drilling oil wells. So we have always farmed that out the third parties and we develop good relationships with them.

Drew E. Venker – Morgan Stanley & Co. LLC

Thanks, Bryan.

Operator

Thank you. Our next question comes from the line of Neal Dingmann with SunTrust. Please proceed with your question.

Neal D. Dingmann – SunTrust Robinson Humphrey, Inc.

Good morning, guys. Bryan, the question maybe for you or Matt. Could you just talk about maybe (34:08) I think was one of your competitors just contracted some of the proppant. You mentioned – I know you guys are always planning well ahead. How do you think? And then, just somebody else mentioned today, they don’t like doing that. So I guess this is more just your strategy. If you think, there is going to be plenty availability of proppant and raw materials going forward, how you see either contracting that or not?

Matthew Gallagher – Parsley Energy, Inc.

So we are in a very close communications with our service providers and have been happy to contract directly if need, but through transparent discussions with them, we see the same Q1 2018 timeframe of proposed proppant pricing reduction due to additional supplies coming online that they’ve secured directly and have indicated willingness to pass that through as long as we can continue on our activity levels in a planned manner. That should not be an issue. So that’s how we’ve been tackling it.

Bryan Sheffield – Parsley Energy, Inc.

I think a few months ago, there was a big frenzy in minds of contacting us, going around the service companies. It seems like when you’re getting floods of e-mails and visits from those type of same companies, I’m a big believer of not doing anything because it just – this frenzy that’s boiling up. So, we’re kind of just in wait and see mode. We really do lean on our service companies. Our service companies are the ones that are supposed to lock in the sand for the following years to come.

Neal D. Dingmann – SunTrust Robinson Humphrey, Inc.

Great, color. Thanks, guys.

Bryan Sheffield – Parsley Energy, Inc.

Thanks.

Operator

Thank you. Our next question comes from the line of Asit Sen with Bank for America Merrill Lynch. Please proceed with your question.

Asit Sen – Bank of America Merrill Lynch

Thanks. Good morning, Bryan and Matt. So, on Wolfcamp C, thanks for the color, but my question is trying to understand the potential upside. So 920 net location count assumes how many flow units? And also, I know it’s early, but what are your expectations on oil cuts over the life of a well?

Matthew Gallagher – Parsley Energy, Inc.

That is simply one flow unit, Asit. It’s a very thick column, over 800 plus feet of thickness. So there is continued upside as we methodically assess this resource, same playbook, same that we would have take on our historical zone assessment. And so, great starting point out of the gate and lots more resource potential to evaluate in the long run under the right pricing conditions.

On the cut side, we are probably looking starting somewhere in the 60s. And over the entire life of the projects, we’ll have to watch the declines of these things, how resilient the gas is, but it could be down into the 50s, maybe a 15% absolute decline on the cut over the life. But we’ll be evaluating that as we get our additional PBT (37:16) and bottom-hole pressure work book in-house.

Asit Sen – Bank of America Merrill Lynch

Great. Thanks. And then my follow-up is a big picture question. Just thinking about infrastructure over the next two to three years, what do you see as potential pinch points? And could you speak to how Parsley is planning to stay ahead of the game?

Matthew Gallagher – Parsley Energy, Inc.

We’ve worked on well pretty aggressively and we feel we have the firm commitments for Parsley on 75,000 barrels of oil just in the near term. That’s scalable. It can go up as we need it and we’re connected to six long haul pipes, physical connects out of the basin. So, we’re really in good shape on that front.

And then the next down the line to address would be gas. We have two additional plants on our acreage. We’re 90% tied in behind Targa, which is one of the largest gas processers on the Midland Basin side. They’re very proactive on addressing takeaway, and in fact, they’re building two additional plants, which will be online in 2018. It’s roughly 400 million a day of additional processing capacity. Same holds true in Delaware. We’re right at the WAHA Hub with our surface acreage. We’re tied into ETC and others and they have – and Brazos (38:35) and both of them have additional processing projects online and they’re two massive pipes, 2 Bcf a day, that originate right there at that Hub. So, that is the next one to look for us long term Permian gas takeaway capacity. Obviously, everything you’re seeing in the Permian names on their releases right now, makes that a front burner.

Asit Sen – Bank of America Merrill Lynch

Great. Thank you, guys.

Bryan Sheffield – Parsley Energy, Inc.

Thank you.

Operator

Thank you. Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please proceed with your question.

Daniel Eugene McSpirit – BMO Capital Markets (United States)

Thank you, folks. Good morning. In what period do you see the company achieving a free cash flow neutral state, say, in a $50 world? And what does that mean – or what does the move mean from delineation to say development? What does that mean for returns at the corporate level? And are there any internal goals to that measure?

Ryan Dalton – Parsley Energy, Inc.

Hey, Dan, it’s Ryan. I’ll address the first part as far as free cash flow neutral or positive. It’s not something we’re specifically targeting in the next couple of years. We have the governors of liquidity and leverage to determine the outspend (39:58) that we’re going to make or use each year. And as we prepare our 2018 budget, we’ll be looking at both of those. We feel like the balance sheet is in really good shape, low leverage. We’ve got $1.5 billion of liquidity right now. So, at least for the next year, I would expect our activity level to outpace the cash flow.

Daniel Eugene McSpirit – BMO Capital Markets (United States)

Okay. Okay, great. And as a follow-up to that, and if I could just revisit the GOR question, and I apologize for doing so. But how would you assess the risk to the oil stream as pressure declines in the reservoir and maybe more gas drops out of that stream? And how does the completion technique play a role in mitigating that risk, if there is any risk?

Matthew Gallagher – Parsley Energy, Inc.

I don’t see any material risk versus what we forecast. We have probably 50 to 75 wells producing at low pressures now. We install artificial lift early on and helps move that oil once we get a below the early flush stages. So, if you’re analyzing a project in isolation, without any artificial energy into the system, you would have oil declines. When you set up the system for artificial lift and long-term production, you arrest those declines and you move the oil out. So we have 75 wells or so on production, on trend that are looking just fine. So wouldn’t see anything explicit at all.

Daniel Eugene McSpirit – BMO Capital Markets (United States)

Very good. Thanks again. Have a great day.

Matthew Gallagher – Parsley Energy, Inc.

Thanks.

Operator

Thank you. Our next question comes from the line of Jeff Grampp with Northland Capital Markets. Please proceed with your question.

Jeff Grampp – Northland Capital Markets

Good morning, guys. I wanted to touch base on this Wolfcamp B stack test again and maybe get some insight on how you guys take this early on info and then potentially integrate that into future development. I know you got some more tests and not deciding anything definitively today. But just generally, if you guys can increase per section NPVs, but possibly at a lower individual IRR, is that something you do in this environment? Do you need higher prices to justify that or just wanted to get some high level perspective on how you guys view that potential trade off?

Matthew Gallagher – Parsley Energy, Inc.

That’s a great question and it is the discussions we’re having right now. And with the runway of inventory we have on 660s, you really want to gather the data and be a returns driven company in the near-term. However, you want to most effectively recover the resource on a per section basis as well. And I think we have some line of sight on some things that we mentioned before to where you could be a return parity due to cost savings on the design side and then also have the NAV uplift. So as it sits today, we’re getting the NAV uplift, but at a rate of return deficit due to a single well case. It’s slight, but it is a deficit. So, you use the tools in your tool kit to make that a parity. If you get there and you have that crossover, then it’s a no brainer and you roll it in to long-term development. But again, tremendous runway, 660 foot spaced wells. So we just need to assess the impacts of these lower capital costs on the completion side.

Bryan Sheffield – Parsley Energy, Inc.

Hey, Jeff, it’s Bryan. This kind of goes back to Dan’s, I think, second part of his first question, how we manage the delineation program in 2018 and 2019. We’re still in discussions, but this Wolfcamp C is still big. I mean it basically competes – actually, the program helped to prove it up, but now it’s competing with that particular program. So, I could see that start shifting over more and more to this Wolfcamp C program like 10% maybe CapEx next year or something like that. And that might be then (44:16) into that particular program, but we’re still kind of thinking about 2018 all together on that.

Jeff Grampp – Northland Capital Markets

Okay. Appreciate all of those comments. And then, for my follow-up, it seems like there’s a couple of different data points here that showing that potentially lower proppant with the well cost savings could generate some better returns. I wanted to see if that was a fair characterization of things and if that’s something that you guys could maybe look to expand upon maybe just beyond just the more densely spaced well patterns and maybe that’s just kind of a standard Parsley practice in the future if that plays out.

Matthew Gallagher – Parsley Energy, Inc.

Yeah. I think if we don’t get those promises delivered by the service companies in first quarter, that’s definitely a route to take because you’re in the business to make money per well, not rates. And so, we can – we’re actually seeing both on that density staged project where we had lower loading and still got increased production. So, I think we can methodically roll that out in the back half of the year and assess that as well. So, it’s a nice lever to have.

Jeff Grampp – Northland Capital Markets

Okay, great. Appreciate the comments, guys.

Bryan Sheffield – Parsley Energy, Inc.

Thank you.

Operator

Thank you. Our next question comes from the line of Joe Allman with FBR Capital Markets. Please proceed with your question.

Joseph Allman – FBR Capital Markets & Co.

Thank you. Good morning, everybody.

Bryan Sheffield – Parsley Energy, Inc.

Hi, Joe.

Joseph Allman – FBR Capital Markets & Co.

Hey. So, on two issues that Pioneer addressed yesterday. So, first, the pressure issue that’s requiring Pioneer to add a fourth casing string. Could you talk about just across your acreage position do you expect to see any similar pressure issues and just kind of elaborate on that?

Matthew Gallagher – Parsley Energy, Inc.

We don’t expect to see it and we have not seen it. So, we use on average about a 9 pound mud and it’s very controlled as we drill through the San Andres section, no issues. And we’re able to maintain that and drill through the lower pressured Lower Spraberry all in one chunk, evidenced by the 49 wells in the quarter, that it would be the most recent example of that. Of course, that’s across the entire company, but all of our Midland Basin wells, no issues in that front. We have a couple rail roads (46:47) drill very quickly through the Spraberry portion and we just simply have not seen those issues. And we also inject into a – just as we have thicker Wolfcamp C in the majority of areas, Wolfcamp A and Wolfcamp B, we have thick San Andres and we inject into a large interval and that dissipates the anticipated pressure growth over the years that we would expect to see. So there’s a lot of things in our favor that we’re just not – we’re not seeing in that situation.

Bryan Sheffield – Parsley Energy, Inc.

Hey, Joe, I think some other operators are permeating – the SWE (47:34) permeating around 800-feet intervals compared to our 1,200-feet. So that could be some of it. The other thing is if you look at the history of our acquisitions, we’re buying HBP leasehold in these holes where these – they weren’t vertical wells or a vertical well Wolfberry program through 2008 to 2012. So we’re very fortunate with the acreage we have, how it lays out around this vertical map, if you look at the larger vertical map.

Joseph Allman – FBR Capital Markets & Co.

Yeah. That’s very helpful. And then, on the second issue that the – back to the GOR issue. So, first, like when I look at slide 21, I look at your proved reserve summary. I see the PDP oil percentage of 57% and I see the PUD percentage at 65%. So could you address that? That’s the oil percentage of total. And also, could you just take us through the various formations like, what the oil cut is at first and what you expect it over time? I know you did it already with Drew, but I don’t want to narrow it to a three to five year window. Just kind of, over time, you expect it to start at X and ultimately, the terminal rates going to be X. And so, over the life of well, it’s going to be X. Could you just take us through that? And just address what one or two callers have asked, will the gas just not – as the gas increases, will that not just continue to compete with the oil for the flow pads and causing the oil to potentially drop below your expectations? So I don’t want to narrow it to any kind of timeframe. I just want like over the life of these wells and over your acreage position and over the formations, like what do you expect?

Matthew Gallagher – Parsley Energy, Inc.

I’m going to start with your observation on the proved reserve, that’s a great place where proof is in the pudding, heavily (49:23) and on the PDP includes all their vintage vertical wells in our production. And what is PUD, PUD is our horizontal future program. So you can see there much higher oil cut and that is life of well EUR. So very strong on oil cuts and as predicted.

And as you go into the production by bench, I mean we don’t have the rest of the day here with – there are 13 benches, but if we can just quickly pick A Spraberry bench, an A and a B. Starting on Spraberry, probably would be the lowest of the three on the GOR increases over time. This already starts at a lower pressure. So what you see early on is what you get later on and maybe that’s an 8% cut change over time.

And you actually hit a terminal – you don’t really hit a terminal rate. You have a gradual increase 5 to 10 years and then you see a fall off or a plateau, but you again see a fall off in the terminal years. Then, you come into the Wolfcamp A. You’re going to look at something in the order of 12% to 13% over the life and then Wolfcamp B, 14% to 16% over the life.

Joseph Allman – FBR Capital Markets & Co.

Okay. So that 65% oil percentage in your PUD, so is that representative of what the life of well oil percent will be across your various formations in here that represent the PUDs?

Matthew Gallagher – Parsley Energy, Inc.

Yes. So that is exactly right and our PUDs are primarily dominated today by Wolfcamp B and Wolfcamp A wells. So as we get additional Spraberry wells booked under PUDs, they will contribute to – they’ll bring that percentage up. So it’s just a matter of the ratio of your entire benches. That’s exactly right.

Joseph Allman – FBR Capital Markets & Co.

Okay.

Matthew Gallagher – Parsley Energy, Inc.

And then competing for flow pad, the flow pads are open day one. So there is no – you’re not seeing the absolute volumes that you’ll see. There are relative permeability changes over time, but that is what’s contributing to this increase in addition to the dissolution of the gas out of the – due to pressure. So it’s a kind of known relationships that are driving to that life of well mix at 65%. We’re not seeing anything unpredicted at this point.

Joseph Allman – FBR Capital Markets & Co.

Got you. Okay. All right. It’s very helpful, guys. Thank you.

Bryan Sheffield – Parsley Energy, Inc.

Thank you.

Operator

Thank you. Our next question comes from the line of the John Freeman with Raymond James. Please proceed with your question.

John A. Freeman – Raymond James & Associates, Inc.

Hi, guys.

Bryan Sheffield – Parsley Energy, Inc.

Hey, John.

John A. Freeman – Raymond James & Associates, Inc.

When you all originally came with your 2017 budget, you all set aside about originally like 25%, 30% of your capital toward delineation efforts and obviously you’re a good bit more active in that. This quarter with about half of the wells. But at the time you did it, if memory serves, Matt, I remember you’re saying that like when you were doing these delineation efforts like the Wolfcamp C, the first well, you risked pretty heavily kind of the pre-drill expectations when you were coming out with your original production guidance. And I am just curious as you continue to get very encouraging results with a whole host of these delineation efforts, do you still have a similar risking in place. Or have you sort of narrowed that as you progressed through the year and have given out additional guidance?

Matthew Gallagher – Parsley Energy, Inc.

Yeah, it narrows. And I think that’s a factor of what we put in our guidance in the back half of the year. But on 8-well pad, I mean in the modeling we had a 75% of curve expectation and it came on at 84% up. So it beat our internal models. Now, it also came on about four weeks late. So in that specific quarter, you didn’t have the volumes deliver. But going forward, case-by-case, delineation-by-delineation, we are beating our internal estimates. And that’s a reflection of doing more with less on the year, able to meet the annual oil production and increasing total production guidance for the remainder of the year.

John A. Freeman – Raymond James & Associates, Inc.

Great. And then just one just quick follow-up from me. When I look at 2018, should I assume a pretty similar percentage of capital is directed toward delineation versus development next year?

Matthew Gallagher – Parsley Energy, Inc.

And I think that’s what Bryan was alluding to. I think with our tremendous runway of inventory, and now some success out of this delineation projects, we can kind of focus in on what we have known today. Now, one component that is the Wolfcamp C which used to be in the delineation bucket is now in more of a known quantity. So, yeah, I think it’d be a lower percentage spend on headline delineation.

John A. Freeman – Raymond James & Associates, Inc.

Great. Thanks, guys. Appreciate it.

Bryan Sheffield – Parsley Energy, Inc.

Thank you.

Operator

Thank you. Our next question is from the line of Michael Hall with Heikkinen Energy Advisors. Please proceed with your question.

Michael Anthony Hall – Heikkinen Energy Advisors LLC

Thanks. Good morning. Just wanted to kind of come back and revisit the thoughts on development in the Midland Basin. As you alluded, you kind of have known quantities or more so now, as it relates to spacing and dual bench development in the A and B, and now you got the C. As you think forward, how should we think about how you go about developing those pads and those units? Do you think co-development is an important factor in that or will it be kind of coming though zone by zone? What’s the game plan and current thought process on that?

Matthew Gallagher – Parsley Energy, Inc.

Hi, Michael, we do believe co-development is the efficient way. One, we’ve seen a great pad uplifts, when we do sequential A, B projects in the right thickness. Obviously, component is our AA, BB, that’s coming up, and that will be kind of full scale development mode. And then you go out to the spacing co-development, and that’s where we’re at on the 660 foot, versus 330 foot decision. Don’t see a need today to aggressively put that into the 2018 component mix, based on our results we’re seeing from the C. And it’s such a standalone entity, 1,000 feet our other zones, it can be singularly developed where we would be co-developing it with pads, while we’re in the area. So, a component of co-development is key. And of course, you see the surface savings on the order of $250,000 per well, when you go to that high count well pad development.

Michael Anthony Hall – Heikkinen Energy Advisors LLC

Okay, excellent. And then I think you did a great job in the quarter in terms of getting ahead of things with the spuds, bringing in the rigs early, seems like you had some good foresight there. And any similar moves you’re contemplating currently as it relates to kind of execution and avoiding some of the risks out on the horizon. And anything you can highlight on that front that you’re doing to help reduce the execution risk going forward?

Matthew Gallagher – Parsley Energy, Inc.

We’ve been very aggressive on the oil gathering side. We – that pipe is in the ground, building out to the Delaware and it has already been built out effectively on the Midland, so that helps on execution and takeaway there. Water gathering and disposal is something that we feel that we’ve been head on and we like our approach and as evidenced by not seeing any issues on it to-date. Think that we’re doing some things right, but are always looking for ways to optimize in the future. So we think we’ve been able to stay ahead on that front. And then, we obviously demonstrated on the drilling side, what methodically comes next is a completion side and we’ve teamed up with kind of two rig service providers and have already secured additional fleets from them, which have already been in process on one and the second – the last one is coming at the end of August. That’s already identified and has been for a long time. So we feel like we’re in good shape there and getting good efficiencies out of those guys.

Michael Anthony Hall – Heikkinen Energy Advisors LLC

Okay. Great. I appreciate the color. Thanks.

Operator

Thank you. Our next question comes from the line of John Nelson with Goldman Sachs. Please proceed with your question.

John Nelson – Goldman Sachs & Co. LLC

Good morning. And thank you for taking my questions.

Bryan Sheffield – Parsley Energy, Inc.

Hey, John.

John Nelson – Goldman Sachs & Co. LLC

Matt, I think you’ve done a great job in answering kind of the oil mix questions for the specialists, but I apologize, I’m going to ask it one more time because the stock still seems to be behaving irrational here, so maybe we can answer this for generalists. And so, if I were to think about where your oil-only development costs were relative to call it three or six months ago, have they gone up, down or are they neutral?

Matthew Gallagher – Parsley Energy, Inc.

Oil-only development costs has gone up. We are seeing productivity per foot increases on oil-only based on our results today.

John Nelson – Goldman Sachs & Co. LLC

So do you mean down, then? So, in other words, your…

Matthew Gallagher – Parsley Energy, Inc.

Yes, yes.

John Nelson – Goldman Sachs & Co. LLC

…proved development cost per foot, but if I’m just scaling by oil.

Matthew Gallagher – Parsley Energy, Inc.

That’s right.

John Nelson – Goldman Sachs & Co. LLC

So the capital efficiency of your business.

Matthew Gallagher – Parsley Energy, Inc.

Capital efficiency has gone up, even if you’re looking at oil-only.

John Nelson – Goldman Sachs & Co. LLC

And the messaging on mix is really just what we might be toggling to areas that overall have even more capital efficiency, but just have disproportionate gas and NGLs. Is that fair?

Matthew Gallagher – Parsley Energy, Inc.

I think that’s exactly right. And I think if you look at the back half on the completions projected and the production projected, you’re getting the same amount of oil as originally forecast with less wells. So that is proof in the pudding right there that per well oil is delivering.

John Nelson – Goldman Sachs & Co. LLC

And I guess just on the comment that we would stay at a flattish kind of oil mix into 2018. Could we just talk kind of generally – I know you don’t have official guidance out, but what is the level of Delaware Basin activity kind of assumed in those comments?

Bryan Sheffield – Parsley Energy, Inc.

That’s pretty early on that with this Wolfcamp C program that could be competing with the Delaware. What are we, like 60%? 40% over in Delaware, 60% this year. I could see that shrinking a little bit because of the Wolfcamp C program eating into the capital.

John Nelson – Goldman Sachs & Co. LLC

Okay. And then if I could just have one follow-up on the development question on the – staying at three string casing. I was just wondering could you comment, are you seeing increased pressure in some of those reservoir pressure and some of those shallower zones from higher kind of water injections? Is that something that that you guys have been witnessing across the field and just been able to offset with mud weights or has not really been (01:11:35)

Bryan Sheffield – Parsley Energy, Inc.

We’ve only encountered it like once or twice. We’ve only encountered once or twice on all of the wells that we have drilled. So it’s just like I said that, you look at our acquisition history, we don’t have ton of vertical wells on the acreage. I mean some of it we acquired from Anadarko and Cimarex, the HBP (01:01:56) other acquisitions, a lot of it is just HBP by third parties without inheriting vertical wells except this last deal with (01:02:02) and Apache. That’s a only time we’ve inherited a lot of the vertical wells. And also the – just like we talk about, we’re permitting permeating (01:02:13) on the 1,200 foot interval and we’ve looked back at other operators and they’re around 700 or 800 feet intervals. So we think that might have something to do with it. And why, because of a (01:02:22) four string design. We did not plan on going to a four string design. I call ours three string a long – long second string, long intermediate casing, so it’s three string design.

John Nelson – Goldman Sachs & Co. LLC

Got you. Okay. I’ll leave it there. Thanks answering those questions.

Bryan Sheffield – Parsley Energy, Inc.

Thank you.

Matthew Gallagher – Parsley Energy, Inc.

Thanks John.

Operator

Thank you. Our next question comes from the line of Kashy Harrison with Simmons Piper Jaffray. Please proceed with your question.

Kashy Harrison – Piper Jaffray & Co.

Good morning, guys. Thanks for sliding me in here at the end of the call and I promise not to ask about GORs, so just something maybe a little bit easier. On the 330 foot spacing test, do you have any idea of just how many months or years of data would you need prior to entering development mode and saying this is how we want to space the Wolfcamp B wells moving forward?

Matthew Gallagher – Parsley Energy, Inc.

Well, I think you would need to put another project down with a lower capital cost test like we discussed on the frac side before you would – and then you’d be pretty close on your decision on if you want to go across the board on that way or across the board on 660s. If you see a modest increase in oil price, even if nothing changes, that would accelerate the decision to do 330s. So it’s a combination of factors and conditions and then – but then the timing on that decision delays as we have kind of fixed capital to deploy over the next few years and additional projects that move up in the queue, such as Wolfcamp C.

Kashy Harrison – Piper Jaffray & Co.

Got you. Got you. All right. Well, that was it from me. Thanks for the time.

Bryan Sheffield – Parsley Energy, Inc.

Thank you.

Matthew Gallagher – Parsley Energy, Inc.

Thank you, Kashy.

Operator

Thank you. Our next question comes from the line of Chris Stevens with KeyBanc Capital markets. Please proceed with your question.

Chris S. Stevens – KeyBanc Capital Markets, Inc.

Hey, guys. A quick one on the Delaware, are you guys seeing any difference in productivity between the Upper A and the Lower A bench out there?

Matthew Gallagher – Parsley Energy, Inc.

Yeah. We’ve seen – we have Upper A, Lower A and then Upper B test and when we put both the As on, we have seen influence between the two. But in entirety, they’re seeing about 80% of the single well case. So it’s again an uplift in total resource recovered from the zone. A and B are independent of each other.

Chris S. Stevens – KeyBanc Capital Markets, Inc.

Okay. And I guess on a go-forward basis, as most of the development going to be just focused on the Lower Wolfcamp A or you’re going to continue this Upper/Lower A staggered drilling?

Matthew Gallagher – Parsley Energy, Inc.

We’re really encouraged, probably near-term pick one A and this recent B well, it has been our strongest well to-date from a pressure standpoint, still flowing naturally at elevated pressures. So we like a B/A combo mix for the near term and then it gets into long-term development, what are the decision points, do you go for a complete NAV resource captured or return driven.

Chris S. Stevens – KeyBanc Capital Markets, Inc.

Okay. Got it. And then just on LOE. Is there a good sort of timeframe to getting that back towards the mid $3 per Boe sort of level that you experienced earlier in 2017?

Matthew Gallagher – Parsley Energy, Inc.

Yeah. I think it comes down aggressively and ratably in the back half. We described roughly $4 million of project to get integrate these acquisition wells in the second quarter. Most of that goes away. There’ll be some slight carryover mostly in July, just finishing that up, but nothing to the magnitude that we saw in the second quarter.

Chris S. Stevens – KeyBanc Capital Markets, Inc.

Okay. Great. Appreciate it.

Bryan Sheffield – Parsley Energy, Inc.

Thank you.

Operator

Thank you. Our next question comes from the line of Michael Glick with JPMorgan. Please proceed with your question.

Michael A. Glick – JPMorgan Securities LLC

Hey guys. Just thinking conceptually about the Wolfcamp C and I think Matt hit on this a little bit earlier, but if you ran a hypothetical 2018 development program that incorporated more Wolfcamp C wells versus a prior a prior program that didn’t contemplate the material numbers of C wells, in theory wouldn’t absolute oil move higher along with gas, just given your experience with the oil productivity in the first two wells?

Matthew Gallagher – Parsley Energy, Inc.

Yes, that’s exactly what we’re trying to say.

Michael A. Glick – JPMorgan Securities LLC

Got you. Got you. And I know that first well has been flowing naturally for a long time, but what are your thoughts on artificial lift that you’re going to see?

Matthew Gallagher – Parsley Energy, Inc.

It would be tied into our gas lift systems in the area. Gas lift is a nice natural fit, very cost effective way to produce these types of wells. So, likely gas lift that’s why the majority of our Upton and Reagan wells are on anyways. And so you actually get some nice benefits. You don’t have to bring out additional compression. You can tie in as other wells die off, use similar compressors.

Michael A. Glick – JPMorgan Securities LLC

And just a question on capital efficiency from a high level, just by taking earlier delivery of the rigs in 2017, what are the implications for your rig ramp need in 2018?

Bryan Sheffield – Parsley Energy, Inc.

We are not there yet on 2018 budget, but that’s a good question. We always stay a step ahead. We’re still watching oil price. Oil price needs to cooperate. I mean, we’ve been very vocal in the conference and in our one-on-one meetings that if oil is in the $50 range, you could see us adding a handful of rigs going into 2018.

Michael A. Glick – JPMorgan Securities LLC

Got you. Okay. Thank you.

Matthew Gallagher – Parsley Energy, Inc.

Thanks, Michael.

Bryan Sheffield – Parsley Energy, Inc.

Thanks.

Operator

Thank you. And our final question comes from the line of Gail Nicholson with KLR Group. Please proceed with your question.

Gail Nicholson – KLR Group LLC

Good morning. And you guys have tested numerous completion design changes from (01:09:00) to the monster frac utilizing brown and white sand across the Midland to the compressed stage design that you guys announced this quarter. When you look at all the testing to-date, how would you kind of rank those from a productivity standpoint and what are you most excited about?

Matthew Gallagher – Parsley Energy, Inc.

Methodically, as we go look backwards in history, compressing the stages and getting discrete pressure complexity has always increased production. So we’ve been assessing different ways to tackle that going all the way back probably to 2015 with an opti-port (01:09:43) type of test. And you want to match it with the capital you have to spend to get it. We were on a program 2015 to 2017 increasing our sand loadings and then took a material jump in the Delaware and kind of settled at a comfort zone on that respect. So, right now, it’s all about, where can you create discrete pressure propagation up and down in lateral and increase your frac complexity in your wellbore. So, everything, we’re doing is with that concept in mind.

Gail Nicholson – KLR Group LLC

Okay, great. And then, in regards to the $10 completion that got pushed into early 2018, were those all on the mineral rights, or were those the combination of mineral acreage and non-mineral acreage?

Matthew Gallagher – Parsley Energy, Inc.

Slightly a combination. And it will be a toggle on if they hit on the back of the year or not, but we decided just to, as pads go, push into 2018.

Gail Nicholson – KLR Group LLC

Okay. Great. Thank you.

Matthew Gallagher – Parsley Energy, Inc.

You’re welcome.

Bryan Sheffield – Parsley Energy, Inc.

Thank you.

Operator

Thank you. This does conclude our Q&A session, and this also concludes our call. Thank you for your participation. You may now disconnect your lines and have a wonderful day.

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