Industrias Peñoles, S.A.B. de C.V.

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

During this call, we'll refer to an investor presentation that could be found on our website. And our remarks may contain forward-looking statements, so please see 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 the 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 posted double-digit percentage oil growth again in Q3, all organic, the fifth time in the last six quarters that we've generated double-digit organic oil growth.

And we accomplished it despite various unanticipated developments, including a hurricane that affected the Gulf Coast region. Zooming out, since our IPO, we've quadrupled oil volumes almost entirely through the drill bit.

We show our production growth on slide 4 of the investor presentation and it's important to note that this growth has accrued to our shareholders. Even when adjusted for the balance sheet expansion that reflects the acquisitions we've made, we've generated more production growth per debt-adjusted share than our peers.

The drivers of this outperformance are straightforward. Our top tier well productivity to cost ratio, along with liquids-heavy production mix, translates to superior capital efficiency as you can see on slide 5.

As we show on slide 6, the third quarter represents a key checkpoint for Parsley Energy in our pursuit of long-term value. So far this year, we've added almost 100,000 net acres, cored up that acreage, doubled our activity pace, kicked off development in three new counties and target four new zones, all during a period of basin-wide activity expansion.

Not only have we navigated the steepest activity ramp among our peers, we've tackled one of the most ambitious delineation programs as well. Almost half the wells we've drilled and completed over the past four quarters have been in new counties, targets or spacing configurations.

The result of all these is that we're now firmly established in all of our core operating areas and we believe we had a good handle on the depth and quality of our inventory and how to develop it. The acquisitions we made in the beginning of the year were designed to position us for the next decade and they have.

Along with subsequent trades, the acquisitions also prompted significant reshuffling of our 2017 development program. The result was a program that looked much different than the set of wells we expected to drill when we first issued guidance.

And yet, despite changes to the drilling schedule, weather events, deferrals from our non-op partners and basin-wide growing pains that have affected the industry at large, we're still on track to come in within the production range we originally guided to. And now, with the steep activity ramp winding down and the acquired assets mostly absorbed in our portfolio, the path forward is coming into view.

In 2018, our focus will return to our most familiar and productive target zones. We also plan to transition to a more measured development pace in 2018 that prioritizes operational continuity and financial stability and takes another big step toward free cash flow generation.

Even at this steady pace, we expect to deliver robust oil growth with top-tier capital efficiency. We're still refining our 2018 plan, but at this point, we expect baseline year-over-year oil growth close to 50%.

This assumes that we bring around 40 wells online per quarter, which is about what we expect in Q4 of this year. So we're getting close to our go-forward development cadence.

Slide 7 shows that the combination of production and spending associated with our preliminary 2018 outlook could extend our track record of capital-efficient investment. And if our hunch is correct that on the whole, capital efficiency in the Permian is headed lower next year, we might end up comparing even more favorably on the efficient spectrum as 2018 comes into focus.

Extending our gaze just a bit, if we were to hold the steady pace I've mentioned for the next two years, at current strip prices, we'd expect to achieve cash flow neutrality sometime in 2019, with no need for incremental funding in the meantime given current cash on hand. And as long as we're considering hypotheticals, if we were to maintain a constant development pace indefinitely, we project several billion dollars of free cash flow over the next decade, which speaks to the depth and quality of our existing drilling inventory.

Our objective is to maximize the discounted value of this wave of cash flow, to follow the path that yields the highest corporate returns over several year timeframe. If that path involves higher activity, we will take that path as long as it makes sense from an operational and balance sheet perspective.

We see our outspend compressing on almost any scenario. To assure everyone, we could be cash flow neutral right away if we chose.

But the goal has always been to build a company that is able to invest large amounts of capital at high rates of return, to grow into a sustainable cash flow generation machine and the steps we've taken in recent quarters position us to do that. With an eye on the long-term prize, our task is to put one foot in front of the other as we turn these possibilities into reality.

I want to circle back to our near-term outlook to emphasize that we're well positioned to take these next steps. As we've discussed, this year has been unusual in several respects.

And yet, we've still delivered top-tier organic oil per dollar. On the whole, our operational performance has been strong.

Essentially all Permian operators, Parsley included, have seen completions pushed out this year. For us, this is primarily a function of two things, acquisition-related drilling obligations shifted us to new areas and we experienced delays on our biggest project of the year, the eight-well downspacing pilot we talked about last quarter.

And those delays radiate throughout the program. Other than that, we've experienced nothing that wouldn't be expected as part of the normal onboarding process for new rigs and frac crews of which we've had more than anyone.

Having just now satisfied our equipment needs, we're optimistic as we look toward 2018. As a company, we expect to build on the operational momentum we've established this year with a steadier activity pace and greater visibility on our development plan.

As an industry, we do think there could be some challenges given ongoing tightness in the labor market. But Parsley should be relatively insulated next year with a stable activity profile.

We've also derisked 2018 from a financial perspective with a very robust hedge position. So, even in a downside scenario, we'd expect to keep running at a steady pace next year.

Our hedges also help from an operational standpoint by enabling us to plan more concretely. So we feel like our steep climb will pay off and we anticipate flatter terrain in 2018.

With that, I'll turn it over to Matt.

Thanks, Bryan. Our body of work to date has truly been staggering.

For reference, we are the basin's fourth largest operator when ranked by operated stimulation fleets. This gives us an advantaged voice in the marketplace.

During the third quarter, we set a company record for most completed footage by a significant margin and we're running the equipment we need for our baseline 2018 program. We're approaching our stabilized completion pace.

And as Bryan commented, we hope for efficiency gains as we hit our regular stride. I wanted to expand on Bryan's comments about the acquisition integration process.

Our commitment at the time of the Double Eagle acquisition was to extract maximum possible value from the assets and we are well on our way. One example is the ongoing progress in coring up the acreage.

As you can see on slide 8, the third quarter represents our most active period yet in terms of acreage and inventory added through trades. Recent trades added more than 1.2 million lateral feet to our horizontal drilling inventory, on top of 1.4 million lateral feet previously added following the Double Eagle acquisition.

All told, these trades have added the equivalent of more than 10,000 premium net acres with four target intervals to our portfolio. And to be clear, these figures are net of acreage traded away, most of which was non-operated with low working interest.

Turning to slide 9. Recent transactions value core Midland Basin acreage at more than $40,000 per acre.

So on that basis, we've added several hundred million dollars' worth of value without spending a dime. And now that the geometry is in place, we're ready to concentrate on the core development blocks we've constructed and consolidated from the acreage we acquired this year.

A significant challenge with many acquisitions is the assumption of legacy wells, many of which may require remedial work. Slide 10 shows that after an uptick in LOE last quarter that was largely driven by acquisition-related workovers, LOE per Boe has already turned lower in the third quarter.

We've already reduced LOE per Boe on the operated wells we acquired, in contrast to the trend that we see on acquired wells which we don't operate. I think this speaks very well of our operational proficiency, processes and systems and of our commitment to extracting maximum value from our asset base and production stream.

The Double Eagle acquisition transformed Parsley in many ways, one of which is that it expanded the breadth of our drilling program. On slide 11, we've introduced new reference curves to update for actual results, our current asset base and our anticipated development program.

The 1 million Boe curve we introduced shortly after our IPO was based on the performance of Wolfcamp A and Wolfcamp B wells in Upton and Reagan Counties, which represented the extent of our horizontal drilling program at that time. Actual results in those areas has exceeded 1 million barrel curve to date, but no longer represents the best proxy for our broader program.

Now, of course, we've expanded into several new counties. We're targeting new zones and we're drilling longer laterals as well.

The new Midland Basin curve is a composite curve designed to approximate the productivity of the Midland Basin wells we expect to drill over the next couple of years or so. There are, of course, differences by area and formation and we'll plan to organize actual results accordingly.

But for the sake of simplicity, we think a basin-level reference curve is most helpful for modeling and evaluating well productivity. There are a couple nuances to note relative to our previous curve.

One is that we've set the lateral lengths to 2 miles to more closely match our anticipated development program. Another is that whereas our previous curve started at peak daily rates, we've started the new curve at first production and incorporated a ramp-up period to better reflect actual well performance.

Compared to the previous curve, the new Midland reference curve has equivalent oil per lateral foot at the two-year mark, even with the ramp-up period and also the life of the well, reflecting the flatter long-term declines that we have been seeing. And the new curve has higher gas and NGL volumes, consistent with our actual results.

As you can see, our Wolfcamp A and Wolfcamp B wells, which still comprise a significant portion of our drilling program, are closely tracking the new reference curve. Composite Lower Spraberry results started slightly lower, but converged with the curve over time with a flatter decline profile.

And early results on two Wolfcamp C wells are very promising. We're also introducing a Southern Delaware reference curve.

Here again, the curve represents expected results from our anticipated development program in the Delaware. Oil volumes are a bit higher than in the Midland Basin curve, while gross gas and NGO volumes are a bit lower.

The key takeaway from these new reference curves is that we have significantly enlarged our asset base without diluting the average quality of our wells. Turning now to updates on a couple of new initiatives.

We remain excited about early indications from the Wolfcamp C formation. Our first well, the Taylor, continues to churn out oil up to almost 300,000 barrels of oil in the first eight months.

Slide 12 shows that the second well, while not a basin record like the Taylor, is holding its own with a 60-day IP of more than 1,500 Boe per day. Taken together, these wells continue to suggest that the Wolfcamp C could be situated in the upper tier of our inventory and we continue to move forward with tests across a broader area.

With several industry Wolfcamp C wells in process, we think our early success in the interval highlights our leadership on the technical front and, in context of our acquisitions, our ability to perceive value where others might not. Turning to slide 13, we are constantly exploring various design adjustments that could enhance the economic profile of our wells.

Among these are compressed stage designs that we first discussed last quarter. We remain encouraged by early results.

The first test continues to outperform offsets by a widening margin, and subsequent tests are tracking ahead of offset wells as well. Productivity gains are outpacing more modest cost increases, yielding a favorable economic profile.

We'll continue to monitor these wells and have several additional tests planned. As always, capital efficiency, not maximum productivity, will be the criteria.

As we look ahead, with signs of tightening services in labor market and a number of operators discussing rig and fleet additions, we feel we are ahead of the game at this point. With a stable development pace on tap and a renewed focus on established targets, we're confident in our ability to deliver differentiated results as we move forward.

And now, I'll pass along to Ryan to discuss our financial positions and results.

Thanks, Matt. Third quarter production growth flowed through to the bottom line with adjusted EBITDAX of 15% versus Q2 to $165 million.

CapEx was up just slightly at $307 million in Q3 versus $295 million in Q2, as drilling and completion activity came into balance following a quarter weighted more towards drilling. Unit costs were favorable as LOE per Boe reversed course after increasing in Q2 on acquisition-related workover activity, down 11% to $4.41 in Q3.

And cash G&A per Boe decreased from $4.50 per Boe in Q2 to $4.32 per Boe in Q3. We've taken steps to fortify our financial position and lock in the baseline 2018 development program.

On the liquidity front, in early October, we issued $700 million of 10-year notes. And on slide 14, you could see how this bolstered our liquidity.

As Bryan mentioned, we see this funding as a bridge to cash flow neutrality at current oil prices. But of course, our revolver is available, if necessary, and in fact, we recently increased our borrowing base to $1.8 billion, while leaving the committed amount unchanged at $1 billion.

Capital markets can open and shut without much warning and we think it makes sense to work from an advantaged liquidity position. Turning to Slide 15, we've been aggressive with our hedging program, which protects our cash flow and equips us to move forward even if oil prices retrench.

Note that the majority of our barrels are hedged with a put spread structure, which retains all of the upside, while also providing downside protection. So, our risk management efforts have been diligent.

We've managed commodity risks by adding significant hedge protection through 2018 and into 2019. We've managed operational risk by lining up the rigs and crews we will need and we've managed liquidity risk by ensuring that we have low-cost funding in place to keep those rigs and crews running without relying on other funding sources.

I'd like to speak briefly about our incentive structure. As you can see on slide 16, management has a far larger stake at Parsley than is the case at any of our peer companies.

Parsley's long-term, performance-based incentive plan is based exclusively on total shareholder return relative to peers. And the company's annual incentive program balances capital efficiency, cost and production metrics.

So we're focused on the same thing as you are and we're excited about the value creation potential we see ahead. With that, we'll be happy to take your questions.

Good morning, everyone.

Good morning.

Bryan, in your prepared remarks, you talked about the potential to become free cash flow positive if you so chose. Can you give us a little more color on how you're thinking about that more steady pace of activity that you mentioned and then whether free cash flow neutrality is a priority for you and how you're thinking about that going forward?

Yeah. It seems the past four to six weeks has been the top theme of the investors compared to six to eight months ago as if we can get sand.

But we feel like this is a subject to address. And for modeling purposes, we're just pointing to a point in time some time in 2019, if oil prices stay at this stage flat and then we run the same amount of rigs as we are in the fourth quarter.

So, to me, it's sort of a check in the box and to show what can be done. Now, I don't think that would be our mentality.

But for now, for over the next six to eight months, I do see us running the same amount of rigs we are running walking into the 2018. We're not adding more rigs.

I don't know if that helps you.

Sure, Bryan. Yeah, that helps.

And going forward beyond 2018, you're talking about a more steady ramp, is it – can you dimension that for us at all, just a ballpark of what you're thinking in terms of is that adding just a small number of rigs each year or a small amount of incremental capital growth or can you dimension that at all for us?

Well, the incremental activity must drive value creation. So, that's the first thing we'd look at.

But with this preliminary outlook, I don't really want to comment on really rig additions in 2018 and 2019, but you've seen the history of Parsley. I see us continue to grow our base.

But the most important thing is and what I've been very vocal about is our spend needs to continue to decrease versus our cash flow. And so, there is light at the end of the tunnel in the next two to three years.

Thanks, Bryan.

Thanks.

Good morning, Bryan, to you and your team there.

Good morning.

I wanted to also go back to your prepared comments. And you made a comment that I think I agree with about the capital efficiency basin-wide in the Permian probably deteriorating in 2018.

And I wonder if you could share what you see as the drivers of that. I think you already touched on a few, but I'm curious if you can just elaborate a bit.

Well, a lot of it is we've been high-grading the past two to three years, hitting our – the top projects, Wolfcamp B over and over again. Those were like 70% returns.

We still have a lot of those returns in place now. And then I think you're just referring to the completion delays that we've seen through the past couple of quarters, throughout the industry, the entire industry.

We've just seen bottlenecks such as labor. I think that's well-known right now.

The number one issue right now is labor going into 2018. So, fortunately for us, is we've got our completion crews set.

We've got the rigs. It's set.

And so we're not shuffling. We're not adding rigs in the first or second quarter of 2018.

So I feel like we're set for the next six to eight months on this front. But there will be labor issues.

Got it. That's helpful, Bryan.

And then I wondered if I could ask a question, and perhaps this is for Matt, about the Wolfcamp C. I'm wondering with the benefit of not just a couple more months of production, but also the work you guys have been doing, are you – any – do you have any lessons that you'd be prepared to share right now or maybe a different outlook for the Wolfcamp C in 2018 based on the work you guys have been doing?

I'll just say that it's a pretty early placeholder in this outlook and something very achievable that doesn't necessarily even reflect the results of just those two wells because two wells is not a data set. So we're extremely encouraged by the two wells that we now have some longstanding production data on and turning to production tomorrow morning, the third and subsequent wells will come quickly behind that.

So, the database will be building here quickly and as we roll into 2018, that should be a refinement point for us that we're excited about.

Thanks, Matt. We'll look forward to hearing about those.

Hi, guys. Good morning.

Morning.

A couple ones from me. Matt, I know you've previously looked at and kind of quantified the number of frac stages you guys complete on a daily basis for just the – in an effort to just gauge how you guys are trending on the efficiency front, I wonder if you have that metric handy and how that's trended and how you expect that to trend as you go forward here?

We did throw out a number at Barclays that we kind of hit a few times in one-on-ones, and that was a number just representing a stage while they're running. But it wasn't necessarily a modeling stages per day as a fleet is running, but it wasn't necessarily a full year modeling when you take in account mobes (25:33) between crews and all of that and between wells.

So, we are – we have stabilized there. So, our peak efficiency occurred in the fourth quarter of 2016 and we have stabilized since that point, now that we've got these new crews on the bank and have five active crews running and we're seeing about a two-month uptake to get those crews back to where we'd like to get them.

And we have all of the crews except for one have been running for two months or longer. So, we're using the rate that we're currently at in our 2018 forecast on efficiency, timing on stages per day across the basin.

It's different on Delaware due to the sizing of the fracs in Midland. It might average out somewhere in the – if you do 365 days a year, you might do five stages per day – four-and-a-half to five stages per day per crew.

So, that's different than the – as their running rate, we'd like to see the crews hit a peak anywhere from 7 to 10 stages a day depending on the stage type and the count. So, hope that's helpful.

But it has stabilized on the cycle times there and then we hope to just improve upon that now that we have all of our fleets in place.

Got it. Okay.

Thanks. That is helpful.

And that kind of dovetails into my question. If I'm looking into the 2018 guidance, you guys have in the slides here, that you expect about 40 completions per quarter.

I'm curious what that does, what that implies for cycle times or spud-to-spud, and just get your sense on if that 40 is something you ultimately hope to beat as you go through the year. And then just to bolt on to that too, just – if we look at that production number throughout there, just curious on the trajectory through the year.

Should that be pretty steady pace as we're modeling this or does something stand out in terms of just how that production should flow? Thanks.

No, it really should be. It's a derisk program going into 2018.

As I mentioned, the body of work in 2017 was complex. It was staggering and it borne out tremendous value to the company through Wolfcamp C discovery and others.

Going into 2018, we're hitting the known quantities. We have a tremendously deep inventory of the known benches, on the premium benches.

So, we don't need a discovery of any new benches. We don't need to test any new downspacing.

We've kind of dialed it in. So, the fact that we're assuming current cycle times and we have our fleets in place, we have our rigs in place, I think, is a good midpoint, is a good conservative guide.

And we obviously hope to improve upon that as the year unfolds.

Great. Thanks, guys.

Thanks.

Good morning, gentlemen, and thanks for taking my questions.

Good morning.

So, Matt, you continue to highlight some really positive results from the compressed stage spacing tests. I was just wondering, how much data would you need to see to transition the bulk of the Midland Basin program to these compressed stage spaced wells next year and how quickly can that happen?

Is that something you could just go to in like Q3 of next year or would it take six to nine months to transition the entire program to compressed stage spacing?

It can happen very quickly. It's a decision point on economics.

You want to see these things unfold over at least six months' timeframe. We'll continue to feather them in the meantime.

You're testing in new areas, but nothing dramatic across the entire program. But again, you're not – it's just a design change that you can do on the fly.

And it's very quick, as you call out your materials needed for that design. So, I would expect a decision to – in the first half of the year for the back half of the year, I would assume.

Excellent. That's what I was looking for.

And then just one quick housekeeping item from me. Out of the 40 completions in Q4, are those 9,500-foot laterals or are those 9,000-foot laterals?

Right now, they are 9,000-foot laterals. So that's a little bit of the difference.

That's a new data point on the quarter. It's longer than our average throughout the year.

And then, as you mentioned, the 9,500 feet, that will be our average for 2018. Just to circle back on a previous question, I think there are some cycle-time questions on spud-to-rig release.

In the Midland, we're about 26 to 30 days per 10,000 footer. Delaware, about 40 days.

Okay. Thanks, guys.

Thanks. Good morning, everyone.

I have two unrelated ones. Thanks – Matt, thanks for the updated type curve on Midland.

But could you provide some additional color on dispersion it resolves by counties, areas? And also, is there a way to quantify how much of the scale-up was due to longer laterals or modification and completion designs or acreage quality?

Sure. So, it's a pretty broad footprint, but I can walk through some generalities.

Generally, as we go north into Martin, Midland counties, you see slightly higher oil production over the life and lower gas production and a little bit flatter declines. And then it – and actually, I phrased that wrong.

You just see – as a percentage, you see flatter declines, but our highest oil rates on an absolute basis are in Upton County. But you do see an earlier peak production out of those Upton County wells, and then they flatten out.

And then, Reagan County is kind of a mix between those two statements. It will probably be the higher gas content over the life of the well in Reagan County.

And then – now we need to talk, that's the generality across all benches. But now, if we talk from the bottom up, Wolfcamp C is its own animal.

That's probably going to be very high flush oil production and good stabilized oil production rates as well, but higher gas. And right now, we see that development in Glasscock, Reagan and Upton potentially.

And then, Wolfcamp B is the most prolific in Upton and Reagan. And then, as you go into the Northern counties, you'll be focused more on the Spraberry's.

And then, Delaware Basin, as you go to the East, we have an extremely high oil content, as you noticed in the Delaware Basin, we're on the Eastern edge of the Southern Delaware Basin along the oil window. The majority of our 2018 program will be focused on where we have mineral ownership, and that's a high oil cut area.

The Reeves County stuff is about 65% crude as you go a little farther West.

Excellent. Very helpful.

And then on – some of your peers have begun to test in-basin sand, and they're seeing some positive uplift on savings. Can you talk about whether you are conducting similar tests and what your thoughts are on that?

Yeah, we have agreements in place to steadily pump that down wells throughout Q1. We do expect some good savings on the total well costs in line with what everybody else is seeing.

We're also encouraged that just additional supply on the market will suppress the broader sand market. So the other white – premium white sand just won't have as much demand.

So it'd be nice from that front. But we are testing it in Reagan County in Q1.

We actually have some in the well as we speak, but not under a price-saving agreement. That was just kind of a jump-start to get some data back and make sure nothing is out of whack on that front.

But yeah, we'll start seeing cost savings throughout the Q1 timeframe.

I wanted to mention that we – this is not baked into our preliminary, so there's potential upside on the Permian Basin sand if we go that direction.

Great, Bryan. And if I can sneak one in, you mentioned capital efficiency is heading lower in the Permian.

And now that you're 100% or fully hedged with 2018, is there a way to quantify how much of the cost side of the business is locked up for PE?

To quantify the cost.

We have about a quarter of our drilling costs, which would be our contract day rates locked in. And then our tubulars, which is another quarter to bring us to 50% of our drilling site, we bulk out at about two quarters at a time, so we have most of our first quarter needs will be going out for second and third quarter here shortly.

And we're encouraged by early indications of the market on that. So that's roughly 50% of our drill spend, and then the completion is roughly exposed to market conditions.

We have key performance indicators and we have – but we don't have a lot firm pricing target on the completion side.

Typically, we don't – we avoid signing contracts with frac, but we're debating it as we speak.

Great. Thank you.

Good morning, gentlemen. Probably a question for Matt.

Just wondering – or even Bryan. You talked about the efficiencies I think on a prior question and I'm just wondering given the plan for next year, will that continue?

We pretty much stick with the 14 rigs, would the frac spreads vary or if you could talk about as far as just what you thought the optimal rigs and frac spreads would be for next year given the efficiencies you're seeing?

Yeah. Right now, as we model it, we can get everything done with our 14 to 15 rigs and 5 frac spreads.

So, if we start seeing gains in efficiency, as you build out the banks towards the end of the year, you may not need an extra frac fleet or if you jump-start on the drilling side, you may need to pick up an extra frac fleet if you start making more hole than you forecast, but we have a pretty good range in there on assumptions. So I think that's going to be sufficient for us throughout the year.

Okay. Great point.

And then just one last follow-up. Bryan, I think, in your prepared remarks, you talked about just to continue sort of developmental plan for next year.

Does that – I'm just wondering with that plan, does that – what type of multi-zone development, will you continue to sort of push the limits on that or are you sort at the areas, when I look at anywhere down in recent Pecos (37:55) all the way over to your large Midland footprint, will you continue to push that multi-zone development?

No. I think in the comments, we're dialing down back, I guess, from 2017 going into 2018 on de-risking zones and down spacing from, I think, is 25% down to 5% to 10% potential new zones in our CapEx plans for 2018.

We're going to focus on Wolfcamp A, Wolfcamp B and then the main target in the Upper Wolfcamp in the Delaware.

Very good. Thanks guys so much.

Good morning, guys. A question on next year's CapEx program and you guys obviously talked a lot about kind of how efficiencies can potentially change in the industry and then whatnot, but just from a high level, can you guys talk maybe what kind of well cost assumptions are generally baked into 2018 CapEx number either on an absolute basis or just directionally how you all are thinking about well cost changing into next year versus what you've seen year-to-date here in 2017?

Yeah, for our 10,000 footers Midland Basin, around $8 million to $8.5 million pegged in these assumptions, and Delaware around $11 million to $11.5 million.

Okay. So, that's kind of current costs as well as what you're forecasting into next year then?

That's right. Yeah.

Okay, got it. And then you guys were very active last quarter on the trade front.

Just kind of wondering where you guys stand on that side of things? Would you say most of the heavy lifting has been done with the Double Eagle acreage that you guys have kind of earmarked for trades, or I guess just trying to get a sense for me, what inning we're in there on the trade front?

I'm probably jumping the gun a little bit, but I am excited about another slug of trades coming through this quarter and next quarter. You just never know the – that these sort of trades are with larger companies and it takes a lot more time to deal with them and go through multiple lawyers and land departments and their asset managers.

It's a lot easier with these mid-tier companies; kind of two to three people to get it done. So that's our next focus, is the larger companies.

And amazingly, they are talking to us. So it's – I think they've been vocal in their slides how they want to trade when they present.

And so that's the big positive this – that the swaps and trades is working, they're working for everyone, creating value out of thin air.

Okay. Perfect.

That's great to hear. I appreciate the time, guys.

Thanks.

Hi. Good morning, everyone.

Good morning, Jeanine.

Morning.

So, Parsley has had tremendous production growth over the past couple of years which has been very positive on a debt-adjusted per-share basis as you mentioned. But it also puts you on a steeper treadmill.

So my question is what's your PDP decline rate right now? And can you talk about how you see the trajectory of that over the next few years.

So specifically, how much of a factor, if any, in your path towards cash neutrality and sustainable growth is flattening that trajectory now with more moderate activity?

Yeah. We'll come in over the next 12 months or so around 45%.

There are differentiated declines on the PDP base, so 45% on oil and 25% on gas kind of across the base. And you're absolutely right, as time unfolds here and we reduce this outspend, that corporate decline declines over time and becomes more stable as we get to a more moderated growth rate.

Okay. And then just a more general question as well.

In terms of – given your market cap size, your production base maybe isn't as large as others. Just wondering what you're seeing in terms of what a critical mass size could be for you guys, where you kind of do have that inflection point in your numbers, your base or whatever it is that you can achieve a more sustainable growth without having to be on this faster treadmill?

So this is really just a critical mass question.

I think it unfolds naturally with the outlook that we've given. In that timeframe, we're moving well north of 100,000 barrels equivalent a day, as we've stated our bridge to cash flow neutral on that potential outlook.

And that's plenty of critical scale. But no matter what the volumes you're moving, I think that underlying base decline is more of the maintenance cap that you look at.

When we look at our activity level in the basin, our footprint in the basin and even the barrels that we do move in our marketing agreements, we do think we are – we have a voice from operational scale on many fronts.

Okay. Great.

Thank you for taking my questions.

Thanks, Jeanine.

Good morning, and thank you for taking my questions.

Good morning.

Was wondering what the rough split of capital between the Midland and the Delaware is in the preliminary 2018 plan?

Should be similar versus 2017's 65:35; 65%, Midland; 35%, Delaware.

Okay. And then I wanted to make sure I kind of heard the earlier response correctly.

Well costs or cost inflation, there's no additional cost inflation assumed in the 2018 guidance versus current levels? Is that...?

I think that – yeah, any cost assumptions would be off a midpoint into the upper end of the range. That's how I'd think about that.

Okay. So, the top end of the range protects against that increase?

Yeah.

Great. And then, Bryan, if we play out the productivity headwind that you kind of talked about earlier in your comments, one of the thoughts that I would potentially expect is we could see more consolidation within the basin over the course of 2018.

Is that something that you'd potentially agree with and how do you think Parsley could potentially play a role?

I would agree with it, but I haven't – we haven't seen much. We were just talking in the hallways a couple days ago and it's kind of like test the winds.

The banks aren't even coming through with pitches. I haven't seen anything.

It's been crickets. So that kind of tells you something where there's no deal flow or no one's looking.

I've mentioned in previous calls we're not looking. We feel like Double Eagle was our deal.

And even if a good deal comes across, we just don't need to do it because of our 5,000 high-quality locations, multiple years running room. There are a few – I'm looking at a map right now.

There's a few private equity-backed guys in the Midland Basin that would be attractive to maybe one of our competitors, PetroLegacy, Guidon. That's in South Martin, Mid-Martin and then Sable was the old Aubrey McClendon company.

That has some nice assets in Reagan County. Flipping over to Delaware, I've mentioned this asset before, Felix is north of Whiskey River.

That should be – that would be a big deal. I think that's managed by EnCap.

And then you've got the BHP deal and then a smaller deal, Colgate, both in Reeves County. Those are the only – there's just a handful of deals that I can think of that are out there, but it seems like they've been kind of waiting for a while, wait for oil prices, I guess, maybe above $55 to $60 and maybe run a process in the first or second quarter of 2018.

You don't want to run a process during the holidays.

And I guess just interestingly to follow up on that. Public was certainly even left out of the contemplation.

Do you think there could be public consolidation that we'd potentially see in 2018 or do you think...?

You would think so after all these years, even with this downturn and think there's been some attractive currency widening between companies. And you just haven't seen it.

The only deals I've seen there, the Rosetta and Clayton Williams by Noble. Noble seems like the only one going after public companies.

But you really haven't seen anything in the Midland and Delaware. So two things could happen, you might see consolidation or you're going to see all these pure plays continue marching down their own path with their own story and that could happen over the next three to five years or you're going to see the consolidation.

I don't know when it's going to be. You think it would happen, but it just hasn't happened.

Great. I'll leave it there and let somebody else hop on.

Congrats on all the success in integrating Double Eagle. I'm sure it's been a lot more than maybe what Wall Street appreciates.

So, congrats on that.

Appreciate it. Thank you.

Good morning, everyone. I just want to go back to the compressed stage design.

Looking across the three test areas, there is a delta in the outperformance. I was wondering if you could just give a little bit more color in regards to what's causing that delta potentially.

And then looking at the 5% to 7% incremental cost for the compressed stage line, what is the biggest component of that cost increase?

This component of the cost increase is the additional drill-out time, additional plugs, additional mechanical equipment in the hole. So that's on that front.

The productivity dispersion there, really North Upton, since the company's founding, has been our honey hole. It's got very high productivity.

And usually when you find something that works even out when we look across the basin and when people find something that is bringing a tier acreage out into the economic realm, if we apply it here, it just works that much better. So it's just the productivity index of those wells.

If you stimulate more rock, you get more of the rock flowing. So it's an indication of most likely the outsized rock quality in that localized area.

Okay, great. And then do you plan to test the compressed stage design on the Double Eagle acreage in 2018?

Haven't specifically broken it down to Double Eagle or not, but it would – as we feather it into the program, it makes sense to apply it North. So, I would assume so.

Okay. Great.

Thank you.

Thank you, folks. Good morning.

If you could revisit an earlier question where you talked about the 2018 guide being conservative, could you speak further maybe to how much of a base-case guidance 40 wells on line per quarter represents? I guess what I'm asking is what's the upside case here?

Well, it is the midpoint of our expectations. We don't have compressed stages in there on an across-the-board manner and just the ranges would give room for improvements on cycle times, et cetera.

And there's also just – we haven't really touched on it, but it is clear that it's different versus consensus. As we shift to these long laterals, it's not prudent nor is it capital-efficient over the payout period of these wells to build a facility for the first 15 to 30 days of flush.

And when you have two to three wells coming online on long laterals, that's a significant amount of liquid volumes. So we simply don't see the per-foot peaks and that's by design as we would on these shorter laterals.

So when you roll that into the oil forecast, you don't get the benefit of that 15-, 30-day flush per foot to the same magnitude. So, that's just – there's nothing rock-wise going on different there.

That's just the design decision for payout efficiency, what are we doing for the life of these wells and the life of these assets, we're not going to design a facility for the first 15 days.

Okay. Appreciate it.

Thank you for that follow-up. And then just to be clear, the company is not solving for a cash flow-neutral stake, correct?

And I asked because if returns in the field are – are certainly far and above your cost of capital, what does it matter if you outspend cash flow from time to time especially given how low the leverage sits today?

We're solving for data point modeling purposes to see, at this point in time, with our current rigs running and the NYMEX strip and where we would be, we haven't really mentioned that or talked about it, but we think it's important to talk about to investors. We have 50% wellhead returns and it's okay to outspend here or there like you're saying.

My goal has been, over the next two to three years, to continue the percentage decrease on outspend versus cash flow and then get to cash flow neutral, but not immediately as of today.

Appreciate the answer. Thank you.

Have a great day.

Thanks.

Hi. Just going back on some of the labor constraints you guys are seeing, could you elaborate a little bit more on that and if there's any specific roles, be it completion engineers or geosteerers or field laborer, just trying to understand where were some of the choke points are on the labor constraints that you guys mentioned.

I got one example, I heard the other day that we've had frac night crews or drill-out night crews and usually you get night crews during downturns and because people want more work or the B crews work at the night or C crews and now I'm hearing that there's a big push back on these night crews, and eventually, you may not see these night crews anymore on the drill outs or frac. And it's just something that is evolving and it's back to the norm when we're at higher oil prices, just day crews only.

We're coming up with ways to maybe circulate at night and have a thinner crew or something like that. So there's a way to adapt and make it better.

And we've – we're smarter now through this last downturn. I don't know if there's any more examples.

Or just broadly speaking, when you look at nationwide and even local unemployment rates, the Midland-Odessa area is the lowest unemployed area in the state and possibly in the country, sub-3%. So, it's just a function of the labor pool.

But it is – what we're seeing Parsley-specific is in the third-party vendor supply chain. We have a tremendous team here internal to the company, and we've had no issues recruiting, retaining absolute top-notch talent on the technical front, engineering, land, geoscience, all the way across the board.

So, it's a matter of that supply chain. And I've mentioned to some people before, we – every day, day in and day out, we have on the order of 650 third-party personnel that are on one of our well sites.

They rotate out every two weeks. So that's 1,300 people.

And that's just Parsley and that's through the third party – well, just our operations through our third-party network. Then those guys all have to call out logistics, the last mile on the sand.

That doesn't include the truckers and all of that. So when you're dealing with 3% unemployment, it just takes a – it makes things tighter.

So we're – it kind of ties into why we're really excited that we've done our equipment ramp to-date. We've done our activity ramp and we're in a stabilized state right now and we have our people and our crews and supply chains in place.

And we think that's why we're seeing this bend over and this rollover to the positive and stabilization on efficiencies.

Okay. No, that's helpful.

And then I guess changing a little bit more to a high-level one. With most of the production hedged out for 2018, I guess how do you guidepost on either increasing or decreasing activity throughout the year and how do you compare that decision to make those changes relative to a corporate return metric?

Well, we have – we're not going anywhere for the next six to eight months. We enjoyed a stabilized pace and we're generating around 50% crude oil growth.

It looks like number one versus peers our size. And so we feel pretty good about where that shakes out.

But we just have a few pillars, strategic pillars that we watch and number one is the operational execution capacity. Number two is financial considerations.

As Bryan has mentioned, we have to reduce the outspend. We're going to adhere to that in any environment.

And we want our leverage reducing over time and we want to have sufficient liquidity, which we definitely have on that front. And then we want to make sure that the asset base is not diluted on the return profile.

And we have the inventory that that shouldn't be an issue either. So we'll just watch the commodity environment and adhere to those pillars.

Okay. Thank you.

Hey, guys. I think most of the higher level questions have been asked.

So, I have a couple more modeling questions. So if I look at the type curves in slide 20, the NGL percentage relative to EURs is quite a bit higher than your current corporate rate.

Should we read that to mean your corporate NGL mix trends higher over time?

Well, it depends on what mode of ethane rejection the plants are in. So that's what we're as – that would be the delta there.

And on the detailed modeling, Kyle and Brad and team, they do have some conversion factors down to net sales that they can get with everybody post the call.

Okay. Got you.

And then bear with me here. Some more math.

And considering it was a late night, just looking at the implied 4Q oil guide based off the 2017 guide in the deck and where your 3Q oil number ended up shaking out, it points to an oil number that's well above the guide post-Harvey, like something closer to 56,000 or 57,000 barrels a day. Are we thinking about that the right way?

I don't think so, Michael. We can follow up afterwards, but it's consistent with our – the 50% is kind of the bottom end of the range from the starting point of the guidance that we gave for Q4.

Okay. Got it.

Thank you.

Thank you.