Industrias Peñoles, S.A.B. de C.V.

Thank you, operator. And thanks, everyone, for joining us today.

With me this morning are Bryan Sheffield, our Chief Executive Officer; Matt Gallagher, our Chief Operating Officer; and Ryan Dalton, our Chief Financial Officer, each of them will deliver prepared remarks. If you'd like to follow along with our Investor presentation, you can find it on our website on the Investor Relations page under Events and Presentations.

Before we go further, I'd like to remind you that our remarks contain forward-looking statements and we refer you to our earnings release for a detailed discussion of these statements and the associated risks including the fact that actual results may differ materially from our expectations. We may also make reference to non-GAAP measures, so please see the reconciliations in our earnings release.

We'll be happy to take your questions after our prepared remarks. And I will now turn the call over Bryan.

Hello, everyone. And thanks for joining us this morning.

Before discussing the quarter, I want to take just a moment to celebrate the life and mourn the passing of my grandfather, Joe Parsley, after whom this company is named. As many of you may know, Joe passed away last Friday, but his influence will certainly continue given his connection to so many Permian-focused companies.

Joe believed in Parsley Energy and was a top shareholder at the time of his passing and I'm grateful for the example he's set; the wisdom he shared and the legacy established, which we hope to build on. Turning now to the third quarter, we made progress on many fronts, which is especially apparent when you look beneath the quarterly totals to the inter-quarter trends.

For example, daily production increased 17% from July to September, resuming an upward trajectory that, we believe, will become even steeper over coming quarters. We've been saying, since we first introduced 2015 production guidance, that the shape of our drilling activity will create a pause in completion activity that would impact third quarter results.

And this played out exactly as we expected. You can see this on slide 4.

Having operated just one horizontal rig for a significant portion of the second quarter, the first half of Q3 was relatively quiet on the completion front. Now that we've had four rigs running for a few months, we're back to a steadier completion schedule, and the right side of the chart shows that production growth has indeed picked up.

Month-by-month, we're drilling faster and cheaper, and we're seeing some of the same dynamics on the completion side. Our first pad project was a tremendous success, setting company records for drill time and drill cost.

So we're looking at a meaningful cost and time savings on top of what we've accomplished on a single well basis as we transition to more pad drilling over time. An important theme this quarter is positioning.

Through an equity offering, through the way we've managed the shape of our activity year-to-date, through strategic high-grading transactions, through ongoing progress on cost and efficiencies and through a consistent hedging program, we're now positioned to take our production growth and our returns and margins into another gear. We mentioned on our earnings call last quarter that at the pace we were drilling and completing wells at the time, we expect to generate 35% to 40% year-over-year growth in 2016.

If we continue to drill faster, as we did in the third quarter, we would expect even greater annual production growth. Our exact plan and pace will hinge on, among other things, how much capital we allocate to less delineated portions of our asset base.

So we're not going to go into detail about 2016 yet. But in almost any case, we will be looking at a leading production growth profile.

And it's very important to understand that because of the steady growth in our horizontal volumes, as a percent of total production, our oil production growth rate should meaningfully exceed our overall production growth rate. For example, in conjunction with the 35% to 40% annual production growth rate we previously mentioned, we would expect an oil growth rate north of 50%.

While it doesn't make sense to spend too much time discussing 2016 plans when they're not yet firmed up, we do have significant visibility for the next several months and we're excited about the momentum we will generate. In fact, things are tracking so well that, barring some unforeseen circumstance, we expect our net production to eclipse 30,000 barrels per day at some point during the first quarter in 2016, which would represent an increase of almost 40% from our Q3 average.

We think it makes sense to maintain course for a couple reasons that are unique to Parsley. For one thing, at strip prices and with the production profile and costs associated with our extensive Wolfcamp inventory, we're generating 50%-plus returns today.

In addition, for Parsley, growth and returns go hand-in-hand. As we grow, our horizontal production as a percent of total production increases, leading to a higher oil percentage and lower operating expenses per Boe.

among other benefits. And given the consistently strong nature of our inventory, it's not as if we have to dip into lower-return projects to accomplish dynamic growth.

I don't want to give the impression that we have blinders on, oblivious to the macro environment and focus on growth at any cost. We've shown that we're quick to calibrate our strategy and activities levels to our context.

When oil prices collapsed a year ago, we were one of the first to lay down rigs and we have flexibility to do that again if it makes sense. In addition to funding the few acquisitions we announced at the time, one of the primary reasons for our equity raise in September was to prepare for the possibility of a deep and extended downturn in oil prices.

While we don't consider this likely, there's a difference between unlikely and impossible, and we want to be prepared for any scenario. So we will certainly be mindful of the commodity price context going forward.

Keep in mind, we're not talking about adding rigs. We're not talking about extending the balance sheet.

We're simply talking about natural consequence of highly productive wells and consistent efficiency gains, which is faster growth. Importantly, when we run scenarios at the strip, our leverage actually comes down over time at the faster rate of drilling and growth we've been discussing.

So because of the positioning work we've done, including the hedge book we've built and our strong balance sheet, we feel comfortable letting our growth rate move higher. Turning to slide 5.

We're very excited about the way we've been able to high-grade our asset base over the past several months. The history of this company is filled with examples of creative transactions through which we've built a premiere acreage position and we continue to pursue strategic opportunities today.

We've recently entered an agreement to divest approximately 7,300 net acres in north Martin and south Dawson Counties, with a few hundred barrels of production for $40 million in cash. Any time you can effectively swap lower priority acreage for higher priority acreage, we consider a huge win.

And that's exactly what we've done. We're selling this acreage for $40 million, and we announced at the time of the equity offering that for approximately $39 million, we'd acquired around 1,900 net acres in our focused area in north Upton and northwest Reagan counties.

We've been concentrating our acquisition efforts in areas we know well in which we can leverage existing infrastructure. Returns on capital are enhanced any time you can use existing infrastructure.

And it doesn't get much more efficient than increasing working interest, which doesn't require any incremental facilities. Little by little, quarter-by-quarter, we're strategically filling in our drilling corridor, building a footprint that can support a high level of activity and rapid production growth over extended periods.

We've also been proactive in executing acre-for-acre trades where no money changes hands and we've made significant progress in that regard during the third quarter. You can see an example of an acreage trade on slide 6.

This is just an example, not an actual transaction, but shows how it works. Essentially, two parties with stranded tracks that are unsuitable for horizontal development or are limited to shorter laterals, can trade acreage to create new drilling locations and/or links in existing locations.

With no investment except hard work, these are home run types of transactions. Altogether, between the acquisitions, divestitures and trades, we've executed since the beginning of Q2.

We're netting 27 horizontal locations and extending 60 laterals by more than 2,500 feet on average, all in our focused area, all while collecting around $10 million in cash. We're excited about these additions, which are right in our sweet spot and will continue to look for these types of bolt-on opportunities going forward.

As it is, we have a consistent, durable, high quality inventory of high return drilling locations as you can see on slide 7. Following our recent transactions, 97% of our horizontal drilling locations are located in our focus area for our Wolfcamp wells are outpacing our 1 million Boe type curve.

An underappreciated asset at Parsley drilling inventory is our working interest, our high working interest. The average working interest across our entire horizontal inventory is approximately 85%.

Higher working interest enables more production per rig, which means more efficient growth. This is one reason we expect to be able to show leading growth rates for a long period of time.

We're pleased with the outcome of our fall redetermination process, through which our borrowing base has increased from $500 million to $575 million. This increase accounts for the removal of reserves associated with the assets being divested.

A larger borrowing base, along with equity offering we completed in September, puts us in a really good spot in terms of our balance sheet and liquidity. All in all, we have a clear path to bring forth the value of our Wolfcamp portfolio while also unlocking new sources of value.

And now I'll turn it over to Matt for more color on our operations.

Thanks, Bryan. On the operational front, the big thing continues to be cost and efficiencies.

Through an internal program called operation High Five we are identifying and implementing durable improvements to the way we operate. As you can see on slide 8, our rate of drilling has really increased this year and we took another big step in Q3.

We're seeing favorable trends on the completion side as well with frac stages per day climbing over the past few quarters. The orange bars on the right-hand side of these two charts suggest that there is more room to go as record drilling and completion rates we achieved in the third quarter exceeded our Q3 averages.

Turning to slide 9, as Bryan mentioned, we're thrilled with our execution on our first pad project. The charts on this slide show how drill times and well costs on our first two well pads compared to the other Wolfcamp wells we've drilled on the same lease.

This pad consists of a Wolfcamp A well and a Wolfcamp B well in Reagan County with an average completed lateral length of approximately 6,700 feet. We drilled both wells in 29 days from the spud of the first well to the total depth of the second well.

One of these wells set a company record at that time for the shortest drilling time and the lowest drilling costs on both absolute and lateral length adjusted bases. More recently, we set a Permian basin record for the fastest lateral drill.

This occurred on a two-well pad on our RINGO lease in northwest Reagan County. We drilled a 7,100-foot lateral in 41 hours, including 4,500 feet in 24 hours, another Permian record.

Based on field estimates, D&C costs for this Wolfcamp A well are tracking below $5.5 million. The take away here is that the average well cost and cycle times should continue to decline as we transition to more pad drilling regardless of service cost trends.

As you would hope, the efficiencies that we've realized on drilling and completions have translated to significant cost savings over the past few quarters. On slide 10, you can see the downward trajectory in both drilling costs and completion costs.

Again, our pad wells and single well records suggest room to run, and in fact, we think our fourth quarter well costs will be closer to our record well costs. Slide 11 shows how lower costs translate to higher returns.

As of Q3, in light of improved drilling and completion times and costs, we estimate that the rate of return and net present value associated with our Wolfcamp A/B type curve have increased to approximately 50% and $6 million, respectively, at strip prices. And based on current costs we're seeing, we expect to push towards 60% and $7 million in Q4.

Parsley's Wolfcamp A and Wolfcamp B wells continue to show encouraging decline rates, supporting cumulative production profiles that track above those implied by our 1 million-barrel Wolfcamp A/B type curve. We show the curve on slide 12 and it's important to understand that the type curve is based on all of our Wolfcamp wells across our entire focus area not just the selected sweet spot.

As of the end of Q3, our actual results showed greater positive separation from the curve than they did at the end of Q2. So it's not just that our Wolfcamp wells hit hard off the gate, but they hold in strong as the months' pass.

Together, high IPs and solid decline rates are our recipe for highly economic wells. On slide 13, you can see our Wolfcamp wells continue to outperform those of our peers in terms of both 30-day IPs and 180-day cumulative production.

We continue to believe that our Wolfcamp is advantaged in terms of depth, thickness, and consistency as indicated by our leading well results. Scaled IPs weren't quite as eye-popping this quarter given recent well mix with more weight towards Wolfcamp A and Reagan County wells, which tend to come on more gradually, but we actually recorded a Parsley record IP for our first Upton County pad just last night.

In 24 hours, we produced 2,400 Boe from a 4,550-foot Wolfcamp B lateral on our ROBBIE pad. Put differently, that's roughly 550 Boe per thousand stimulated feet.

Truly prolific, especially considering oil alone accounted for 1,800 barrels of that 24-hour total. And we also recently set a company record, 30-day IP rate, for a Reagan County well at more than 1,500 Boe per day on a 9,800-foot completed lateral on our Taylor lease.

This was actually our first horizontal well on the Reagan acquisition we announced in Q1. One example of our operation High Five initiative is a straightforward adjustment to our wellhead design that we've recently identified and we think will lead to even higher initial production rates.

As one indication, we've recently switched out the wellhead on a three-month-old horizontal well and experienced a production uplift of approximately 100 barrels per day. We have more than 50 examples of this type in similar improvements, signaling the type of attention to cost and efficiencies that will boost returns across market cycles.

We made very good progress on our delineation projects. Drilling and completion on our first lower Spraberry well went smoothly and quickly and we're excited to bring that well online soon.

Field estimates point to D&C costs under $5 million on this well, and we also recorded our lowest unit cost per frac stage on this well. Turning to slide 14, we've seen some impressive lower Sprayberry results from peer companies on the far west side of the basin and we expect similar rock quality in the central portion of the basin where we're located.

For example, our analysis suggests similar thermal maturity, POC, and oil gravity in north Upton and West Midland counties. We haven't prioritized the lower Sprayberry to-date because our Wolfcamp is so productive and because drilling the Wolfcamp holds both it and the Sprayberry.

But we could certainly envision the Sprayberry comprising a meaningful portion of our development program in the future. Drilling also went well in our first Southern Delaware well.

We're pleasantly surprised to match the drilling times we've seen in the Midland Basin, which is very encouraging considering this is our first operated horizontal well in a new area for us. You can see on slide 15 that activity continues to pick up around our Trees Ranch prospect with Apache, Anadarko, and Occidental drilling within a few miles of our acreage.

If everything goes according to plan, at our next quarterly update, we should have 30-day IP rates for both of our operated well and non-operated well in the Southern Delaware and our lower Sprayberry well. So a lot to look forward to as we prove out these assets, make adjustments that could enhance IP rates and continue pushing on the cost and efficiency fronts.

And now I'll hand off to Ryan for details on Q3 financial performance.

Thanks, Matt. A quick note on our share count to start.

Our Class B shares associated with non-controlling interest were not included in the diluted share count this quarter because they would be anti-dilutive. We reported an average diluted share count of approximately 109 million shares in Q3.

But for modeling purposes, you would use our full 156 million shares outstanding during periods of solidly positive income. You can see our release or 10-Q for details, but I wanted to quickly bring this to everyone's attention.

Adjusted EBITDAX decreased 13% versus Q2 to $46.6 million on lower volumes and realizations. Our hedges are really paying off in this environment, boosting our oil realizations by $15 per barrel in Q3.

As we were expecting, reduced water disposal costs led to a significant quarter-over-quarter decline in LOE per Boe, down 16% to $7.63, which is $2 lower than we reported in the first quarter. Reported capital spending came in a bit higher than we expected at $120 million.

We have good reason to believe that the third quarter isn't a good run rate on the CapEx front. Significant non-consent put upward pressure on working interest during Q3 and we also pulled forward several spuds into the quarter.

While we completed 11 wells in Q3, we spud 18 wells. Longer lateral lengths and sticky cost estimates in a declining service and equipment pricing environment also lifted Q3 CapEx.

As Matt and Bryan mentioned, leading edge cost estimates are significantly lower than those reported during the third quarter. So we expect to report lower well costs in Q4 than in Q3.

In addition, given the patterns we're seeing in actual well costs as they come in, it has become clear that we have consistently bettered our cost estimates year-to-date, and this outperformance should flow through to reported fourth quarter CapEx as well. Slide 16 shows full year 2015 guidance.

We expect to complete a few more wells in Q4 than in Q3, but we also expect a few less spuds. So overall activity will be pretty similar in the third and fourth quarters.

With comparable activity and lower costs in Q4 versus Q3, along with the accumulated cost outperformance I mentioned a moment ago, we expect lower CapEx in the fourth quarter, as full-year guidance implies. We're on-track for our full-year 2015 production guidance of 21.5 to 22.5 MBoe per day with a bias toward the middle of the range in light of divested production and the timing of upcoming pad wells.

This represents 55% year-over-year production growth, with projected oil growth north of 70%. And as Bryan observed, production growth should accelerate as we enter 2016.

Slide 17 outlines our strong financial position. We have ample liquidity to fund our drilling program, with almost $700 million available at the end of the quarter after the effect of our fall re-determination, which we finalized this week.

We were pleased with the outcome of that process through which our borrowing base and committed amount increased 15% to $575 million. As we expected, strong reserve growth and substantial hedge protection more than offset the effect of lower price deck and divested assets.

Slide 18 details our hedge position. We're fully hedged next year on consensus oil barrels and the structure of our hedges allows us to retain all of the upside in the event of an oil price recovery.

We've been adding to our hedge position in 2017 as well. In summary, we're right where we hoped we'd be at this point, with visibility to higher volume margins and returns and a strong balance sheet to deliver on these objectives.

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

Morning, gentlemen. A couple things here.

First, obviously it looks like production is going to ramp pretty nicely, as you indicate on your release. My thoughts are more about regional, how are you going to attack this next year, including that bolt-on acreage down in Reagan?

Will that be part of the mix or will you continue to stay more in the original corridor area further up northwest?

Good morning, Neal. This is Matt.

We're extremely pleased with our first result in that Reagan area, the Taylor well, posting very strong 1,500-plus Boe a day rates on a 30-day period. So there will be a heavy component of our program in the Reagan area that we bolted on earlier in the year.

Having said that, we'll probably keep an even mix in our north Upton core area and the Reagan area. And then we're waiting to see the results from our Lower Spraberry test as well as our Southern Delaware area to see what component of the 2016 program that's going to fill.

Got it. And then, Matt, obviously your completions and efficiencies continue to improve.

Are you going to continue to look at some longer laterals, frac size as far as tighter fracs? Just maybe your thoughts about completion optimizations.

Sure. We pride ourselves as a continuous learning organization, so we do continue to optimize and I think that bears through on our recent well that's coming through last night that just shattered our rates on a 24-hour period, over – around 550 Boe a day, that's kind of the culmination of all the latest and greatest on the completion sides that we have been learning and applying to use.

For reference, our next highest single well, 24-hour peak, was 340 Boe per day. So – per thousand feet, yes.

So, pretty excited on that front. We do continue to optimize and plan to continue that throughout 2016.

All right. Then just lastly, I would agree that – you mention your ample liquidity, I got to agree there.

Just your thoughts on any further potential divestitures and non-core, either in northern Martin or Dawson or anything, or at this point are you pretty satisfied with what you have?

Neal, this is Bryan. I feel like we have finally pulled all triggers on defense, and we are finished selling all the assets.

We've put 2016 hedge books 100% hedged on our oil. And then the equity sale.

And so I feel like we are bulletproof and we're going to continue to move forward going into 2016.

No. I've got to agree.

Thanks, guys.

Thank you.

Yes. Good morning.

Good morning.

Good morning, Michael.

Just – I guess maybe this first question will be for Ryan. So I think you commented that you're actually getting better costs year-to-date on these wells than maybe you kind of originally accrued for when you were sort of calculating capital spending year-to-date, so can you just provide a little more context around, kind of, Q4 capital spending and just sort of how you expect a true-up to kind of keep you within your full year spending guidance?

Sure. I think I'll answer it this way.

There are a few reasons Q3 isn't a good run rate for Q4. As I mentioned, non-consent lateral length, et cetera.

We did see favorable cost trend within Q3 with September being much lower than the other two months, and we expect that trend to continue. And then on the accounting adjustment you mentioned, we're really proud of the way we've driven costs down, and based on where those costs are coming in, compared to what we've estimated year-to-date, we're very confident in this – in getting a substantially favorable adjustment coming to us in the fourth quarter.

We're still working through the numbers, and – but based on early indications of what we expect the minimum amount to be, we feel like it was significant enough to keep the CapEx range where it currently is.

Okay. That's helpful context.

And then I guess just maybe one other question would be, sort of heading forward into next year. Obviously, you haven't released a budget yet, but can you just maybe talk broadly about, kind of, your outlook for continuing to invest capital in your vertical development program, just trying to get a sense for, I guess, the capital – expected capital weighting and horizontal development versus vertical development going forward?

Thanks.

I would say 95-plus percent is going to be focused on horizontals. We do drill targeted verticals as needed for multiple reasons but it's very few and far in between these days.

We're seeing AFEs around $1.5 million with our vertical Wolfberry wells.

Okay, great. Thanks.

Thanks. Bryan, condolences to you and your family, first off.

Thank you.

Yeah, I guess I just wanted maybe to get a little better sense on what the positive results you all saw on the pads – or on the pad, I should say. How much of the 2016 program do you think you could put on pad development and how much of an impact on cycle times could that potentially have?

Great question, Michael. It really is timely for us because we are now in full swing to pad mode.

So, as we mentioned, this was our first pad drilled as a company. We've had – we have two more under our belt currently.

And going into 2016, we'd expect somewhere in the add order of 50% of our program to be directed towards pad development. Any one particular quarter might be over or underweighted on that 50% just due to timing but over the full year, we do essentially have two of our rigs penned in for pad development.

And then we are seeing, as I mentioned, that recent well, it's flowing back now, with that higher productivity, it was a part of a B/A pad. Both the B and A are on track to be some of our highest 24-hour rates.

And looking back at the completion of the wells, we did see a positive stretch shadowing. We think that just aids in completion techniques in the fracture complexity in the area.

So a lot of excitement on the outskirts and on our end on what that's going to unfold for in 2016.

Okay. And I guess is there any way to quantify cycle time, you know, differences between running single wells versus pads?

We do think kind of on the industry basis, we were at where other people were at on their pad cycle times. We were averaging around 25 days a spud-to-rig release on our single wells.

And in our first two, we have seen on the order of 30% reduction on those cycle times, granted these are just two well pads right now. So we'll need some additional time to get to our third well pad – three well pads and quantify that, but a reduction is insight for sure.

Okay. Great.

And I guess I was also curious on your comments on how much of your oil or consensus oil production is hedged. Are there any limits on how much oil you can have hedged?

Our credit agreement does provide some limits, but given the structure that we use, which is purchasing put spreads, that doesn't fall within the constraints of the credit agreement.

That would be swaps. Swaps would be.

Got it. Okay.

And then I guess last one of my near term question, I don't think I caught it in the comments, what sort of pop – how many wells do you think you'll put on production in the fourth quarter?

We're estimating about 15 completions in the fourth quarter. But given a couple of those are pads, it could swing up or down just a bit.

All right. Thank you very much.

Congrats again.

Thank you.

Thank you.

Yes, good morning, gentlemen.

Good morning, Robert.

With your estimated returns at the strip, it's a little surprising that you would see a jump in non-consents last quarter. Is there a concern that your non-op partners maybe a little more hesitant to spend along with you guys, or is there some balance sheet concern on their part and does that present an opportunity for you to pick up more working interest?

We've continued to buy out our non-op partners as we continue – well, as we continue to transition from vertical to horizontal. So what happened is, these partners and other working interest owners were investors into a vertical play, and so when you convert from a $2 million AFE to an $8 million AFE early in the year now down to $5.5 million, I think some of them just throw in the towel.

And we're running four rigs on multiple leases in the same area, and they drill a few wells and they like it, but then they're ready to sell. That's kind of how it plays out or they're just going non-consent.

Okay. Great.

That makes sense. And a follow-up, it looks like your Tier 1 drilling inventory is down a little bit.

Is that just due to the acreage transactions or is there – something else going on there?

Yeah, that's the north Martin acreage transaction that we're in the middle of.

Okay. Great.

Thanks very much.

Thank you.

Hey, guys. Good morning.

Great update.

Good morning.

I think I've got to say I'm glad to see you guys aren't getting soft on 2016 like a lot of your Permian peers are. A question on that front, really maybe two questions.

One, what's the threshold price that maybe kind of does give you pause? I know there's a lot of variables there, but kind of curious on your thoughts there.

And then conversely, as you move into Q4, do you see 60% project IRRs, why not accelerate further, how you think about potential acceleration with those types of returns? Thanks.

Yeah, it's Bryan. Let's just say, if oil goes down to $35, I mean, we need to have a discussion – the management team needs to have a discussion.

At the same time, we're hedged in 2016 at $54. So maybe we would drop the rig that we have month-to-month, but the whole point of our hedge book was to execute with the four rigs next year and maintain their growth profile.

What was the other question, about? Returns, looking at returns?

Yes.

Returns are getting juicier. But at the same time, you got to manage your balance sheet, you don't want to borrow too much.

I'm not sure we're out of the woods yet. But I think that is just gravy.

If our returns move from 40% to 50% to 60%, maybe it helps us pay down a little debt and just continue to run the four rigs.

Okay, great. And then switching over to the Delaware, you're going to have results next quarter.

And just strategically, how do you think about this asset if those returns show up as good as what other people are doing in the Basin? How do you fund that in light of really strong returns you got in the Midland?

How do you do both I guess?

You got look at, like you mentioned, returns and it's got compete on a return basis. So out of the gate for our first well to deliver on a 21-and-a-half day spud-to-TD was very exciting for us and does start to pique your interest and put it on the platform where it could potentially compete with our returns.

So now you have a good problem to solve on development. The good news is we have no development obligations on our 30,000-acre ranch pointing towards three years now, so we have time to allow for our balance sheet to handle development over there.

But it would be in a market manner and we would always make sure it has to compete with the Midland Basin side.

Would you guys contemplate bringing in a JV partner on that or just slow play it if you have to?

We have a three-year term extension on it, so we have time. I don't feel like we need – usually these JV deals are usually a rush because of leases expiring, we just have too much of it.

We have discussed it. We need to figure out on these two wells, maybe drill a couple more, need to figure out what we really have before cutting a JV well.

Once you know – a JV venture. But we just need to be patient instead of making a fast decision on that.

Got it. Thanks, guys.

Again, great update.

Thanks.

Good morning, guys.

Good morning.

If I could go back to the question about the transition to pad drilling and the efficiencies available there. In the slides you guys put out last night, it really gave me the impression that there's a step change that may be available to you.

And I'm wondering if you can talk in a little more specifics about what was maybe different with those pad wells, whether you had a new rig or a new kind of bit selection for the lateral? And what I'm really going for is, how much of this may be just one-off and how much of this is really something that we ought to think is going to apply across your whole program next year?

Well, what you're seeing here is a two-pronged approach. You're seeing the improvements of our drilling team and the drilling applications just as the bit is in the ground and the rig is over the hole, which does apply to our single wells also.

But then you're going to see the improvement transitioning to pads a reduction in load times. But when you're on the same area and the crew gets to drill essentially the same rock back to back, they just get to hone in on landing zones and hone in on drilling parameters for that specific area as opposed to drilling and then resetting five miles or 10 miles away.

So I think a lot of it is sustainable through our single wells, but you even get another leg up going to pads.

Got it. Thank you, Matt.

And if I could transition and ask a question about the Lower Spraberry. So I understand you've got your first one down and you're going to bring it on in Q4.

But it looks like it's going to be a bigger part of your program in 2016. And I'm wondering if you could tell me if that's the right impression or right conclusion to draw and maybe talk about what kind of plans you have for that zone in 2016?

We haven't really decided yet. We do want to see this well – there's no impetus on us essentially to go heavy on Lower Spraberry since our Wolfcamp drilling is so robust and the returns are so robust and we do hold all of the Lower Spraberry rights as we drill on our Wolfcamps.

But as this well flows back, that will dictate what portion of the program we would continue drilling Lower Spraberrys. And one well does not set the pace.

So we will drill a handful regardless of this outcome. But if it exceeds our expectations, we may drill a few more in 2016.

Got it. And if I could just sneak one more in that may be related.

Matt, when you were talking about the two wells that you brought online, the one that recently set the record. And I think you said one was Wolfcamp A, one was Wolfcamp B.

It sounds like you guys completed those at the same time. And does that put you in the camp that you think you need to develop those reservoirs at the same time or is that too early to say that?

That's a positive indicator that it's going to be another good sign for pads. So it's pretty exciting that our single-well results have industry-leading productivity.

And now our first pad results, when we do complete them at the same time, have shattered those previous results. So it's a good leading indicator and we're going to keep watching it.

All right. Thanks a lot, Matt.

Yep.

Good morning, guys. The Wolfcamp results you guys put out looked very good.

Could you give us some oil cuts on those results though?

They should be tracking right around that 73% to 76% range on our 30-day rates. Pretty much...

(42:43) Reagan County?

I'm looking across the board here. Yes.

Okay. And then with volumes picking up pretty rapidly going into next year, where do you see the company-wide mix heading?

I mean, it was 58, two quarters in a row. Do you see it going into the mid 60s by the middle of 2016?

Yes, that's correct. It was 58% for the quarter but a favorable trend in September was up to 62%, when horizontal completions picked up.

You're right, I'd say probably mid 60s next year, hopefully trending to upper 60s towards the end of 2016.

All right. Sounds good, guys.

Thanks for the color.

Thanks.

Thank you, folks. Good morning.

Just following up on the last question, can you sketch for us how the base decline rate will change over time as the company transitions to greater use of horizontal drilling to develop the asset? Just asking in an effort to get a better sense of the kind of the rate of change of the company's capital efficiency?

Sure. When we look at our – when we looked at our maintenance cap coming into 2015, the horizontals are obviously a little higher than the verticals.

The verticals have a good solid base, around 22% to 24%. Those verticals are getting older so the decline rates are getting shallower.

But as our horizontal percentage increases and our production increases, our corporate average would probably increase from the mid-30s or so going up. We haven't looked at it in detail, going into 2016, but that would be our off-the-cuff estimate.

Very helpful. Have a great day.

Thank you.

Thanks a lot.

Hi, good morning. Bryan, I was wondering if you could provide some context to that 30,000 barrels a day production figure that you spoke to hitting to at some point in the first quarter.

Is that a figure that's more a point in time or do you think that's a fair estimate for 1Q or 2Q average here?

I think it's a one point in time sometime in that quarter. We feel very confident about that number.

And continue to grow from there.

Right. Right.

And that makes sense. So the 35% to 40% growth that we've spoken to in August for both 2016 average and exit to exit is still sort of the right number to think about as we look out to 2016?

Yeah, but we keep on drilling faster, so just keep that in mind.

And that's assuming a four-rig plan for 2016, which, we're still finalizing 2016 plans.

Got you. Is there a propensity to increase that plan or decrease that plan given the returns that you guys are looking at here?

What we're really doing sensitivities on are these cycle times and trying to wrap our 2016 plan around that. So it's not – the returns are – we feel comfortable with where the returns are at, it's just trying to model how much of this impacts the total program for the next year.

While I mentioned in the earlier question that if we start seeing 50%, 60% returns, it doesn't mean just add a rig. We'd rather use it as gravy and kind of weigh our options in 2016.

We're just really focused on maintaining these four rigs.

Got you. That makes sense.

And then one unrelated question, if I may here. You guys spoke to what drove the sequential movement in initial 30-day rates here.

I just wanted to see what the 30-day rate was that's embedded in the 1 million barrel type curve for comparison purposes here?

Let's pull that for you. We'll have to get back to you on that one.

It'd be an off-the-cuff number, if I gave it now.

Sure. No worries.

Yeah. No worries.

One final one for me here. LOE came down significantly.

I'm curious if you can speak to 4Q here, midpoint of annual guidance would imply another $1 a barrel, let's say, sequential drop to the mid six range, is that the right way to think about it or just any color you have as we kind of look out to 4Q for LOE and then on to 2016?

No, directionally, without an exact quarter specific, that's the right momentum that we're delivering on. We've seen a tremendous improvement due to our build out of our saltwater disposal infrastructure.

You also have to remember that we had a lower production quarter in the third quarter, so we had less volumes to spread that LOE cost over. So as we pick up in our volumes and we continue to focus on horizontal activity, which has a much lower LOE per Boe, we have a good tailwind on that front and that range that you mentioned is not outside of the realm, especially when we get into 2016.

Thank you for all the color.

Yes.

Hi, good morning, guys.

Good morning.

Good morning.

Just a quick question on the activity level outlook. At what oil prices would you look to increase activity and, conversely, where would oil have to be for you to drop additional rigs?

We – let's say for 2016, we are 100% hedged on our oil. So I think we do need to huddle if the oil goes down to $35 and you can actually collect your hedges, take down some of your hedges on the value and we could drop maybe a rig, but we're still drilling at the same return since we're hedged at $54.

But on the upside, adding a rig – I mean, I think you need to start seeing 60 – $60. I think if you go into $50 that would mean just – as volatile oil price has been and the way it just moves up 10% over a week and down 10% over a week, all because the oil goes to $55, I'm not sure you should just go and add another rig.

I think that if you're making 50%, 60% returns, it's just kind of this gravy to the bottom line, and we'll just assess as time passes.

Makes sense. That's helpful.

A follow-up just on – I wanted to dig in on the frac design implemented on this recent completion that's set an IP rate record. Can you just shed a little color on what you're doing differently relative to the – to previous completion designs?

There's multiple different types of slick water designs and I would say this is as extreme on the slick water as we can get without using any additional, what we used to call tool kit additives, but we have been pushing for that over the past few months. So it's just a tweak in our continuation of our optimization program on the completion front.

Has the quantity of proppant per well changed at all or per lateral foot changed at all in this most recent completion relative to previous wells?

No, we're still around 1,800 pounds per foot.

Okay. Perfect.

I'll leave it there. Thanks, guys.

Thanks again for joining us, and feel free to be in touch. If you have any more questions.