Industrias Peñoles, S.A.B. de C.V.

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

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

Thanks, Brad. Q4 was another quarter filled with milestones and accomplishments.

Matt and Ryan will cover the details, but I'll hit a few of the highlights. First of all, as you can see on slide four, we grew oil volumes 27% in one quarter, all through the drill bits.

Growth of this magnitude is generally accomplished over the course of years, not quarters. So, this is a tremendous accomplishment.

Speaking of years, years of hard work and investment are starting to pay off in the Southern Delaware. We mapped and acquired a Trees Ranch prospect in 2013, and we spent much of 2014 and 2015 exploring and understanding the asset.

Now, our hard work is starting to pay off. So far, the results from our first horizontal well in the Southern Delaware couldn't be more favorable.

We said previously that, for the Southern Delaware to compete with our Midland Basin portfolio, we'd want to see productivity on par with our Midland Basin Wolfcamp program. While the Trees State 16-1H tied for the second-highest scaled 30-day IP rate, we posted as a company 252 Boe per day per thousand completed feet.

We're absolutely thrilled with this result and also pleased with robust productivity from the non-op well we participated at the edge of our acreage. All of which makes us excited about the future for Parsley Energy in the Southern Delaware Basin.

During Q4, we also saw a solid result from our first Lower Spraberry well. We bolted on another desirable asset in the heart of our Midland Basin core area for a favorable price, and we made significant progress on unit costs as well.

All in all, it was a fitting end to a pretty remarkable year given the circumstances. Looking ahead, enthusiasm is tempered at a time like this, but we continue to believe we have a lot to look forward to this year.

Slide five outlines our current plan for the rest of 2016. Based on current strip prices, our plan is to continue to drill and complete at a steady clip.

Operational momentum is an elusive phenomenon that we're keen to maintain. As of now, we plan to drill and complete 60 to 70 gross horizontal wells this year, including a handful of wells in the Southern Delaware.

Adding in facilities and infrastructure capital, along with a few vertical wells, we expect to spend $380 million to $430 million this year. And we project to generate production growth of around 40%, with oil growth more like 60%.

It's our conviction that maintaining an industry-leading growth rate will enhance full cycle value creation. We've discussed before how, for Parsley, growth and returns go hand-in-hand.

This is a function of several things, including unit cost compression and also, uniquely for Parsley, increasing oil volumes as a percent of total production. At strip prices, our Wolfcamp wells generated returns above 35%, driven by our basin-leading Wolfcamp productivity and low costs.

And given where we are in our corporate lifecycle, the trajectory of our cost and efficiency gains is steep, pushing our returns upward even if commodity prices remain depressed. We have a durable inventory of premier horizontal drilling locations now supplemented by high-quality inventory in the Southern Delaware Basin.

And we've strengthened our balance sheet, such that ongoing growth does not compromise our financial strength. Finally, as I mentioned a minute ago, continuing to grow and maintaining the operational momentum we've worked hard to generate, it minimizes the friction costs associated with starts and stops.

So, continued growth makes a lot of sense for us. That only makes sense if you position the company forward, and that is exactly what we've done.

Our hedging program and capital markets activity have been sized to allow us to drill through a downturn of the magnitude and duration we are experiencing without moving outside of our leverage and liquidity comfort zones. If we hadn't taken steps to further strengthen our financial position, would we be doing anything different?

Yes, we would. But the fact is, we made these decisions in anticipation of this scenario.

These decisions bought us time. If oil prices are still plodding along in a few months, we'll reevaluate.

But for now, this is an opportunity for us to stay a step ahead. Last year, we were a step ahead when we were among the first to stack rigs.

We were a step ahead when we get land on hedges, and we're a step ahead when we raised equity in September in a much more favorable market context. Now, we hope to be a step ahead if things turn around.

I want to note that we are not compelled to maintain activity because of lease holding obligations. In fact, close to 80% of our core acreage is held by production.

So, the majority of our development plans is truly discretionary, which means both that we truly believe it is the best path to top-tier value creation and also that we could certainly drop rigs if necessary. Matt and Ryan will elaborate on several of these points.

I'll finish by saying that while obviously we'd all hope for a more favorable commodity context, we're pleased with how we're positioned for this year and how our 2016 plans to allow us to carry momentum into 2017 as well. Matt?

Thanks, Bryan. One of the ways we strive to stay a step ahead is by continuously high-grading our asset base, and these efforts took several forms last year.

Slide six shows that through acquisitions, divestitures and trades, we added close to 400 net locations and extended 70 laterals for $178 million. And as the graphic shows, the inventory we added is in a very desirable portion of the Midland Basin.

All told, we increased not just the depth of our inventory, but also its average quality and average working interest. Our high-grading initiatives are part of an ongoing effort to build an enduring inventory of high-return drilling locations.

As you can see on slide seven, we increased our horizontal inventory by 36% last year and also increased the percentage of the inventory in our core area from 67% to 77%. Counting just our most proven target formations, the Wolfcamp A and B horizons, we have almost 1,000 horizontal drilling locations.

So, as Bryan noted, we have plenty of running room to continue at a steady development pace. Turning now to the operational front.

There were several exciting developments in Q4. Broadly speaking, we're in the midst of a pretty significant corporate transition.

As recently as the fall, we completed our first pad wells. Given how successful our initial pads have been, our development program going forward is likely to consist primarily of pad wells with a smattering of stand-alone wells where appropriate.

The obvious benefit of pad drilling is efficiency. And as you can see on slide eight, we're certainly spending less time and money drilling and completing these wells.

There's also a less obvious benefit of pad drilling that may prove even more important, and that's enhanced reservoir stimulation, which translates to improved productivity. It's still early, but we really like what we're seeing with our Wolfcamp A/B pad combinations.

Take our Robbie pad for example, a two-well Wolfcamp A/B pad in north Upton County. We highlighted the Wolfcamp B well last quarter, noting that it generated a staggering 24-hour IP of more than 550 Boe per day per thousand completed feet.

That well went on to establish a company-record 30-day IP rate of 260 Boe per day per thousand completed feet. Meanwhile, the Wolfcamp A well on the Robbie pad has been our strongest Wolfcamp A to-date, generating almost 30,000 barrels of oil during its peak 30-day period.

And the Robbie wells weren't our only record setters last quarter. A Wolfcamp B well on our Bast lease in Reagan County produced more than 43,000 barrels of oil during its peak 30-day period, setting a new company record for first-month cumulative production.

This is noteworthy in that this well is situated where our recent bolt-on activity has been focused. We've also executed our record spud to reach TD horizontal in just eight days on a 5,019 foot lateral in Reagan County.

So, our Wolfcamp machine continues to hum along, setting the pace in the Midland Basin. As you can see on the chart in slide 10, we continue to outperform our million Boe Wolfcamp-type curve, with outperformance increasing the longer the wells are on production.

As we've emphasized before, this data includes all of our 55 Wolfcamp A and B wells with production history, so we're not cherry-picking here. Bryan noted our strong returns profile.

Slide 11 shows that we're above 35% returns at strip pricing, with NPV approaching $5 million per well. We've included year-ago returns to show how cost reductions have enhanced our return profile, a trend we expect to continue.

Our first Lower Spraberry well posted solid results out of the gate on par with offset wells in the area. As is typically the case in lower pressure zones, the IP rates weren't as high on – as on our Wolfcamp wells, registering close to 600 Boe per day during the peak 30 days on a one mile lateral.

It's an encouraging result, and one we look forward to building on. As with any first well in a new formation, we learned quite a bit and plan to make a few adjustments to our completion and lift designs and also keep narrowing down the optimal target interval.

All in all, we remain very positive on the value of our Lower Spraberry inventory. Turning to the Southern Delaware.

It's becoming clear that our excitement has been warranted. As Bryan mentioned, we couldn't have asked for a better start to our horizontal drilling program on our Trees Ranch acreage.

Importantly, we drilled the Trees State 16-1H in less than 20 days, with the D&C cost coming in under $6 million. Team that with productivity at 252 Boe per thousand completed feet, a high oil cut of 81% and strong offset results, and you can begin to share in our excitement.

The non-op well drilled onto the northwest corner of our acreage was another positive data point, producing close to 1,200 barrels of oil per day over its peak 30-day period on an 8,300 foot lateral. The results from these two wells are consistent with the most prolific wells we've seen in the Wolfcamp Phantom field to the northwest, several of which are listed on slide 12.

Given these results and the exploratory work we've done, we think the value of this asset is substantial. It's a large contiguous block that's ideally suited for long lateral development.

And just like in the Midland Basin, we've been high-grading in the Southern Delaware. We picked up some acreage in the area while letting go of a small portion of our acreage that came up on the Central Basin Platform.

At this point, 99% of our Southern Delaware acreage is secured through 2018, so explorations aren't on the horizon. We completed the Trees State 16-1H in the upper portion of the upper Wolfcamp, the flow unit that at this point looks the most uniformly productive across our acreage.

As you can see on slide 12, we have 3,000 feet of Wolfcamp to work with. Our vertical exploration wells have produced from much of this 3,000-foot interval as well as the Pennsylvanian, the Mississippian and the Woodford intervals, and that's not to mention the third Bone, which has been productive to the northwest.

So we definitely think there is potential for additional flow units. There are different ways to slice and dice location counts, and we're still working on our optimized development plan.

But for now, we'll note that we estimate something in the neighborhood of 1 million lateral feet on our risked acreage on just a single Wolfcamp flow unit. Additional flow units would, of course, add to that total.

We're sufficiently encouraged by everything we've seen, and we plan to allocate additional capital to the Southern Delaware with three to five wells planned for the second half of the year. As you can see on slide 13, 2015 was a great year for us in terms of infrastructure build-out.

Often, these types of projects have lengthy payback periods, but we are already seeing significant returns on our investments. We connected 80 miles of gathering system last year, which enabled us to reduce the percent of water hauled from 45% in Q1 to 18% in Q4.

LOE in general has been on a consistent downward trend thanks to the execution of a myriad initiatives capably implemented by our field personnel. In addition, at the beginning of 2015, we were truck hauling all of our oil.

Today, we're only hauling around half of our oil. Higher volumes on pipe have led to lower transport fees in recent quarters.

Additional acreage dedication should push us up to 75% of oil volumes on pipe and translate to additional declines in transport costs. All told, we expect to have shaved $0.60 to $0.70 off our oil transport costs per barrel by the second half of this year, which flows through our realized prices.

Among the things we are looking forward to in the coming quarters are evaluating upper and lower Wolfcamp B flow units in the Midland Basin, appraising the Wolfcamp C formation, honing our Spraberry well design and rounding out our understanding of the Southern Delaware acreage. So, it was a great quarter, a great year, and we have a lot more to come.

And now I'll hand off to Ryan.

Thanks, Matt. On the financial front, we saw several strong trends in the fourth quarter.

Despite significantly lower commodity prices, adjusted EBITDAX increased 25% versus Q3 to $58 million in Q4, driven by higher volumes and lower unit cost. We're very pleased with substantial progress on unit cost.

As you can see on slide 14, LOE per Boe decreased 27% quarter-over-quarter, down more than $4 per Boe relative to the first quarter of 2015. The primary drivers of the favorable LOE trend are lower well failure rates and the reduced water hauling expense Matt discussed, both of which we expect to sustain.

The G&A trend is also quite favorable, with cash G&A per Boe down 36% quarter-over-quarter to $4.41 per Boe in Q4. Reported CapEx came in at $84 million during Q4, including $7 million of non-op spending.

This is down 30% quarter-over-quarter as our AFEs start to catch up with our actual expenses, despite the fact that, not including the non-op well, we completed seven more wells in Q4 than in Q3. More horizontal and vertical completions than planned, higher average working interest of 95% and the lateral links close to 6,900 feet on average pushed Q4 CapEx slightly above our expectation, but a 30% sequential decline is a strong trend and bodes well for our run rate this year.

Fourth quarter production of 25.2 MBoe per day was up 17% versus Q3, putting us right at the midpoint of our annual guidance at 22 MBoe per day for the full year, which is up 55% compared to 2014. Oil growth was especially strong in Q4, up 27% quarter-over-quarter and now up to 63% of total production volumes.

As we have discussed previously, we expect this trend continuing this year. In discussing our 2016 capital program, Bryan mentioned our financial strength.

We've been very deliberate about managing our leverage and liquidity. And as you can see on slide 15, we're in an even stronger position entering 2016 than we were entering 2015.

Pro forma for the acquisition we announced in December, liquidity is up to $770 million and our leverage ratio is down to 1.5 times. Slide 16 details our hedge position.

We're fully hedged on expected oil volumes this year, and we've continued to add a substantial hedge position over the first half of 2017 as well, redeploying proceeds from rolling down put spreads that were set to expire during the first half of 2016. Brad or I can walk you through the mechanics of the roll-downs, if you like.

Just remember, when you see lower strike prices in the first half of the year, that we've captured the value of the original positions. Turning to our 2016 outlook on slide 17.

The midpoint of our $380 million to $430 million CapEx range is flat compared to full year 2015 CapEx, despite the fact that, at the midpoint, we expect to complete 17 more horizontal wells in 2016 than we completed in 2015, including several wells and a new play for us. So, we expect significantly lower completed well costs this year than last.

Facilities and infrastructure should comprise roughly 10% to 15% of total CapEx in 2016. We will be drilling a handful of vertical wells to hold leases.

In light of current industry focus on longer laterals, it's worth mentioning that we expect our average lateral length on the horizontal wells we drill this year to be around 7,000 feet. The midpoint of our production guidance range implies year-over-year growth of more than 40%.

And again, we expect oil growth in the neighborhood of 60% as oil as a percent of total production increases from 60% in 2015 to 65% to 70% this year. This is on top of almost 70% growth in oil volumes in 2015 versus 2014.

Last quarter, we mentioned that we expected to hit 30 MBoe per day at some point during Q1. And in fact despite a slow January, we recently produced a 30 MBoe with a wave of pad wells, hitting production.

We're very proud of this accomplishment, considering 30 MBoe per day is up almost 40% from our Q3 2015 average. Together the midpoints of our LOE and G&A guidance ranges are almost $2.50 lower than our 2015 averages, a material boost to operating margins, especially in this commodity price environment.

Adding in anticipated savings in transport costs really boosts our cash margin per Boe. It's worth explaining that our ranges are a function of typical variability in the metrics we guide to, not different plans.

A few wells faster or slower than usual or a few wells above or below cost projections span the width of the range. In other words, what we are providing is a range of outcomes associated with a particular plan not a range of possible plans.

I'll also note that we expect to deliver significantly more production growth per dollar spent than our peers this year, as you can see on the chart on the bottom right of the slide. Finally, turning to slide 18, we posted strong reserve growth in 2015, despite substantial macro headwinds.

We grew proved reserves by 36% year-over-year with minimal contribution from acquisitions. Pricing changes limited reserve growth to a considerable extent, making our additions even more impressive.

To echo Bryan and Matt's comments, we're happy with the way we executed in 2015 and the way we positioned ourselves for another strong year. With that, operator, we'd like to take questions.

Morning, guys. Nice update.

Say, Bryan, when you just look – or you or Matt, obviously the production growth this year certainly above most others out there. How do you think about sort of low end versus high end?

And again, how do you think this positions yourselves for 2017?

I'd say – Hi, Neal. Good to talk to you.

I'd say that the low end itself is a 36% growth rate year-over-year, so pretty substantial. And I'd point to – if you just smooth it out over the year, requirement of 2,000 barrel a day average quarter-by-quarter and that's just the low end.

So, pretty robust growth and transitioning to pads, which went into effect in the back half of the year. It probably won't be as smooth as that 2,000 barrels a day every quarter.

Maybe a little front-end and back-end weighted on the full year.

Got it, got it. And then, the transition to 2017, it looks like – again, given the rigs, it looks like growth should continue.

We're not – this is Bryan. We're not going to comment on 2017.

We've put in a lot of hard work in the past couple months on 2016. We just released it, so give us some time to start thinking about 2017.

Okay. And then – fair enough.

And then, just lastly, guys, it looks like you just updated a little bit just on the Midland core as well as the Tier 1 as well as the Southern Del just on your position. Can you just comment there, I mean, how you view kind of that core versus the Tier 1?

And I know you guys are always looking to block up things. Is there – I guess my question around that, is there more to block up here in the near term or would there have to be another separate M&A deal?

We're always working. We always have brokers running in our core areas and little small pieces, 80s and 160 acres that extends our acreage.

It's always getting harder and harder. Sometimes, it takes a few months to get some deals through, but we're always going to look anything that's contiguous to our acreage in the core and Tier 1.

I kind of think of it as one and the same with our west Reagan results that we're seeing, very similar to Upton County. And then, also, we're going to use the same kind of broker network in the Southern Delaware with these new well results.

Makes sense. Thank you, all.

Thanks. And a little bit of a follow-up to that last answer.

As you look at the Southern Delaware, can you discuss in general your view of the continuity of your acreage position? It looks pretty big.

Does that lend itself to long laterals? And how much opportunity really down there in your view is there for picking up more acreage or doing some kind of swaps?

Yeah, Scott. We're really positioned in a tremendous setup for long lateral development, a large contiguous block there.

It's quite different on how we built the Midland Basin position starting in 2008. So, fortunate to be able to have that larger contiguous block.

And as we've said, we're still optimizing our development plans and – but we have the ability to slice and dice the way we want to for pure optimization. We're not really looking at any offset operators as far as trades right now just because of the contiguous nature of our block and the amount of running room we have on that current position.

So, it'd all probably be new adds at that point.

Okay. And just in general, I mean, you talked about that really thick section you've got there.

When you step back and look at it, 26,000 acres in a thick section, it seems it lends itself to that it's helping a big resource opportunity. When you drill these three to five wells in the back half of the year, are you going to use some delineation of that interval?

Or are you right now more concerned with let's just get a sense of this upper portion and get more comfortable with it at this time?

Yeah. I think, in this commodity environment, you have to be cognizant of delineation versus appraisal.

And with our – the 3D seismic that we do have and the work we've been putting onto this asset since 2013, we have a good feeling for what the rock looks like across the position and we want to focus on getting some strong wells done down in a concentrated area, maybe working on a pad well or two. So, I think it will be optimizing the zone in the current area as opposed to stepping outside of the 3D seismic or anything like that.

Okay. Thanks.

And if I could do one more. And, Bryan, I appreciate the fact that it's probably way too early to think about 2017 right now.

I guess, you guys are a little advantaged in 2016 where you've got a great balance sheet and a good hedge book. Big picture, maybe if you could just talk strategically, as you look forward, if you do see an environment where we've got lower for longer.

And obviously, that will obviously have an impact on your hedge book as you roll into 2017. How do you look at managing the business?

Is it some form of leverage metric? Some form of optimizing your development plan?

How do you look at that?

So, I think one goal is definitely to stay south of 3.0 net debt-to-EBITDA. That's probably one of the first things I'd look at over the next year or two.

The important thing is I'm trying to maintain this growth rate also. So, we're in a very unique position.

And when you taper back on this growth, it's really, really hard to get it back. Let's say we came out with two rigs or three rigs this year, it's hard to get it back, coming back, walking back into 2017 if you look at your model because of the declined rates of the most recent wells.

But I'm trying to think – I missed the second half of your question, I think. I think I answered you, but that's just kind of my thinking.

And then, also, the hedges, we also continue to add hedges. It doesn't matter where they are at.

So, if it's 40, we're going to add 40s. In one year, we're going to add 30s a year out.

We're going to take advantage of the contango curve. And usually, the hedges march towards the spot price.

I appreciate that. That's good color.

Thanks.

Good morning to you, Bryan, and to the rest of your team there. I think I'm going to...

Hi, Charles.

Hammer you a little bit more on this, but maybe from a different angle. I really like your comments about operational momentum being, I think you said, an elusive phenomena.

And sticking just with 2016, you've got this $400 million capital program, you're flat on a spending basis but kind of up on an activity basis versus 2015. As you're getting into the back half of 2016, how would you look at steering the ship six months ahead if the strip as it currently stands bears out?

Well, our hedges is one tool that we have, and I think we got some higher short puts in the back half and you've seen us to be proactive in rolling down our put spread, so we collect on that position and we put it on the new position to collect more if we're in the same exact environment that we are in today. So, let's say $30 oil, if we're in $30 oil in the back half, I feel like we will capture even more value because of our hedge book.

So, it kind of gives us flexibility to keep marching forward and drill for 35% returns. I also believe that costs are going to continue to come down.

The new recent frac bids have come in, and we're seeing 10% to 15% reduction on our frac bids. Then also, we have new pipe price orders 50% less from 12 months ago.

So, you're seeing some serious downward movement on our AFEs. So, it's just going to offset – continue to offset the price environment.

Now, if you're at a $24 – let's say we're at $25, $24 for a couple of months. I think it's – that would be a time to kind of taper back maybe on – let go of a rig.

We have one rig with a month-to-month contract. And so, it's not when oil just goes $26 for like three days and it bounces back up to $32, I don't think that's going to push us to reduce rig activity.

I think you need to see it for four to six weeks up to eight weeks.

And, Charles, just to add to that, the operational momentum, it's almost a compounding effect when you're the only hotel with a vacancy sign and still open for business, all the vendors are coming our direction. We're working with them closely to keep them active and to be able to continue drilling wells at good, strong returns.

Got it, Matt. It's like you are the hot nightclub in town or something.

If I could shift and ask about the – those – the Trees Ranch wells, Matt, I'm wondering – if I recall correctly, that Wolfcamp zone in the Delaware Basin was over pressured. And I'm wondering if you can – if that's correct, can you talk about how – I know it's early days, but how those wells are declining?

And if there is – if there are any similar – or how are they similar or different from the analogs to the northwest in that same trend?

We are seeing outsized pressure, geo pressure in the area, and they follow a typical shale well decline. But due to the pressure, they're going to start higher.

And also the additional pressure may help in certain areas go on artificial lift a little later, so you could flow a little longer. It could help early time LOE.

We do not push down as deep into the pressure cell as we could have across that 3,000-foot interval by design, first well out of the gate getting the drilling done. We did achieve the drilling and completion there for under $6 million, so that was a big goal coming out of the gate is to operationally get a well down.

So – but all in all, the pressures are very good, and it's unique to have pressures – geo-pressured high oil content in combination. Usually, you start seeing your additional pressured zone over towards your condensate window of these shale plays, so it's a very unique setting for this play.

And so, that – is that one of the distinguishing characteristics from the trend as it moves through the northwest?

Yes. As you move farther to the northwest, your oil content goes down.

You do get deeper into the basin, so your pressure gradient is probably the same, but your absolute pressures can go up but your oil content goes down. So, we are in the oil window.

That's great detail, Matt. Thanks a lot.

Yeah.

Good morning, guys. I wanted to stick on the Delaware here and maybe just kind of get your thoughts of – from a big picture standpoint, what do you guys kind of need to see, whether it's commodity prices, more well results or whatnot, to get more comfortable with maybe a development program, parking a rig and busting out some of these Wolfcamp wells out in the Trees area?

Yeah. I think just with our inventory and kind of the stellar results we have in the Midland Basin, we are – and the lease situation in the Delaware, we don't have any obligations, so we're able to take it in this commodity environment cautiously.

So, I think three to five wells is a – is kind of cautiously aggressive. And I think, after the results of those, we'll take a look at the environment at that point and decide on keeping a rig running or staggering it in.

I think we do have the confidence if commodity prices were to rally or were $10 higher today, we would have one rig over there and four rigs running in the Midland Basin. I mean, we're kind of forming our own new asset or new oil and gas company over there.

Okay. That's helpful.

And then, just kind of thinking about well costs, I think you guys mentioned a minute ago that you're seeing some bids come in lower. Can you just kind of talk about I guess what you guys are kind of thinking as far as we progress through the year, where well costs can go taking those into account along with more pad drilling and kind of expectations of where well costs can go this year?

We do bake in a little bit of additional cost reductions versus the $5.5 million that we have posted in the slides throughout the year. We'll tell you that we already have two wells, actuals in under the belt.

These are 1 1/2-mile laterals that came in D&C in the Midland Basin side under $5 million. We're not using that in the model, but there's no reason to think that it can't get there over time, especially what we're seeing just in the last week or two for our recent bids.

Perfect. Thanks for the color.

I'll hop back in the queue.

Hey, guys. Thanks.

Just a question on your reserve adds in the Midland Basin last year. I'm wondering if you can provide us with the average EUR that Netherland, Sewell gave you credit for in both the Wolfcamp B and A and whether or not there was any difference between the EURs for your PDP adds and your PUD adds?

I don't have the specific details handy on – by bench. But there was about a – we cross-reference with our internal data and there's a – across the board, we always want to make sure we're within 10% and we were both on PDP and PUDs from our internal views and Netherland, Sewell's views.

And all that internal data is driven to drive our current type curves, which is more of a P50 actual. And of course reserves are booked on a P90 situation, so 90% certain you will meet or exceed, not a 50% chance you'll be on target.

So, everything came in in line and we can follow up with specific granularity, perhaps we can get those pulled for you.

Okay. So, the overall average, though, was relatively close to your type curve, is that safe to assume?

I think, on a reserve basis, it's going to be lower than the type curve that we present only because it's booked on a reserve basis of P90 versus a most likely of outcome...

Okay.

So it's a certainty switch, but they're off the same curves and there's no – if you put the probability distribution out there, there's no – they're on the same distribution so...

Okay. So, as we get more performance, it's likely that you could see some upwards performance revisions.

Is that the way to think about it?

That's right. We actually had positive performance revisions this year.

There were no negative PUD performance revisions in the books, and we consider that – we anticipate that to continue ongoing over time.

Okay. And then, I'm just trying to get a sense for how sensitive the EUR bookings are to price.

If we take your latest wells around 1 million barrels or so or even higher than that with the outperformance you're seeing, is there much of a difference in what EUR you can book between sort of a $90 oil price scenario and let's say a $30 flat scenario? I mean, as prices go lower, you would presumably lose some of the tail in the out years.

Is that the right...

Yeah. You start losing your tail.

The PV-10 impact hopefully does not go in the same rate. I mean it kind of follows the oil price reduction, and then the EUR impact is not as dramatic as it usually just hits the tail of the EURs.

Okay...

They do run at a lower price, our horizontal PUDs.

Okay. And then, I think the Trees Ranch well came online in November, if I'm not mistaken.

Was that well included in your year-end reserves? And if so, can you tell us what that was booked at?

We may have had a marker placement in there, but they really need to see about six months of production before they'll put a full PUD – PDP curve...

Okay.

On those wells.

That makes sense. Thanks.

Hey. Good morning, guys.

Over in the Delaware Basin, I think you mentioned the first well came in a little bit under $6 million. Any thoughts on where you might be able to get that in development mode?

And also, what do you think the costs would be on some of the longer lateral wells, maybe the 7,500 foot or 10,000 footers? And maybe any plans to test the longer lateral wells this year?

Yes. Our pads that we have penned on the books are going to be longer laterals in the back half of the year.

And our – that non-op well that we participated in, the Cilantro, it came in at about $8.5 million D&C. It was a very long lateral, but that was in the October timeframe on the drilling side, so the cost of change.

I think, when you just look at it, you're probably going to be at 5% to 10% additional costs when you get into development mode versus our Midland Basin activity due to the pressures in the rock that we're drilling through.

Okay. That's helpful.

And I guess, just on the down spacing side, maybe any thoughts around some of that on your acreage? It seems like other operators around the basin are trying to push the limits on how tight you can push these wells together.

Maybe any thoughts on whether or not you'd be able to do a little bit more than eight wells per section on your acreage. And do you have any pilots planned maybe for later this year or 2017?

We're still focusing on our multiple B bench delineation and upper B and a lower B. We just still have a lot of running room to assess this thickness of our benches.

We have five or so wells that are actually producing out of the upper B. And I think, now, we're going to test throughout the year in upper and lower B in the same area.

So, for us, we're still delineating the actual landing horizons stake in our area, and we have a lot of running room there that we're excited about. We do believe that there's potential clearly to down space.

And that's not something – aside from the 660 spacing development that will continue on, this year is not something that we're testing any 330s.

Okay. Thank you.

Hey, guys. Good morning.

Good morning.

Matt, you named a number of operational initiatives that you guys are going to be working on in 2016. And really, I just kind of wanted to get your sense of what you're the most excited about?

What do you think has the most potential to add incremental value? Thanks.

Yeah, Mike, it is just kind of all across-the-board. We have participated and initiated an electrical commission that we meet with other operators and the PUC and our electrical guys are getting our build-out done much quicker and then also tying in long-term lease electrification right when the well is ready as opposed to a month or two down the road.

That reduces generator costs that had been constantly carried on a run rate per well previously and were down. Across almost 700 wells, we have less than 60 generators running out there in the field.

So, that's a huge testament to that type of initiative, and we see that across-the-board on just coordinating initiatives with different vendors and operators. We're – I may have missed your question though.

Did you say delineation?

Yeah. More so probably just on all the certain tests, whether it's the upper B are going back and testing the Delaware again.

Just what do you think kind of has maybe the most upside potential?

I apologize, Mike. Brad had to kick me in my leg there.

So, yeah, it is going to be focused on multiple zones within the B this year, especially in our northwest Reagan area and where we just acquired acreage. Our last two acquisitions, we see a lot potential for multiple B targets.

And then, the geos are continuing to identify and due to offset operator results in Reagan County, a C bench, so we will have one well targeting the C. We have additional Lower Spraberry well on the books.

This will be a long lateral. I'd like to note in that well, D&C cost was $4.7 million.

So, that well was drilled very efficiently. It helps to offset the lower IPs that we see.

So, we're looking forward to a long lateral test in the Lower Spraberry there as well. So, in this environment, you want to stick to a lot of the bread and butter, but we still have a lot of good things going on, on the delineation front.

Okay. Great.

And I just got to ask you, on the Southern Delaware, maybe just in ballpark kind of gut feel terms, how much of your position do you think is de-risked? And then, just curious if we could expect you guys to get maybe more aggressive on the leasing from there after these strong initial results?

Thanks.

On the de-risked part, internally we feel very comfortable. It's – we had a 3D seismic, so it's safe to say that about – on the high side 20% of our acreage, we wouldn't categorize as a resource play.

As you get east of our 47 – our vertical wells in the 47 block, that acreage is outside of resource play. Inside of that acreage, we have 3D seismic covering the whole shoot and of course this vertical testing.

So, we feel internally, essentially de-risked and – but it does take time to put the wells – horizontal wells across the footprint.

We have the logs that ran, three open-hole logs in the vertical wells and we have mapped towards the northwest and the rock looks very similar. And so, we were actually very confident before we even drilled the horizontal well.

So, that's why we ended up drilling it. So, I would say we are moving from moderate risk to low risk in this area.

So we're very excited about that. Sure enough, we knew that we're going to re-lease these wells, so we've had brokers running.

We knew that this would cause a lot of attention. We know there is a lot of private equity – some private equity companies in the area.

So, we're competing with them. We think this area is going to start really picking up on leases and acquisitions.

Okay. Great.

And should we expect you to participate in that, Bryan?

Participate in...

Just the...

M&A?

Yeah.

Yeah, yeah, we – I think it's raising – I'm going to mention price per acre. I think it's $5 up to $10 maybe.

There might be up to $15 where things really heat up, if oil rallies another $10 to $15, but it's not at the Midland Basin. But we're picking up acreage right now and there could be some acquisitions in the future.

It'd be nice to pick up barrels with it, but it seems like it's the same thing in the Midland Basin. Private equity guys have a lot of acreage.

That's great...

Luckily, we have lots of running room with our current position with the 30,000 acres.

Got it. Thanks a lot, guys.

Nice quarter, everyone. Just a quick question on the LOE.

So, if I look at your 4Q per unit number of 557 of Boe, it already seems consistent with the low end of your 2016 full year guidance of 550 Boe to 650 Boe. Is there anything going on with either 4Q or 2016 to be aware of as volumes continue to ramp?

Is – or is there some level of conservatism baked in there?

Well, historically speaking, we always see a little bit of true-ups and closeouts even on the LOE side at the end of the year and we get back on the run rate in the beginning of the year. So, we want to see that come through.

But when we screen out the per well forecast, there might be a little bit of conservatism in there. But we'll see how things unfold as the year rolls out.

Great. And then, just a quick question on slide 16, the volumes hedge by quarter.

I think you may have hinted at this earlier in the call, but should I think of those volumes on the top row of that chart reflecting high level anticipated quarter-by-quarter production trends? So, 2Q having the lowest volume hedged and then ramping in the back half of the year, is that just how the hedge book shook out?

That's really how the hedge book shook out. I mean, it's – I wouldn't read that oil is going down in Q2.

I mean, it's – given the variability and timing of pads, it's tough to match up our barrels month-by-month. But generally, it would make sense that the hedge book builds in the latter half of the year, as we expect more oil being produced then.

Great. Thank you.

Thanks.

Yeah, hey. Good morning, guys.

Good morning.

If you could talk about your first Lower Spraberry well and what do you take from that and sort of translate into the longer lateral well that you plan to drill?

Yeah. I think it is a decent result given the length of the lateral and these things produce on a flatter profile than the Wolfcamp wells.

It's a first really application for us on a couple of different lift mechanisms and flow-back procedures that we'll be tweaking on our second well, and we look forward to – I think when you look at the industry norm from these wells, they're in between 110 Boe and 130 Boe to 140 Boe per thousand feet. This one was 119 Boe, kind of landed right in there.

And our well cost was extremely low. So, looking forward to additional – to landing it there.

All right. And then, just quick – or two quick ones about the 2016 guidance.

Are all the rigs going to be, for the time being – before one scoots over to the Delaware, are all the rigs going to be in your core area?

Yes, they will. Yeah, the – as you mentioned, the fourth rig will run over to the Delaware beginning mid-year.

And is the average lateral length – given your well costs, look at the trend in the well costs, look at your de-linear efficiencies, is that average lateral length just a function of lease geometry?

Yes. We would drill longer in areas where we have the ability to do so, so that's simply lease geometry in the areas we've chosen to drill.

About...

Would it...

About a quarter of our inventory is 10,000 foot laterals, so we do have the ability to completely front-load in certain areas, if we chose to.

Got you. Great.

Thank you.

Thanks.

Hi. Good morning, everyone, and congrats on a – thanks for squeezing me in here.

I just have one question. So, we spent a lot of time on infrastructure expansion in the Midland.

Can you maybe just talk about infrastructure in the Southern Delaware? And I understand that, with three to five wells in 2016, it probably won't be an issue.

But do you have any constraints that maybe keep you from ramping more quickly than you'd want in the future?

Yeah, we're in a very fortunate position on the Delaware. If you look at our position in the map, of course Pecos County, we're kind of the first stop.

We're kind of the crossroads of infrastructure. There's the Waha Hub that is where gas pricing was set and NGLs were set for a long time, just to the west of our acreage.

So, there's large plants, there's large pipes that come into the area. Electrical transmission lines come through the north side of our field.

So, as we get to development mode and really build out those long-lead items, they're all kind of right there. Right now, it's just a matter of negotiating a fair price for us on, you pick the infrastructure line item, and we want to put our most robust plan together with the parties that we're negotiating with before we tie into that.

So, it's more a matter of negotiations as opposed to location of the infrastructure for us.

Got it. That's all for me.

Thank you very much.

Thanks.

Good morning, guys. Matt, I think you mentioned in the prepared remarks a potential appraisal for Wolfcamp C this year.

If so, when will that well be spud? And I guess, any expectations you have?

Sorry. Can you repeat the well?

The C?

Yeah, the Wolfcamp C formation?

Should be in the back half of the year right now also. It will probably be spud right around the turn of the second and third quarter.

Okay. Will that be in the northern Upton area?

Not currently, no. It's going to be in our kind of Reagan core area.

C – we don't see C up in Martin County. And then, as you go into south Midland it starts appearing, it starts getting thick and thicker in the Upton.

And I'd say it's the thickest in Reagan County.

Okay. Thanks.

And then, in terms of completions, I know you guys have pushed in terms of concentrations of sand per thousand feet. And you guys have kind of been on the forefront of that being small and nimble.

I'm curious where your current well design is in terms of proppant load. And where do you see that trending?

And if you've kind of reached diminishing returns in terms of enhanced completions.

Back in the summer of 2015, we saw our productivity start to break over. We still saw an increase, but we chose to kind of hold pat in the design being cost conscious.

And we've continued to do so. We do have a couple of wells on the books in 2016 that will be pushing again for us.

We haven't pumped those wells yet.

Okay. Thanks for all the detail today, guys.

Good morning. Just one more question on the Delaware.

So just looking at your operated well result. At least, on the first 30 days, it's about 40% or so more productive than the non-op well that you have a working interest in as well as two Jagged Peak wells just further west.

And the oil cut is pretty similar. So, I'm just kind of curious what your all thoughts on what could be driving that higher productivity and if there is any difference in completion recipe between your wells and Jagged Peak.

I think those guys are doing great work being the tip of the spear out there in the Southern Delaware. I would say that I think 3D seismic really helps in this area in resolving items to within one frequency really helps with landing.

And aside from that, you just have a short lateral versus a long lateral. But I think the production trends are relatively similar.

So, I don't know that there's just a lot to read into that. There are different completion techniques between the two, and I think we'll wait as time unfolds to see kind of which one is working in the long run a little better.

But both are coming from a very good place. I did want to follow up on an earlier call.

We do have some PUDs booked offsetting that Delaware well and on a reserve base again lower due to a reserve base, but – and it's a placeholder since you only had two months of data, but it was at 700 MBoe at that point.

Okay. And maybe just one last question, if I could squeeze one in.

Just on the 2016 budget, your estimated 57 to 65 Midland Basin completions, is there a rough split you all can provide between Upton and Reagan County? Thanks.

We are closer to 50-50 this year. I think we were a little lower than that in Upton last year.

Great. That's all I needed.

Thanks.

Thank you, and good morning. Could you discuss how you're approaching hedging in 2017 and maybe periods beyond, and whether that approach will differ much to how 2016 oil volumes were hedged in talking about the put spread structure?

That's it for me, and have a great day.

Hello, Dan. I think you're going to see partially continue to use the put spread structure.

It served us well in higher times and now lower times. Historically, we've tried to hedge a couple of years out.

That strategy has changed a little bit just because of where prices are right now. But you saw us in January and early February add to our first half 2017 position.

I think, as you get closer to 2017, we're going to want to have the back half of the year hedged as well. And so, at some point, we will bite the bullet and add those positions out there if...

After a rally.

After a rally, exactly.

Very good. Thank you.

Thanks.

I think that's...

Sorry, go ahead.

I appreciate everyone taking the call, and we look forward to talking about the Delaware story in the upcoming conferences next month. Thanks.