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Edited Transcript of PE earnings conference call or presentation 24-Feb-17 2:00pm GMT

Thomson Reuters StreetEvents

Q4 2016 Parsley Energy Inc Earnings Call

Midland Feb 24, 2017 (Thomson StreetEvents) -- Edited Transcript of Parsley Energy Inc earnings conference call or presentation Friday, February 24, 2017 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Brad Smith

Parsley Energy Inc - SVP of Corporate Strategy & IR

* Bryan Sheffield

Argus Research Company - CEO

* Matt Gallagher

Parsley Energy Inc - COO

* Ryan Dalton

Parsley Energy Inc - CFO

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Conference Call Participants

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* Charles Meade

Johnson Rice & Company - Analyst

* Drew Venker

Morgan Stanley - Analyst

* Dan McSpirit

BMO Capital Markets - Analyst

* Neal Dingmann

SunTrust Robinson Humphrey - Analyst

* Scott Hanold

RBC Capital Markets - Analyst

* Irene Haas

Wunderlich Securities - Analyst

* Michael Glick

JPMorgan - Analyst

* Jeff Grampp

Northland Capital Markets - Analyst

* John Freeman

Raymond James - Analyst

* Michael Hall

Heikkinen Advisors - Analyst

* Sam Burwell

Canaccord Genuity - Analyst

* Gail Nicholson

KLR Group - Analyst

* John Nelson

Goldman Sachs - Analyst

* Jeff Robertson

Barclays Capital - Analyst

* David Tameron

Wells Fargo Securities - Analyst

* Chris Stevens

KeyBanc Capital Markets - Analyst

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Presentation

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Operator [1]

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Good morning, ladies and gentlemen. Welcome to Parsley Energy's fourth-quarter 2016 earnings call. My name is Audrey, 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 Senior Vice President of Corporate Strategy and Investor Relations.

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Brad Smith, Parsley Energy Inc - SVP of Corporate Strategy & IR [2]

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Thank you, operator, and thanks, 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 at our website on the investor relations page.

As usual, our remarks contain forward-looking statements. So please refer to our earnings release for a discussion of the 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 those reconciliations in our release as well. And after our prepared remarks, we will be happy to take your questions. And now I will now turn the call over to Bryan.

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Bryan Sheffield, Argus Research Company - CEO [3]

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Thanks, Brad. 2016 was an incredible year for Parsley Energy. Over the past few quarters, we've set the pace on both production growth and cost compression. A year ago on this call, we were excited to point to expected production growth of around 40% in 2016 versus 2015. We actually grew production by around 80% last year, and we achieved this on a steady rig count for most of the year. We're proud that our growth has been capital efficient as we've added more barrels per dollar than our peers.

The fourth quarter was a strong conclusion to the year. As you can see on slide 3, we grew production by 5% versus Q3, capping off a year of tremendous production growth. And we're expecting very sharp growth again this year.

Slide 4 shows that well costs are holding steady, despite rising completion intensity and the first traces of cost inflation. And we continued to lead the pack on operating costs, with another substantial quarterly reduction. The big news, of course, is our pending acquisition of Double Eagle, which gives us a commanding presence in the Midland Basin. We are acquiring around 71,000 net acres, with some production and a number of drilled, uncompleted wells.

The inventory potential is tremendous, with around 1,800 net locations in our highest-priority targets, the Lower Spraberry, Wolfcamp A and Wolfcamp B. And many more locations in other many promising locations like the Wolfcamp C. As you can see on the map on slide 5, most of the position is operated in non-operated portions, mainly distributed around the edges. The primary development units consist of higher working interest blocks in the interior of the acquired acreage.

On the other hand, the non-acreage averages just 25% working interest, which weighs down the overall average, and also makes the non-op acreage look like a bigger component on the map than it actually is. For example, the big non-operated block into north-central Howard County is only around 1,500 net acres. We are seeing positive results in this area and around most of the non-op acreage. But given the low working interest, we're actively discussing trades that would add mass and increase net in the main development areas.

The asset is evolving constantly, and we feel very fortunate acquiring it now. In a transaction like this, you pay for the net, but much of the upside is in the gross. The acreage represents compelling value today, but ultimately, we expect the map to fold inward to the central core-operated divisions.

Already there are years of long lateral high-working interest locations in plays in the best parts of the basin. We will drill these locations first. And all the while, we'll be working the rest of the asset, blocking up, extending laterals and increasing our net, which is the same playbook we used to build our legacy Parsley position.

Turning to slide 6, more than 80% of the net acreage we're acquiring is in part of the Midland Basin that we've identified as the sweet spot. This is an area where favorable depth, fitness and thermal maturity profiles combine to yield the most attractive reservoir characteristics. And again, the acreage that lies outside the sweet spot is a much lower working interest than the rest. Parsley has always focused on core acreage. That mindset has served us well, and we're sticking to that strategy with this acquisition.

When you look at the pro forma map of slide 7, not only will we have the second largest Midland Basin net acreage division among publicly traded E&Ps, we think it's the highest-quality position as well. As you can see, our acreage is situated in the heart of the basin, mainly inside peer-company footprints. We truly are in the core of the core.

Another important aspect of the acquired acreage is that it's essentially undeveloped horizontally. The time to acquire an asset is in its infancy, and we will have a lot of virgin rock to drill, which is really positive for expected productivity. It also allows us to optimize layouts for long-term, fully down-spaced development.

We believe this acquisition puts us in a position of strength. As you can see on slide 8, it puts us well-over 200,000 net acres. And it pushes our inventory above 4,000 net drilling locations in the Lower Spraberry and Wolfcamp targets alone. After integrating these assets, we believe we could run around 25 rigs on the combined footprint in the near term. That number will surely increase over time with additional infrastructure build-out. So we've definitely increased our peak production potential.

We've seen several larger packages change hands across the Permian over the last few months, and there aren't many left, especially in true core areas. For our part, we feel essentially right-sized, and are focused on pulling forward the tremendous value associated with our asset base. At this point, we can truly say that there isn't a single acreage position of comparable size that we would trade ours for.

We do believe in the value of scale, and anticipate ongoing consolidation in the Permian. But we're entering a digestion period, where we expect to concentrate on optimizing and developing our own portfolio. With this in mind, we're planning to add four rigs by the end of 2017, as you can see on slide 9. Naturally this sets us up really well for continued strong growth in 2018.

We believe we're entering a sweet spot as a Company, large enough to push down costs and capture efficiencies, but not too large to grow rapidly and adjust to changing conditions. Our recent acquisitions ensure that we have the runway to deliver on the growth potential, and also that we will be drilling on premium rock for many years.

As discussed, our Midland Basin acreage represents the core of the core. And our Delaware position remains a crown jewel, with strong productivity, low costs relative to other portions of the Delaware, and the economic uplift of mineral rights on much of the acreage. This means that for a long time, we'll be able to say that the rock we drill tomorrow will be as good as the rock we drill today. With that, I'll pass it off to Matt for more detail on the quarter.

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Matt Gallagher, Parsley Energy Inc - COO [4]

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Thanks, Bryan. It was a great quarter on the operational front. Our production growth is driven by consistently outstanding well results, which are a function of excellent rock and strong operational performance. We continue to achieve high initial productivity, even as we increase lateral lengths. In fact, as you can see on slide 10, several recently completed wells posted Company records in both the Midland Basin and the Southern Delaware.

You can see on slide 11, that our Midland Basin wells are registering the most revenue per lateral foot during the first three months of production among Midland Basin operators. This is a function of leading productivity in an oil-weighted production mix. Results like this give us confidence to double down in the Midland Basin, as we've done with the Double Eagle acquisition.

Turning to slide 12, in the Midland Basin, we've focused primarily on the Wolfcamp A and Upper and Lower Wolfcamp B targets to date. But we're starting to see results from other targets that rival the Wolfcamp A and B. For example, our two-mile Lower Spraberry well continues to shine. We show its production history here against the 1 million barrel type curve that reflects the shape of Wolfcamp A and B wells.

The Spraberry well started lower, as expected, but with near-flat production trends, it looks poised to surpass the curve. And based on the production trajectory, we could be looking at a very robust alternate recovery. Combined with slightly lower costs and slightly higher oil cuts, our Spraberry portfolio could give our Wolfcamp wells a run for their money. This particular well is in Upton County, and much of the acreage we are acquiring is in prime Spraberry territory to the north. So we expect the Spraberry to be an important part of our development program going forward.

Perhaps more notably, we recently completed our first well in the Wolfcamp C formation, and it posted the fourth-highest 24-hour IP rate in Company history. The well is currently making around 75% oil, and flowing at over 3,000 pounds pressure. Yesterday alone, it made more than 1,700 barrels of oil. This is obviously a very encouraging result and suggests that the Wolfcamp C could be on par with our other premium locations. So stay tuned for more to come on the Wolfcamp C.

Turning to the Southern Delaware on slide 13, record well results are making us feel very good about our recent acquisitions in Reeves County. Acquiring a block like this adjacent to our existing footprint is a real coup. Clearly this sets us up nicely for long lateral development. And the target zones on this block are actually a little thicker than our existing Reeves acreage immediately to the north.

The first well we drilled in Reeves posted an IP30 of more than 1,900 Boe per day, representing our strongest Southern Delaware result to date, and the third-highest IP30 Companywide. Our second drilled well threatens to suppress that mark, having turned in the highest peak-24 rate in Company history, and more than 2,600 Boe per day. These rates, combined with the minerals we acquired on and around the position, have made this asset the match of anything in our portfolio.

You can see on slide 14 that we posted tremendous reserve growth in 2016, growing crude reserves by 80%, despite writing off what remained of our vertical reserves. We added seven times what we produced, mostly through drilling. And we showcased very strong capital efficiency, with PD F&D costs around $8 per Boe. Like our production growth, our reserve growth is a function of strong and repeatable wells.

Several of our PDT wells are booked at EURs at 1.5 million Boe. One is booked at over 2 million Boe. With PUDs conservatively booked at much lower EURs, we have substantial reserve growth ahead of us. So lots of positive trends and developments on the operational front, and a lot of exciting results ahead in 2017, with a good portion of our capital going to relatively unproven zones and new spacing configurations. With that, I'll hand off to Ryan for color on our financial and capital program.

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Ryan Dalton, Parsley Energy Inc - CFO [5]

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Thanks Matt. We posted a strong increase in adjusted EBITDA in Q4, up 24% versus Q3, to $117 million, driven by higher volumes and lower unit costs. Fourth-quarter production came in better than expected at 45.1 MBoe per day, up 5% versus Q3. This puts us within our recently updated guidance range for the year, as does reported CapEx of $158 million. Normalized well costs held fairly steady, so we had particularly long laterals and high working interest on the 21 wells we completed in the quarter.

Slide 15 shows our 2017 capital plan, which we introduced several weeks ago, and then updated for the Double Eagle acquisition. We're keenly aware of the needs to earn strong returns on committed capital, and our 2017 budget is designed to extract value from new and existing assets alike.

Our asset base, financial profile and operational capacity position us to significantly increase drilling and completion activity this year, and that's what we plan to do. We're targeting 130 to 150 gross horizontal completions in 2017, with about 70% of those in the Midland Basin, and the rest in the Southern Delaware. We intend to spend between $1 billion and $1.15 billion this year, translating to annual production growth of around 70% at the midpoint of guidance.

We got a rolling start on 2017 growth, having added a rig in September, and we're now running 10 rigs dedicated to horizontal drilling activity. In light of the pending Double Eagle acquisition, we plan to add four more rigs by the end of the year. So we expect steady growth through the first half of the year, and then steepening growth in the back half of the year leading into 2018. In fact, we expect net production to average 75 to 85 MBoe per day in the fourth quarter of this year, which would be a 77% increase versus Q4 2016 at the midpoint. We're excited about that growth trajectory, and also about the character of that growth.

For several reasons, we expect 2017 production growth to be accompanied by expanding margins and healthy returns. For one thing, we're taking another step up in average lateral links, from around 7,400 feet last year to around 8,000 feet this year. Developing our Southern Delaware acreage with mineral rights should lead to higher average net revenue interest, translating to more revenue per dollar invested. We also expect an ongoing increase in oil as a percent of total production, which should translate to higher average realizations. The unit cost trends look favorable as well, following significant declines in 2016.

As you can see on slide 16, from a financial perspective, we're well-positioned to implement an accelerated growth plan. Pro forma for several recently announced transactions, we project to have more than $1.3 billion of liquidity, including more than $750 million cash on hand, and a fully undrawn revolver with a commitment of around $600 million.

Turning to our hedges on slide 17, we've been adding to our hedge portfolio since oil rallied on news of the OPEC cut. And we've added even more in light of our pending acquisition of Double Eagle. Based n on our guidance ranges for Q4 and for oil percentage, we're more than 80% hedged fourth quarter of this year. We built a strong position in 2018, and have extended into 2019 as well. We'll even assume a strong hedge book from Double Eagle upon closing. All this increases our ability to plan, lock in services and equipment at relatively favorable rates, and execute on our strong growth trajectory.

To conclude, 2017 is off to a great start, with an infusion of high-quality assets at attractive prices, and substantial momentum toward significant production and cash flow growth. With that, we would be happy to take your questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions)

Charles Meade, Johnson Rice.

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Charles Meade, Johnson Rice & Company - Analyst [2]

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Good morning, guys. Bryan, I wanted to go back to your prepared comments and get you to expand a little bit. I hadn't heard that phrase you used, talked about the acquisitions, where I think you said you pay for the net and the upside is in the gross. Can you elaborate on that, and help me understand what that means?

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Bryan Sheffield, Argus Research Company - CEO [3]

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Hey, Charles. A lot of it is pointed towards Double Eagle because of the average working interest -- let's say roughly, I think, 60% to 70% average working interest in the operated properties. And there's a lot of bolt-ons that need to be done, buying out working interests, increasing our net. Usually you can get cheaper buys from non-op working interest owners versus operated, versus let's say, 30,000 acres. And usually you can get non-authorized $15,000 an acre. That's what that comment was about.

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Charles Meade, Johnson Rice & Company - Analyst [4]

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Got it. So if I'm understanding you right, Bryan, it's like getting that working interest or the gross exposure is like a toehold to then being able to tack on those efficient net acres subsequently. Is that right?

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Bryan Sheffield, Argus Research Company - CEO [5]

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Yes, it provides tremendous opportunity and value.

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Charles Meade, Johnson Rice & Company - Analyst [6]

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Got it, thank you. And then if I could ask a question about the Wolfcamp C. Matt and/or Bryan, could you talk about what you saw when you were drilling this well, either in the vertical section, that made you choose this location, or what you saw on the lateral? And how the production that you've seen to date fits with what your pre-drill expectations were?

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Matt Gallagher, Parsley Energy Inc - COO [7]

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Yes, Charles. It's been a long lead effort by the team, something the geo guys have been very excited about for a few years now. Drilled a full core and pilot well, and had the full analysis of the data over a year ago. But then with a pullback, you obviously press pause on delineation wells. So it's been in the queue for a while and we've been excited about it.

All the technical data that we've amassed to this point kind of points to a good oil zone, the play fairway in Western Glasscock, Western Reagan. So it folds in nicely, I think, with all the recent acquisitions we've been active on. And in fact, 35% of the acres that we just picked up on the Double Eagle acquisition aligns right in this fairway. So we're real excited about this result.

Really, pre-drill expectations and the pressures we saw were very good. And then aligned with the completion and the pressures we saw, average treating pressures and [IS], IPs -- all looks very strong and encouraging, and is flowing through on the production results. In fact, yesterday was a 1,700 barrel oil rate; today, it's looking like it's going to traject towards a 1,900-barrel oil rate, which would be a Company oil record for a 24-hour period on a well. So we're real encouraged by the pressures and rates and oil cuts on this well -- well-over 70% on the oil cut side.

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Charles Meade, Johnson Rice & Company - Analyst [8]

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That's all great detail, Matt. And congratulations on this raft of rail results you guys offered. Thanks a lot.

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Bryan Sheffield, Argus Research Company - CEO [9]

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Thank you.

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Operator [10]

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(Operator Instructions)

Drew Venker, Morgan Stanley.

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Drew Venker, Morgan Stanley - Analyst [11]

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Good morning, everyone. I was hoping you could speak about the strategy around acquisitions and divestitures. Bryan, you had said in your prepared remarks that you're going to focus on your core, in entering into a digestion mode. Can you speak to more about what your appetite is, and what would make the cut for future acquisitions? And whether you're focused really on just, like you said, increasing your working interest in what you have? And maybe whether you're considering divesting some larger pieces of the portfolio?

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Bryan Sheffield, Argus Research Company - CEO [12]

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Yes, the digestion mode was a signal to tell you guys that I think we're pretty much done through 2017. We've done over $3.5 billion worth of acquisitions. And if you add the two Apache deals, plus Double Eagle, that's over 90,000 net acres, the majority of it being in the Midland Basin.

We have a lot of work to do. We have a six-month MSA, master service agreement, signed with the Double Eagle management team to help us continue to swap, trade, blocking and tackling. There are some non-op on the outer perimeter we need to swap out of or sell. But it's going to provide opportunity to core up in the center of the area.

I do believe that it's all basically all gone -- Double Eagle is basically one of the last crown jewels in the Midland Basin, and we had to take advantage of an opportunity before they ran the process. We're very excited about the deal.

There's probably a couple others. There's Felix, north of Jagged Peak, that's still there. That's run by EnCap. You can probably see that one go. And the two large private guys in Midland Basin are family-operated -- I'm thinking CrownQuest and Endeavor. You're probably going to see IPOs into 2017, going into 2018.

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Drew Venker, Morgan Stanley - Analyst [13]

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Okay, so Bryan, it sounds like more swapping and coring up versus actually tacking on larger additional packages. Is that right?

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Bryan Sheffield, Argus Research Company - CEO [14]

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Yes, the B group is dusting off their golf clubs for this year, so we're going to be focused on leasing and swap and trades.

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Drew Venker, Morgan Stanley - Analyst [15]

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Okay, thanks, Bryan.

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Operator [16]

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Dan McSpirit, BMO Capital Markets.

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Dan McSpirit, BMO Capital Markets - Analyst [17]

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Folks, good morning, and thank you for taking my questions. In your prepared remarks, you talked about seeing the first traces of cost inflation. I was hoping you could expand on that comment? And what is the expectation on the cost curve shifting away from the Company and the industry over the next 12 to 24 months?

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Matt Gallagher, Parsley Energy Inc - COO [18]

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Yes, that's rolled into our guidance and our budget for 2017. It's -- the canary is mostly on the completion side. I think that's common to the entire basin and most operators. But what we're seeing is on the order of 10% to 20%, depending on the area and the average treating pressures. And then when you roll that into the total well cost, we have a lot of our services and supplies locked in and committed. So it's only on the order of about 10% of what we feel in the entire delivered well cost throughout the end of the year.

And again, mostly on the completion side is where we are seeing a ratchet-up. And really, that's to reactivate crews and rigs, and they need that additional cost to break the crews back out, that frictional startup cost to break out additional crews.

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Dan McSpirit, BMO Capital Markets - Analyst [19]

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Okay, got it, thank you. And as a follow-up, on slide 6 of the presentation, you identify the area in the Midland Basin that screens best for factors like thermal maturity, thickness and pressure. What is the range of economic breakeven prices throughout the leasehold today, and how could that range tighten or change over time? And just as a follow-up to that question, how would you draw a similar boundary in the Delaware Basin, or is it too early to do so?

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Matt Gallagher, Parsley Energy Inc - COO [20]

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You know, we are extremely fortunate we have a very deep bench of high-returning inventory. On our reserve case, we would need to see sub-$30 oil before we reach economic thresholds that would impact it. And then within this outline, I think that's a good, call it, depending on -- we have basin-leading costs on the D&C side. But if you use basin-averages costs, I think that outline is in the 30% to 35% minimum rate-of-return hurdle, to get in that big black line.

If you're leading on cost, you can push those returns up. And that as you core-up into the sweet spots within that five-county outline, you can obviously push an IRR rates return between 60% and 90%. And yes, we have a look at the Delaware. First pass geology doesn't change one day to the next. So we have [petilar] maps in the Delaware, and our footprint is definitely inside of that line within the Delaware as well.

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Bryan Sheffield, Argus Research Company - CEO [21]

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I think one way to think about the Delaware on returns is, the closer you get to the oil window, the higher IRRs you're going to see, versus going West, a little bit more gassy.

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Dan McSpirit, BMO Capital Markets - Analyst [22]

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Got it, thank you. I appreciate it. Have a great day.

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Bryan Sheffield, Argus Research Company - CEO [23]

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Thank you.

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Operator [24]

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Neal Dingmann, SunTrust Robinson Humphrey.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [25]

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Good morning, gentlemen. Looking at that slide 23, on the Double Eagle acquisition, you obviously talked about the Taylor. Fantastic result there, guys. Just wondering your comments that you would suggest about maybe some additional lower Spraberry in the area? What do you think the potential, especially in that part of Reagan? Or the other way to ask that is, given the tremendous result you had on the Wolfcamp B on the Taylor well, will you continue with that in that area?

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Matt Gallagher, Parsley Energy Inc - COO [26]

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Yes, it screens out very well, our Dusek result, the competing returns, because of the lower costs on the Spraberry. The comment on the acquisition on the Spraberry is adding, if you look on slide 24 and 25, is adding in heavily drilled Spraberry areas as well, where there are already extremely high, proven, repeatable well results. So it's good across the board. In this particular area, the Wolfcamp B on slide 23, is the most proven to date.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [27]

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Got it. And --

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Bryan Sheffield, Argus Research Company - CEO [28]

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I want to comment. I think the area you haven't seen a lot of Spraberry wells is -- it's all HBP and held by Pioneer Natural Resources. They're large units that touch all this. And these acquisitions that we've bought over the past two years kind of blocking up West Reagan has all been HBP acreage as well. So it's all legacy titles, where operators aren't rushing to hold the leases. And that's why you've seen the slow [process hitting] the other [businesses].

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [29]

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Great color, Bryan. And then Bryan, for you or Matt -- once you add the additional rigs now post this acquisition, I mean, you guys are right up there among the most active with all the bigger players in the Perm. How do you think about first, service costs? We've heard a few peers on the conference calls mention about trying to lock in some of their D&C for the remainder of this year, into next year.

Again, certainly now that you've got the economies of scale and you guys are one of the more well-known of the area, does that give you the ability to do that? Or maybe just any color you can add about locking things in right now versus for the rest of the year?

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Matt Gallagher, Parsley Energy Inc - COO [30]

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You're absolutely right, you need to be in a sweet spot of activity level in this. What we've seen over the past two years is that we are in that level. We're an operator of choice for the vendor network. And then it's all about transparency -- our supply chain management group and procurement group forecasting out, being good partners with our vendors, telegraphing to them how much sand demand we're going to have the third week of November.

And we know all these things based on our projections. We might as well share them with our preferred vendor network, and help them on their supply-chain side. And that's helping alignment. That's the best way to control costs right there. And we've had a lot of success with that in the past, and we plan on doing that in the future as well.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [31]

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Great, thanks guys.

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Matt Gallagher, Parsley Energy Inc - COO [32]

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Thank you.

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Operator [33]

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Scott Hanold, RBC Capital Markets.

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Scott Hanold, RBC Capital Markets - Analyst [34]

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Thanks, good morning. You discussed some of the wells that you have in your reserve, in your report, that are between 1.5 million and 2 million barrels. Can you do two things, one, discuss what the average EUR on your -- I don't know if it's relevant just to look at -- your 26 program is in your reserve reporting. And could you also give us some context of where those larger wells were located? And the rationale why those are so big?

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Matt Gallagher, Parsley Energy Inc - COO [35]

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Yes, I think on order of magnitude, it's in North Upton, is where the largest wells are, on absolute EURs. So that's just been based on the deposition in the basin. And that's been, from the beginning, the highest absolute productive area. So those are where the larger wells are.

And then as we extend lateral lengths, of course. In Reagan, drilled multiple 10,000-foot-plus lateral lengths. We're seeing close to that on the EUR across the rest of our portfolio. So don't have the exact -- we don't disclose the exact average of 2016. But it's increasing year over year in a positive manner.

And the PDP EURs are much higher than what we pencil in, and what's audited for a PUD, until we get them online. So we always have -- we had positive revisions this year, all stemming from PDP performance. So we expect that to continue in the future.

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Scott Hanold, RBC Capital Markets - Analyst [36]

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Okay, appreciate that. And as my follow-up, obviously you talked about the momentum you have building through 2017 into 2018. Can you give us a little bit of color on what 2018 is shaping up like? Do you sense, is it still a year where you're going to spend to accelerate the opportunity? Or when do you think you could cross the gap of bridging free cash flow-neutral?

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Matt Gallagher, Parsley Energy Inc - COO [37]

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Good question. I mean, essentially, we're keenly focused on returns. We have some of the highest returns in the country, and a deep bench of inventory to affect them. So we are a growth Company right now. And you could attack it two different ways. You could get to cash flow-neutral by reducing activity, or you can actually get there in the long term by accelerating activity. So our outspend drops dramatically year over year. And we are on a trajectory eventually towards free cash flow, with a tremendous production growth along the way.

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Ryan Dalton, Parsley Energy Inc - CFO [38]

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This is Ryan. I'll just add to that. We're always focused on leveraging liquidity. So to the extent that we are out-spending cash flow, we're going to do so such that it doesn't impact the balance sheet at all.

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Scott Hanold, RBC Capital Markets - Analyst [39]

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Understood. Appreciate it, thanks.

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Bryan Sheffield, Argus Research Company - CEO [40]

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Thank you.

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Operator [41]

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Irene Haas, Wunderlich Securities.

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Irene Haas, Wunderlich Securities - Analyst [42]

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Yes, hey, good morning. My question has to do with Delaware Basin. I noticed that you have some inventories on the Bone Spring intervals too. My question is, when would you drill that? And is it going to be this year? And how many stack pays do you expect from that part of the Delaware Basin? Understanding that the pipes are good for oil and gas, how is the water handling in this part of the neighborhood?

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Matt Gallagher, Parsley Energy Inc - COO [43]

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We do have a couple of Bone Spring delineation wells as part of our delineation budget, in the back part of 2017, being spud on the back part of 2017. And we have an operated set of SWDs that has plenty of capacity for 2017, so we feel that we can handle our water in 2017. There will be ongoing build-out in ratio to the program activity throughout 2018.

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Bryan Sheffield, Argus Research Company - CEO [44]

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We're very fortunate at the surface, that we own over 30,000 acres of surface. And we're close to the platform, so we feel like we can maneuver on the waterfront.

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Irene Haas, Wunderlich Securities - Analyst [45]

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This is great. And in the Bone Springs horizons, are you after the sand or the shale? Is it second or third?

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Matt Gallagher, Parsley Energy Inc - COO [46]

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We will be testing a third and a second in the shale.

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Irene Haas, Wunderlich Securities - Analyst [47]

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Great. Thank you so much.

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Operator [48]

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Michael Glick, JPMorgan.

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Michael Glick, JPMorgan - Analyst [49]

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Just a question on the Wolfcamp C. Was there a well drilled on a unit that already had Wolfcamp B production? And if not, do you see any risk regarding interference between the two benches?

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Matt Gallagher, Parsley Energy Inc - COO [50]

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Zero risk of interference. We are 580 feet deeper than our Wolfcamp B landing in the area. We do have Wolfcamp B wells on the Taylor lease, very prolific wells also. Zero interaction between the production on those wells and this well. The Wolfcamp C complex alone in this area is 700 feet thick, which is essentially double the A/B complex. So again, we're 580 feet deeper than our Wolfcamp B. It is its own oil fingerprint and its own zone.

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Michael Glick, JPMorgan - Analyst [51]

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Got it. And then more broadly -- and I guess you need more production history here -- but how do you see the Wolfcamp C, and the lower Spraberry as well, fitting into your long-term development plan? And to ask the question in a different way, when do you think you'll have nailed down your ultimate development plan and associated pad design in the Midland Basin?

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Matt Gallagher, Parsley Energy Inc - COO [52]

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We have a lot to tackle. It's a good problem to have, with this many productive, high-quality benches, high rate-of-return benches as we do have. I'd say we're probably, depending on the results of our high-density Wolfcamp B pad that comes on midyear, we're probably honing in on ideal spacing with the Bs.

But were probably overall in the portfolio still third, fourth inning on ideal spacing across all of these. So we're planning long term on our surface development to handle, as I mentioned in previous calls, 60-plus wells per development unit. And this just adds another bench on top of that, that we can attack. And then it all folds in, rateably increasing activity to pull the value forward from our own footprint.

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Michael Glick, JPMorgan - Analyst [53]

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Got you. Thanks, guys.

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Operator [54]

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Jeff Grampp, Northland Capital Markets.

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Jeff Grampp, Northland Capital Markets - Analyst [55]

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Good morning, guys. Sticking on the C bench result here and the prospectivity of that target across the basin. Matt, I think you mentioned you guys have mapped a sweet spot or fairway in the West Glasscock, West Reagan area. And just wondering, when we look at your inventory, I think, pro forma, you guys are at 900 or so locations in the seed. Do you have a sense of how many of those locations are within that identified fairway?

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Matt Gallagher, Parsley Energy Inc - COO [56]

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I'll tell you, at least probably around three quarters of the seed identified as in that sweet spot fairway.

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Bryan Sheffield, Argus Research Company - CEO [57]

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We don't have Howard or Martin on the seed.

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Jeff Grampp, Northland Capital Markets - Analyst [58]

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Okay, perfect, thanks. And for a follow-up, I find it real interesting on, Bryan, to your comments on netting up your gross. And it seems like every quarter, your average working interest is trending up. So just curious, is that really a function of you guys maybe aggregating those non-op interests, or even front-loading the higher working-interest wells?

Just trying to get a sense for, when you guys first are AFEing these wells, are you guys at 80 -- for number's sake -- and your bolting up into those high 90s? Just trying to get a sense for how that range changes as you guys move forward in the development program?

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Bryan Sheffield, Argus Research Company - CEO [59]

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You know, it's a mixed bag. It's funny that the drill bit -- when you AFE, the drill bit motivates other non-op working elements to sell, or motivates JOA. It happens always on-the-fly, so it's hard to put a thumb to it. But we are also -- those same guys sometimes win a trade or swap out of it, and a lot of them are competitors.

And a lot of them are old mom-and-pop, non-op operators that have their own properties. So you can keep on going down the line. It's just a different makeup of each time we drill a well. But we are always focused on higher working-interest properties as we move the rigs.

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Matt Gallagher, Parsley Energy Inc - COO [60]

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Our legacy horizontal inventory was 90% working interest. And then as we acquired Double Eagle, around 70%. So those are the types of deltas that come at you as you put the bit in the ground. And as Bryan mentioned, we can aggregate additional working interest.

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Jeff Grampp, Northland Capital Markets - Analyst [61]

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Okay, perfect. Appreciate the time, guys.

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Bryan Sheffield, Argus Research Company - CEO [62]

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Thank you.

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Operator [63]

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John Freeman, Raymond James.

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John Freeman, Raymond James - Analyst [64]

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Good morning, guys.

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Bryan Sheffield, Argus Research Company - CEO [65]

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Good morning.

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John Freeman, Raymond James - Analyst [66]

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Last quarter, the big news was on the grace pad, when you did the Upper-, Lower-B stack test. Can you give me an update on the timing on the Upper-, Lower-A stagger test that you all contemplated doing?

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Matt Gallagher, Parsley Energy Inc - COO [67]

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Yes, it's online, still early and looking really good. That's out in Eastern Reagan, and more positive news on that front. So stacking in line -- we think that these multiple stacks zones are the optimal way to go. So we'll see more of that going forward.

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Bryan Sheffield, Argus Research Company - CEO [68]

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Were you asking about AA?

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John Freeman, Raymond James - Analyst [69]

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Yes, well, the Upper-, Lower-A stagger test that you all were contemplating, to see if basically, like the B, you've got these two sections?

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Matt Gallagher, Parsley Energy Inc - COO [70]

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I'm sorry, I thought you were asking about more stacked ABs. Yes, the Upper-, Lower-A comes on midyear.

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John Freeman, Raymond James - Analyst [71]

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Midyear, okay. And then my follow-up question -- when I look at just the massive out-performance you've got on these Reeves County wells, and then you still have the continued out-performance on Midland side. When I look at the production guidance, is that supposed to be indicative of leading-edge, or more indicative of that 1 million curve you've all been showing for months, even though you are doing well-above it?

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Matt Gallagher, Parsley Energy Inc - COO [72]

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Coming into 2017, we have about 20% of our capital, to 30%, if you count the down-spacing on the delineation project. So there's a risk factor coming into that, applied on our forecast. And we hope that it outperforms, such as this Taylor well obviously outperforming baseline placeholder in the budget. We have 20% to 30% of the capital is risked on the production forecast.

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John Freeman, Raymond James - Analyst [73]

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Great, thanks, guys. Appreciate it.

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Bryan Sheffield, Argus Research Company - CEO [74]

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Thank you.

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Operator [75]

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Michael Hall, Heikkinen Advisors.

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Michael Hall, Heikkinen Advisors - Analyst [76]

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Thanks, good morning. Just wanted to revisit the conversation around how you ultimately think about developing units, how you think about the importance of co-developing up and down the hydrocarbon column at the same time. And the importance of developing out a lease all at once, or a unit all at once, as opposed to having a single well come through. What sort of degradation do you think you might see as you do a full development versus a single one on the unit?

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Matt Gallagher, Parsley Energy Inc - COO [77]

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Yes, that's exactly what we're solving for in our super pad. We've had the full, developed 660s, with the offsets on either side, for a long time now. But now what we're trying to push is the sequencing and the density down to 330 feet between wells, and enter a B. So really, where it only matters is, zones that are within the same flow unit.

And we do continue to see stress shadowing and benefits between the A and the B, when you put on these stack pads. We don't see necessarily hydraulic communication, but we do see interference on the frac complexity. So it's resulting in positive production.

But we do not expect when we drill this eight-well down-space pad, for them all to meet the parent type curve. We risk each well down about 25%, and we expect that. But then when you look at the NPV per section, you see a massive uplift. So it is additive to NPV.

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Bryan Sheffield, Argus Research Company - CEO [78]

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And we just added a potential new component. We might consider drilling a Wolfcamp A, BB, and a C -- you know, those kind of formations.

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Michael Hall, Heikkinen Advisors - Analyst [79]

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And how much vertical distance -- follow up on that -- how much vertical distance do you think is required to avoid communicating between zones? I mean, you talk about Wolfcamp AB stacked getting some benefits from each other. But like with the C being as far down as it is, what's the threshold there as it relates to how much vertical distance you need, do you think?

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Matt Gallagher, Parsley Energy Inc - COO [80]

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Good question. We don't expect any stress shadowing benefits from the C. It's far enough away. We like about 250 to 300 feet between targets. In between that, you see actual hydraulic communication, where you might be accelerating the same rock.

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Michael Hall, Heikkinen Advisors - Analyst [81]

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Okay, that's helpful. And then last, on my end -- you alluded to the max rig count that you guys talked about earlier of 25 rigs. And that, over time, could trend higher with infrastructure and organizational capacity. Is there a benchmark rule of thumb you guys think about as it relates to what sort of limits there would be to efficient development on, say, a 10,000-acre block? We're trying to come up with (multiple speakers)

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Matt Gallagher, Parsley Energy Inc - COO [82]

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We go by area, and we work by the constraining point of water supply, water disposal. And then you would look at electrical grid capacity, and you work inside-out to drill that. I mean, theoretically with these benches that Bryan mentioned, an A, a B, and a C in the Lower Spraberry, you could have four rigs back-to-back-to-back. But what's going to limit you is how much water you can prepare for the frac.

So in some areas, as you build out that infrastructure, if you want to build for that, you could be extremely dense on a 10,000-acre unit. But right now, as we go by our entire footprint, we have the capacity essentially today, in that water sourcing and disposal, to handle 25 rigs.

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Michael Hall, Heikkinen Advisors - Analyst [83]

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That's helpful color. Appreciate it, guys.

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Bryan Sheffield, Argus Research Company - CEO [84]

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Take care.

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Operator [85]

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Sam Burwell, Canaccord Genuity.

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Sam Burwell, Canaccord Genuity - Analyst [86]

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Good morning, guys. I wanted to touch on some things out in the Delaware. Obviously the results you guys put up in Reeves were spectacular. But I wanted to get a sense of your plans for Pecos, given that you got the full benefit of the mineral rights out there. Just curious if we should expect some kind of delineation results as you move southeast in the coming quarters?

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Matt Gallagher, Parsley Energy Inc - COO [87]

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Absolutely. So about 35% of our total D&C is focused on Delaware Basin this year. And of that, two-thirds is going to Pecos. So throughout 2017, you'll see development -- I'm sure the permits will start hitting here shortly that can be mapped out. But it goes from the northwest to the southeast. And we've always said we're just building that out on our electrical grid from the northwest to the southeast of our ranch there.

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Sam Burwell, Canaccord Genuity - Analyst [88]

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Okay, got it. And then switching gears a little bit, on the LOE side, certainly impressive. You guys got it down to almost 350 per Boe this quarter. Looking at the 2017 guidance, some kind of uptick is baked in. Understand you guys may want to be conservative with respect to guidance. But still, I just wanted to or see whether you guys were incorporating either a higher LOE because of more Delaware production being layered in, or if you guys are factoring any inflation in operating costs?

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Matt Gallagher, Parsley Energy Inc - COO [89]

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The main component there, Sam, is digesting these around 400-plus vertical wells from other operators, getting them up to Parsley specs, and working them over properly from our recent acquisitions. So there's a lot of unknowns there, and we think we definitely captured that within the guidance range.

And then secondary to that, as you mentioned, is a larger component of our CapEx going to Delaware. And we do see about double the water rates over there, three-to-one, or four-to-one per barrel compared to two-to-one on the Midland side. That's just a mathematical component that increases the LOE. But the main driver on that guide up is digesting these vertical wells.

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Bryan Sheffield, Argus Research Company - CEO [90]

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Which is pulling [in] and driven -- broad parts, [tumen] leaks, remedial squeezes.

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Sam Burwell, Canaccord Genuity - Analyst [91]

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Okay, makes sense. Thanks, guys.

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Bryan Sheffield, Argus Research Company - CEO [92]

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Thank you.

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Operator [93]

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Gail Nicholson, KLR Group.

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Gail Nicholson, KLR Group - Analyst [94]

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Good morning. Are you still using brown and white sand, depending on the area that your drilling in, or have you transitioned to one type of sand?

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Matt Gallagher, Parsley Energy Inc - COO [95]

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Hi, Gail. Yes, still the majority of Upton County, due to the depth, is white sand. Reagan County, Glasscock County, Howard, it will be brown sand. We use white on our Wolfcamp C well. Again, it's 580 feet deeper. And then all white over in Delaware. We've had a positive test using brown in Upton, but it's not the main piece of our program in the current budget.

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Gail Nicholson, KLR Group - Analyst [96]

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Okay, great. And then looking at the [tin] outlook, Spraberry and that shallow decline, is that two-mile shallow decline similar to the one-mile that you did, which also exhibited a shallower decliner? Or is the two-mile actually declining at a shallower rate than the one-mile?

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Matt Gallagher, Parsley Energy Inc - COO [97]

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The two-mile is almost completely flat, but the one-miler had a very low decline as well. It had lower IP, but pretty low decline. But this one is very flat. It had a different completion and well bore design throughout. There's some different things on our first well that -- the one-miler -- that we're kind of restricting some things.

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Gail Nicholson, KLR Group - Analyst [98]

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Okay, great. Thank you.

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Operator [99]

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John Nelson, Goldman Sachs.

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John Nelson, Goldman Sachs - Analyst [100]

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Good morning. Congrats on Double Eagle, and thank you for taking my questions.

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Bryan Sheffield, Argus Research Company - CEO [101]

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Good morning, John.

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John Nelson, Goldman Sachs - Analyst [102]

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Bryan, if the upside is in the gross, I'm just curious how soon investors could potentially see that upside? And so my question is, is there a lot of low-hanging fruit with regards to trades, that we should be looking for some core inventory expansion by year-end 2017? Or do those sorts of talks or negotiations take a little bit longer, and it's hard to predict it coming in the next six to 12 months?

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Bryan Sheffield, Argus Research Company - CEO [103]

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You know, it comes in waves from our land group. For one quarter, you don't see much, and then in another quarter, you see a lot coming through. But fortunately, the Double Eagle team, they are a machine -- they are in every operator's office, it seems like, all week, every week. And it's amazing how they can get in the doors of these larger companies. So we're going to lean on them as much as we can, because they have this machine going, and we want the machine to keep on moving.

And there's a lot of swaps being discussed right now. Especially during May, I think we met with five or six different operators. So it's hard to put a finger on it. It's going to come in waves. It could come in within the next few months, it could come in by the end of the year. But it just depends on how fast the other operators want to move.

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Matt Gallagher, Parsley Energy Inc - COO [104]

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They've already completed -- the week after signing, they completed 1,000 acres of folding in, as we call it, that's not reflected on the map.

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John Nelson, Goldman Sachs - Analyst [105]

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Okay, that's helpful. And then my second question. Medallion had to December press release mentioning you all as an anchor tenant on their Pecos-to-Crane pipeline. I'm just curious what level of capacity you all took down, and if you could tell us the tariff level?

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Matt Gallagher, Parsley Energy Inc - COO [106]

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We can't disclose the tariff levels, but being that anchor tenant and then tying into our footprint in our Reagan and Upton area, it's very favorable to us, we believe. And I think it was a win-win for both sides, getting their extension over to the Delaware Basin. And they're required to take all of our barrels on the footprint committed, and we've shared a projected forecast with them, and they're building out for that.

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John Nelson, Goldman Sachs - Analyst [107]

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Oh, so it was just an acreage dedication and not a set [NBC]?

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Matt Gallagher, Parsley Energy Inc - COO [108]

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That's right.

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John Nelson, Goldman Sachs - Analyst [109]

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Okay. And just on the tariff, is the way we should think about realizations for the Delaware Basin -- do you expect those to be materially different from how you've been trending thus far?

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Matt Gallagher, Parsley Energy Inc - COO [110]

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Yes, trucking in the Delaware is on the order of $2 a barrel, and it's much more favorable than that.

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John Nelson, Goldman Sachs - Analyst [111]

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So Delaware Basin oil realizations will actually improve the corporate level, as that total volume -- as the Delaware mix grows, is that what you're saying?

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Matt Gallagher, Parsley Energy Inc - COO [112]

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Yes.

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John Nelson, Goldman Sachs - Analyst [113]

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Okay, perfect. Thanks so much. I will let somebody else hop on.

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Bryan Sheffield, Argus Research Company - CEO [114]

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Take care.

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Operator [115]

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Jeff Robertson, Barclays.

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Jeff Robertson, Barclays Capital - Analyst [116]

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Thank you. Bryan, just a question on how you think about capital efficiency going into 2018, with the combination of longer laterals and whatever you're seeing in service cost inflation? Can you talk about where you think that direction is headed?

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Bryan Sheffield, Argus Research Company - CEO [117]

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Well, our program is already in place. And you can look at one of the first slides, where we had some serious [for] going in the fourth quarter, on the production growth. I don't see it changing much on lateraling going into 2018. And the same amount of working interest decides the swap and trade, so you should see an increase there. I don't see much changing with our momentum going into 2018. I would just use the same model that you used in the back half of 2017.

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Jeff Robertson, Barclays Capital - Analyst [118]

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Do you see cost having much of an impact on where you think that will be in 2018, or can you (multiple speakers)

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Bryan Sheffield, Argus Research Company - CEO [119]

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I think it was baked in like 10% to 15% cost inflation for 2017. Now if oil does move up to the $55, $60 range, yes. But I don't see it if we're just sitting in this range from $50 to $54. If we're just sitting here, I don't see another leg up in service costs. It depends on the commodity prices.

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Jeff Robertson, Barclays Capital - Analyst [120]

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Okay, thanks Bryan.

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Bryan Sheffield, Argus Research Company - CEO [121]

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Yes.

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Operator [122]

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David Tameron, Wells Fargo.

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David Tameron, Wells Fargo Securities - Analyst [123]

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Yes, if I could just go back to the development question. And Matt, I think you said third to fourth inning. But if we think out to, whatever, 2019 or 2020, even back half of next year, do you anticipate you starting to be in that optimization, as far as the development mode goes?

I mean, when do you think you get there where you can comfortably say: hey, this is -- I guess you never fully get there. But get close enough where you could say: hey, this is the way we are going to develop the section, we're going to put this many wells in. When do you think you could get to that point?

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Matt Gallagher, Parsley Energy Inc - COO [124]

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Well, we're trying as fast as we can, but when you deal with eight-well pads -- the green-light decision on the eight-well super-pad was April 21 of last year. It's not coming online -- after you go through the planning process and then the actual spud, which was late last year -- not coming online until mid this year. And then you like to see 90 days of production to really change your port. So you're looking at one-year cycle times to change full development behavior. That's what we're up against.

We think we're almost there on the B. We're just taking off with that process on the A, getting into the AAs, then we have just drilled a C. And very early on in our development on the Spraberry. Although we can definitely lean on industry development to get to the right spacing on the Spraberry. So that's driving all that timing. And hopefully, by the 2019 timeframe, you back into -- back of 2019, 2020, like you said, should be pretty close to be on full-scale.

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David Tameron, Wells Fargo Securities - Analyst [125]

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All right. And then just have one follow-up. Do you care what mix you are using, as far as the sand goes? Do you care if it's 20/40, 30/50, 40/70? Do you see a noticeable difference when you complete these wells?

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Matt Gallagher, Parsley Energy Inc - COO [126]

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We actually have not seen a noticeable difference in production, but we see a noticeable difference in treating and the ability to get the sand away. It's just easier the smaller grain size you use. Convention would tell you that a larger grain size has more conductivity, but it's easier to get the smaller grain size put away. We're primarily 40/70. We don't use much 100-mesh. A lot of other industry using 100-mesh. So it's a mix between those that is mostly favorable in the basin right now.

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David Tameron, Wells Fargo Securities - Analyst [127]

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Okay, so logistically, it's easier, but not necessarily -- you're not seeing it in the well performance. Is that --?

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Matt Gallagher, Parsley Energy Inc - COO [128]

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(Multiple speakers) Yes.

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David Tameron, Wells Fargo Securities - Analyst [129]

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Okay, all right, thanks.

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Bryan Sheffield, Argus Research Company - CEO [130]

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Thank you.

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Operator [131]

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Chris Stevens, KeyBanc Capital Markets.

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Chris Stevens, KeyBanc Capital Markets - Analyst [132]

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Hey, guys, just a quick one on the Lower Spraberry. How much of your inventory do you believe has been de-risked for the Lower Spraberry, in terms of how much do you believe can actually perform in line or better than that Dusek well at this point?

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Matt Gallagher, Parsley Energy Inc - COO [133]

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I think that Dusek well is very representative of maybe even the bottom edge of our inventory. As we go north, it gets into more delineated, due to industry offset Spraberry results. So I think you're looking at 80%-plus very comfortably.

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Chris Stevens, KeyBanc Capital Markets - Analyst [134]

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All right, thanks a lot, guys.

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Matt Gallagher, Parsley Energy Inc - COO [135]

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Thanks, Chris.

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Bryan Sheffield, Argus Research Company - CEO [136]

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Thank you.

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Operator [137]

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Thank you. Ladies and gentlemen, that does conclude our question-and-answer session. And with that, today's conference has been concluded. We thank you for your participation. And you may disconnect your lines at this time. Have a wonderful day.