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. We're off to a great start in 2016, with strong quarterly production growth, as usual, up 15% versus Q4.

Oil growth was even stronger at 20%. We spud 20 horizontal wells during the quarter and completed 15 horizontal wells, all in the Midland Basin.

So we are right on track for the 65 wells to 75 wells we expect for the year. Last quarter, we reported very encouraging well results on our Southern Delaware acreage.

And this quarter we doubled down in the Southern Delaware, adding around 14,000 net acres to bring our total there to more than 40,000 net acres. As our confidence in the Southern Delaware grew, we launched a section-by-section leasing program centered on our existing acreage position.

You'll notice on slide five that we've been filling in the few holes that remained on our Trees Ranch prospect on the Reeves/Pecos border. And we've also extended the edges of that acreage block.

These additions are strategic for several reasons, including the fact that they extend lateral potential and allow us to consolidate facilities. The larger acquisition we announced a few weeks ago accelerates our expansion program and gives us the critical mass necessary to make this Southern Delaware an integral part of our development program.

Firmly entrenching the Southern Delaware, we now have a larger opportunity set for accretive transactions like the one we announced in April. And we also have leverage to an up and coming part of the Permian that's in an even earlier inning than the Midland Basin.

In many ways, the packets we acquired in Reeves and Ward Counties to the west of our existing position is an extension of that position on the other side of the Waha gas field. The acquired acreage has a thick Wolfcamp interval that is right for development and that would be our initial target.

We have included inventory into Southern Delaware yet, so we're taking the same approach to estimating development potential on the acquired acreage as we did on our existing acreage. Based on just one flow unit in the upper Wolfcamp formation, we estimate that we're adding something in the neighborhood of 700,000 drillable lateral feet.

This is on top of the million lateral feet we previously estimated on our existing Southern Delaware acreage. And we see upside on the acquisition acreage from additional Wolfcamp flow units and both Bone Spring targets as well.

So we're going to get busy on the acreage right away and currently plan to drill three wells on the acquired acreage during the second half of the year. This is on top of the handful of wells we'd already planned for the Southern Delaware.

We plan to move one of our rigs over to the Delaware mid-year and then likely bring it back to the Midland Basin after drilling a few wells. At this point, once it moves over, it will likely stay in the Delaware through the end of the year.

Moving to slide six, we're always excited to add to our acreage position in the heart of the Midland Basin. During the first quarter, we drew on our standard playbook, completing a couple of privately negotiated transactions that add around 9,000 net acres.

As in the Southern Delaware, a good portion of these acquisitions represent erect bolt-ons on existing positions, so we're both adding locations and lengthening existing locations. All of these are in great neighborhoods, essentially returns equivalent when you factor in expected productivity and costs, and more than 10% of the increase in Midland Basin acreage comes from working interest buyouts, which we view as a particularly efficient use of capital.

So we're thrilled to add these assets to our portfolio. All told, we added almost 23,000 net acres, which increases our acreage footprint by almost 20%.

So these are significant transactions that bolster our ability to deliver high return production growth for many years. For now, Parsley is one of a very few companies that has chosen to maintain activity levels this year.

Nothing has changed our thinking since we announced our capital growth plan in February, and with the positive trend in oil prices in recent weeks, our plan is really working out perfectly, especially as we continue to push on the cost front. So we feel like we have the wind at our back, realized prices are going up with a oilier mix, unit costs are coming down with greater scale, we're delivering strong Wolfcamp wells, we're just scratching the surface in the Southern Delaware, and we're looking forward to some promising appraisal activity in Midland Basin as well.

And we're also maintaining the operational momentum that's so important to us that Matt can discuss in more detail. Matt?

Thanks, Bryan. We certainly have strong momentum as we continue to execute in all phases.

As you can see on slide seven, our Midland Basin Wolfcamp wells continue to show positive separation relative to our type curve, especially as you get out to 180 days of production and beyond, which bodes well for ultimate recoveries. Slide eight show that we continue to experience favorable cost trends.

These windows of time when oil prices are rising and service and equipment costs are falling are rare and we're fortunate to be maintaining healthy activity levels at a time like this. D&C costs were down another 5% during the first quarter, averaging around $5.2 million for a 7,000-foot lateral Wolfcamp well.

And leading edge costs are lower still. With oil prices up and costs down, estimated returns are back up close to 60% at strip pricing, with NPV per well around $6 million.

Turning to slide nine, our transition to pad is essentially complete and we're experiencing the type of benefits we expected. Among the wells that achieve 30-day peak production period since our last update, I want to highlight a three-well pad on our Atkins lease in north Upton County.

Together, these three wells, two of which were completed in the Wolfcamp B formation with the middle well in the Wolfcamp A zone, produced almost 100,000 barrels of oil during their peak 30-day periods and a Wolfcamp A well established a company record 30-day IP rate for Wolfcamp A well at 1,883 Boe per day, or 242 Boe per day per 1,000 feet. This has been a typical pattern for us as we've seen a clear uplift on our Wolfcamp A productivity since going to B/A pads.

So not only are we seeing lower costs per well in our pads, we're seeing higher productivity as well. We think what's happening is called stress shadowing, where we find the right vertical spacing that allows for stress plane alteration, but not hydraulic communication.

We are effectively squeezing the sponge and adding complexity to the fracture network by applying pressure from an adjoining formation. All this leads to enhanced returns compared to single-well development.

The chart in the upper right quadrant of the slide is new. We're estimating around $1 million of cost savings on a three-well pad relative to three single wells, not including a slight reduction in LOE based on centralized compression.

So, assuming all of those cost savings, we now show the return and PV uplift associated with different levels of productivity enhancement. To pick a point, assuming just a 5% increase in well performance, we expect around a 6% increase in project returns, which translates to PV increase of more than $2.5 million across the three-well project.

Turning to slide 10, we were very encouraged with initial production rates on our first operated well in the Southern Delaware and also on the non-op well on the edge of our acreage. We're equally encouraged by their production trajectories over the last few months.

Just for reference, we've plotted their cumulative production against our 1 million Boe Midland Basin Wolfcamp curve, as you can see. Both wells are handedly outpacing the curve when normalized to 7,000 feet.

Moving to slide 11, I'd like to talk for a minute about the acreage we added in Southern Delaware. When we first stepped out into the Delaware Basin in Pecos County in 2013, we knew it was off the radar, but situated in a really favorable depositional environment.

Our Trees Ranch area is bounded to the west by the Waha gas field to the south by the Coyanosa Wolfcamp field and to – on the eastern edge by the Central Basin platform. Essentially, it's an extension of the Wolfcamp Phantom field to the northwest.

As Bryan noted, what we've just picked up a few miles to the west is in some ways an extension of our Trees Ranch position wrapped around the Waha gas field. It's a traditional Southern Delaware acreage that operators have been getting comfortable with for a good while now.

As you can tell, the average thickness of the Wolfcamp complex in our newly acquired acreage is similar to that on our Trees Ranch position. So, we're optimistic about multiple Wolfcamp flow units across the Southern Delaware portfolio.

Wolfcamp complex in this area is deep, but not too deep, highly pressured, but not cooked too long. As you move much farther to the west in Reeves County, you get into a gassier regime, but all of our acreage is comfortably in the black oil window.

There's plenty of thickness in the Bone Spring to support the possibility of perhaps two flow units in that complex as well. In fact, when operators started drilling in this area a few years ago, they were after the Bone Spring, focus quickly shifted to the Wolfcamp, given the kind of results people got, but now operators are starting to apply the latest and greatest techniques to the Bone Spring, so that's certainly a promising formation for us.

And we have the rights to the whole column in the Delaware, so we'll evaluate deeper intervals, too. People have asked us how the Southern Delaware is likely to stack up relative to our Midland Basin returns.

It's a high bar, considering the Midland Basin returns are among the best in the industry, but there's no reason to think our Southern Delaware assets couldn't support similar returns. It's still early, but we can certainly envision productivity in the Southern Delaware that rivals our best Midland Basin wells, which would leave costs as a crucial variable.

The Wolfcamp is a bit deeper on the Delaware side than on the Midland side. So, all else equal, that might lead to a slight cost uplift, but we actually set a company record for the most vertical footage drilled in 24 hours on our first Southern Delaware horizontal well.

And in fact, we drilled this well in less than 20 days for under $6 million, which is a tremendous out of the gate result. We've already identified a number of line items that should come down as we get more established in the Delaware, not to mention savings associated with the transition to pads.

For example, we used our highest day rate rig on our first well, which was also burdened by weather delays that contributed to an expensive mobilization from the Midland Basin. We'll also be able to wean off some of the redundancies we always build in when tackling a new formation in a new area.

All in all, we already have line in sight to several hundred thousand dollars or so of savings compared to our first horizontal well, which came in at an encouraging low cost to begin with. Zooming out, in general, the Delaware is more structurally complex than much of the Midland Basin, but that's painting with a really broad brush.

Our Trees Ranch area is relatively quiet from a structural perspective and we plan to evaluate seismic data on the new piece as well. So we don't see any reason we can't come within 5% to 10% of our Midland Basin D&C costs over in the Southern Delaware.

Combine that with top tier productivity and you have an exceptional return profile. Back in the Midland Basin, we have several exciting projects on tap.

Among these is a long lateral Lower Spraberry well this summer. This will be our second Lower Spraberry well and we have a couple of design tweaks planned that should help that well get off to a more productive start than our first.

We have a couple of stacked upper Wolfcamp B and lower Wolfcamp B tests coming this fall, which could really be transformative in terms of inventory upside. And then we'll drill a Wolfcamp C well around the end of the year or early next year.

Further out, base focus in 2017 will be understanding well spacing. Just focusing on Lower Spraberry, the Wolfcamp A and the Wolfcamp B on a fully down spaced scenario, we could have 58 wells per section when you incorporate a second Wolfcamp B flow unit.

Currently, we count no more than 24 wells per section in these intervals, with nothing counted yet in the upper Wolfcamp B. So clearly, a lot of upside if we can achieve even a fraction of these possibilities.

There's a lot of talk these days about completion optimization, and this is an area in which we've really been ahead of the curve. We are one of the first companies to go to slick water in the Wolfcamp and then ramp up to tighter stage spacing and higher proppant loading.

There aren't many secrets in this business, so it's no surprise to see convergence on many of these variables. We've been holding pad around 170 feet between stages and 1,700 to 1,800 pounds of sand per foot for several quarters now, but we're gearing up for what we're calling a monster frac in a couple of months.

Essentially, we're going to push the limits on both fluid volume and proppant loading where we have very good control wells as offsets. And then we'll work backwards to find the sweet spot for productivity and costs.

We're not talking 2X or anything like that, but we'll start with something around 40% to 50% and go from there. We're also going to test brown sand in our core area where we've historically used higher cost white sand, so it will be exciting to see what we find.

And the great thing is that whatever we benefit, we will see on top of basin-leading Wolfcamp performance to start. I also want to mention that LOE has been a big focus for us over the last year.

And on slide 12, you can see the tremendous progress we've made. We've spoken before about our infrastructure build-out and how it has reduced our dependence on water hauling and that is certainly an important part of the effort.

But more fundamentally, we're doing a great job keeping our wells up and running. Fewer interventions mean lower LOE and that's what we're experiencing.

A lot of proactive efforts on weatherization and well maintenance have led to favorable run times, so kudos to the team up and down the operational chain. So, like Bryan said, it's a great start to the year, and now I'll pass over to Ryan.

Thanks, Matt. Adjusted EBITDAX declined by 5% in the first quarter to $55.4 million, holding up well in the face of a 20% decline in oil prices.

Matt mentioned the favorable trend in LOE per Boe, which was down to $5.25. Cash G&A per Boe was up seasonally to $6.25, burdened by full year vacation accruals and non-recurring relocation expenses associated with moving our last couple departments from Midland to Austin.

We expect to be back in our guidance range of $4.75 to $5.75 next quarter and trending lower over the course of the year. B&A (16:23) per Boe decreased by more than $3 versus Q4 as a reserve growth outpaced strong production growth.

Reported CapEx came in at $110 million in Q1, on track with full year guidance. Reported capital expenditures include costs associated with the horizontal drilling activity we've discussed, as well as one vertical well and three of the six saltwater disposal wells we plan for the year.

It's worth repeating that first quarter production of 29.1 MBoe per day was up 15% versus Q4. Oil growth was especially strong, up 20% quarter-over-quarter and now up to 65% of total production volumes.

As we have discussed previously, we see this trend continuing this year. As indicated on slide 13, we continue to enjoy an advantaged financial profile.

Pro forma for the acquisitions and equity offering we announced last month, we have around $740 million of liquidity and our leverage ratio is at 1.7 times. During our spring redetermination process, our banks indicated we had room to increase our borrowing base in sharp contrast to broader industry trends.

But given that we remained undrawn at the end of the quarter, we chose to keep the facility at $575 million to limit associated expenses. We're also happy to be one of only three companies upgraded by Moody's out of 165 energy companies under review.

Slide 14 shows our hedge position. We're well covered on oil volumes for the next several quarters and we've been building out our position in the second half of 2017 as well.

We show full-year guidance on slide 15, in conjunction with the acquisitions we announced last month, we increased production guidance by 1,500 barrels a day to account for acquired PDP, which we should get for a little over half of a year and also a handful of drilled and uncompleted wells that will be folded in over the second half of the year. We also increased our CapEx guidance by $30 million at that time to account for the DUCs, a couple incremental wells are still in the Delaware, and related facilities and infrastructure expense, especially on the Delaware side.

Accordingly, we increased our expected gross horizontal completions from a range of 60 wells to 70 wells to a range of 65 wells to 75 wells. All this puts us on track for the leading production growth this year and we look forward to continuing our run of strong execution and results.

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

Good morning, guys. I would like to ask a question about the – your transition to pad development and how that interacts with the emergence of these other zones.

I think this quarter we had that – you had the really good Wolfcamp A results. But when you – when, Matt, you laid out the plans for the rest of the year about testing upper and lower Wolfcamp B and things like that, I am curious: how much has your pad development or your kind of plan for your pads changed, say, the last six months because of the emergence of the Wolfcamp A perhaps and then how much might it have to change?

And how will that change the way you guys approach the back half of 2016 and 2017 if you're successful with more of these zones?

Hey, Charles. Well, it has been dramatic.

We go through a well selection process about 12 months ahead of time, but we've been reshuffling the deck, no doubt, given the results of our pad success. But they also go hand-in-hand when we look at testing the stacked As and Bs, and then also the intra-Bs.

It's beneficial to drill that from a pad position and get results on like acreage. So it does take some reshuffling, but it's out a few months in advance and teams get the work done and come forward with new and better proposals, and having the pad as a tool has really been a benefit to us.

So are you having to change your whole pad design, for example, that maybe the tank batteries or just the physical space you had on the surface with the emergence of additional zones, or is that not an issue?

No, not an issue versus a -- three-well pad is a three-well pad from a surface standpoint, and so really not an issue on that front. And then going to a pad from multi-single development on a lease when we drill out a development plan, it's actually more surface efficient from that point.

So really not – a non-issue on the surface.

Got it. Thanks.

And then a question about the Delaware Basin stuff. It looks like the two wells – or your one operated well, your one non-operated well are up there in the northwest portion of your, call it, your legacy position.

Then you guys added going to the west. Is there anything to read into about the prospectivity of most of your legacy position going down to the southeast?

Or do you have any – are any of your late 2016 or early 2017 wells going to test that position further to the south and east?

Think slide 11 in our contour map is a good proxy to look at there. Really in that small area on that red shallow contour, that's where you're coming up on the platform.

We've always risked that as less prospective for resource horizontal development. But we do have seismic over the entire footprint.

And as we come to the south and east of our active operated well, we see very smooth contours and can map the flow unit to the south and east all the way down to the edge of our seismic. So really no large differences until you get up on to that red acreage for us on the Central Basin platform, which is already taken out of our lateral footage.

So we don't see any material differencing – differences there in the flow unit going to the south and east. You get slightly shallower, but if we were to remove our acreage and you just looked at the contour map, you would see a light blue depression in that whole piece.

And that's where we always came up with that Catcher's Mitt nomenclature. But in 2016, we'll be probably drilling the obligatory wells with this exploratory – with the package we just picked up.

And then a new pad well – pad project on our Trees, so that's going to really be 2017 before we drill to the south and the east.

Got it. That's where I was going with that.

Thanks, Matt.

You're welcome.

Yeah. Thanks a lot.

If we could stay on the Southern Delaware, could you discuss as you keep that rig in area for the second half of 2016, what is really the plan or the goal? How do you tend to look at evaluating the prospectivity here?

And is it just to test some of the deeper stuff, or could we expect some Bone Springs in there? Will there be any kind of spacing assessment?

So what is the goal for 2016?

I think we look at it as its own business unit and it's got to support itself on its own and generate some production, some cash flow. So you want to get a good foundation under your belt, and then you start assessing other zones in spacing and the whole enchilada in 2017.

So we have a productive zone, an economic zone working phenomenally out of the gate, and we'll focus on that – on just a few well project here in 2016 and then expand the program in 2017 most likely.

Okay. That's good.

Thanks. And on the upper Wolfcamp B, obviously you discussed the potential for 58 wells per section.

And when you go to test that, is that the plan to test that kind of spacing right away, or are you going to gradually move into that? And if you can maybe provide us some color on your view of confidence in having two zones based on offset data or just geological data across your acreage.

We have over 10 producing wells out of the secondary zone within the Wolfcamp B. So we have a high degree of confidence of the discrete production out of that target zone.

So we'll be in the back half of the year targeting intra-B stacks and see the result from those together in one tight area. And then as far as the 58 wells across, tremendous opportunity set, a lot of modeling and a lot of resources to go in to plan that out properly.

2016, if not the focus for 2016 down-spacing will really be another 2017 project.

Hey, it's Bryan. The 10 wells, I think, majority are – all of them were acquired wells and drilled and fraced.

All, yes, majority of the wells. So this will be the first time we're going to do it ourselves and then test them with the lower Wolfcamp B well.

Okay, okay. And so certainly you're not going to push the envelope here with these initial wells.

It's just to test the productivity of the upper along with the lower, is that correct?

That's right. Stacks right on top of each other in the same area.

So they'll be right on top of each other, not staggered at all, is that right?

That's right.

Okay. Understood.

Thanks.

Good morning, guys. So I'm trying to get an idea, you mentioned that in part of Scott's question as well, the 58 wells potential per section.

Is that now just in that area, or is there potential now if you would move up just a bit, I guess it would actually be a bit east on that? Could you do that in other areas, or is that just in that one sort of area or that section?

Well, we have leading Wolfcamp thickness across our Midland Basin. Our thinnest Wolfcamp B is in the neighborhood of 400 feet and it expands out to 750 feet to 800 feet.

So this will be in kind of the middle. The first test out of the gate will be in middle thickness around 600 feet of targeted thickness.

So we certainly feel like it would extrapolate to the thicker areas and we still think 400 feet is sufficient, but I would expect we'd want additional test at some point down the line before we do multiple Bs in our north Upton area, stacked Bs.

No, got it, got it. And I guess, Bryan, maybe a question for you.

Given what you and Matt have been saying this morning, I guess, how good the Southern Del type curves are looking, obviously even versus the Midland, when you think about further acquisitions, are you agnostic as far as adding more down around your Southern Del position versus potentially finding more up in the Midland?

Yeah. I mean, we're very fortunate that we officially have two backyards.

And so we can kind of bird dog both backyards and we are surrounded by potential acreage in the Delaware. It just takes time.

You have to – I've mentioned in other calls, you have to nurture the relationships and hopefully you can acquire or lease more acreage through time.

Got it, got it. And then, one last one, if I could.

Just I noticed maybe a little bit more further north in the Delaware, I don't know if the same holds true to the southern, as far as the way some people are letting, you know, just kind of opening these wells up and letting them go initially. Your thoughts on that, I mean is the availability, or I guess the opportunity to do the same down south, and if so, are you still thinking more of a managed choke program or how do you think about that?

Out the gate we've taken the same approach we have to our Midland Basin side to set a baseline where we do have some build, fluid per hour limitations for the first few days, and then hit a cap there and then they come off. So I don't see us going particularly more aggressive on a wide open manner in the first few wells out of the gate until we set a good baseline.

Thanks so much, Matt. Thanks again, Bryan.

Hey, good morning, everyone, and congrats on the results. So as you guys mentioned, you're already delivering some of the best growth in the industry.

We're also seeing oil move quite a bit higher since you reported 4Q. So I guess, I'm just trying to understand, what's your decision-making process around potentially stepping more aggressively on the accelerator at this point?

Is there a certain oil price? Is there something else?

If you could just give some color around that.

I think we're – there's only maybe a handful of E&Ps that increase CapEx year-on-year. I felt like we came out with pretty stellar CapEx program for this year and we just need to focus on the four rigs running with oil prices rallying.

To me, that's just kind of gravy and wind at our back. If we acquire something, maybe we need to add a rig right away, but we're really looking into 2017 on rig adds.

Got it, thanks. I appreciate that.

And so just to follow up, so I mean, you guys talked about expanding the program in the Southern Delaware next year. So is the plan to kind of do what you guys are doing this year and move the rigs back and forth, or is it to pick up a new rig?

It's early coming into 2017, but we wouldn't want to move rigs back and forth. We would want that to support itself on its own business unit and have constant rig.

Got it, thanks. And just one quick one.

Matt, I might have missed this in the prepared remarks. You mentioned the monster frac.

Where is that located and can you maybe just rehash again the details around what exactly you guys are doing there and the incremental cost of that frac?

It's going to be in the Midland Basin. It's going to be central to our position – our activity position in the Midland Basin.

And it forecasts out to roughly $900,000 to $1 million of additional expenditure on the full stimulation costs. We're going to go up in the 40% range on pounds per foot as well as volume of fluid per foot and go from there.

Appreciate it. Thanks again, guys.

Thanks, Jason.

Just intrigued by stress shadowing concept that you talked about. Curious if, in your experience was that influenced by the prop mix or the prop in volume or any other stimulation techniques that you used, if you can throw some color on it?

No. It takes us a long time on our completion optimization to set baselines and change one variable at a time.

So as we unfolded our pad drilling, we kept our completion design the same. The only difference was having B wells stacked right next to an A well.

So that's really the only difference on our early results. Now, we have those under our belt, we can start pushing on physical completion design again.

Okay. And then with any M&A, you're often posed with the question of how do you bring the value forward, especially when you do an equity raise today.

So just thinking and I appreciate your clarity on the Delaware part, but when you think about that Midland part of the acquisition, are there any plans to sort of put rigs to work on that acreage?

We've been very fortunate with the rig acceleration. And when we acquire, we just add locations in those slots, but I think we're starting to get pretty full there.

So future acquisitions, you're correct. I think we need to add a rig to get a return on the acquisition costs.

And then as an update – and this is my final, as an update to boost your acquisitions, how do you look at the acreage value in both the Delaware and Midland, if you can throw just broad comments and you've seen the bid-ask narrow and then just the relative valuation between the two basins.

In the Midland Basin, I'm still seeing average around $20,000 an acre. Oil prices have rallied, but I think deals can still be done there.

And then the Delaware, it ranges from $5,000 to $15,000. It just depends on how much development.

I mean, Delaware's just – we're in such early innings on the Delaware, so the bid-ask is going to be a lot wider.

Thanks, Bryan.

Thank you.

Hi. Good morning, everybody.

Congrats on a good quarter.

Thank you.

Just on the M&A that you just mentioned, can you describe if you've seen any change over the last three months to six months or any change more recently with – we're hearing the bid-ask spreads coming a little bit on some of the stuff, but can you just generally address that?

What I've noticed the past six weeks is the deal flow is picking up and I know it's picking up with our competitors too from when I go to the Midland and talk with our competitors and talk to other private equity guys. It seems like the sellers are finally willing.

You just don't want to sell at $26 oil and everyone's been waiting, digging in, drawing the line in the sand, and now we're hearing more chatter from the investment banks that some – the investors are coming from larger companies or selling portfolio companies and private equity. It's picked up the past six weeks.

Ordinarily, we're tightening our borders. We're focusing on non-op working interest in our wells in Upton County and Reagan County and we're going to be very selective of this pickup in deal flow.

Okay. That's helpful.

And I'm not sure if Matt or Bryan you actually addressed this, maybe I missed it but what – the thoughts on 2017, you talked about rig adds, but like what magnitude kind of how should we – I know you can't give guidance yet, but any big picture, thoughts or framework around 2017?

It would be nice to be above 50, if I'm thinking about adding a rig, a fifth or a sixth rig. I'm seeing average price above $50 or costs continue to trend downward.

If we just stuck in this environment, a range between $40 and $45 and the same costs, we could potentially still be at four rigs going into 2017, just depending on the environment.

Okay. And then final question, just on costs, not that this is a new topic, but with all the efficiencies, kind of where are service costs?

Just given the uptick in pricing – uptick in crude pricing in the strip, are you seeing any difference in service providers as far as what they are asking on day rate type stuff or spot rate? Can you just talk about the current service environment?

No, David, we're really not. We're still seeing selective reductions across line items, but we are keeping a close eye on it and trying to be good partners and -- with the people we're active with -- and they are in business to be in business as well.

So we see slower cost reductions lately, on the magnitude of 5% to 10%.

Okay. Thanks, Matt.

Thanks, Bryan.

Thank you.

Good morning, guys.

Good morning, John.

When I look at the legacy Southern Delaware position, is the best way to think about it in terms of the activity the next six months, seven months, is it similar to the Trees State well, that the activity will sort of be -- stay kind of around where those three existing vertical wells are located?

Yeah.

We have some obligation wells.

Well, that's in the legacy. And the obligation wells on the new – we'll have – with the new acreage we just picked up, they had some expirations coming up that we have to get to pretty quickly, and of course, we'll be drilling those wells.

Right. But the legacy stuff, just around the three existing verticals?

That's right, yeah.

Okay. And then you mentioned that you're going to look at testing brown sand.

Can you just remind me now with how much sand prices have come down, like what the savings would be if successful using the brown?

If successful, that's another $200,000 to $250,000 of savings on our north Upton wells.

Great. And then if I could sneak one more in, just to follow up on the productivity uplift you all have seen, when you go to the pad development, I'm curious: does that cause you all to have to move or think about consider moving towards, I guess, bigger pad developments?

Instead of doing like the two-well pad, you started moving more to bigger pads to get the basically what you all are calling the stress shadowing effect?

Yeah. I think that's definitely part of the 2017 analysis on – as it goes hand-in-hand with the 58-well concept and how many of these do you hit out of the gate.

So today, we have multiple two well pads, multiple three well pads, and going in through 2017, there's definitely the ability to drill more at one time to work that stress shadow benefit across a multi-bench interval.

Thanks, guys. I appreciate it.

Thanks.

Thanks.

Hey, guys. Good morning.

Good morning.

On the monster frac, just curious what you hope to see in terms of maybe an uplift in the EUR, what you need to see in order to justify that extra cost, Matt. Thanks.

Well, it's right at $1 million additional on the D&C side and we get about a $1.5 million NPV uplift on a 5% to 10% uplift in performance. So it doesn't take a lot in an absolute sense in a stabilized oil price environment to realize the payout on that.

That's kind of the magnitude we would be needing, that kind of uplift to generate a payout.

Okay; great. Maybe a question for Bryan, just given all your comments this morning on the Southern Delaware and the data points on the maps just look great.

Do you think there really deserves to be a discount here between acreage costs in the Delaware versus the Midland? And if you guys could pick up acreage at $5,000 an acre to $10,000 an acre, are you just wanting to do that all day in this environment knowing where you think that could go?

Thanks.

If you just look at the early innings of Midland Basin, it was all about Wolfcamp B. And then a few months later – or I think six months later, Wolfcamp A talk and then about six months later, Spraberry – and then two Spraberry benches.

So, that's the difference in price per acre to me and there just needs to be – it's going to take a couple of years for the prices really to come all the way up to Midland Basin because there's value in two benches to three benches or four benches in the Midland Basin compared to the one bench in the Delaware.

Got it. That makes sense.

Thanks a lot, guys.

All right. Thanks.

Good morning. When you look at your spud times, they have improved quarter-over-quarter.

You did 20 wells this quarter versus 15 wells in 4Q. Was that all attributed to pad drilling, or are you also just being more efficient with the drill bit?

And do you think you have more room for improvement?

Yes. So, all of the above, pads are a contributor to per-well cycle times.

We've made physical well design changes and drilling parameter changes that continue to press – that would be here to stay in a recovery mode. So I do think we'll continue to see a grind-down both on a per well efficiency gain and then spud – we track full spud-to-spud and that's, of course, where the pad efficiencies gain is, on your rig moves and the like.

And then going over and looking at the two horizontal wells in the Delaware, the outperformance that you're seeing versus the Midland type curve, I mean is that due to a shallow decline? Are you seeing higher pressure?

Do they slow naturally longer? Can you give us any clarity on that?

We are over-pressured. So I would say pressure is the main driver.

The rock quality is fairly similar, maybe slightly better here in the Delaware. And then you team that with overpressure and it really pushes the productivity and the rates.

And then it – but as far as the profile, it's matching the decline curves of our Midland Basin side essentially. So, it's really a parallel uplift in productivity.

Okay, great. Thank you.

Thank you.

Good morning, guys. I was wondering if you could give us some quick color on the infrastructure situation out in the Southern Delaware.

Would you guys characterize it as pretty sparse at this point or reasonably well developed?

I would say reasonably well developed for our footprint. We're fortunate as most of the infrastructure gets built out from the Midland Basin side to the west, all the barrels go back to that direction and we're kind of the first stop.

We're at crossroads on our physical acreage footprint, which is very fortunate. So, it's very competitive for our barrels and for our guests and continued to work those arrangements and I'd say it's reasonably well built out.

Okay. That makes sense.

But when you guys are running a full-time rig out there, do you see an uptick in kind of the – or from the $50 million to $60 million a year infrastructure CapEx up to something higher than that? Or do you think that run rate will stay pretty similar going forward?

I think on a percentage basis, it stays similar. We generally don't spend – our infrastructure CapEx is usually on our water gathering systems and disposal.

We'll continue to do that build-out in Delaware. So probably on the order of 15%, maybe 20% depending on how active we get with the rig count and how quickly, and the Midland Basin side will be in the 15% to 10% as we get more developed.

All right. Sounds good.

Nice quarter, guys.

Thanks.

Thanks.

Hey, guys. Just a quick one on the low LOE unit costs in the quarter, as you discussed.

Could you walk through how to think about that through the rest of the year? I know, on one hand, the growing volumes and the transition of pads should drive unit LOE continuing to go lower, but I know the recent acquisitions included about a 100 vertical wells with higher costs so trying to think about those offsetting forces and how to – if there is anything else to consider.

Yeah. The only thing really additional to consider there is really active acquisition on the acquisition front in Q1.

So we want to get those acquired wells in-house and know what we're dealing with there before we look forward on a full year. But those are mainly vertical wells.

So on an absolute basis, it may not have a material impact. So we're definitely optimistic on the LOE front on the full year.

Got it. Okay.

So you're waiting to get the asset package into the portfolio and then figure out what you want to do with the full year guidance from there?

That's right.

Great. Thanks, guys.

Good morning, guys.

Good morning, Jeff.

Wanted to kind of get your take on the Delaware side of things. It seems like you guys have gotten a tremendous amount of benefit from the ownership of the 3D seismic shoot on Trees Ranch.

Do you guys feel that something like that is critical for development out there on the horizontal front and just thinking about the Reeves County position, does that interest you to get some 3D out there, or do you think that based on well control and development out there, that that's not necessarily critical going forward?

Yeah. You're absolutely right.

We've got a lot of benefit from that and continue to glean additional information from it that we think will optimize on a point forward. We have the team in-house now that has gone through full cycle on that geophysical front.

So I think we'd make that par for the course before we aggressively develop out here. There is more good definitely that can come from it versus against the cost of acquiring it.

So definitely would presume to have drill a seismic out here.

Okay. And, Matt, do you have an idea on what that type of shoot would cost you guys if you wanted that over that Reeves County acreage, or is it a bit early to get a quote on that?

It's a little bit early. It's probably 30% less on a square than what we saw when we shot our Trees Ranch.

But the other thing to consider is, as we work to the west, there is quite a bit of active and previous shoots that we can purchase off the shelf whereas that was not the case for our Trees position and that's where you see a significant cost savings. So we're in the middle of analyzing those right now.

And if they are to the full dataset that we want and if they are, it should be a minimal cost and otherwise we'll just go shoot our own.

Got it. That's helpful.

And then the only other one for me, just kind of wondering kind of longer-term performance on your first Lower Spraberry well now that you got another quarter of data, just kind of how that's tracking if you have any kind of EUR number that you could share?

Yes, performance is doing a traditional Spraberry flat as a pancake. For the last three months, it's been 250 Boe a day perpetually flat.

So the only thing we need to work on is the initial rates. And again, that was some wellbore design on our side, limited pump sizing due to the casing design and things of that order.

And then the other thing to remember is that was only a 5,000-foot long lateral. I think most Spraberry wells drill their longer laterals on the production front.

So our second well out of the gate will be a two-mile lateral.

Great. Appreciate the time.

Good quarter.

Thank you.

Thanks. I had a quick question on the Southern Delaware.

I understand it's still early. But on the Bone Spring, you mentioned potentially two flow units.

Based on what you know, is this more of a sand or a shale that you could potentially target down the road?

It does have more silica influence in the shales traditionally, in the northern Bone Spring. As we get down into our area, we get a little bit more carbonate influence in the bones, so it's multiple ways to call it.

It's surrounded by shale packages, but you have an influence of both carbonate and silica where we're at also in the pathology mix there.

Okay. That's helpful.

And last question, just going over back to the Midland, you mentioned potentially 58 wells per section. I was just wondering, have you all kind of thought about what the implications are for recovery factors relative to original oil in place, at least as that compares to your current down-spacing assumptions?

Well, we have recent internal view on our petro physics and the oil in place continues to go up as we get additional – on one flow unit, we have 58 million barrels in place on a Wolfcamp B. Of course, all 58 of those wells are not targeted in the Wolfcamp B.

So you're still going to be sub-40% – 20% to 40% of total resource recovery if you really get to 58 wells. And that's kind of off the cuff.

But you're still going to be far lower than the old conventional days.

Okay, great. Thanks.

Appreciate it.

We appreciate everyone taking the call and we look forward to seeing you at future conferences. Thanks.