Industrias Peñoles, S.A.B. de C.V.

Thanks very much and thanks everyone for joining us today. With me this morning are Bryan Sheffield, our Chief Executive Officer; Matt Gallagher, our Chief Operating Officer; and Ryan Dalton, our Chief Financial Officer.

During our prepared remarks, we’ll be referencing the investor presentation we posted to our website, so I encourage you to download the presentation, if you haven’t already. You can find it on our Investor Relations page under Events and Presentations.

During this call, we’ll be making forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our news release and SEC filings.

We may also make reference to non-GAAP measures. So please see the reconciliations in our earnings release.

Bryan will begin our prepared remarks with an overview of the quarter and an update on our outlook. Next, Matt will discuss our operating performance last quarter; Bryan will then discuss our Q1 financial results and update our guidance for 2015.

After that, we will be happy to take your questions. With that I will turn the call over to Bryan.

Thanks Brad and good morning everyone. Every quarter the value of our assets and our ability to develop them becomes more apparent, despite a significant impact from winter storms.

During the quarter, production increased several hundred barrels a day from Q4 to 18.9 Mboe per day in Q1. As you can see on Slide 4 of the presentation we posted, production has continued to increase as we have slowed our drilling activity over the last few weeks, averaging more than 21,000 Boe per day for the month of April.

For this reason as well as others, we will discuss throughout the call, we will raise our full year production guidance to between 20 to 21.5 Mboe per day, up from 18 to 19 Mboe per day. Slide 5 shows that our Wolfcamp B wells, which have consistently ranked among the best in Midland Basin or any target formation, continue to get even better.

According to IHS, our Ratliff 28-1 H Wolfcamp B well located in the middle of our densest concentration of acreage and drilling locations as the highest reported oil rate of all horizontal wells, completed in Upton County today. And on average the three Wolfcamp B wells we completed in our core area this quarter generated a peak 30-day IP rate of 231 Boe per day per 1000 stimulated feet.

Since we have started drilling horizontal wells in late 2013, the average scaled IP rate for our core Wolfcamp B wells have increased every quarter, up more than 30% altogether from what was a very robust starting point. Our Wolfcamp A wells are coming very storng as well.

Our more recent Wolfcamp A well, the Mary 18A-18-2H in Upton County generated a peak 30-day IP rate of 188 Boe per day per 1000 stimulated feet with an oil cut of more than 80%. Turning to slide 6 having kicked off of our horizontal drilling programs just a year and a half ago, to this point we’ve used the type curve based on all publically available Wolfcamp A and B results.

Now, we have 30 Wolfcamp A and B wells of our own under our belt. We finally have a significant data set to work with enabling us to base our type curve on our own well results.

This new Wolfcamp A and B type curve has a EUR of 1 million Boe, reflecting the actual performance of all Wolfcamp A and B wells we have drilled to date. As strip pricing and current drilling and completion costs, this type curve, which is normalized to 7,000 stimulated feet generates a PV-10 of $8 million per well.

When you considered a more than 750 net Wolfcamp A and B drilling locations in our inventory, you start to get a sense of the tremendous value of our asset base, before even considering inventory in several other perspective zones or the value of our Southern Delaware acreage. Speaking of our inventory, we’ve adjusted our drilling locations to reflect new regulations regarding lease line offsets as well as industry results and our own petrophysical analysis both of which support 660 foot between wells basin for a Wolfcamp client and lower Spraberry drilling locations relative to our previous basin assumptions of 870 feet between wells.

This increase is the number of laterals per one mile section from 6 to 8, as you can see on Slide 7. The new lease regulations don’t apply to the Atoka horizon, so inventory in that formation still looks a surprise.

Slide 8 shows our inventory growth including around 114 net locations we’ve picked up through bolt-on activity this quarter. Our net horizontal location count is up around 20%, assuming a 6-rig run rate we have almost 40 years of horizontal drilling inventory, including 13 years of Wolfcamp A nd B locations alone.

This worth noting that the average lateral length associated with our drilling inventory continues to increase. Now over 5,500 stimulated feet, which corresponds to a total lateral length of around 6,000 feet and the average total lateral length per well drilled this year should be around 7,000 feet.

We’re actively pursuing acreage rates that would increase both future drilling locations and the average lateral length of our drilling inventory and we continue to be opportunistic on the acquisition front, bolting-on around 3,600 net acres in our core area in Northwest Reagan and North Midland counties for approximately $7 million in cash and the estimated $10 million in drilling carries. Slide 9 updates our expectations for the year.

As we have discussed before entering the year, we made a decision to our activities towards the back half of the year in anticipation of decline in service cost and perhaps higher oil prices. The plan was to average two wells in the first half of the year and then run four rigs starting in July for the duration of the year, but also to maintain the flexibility to adjust the plan as desired.

With cost down, oil prices up, and our wells performing so well, we now plan to ramp back up the four rigs at the beginning of June, one month earlier than anticipated. We now expect production of 20,000 to 21,500 Boe per day for the year on CapEx of $250 million to $300 million.

Relative to 2014, this represents 46% production growth on sharply reduced spending. And given the shape of our activity, production should really come on strong at the end of the year.

In fact, we’re estimating that Q4 2015 production will be up more than 30% versus Q4 2014. So we’re really pleased with how things are tracking.

Our wells are coming even better than expected and improving all the time and we say that really well for the remainder of the year and for momentum into 2016. With that, I’ll turn it over to Matt.

Thanks, Bryan. It’s really exciting from an operational perspective, it’s not just how strong our wells are, but the trend we’re seeing in our well results and the potential we perceived for ongoing improvement, relative to other basins, horizontal development and the Permian is still in its infancy.

Before I get to the slides, I want to elaborate on our strong Wolfcamp results. The data we’ve gathered suggest that the adjusted per lateral length 24-hour IPs on our Wolfcamp B wells in Upton County are coming in close to 75% higher than average for the county.

And as Bryan noted, productivity has increased every quarter. Our 30-day Wolfcamp B well productivity, in our core area, has increased from 175 Boe per day per 1000 stimulated feet in Q1 2014 to 231 Boe per day per 1000 stimulated feet in the first quarter of this year.

We think that favorable trend in our well results is a function of several factors including higher stage density, more slickwater stages and greater proppant per stage and also honing in on optional landing zones. We also think there is more left in the tank and with lower cost and higher activity on the horizon.

We plan to keep working toward our stretch goals on our completion design. We’re seeing improved productivity on our tier 1 Wolfcamp B wells in Reagan County as well.

Not only that, the decline rates on our tier 1 wells in Reagan County are proving to be relatively sharp, along with lower drilling costs associated with lower depth in pressure, this relatively flat production profile supports very healthy well economics in our tier 1 area. The data we have collected suggest that 24-hour IPs on Wolfcamp B wells in Reagan County are around 55% higher than average for the county when adjusted for lateral length.

Even as we’re refining our completion technique, we’re also increasing our drilling efficiency. We have registered a spud to regular lease time of 17 days on 8,000 plus foot lateral and at Parsley record 14 days on a 5,400 foot lateral, so we’re making great progress on cycle times.

We’ve recently used a new casing design in our core acreage, which has shaved 5-off of our average well in that area. On top of this, we have moved and equipped for purpose rig to preset casing, which allows us to use a much cheaper rig to drill the intermediate section of the well.

This may allow us to drill the same amount of wells with fewer dedicated horizontal rigs. Focusing now on Slide 10, the first quarter was a significant milestone for us regarding whole scale infrastructure.

Now have roughly 30 tank batteries selling into the Medallion pipeline to Colorado City, a first for our company. This along with significant water transfer system, we have in place gives us tremendous flexibility to increase activity levels if we choose.

We’ll have over 90 miles of water transfer lines installed by the middle of the year, connected to 18 disposal wells, which will reduce water hauling by 60%. This system along with the oil pipeline is set to reduce truck hauling significantly, thus reducing our sensitivity to adverse weather, which impacted our production to the tune of around 1,500 barrels per day in Q1.

We will also have a significant impact on our bottom line, saving us a couple of dollars per barrel on water disposed in garnering roughly $0.50 premium per barrel of oil sold into the pipeline relative to trucking. In the pipeline, we will also diversify our crude pricing giving us access to the Gulf Coast when Permian Express II comes online in a couple of months.

More broadly on the cost front, we’re seeing reductions in line with what we anticipated and have discussed on the first quarter call. The bulk of the savings have come in over the last few weeks, so clearly, we didn’t see as much impact in the first quarter, but on average drilling and completion costs are down roughly 15% from the peak last year and we had line of sight on the incremental concessions that would bring total savings to 20% and we will certainly push for more.

In Q1 cost reductions were offset to some extent by higher completion intensity and our decision to focus the majority of our drilling activity in our core area, which is deeper, higher pressure and therefore costlier, but also more productive. Turning to Slide 11, in the Southern Delaware, we continue to be very encouraged by the offset results in the zonal testing we’re doing in our exploratory wells.

24-hour IPs for 1000 lateral feet averaged 295 Boe per day to the 10 offset horizontal wells we show in the slide. One of the closest of which was drilled by Rosetta Resources by the way, which is set to be acquired at a healthy evaluation.

We’re focusing on the Wolfcamp A horizon as this initial target zone and we’re anxious to drill the horizontal well in the area. We’re also pleased to have secured a three year extension on the majority of the Southern Delaware acreage that enhances the value of the prospect and gives us the flexibility to develop it on whatever timeframe makes the most sense for us.

In light of the positive data points that are coming in, we’re eager to bring forward the value we perceived in the Southern Delaware basin. Bottom line this quarter is that we’re really pleased that our Wolfcamp wells continue to improve and are well equipped to maintain that trend and return to higher activity levels.

And now, I’ll hand off to Ryan to cover our financial results and outlook.

Thank you, Matt. We posted an adjusted net loss $0.07 per diluted share in the first quarter.

Adjusted EBITDA for Q1 2015 was $36 million. As Bryan stated net production averaged 18.9 MBoe per day during Q1, up 4% over Q4 and up more than 100% year-over-year.

We estimate that without the impact of winter storms, production would have averaged more than 20 MBoe per day for the quarter. Notably, oil production represents 59% total production in Q1, up 57% in Q4 and 52% in Q3 2014.

We saw a seasonal uplift in LOE per BOE in Q1 intensified by cost associated with bringing wells back online following the winter storms. We’ve also taken advantage of reduced drilling activity focused on our producing wells and as a result incurred higher than usual workover expense.

Among other maintenance, we’ve replaced entire tubing strings on a number of old wells, drawing down higher costs of inventory that flows through to LOE. Water disposal is the largest component of LOE following the investment in our water disposal infrastructure; our disposable cost will be coming down considerably.

So we expect lower LOE per BOE over the rest of the year. Meanwhile, G&A and DD&A increased slightly versus last quarter, $6.74 per BOE and $21.95 per BOE respectively.

CapEx declined 8% versus Q4, coming in at $122 million despite completing four more horizontal wells in Q1 and in Q4. We actually completed two-thirds more horizontal frac stages during Q1 than we did in Q4 with a greater scope of work on average as well.

Q1 CapEx should represent the high point of the year. We haven’t deferred completions to spending associated with wells drilled last year represented a significant component of first quarter spending.

We expect Q2 CapEx to be substantially lower as we’re running just one horizontal rig until we jump back up to four rigs at the beginning of June. Ranking back up to four rigs, a month earlier than anticipated will allow us to drill and complete several incremental wells this year.

So we're increasing our budget to $250 million to $300 million to reflect this additional activity. For the year, we now plan to complete 35 to 40 gross horizontal wells up from the previous estimate of 30 to 35 wells and we have adjusted our drilling schedule to focus on longer lateral this year as well.

And as Bryan mentioned, we are also increasing our production guidance raising our full year expectation from 18 to 19 Mboe per day to 20 to 21.5 Mboe per day with production increasing rapidly throughout the end of the year and then oil as a percent total production increasing as well. We continue to maintain a healthy balance sheet and strong liquidity profile, in conjunction with our spring re-determination, we increased the committed portion of our revolver from $365 million to $500 million, representing the full amount of the borrowing base.

We’re well hedged this year and next, with most of our estimated oil production hedged this year and more barrels hedged next year than this year. We’ve also established meaningful position in 2017.

We think the size and the strength of our hedge book positions us well for the fall re-determination process, and the structure of our hedge position allows us to retain the great majority of upside, if oil prices were to rally. Given our strong financial position and operational momentum, we’re working from a position to strength, no matter the direction of oil prices.

Operator, we’d now like to take questions.

Good morning guys.

Good morning, Will.

You guys came in ahead of me on production this quarter and you did note that you’re accelerating a little bit in June, but judging by slide 9, is still a way to think about this is a fairly light activity quarter for 2Q and probably production wise as well and then we really see the big ramp in production start in 3Q?

Will, it’s Bryan. You’re correct.

With lower drilling activity in Q2, I think you’ll see Q3 be the lowest from a production standpoint then really ramping back up on the production in Q4 heading into 2016.

Also – I just want to throw this out there, we spudded one well in April in a 50% working interest well. That kind of give you a sense in the second quarter.

Got you, thank you for that. And then on slide 10, it seems like this water hauling savings could be big for you guys.

I wonder if you guys could clarify on it’s the number one line item for LOE, can you talk about how big of a chunk that is? And then will you guys get the full benefit of that in 3Q that saving – that savings or is that kind of layered into the year?

How do we think about how LOE changes once that’s instituted?

Yes, Will, this is Matt. That’s a really big project for us and we are going to realize significant benefit and reduction.

Roughly, we point to on a magnitude of $1.5 million to $2 million of quarterly savings right out of the gate entering July. And of course, it’s dependent upon the concentration of horizontal activity.

It can go even higher than that on a flow back savings. So it will be a material savings for us going forward.

So, 1.5 million to 2 million starting in July is kind of the run rate you guys were looking at?

Yes. In addition, if you’re tying into LOE in general, in the first quarter with the reduction in completion activity dramatic reduction compared to the fourth quarter, we had a lot of extra time on our hands.

We took that opportunity to really get after kind of some preventative maintenance projects on older wells and quite a bit of full tubing switch else as well as repairing the wells, get them back on response to the whether events that hit us, hit North Upton extremely hard in the first quarter. So, there were a lot of – there is two things going on with LOE, one more of the one time things in the first quarter than two of these water projects will be taking it down dramatically.

Perfect, that’s great color guys. Thank you.

Thanks a lot Will.

Good morning gentlemen. I firstly wanted to ask you a little bit about the overall well performance per 1000 foot lateral.

I wonder if your primary peers who is in Northwest Midland Counties talked about their Wolfcamp A and B is kind of averaging 132 BOEs per 1000 foot lateral, you’re well over 200, could you just comment Matt on what’s driving that the well performance.

Sure, I can speak to our acreage and our results and even out of the gate our first well on back in January of 2014. We didn’t see those types of rates in the 130s.

We’ve always been north of that. And that’s really driven from what we’re seeing on our cross-sections is just the thickness and depth of our acreage in addition to over 700 foot in our thinnest area in that A and B complex.

And then in addition to that really honing in continuing to refine out petro-physical model working with geosteering and landing in the optimum zone. And we really think that is driving a good bit of the continued increase in our productivity along with continued tweaks on our completion recipe.

And we started pretty aggressive, but we did have safe stages where we’d use some more hybrid of towards the total just to make sure these things got off and we’re more comfortable going straight to slickwater right away now and we’ve increased the portion of the slickwater stages, compress the density. We still have stretch goals.

We put on pause in Q1 pushing those anywhere past to where they were. We didn’t make positive steps compared to the fourth quarter, but we would have pushed more aggressively if we had increased activity.

So we’ll continue to push towards our stretch goals in the back half of the year.

I want to chime in. It’s the same thing that we’ve been saying over and over again in all the conferences, deeper and thicker.

Great, thanks a lot. My second question Bryan, I just wanted to see if I can clarify some comments you made on the Q4 2015 production.

I think you mentioned that you though according to your guidance that production would be up 30% year-on-year. So if I did my math correctly that would imply production around 23.7 Mboe per day, is that correct?

Am I doing that right?

I think that’s a fair calculation.

Okay. And The Street today is I think for next year at 22.2.

So you’d be running ahead of The Street just using that exit rate if I did my math right?

The Street straight average for 2016, yes.

Okay. And just finally, you talked about some middle Sprabeery inventory that you have added, Matt or Bryan can you talk a little bit about what part of your acreage you think the middle Spraberry would be perspective?

We see it over – all of our acreage right now since we have not drilled wells yet, we are only counting inventory in our North Upton piece. But we do have and mapped across all of our acreage.

We'll just – as we’ve done with all of our inventory make sure that we have production was stages near it which we do have confirmed where all counting inventory as well as an additional areas, but we’re – we’ll be quantifying that over time, the additional zones across Reagan and then in Midland. Of course, the acquisition we just picked up in Midland we’re not counting it there, but we have it and then in North [Indiscernible].

Okay, thanks a lot gentlemen.

Thanks.

Thanks, good morning guys.

Good morning, Scott.

I was wondering if I could stay a little bit on scene of your well performance here recently and more specifically on the amount of proppant in the spacing the stages you used. Can you remind us what currently today you’re using or you’re assuming you’re going to use in your wells per lateral foot?

Sure, we’re 1,800 pounds per foot today. We’ve been talking to some other industry constituents across multiple basins but also focused in the Permian.

And they are successfully putting away 2,200 pounds in rock that we identified as similar. We like the results they are seeing.

Of course, that was always internally stretch goal, but it is nice to have someone else that has placed it away successfully. That’s similar loading as us, so it’s just ends up having a much larger stage, more volume pumped per stage and that’s something what we’ll be looking into throughout the back half of the year.

Okay, okay, good. And as you sort of test these limits, what do you think the impact could be on your down spacing you’ve talked now obviously about 660 foot spacing.

Can you talk a little bit regarding the communication that you may or may not see there that you think you could see and how that works with that proppant loading?

We don’t think you’re getting these traditional bi-wing fracs. We think that you’re hitting a very complex stimulated rock volume area.

And it’s all about the area that you connect through these [indiscernible]. And even though these are getting larger and larger for our design if you – if it is a complex swarm, the actual drainage rate is still small on this type of nanodarcy rock and the oil in place.

So it’s all about increasing those areas stimulated rock volume across from the well board and getting away from the traditional planer wings that you would have with more your gel jobs. So I think the 660, especially with the testing that’s going on out there in the basin is not a stretch and then the question will be farther from the 660s down to the 330s the impact on that front.

Okay, thanks for that. And one last question, you’ve all been somewhat of a consolidator over the course of last few years.

What is your view of that market right now? What are the spreads doing from your view?

And do you see some opportunities?

It seems like they are all over the place. So we just came out with this deal with around 5,000 acre and then you are hearing deal is around 30,000 acre, and I would say it continue to be all over the place in the next six months because of oil price volatility.

It is very tight. There is not much left.

To me the only deals that are left are these farmout agreements, formal deals that you have to continue to nurture over the months and months and then you convert the carries into this acquisition costs. But I would say there’s only a couple more private equity guys that are looking to sell and then it’s just going to be tight from then on out.

Understood, thank you.

Hi, good morning guys.

Good morning.

So just a question on the type curves. As you’ve released the $1 million Boe curve for – which is now based on your Wolfcamp A and B results.

So how should we think about modeling the EURs for the Wolfcamp C and the Cline zones and potentially a bit more shallow Spraberry at this point?

I think you’re saying – Rowe, I’m just touching on our type curve that’s all of our wells to date, so that’s 27% tier 1 is included in that million barrel EUR. So they are strong wells out there, but also we’re focusing 80% of our remaining wells on core B.

So pretty robust curves and we’re excited about what we have left to do in the year. Going into the remaining zones, we have not changed our 690 type curve for the sea will decline at this point.

And then I think there is plenty of industry data pointing towards the productivity in the lower Spraberry in the middle Spraberry. We have not released a type curve specifically to that as we have not drilled a horizontal well on our acreage, but there are a lot of offset data across our acreage and we’d anticipate similar results based on again the thickness and the depth of our Spraberry.

This is where the Spraberry have over 60 years of Spraberry production and results that have been very productive in this area. So we would anticipate similar results based on that.

Okay. And just a quick follow up on that.

I mean do you have any tests potentially in 2016 that you’re thinking about potentially delineate the Spraberry there or is that too hard to say right now?

No, I think it’s fair to say that that’s when we would get on it pretty early in 2016 just an overall compared to 2014 plans or reduced activity in 2015 brings the focus among these main ventures that we’re focusing on but early 2016 we definitely want to get after it.

Great. And just one last question would be if you added some chunks of acreage in north Midland, can you talk about your strategy there obviously don’t have as much contiguous blocks up there or just not as much locations relative to north Upton your core area, but are you potentially setting yourselves up to add more scale in acreage in northern Midland over time?

Like I said in previous question, it’s really tight in the core. We’re focused on bolt-ons and anything – especially anything contiguous to our current acreage.

Let’s say about 3,000 acres of the deals that was announced is contiguous to the APC acreage that we acquired last fall.

And also we do operate roughly 110 or so wells just offsetting the small piece we picked up in north Midland, so we do have an operational footprint there. Of course, those wells were lower interest historical wells, but so it is nice to pick up higher interest, nice block in north Midland.

Great, thanks guys.

Good morning guys. Bryan, I’m wonder – I’d know you’ve been asked about this – the acquisition market a few times.

I would like to try to – may be take a little different angle on it – that looks like a great acquisition you made and I would suspect that a lot of that was contiguous because your average lateral length went upon your program is part of guidance. But I’m curious do you see opportunities for these kinds of farmouts as increasing or diminishing and I know the normal thing I would expect is that they were diminished but on the other hand perhaps there is a lot of drilling obligations that people incurred in a different commodity price environment that they’re going to come look at you to help them with.

So how do you see it evolving?

Let me just give you an – well, first of all, these kind of deals that takes time to nurture in its relationship. We started this company seven, eight years ago, so the Parsley name has always helped there.

The core of this deal has – well, I think we’ve been working on this deals for 12 to 18 months, they’ve gotten multiple offers and it’s one of those deals where the family has enough money, they’re not looking at bonus money. They want a working interest.

And so it takes time to figure out and through lawyers what they really want and what their goals are. And on this current deal, 600 of the acres, we paid 12,000 an acre – Wolfcamp B and down.

Now on the farmout 3,000 acres, you got 2000 acres, top of the Spraberry down to Wolfcamp A and 1,000 acres Wolfcamp A and down. Now here is the part that was flexible for Parsley Energy, six obligation wells, three – we need to drill three wells in three years and the next three are in continuous drilling.

Got it, got it. There is a lot of subtlety in that.

And then…

Also with – okay, go ahead.

No, no, go ahead, Bryan. I’m sorry.

We do have 10 to 20 deals that we’ve been working small deals across the counties. And you just don't know when they’re going to land.

These just come in waves and they might come in 18 month, they might come in 6 months and there are similar deals, smaller deals, 2,000 acres chunk here and there. So I can’t really pinpoint when they come, but that’s kind of – you kind of get an idea of our strategy.

Yes. That’s exactly kind of detail I would look for Bryan, thanks for that.

And then going back to your type curve, Matt added a little bit of detail there and said that your million barrel type curve includes 27% of those wells in the – and the actuals are from your tier 1. But the other thing I’m looking at if you look at your slides five and six together, if the million barrel EUR reflects your total of your 30 wells to date, but your wells have been consistently getting better over the last four quarters.

It seems to me that that type curve is going to be biased upward. I mean I know you’re not going to – I know you just came out of the type curve and so…

Any one of this type curve again?

No. Well, I’ve got some questions…

You think…

You think it’s headed up too.

Yes, you’re thinking

Am I wrong in thinking that it’s biased up?

I think you’re correct. We continue to take a conservative approach.

We’ve taken a few quarters for the [indiscernible] and there could potentially be upside over time. We just need to see another handful of wells if we’re going to go there.

All right Bryan, that’s great detail, thanks a lot. I’ll talk to you soon.

Thanks.

Hi, guys good morning.

Good morning Mike.

I just wanted to – I was hoping to get your initial thoughts on 2016 in terms of rig count or activity levels? Thanks.

We’ve gone into 2016 just yet, it’s pretty early in the year, but if we just hold our activity level flat on our exit rate at four rigs in the fourth quarter we’ll be generating signification production growth.

And you look at this new type curve now and I mean the rate of return are generous that really current prices just – so I guess I’m trying to get a sense on further acceleration, desire to do it, it seems like the balance sheet, we got the liquidity, the leverage metrics look fine and as you go into 2016. Just maybe initial thoughts, would want to say at the four or push it higher?

I think the next step and focus for Parsley Energy is what we’re modeling, I think we’re [indiscernible] 30 days and you could see more of an acceleration with our four rigs and we’re starting to see results. We don’t want to just talk about just yet when you see a handful of wells under the 30-day mark and that’s the most exciting thing, we’re looking at future couple of quarters.

Okay. So, maybe a similar rig count, but more actual wells being put online…

There you go…

Okay. All right and also that was encouraging that the average lateral length is increasing over 1000 feet here in the 2015 programs.

I just wanted to check in and to see how we should think about really the whole inventory in terms of your ability to drill these longer laterals and how that’s set to evolve here going into 2016 as well and your ability I guess to continue to push that higher? Thank you.

Your average lateral length is kind of denoted in the footnote on Slide 8 and it did go up as well across the entire inventory position. So, we’ll continue to work the geometry and work with offset partners and potentially evaluating trades where it makes sense with a whole goal of continuing to drive that further longer where we can.

All right, thanks guys, great quarter.

Thank you.

I appreciate it.

Hi, guys.

Hi, John.

Hi, John.

I was looking at Slide 9 where you lay out kind of the proportion of CapEx kind of by quarter along with the rig count. And I’m little surprised that the third quarter CapEx number is bigger than the fourth quarter and I’m just wondering if potentially the third quarter is it just the timing of maybe some infrastructure CapEx that happens to follow that quarter or something else I may be missing?

Yes, as detailed by the bubbles there it’s slightly bigger, it’s likely driven by just the working interest changes between the quarter and timing of spuds.

And could you give me where the backlog on completed well stood at the end of the first quarter?

We don’t have any unusual backlog. We have about one well per rig.

We get on pretty quick after we frack on – that was – after we drill them and that was just baked into our strategy to reduce the entire rig count. So we were reducing the entire capital structure throughout as these costs were coming in.

We wanted to reduce the drilling spread rate and the completion spread rate.

Okay. And then just the last one from me, Matt, you talked about some of the success you’re seeing with the – the fit for purpose rigs and I’m just curious if do you feel like you need to see more on that front before you’d maybe decide to make a big change in kind of go that way.

Is it something could happen in the next months or is this more something we should just look for in 2016?

No, I think we’re very encouraged by it and I think we’ve had good success, actually the first two wells out of the gate. And I think we’re marching that direction.

I think the only thing that we’ll wait on is just quantifying how it rolls through – how it rolls through our models and the like. So we’re proceeding with the work and right now we’re assuming no efficiency gains in our modeling.

But as Bryan mentioned, we’re pretty excited about the impact that it could have. And especially, the first two well downs under our belt, it’s very favorable.

Thanks, guys. Good quarter.

Thanks, John.

Thanks, good morning.

Good morning.

Good morning.

I just wanted, I guess, and I apologize if any of these has been addressed I had some IP issues, but I'm just curious, are you all – do you anticipate doing any in-house testing of the new spacing configurations and if so when?

We already have one location and that’s roughly 660 across and we saw good production results from that. We do have late in the year additional plants in early 2014 – I mean sorry 2016 would be continued spacing testing.

Okay. And then I guess on the testing front when do you think you’ll start putting up more wells in the core area in Reagan and some of that newer acreage you picked up recently?

Well the actives throughout the remainder of the year, pretty good concentration of wells out there and in fact one of the successful fit for purpose rigs that I’ve just discussed was on our acquisition properties. So we’re actively doing that now, yes.

Okay. And then on the cost front, you mentioned with the increased focus in the deeper parts of your core acreage increasing intensity of the wells in the first quarter.

I am just curious how much do you see kind of well costs varying around that $7 million level laid out on slide six across your acreage?

It range anywhere from about $6.5 million to $7.2 million, to $7.3 million on the D&C side right now, it’s from shallowest to deepest.

Okay. And those are current costs?

Those are current costs and another important thing to note is we’re also reflecting our current pre-purchased or pre-committed to casing and of course our contracted rig rates. So when I mention line of sight we know we’ll be running through that casing order and picking up spot casing pricing and then the additional rig which will be at spot pricing and that quickly gets us into that 20% reduction range across the whole well.

And that’s also normalized to 7,000 feet of course our laterals are longer than previously planned, but we’ll be below the 7,000 foot total length.

Okay. And sorry I may have missed it, but for like the second half then what do you think is a kind of reasonable mid point target go over 7,000 foot lateral on a dollar basis?

Well we think that $6.5 million would be a 20% reduction against Q4 and we’d anticipate being close to there on a 7,000 foot lateral on a blended case.

Okay, got it. I appreciate that clarification.

And then any change – last one of mine is just any change to the mix around the EUR or is that – that’s been stated in the past, I’m taking higher in total.

Since we do have – Bryan can give you to the details on the exact modeling, but it is 75% crude in the first portion of the well, since we do have our own data in-house now it is the sliding scale of GOR up to about 2,200 in the out years, these are in the back years. So the full-year – I mean the full total impact on crude percentage is lower than that, but I am try to get a follow-up on the modeling details on those out years.

Great, I appreciate it. Thanks guys.

Good quarter.

Thank you.

Thanks a lot.

Hi, guys. A question on strategy.

What type of the cash flow outspend are you comfortable with in the near-term based on the rates of return you’re seeing? And then how do you think about leverage through the commodity cycle?

Yes, on the leverage front, we try to maintain a conservative approach. 2.5/3 times on looking forward, admittedly we are in that range now, but we’ve got a line of sight to drill through that.

So we expect leverage to come down over the next few quarters. On the out spend, we are outspending this year modestly expect to tap the revolver.

But it’s just a matter of maintaining our leverage and making sure we’ve got sufficient liquidity at all times. So you will expect us to outspend.

We’re looking at a few examples, scenarios we believe we’ll get to $70 or $75 in 2016. We would be about cash flow positive for the year.

Okay, that was helpful. And then with more crude on the medallion pipeline starting up in the second quarter, really in the second half.

Can you just talk a little bit about where you think differentials are going to trend versus where you were in the first quarter?

That’s a tough question. Is that speculation question – are you talking about…

I guess or – more along the lines of your transportation costs, if there's any benefit there from getting more crude on medallion versus trucks?

I think would definitely help with the blowout – if they’re blowout in the future over the next 18 months to two years. I think for now it’s just as competitive truck hauling, I think it’s only like [indiscernible] difference we’re seeing in our truck hauling leases in North Upton.

So the whole idea was efficiency on the lease and moving along during the weather – the winter storms and then protecting us from future Mid-Cush blowouts. So majority of that oils being sold to the market at the moment.

I think it’s a six month rolling contract or is a 12 month.

Yes, once the Permian Express II pipeline gets up and running run we went with a 12-month contract…

12-month contract and then we can pivot that WTI if we want – need to or want to.

All right guys, thanks a lot and that’s helpful.

Thanks a lot.

Good morning and thank you for taking my questions.

Hi, John.

Good morning.

The 29% increase in core locations that’s definitely surprised me to the upside. I was hoping you could potentially breakout may be the percentage of those locations that came from just the lease line regulation change, put some context around that?

We had about 114 locations due to the acquisition in the core and then the remainder would have been due to – going to eight wells across as opposed to six wells across and that lease line helped to justify that split so those were around 300 wells.

I’m sorry, the 300 wells include both the incremental down spacing and the lease line or you’re saying just…

Well, they’re kind of one in the same because we were at 870 feet between wells. The 330 foot lease line offset allows for an optimum spacing of 660 between wells and then you can future – you can fully down space to 330s on a nice slot pattern with no overlap.

We were not able to do that on the 467 foot spacing, so they kind of go hand in hand essentially.

That’s helpful. And then I just wanted to circle back the comments on 4Q production given that you’d probably also have some flush production from horizontal wells that you talked about being about 75% oil early on.

Would it be fair to say that that 4Q oil mix would be above the high end of your full year guidance or can you put any color or context around that?

Yes, John. You’re correct as far as the oil mix in Q4 would expect to be higher than our guidance.

Okay. That’s all I had.

Thanks guys.

Thanks, John.

Hi, good morning. Could you guys touch on the number of completions per quarter given the large step up from 3Q being the lowest and then 4Q being north of 23,000 a day and is that partially driving the difference in – I think John touched on earlier between the 3Q CapEx number being above the 4Q CapEx number?

Yes as far as the completions it’s really tracking our CapEx if you look on Slide 9 kind of the bubbles, it’s going to be back – backward – back half weighted. And then, Paul, I’m sorry, I didn’t catch your second question?

Just on – it’s kind of partially related to that. Just a little bit more detail on the number of completions.

Is it – with the four rigs coming on in June are you guys ramping up with the completions in July, August, September? I'm just trying to get a sense on with 3Q getting lower and then 4Q popping so much on the timing of those and when they are at the quarter?

I think you are right on. There will be a month – a month delay or so once we ring a backup and then so starting in call it July, August, we would have kind of the standard or a stead number of completions per month.

Okay. And then you mentioned being eager to bring forward the value in the Southern Delaware basin.

Is that something we could see in 2016? And could you just provide a little bit more detail in your thoughts going forward there?

We keep talking about it. It would be nice to find incremental capital this year to at least drill one horizontal well this year, but we haven’t made a decision on that yet, but we’re fortunate with this three year extension that we’ve gotten for roughly 22,000 – around 20,000 acres.

So by this time to make decisions and went to focus on capital in that direction. I would definitely say there would be a capital program for 2016.

I think what really has our attention over there is the productivity as the well results and activity marching to the North and East of Reeves and to the south and east [indiscernible] and kind of honing in and pointing right towards our ranch over there. So, in addition, our – our zonal testing on our wells is going very well.

We like what we’re seeing and we’re in very early flow back days on our third well across our horizontal target in the Wolfcamp A. So, we like those results.

And if we can point to some efficiency in hand which we do believe we’re seeing but we just need to quantify it on the Midland Basin side, can open up some capital opportunities there.

Okay. And then I think you mentioned on the new – the three new rigs have been added in June, using the spot market.

Is there any thought on entering into term contracts for those rigs given the lower service costs and an ability to walk in those prices?

There is a little bit of a hesitance on the service side to lock in at the base and additionally as we’re quantifying our efficiency gains, something we might be a little bit hesitant to do as well. So we’ll just do kind of practical contracts on the spot rigs.

When you bring these rigs, you want to see – so it’s nice to get them in month-to-month, watching the cruise and watching the rig, and shuffle the rig, so in this time – at this time in a moment in time and over the next three to six months, it will be month-to-month probably on the number of rigs out in the Permian basin and then you’ll start getting tight again.

Okay, thanks for taking my questions.

Thanks again for joining us and for your interest in Parsley Energy. We look forward to seeing you all at the end of June, there are three conferences we’re spreading out and we appreciate the call.