Q2 2016 Parsley Energy Inc Earnings Call

Midland Aug 5, 2016 (Thomson StreetEvents) -- Edited Transcript of Parsley Energy Inc earnings conference call or presentation Thursday, August 4, 2016 at 1:00:00pm GMT

TEXT version of Transcript

Corporate Participants

   * Brad Smith

      Parsley Energy Inc - VP of Corporate Strategy and IR

   * Bryan Sheffield

      Parsley Energy Inc - CEO

   * Matt Gallagher

      Parsley Energy Inc - COO

   * Ryan Dalton

      Parsley Energy Inc - CFO

Conference Call Participants

   * Neal Dingmann

      SunTrust Robinson Humphrey - Analyst

   * Drew Venker

      Morgan Stanley - Analyst

   * Irene Haas

      Wunderlich Securities - Analyst

   * Jeff Grampp

      Northland Capital Markets - Analyst

   * Charles Meade

      Johnson Rice - Analyst

   * Will Green

      Stephens Inc. - Analyst

   * Michael Hall

      Heikkinen Energy Advisors - Analyst

   * John Freeman

      Raymond James - Analyst

   * Kashy Harrison

      Simmons Piper Jaffray - Analyst

   * Sam Burwell

      Canaccord Genuity - Analyst

   * Gail Nicholson

      KLR Group - Analyst

   * Dan Guffey

      Stifel Nicolaus - Analyst

   * Jeb Bachmann

      Scotia Howard Weil - Analyst

   * Eli Kantor

      Iberia Capital - Analyst

   * Jason Smith

      Merrill Lynch - Analyst

   * David Tameron

      Wells Fargo Securities - Analyst

   * Chris Stevens

      KeyBanc Capital Markets - Analyst


Operator [1]

 Good morning, ladies and gentlemen. Welcome to Parsley Energy's second-quarter 2016 earnings call. My name is Jesse, and I will be your operator today. As a reminder this call is being recorded.

 (Operator Instructions)

 And now, I'm pleased to turn the call over to Brad Smith, Parsley Energy's Vice President of Corporate Strategy and Investor Relations.

 Brad Smith, Parsley Energy Inc - VP of Corporate Strategy and IR [2]

 Thank you, operator, and thank you everyone for joining us. With me this morning are Parsley's CEO, Bryan Sheffield; COO, Matt Gallagher; and CFO, Ryan Dalton.

 If you'd like to follow along with our investor presentation, you can find it our website on the Investor Relations page. As usual, our remarks contain forward-looking statements, so we refer you to our earnings release for a discussion of these statements and associated risk, 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 our earnings release.

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

 Bryan Sheffield, Parsley Energy Inc - CEO [3]

 Thank you, Brad, and thank you for joining us this morning. I think it's safe to say that Parsley Energy is firing on all cylinders.

 Production increased 23% this quarter versus last quarter, and taking a broader look we've grown production 16% per quarter since our IPO in early 2014, almost exclusively through the drill bit. You will notice on slide 3 that our recent production growth has come without adding rigs, which makes it even more impressive.

 We're raising full-year production guidance for the second time this year. We previously increased guidance by [1500] Boe per day to account for acquisitions, including flow-in production and drilled wells to be completed. We're now increasing guidance by 4,000 Boe per day at the midpoint to a range of 36 to 38 MBoe per day, reflecting strong productivity and more wells.

 We're now planning to complete 15 more gross horizontal wells this year, which is almost like adding a rig for a full-year and only increasing CapEx by $50 million or roughly half of what it would take to run a rig for a year. As proud as we are of a topline growth, we are equally proud of our progress on the cost front. DNC cost per 7,000 foot well are now less than $5 million, and as you can see on slide 4, we have reduced operating costs per Boe by 40% over the past year. We're lowering full-year guidance for on LOE per Boe and G&A per Boe by more than $1.50 combined.

 Turning to slide 5, recent transaction metrics certainly speak to the value of acreage position we've established. We feel fortunate to have added to this position in recent months at prices that look more compelling all the time. All told over the past few months, we have added around 33,000 net acres for around $12,000 per acre after backing out PDP value. This includes significant lease hold in both the Midland Basin and the Southern Delaware.

 We also recently closed our acquisition of mineral interest in the Southern Delaware, which increases our production and cash flow torque by adding incremental barrels without incremental activity or costs. In fact, as we say on slide 6, if you compare the contribution of one rig running for a year on mineral acreage versus drilling on acreage without mineral rights, the rig running on mineral acreage contributes around 400,000 more Boe and roughly $16 million of extra cash flow in one year.

 To give a sense of our tremendous growth potential, we framed a set of acceleration possibilities on slide 7. Obviously given that declining nature of shale production, you can't grow rapidly if you can't increase the number of wells you bring online. As the chart suggests, we have sufficient inventory and operational capacity to add several rigs over the next couple years.

 At the low end of this spectrum, if we were to add just one rig per year, we estimated that we could generate a compound annual production growth rate of approximately 30% over the next two years. If I said, if we were to add three rigs per year, we would likely generate something around 60% compound annual growth rate for 2018. The reality is likely to lie somewhere in between and will obviously depend on a number of factors, including the commodity price environment.

 We're not going to commit to anything at this point, so if we had to handicap it today, the most likely scenario for 2017 would be to run six rigs, three in the Midland Basin, and three in the Southern Delaware, with two of the rigs in the Southern Delaware drilling on our mineral acreage. However it plays out, we're very excited about the possibilities as our team continues to execute.

 And now I will turn it over to Matt for an update on that execution.

 Matt Gallagher, Parsley Energy Inc - COO [4]

 Thanks, Bryan.

 We truly are firing on all cylinders with robust well results across our acreage position. Turning to slide 8, this is the first time we've put Midland and Delaware type curves together, and I think it is instructive. For a 7,000 stimulated foot Delaware well, we're showing an 880 MBoe type curve provided by our reserve auditors.

 As you can see on the chart, while the EUR is lower than our 1 million Boe Midland Basin type curve, initial productivity is higher on the Delaware curve than on the Midland curve. The fact that our initial Southern Delaware wells are outpacing this curve helps explain why we're so excited about our Southern Delaware position and why we project very strong returns from our Southern Delaware wells.

 Meanwhile, Midland Basin Wolfcamp well result continue to impress, especially as you scan through the first year of production. The great majority of our Midland activity is focused on what we call our core area, and in fact all of the wells we completed in Q2 in the Midland Basin were located in the core. So we have broken out the performance of our core wells in particular.

 And as expected, they show higher cumulative production rates than when they are blended with tier 1 results, which yield healthy returns in their own right. As has been our custom, we've included all of our Wolfcamp wells in the data set so there's no selective sampling involved.

 It's worth noting that roughly 80% of our Wolfcamp A and B inventory in the Midland Basin is in our core area, and given the results we are seeing in Reagan County, we think that for the Wolfcamp the core extends farther east than we currently show on the map. In fact, we plan to redraw our map to reflect our latest petrophysical analysis and well results, so you can be on the lookout for that in the near future.

 There's a lot of information on this chart, but the take away on this slide is that we are completing really strong wells across our acreage footprint. Turning to slide 9, we continue to push on development costs and are still seeing favorable drop-down trends. Is Bryan mentioned, Midland Basin DNC cost for a 7,000 foot well averaged less than $5 million in Q2, and we accomplished this despite an increase in our average completion intensity. In fact, a well on our core equity set a Company record for lowest Wolfcamp DNC cost at less than $550 per foot, which would be less than $4 million when normalized to 7,000 feet.

 In addition, we're seeing very rapid rate of change in the Southern Delaware cost, which has historically been the biggest drag on development economics on that side of the platform. Our first Southern Delaware well was burdened by a number of startup and one-time costs that are standard for the first well in a new area. We are already drilling faster in the Delaware as you can see on the chart at the bottom, and our current costs are trending towards our Midland Basin well costs. We may not quite get all the way there because of greater depth and treating pressures in the Delaware, but we expect ongoing convergence.

 And surface rights on a good portion of our Southern Delaware acreage will shave another $200,000 per well associated with the water sourcing and disposal, a key differentiator for us in the Delaware that will further narrow the gap between Delaware and Midland well cost.

 Moving to slide 10, we've talked before about the cost savings associated with our transition to pad drilling and also our belief that completing multiple wells at the same time could boost productivity as well. Recent results, especially in the Wolfcamp A target interval, suggest that this productivity uplift could be significant. Our Wolfcamp A wells completed on pads in conjunction with Wolfcamp B wells are showing higher 30-day RP rate than our standalone Wolfcamp A wells. And a couple of our Wolfcamp A well pads in Upton County set Company records, not just for Wolfcamp A, but for the Company as a whole.

 Wolfcamp A well on our Hirsch lease, for example, registered a 30 day IP rate of 284 Boe per thousand feet, while a Wolfcamp A well on our Atkins lease produced 130,000 Boe in 90 days. So while Wolfcamp B wells have long set the pace in the Midland Basin, our Wolfcamp A wells are certainly in the same league and in some cases showing even higher productivity with a higher oil cut to boot.

 Together the outstanding productivity and cost performance we've discussed yields a truly compelling return profile across our Wolfcamp portfolio. You can see on the first chart on slide 11 that a standard 75% NRI, projected Delaware returns aren't far from our world class Midland Basin returns, with the shape of their respective type curves to accounting for increased separation at higher oil prices. Factoring in mineral interests in the Southern Delaware provides a huge boost to returns, catapulting these wells to the top of their return spectrum.

 It's a similar story on MPV, though with more cash invested and more cash generated, Southern Delaware wells show a higher MPV even before incorporating mineral interests. Bottom line, at stirred prices you are looking at returns of 60% to 90% and MPV of $7 million to $12 million on our 1,500 plus Wolfcamp locations, which certainly justifies the type of production growth we've generated and are preparing for.

 Turning to slide 12 we previously shared tremendous results on the first couple of wells on our Trees Ranch position in Pace County, and these wells continue to perform well. We are also very encouraged by initial results on our more recently added acreage position in Reeves County. We recently completed a well drilled by the previous operator and through the first 60 days results are outpacing the Delaware type curve and on trend with the Trees Ranch wells.

 We actually flowed the range of the well back pretty conservatively as you can see. It really came on strong in month two. We think the offset results we show at the bottom of this slide are more representative of the resource potential in the area than the wells that were previously completed by another operator on our acreage, which used a different completion design than we use, weren't necessarily in the same landing zone that we would target, and had some facilities-based flowback constraints. We've accumulated a deep inventory of high return drilling locations and on slide 13 we point to significant upside potential as we evaluate additional target intervals and tighter spacing scenarios.

 We continue to appraise our Southern Delaware position, analyzing a whole core sample we took, and triangulating with the seismic data and well logs. Our current best estimate of inventory in the Delaware attributes locations to four discrete target intervals, two in the Wolfcamp and two on the Bone Spring. For now we're counting eight wells per section in the Wolfcamp and four wells per section in the Bone Spring.

 We have a lot of inventory upside in the Midland Basin. We currently count just 16 total Wolfcamp A and B per section in the Midland Basin and over the next few quarters we're going to test potential for up to 45 locations per section in the Wolfcamp A and B alone.

 First we're going to work vertically, evaluating the interaction between the Wolfcamp A and two Wolfcamp B target intervals. Then we are going to test horizontal spacing, completing a set of eight upper and lower Wolfcamp B wells at 330 ft spacing. At 853 ft thick, our Wolfcamp A/B complex is the thickest you'll find in the D portion of the basin. So were optimistic about adding to our Wolfcamp inventory as these tests unfold.

 So we continue to have a lot to be proud of and a lot to look forward to when it comes to unlocking the value of our asset base; and now I'll turn it over to Bryan to discuss our financial results.

 Ryan Dalton, Parsley Energy Inc - CFO [5]

 Thanks, Matt.

 It was a very strong quarter from a financial perspective. Adjusted EBITDAX increase by almost 50% quarter over quarter, benefiting from higher volumes and realizations as well as lower costs. We exited the quarter with ample liquidity, including a fully undrawn borrowing base of $525 million.

 On slide 14, we reduced our cash balance to account for the closing of our mineral rights acquisition after the end of the quarter, resulting in a pro forma cash balance of $189 million and total liquidity of more than $700 million. Leverage is very favorable with a net debt to annualized adjusted EBITDAX ratio of 1.7 times.

 Slide 15 shows that we continue to have a substantial hedge position in place with the majority of our expected barrels hedged through the remainder of the year. Then we are back into our more typical range, 40% to 70% of barrels hedged for the first half of next year and we have been building our position in the second half of 2017. Or hedge position certainly dampens the impact of the recent pullback and oil prices on our bottom-line.

 I will also note, that in light of strengthening natural gas prices, we recently added some costed throughways to give us a bit more visibility on the revenue front. We've made several changes to our full-year guidance, as you can see on slide 16. Production guidance is up 4,000 barrels per day at the midpoint.

 And as Bryan mentioned, we're planning to complete around 20% more wells this year. It only increased in CapEx by around 10% at the midpoint. CapEx this quarter came in at $136 million, up just $26 million versus Q1 despite the fact that we completed ten borough lengths as well.

 Bryan also mentioned the changes in unit costs. We're reducing guidance for LOE per Boe by more than $1.00 at the midpoint. And for cash G&A per Boe, by $0.50 at the midpoint. We think it's clear that maintaining our activity and momentum over the past few months, when many operators slowed down, has allowed us capture a lot of value.

 We are realizing the benefit of increasing scale, spreading costs over a larger production base. All the pieces are in place to continue these trends and we expect to continue delivering a compelling combination of growth and returns.

 With that, operator, we'd like to take questions.

Questions and Answers

Operator [1]

 (Operator Instructions)

 Neal Dingmann, SunTrust.

 Neal Dingmann, SunTrust Robinson Humphrey - Analyst [2]

 Could you talk about how you'd try to complete the Delaware, any different than your Midland Basin wells?

 Bryan Sheffield, Parsley Energy Inc - CEO [3]

 I think in the beginning we just applied our Midland Basin completions very simple, probably more sand per foot, closer to 1,800 or 1,900 pounds per foot, more than at the time 1,600 to 1,700 pounds per ft in Midland. But that's the only difference, and we're using full slick-water frac, hardly any gel. So very similar to the Midland Basin, but I do see us increasing the same content in the Delaware.

Operator [4]

 Drew Venker, Morgan Stanley.

 Drew Venker, Morgan Stanley - Analyst [5]

 I was hoping you'd provide some more color on that development scenario that you laid out through 2018 in your slide deck/ What kind of commodity prices would each of those matchup with and any other assumptions you could detail, like well costs or well performance assumptions?

 Bryan Sheffield, Parsley Energy Inc - CEO [6]

 I think that I kind of look at the slide and this is derived off probably the past week's strip, and I think it's fair to think every $10, I've said before in other quarters, every $10 we would add a rig so that would be on top of our mentioning looking into 2017 with six rigs. If we start seeing an oil price rally you could potentially see an additional rig every $10 increments. On the service cost, we all know that service costs will eventually bump upward and hopefully it's in line with an oil price rally, but at times it's not, so we have to prepare for that so that could be a drag on my earlier comment.

 Drew Venker, Morgan Stanley - Analyst [7]

 Just to follow-up on Neal's question on the Delaware Basin completion design, as you ramp-up next year do you expect a slow increase in your proppant loadings, or can you just talk about how you plan to test different completion designs next year?

 Matt Gallagher, Parsley Energy Inc - COO [8]

 Where legging up quite a bit. Recent designs are going to be 2,500 plus pounds per foot and we have a multitude of specific tests down the spectrum of line items on that side, but we want to start with the baseline with our Midland Basin completion technique. On Midland we continue to incrementally push but the Delaware with the offset results and the vintage of where they're at over there, we're kind of legging up in a larger step fashion.

 Bryan Sheffield, Parsley Energy Inc - CEO [9]

 And Matt, just to hop on that, have you seen a strong relationship between much higher proppant loadings and much better well performance in the Delaware Basin?

 Matt Gallagher, Parsley Energy Inc - COO [10]

 We have. When you vintage it over time on the broad-basin analysis that we look at, you do get a positive correlation to increase to rates and then projected out to EURs with more sand loading, but there's a lot of different variables that go into it but that's what the highest -- higher correlation.

Operator [11]

 Irene Haas, Wunderlich.

 Irene Haas, Wunderlich Securities - Analyst [12]

 One more question on the Delaware Basin well. What was the cluster spacing for the Ranger well and also in terms of landing zones, how is this well differ from nearby wells?

 Matt Gallagher, Parsley Energy Inc - COO [13]

 So [stage spacing] is one of the variables that will definitely be pushed on, we're still at the 160 foot to 170 foot stage spacing with our initial wells out of the gate over there. And then we have identified four to six discrete targets to land in depending on the area, and this most recent well was landed in what would be kind of equivalent. We're still zeroing in on our naming convention, but to the upper portion of the Wolfcamp and it was held flat there. Don't know if it was actively geosteered before we took it over, so we will be implementing our geosteering practices going forward, and we look forward to that in our individual landing zones going forward.

 Irene Haas, Wunderlich Securities - Analyst [14]

 So we should expect better result with time as always?

 Matt Gallagher, Parsley Energy Inc - COO [15]

 That's always our drive.

Operator [16]

 Jeff Grampp, Northland Capital Markets.

 Jeff Grampp, Northland Capital Markets - Analyst [17]

 I wanted to touch back on the [outlook] into 2018 that you guys put in the slide deck, and maybe just ask little bit more specifically to the prior question. On type curve assumptions or well productivity, should we think about that model basically baking in that 1 million barrel Midland Basin and 880,000 in the Southern Del, or are you guys baking in given the fact that it looks like results are tracking ahead of expectations there?

 Bryan Sheffield, Parsley Energy Inc - CEO [18]

 I think if you want to model it out I would stick to those type curves. As we drill down these sections it's a safer bet -- don't increase what we're showing tracking this year because you never know what's going to happen in two years.

 Jeff Grampp, Northland Capital Markets - Analyst [19]

 And then back on the Delaware side, Matt, I know you guys highlighted some real positive productivity improvements from doing zipper fracs on the Midland side, and is that something that you guys see as some potential down the road to start testing and getting some uplift on similarly on the Delaware side, and if so can you guys just talk about any potential timing for when it makes sense to start to test out there?

 Matt Gallagher, Parsley Energy Inc - COO [20]

 You hit the nail on the head. It took us two years to methodically work through our processes in the horizontal gain on the Midland side and it think it took us two months on the Delaware side. We just completed our first zipper fracs off a two well pad last night and are essentially moving forward in pad development mode in the future on the Delaware.

 Jeff Grampp, Northland Capital Markets - Analyst [21]

 You guys kind of touched on the average lateral length of your Midland wells this past quarter. Can you guys just kind of remind me what the average lateral length is assumed for your core inventory, if you guys have that offhand more or less?

 Bryan Sheffield, Parsley Energy Inc - CEO [22]

 About 6,500 ft.

Operator [23]

 Charles Meade, Johnson Rice.

 Charles Meade, Johnson Rice - Analyst [24]

 If I could get you to go back to that slide 7 that you put in your slide deck, which I thought was a really interesting slide. It is really helpful about laying out what the future could look like for you guys. Can you talk a bit more about -- I believe the slide is set up -- this talks about maybe adding rigs in 2017.

 I know you guys are at four rigs right now, can you talk about what your current thinking is for the back half of 2016, when you might add rigs or what you are thinking of for maybe Q4? And more particularly talk about what's your timeline for making that decision and what the variables would be outside. You mentioned the oil price and that is an obvious one, but are there others and what's your timeline for thinking about that?

 Bryan Sheffield, Parsley Energy Inc - CEO [25]

 In our script just now we talked about that a little bit, about potentially adding two rigs in 2017, and also these four rigs that we have running, you have to remember they're accelerating right now. We just added 15 more wells, we could accelerate even more. So I think it's best to kind of stick with the plan.

 We were more aggressive in the beginning of the year with this aggressive rig program and CapEx program, and so the high is adding the two rigs going into 2017. Now that doesn't mean fourth-quarter -- third or fourth quarter, we're just going to continue going with these four rigs. Does that help with the timeline?

 Charles Meade, Johnson Rice - Analyst [26]

 That does, Bryan, and to clarify you talked about adding a rig for every $10. That's on top of a base of $50 oil?

 Bryan Sheffield, Parsley Energy Inc - CEO [27]

 I think that's fair thinking there. We're talking $0.01, but if oil moves up $10, we could be potentially add another rig sometime in the following year.

 Charles Meade, Johnson Rice - Analyst [28]

 And if I could ask a question about these up-and-coming Wolfcamp A wells? Obviously that's a great result to see from those wells and I'm curious, though. To what extent did you anticipate a result like this or did this 18% uplift surprise you? How many data points do totally have across this Wolfcamp A to be confident that this -- or how confident are you at what point would you become more confident that this is something that you can put your plans going forward?

 Matt Gallagher, Parsley Energy Inc - COO [29]

 We converted to pad drilling essentially this time last year, September of last year, bit in the ground, and at that time we were actually conservatively forecasting slight degradation in the stack scenario so this was a slight surprise. There was some conceptual modeling that forecasted it could be the case but we wanted to see it into the tanks. We now just have under 10 wells that have shown these types of results, so we are building our data set. We like to have a little but more than that, but we're trying to share the results of how we see to date and it's definitely encouraging to date.

Operator [30]

 Will Green, Stephens.

 Will Green, Stephens Inc. - Analyst [31]

 Great detail on what the mineral acquisition does for the MPVs out in the Delaware, so I guess the question I would have now is when you guys are adding rigs and looking at the 2017 budget and even looking out to say 2018, should we think about the Delaware getting an increased portion of the CapEx, or how are you guys thinking about CapEx allocation?

 Would we be in a scenario where you guys are moving rigs from the Midland to the Delaware or simply every rig addition goes out to the Delaware? How you guys thinking about that? Is there anything that prevents you guys from capitalizing on that great advantage you guys have out there?

 Bryan Sheffield, Parsley Energy Inc - CEO [32]

 There in the script we mentioned potential three and three Midland Basin and Delaware and two of the three in the Delaware on the mineral acreage. If you ask me today, I would think more rigs adding the percentage would increase in the Midland Basin, because we have a larger footprint and more -- operations that's more and intact more frac, the midstream's in place and the frac bits are in place. So you would think you would add more rigs in the Midland Basin, but the percentage of CapEx, maybe it goes 60/40, 60 Midland-40 -- through time, maybe a little bit higher and that just comes down to footprint.

 Will Green, Stephens Inc. - Analyst [33]

 And then I want to talk about the potential horizons down there in the Southern Delaware. You guys cave some color of that in the prepared remarks as well. We hear a lot about geologic complexity being greater over in the Delaware, certain Bone Springs areas being water saturated. When you guys targeted this position, how much mapping did you do? How confident are you guys that Bone Springs gets developed independently, and is there a reason that the first Bone Springs is not included within those target horizons?

 Matt Gallagher, Parsley Energy Inc - COO [34]

 I think it's key to note that we mapped and have been gaining data here since 2013. That's when we entered the position, and then we've been methodically taking all the right steps, full seismic proprietary shoot across our Pecos County position and then market seismic across the Reeves County position, whole core throughout the Wolfcamp interval, so the only reason these shallower zones, the Avalon, the Bone Spring, First Bone, of course it is sourced from the north, so we think it would be different in our area, but there is still oil in place, significant oil in place in those zones in our area, but we haven't done that type of work yet.

 We started with our primary target in the Wolfcamps and over time, over the next year or so we will be grabbing additional core and triangulating it with our well logs and sidewall cores and doing the work in a methodical fashion. So it is candidly more geologically complex. We've been building the team out since 2012, the entry position, and we think we have a good understanding and we think there is a lot of upside out there and excited about the entire column.

 Will Green, Stephens Inc. - Analyst [35]

 Nothing precludes you guys from ultimately maybe developing first Bone Springs, maybe even Brushy Canyon or Wolfcamp C even at some point, so it sounds like there's still some even additional inventory upside from what you guys are talking about.

 Matt Gallagher, Parsley Energy Inc - COO [36]

 Precisely. There's a lot of shallow shows from older vintage wells all across our footprint, but we do know to date very similar to the Midland Basin, but we have significant overpressure in the Wolfcamp even creeping up in the Third Bone, and we probably lose a little bit of that in the First Bone and shallower, but you can still have very economic wells without overpressure, as is evidenced in Midland Basin and the Lower Spraberrys.

Operator [37]

 Michael Hall, Heikkinen Energy Advisors.

 Michael Hall, Heikkinen Energy Advisors - Analyst [38]

 I guess just keeping on the question around the inventory picture in the Southern Del, what sort of time line would you say you have the test the intervals you've got in that slide? I think it was slide 13?

 Matt Gallagher, Parsley Energy Inc - COO [39]

 Returns focused, so out of the gate we're seeing tremendously strong returns and then on our minerals, so I think we always take about a six-month approach of recouping our investment costs and returning cash to investors, well to our portfolio, and then methodically testing the column there. But we want to get the core sampling done and then triangulate that to physical well testing, so there will be a 12 month to 18 month process, there's a lot of column here. But we're definitely going to target the two discrete Wolfcamp flow units early in 2017.

 Bryan Sheffield, Parsley Energy Inc - CEO [40]

 I think it's important to point out in the past when we de-risk zones, we tried -- we lean towards around 3% to 5% of our CapEx, so we're really focused on this growth and this operation momentum and on the 1,500 Wolfcamp locations that we feel like are lower risk and high returns.

 Michael Hall, Heikkinen Energy Advisors - Analyst [41]

 And then I guess my only follow up would be --operating costs, I mean they came in very nicely in the quarter, [obviously this] guidance as well -- we're trying to get our head around how sustainable these cost improvements we're seeing across the space are and just how sustainable the whole cost structure shift is thought to be. So particularly on the operating cost side, I'm just curious how sticky or sustainable do you believe these improvements could be as we think through that 2017, 2018 timeframe and kind of reacceleration from the industry?

 Matt Gallagher, Parsley Energy Inc - COO [42]

 First I want to note it's purely a testament to the energy, excitement, innovation of our employees, product of wholesale processes that they put in place a year ago and we're seeing the fruit of that improvement. So to that extent the process improvement, these are things tying into our own SWD infrastructure and wholesale mine shifts that are sticky that are going forward for us. So no doubt if there is a aggressive recovery in oil price or activity levels, you'll see pressure on different line items, but we have a structural advantage now with our footprint in the Midland and the things that we're putting in place of the Delaware that we think will be able to mitigate and hedge against some of that recovery.

 So we are preparing for that kind of creep, but I think historically you look in the -- on the operating cost range, it lags a little bit, the oil price run, but it does come on the order of 10% or so in that manner. But we had 26% reduction even from last year on D&C and over 50% reduction on LOE and that's just an amazing testament to the team.

 Michael Hall, Heikkinen Energy Advisors - Analyst [43]

 The 10%, what was that in reference to? In terms of potential inflation I guess, is that what you're referring to? Or 10% of the cost would be exposed to?

 Matt Gallagher, Parsley Energy Inc - COO [44]

 Think about 50% of our cost of our line items would be exposed to unit cost depreciation and then I think that boils down to in a moderate recovery about 10% creep from whenever we hit our base.

 We are -- wells that we're just putting down right now are still cheaper than what wells we put down in the second-quarter so we are not at the bottom yet. But we are seeing fringe line items with cost pressures when these guys are below their cash costs, so we're trying to work with them to keep them around. So the order of magnitude in the cost reductions are slowing, and then that 10% was in reference to the 50% of line items that we think are exposed to unit cost [depreciation].

Operator [45]

 John Freeman, Raymond James.

 John Freeman, Raymond James - Analyst [46]

 When I look at slide 13 and the plan for 2017 of doing the Upper and Lower Wolfcamp B stack and [stagger] test -- how should I think about that approach and how you kind of juggle that with obviously the big uplift you show on slide 10 when you complete the Wolfcamp A and B in tandem?

 Matt Gallagher, Parsley Energy Inc - COO [47]

 It is important that we're not expecting that kind of uplift within Upper B and Lower B. We still have significant height to work with, but as we started modeling on our Upper A -- I mean A and B test, we expect individual well results to be slightly off from a standalone well in our forecast, which is kind of baked into those sensitivities going forward.

 We hope to be surprised of the upside, but it's just reasonable and prudent to expect individual well reductions, but we are looking for the whole system maximizing MPV per section, so you get into a much more efficient surface development situation when you go to this type of spacing and then of course capturing additional resource through that discrete bench in the Upper B.

 John Freeman, Raymond James - Analyst [48]

 And if I shift over it to Delaware, you know, Bryan, you have always been really candid on what you are seeing in sort of the A&D arena, and obviously when we look at the acreage prices. You picked up acreage from the Delaware in the spring and then as recently as last year's call you sort of said in the Delaware you were seeing acreage prices like $10,000 to $5,000 acre, and obviously last month we've seen like a double. I'm just curious from your perspective what you think drove such a huge increase just all of a sudden? Is there anything you can point to in terms of confidence of additional zones, costs or anything like that?

 Bryan Sheffield, Parsley Energy Inc - CEO [49]

 I'm still little bit in shock what I've seen in the past couple months. I mean we just paid last April came out and you look at April, we paid around $9,000 an acre, and I know some of these sellers, recent transaction sellers, paid about equivalent, about six months ago, or nine months ago, if look at the [Ogder Stevens on his bond], and [as research] you know how much -- you can kind of put together what the transaction is and then six months later.

 So it's truly amazing. We've gone from $9,000 acre print to a $25,000 acre print and now a $35,000 acre print. I think we're in the world of $20,000 to $25,000 in the Delaware. I really think that's the reality. Anything north of $30,000, I think that's kind of -- we can't get to it on a map in the return on acquisitions.

 John Freeman, Raymond James - Analyst [50]

 That's really helpful.

Operator [51]

 Kashy Harrison, Simmons Piper Jaffray.

 Kashy Harrison, Simmons Piper Jaffray - Analyst [52]

 Given the increase on the mineral inventory in the Delaware Basin with the potential to take that even higher over time, how are you guys thinking about extracting the most value for those assets? Specifically do you think that spinning a yield vehicle over time would give the most value or do you like the idea of keeping the minerals within Parsley as is?

 Bryan Sheffield, Parsley Energy Inc - CEO [53]

 I think it's very early to even wrap our minds around it. I do kind of fear the investment bankers will start coming in about a year, saying we should spin it off or do it similar [venom], and we need to be open-minded. We get a look at it and we got to assess.

 Its a way to access capital and increase our rig count. We need to look into it, but right now I need to remind you we're well underneath 1,000 barrels on the mineral acreage, so we really need to get up a 7,000 to 10,000 barrels to really even think about anything like that.

 Kashy Harrison, Simmons Piper Jaffray - Analyst [54]

 Thanks for that. Apology is this was mentioned earlier, but you guys are making excellent progress driving the completion cost lower in the Midland, do you have any thoughts on where those could be by the end of the year?

 Matt Gallagher, Parsley Energy Inc - COO [55]

 We mentioned a well that we've got under our belt, it's [sub] $4 million, 7,000 ft. That was a good well. Everything went right, and had a great cycle times on it. But that does appear to be repeatable and we're continuing to make [BHA] and improvements throughout the process, but on average, I'd expect a slight downtrend from our $4.8 million average that we just printed on our core wells. And remember every well we drilled was in the core which is our deeper, higher pressure area and historically higher drilling costs, so it's really a larger cost savings than just the math would show. So that should, at least in the third quarter and continue to slightly [trim] down.

 Kashy Harrison, Simmons Piper Jaffray - Analyst [56]

 And then just last one for me. On those -- on page [15], those down spacing tests that you had planned in the Midland Basin next year, what part of -- what's the timing of those in 2017?

 Matt Gallagher, Parsley Energy Inc - COO [57]

 It takes a long time to bring these things online and then we're going to be doing a lot of data-gathering as well, so realistically it would probably be the back half of the year before we would see results there.

Operator [58]

 Sam Burwell, Canaccord.

 Sam Burwell, Canaccord Genuity - Analyst [59]

 I want to dig in a little bit more on the efficiency gains that drove the out-performance in Q2 and then guidance rate in the back half. Is there like a go-forward assumption that we should use for the amount of wells per rig, per year in the Midland. Has that changed dramatically?

 Matt Gallagher, Parsley Energy Inc - COO [60]

 We are down around 20 or 21 days full cycle on average per well, and then I think this time last year we were up 28 to 30, and our wells are getting longer, so that's key there, And then we expect that to continue to grind down, as well, and then on the Delaware side, tremendous rate of change over there. The teams have done great.

 Our fourth well that we just TD'd that's not on the chart was quicker cycle time than the first three wells, so progressive improvement over there. We hope to compress that to the Midland Basin cycle times, and we are well on our way, so we're in the 24 to 25 day range over there in the Delaware.

 Sam Burwell, Canaccord Genuity - Analyst [61]

 And if I could take sort of the flip side of the question that's been asked a few times. Bryan, if I heard you correctly, it seemed like you said $50 is sort of what underpins the six rig plan for 2017. If we are looking at WTI in the low 40s at this time six months from now let's say, does that change the plan materially? Would you take it down, and if you did, would that change the sort of 50-50 split between rigs in the Delaware versus the Midland?

 Bryan Sheffield, Parsley Energy Inc - CEO [62]

 Every $10 we would probably give it a hard look adding the rig on top of the scenario that you are seeing, but I also mentioned we need to remember about service costs, a service costs increase, so that could be a tailwind on that thinking. But we're really focused on adding the two rigs in 2017. The last part of your question was on allocation, right? Allocation of capital?

 Sam Burwell, Canaccord Genuity - Analyst [63]


 Bryan Sheffield, Parsley Energy Inc - CEO [64]

 It's just we have a larger footprint in the Midland Basin, so I just imagine -- if you want to add rigs and modeling that would add -- first add an extra rig in the Midland Basin, and then moving forward I would think 60% to 70% of our capital would still be the Midland Basin, mainly because of footprint, but I still feel like the returns are superior than the Delaware.

 Sam Burwell, Canaccord Genuity - Analyst [65]

 What I was really trying to get at, though, is there a price where you would decelerate from the six rig plan?

 Bryan Sheffield, Parsley Energy Inc - CEO [66]

 Yes. We are hedged pretty good, 100% hedged for the rest of the year 2016, I think first half 2017 we've got 60% hedged, so we are in a position of strength on our hedge book, and if you start seeing low 30s in oil, I'm going to anticipate there's going to be more pressure on cost, so you might see us dial back the additional rigs in 2017.

Operator [67]

 Gail Nicholson, KLR Group

 Gail Nicholson, KLR Group - Analyst [68]

 Bryan, you mentioned that you could accelerate more in 2016 if you wanted to. Was that on the current forward program, or would that have been under the assumption that you added a rig?

 Bryan Sheffield, Parsley Energy Inc - CEO [69]

 I think that was on the previous question -- that was just on acceleration of the four rigs and adding well count on the four rigs. We do not plan on adding a rig this year.

 Gail Nicholson, KLR Group - Analyst [70]

 On that four rigs, and if you wanted to do more completions on the [RE] uptick of the [15], how many could you actually do if you were completely maxed out?

 Matt Gallagher, Parsley Energy Inc - COO [71]

 I think it's just a function of cycle time improvement, so what we are mentioning is that 15 rig count is at our current cycle times today, but over the last 12 months, month by month, quarter by quarter we've seen efficiency gains on cycle times, so we hope with that same four rig count to deliver more than the 15 as we continue to improve cycle times.

 Gail Nicholson, KLR Group - Analyst [72]

 And then looking at the Trees Ranch well versus the Ranger, was there any difference in the compositional mix that you've seen over the 30 to 60 day timeframe for oil?

 Matt Gallagher, Parsley Energy Inc - COO [73]

 Yes. As we go west on our position, we're going to be slightly less oily. We're probably the highest in the basin on our oil content on the Trees position. You are at 90% crude on a two stream basis. As we get over the western position, the very western edge, it would be 70% to 75% on crude, so still very high oil content.

 Gail Nicholson, KLR Group - Analyst [74]

 Looking at the potential rig acceleration, the one rig, the two rig, or the three rig per year, in the 2016, 2017, 2018 timeframe, do you need to add more personnel to accelerate that rig count, or do you have enough personnel currently on staff to handle those three scenarios?

 Matt Gallagher, Parsley Energy Inc - COO [75]

 I think it's a scalable model and you have -- we have a system in place, methodically as your well count grows you're going to need key personnel in the field that can only handle 40 to 50 wells per person. So it grows scalably, but the core structure is in place and it would definitely not increase the G&A per barrel, nothing structural would need to be changed. There would just be scalable ads.

 Gail Nicholson, KLR Group - Analyst [76]

 Okay, great. Thank you so much.

Operator [77]

 Dan Guffey, Stifel.

 Dan Guffey, Stifel Nicolaus - Analyst [78]

 I guess what type curves are being used to drive your production guidance in second half 2016 and sensitivity through 2018, and then obviously with the clear out performance across all of your acreage, at what point might your -- might you raise your average type curve and/or EUR?

 Matt Gallagher, Parsley Energy Inc - COO [79]

 We have probably around 24 discrete curves by area, so to try to boil it down to an average is a little tough but we are still in that -- essentially using that average that we are forecasting on our slide deck, on slide eight in both basins. And the reason being, as Bryan mentioned, and we are doing additional down space testing, when you blend it all altogether, there is still the unknowns on those spacings, so we think it's sufficient to use that curve for the long-term on a broader modeling sense, but we do have discrete curves by area internally.

 Dan Guffey, Stifel Nicolaus - Analyst [80]

 And can you provide a cost difference for the central Upton rig into northern Upton wells, because of the depth and pressure differences?

 Matt Gallagher, Parsley Energy Inc - COO [81]

 A year ago it was around $500,000. You are probably in the $100,000 to $200,000 absolute range for a 7,000 ft well.

 Dan Guffey, Stifel Nicolaus - Analyst [82]

 Any near-term plans to test Lower Spraberry?

 Matt Gallagher, Parsley Energy Inc - COO [83]

 Yes. We have a well flowing back right now. It doesn't have its 30 day rate, but because it is still cleaning up, but very good rates right now, extremely encouraged by it, and we look forward to updating everybody with that result when it gets a 30 day peak.

 Dan Guffey, Stifel Nicolaus - Analyst [84]

 Looking into 2017, will that be an active part of your program?

 Matt Gallagher, Parsley Energy Inc - COO [85]

 It appears to be returning competitive out of the gate, because as you go to shallower intervals your D&C costs come down even further, so it would be a component of CapEx, but probably a pretty small component just trading one equivalent in return for another, so it would stick in the -- it would be a small component, yes.

Operator [86]

 Jeb Bachmann, Scotia Howard Weil.

 Jeb Bachmann, Scotia Howard Weil - Analyst [87]

 Where are the early 2,500 pound proppant tests going to be located on the Midland side?

 Matt Gallagher, Parsley Energy Inc - COO [88]

 That's going to be in northwest Reagan and again that is flowing back, hasn't hit its 30 day peak either, still cleaning up. We did also do quite a bit larger water volumes as well, also encouraging results, so those -- that will probably come hand-in-hand with our Lower Spraberry results.

 Jeb Bachmann, Scotia Howard Weil - Analyst [89]

 And just to clarify, you guys have a Wolfcamp C test later this year, is that right?

 Matt Gallagher, Parsley Energy Inc - COO [90]

 Spudding, yes.

 Jeb Bachmann, Scotia Howard Weil - Analyst [91]

 And what County is that in?

 Matt Gallagher, Parsley Energy Inc - COO [92]

 Should be in Reagan County.

Operator [93]

 Eli Kantor, Iberia Capital.

 Eli Kantor, Iberia Capital - Analyst [94]

 I just want to follow-up on the A and B conversation, can you kind of touch on the [similar] acreage valuation thoughts with regards to Midland basin, that's what you mentioned in the Delaware.

 Bryan Sheffield, Parsley Energy Inc - CEO [95]

 There is an outlier out there and it made everyone perk up little bit. I think certain companies need to -- if they want to get in the basin, you've got to break in to be an outlier.

 That one asset is a very nice asset in southern Martin County, nice blocky, all benches, but it's hard to gauge right now since there hasn't been another Midland transaction with that outlier price, so I really couldn't tell you. My guess would be $25,000 to $35,000, since we now are pulling the range up, but we just haven't seen anything yet.

 Eli Kantor, Iberia Capital - Analyst [96]

 And at what price point do you start to struggle internally with the making the wellhead economics work?

 Matt Gallagher, Parsley Energy Inc - COO [97]

 I think it comes down to what kind of rig program you can throw at any acquisition with both basins with the type of productivity and the well costs multiple operators are seeing right now, it comes down to adding tail inventory, where you are adding it in your inventory cycle. But any acquisition on a standalone, if you put enough activity at it you can pull that value forward. So what you're seeing now are different people coming at different acquisitions at different cycles in their company and their inventory, and how aggressive they can be with their activity once they make the acquisition.

 Eli Kantor, Iberia Capital - Analyst [98]

 And in terms of the number of packages and the size of packages available for sale, can you just give a sense of what the opportunity set looks like? Comparing Midland Basin versus Delaware.

 Bryan Sheffield, Parsley Energy Inc - CEO [99]

 Midland is a lot tighter because we've seen a number of acquisitions the past three, four years. It seems like we are all bumping into each other a little bit, so I really haven't seen any packages in the Midland Basin, so it's more homegrown leasing and [pulling] and trades. There might be a few more left that just pop out of nowhere, some of those old operators from family operators out of Midland Texas.

 Now in the Delaware there is a lot of private equity. Companies that have a lot of acreage all around us, all over the southern basin, I'm hearing there's potential IPOs still even though one of them got taken out, so you're going to see more activity probably on the [A&D] side in the Delaware because of the stream for the private equity acreage.

 Eli Kantor, Iberia Capital - Analyst [100]

 Last one for me just on the well cost front. You guys continue to drive down your overall [AFVs], very impressive. Curious as to what the duration and prices of your current service contracts are, what you're expecting for these two rigs that are scheduled to come online for next year, and if you have any appetite or interest in locking in either component, whether it's rigs or frac crews for an extended period of time?

 Matt Gallagher, Parsley Energy Inc - COO [101]

 We only have two of our rigs contracted long-term rates. Those were carryovers from the previous high cost era, the rest are at spot rates and we see the market anywhere from $14,000 to $16,000 a day depending on what type of bells and whistles people are adding on to the rigs.

 And then we would be open to extending contracts on the new pricing regime given our base level of activity even in a reduced commodity price environment. So we would look to term out the rig side. We have not as a Management team been in favor of anything termed out on the frac side, just very tough to incentivized and get alignment there historically as an industry and motivation seems to lag, so we will probably continue using four to five vendors at any one point and competitively working the process on that side.

Operator [102]

 Jason Smith, Merrill Lynch.

 Jason Smith, Merrill Lynch - Analyst [103]

 I know we've covered a lot of ground, so just a quick one for me. I appreciate all the color on slide 22 on the infrastructure in the Southern Delaware, can you just maybe help us frame what your potential infrastructure spend looks like, if you ramped up your rigs and especially on things like water supply and disposal? And I guess combined with that, I guess is there a need for further buildout in the near term if industry does add rigs as aggressively as it seems they are beginning to in the play?

 Matt Gallagher, Parsley Energy Inc - COO [104]

 Our corporate approach is to let the experts focus on that and spend mineral costs on infrastructure and focus on our high return wells. So a lot of these you can create compelling midstream entity on your own but when you look at your returns on the wells, we seem to be outpacing that. And fortunately we can do that in high density areas with a lot of competitive buildout on the infrastructure side. So really when we're on top of our D&C costs, we're around 10% on what we call facility and infrastructure, which is essentially well level facility to the connect points.

 On the Delaware side, the next 18 months I predict that to be in the 15% to 20% range, just as you are just building out some additional physical roads to connect to those SWDs. We do drill our own SWDs and have that infrastructure and water gathering in house, Then the other thing to note on our Delaware position is we own the surface. So water sourcing is going to be very beneficial to us, and we see on the order of $200,000 of savings per well just due to our surface ownership there as we look at building out or water sourcing, gathering and disposal systems out there. So really, we're talking about an oil takeaway and gas takeaway and electrical inbound, and we're in a very good position for all of those three line items on -- in the Delaware.

 Jason Smith, Merrill Lynch - Analyst [105]

 You guys touched on rig rates. Are you seeing any upward pressure yet from service companies on pricing in the basin now at this point?

 Matt Gallagher, Parsley Energy Inc - COO [106]

 We essentially are not, but the order of magnitude of the reductions are lowering, so it's more competitive around a singular price right now.

Operator [107]

 David Tameron, Wells Fargo.

 David Tameron, Wells Fargo Securities - Analyst [108]

 Bryan, as you think about the big picture, and you talked about how the acquisition continues to heat up, how do you think about where you are at in your portfolio, how much bigger do you want to get? How should we think about the way you are thinking about and the way the Board is thinking about the evolution, if you will, of Parsley over the next, call it (multiple speakers) two or three years.

 Bryan Sheffield, Parsley Energy Inc - CEO [109]

 Now we look at the Wolfcamp locations. That is our highest return project, and we kind of do the math on full rigs, how many years, for 12 to 14 years out on four rigs, and if you add a couple more rigs, how many years, and we like to stay at least seven to 10 years out on this. I think in a couple years it is going to be harder and harder and we're going to have to make tough choices as a Company, but right now with the down spacing project in the [BBs] could delay it.

 We don't really need to worry about it right now, but it is something to watch, but right now we have 1,500 locations right now so you can do the math. We're in a very good position with a lot of running room.

Operator [110]

 Chris Stevens, KeyBanc Capital Markets.

 Chris Stevens, KeyBanc Capital Markets - Analyst [111]

 Quick question on the Delaware Basin. Do you know what the average lateral length is going to be as you start putting rigs to work there in 2017? And then also on the Midland Basin side, should we assume the lateral length is pretty much in line with the 7,000 ft from this year?

 Matt Gallagher, Parsley Energy Inc - COO [112]

 Our average around 7,000 feet on our potential locations on the Delaware side, but really we are going to frontload our 10,000 footer, so our Pecos County position is all 10,000 foot development. That's on our 30,000 acre ranch, and we will have a high percentage of 70% to 80% of 10,000 footers. On the Midland side, when -- we also tend to frontload it, and then a lot of success from the teams on these trades that are extending lateral lengths month in and month out, so to the extent possible, continue frontloading the longer locations on the Midland side, as well. So that should slowly grind up on average program lengths.

 Chris Stevens, KeyBanc Capital Markets - Analyst [113]

 And finally on the M&A side, if you guys were to continue adding out in the Delaware Basin, are you pretty much only focused on that southern area near Pecos and Reeves where you are right now? Or do you sort of venture out and maybe look at other areas of the Delaware Basin closer to the state line area or up into New Mexico?

 Bryan Sheffield, Parsley Energy Inc - CEO [114]

 We've always had a strategy, more bolt-ons and close radius of our operations. You have a huge edge and advantage when you stay close to home and where your field office is, where your [properties] and foremen are, where your engineers are focused on and especially in the rock, and if you understand the rock in a certain area. So we're just going to keep on pounding away on anything that is close or contiguous. Maybe up to a 50 mile radius, and that is the same strategy we have applied in the Midland Basin also.

Operator [115]

 Ladies and gentlemen, we have reached the end of our question and answer session and this does conclude today's teleconference. Again we thank you for your participation. You make disconnect your lines at this time and have a wonderful day.