Industrias Peñoles, S.A.B. de C.V.

Thank you, operator. Good morning, everyone.

With me this morning are Parsley's CEO, Bryan Sheffield; COO, Matt Gallagher; and CFO, Ryan Dalton. During this call, we will refer to an Investor presentation that can be found on our website and our remarks may contain forward-looking statements, so we refer you to our earning release for discussion of these statements and associated risks including the fact that actual results may differ materially from our expectations.

We also make reference to non-GAAP measures, so please see the reconciliations in our earnings release. After our prepared remarks, we'll be happy to take your questions.

And with that, I'll turn the call over Bryan.

Thanks, Brad. Parsley Energy is off to a fast start in 2017, setting the stage for a year of stellar execution.

As you can see on slide 3, this quarter, we grew production by 21%, or almost 10,000 barrels a day compared to last quarter. And as you can see from our estimated production in the fourth quarter of this year, there's a lot more growth on the horizon.

We're raising both our fourth quarter production guidance and our full-year production guidance. Full year net production moves from a range of 62,000 Boe per day to 68,000 Boe per day to a range of 65,000 Boe per day to 71,000 Boe per day.

And Q4, increases from a range of 75,000 Boe per day to 85,000 Boe per day to a range of 78,000 Boe per day to 88,000 Boe per day. At the midpoint, this translates the year-over-year production growth of 78% and even higher fourth quarter to fourth quarter growth of 84%.

For a good while, we've been promising that our growth would be characterized by improving margins and healthy returns. As you can see on slide 4, we're extracting a lot of value from each unit of production.

Our cash margin has been increasing on both an absolute and a percentage basis, driven by oilier mix and lower unit cost. In fact, our cash margin in Q1 is almost 50% higher than it was in the second quarter 2015 despite the fact that oil prices were almost $60 at that time.

The chart in the upper right shows that we continue to set the standard on lifting costs, which is a testament to our excellent field operations and also a function of ample and scalable infrastructure in place. The key to our superior production growth is straightforward.

We drill and complete excellent wells across our acreage portfolio, and well productivity is getting even stronger over time. The chart on the left side of slide 5 shows that both our Midland Basin and our Southern Delaware wells are outpacing our 1 million Boe reference curve.

Even our earlier vintage wells at the far right are holding strong relative to the curve, and these wells were completed with less intensive frac jobs. What's really encouraging is that we're showing stronger scale IP rates each period.

And in fact, as you can see on the chart in the upper right corner, normalized IPs have strengthened at the same time that we've increased laterally. Typically, there is a trade-off between lateral length and initial production per 1,000 feet because of flow back constraints among other things.

But we're actually seeing a parallel increase in lateral lengths and scale IPs. Turning to slide 6, we closed the Double Eagle acquisition a couple of weeks ago and we're very excited to bring these assets into the fold.

High grading efforts are well underway and we've already added substantial value. In fact, we've already executed no cost acreage trades that has moved us out of some low working interest non-operated tracts into some premium operated blocks.

These trades have delivered around 155 net horizontal drilling locations with an average lateral length of approximately 7,000 feet. They also extend to another 70 net horizontal drilling locations by an average of approximately 4,000 feet.

Net of what we traded away, these trades added more than 900,000 net lateral feet to our drilling inventory which is equivalent to adding more than 3,000 premium acres without spending a dollar. We've talked about digestion period as we integrate and develop new assets and we continue to expect that for the time being we're on the sidelines when it comes to sizeable acquisitions.

But digestion is an active process as we shape an already superior acreage portfolio into an even more concentrated and valuable position. With more trades on the horizon, strong returns on our growing production and lots of exciting well results in store, we're excited to walk forward through the rest of the year.

With that, I'll hand off to Matt for more detail on our operations.

Thanks, Bryan. Major acquisitions take a lot of an organization's time and energy, and our recent acquisitions are no exception.

I think it says a lot about Parsley's ability to execute that we delivered outstanding operational results during a period in which we were waist-deep in significant transactions, a testament to our operational capacity and our team's efforts. Regarding Double Eagle, the thing we're most excited about is the quality of the acreage, and we've already started to see that play out.

As you can see on slide 7, initial results on acquired acreage in Southeast Martin County, a new area for us, are outstanding. This three-well pad targeted three discrete zones, the Lower Spraberry, Wolfcamp A and Wolfcamp B, and each is performing very well.

Each of the wells is tracking above 1,300 Boe per day and, together, the three wells have produced more than 100,000 Boe during the first 30 days-plus of production. With 1.5-mile laterals and 100% working interest, this pad is typical of the projects we're going to be executing on the acquired assets.

As always, we're striving to increase the concentration and working interest of our acreage, but there are hundreds and hundreds of high working interest operating locations ready to go. Through the end of the year, we anticipate around 10 multi-well pads across 4 counties on acreage acquired from Double Eagle.

We believe in the quality of what we have acquired, and we look forward to strong results from these projects. One of the reasons we're really excited about Double Eagle is that it adds meaningfully to our Lower Spraberry portfolio.

The Lower Spraberry well on the Strain Ranch pad in Martin County is the latest in a series of strong and strengthening Lower Spraberry wells that spans much of our Midland Basin acreage. The chart on slide 8 shows that the Lower Spraberry well we drilled on our Dusek lease in North Upton County recently surpassed the 1 million barrel curve.

And, more recently, drilled Spraberry well in Glasscock is tracking ahead of the Dusek so far, and the Spraberry well in Martin County is off to a faster start than both of those. We feel really good about our Lower Spraberry results, and with 1,500 gross locations, we intend for it to be a big part of our drilling program.

Currently, we have close to 30 Lower Spraberry wells on the schedule for the next 12 months. Turning to slide 9.

While our success in the Lower Spraberry follows that of other operators in certain parts of the basin, our initial Wolfcamp C well is a groundbreaking success. The Taylor well in Reagan County has been on production for 60-plus days at this point, and not only is it our most impressive well to-date, it's among the strongest wells ever completed in the Midland Basin.

The well is so strong that it's like getting two wells for the price of one. At the 60-day mark, its cumulative production is almost double that implied by the million-barrel-type curve.

In less than 70 days, it has generated 115,000 barrels of oil and lots of gas as well, which puts it on track for a payout in roughly six months, even including customarily higher first-well cost. And the GOR has been pretty stable in the 2,000 to 2,500 range, which is lower than might be expected.

Wolfcamp C's productivity is a very pleasant surprise, but by no means an accident. Our geoscience team has been beating the drum for a couple of years now, and I think the favorable results speak well of our delineation processes, the same processes that have yielded good outcomes in the Southern Delaware as well.

We actually picked initial Wolfcamp C landing targets and well spots in 2014. In 2015, we drilled a pilot well on our Taylor lease.

In early 2016, after conducting log and core analysis, the team proposed a Wolfcamp C well on the Taylor lease. Later, in 2016, amidst the oil price pullback, information obtained in data trades helped us calibrate our drilling and completion plan for the well.

And, finally, in January of this year, we drilled the Taylor well. Informed by two years of advance work, we approached our first Wolfcamp C well with a good degree of precision, and the outcome is as good as it could be hoped for and a real credit to our technical and operational teams.

When compared to previous Wolfcamp C wells in the Midland Basin, we targeted a different part of the formation and utilized a different completion design as well with higher proppant loading and slickwater instead of gel among other differences. The exciting thing is that we have abundant acreage in what we consider the Wolfcamp C fairway.

We identified this fairway by cross-referencing several reservoir properties, including abundant oil in place, ample thickness, optimal thermal maturity and high reservoir pressure that is closer to what you typically see in the Delaware Basin than in the Midland Basin. If you look at our last several acquisitions, they have largely been concentrated in this fairway.

And if our subsequent Wolfcamp C wells are even half as strong as our initial well, we will have captured tremendous value by acquiring acreage in this fairway. Since the first well was so prolific, we're pulling forward a handful of Wolfcamp C wells into our drilling program this year.

We'll radiate outward from the initial well to evaluate the areal extent of the play. Later, we'll assess the potential for multiple flow units within the Wolfcamp C complex.

Certainly, there is plenty of thickness to support that possibility. Turning to slide 10 on the Delaware side, we continue to believe that our Pecos County acreage is among the most desirable positions in the basin.

All of our Trees Ranch wells rank among our 20 most productive wells in terms of cumulative oil production at 180 days. We're setting the pace on lateral lengths in the Southern Delaware and, like on the Midland side, as we've increased lateral length from the 1 mile to 1.5 mile to 2 miles, production per 1,000 feet has held steady, which is very encouraging.

Also encouraging is that at the 180-day mark, oil cuts on our Trees Ranch well are north of 80%, this is good quality pipeline spec oil too, which is in short supply in the Southern Delaware and which we think is going to become a differentiated driver of pricing over time. We've done more analysis on the Wolfcamp formation on our Trees Ranch acreage and are feeling good about three flow units within the broader complex.

We're currently flowing back two wells targeting discrete flow units in the upper Wolfcamp in a staggered configuration with around 330 feet of lateral separation. We're also completing a well that targets what we might think of as the middle Wolfcamp.

So, a lot of noteworthy data upcoming and in the meantime, our existing wells are very productive and making lots of oil. A quick note on our Wolfcamp development on the Midland side; a couple of quarters ago, we added a second Wolfcamp B target to our inventory prompted by strong well results in both the upper and lower Wolfcamp B landing zones.

The next step is to evaluate lateral spacing and we're getting closer on some initial data on that front. In the next few weeks, we'll bring online an 8-well pad consisting of four wells in the upper Wolfcamp B and four wells in the lower Wolfcamp B essentially stacked with 330 feet of lateral spacing between each well.

We're also underway with a test of multiple flow units in the Wolfcamp A target. We have a lot of Wolfcamp thickness to work with in both the Midland and Southern Delaware basins and we're excited to see how much more resource we can extract.

Looking ahead, we feel good about our ability to execute moving forward. After inheriting a rig from Double Eagle at closing, we're basically planning to add a rig per quarter through the end of the year.

Equipment is secured for this ramp. These rigs are going to the Midland Basin where we and others have an extended track record and abundant infrastructure in place.

In the Delaware, we've said it before that we have multi-year head start on newer entrants and having surface ownership on much of our Southern Delaware acreage really does make a big difference in streamlining development and managing cost. So, we think a strong first quarter is indicative of what we will deliver the rest of the year and beyond.

On that note, I'll turn it over to Ryan to review our financial performance and outlook.

Thanks, Matt. It was a very strong quarter on the financial front.

Adjusted EBITDAX increased by 24% versus Q4 to $145 million in Q1, outpacing production growth of 21%. So volume growth is certainly flowing through to the bottom line.

The increase in EBITDAX was driven by higher volumes and realizations as well as lower unit costs, each of which posted a company record in some form. First quarter net production of 54.8 MBoe per day is up 21% versus the fourth quarter to a new record.

Our average unhedged price per Boe of $40.48 represents 77% of the benchmark oil price for the quarter, a new high for Parsley and reflective of a higher oil percentage and lower transport cost with more oil on pipe. Oil, as a percent of total production moved up to 69% in the first quarter, which is a new high mark.

And we set a new low for combined operating cost in Q1. Together, LOE, cash G&A, production and ad valorem taxes came in below $10 per Boe for the first time.

We spent $188 million on CapEx in Q1. First quarter CapEx includes a good bit of spending associated with the eight-well pad Matt mentioned that we'll be bringing online in Q2.

This limited our completion count, so spuds outpaced completions in Q1. During the quarter, we spud 26 horizontal wells and completed 22 wells.

As you can see on slide 11, our balance sheet supports our anticipated growth with $1.6 billion of liquidity after adjusting for our spring redetermination and the closing of the Double Eagle acquisition in April. We recently amended our credit agreement and increased our borrowing base from $875 million to $1.4 billion.

Of that amount, we elected a commitment level of $1 billion. Turning to slide 12, we've added to our hedge position and now have more than 80% of consensus oil volumes hedged over the second half of 2017, and a robust position into 2018 as well.

This increases our ability to plan, lock-in services and equipment at relatively favorable rates, and execute on our strong growth trajectory. Slide 13 shows our updated 2017 guidance.

All changes are favorable, with production guidance up and all unit cost estimates down. We've given a sense of our quarterly completion cadence, and as you can see, we expect to build substantial momentum through the end of the year and beyond.

So, to conclude, 2017 is off to a great start with healthy progress towards significant production and cash flow growth. With that, we'd be happy to take your questions.

Good morning.

Good morning, Michael.

Just have a few questions on the Wolfcamp C. Could you, maybe give us some more color on the completion design in the C versus the standard B completion and maybe how you expect the hydrocarbon mix to change as you move South to North across your acreage?

Yeah. It's relatively consistent with our latest designs that we're deploying in our Wolfcamp B formations.

We do have a few test designs in this one, but nothing material. It was a white sand job, 40-70, about 1,800-pounds-per-foot loading, and similar barrel-per-foot loading as our Wolfcamp Bs.

At this point, it's just early in the design of these completions, so we're just still working on our cocktail. We like where the results from the original one, but aside from that, we're still refining the process.

Hey, it's Bryan. We're seeing going from South to North, we think there's kind of a slight oil window in Western Reagan County and as you go South down into Crockett or East close to the area and it just gets gassier.

Got you. And then, maybe just a high-level question.

Just in the context of the recent volatility in commodity markets, can you give us a sense where you think about slowing down or does the hedge book give you the confidence to keep accelerating a la last year?

Yeah. We're very fortunate.

Luckily, we were very aggressive with putting on hedges when oil hovered above $50 and we locked in this year roughly around 80% of consensus oil and then even more for the following year. So, I don't see us backing off even at $40 oil, but going into 2018, maybe it's a discussion for below $40 to back off a rig or two if we're closer to $35.

Got you. Congrats on the quarter.

Thanks guys.

Thank you.

Good morning and thank you for taking my questions. I'll ask the same breakeven question that was asked here previously and maybe approach it from the cost side and that is, by how much more can you keep pushing on capital in operating cost over the immediate term to preserve margins and returns, and what does the cost structure look like, say 24, 36 months out when the company is deeper in development mode?

On the capital side on the D&C, we're always going to continue to push. We do think kind of industry wide that the service side was cutting into some bone in the fourth quarter when activity levels were just severely depressed.

So, we need to get to a more stabilized environment from both an operator and service company relationship. We probably think that's been achieved.

We think both sides can work in harmony right now and have fruitful businesses. So then, from that point on, it's all about wringing out additional efficiencies.

We have gone the extra mile of really bringing in our service providers and trying to align on performance metrics to where we are both incentivized to have additional efficiency gains. We have successfully completed that with some of our contracts on the drilling side and some of our key performance contracts – not contracts, but key performance bonuses on the stimulation side.

So, with that in mind, we think we can actually wring out additional cost reduction. So, unit cost will be able to stay flat or even appreciate, so that they can run their businesses, but then, the netbacks to us on a per-well cost, we think, we do still have room to go.

And then, on the second part of the question, which was more focused on longer term, I think we have sensitivities in the back on slide 12, where we can be high returns in a wide range of D&C environments.

Okay. Got it.

And as a follow up to that, maybe a portfolio management question here. Is there acreage in the portfolio today that you see not competing for capital and could be a candidate for divestiture or trade, recognizing, of course, that you've been diligent about what's been acquired to-date?

Yeah. The thing is if oil rises up to $60, we are going to continue to add rigs.

And so, we're hesitant to divest potential benches that are, let's say, today, they're 20% return projects that could potentially be 40% projects in a couple of years if oil rises. But maybe you can take about Cline, but after watching Wolfcamp C, what just happened maybe we go back to the Cline and start a different set of completions against the Cline and that can move up on the inventory curve.

So, right now, we're just focused on vesting non-op, continuing to trade that non-op, the small bits and pieces on the edge rotating back into the core.

Got it. Thank you.

Have a great day.

Thanks.

Good morning, guys. Matt, I was looking at I think it was on slide 9 I believe, but you mentioned how nice the GOR has remained or continue to be stable.

I think it was on that Reagan County well. I'm just wondering are you seeing that in most of Reagan and then as you sort of progress up North, where you have more activity there in Glasscock?

And as I look even into Howard, are you seeing sort of similarities there, just if you could talk about how you're seeing the GOR on a number of these pads continue to play out?

Well, that was in reference to our Wolfcamp C result and how stable it's been around the 2,000 to 2,500 range. For a well with this type of productivity, it's very encouraging to see that.

So, we don't have any Wolfcamp C results farther north into Glasscock, but the rock properties do predict a similar environment as – in reservoir properties as our current producing well. So, we'd expect the GOR to stay similar to slightly lower as we go north into Western Glasscock.

And then across our broader portfolio of Wolfcamp Bs and Spraberrys, we are very consistent in the mid to high 70s on oil cut throughout Upton and Reagan. We don't see high variations in our GOR.

And then the highest oil cut of course would be in the Lower Spraberrys as you get up into Martin and Howard.

Got it. And then one last follow up, Matt, for either you or Bryan, as you continue activity and you become one of the larger producers out there in the Basin, we hear a lot of talk not only just on services, but particularly with the sand and people procuring or doing different things.

As you go forward and continue to gain more size, any changes of how you would think about maybe procuring that or do anything differently on the services side?

We've had all the conversations with many providers. It's our bias not to be owners of mines and not to spend capital where we don't need to.

So, we're just really, as I mentioned, with the alignment and key performance indicators on the completion side. We think we'd had productive conversations to secure our sand.

We've had no issues on our well sites to-date, but we want to stay out in front, so we work on it with our vendors on really granular forecasting and a lot of face-to-face conversations all the way down the supply chain.

That makes sense. Great activity.

Thanks, guys.

Thank you.

Good morning, everyone. I was hoping you could talk a little bit about blocking up your acreage and you've obviously made a lot of progress in a very short window of time already, but how much more is underway with swaps and trades, and where you ultimately think you can get working interest too across the position?

Yeah. I mentioned on the call that our latest trades were roughly around 3,000 net acres and basically equivalent to one of our acquisitions last year between $200 million and $250 million of inventory.

And I think this is just the beginning from talking to the Land Department for Parsley. We are in the middle of talking many more trades through 2017 going into 2018 with six or seven companies.

I think before Double Eagle, it was just around two to three companies. So, the momentum is on our side and what you saw in our deck today, is just the beginning.

Okay. So, continued work throughout the year is fair to expect?

Yeah.

And then as a follow-up to your comments earlier, Bryan, on inventory about the Cline specifically and, I guess, other potential zones. Do you have any plans to test those other zones this year with, given, really, I think great surprise of how productive the Wolfcamp C looks right now?

How much other zones do you have plan to test in 2017?

It took us about 18 month to 2 years to get to the C, and we're focused on the C more than ever. I just mentioned the Cline's potential upside in the future.

I think there are other operators a few years ago that drilled the C and, basically, Wall Street wrote off C, all the operators wrote off C and, now, C is back. So, it's just something to think about Cline in the future.

Maybe in a couple years, we get to that. Maybe another operator drills a Cline well and completes it with the latest completion design that we're doing in B and C.

Thanks, Bryan.

Yeah. Thank you.

Good morning, everyone. Matt, just curious on the C, the wells you have planned for this year.

Are those going to be multi-well pads and kind of where are those going to be located, either Glascock or Reagan County?

Yeah. Where we can, we definitely incorporate them into multi-well pads.

You just have so much efficiency gains on surface and cycle times. So, the majority of those will be in combination with additional development in the Wolfcamp B and Wolfcamp A.

As we mentioned, we're working from the inside out on the next four to six wells. So, probably in the next three or so, will be spud in Reagan and actively aggressive in that process right now and then we'll step out North into Glasscock and West into Upton.

Okay. Great.

And then the last one, Howard County pads, what are those targeting at this point?

They are again against the entire three bench targets: Spraberry, Wolfcamp A and Wolfcamp B.

Okay. Great.

Appreciate it.

Thank you.

Good morning, Bryan, to you and your team there.

Good morning.

Bryan, from my seat, it looks like some of the hotspot of the Delaware Basin and the activities kind of moved north from where you are, and so I'm wondering, does it seem like that to you? And from your seat, is there an increased kind of attractiveness to small tack-on acquisitions or trades down where you are in the Delaware?

Our area was more blocky and it seems that that's where the frenzy started just about 18 months ago. I think, it's all blocked up.

I think, it's basically finished. And you saw, Centennial acquire – they had to jump a few counties up or couple of counties going north with an acquisition in Northern Delaware.

Now, I do think activities – a lot of activity going west. There's some packages out, and I'm hearing the data rooms are full.

I'm hearing you can make pretty good wells going west, gassier for Parsley Energy. We're always focused on higher oil cut, but gassier guys wanting to break into the Delaware, that could be the next move you might see some gas players coming into Delaware.

Got it. But where you are, it's – the work is pretty much done, if I'm hearing you right?

Yeah. It's locked up.

I mean, Oxy bought to the south of us and Diamondback bought to the south of us, and then you got Jagged Peak to the north of us. So, it feels like we're surrounded and it's just all locked up.

It's not like the Midland Basin where choppy acreage and put – it's a kind of an analogy of like a 3,000-piece puzzle versus a 500-piece puzzle. And basically the puzzle, the 500 pieces have already been put together by our competitors and ourselves.

Both of those sound pretty intimidating to me. But if I could ask Matt a question on that Wolfcamp C, I really – it's – I enjoy hearing that narrative of how you matured this over 18 months, and it got me to wonder are there other – without getting to specifics – are there other similar projects that are in some phase of maturation in your technical process right now or is this – or was this kind of a one-off project for you guys?

No. We always have a talented group of folks working for the long-term value for the company.

So, we hear exciting things month-in, month-out about the concepts, and we'll expect that process to continue to be fostered over the next few years as we slowly delineate additional benches and test additional areas throughout the basin.

Got it. Thanks, Matt.

Thanks, Charles.

Hi, guys. Good morning.

Thanks for taking my question. I just was wondering if you could give us any update on the upper A, lower A stagger test?

And the upper B, lower B stacked and down spaced test. I think the last time we talked about is maybe 3Q 2016 earning call.

I'm just wondering any update on these lines and then kind of what does it take to get to that 24 wells per section on the A and the B to that potential 60 inventory per section?

Yeah. We're marching along on both fronts, hopefully a little ahead of schedule on the density test.

We should be turning that project around within the next few weeks. We are right at the finish line there and then we're all anticipating the results and looking forward to it, so then that will roll into our conviction on getting towards the 60 spot density test.

And then the upper and lower Wolfcamp A result will be right on the heels of that, so still on track for the third quarter.

Okay. Awesome.

And then my next question on the mineral interest front, are you guys actively looking for opportunities in this realm? Or is this simply just when acquisitions come if you can get the mineral rights along with it or, I don't know, if you guys can talk around that?

You know, I think that was a one-time deal for us on our Trees Ranch when we acquired the 30,000 acres. It's very difficult to find more minerals.

We try when we can or when they contact us, but in the Midland Basin, it's been so chopped up since the 1920s and siphoned off to cousins and like tree branched out to their cousins. It is very difficult to find mineral owners selling.

And also, people in Midland and West Texas, they pound in their heads to their grandkids to never sell their minerals. So, we feel very fortunate with the Trees Ranch, but it might be just a one-time deal.

Okay. Okay.

That's fair. And then any prior – is there still the opportunity to – I know, you talked about previously to get the – once you get those mineral rights volumes up, is there still – are you guys still thinking about potentially spinning that off into an LP type structure?

I personally don't like the idea of having two companies and two boards and multiple committee meetings, but we need to always keep our options on the table out there. I'm not sure that ARB is there right now.

We're enjoying the high-margins at the corporate level with the Trees Ranch at the moment.

Okay. Great.

Great quarter, guys. Thanks.

Thanks.

Good morning, guys.

Hey, Jeff.

High-level question. With how much growth yourself as well as peers in the Permian are set to be having, how are you guys kind of thinking about out-of-basin takeaway and any potential of looking at long-term agreements to get oil out of the basin?

You've seen a great response to new projects being announced – two more announced just yesterday on the gas front, as far as in-basin processing. And then long haul out of basin.

So, we think people are being very responsive. We think all the companies that investors deal with on a day-in day-out basis are getting ahead of it and we don't see any material issues.

Back when we were private in 2008 and 2009 and trying to get the attention of these haulers with one lease and 30 barrels a day or 300 barrels a day. You have a little bit harder time gaining attention and getting pipeline space and making those agreements.

We think everybody's teams are being very proactive and working together. So, we don't think for the larger players that there'll be any material constraints.

We're physically connected to six long-haul pipes. So, we don't have a – so one of the strategic goals we had was flexibility and building out our gathering agreements.

And all the way from the Delaware to the Midland Basin, we can toggle between those physical pipe connections. And I think, in early Q1, there was a pipeline that had an issue, a single pipeline.

And if you were – if that was the only pipeline you had an agreement with, you may have been shut in for a little bit. And we didn't have any of those issues because we could flex between the six physical connects.

I just want to mention, there is more gas plants being built in the Permian than ever. I think, Target just announced two more a couple of days ago.

So, Permian has the best infrastructure in the basin and it obviously reacts quickly.

Okay. Great details on that.

And just on the well cost side, I think in a later slide in the deck, you guys kind of referenced some R&D efforts and that maybe kind of impacted costs in the first quarter. Can you guys just kind of maybe talk specifically about those R&D efforts and then just kind of maybe give us an idea of what kind of a normalized well cost we're running at for the quarter?

So, without going into specifics, we have about seven – most of them are focused on the completion side. We have a few that we would count on the drilling side, but those are probably immaterial cost-wise.

On the completion side, we have about seven independent projects and concepts that are going that are being prepared – or compared against a baseline parent well objective. And, in 2017, the goal is to combine those projects.

We're seeing successes across pretty much all fronts, but they're on a standalone basis. So, we think that's driving a lot of our well productivity, and we're excited about it.

Some of this outperformance that we've seen here recently and going into this guidance update. So, we're excited about it and we think we'll have some follow-through benefits for everyone.

Okay. Great.

Thanks. And great quarter, guys.

Thanks.

Hi. Good morning.

Yeah. Congrats on the great quarter.

Thank you.

Just on that same slide where the R&D was referenced, it talks about lower average lateral lengths. I guess that specifically front of the Midland.

Can you just – is that just a function of the program or is there something you're doing different going forward or how should we think about that?

Yeah. It's just a function of independent project lease geometry at that point in time.

On average over the years, our – even our Midland side average lateral lengths are increasing throughout time. Now, one thing I mentioned is we had to compare against the baseline some of these projects.

So, if you think about that you have to go and compare against older leases that have already been drilled and those older leases were set up for some of the shorter geometries. So, that's going into it a little bit.

But structurally across our portfolio, the annual programs are getting longer. We went from about 6,000 feet in 2015 to 7,000 feet in 2016 to 8,000 feet over the course of 2017.

Okay. Yeah.

Thanks, Matt. I just wanted to make sure there is nothing – wasn't anything changing going forward.

No.

And can you give you me or give us kind of a – I'm trying to think about a rule of thumb as far as – and I know you guys are testing different proppants all over the basin, but how do you think about an extra thousand pounds of sand per foot. When you start doing the math on that, like how much more uplift do you need?

Is there anything that you can give up as far as what you're looking? I'm just trying to fare when you get that – when that return threshold starts to break over, when you go to 2,000 to 3,000 or 1,500 to 2,500 or – what you're looking for in the uplift in productivity, just in the proppant.

In the 2016 world, when proppant, for all intents and purposes, was free, there was a – you'd keep pushing on that front. As we start seeing proppant pressure on unit pricing, we think we're there on the Midland Basin side.

We like this 1,900, 2,000 pound. We are still seeing better benefits for more sand loading, but it's not linear anymore.

So, then, it's just cost – it's just an economic decision of what we're getting charged per ton. On the Delaware side, we've been using higher sand loadings in the Midland, and I think there's still some room there, but it all comes down to the cost of the delivered proppant.

So, again, it's not a – we don't have a catchy rule of thumb for you, but we like – if we see additional cost pressures on the sand side, we're probably going to be pretty close to where we're at. If we can wring out additional efficiencies on sand deliveries and keep those costs down, we'll add more sand loading.

Okay. And where you're at right now, is that 2,500, 2,800, somewhere in there on the Delaware side?

Delaware is about – yes. Yeah.

That's right, on the Delaware.

Okay. Yeah.

Thanks.

Thanks.

Thanks. Good morning.

Congrats on a solid update. I'm just curious, you mentioned in your remarks the advantages of the quality of crude you're producing in Pecos.

Can you elaborate a little bit on that and how you see that potentially playing to your advantage in the years ahead?

Yeah. I said Southern Delaware, I meant, Delaware in general.

It's more just the gravity in it. The WTI barrel is a blended barrel, it always has been.

We have the export ban lifted now over a year and when you want to get your barrels to international markets, they need – the more specific you can get on a big loading, the better price you're going to receive for your barrel. So, if you can deliver between 38 and 44-degree oil and a large amount of it in a consistent volume, you should be able to receive marginal benefits over time.

So, that's, I think, the industry is working on segregation and then bringing out these pennies here and there on the product stream. And every little penny counts.

Got it. And then can you guys review your – the setup you have to get to Colorado City and what sort of advantages and optionality that provides for your crude and how much volume you have going for you?

Yeah. It's all connected to – well, now -- majority of our oil is connected to the Medallion system and that's the system that gets us to Colorado City.

Our Northern – through the Double Eagle acquisition and a few prior acquisitions, most of the northern stuff is tied into NuStar now. So, with the physical connection to Colorado City gave us optionality to toggle between Cushing and the coast on a six-month basis, so it's all about flexibility and the physical connections.

And any given time, we might choose to go to Colorado City and take that. And then other times, we might go down to the Coast.

So, effectively, all your crude has that optionality at this point in the message?

Yeah. Probably about everything on Medallion, which is probably about 70% of our crude currently.

A good benefit of the NuStar agreement is that you have local refining options. So, that is zero transport fee.

As we continue to develop our property, that percentage is going to move up. We're diluting the properties that aren't being truck-hauled.

Great. That's helpful color.

Appreciate it, guys.

Take care.

Good morning, guys, and a phenomenal quarter. So, Matt, can you share some more info on just some of those key performance indicators you were talking about with the service industry and how you've structured some of those agreements?

That's – it's relatively confidential, but it's agreed upon between two partiers, but it all comes back down to alignment and efficiencies. I mean, one example is just what's the end result that's a benefit for us and at stages per day, and how can we highlight that.

Some people might not like this in absolute stage per-day indicators, so you work with them and you talk to them about, okay, what can we sit down across the table from and have benefits of – yeah, because they might say, well, your stages are larger than they were a month ago. And so, you just have to work through it with the other provider and come to mutual agreements that drive alignment and that you can both agree to.

Got it. And then, just switching gears a little bit.

If I recall correctly, you all were planning on ending the year with about 30 drilled but not completed wells as a result of the Double Eagle acquisition. As you think preliminarily about 2018 and assuming you had an okay crude price, how would go about completing those DUCs.

So, would you just bring a bunch on line in a relatively short period of time or would you – would it be more of a gradual draw down over the course of the year?

Those aren't designed DUCs. Those are just a function of what's – if you're cutting the year off at year-end versus the rolling activity program, so that's just the normal activity level that we continue to complete throughout the beginning of the year in a normal fashion.

We'll be up to five frac spreads going into 2018, but three currently. The fourth stands out here within two months.

And so, they'll burn off in a natural fashion.

All right. That's it from me.

Thanks, guys.

Yeah. Hi.

I would like to ask you a question on really your Wolfcamp C fairway. I'm kind of curious, like what defines your black lines?

Specifically, I understand to the south is losing pressure and higher gas-oil ratio, but towards north at Howard County right next to the Glasscock nose, there are some blocks up there and why did that get weeded out? And also, how much cost for you to drill a typical Wolfcamp C well at this point?

It's a combination of multiple rock properties and petro-physical cutoffs, resistivity cutoffs, clay content, and a myriad of petro-physical inputs help bound those lines. And then the imprint on top of that is obviously thickness, that's the easiest one to show to relate to.

So, you have some – that goes into the cutoff as well. And then on the cost side, we're a few 100-feet deeper from our lower Wolfcamp B target.

So, we'll expect couple 100,000 in additional costs, but nothing – no material design needed, change needed versus the Wolfcamp B well.

How long does it take to drill?

That should be around the same cycle times that extra 200 feet might my account take an extra day in the early part of the program, but over time, should not be any additional time over our Wolfcamp B program.

Great. Thank you.

Welcome.

Good morning. Looking at the Strain Ranch well or Spraberry well, the early time performance is exceeding the first two to your Lower Spraberry wells early time performance.

And I was just curious, do you think that was anything contributed to the fact that that was completed with the Wolfcamp A and B well or is that just a locational standpoint where that Lower Spraberry activity was?

Maybe a combination of both. So, we've seen across our portfolio benefits from what we've been talking now for over a year, stress shadowing into our design.

And then, obviously, these wells were in flight as we're in negotiations with Double Eagle and we're able to influence the geometry of these targets into a Spraberry A and B. And then additionally, the Spraberry screens petrophysically very nice in that area of the world.

So, the combination of both probably.

Okay. Great.

And then when you look over the Delaware Basin, I mean, the wells continued to outperform the 1,000 MBoe type curve. When you look at the longer term production that you have today versus your initial expectation, what is the most surprising factor that you're seeing potentially in that outperformance?

Probably a higher uplift to the early 60 days. We think the long-term production is essentially matching our pre-drill estimates from a year or two ago.

We're definitely getting higher 180-day cumulative volumes on the front end, and we'll have to incorporate that into comprehensive type curve analysis as we get enough wells up to the dataset.

Great. If I can just squeeze one more in, can you remind me, did the Wolfcamp C well flow naturally or did you put that on artificial lift immediately?

It's still flowing naturally.

Great. Thank you.

Good morning, guys.

Good morning.

Just a quick question in regards to some of your uphole delineation and resource opportunity. As you mentioned on the call, the Double Eagle acquisition allows you to target the Lower Spraberry across the portfolio in a more significant way.

Just curious about some of your recent peer commentary on the Jo Mill, your views on the resource potential on your legacy and recently acquired acreage.

I've always thought of Parsley Energy as Wolfcamp chasers, so we're in a different part of the basin, North Upton, Glasscock and Reagan. So, we've really been focused on Wolfcamp.

So now, we're just getting to the Lower Spraberry. We're excited about the Jo Mill.

We're watching the other competitors. I don't see that coming up this year, maybe next year, but it's just a whole another bench.

We talked about the Cline before, but Jo Mills is a whole another bench that could be potential upside for Parsley Energy.

And everywhere we have Lower Spraberry inventory, we'd have Jo Mill inventory as well.

Great. And then just as a follow-up to one of the previous comments in regards to your standard frac design.

I was curious if you have any updated thoughts on the larger frac job you guys performed last year, and if there's any potential to continue to progress your completion design further this year with incremental tests on higher proppant loading or changes to fluid volumes and cluster spacing.

Yeah. As I mentioned on absolute loading, we're starting to see a break over probably on the economic benefit.

However, if you look at that well productivity on a standalone basis, it has been a very strong producer over a long period of time. So, it just comes down to an economic decision.

You do get more oil for more loading, we believe. And then we just need to decide.

There will probably be another test, one single test where we might push the limits again just to combine it with our other seven tests to see if they interact well together. But on a program basis, we think we're good on the Midland Basin around that 1,900 pounds per foot.

But we'll always keep pushing.

Great. Thank you very much.

Thanks, Matt.

Thanks, operator. Good morning everybody.

Hi, Joe.

Hi, Joe.

Just going back to one of the prior questions and answers. So, regarding infrastructure and takeaway, whether it's on the oil side or the NGL side or the gas side, are you expecting any pinch points in the Delaware or Midland going forward?

Not trying to sound overly biased, but, at this moment, we don't see it for a Parsley product. We're very fortunate in the way that the strategy has unfolded for connecting our products, and we've been kind of at this crossroads and intersections of long haul activity, even where our Delaware Basin asset lays, it's on the eastern edge of the Delaware Basin, and the pipes come through there, and then Waha Hub is on some of the surface acreage that we own.

So, we do not see any pinch points at this time. We do see the same basin modeling that everybody else sees, that shows on an aggregate basis without any additional modifiers or surfactants put in line that you see tightness in the end of 2017 maybe early 2018, and everybody is beating on their production volumes.

So, that aggregate tightness should come, but we don't see it on the physical connects that we have.

Also, it seems like there's billions of dollars of private equity-backed management teams just banging on our marketing door and other operators, our competitors. So, luckily, the midstream is keeping up, and I think they're well aware of any potential tightness in the future, and just trying to stay ahead of it.

That's very helpful. And then a separate question, and this is for you, Bryan.

I know you're going through a fairly active digestion period right now, but at some point, do you plan to get back to actively buying big asset packages, and could you just talk about your overall strategy?

I think Parsley Energy has moved up to a whole another level. We need to focus on execution.

We have 4,000 to 5,000 locations. We have high IRR locations and if oil runs up to $60 over the next couple of years, we can go to 20 rigs and 25 rigs, and we'll still have enough locations to look 10 to 15 years out.

We might start looking at bolt-ons next year, midyear 2018, small bolt-ons. I don't see us doing a big deal in 2018 or maybe even 2019.

It depends if it's accretive for Parsley. But right now, we're just focused on execution through 2017.

Okay. That's very helpful.

Thanks, guys.

Thanks.

Thanks, Joe.

Good morning. And congrats to the team on a really, really impressive quarter.

Good morning.

Just wanted to circle back on the Wolfcamp C, two for one, as Matt put it, it's a really interesting prospect. I just wanted to feel out how de-risked, I guess, you all are feeling about that.

And I guess, as we think about the 2018 program, how big do you think the Wolfcamp C could be as a part of your kind of overall 2018 program or do you really still need to see some confirmation from some of the wells you're going to drill over the rest of 2017?

Sure, John. I think that particular well result is not de-risked to a model standpoint.

That's just off one well result, you just can't put that type of result in your model. Whether it would have been good or bad, it was extremely good.

But we're going to need to see a few more before we de-risk that type of result. However, what we do feel is de-risked is this prospectivity on a economic basis across the majority of that outline when everything stacks up on everything that we're looking.

So, we think the zone is effectively de-risked and then we'll have to get a few more wells down to determine the profile of production, but it's a hell of a start. And then as we get these additional wells down, we pull them as far forward in the schedule as we could.

In fact, we're potentially TD'ed on our second well and seeing again high pressures where we had to mud up equivalent to what we run on the Delaware side, and then we had very strong gas shows which is what we saw on the original well. So, if we get this productivity back in any meaningful way in the next two to three wells, it times nicely with our budget cycle and I would expect it to, we're a rate-of-return company, so I'd expect it to be a large portion of 2018, or meaningful portion of 2018 if these results continue.

That's helpful. And I apologize if I missed it, but did you all say when we should expect kind of the next 30-day IP or the timing on those next Wolfcamp C wells?

No. We just said that we've pulled forward a handful as aggressively as we can on the schedule and then I just mentioned that we're roughly about TD, so I mean it's going on the next well, so you need to run casing.

You need to frac the pad and it is part of a pad, so that extends the timing, and then you got to turn it around, clean it up and get your 30 days. So, it'll be towards the back half of the year when all these results come in.

Okay. And then just one housekeeping question for me on Double Eagle's cost structure.

I know you guys lowered the full year LOE guidance, but should we expect an uptick to the top end of the full year range in 2Q before flush production kind of brings us back down in the back half, or just how much, if at all, is kind of Double Eagle potentially driving us up in 2Q?

I don't see that affecting our LOE, especially because we closed on April 20 kind of almost mid of the quarter. So, I think we talked about it in previous calls, around 2,000 Boe to 3,000 Boe per day for the year on the Double Eagle acquisition barrels.

So, it doesn't move the needle on a LOE per barrel.

We did acquire with that acquisition some vertical wells that we'll evaluate and may have some sort of a cleanup cost, which could bring LOE up just a bit. But I wouldn't expect any meaningful increases.

That's really helpful. Congrats again on the quarter.

Thanks.

Hi. Good morning, everyone.

Good morning.

Just following up on Gail's prior question. In terms of stack development with the Lower Spraberry and Wolfcamp A, B, given that the Lower Spraberry comes on a little slower, and I think slide eight is really helpful for all of us in seeing that.

We've heard some other operators talking about pulling back potentially on the proppant loading in the Lower Spraberry when you're doing stack development. And is this something that you thought about for full development or is there something that you see in the most recent Strain Ranch well that tells you something different?

No, there's nothing specific to the Spraberry. I think it ties into the just the general concept of loading and where do you see those economic breakovers.

And then, separately, as you're doing density tests, there's tests that will be coming online for us. The eight-well pad will be a 330-space bench.

Just conceptually, if you were to get down, where do you get down to? Is it 100 feet between wells, is it 50 feet between wells where you would have a smaller frac design?

So, I think that's what people are playing with. We're in the early innings as an industry as this density optimization.

And then, you're going to try to pull back and get the most bang for the least buck and pull back in your designs once you get there. Out of the gate, we have not pulled back on our density test, on our loading, and on our stage sizes, but we have a myriad of downhaul gauges and probably the largest data acquisition project in our company's history that will give us early telltale signs on design improvements going forward and optimizations on that front.

So, when you see that combined with density, I think that's what the industry is working on right now.

Okay. Great.

Thank you for taking my question.