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, and thanks for joining us this morning. Parsley Energy continues to execute at a very high level.

It's starting to sound like a broken record when I say that production increased 20% versus last quarter, but once again, we've packed a year's worth of growth into one quarter. As you can see on slide three, we averaged 43,000 Boe per day in Q3, and we've doubled production versus the year-ago period almost entirely through the drill bit.

We've grown oil volumes even more sharply, well over 100% over the past 12 months, with positive effects on average realizations and margins. What's more, our growth has been efficient as we're pacing the field in terms of barrels added per dollar of development capital.

We're raising our full year production guidance again, this time from a range of 36,000 Boe to 38,000 Boe per day to a range of 37,000 Boe to 39,000 Boe per day, which represents 72% year-over-year growth at the midpoint. Growth is always in service of returns on capital, and the top line is just one side of that equation.

Turning to slide four, we continued to set the pace on the cost front as well, having bolted to the head of the class on operating costs over the past several quarters. And we're still running below $5 million D&C for 7,000 foot wells despite higher completion intensity.

What's really exciting for us this quarter is that we're taking a big step towards major resource expansion. Better yet, this isn't something we have to go out and acquire.

This resource potential is already present on the existing asset base. We're always taking a measured approach to inventory recognition, and this quarter we're recognizing a second target zone in our Midland Basin Wolfcamp B interval.

This adds 550 gross and 450 net locations to our drilling inventory. We'll walk through the rationale over the next few slides.

Slide five supports the resource potential. Slide six presents our results to-date.

Slide seven focuses on our stacked concept, and slide eight shows the impact on our inventory. Looking at the map on slide five, as you move down along the deep axis of the Midland Basin, the Wolfcamp really thickens as you enter and move through the heart of our acreage.

In fact, at 800 feet to 900 feet thick, our Wolfcamp A/B complex is among the thickest you'll find in the deep portion of the Basin. This thickness provides a couple hundred feet between up to four target zones in the combined Wolfcamp A and Wolfcamp B; enough vertical space to execute fracs that maximize combined recovery while limiting communication.

We've already drilled or acquired a good set of wells completed in the upper portion of the Wolfcamp B. And as you can see on slide six, these wells span our Midland Basin acreage.

We've been tracking these 15 wells and they are exceeding the company's 1 million Boe type curve for Wolfcamp A/B wells by 6% at 180 days and 9% at 360 days. This in line with the results from wells we've completed in the lower portion of the Wolfcamp B.

We haven't excluded any wells from the data set. If we exclude several wells completed more than two years ago with different designs, the outperformance would be even more pronounced.

So, at this point, we know we can land in either the upper or the lower portion of the Wolfcamp B with good results. The next question was how well they performed when completed together.

Initial data on simultaneous completion is quite promising. Turn to slide seven.

Results are looking very strong from our 3-Well Stacked Grace Pad, which involves not just the two Wolfcamp B targets but also Wolfcamp A well. In fact, the three wells are on average tracking just ahead of our 1 million Boe type curve after almost one month of production.

Not only that, the well completed in the upper portion of the Wolfcamp B recently registered the second-highest 24-hour IP rate in the company's history at 2,420 Boe per day, representing 306 Boe per day per 1,000 feet. I want to emphasize that this is a direct stacked test, not a staggered configuration, not on the thickest portion of our Wolfcamp acreage.

As you can see on the map, the Grace Pad is right in the middle of our Upton and Reagan county acreage. It's still early, but if combined production from three wells completed as a system even comes close to a single well productivity, it would be a tremendous outcome.

We think this is just the beginning of a process of resource expansion that will be transformational for the company, and we believe it's specific to Parsley and others in this particular corridor of the Midland Basin. This quarter, we're recognizing eight more locations per section going from 16 to 24 locations in the Wolfcamp A and B.

Over coming quarters, we plan to conduct tests that could unlock up to 60 laterals per section in these two intervals on some portion of our acreage, a possibility shown on slide eight. We certainly think there's more to come, including the possibility of a second target zone in the Wolfcamp A.

Like the Wolfcamp B, the Wolfcamp A interval is several hundred feet thick. And as with the Wolfcamp B, we intend to complete multiple Wolfcamp A targets on both a standalone basis and together, including a project next year that will test two Wolfcamp A targets together in staggered formation.

Depending on the ultimate productivity of the new Upper B locations, as they're completed along the wells in other target intervals, we estimate that the net present value of each added location is somewhere between $3 million and $5 million at current commodity prices. So, 450 net locations could represent a couple billion dollars of value before development timing assumptions.

The magnitude is almost like discovering a play in our own backyard. This estimate incorporates the actual lateral length, working interest, and net revenue interest associated with these specific locations.

And the $3 million to $5 million range allows for the fact that the best configuration for resource capture and NPV probably won't generate 100% of a standalone recovery. So there's tremendous value here with more to come.

Moving to slide nine, I will comment briefly on our outlook. Just as there is a lag between oil prices and service and equipment costs on the way down, there is a lag on the way up.

And we've been fortunate to have captured a lot of value by maintaining a healthy activity pace throughout the year. As you can see in the charts at the bottom of the slide, we remain in a sweet spot for returns.

For this reason, we added a rig a few weeks ago and our bias is to continue to increase activity over coming quarters. While we're hesitant to formalize anything ahead of OPEC's annual meeting at the end of the month, at the same time, we believe in the quality of our assets and are inclined to pull forward the value.

And when we do, we'll be drilling longer laterals and developing properties with higher NRIs. So we're well-positioned for higher activity and efficiency next year if conditions remain favorable.

With that, I'll pass it off to Matt for more detail on our operational performance.

Thanks, Bryan. Another excellent quarter in terms of operations and productivity.

The only path to this type of organic production growth we've demonstrated is through strong contributions from both new wells and existing wells, and that's just what our teams continue to deliver. The cumulative production profile shown on slide 10 includes every single one of Parsley's Wolfcamp wells.

As you can see, both our Midland Basin wells and our Southern Delaware wells are performing robustly through the first year of production. New results for Q3 are quite healthy, up versus Q2 on the Midland side and even stronger in the Delaware than in the Midland Basin.

Turning to slide 11, the theme this quarter is not just that our wells show ongoing strength, but that they're getting even stronger as we refine our drilling and completion designs and processes. For example, on our Lower Spraberry well, we installed larger casing and pumped a larger frac than on our first Lower Spraberry well.

The new well is a two-mile lateral whereas the first well was a one-mile lateral, so a two-to-one ratio. But at the 90-day mark, the production rate on the newer well is four times as high as the first well was at the same time.

So we're really pleased with this well, which is still making more than 800 barrels of oil a day with a very flat profile. We've prioritized our prolific Wolfcamp to date, but don't sleep on the Spraberry.

It doesn't yet match our Wolfcamp on a standalone basis, but there's a lot of value there, especially as we move towards a manufacturing model where we complete wells in multiple intervals at the same time. It's a similar story on our so-called monster frac well.

As you may recall, we increased fluid and proppant loading on this well by about 40% each, and results so far are encouraging. We expect that, all else equal, a more intensive completion will generate a flatter decline profile.

So we consider it a likely success from a productivity standpoint if the IP matches that of analogous wells completed with less intensive frac designs. In this case, we're actually exceeding these analogues by several percent to-date.

If this outperformance holds, the value of lift likely justifies the incremental expense. So we're likely to methodically push completion intensity relative to our current standard of around 1,900 pounds per foot in the Midland Basin.

When we evaluate these and other tests, we're seeing consistent incremental improvement, which translates to overall well results. 2016 has been a year of control points on completion variables and we're excited to take these results and apply them in combination to our 2017 development program.

Before turning to the Delaware, a quick note on Glasscock. Still early days and our recent acquisition just closed last month, but the handful of wells we've completed in Glasscock are averaging 174 Boe per 1,000 feet, right in line with our broader Midland Basin average.

So we look forward to folding that area into our development program, especially given the NRI boost on the acquired acreage. Now to the Delaware Basin where results are at least as encouraging as on the Midland side.

Slide 12 shows that while our first set of well results from the Delaware was outstanding, our second round of results is even better. Looking first at results on our western acreage, you may recall that we completed but did not drill the Ranger well in Reeves County.

And while it has performed really well, we were anxious to drill a well that we could geo-steer in our preferred target in the Upper Wolfcamp. Well, our first drilled well in the Reeves County on our Lincoln lease is really soaring, tracking above 2,000 Boe per day.

We've opened the Lincoln up pretty gradually and we're really pleased with its performance to-date. This is an excellent well and reflects very positively on this portion of our Delaware acreage.

Meanwhile, we're posting equally exciting results in Pecos County. Our first pad wells on our Trees Ranch acreage are really impressive.

We completed these wells with higher proppant loading than we used for the first operated well. Relative to the first well, which was a shorter lateral, these two newer wells were completed with about 70% longer laterals, yet are producing at a rate close to 2.5 times as high as the first well at the same well age.

These are really big wells with high oil cuts, and it's worth noting that we drilled them in the same target zone in opposite directions, so we haven't yet seen the benefits of stress shadowing in the Delaware. It's also worth noting that our first well is really strong in its own right, having produced over 100,000 Boe over its first 180 days from just a 4,500-foot lateral.

This is almost 30% more than would be implied by the 1 million Boe type curve scaled to that length. With results like these, once we get rolling on our minerals in the Delaware, we expect a big boost to production growth and margin expansion.

So across our asset base, CapEx, LOE, cycle times and well results are good and getting better. We look forward to applying everything we're learning as we move forward.

With that, I'll hand it over to Ryan to review our financial performance.

Thanks, Matt. Before I turn to our strong financial results, I'll note that this past week we signed a new credit agreement with our bank group.

We're pleased to report an 89% increase in our borrowing base, up from $475 million to $900 million, reflecting strong production and reserve growth. Given the company's current cash position and ample liquidity, we've elected a commitment level of $600 million, which limits unused buying fees.

Pro forma for the new borrowing base and the Glasscock acquisition that closed in early October, Parsley exited the quarter with approximately $800 million of liquidity, including the undrawn $600 million borrowing base. We've been adding to our hedge position covering the second half of 2017 and have built out our position through the first quarter of 2018.

You can see on slide 14 that we continue to have a substantial hedge position that provides significant downside protection while retaining all of the upside if oil prices rally. And we'll keep extending our hedge position as has been our custom.

Reported capital expenditures decreased by $44 million quarter-over-quarter to $92 million, driven by lower drilling and completion activity and also by declining well costs that yielded lower than estimated costs for prior-period wells. With service costs stabilizing, we don't expect an ongoing benefit from differences between budgeted and actual costs.

And we also expect to complete more wells in Q4 than in Q3. Nevertheless, despite adding a thick horizontal rig in September, we're maintaining estimated full year 2016 capital expenditures at a range of $460 million to $510 million.

Strangely enough, the fact that we're planning to complete more wells in Q4 than in Q3 leads us to expect flattish production in the fourth quarter. A number of these wells we're completing are part of the pad projects in our most developed and productive areas.

As such, we're shutting in some significant producers to control the fracs on the new wells. All of this sets up for a very robust production trend in subsequent quarters, and we're able to raise full year 2016 production guidance even as we transition to larger pad projects in Q4.

Back to Q3, cash G&A per Boe increased from $4.28 in Q2 to $5.40 in Q3. We've been at the same rig count now for basically two years.

And as we think about doubling or tripling our activity level over the next couple of years or so, we want to be sure we have all the people and expertise in place to ramp up. This is especially relevant as we scale up in the Delaware, which requires dedicated teams, a separate field office, et cetera.

So we're thinking ahead and making investment in future execution and growth capacity. And just as we've done in prior periods, we expect to drive unit expense down as we deliver an efficient growth plan over future periods.

LOE per Boe came in at a peer-leading $4.15 as our earlier investments in infrastructure, automation and preventative maintenance continues to pay dividends, and we have lowered full year LOE guidance again. In summary, excellent trends on a number of fronts and we'll be coiling the spring in Q4 in preparation for a big year of 2017.

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

Yes, guys. Could you just talk about the M&A environment today versus what you thought a year ago?

Hey. This is Bryan.

Good morning. I would say Delaware is pretty frothy compared to a year ago.

I think I remember us purchasing acreage for around $10,000 an acre and one of our competitors purchasing for $25,000 an acre and now we're hearing $45,000 an acre after six month. In the Midland Basin, I'm seeing transactions between $30,000 to $40,000 an acre right now.

Thank you.

Thanks.

Good morning, everyone.

Good morning.

I was hoping you could talk about your thoughts on activity levels in 2017, 2018. Ryan mentioned potentially doubling or tripling the activity from where you are today.

So, in one respect, how you plan to set the budget and then how large of a program you think you can run in the next year or two, given your staffing levels and infrastructure and any other concerns?

I remember in the last call we mentioned six rigs, we're still eyeing six rigs. That's our main focus right now.

Obviously, we've started the fifth rig earlier and then we're thinking about the sixth rig right in the beginning of January. Now if oil prices move $10 up, $10 down, that's when we kind of – I think we can definitely keep six rigs running above $35 because of our returns.

If oil is up to the $55, I think that's when we consider adding in more rigs. But for now, we're eyeing the six rigs.

The returns are tremendous. So you've seen that we were aggressive before, last year in February with the four rigs running.

As for staff, we're staffing up because we're eyeing 2018, which would be even more rigs, and you could see that old growth chart from the last deck kind of pointing you to the direction of 2018.

Now, on the infrastructure side, Drew, when we look at constraint analysis on our current footprint, we really don't have one from an operating point of view. The assets themselves, we think, can handle about 17 rigs to 20 rigs depending on cycle times and pads in a certain area.

Okay. And in the Delaware Basin, is there the desire to fully delineate the position and size up the resource before you move into full-scale development?

Or is there any consideration like that on the Delaware side?

We feel pretty comfortable about the results on the Delaware, so we're ramping as quickly as possible on the Delaware. And throughout 2017 you'll see methodical well testing across the entire footprint and we feel pretty good about results to-date and the data we've gathered over there.

Okay. Thanks.

Good morning, guys, to Bryan and the rest of your team there. I was wondering if I could ask a question about – to get a little more detail on this Grace Pad.

You guys put in your press release that you've got your second best well with the middle well in that sandwich, if you think about it that way. But I wondered if you could talk about if that's one of your best wells and you had an average around of – on average those three wells are tracking around 1 million barrels, I guess, the implication is that the other two are maybe slightly below.

Could you confirm or talk about that? And then also talk – it's really an interesting and kind of suggestive result that it's that middle well that maybe got some kind of extra energy from the frac, from the fracs above it and below it, maybe that's contributing to the great result.

But just I want to throw that out there to see what you guys can add.

Sure. When we look at the stacked test on the Grace, of course, we don't have 30 days yet, so it's a little early.

But obviously, the Upper Wolfcamp B well producing at a record rate close to 2,500 Boe a day on a 24-hour rate, you look at kind of projected 30-day rates, the Lower B well is going to be in that 1,000 Boe a day range, which is actually a good starting point for our 1 million barrel curve. And then the A well is north of that – trending north of that.

So since we don't have the 30-day rates, have kind of a projected average there off of what we think the type curve can do, but it is interesting. I think the two lower wells, the B wells, you do get the benefit of the stress shadowing, placing these wells in correct proportion away from each other.

And they are acting in early time as a nice system and giving us a benefit. So we got a little bit of additional water flowback from the frac on the lower well and very low rates on the upper well.

And then they stabilize in short order and start acting to get on trend together. The lower well is actually still increasing in rate towards the end of October.

Got it. That's interesting stuff to watch over the next several months.

And if I could ask the second question about the Wolfcamp A and your plans for 2017 with the second landing zone, is this the sort of thing where having done this in the B, you know what the pattern is, and so you're going to follow a similar sort of protocol to prove up or to test a second landing zone in the A? Or is it in contrast maybe the thing where you've learned enough from your process in the B that you could do – you have a different sort of plan for qualifying the second landing zone in the A?

I think it's using a lot of the same game plan, but sticking to the fundamentals that put the concept in place on the B in the first place, rock properties and thickness and then kind of working from the bottom up, as we have. And then you also have to be methodical across your acreage and across your conceptual testing and this just fits into the sequence now.

So we'll just apply it moving forward and it is based off learning and results from the B and fundamental concepts.

Thank you, Matt. A lot of good stuff to look forward to.

Thanks, Charles.

Good morning, guys. Curious to see on – get your take on the number of locations that you guys seem to be talking about in the Wolfcamp, seems pretty darn impressive.

But curious if you guys – if we look at that 60 well section in the A and the B type of concept, do you guys have a figure of what type of oil recovery factors in place that would imply if that indeed proves successful on that 1 million-ish barrel type of EUR that you guys are talking about per well?

Yeah, I think that's a great question. That goes back to the fundamentals we were talking about.

And when you look at a per section basis and what Bryan mentioned, that it is truly unique to us and the people in the direct corridor around us. Within a mapped area over our Upton and Reagan acreage, we have anywhere between 100 million and 130 million barrels of oil kind of in one place, or stock tank oil in place, and that's per section.

So then you double that on a two-mile section, you assume anywhere between 750,000 and 1 million barrels recovery, you're in the anywhere from 17% to 22% recovery. That's with 60 wells draining that opportunity to assist in the Wolfcamp A and B.

And you still only get to around 20% recovery long term. So, a lot of oil in place, a very advantaged position of oil in place, and a lot of opportunities to go pull this resource forward.

Okay. Great.

Perfect. That's helpful color.

And then if I'm looking at slide nine, just a little curious on the lateral lengths, you guys are talking about targeting an 8,000 foot average lateral in 2017. And, I guess, that seems a bit higher than I think kind of average of your inventory with something in kind of in the mid or high 6,000 range.

So just curious, is that 8,000 foot more a function of just kind of front-end loading with the longer laterals or have you guys been able to do some trades or whatnot to get closer to a 7,000 foot to 8,000 foot type as an average for your inventory?

Well, it is mechanically front-end loading. But when you look at we have 15 years of inventory at a 10-rig count, we have the flexibility to front-end here for the next probably five years on 8,000-plus foot laterals.

I'd say over the next three years they'll probably continue to grind up as it sits in place. And then, as you mentioned trades, the team has gotten excellent working trades, and those are what we work on the back half of the inventory to try and continue to block those up and increase that over time.

We've had a good track record of doing so.

Got it. And if I could just sneak one more in.

Can you guys just talk about the service environment right now? I guess, we've heard a couple of other peers talk about or expecting maybe a little bit of inflation as we move into 2017.

Can you guys just talk about what you're seeing on that side of things?

Yeah. I think it's fair to say we're approaching the bottom of cost compression.

We're seeing continued increases in efficiencies, but unit costs are stabilizing. We have had specific line item increases.

We think about 60% of the costs that we reduced since the 2014 peak are due to efficiencies. Probably 40% are exposed to unit cost increases.

And then of that, an example we've seen casing orders going out for full year 2017 from the mill, this is kind of a macro event outside of the industry, the steel price getting tighter and everybody burning through the dead inventory throughout 2014. It might be on the order of 10% to 20% higher.

But then we're still offsetting on cycle times. So I think it would be fair – Q3, we saw continued reduction in our well cost, but we are probably modeling a 10% aggregate increase in our estimated 2017 plan.

Got it. That's helpful.

Thanks, Matt.

Hey. Good morning, guys, and congrats on another impressive quarter.

Just coming back to Neal's question from earlier, you guys have been very active in the M&A market in the last year, but this inventory upside clearly looks like a game-changer. Bryan, you also mentioned that asset prices are a bit frothy.

So just curious, does this inventory expansion take you out of the M&A game for now?

No. We've been very aggressive acquiring the past two years.

I think we've acquired between $1.5 billion to $1.8 billion worth of deals since oil prices collapsed, and we do feel content increasing our inventory count through acquisitions. And by us proving the Double B, it helps us feel even better about having the locations and the runway over the next 10 to 15 years.

I mean, we're not going to take ourselves out of the M&A, but I can see it's a little harder for us to get to if you're talking about $40,000-plus an acre deals when we can just run our own rigs on our inventory.

Got it. That makes sense.

And Matt, I think I might have missed this in your prepared remarks. But in Glasscock, can you just remind us again, what's your plan in terms of drilling that acreage?

And is the plan to initially focus on the western part of the county or further to the east?

The wells to-date have been on the western part. Of course, we just closed our eastern part about a month ago.

Wells to-date in Glasscock are trending about 174 Boe per day per 1,000 feet, right in line with our corporate average. And then back in the acquisition model, we had a handful, six wells, in the 2017 plan.

We plan to stay on track with any acquisition model. We do have the additional override on that acreage, and then the additional A testing that we're doing and Spraberry testing, we're looking forward to additional work over there on that eastern part of the Glasscock acreage.

So there will be activity there in 2017.

And just curious, were those wells that you guys completed on your legacy acreage on the western part of the play, were those completed using your base completion design or did they use lower proppant levels?

Essentially the – it's not stale completion design, but they weren't leading edge completion designs either.

Got it. Thanks, guys, and congrats again.

Thanks.

Good morning. Just in the Midland Basin, the potential inventory per section numbers are obviously pretty significant.

How do you see development at the section level playing out over the next couple of years in terms of pad design or wells per pad?

Well, every time we keep going back to the drawing board, the wells per pad increase. And we find more efficiencies doing so in that manner.

And additionally, we're doing a lot of research on what we call sequencing of our fracs. And we've talked now for a few quarters about stress shadowing, and we really do feel that we're getting benefits by sequencing these fracs in the correct manner.

So there's going to be continued work across the industry on that over the next 12 to 24 months. Our eight-well pad that we're working on is answering a lot of questions on that front.

And we'll be able to apply that going forward. So we don't have the right answer – the final answer right now, but it's all marching that direction.

I would predict in two years from now, activity will be a lot more stationary and you work kind of from the inside out on your sections, and really kind of mow down sections pretty aggressively.

And just another one on the infrastructure side. Just as you guys ramp and industry ramps in the Basin, how do you see your position in terms of oil takeaway over the intermediate term?

Specific to Parsley, it's looking really good. We are connected directly to 1.5 million barrels a day of long-haul pipes through our gathering systems.

And then on the Delaware side, we are literally the gateway to the Basin with over 300,000 barrels of gathering pipe that cross our physical acreage footprint as it heads west and carries the barrels back to the east. So we're in the middle of actually pretty competitive negotiations on that front for a long-term deal with our footprint there.

So partially we feel real good about our committed position and takeaway. We're seeing the same ranging everybody else is seeing: late 2018, early 2019 on total Basin if absolutely nothing changed, but all the marketing teams on all the companies are aggressively working these issues.

So I think for everybody that we deal with, it won't be – and investors deal with, the large public companies, it probably will not be an issue. it may be for companies that don't term up and don't have committed acreage agreements.

Hey, I just wanted to remind you, we've been drilling in these fields, Spraberry field and even at Delaware, since the 1940s. So we're very fortunate to be in the Permian Basin.

And also, there's tons of projects we back, mid-stream companies just banging on our door, calling up every operator wanting to build to us and building pipeline. So there's a ton of projects.

So it's not like we're just this new field where it's tougher in the early innings of other plays.

Got it. Thank you very much.

Thank you.

Thanks.

Thanks. Good morning.

I was curious if you could maybe provide any commentary on offset activity in and around your Delaware Basin footprint. As you referenced the high dollar-per-acre values, I think largely driven by multi-zone development.

I believe your tests have predominantly all been in the Upper Wolfcamp, so is there anything you could point to, I guess, in and around your area recently that gives you any encouragement around the other zones?

Yeah. I mean, depending on how discrete you want to partition off a zone and call it a new landing zone, we've seen probably close to 10 discrete targets within a 15-mile radius that we're tracking.

As you thicken up the target zone a little bit and speak more broadly, we're starting to see good tests in the 2nd Bone Spring that is encouraging. Of course, the active Wolfcamp operations that are going on across probably three discrete zones offset a multiple well set.

All encouraging. So, as Delaware is a very good playground and a thick oil column as well, I don't think that the price per acre is unjustifiable.

It just all depends on each company's model and ability to throw rigs out – at it and pull that value forward out of the ground.

Great. That's helpful color.

And in the context of your commentary around M&A, Bryan, seemed like you didn't want to close the door on it, certainly. And I'm just curious, is there a bias one way or the other within your thinking between the Midland Basin and the Delaware Basin at this point in the context of your portfolio?

I think, in my mind, I'm hoping that the price kind of roll over a little bit and get back to reality a little bit. That's my thinking, and I think the team's thinking.

And we need to always be plugged in, and our bidding team is going to be plugged in on every deal in every data room. And yeah, we'll bid.

But I just don't see us winning with those kind of prices. But we need to be proactive.

I see a lot of smaller deals coming in contiguous to our acreage to increase our laterals and trades. We're going to continue doing trades.

Great. And then on the Midland Basin side, can you all remind me how thick – you've been talking a lot about the thickness in the Wolfcamp.

How about the Spraberry on your position? How thick is the Spraberry?

Spraberry is around 2,000 feet thick from the top of the Upper Spraberry to the Dean, base of the Dean where the Wolfcamp transitions. It's fairly uniform across the Basin.

Lower Spraberry where we've been focused, so we're on 500 feet thick.

And there's some commentary from your peers around three zones and potential development of three zones within the Lower Spraberry. Do you have any views or thoughts on potentially testing that within your acreage or at least focusing on development?

Yeah. We plan on methodically increasing density testing, both vertically, which is what the additional zones for bench and laterally over the next couple of years.

So, a lot of rock in place. We think we're conservative on our Spraberry counts, just by virtue of how we've – we haven't drilled a lot of wells because we've been focused on the Wolfcamp.

So starting on it concerted now, and over the years, we would probably catch up to the industry counts.

Great. That's helpful.

And then last one on my end. I'm just curious, can you all quantify at all the amount of shut-ins that you're modeling in the context of the fourth quarter guide?

It's always been included. Just for a frame of reference, we had about 1,500 barrels a day on average on the third quarter.

And then, on the fourth quarter, we're running around 46,000 barrels a day in October, but we do have a large pad that we're proactively taking offline in December, and then we'll be bringing it back online late December, that goes into that. So it would be north of the 1,500 barrels a day that we averaged in Q3.

Okay. Is that typically pretty – I mean, that 1,500 barrels a day relative to your reported 3Q volumes, is that pretty typical of an average amount that you would have shut-in if we kind of prorate that with production?

Yeah. That's been about normal.

There weren't any large concentrated activity. And then if you do that percentage-wise, as we continue to grow over the years, that's probably about the right percentage.

Okay. Great.

Appreciate the color, guys. Thanks.

Good quarter.

Thanks.

Good morning, guys.

Morning.

Good morning.

On the base case assumption of the six rigs in 2017, should we still assume that that would be evenly split, three in the Midland, three in the Delaware?

That's correct, but mainly around on the minerals. We've got some obligation wells on our acquisition of I think like three to six wells.

Okay. And then when I'm looking at the different testing you're going to do on the Wolfcamp A next year, I notice that there's – it doesn't show anything for like an Upper/Lower A stack test.

Is that in the cards next year?

That's the plan. Just by the specific pad that we're starting on where we – where are the slots, where we're going to start with the stagger, but we think 330 feet across gives a similar answer.

So subsequent to that at some point would be a direct stack.

And, Matt, what's the timing on that Upper/Lower A stagger test? I know it's a 2017, but do you have more specifics?

Is it first quarter? Or...

We don't have any additional specifics at this time as we're going through our 2017 plan and moving the rigs around to trying to push it earlier rather than later. But we don't know if that's first half yet.

Okay. Thanks a lot, guys.

Nice quarter.

Thanks.

Hey, guys. Good morning.

Good morning.

Bryan, I think you said that the A&D market kind of currently at this $30,000 an acre to $40,000 an acre type level. And I'd love to get your thoughts on what you guys think this implies or infers about the number of wells or potential zones that are getting credit from bidders?

And I really am curious, what do you think this ultimately goes to if you take these inventory levels up to going from 20-some wells a section to 60 wells a section; what do you think the A&D market could get to at that point? Just wondering where we are in terms of the industry's de-risking at this point.

Thanks.

I think that the multi-bench – I think there's credit there. But these high, high prices, the only way I can get to it is adding rigs.

We got to add a lot of rigs. And so it doesn't matter if it's like one bench clear across.

If you add eight rigs, you can get like 20% return. So that's kind of the – it's back and forth, right, looking at multi-bench.

And yeah, 60 wells per section, you're thinking maybe the price of poker should go up or be in the $40,000-plus. At the same time, it's all about bringing value forward.

And running it through your models, through the reservoir department and can you make money over the next few years. But yes, I mean, if you run eight rigs, it does kind of make sense with $40,000-plus an acre.

Okay. All right.

Great. And I may have missed this, but, Matt, if you ultimately go to 500 feet – or I'm sorry, 330 feet between wells, do you expect that 1 million barrel EUR to hold up?

Thanks.

No, we'd anticipate some degradation there. When we went back on the vertical wells, you'd see about an 80% reduction from – I mean, sorry, 20% reduction from 160 acre to 80 acre, from 80 acre to 40 acre, and so forth.

So that's in the recovery range. I gave one example of the 750 MBoe curve, and we feel that somewhere in that order when you get down to the 330 feet to expect some degradation.

Okay. Fair enough.

Thanks, guys. Great quarter.

Yeah.

Thanks.

Good morning.

Morning.

Morning.

Hey, Matt, you had mentioned, I think, in your prepared comments obviously looking at doing more enhanced completions relative to your currently 1,900 pounds per lateral foot. Obviously, the monster frac was that it had grown 2,600 pounds.

Where do you envision that number actually falling? And is there any influence of tighter spacing, making you want to back off a little bit from the upper end of that range you've tested?

Yes, all of that comes into it as going into the modeling and testing into our eight-well pad. If you look chronologically on how we pump throughout the years, it's been a steady climb in the loading.

And then we jumped out on the 2,600 pounds per foot loading and as it sits today, it's an economic venture. And we would continue doing so, but we are also modeling what happens if – we're not seeing this yet, but what happens if you get a 50% increase in sand cost and what does that do to the economics and where is the break-over point.

So that all goes into the design. And then as we go down to a 330-foot or full-density spacing, there's an argument that we don't need physically as large as volumes per stage and you right-size your drainage radiuses there.

So we think we have a pretty good cocktail together. And then also, as I mentioned, in 2016, we have a lot of discrete testing on variables.

One was only sand-loading, one was only water volumes, one was perf geometry that we're working on, another one stage-spacing, sand size, sand type. It's exciting, we've seen kind of incremental improvements on all of those in our concept and 2017's plans will be putting those designs all together.

And then in the Delaware, we started with our Midland Basin baseline. We have jumped up to the 2,600-pound, 2,800-pound loading, saw a market improvement there, and we'll continue to push on the sand-loading on the Delaware side.

And just to clarify, so it sounds like the Delaware 2,600 pounds to 2,800 pounds is your, I guess, base design or maybe a good average to use for 2017. What are you going to be in the Midland on average in 2017?

What would you suspect right now?

We'll just keep grinding up in the Midland from the – extrapolating between the 1,900 pounds and the 2,600 pounds as we watch sand-loading and the long-term tail of the monster frac.

Okay. Okay.

Understood. And then with respect to pad development, what is your plans in the Midland Basin generally speaking for 2017 and beyond, how many wells per pad?

Can you talk about spud-to-sales timing just to help us with some of the ebbs and flows we're going to or could see with production as we go through the next several quarters?

I think it'll be fairly linear. We do a lot of pre-planning on that front, but we do obviously have the eight-well super-pad.

That's the largest single pad. We have one to two five-well pads planned and the rest are three- and two-well pads.

Where we came in planning into 2016 at 50% pad planning, we like the results and increased to about 80% and we've accelerated the conversion to 100% here in the fourth quarter, and that's driving that production profile. And then it should be as smooth as we can make it throughout 2017.

Okay. Then specifically again...

Cycle times you could be, on a three-well pad, 160 days from first spud to first sales on a two-mile three-well pad.

So, on average, is three-well pads generally a good average to use throughout the year?

Think so.

Okay. That's great.

Thanks.

Good morning, guys. I wanted to go back to cost inflation, but take it from a little bit of a different angle.

So, you guys and a lot of your peers have guided to or mentioned pretty serious activity acceleration going into 2017. So it seems to be predicated on roughly $50 oil.

Do you guys see a price lower than that at which there's less activity and hence no real upward pressure on service costs? Or do you think there's going to be service cost pretty much no matter what – service cost inflation rather, pretty much no matter what next year?

We have a lot of acquisitions that just got done throughout the first half of the year on a big way in the Permian and you need to execute on those acquisition plans, these broader companies speaking here. So I think the rig count is coming and I think people will hedge or stay active through it.

So I think you need to be planning for tightening services to some extent every way you can.

Yeah, that makes a lot of sense and it sort of feeds into my follow-up too. I mean, you've gotten questions on how high the A&D market can go.

Is there a price at which you think that cools off given that companies will be less able to really justify the acceleration and can't make acquisitions accretively?

No, I think it's the top. You think it's the top.

If oil goes up to $55, I mean, you're thinking the margins are going to – the service costs are going to come up, and so maybe we see the top of our margins and our returns. I think we're right around 80% returns on our Midland Basin, Wolfcamp wells.

So give or take 5% on that. But we're shocked.

We're kind of in shock. I don't know what to say about these $40,000-plus an acre deals unless you're a transformation company.

You're transforming from a gas company into an oil company, or you're light on inventory. But it seems like there's only a few more companies that are going to move in on the Permian.

So maybe we stabilize from there.

Got it. Appreciate the color, guys.

Great quarter.

Thanks.

Good morning. Thanks for taking my question.

So when you all highlighted the production, CAGR, sensitivity last quarter, was that predicated on 7,000 foot laterals? Or did that account for the increase to 8,000 foot laterals?

It is accounted for our view of our lateral range at the time. There have been some incremental trades even from there.

But for the most part, it included an additional lateral length.

Okay. And then on the Lower Spraberry well, I was just wondering, how should we think about the EURs on a lateral-adjusted basis, just following this positive two-mile test.

That would be a guess at this time because the decline rates are so much flatter on the Spraberrys. Off the cuff, I don't think that 1 million barrel is out of reach at all for that well with the type of decline we're seeing.

But we're going to need a – since we only have two wells there as opposed to our 15 to 100 well dataset on the different zones in the Wolfcamps, we'll just be looking at it over time.

Okay. All right.

That's it for me. Thanks, guys.

And good quarter.

Thanks.

Good morning. Just curious, does the higher proppant loading have any effect on the stress shadowing that you're seeing in the Midland Basin?

We don't necessarily think so. We think it's – we see it in early time treating pressures and we think it's due to the distance away and from the previous well pumps and maybe the volumes of the frac, not necessarily the sand.

When we look into 2017 and that kind of growth expectation that you laid out last quarter, did that assume stress shadowing effects in the Delaware? Or is that something that we won't really pick up until 2018 forward?

We had assumed it in the Midland. Not really going to probably pick up much of it in 2017 in the Delaware.

Okay. Great.

Thank you.

Hey. Good morning, guys.

Just wanted to follow up on some of the downspacing questions. Are you guys expecting a 20% EUR degradation for the triple-stacked A Upper B Lower B if they're completed on 660 feet apart?

Or is that only in reference to that 330- foot downspacing?

No, that was only in reference to the 330-foot downspacing in the same zone.

Okay. And at what point would you typically expect to start seeing that sort of degradation in the performance?

Is it a 20% lower first year cume or is it further out in the life of the well?

It's disproportionately weighted to further out in the life of the well.

Okay. Got it.

Thanks a lot.

Welcome.

Everyone, thanks for taking the call. This is a game-changer Upper and Lower B.

We're very excited about this and potential Double A in the future and downspacing in the future. There's a lot to look forward to, and we look forward to seeing you in the conferences.

And, oh, Go Cubs.