Industrias Peñoles, S.A.B. de C.V.

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

Our remarks today 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 expectation. We also make reference to non-GAAP measures, so please see the reconciliations in the earnings release.

During this call, we'll refer to an investor presentation that can be found on our website and our prepared remarks will begin with reference to slide 4 of that presentation. After our prepared remarks, we'll be happy to take your questions.

And with that, I'll turn the call over to Bryan.

Thanks, Brad. We're pleased with our progress and performance in Q2.

But before I discuss the current quarter, I'd like to recognize an important milestone for Parsley Energy. We surged past 100,000 Boe per day during the second quarter, extending a remarkable run of production growth that is unmatched in the industry.

The best we can tell, no oil-focused operator has grown from 10,000 Boe per day to 100,000 Boe per day faster than Parsley has. And for that matter, only one gas-focused operator got there faster.

This growth has come almost entirely through the drill bit with very little acquired volume. And I'll also highlight the smooth production trend, which reflects the consistency of our growth over the last four years.

It's a testament to the skill and drive of our team that we've come so far so fast. And we certainly believe that the best is yet to come.

We'll talk more about our reinvestment runway in a moment. But with the asset base we built, there's a lot more room to run.

Of course, our underlying objective isn't growth, but value. In that context, our rapid growth hasn't been a bunch of empty calories.

Since our IPO, we posted superior growth on a per share basis. This has been reflected in our stock price performance.

So, we're proud of our track record and the value we've created for our shareholders, especially in the context of generally weaker commodity prices since our IPO. Slide 5 highlights the durability of our development program.

Our current activity profile is well- distributed across our footprint. We're favoring our Delaware acreage given the associated mineral interests.

But even there, we have more than a decade of remaining inventory. On the Midland Basin side, we're not leaning on any particular area to drive the volume growth we're generating.

This means we're likely to have a fairly stable geographic mix going forward. And this supports our ability to deliver consistent production growth over time.

Before leaving this slide, I'll point out that the inventory life we show here only includes formations that Parsley has proven up with operated drilling. If we were to include other zones that our peers have had some success in, including targets like the Jo Mill, Wolfcamp D and Bone Spring, that would add many years to this reinvestment runway.

Turning now to second quarter results, Parsley has continued to execute on our simplified development program. Slide 6 outlines the two primary components of this execution.

On the development side, our cycle times have improved, translating to more wells. And on the asset side, we continue to consolidate key development blocks and amplify the impact of our development projects by increasing our working interest.

Together, these accomplishments translate to more net wells. As you can see on the chart on the right, we're tracking ahead of plan in terms of net wells turned to production.

And more net wells translate to higher volumes. As you can see on the chart at the bottom of the slide, we're increasing our production guidance for the year and we don't need additional rigs or completion crews to deliver this extra volume.

So we're executing well and at this point, I'll turn it over to Matt for more details on our operational progress.

Thanks, Bryan. Slide 7 provides more context for our strong execution.

As you can see on the chart to the left, we've regained and actually surpassed the operating efficiency levels we achieved prior to our major acquisitions and steep rig ramp last year, and this is true both of our drilling and completion operations. Coming into this year, we simplified our development program in an effort to reignite operational momentum.

And at this point, we're ready to declare that simplified program a success. This means we'll be transitioning back towards larger pads on average.

With our rigs and crews well-seasoned and running smoothly, we're confident that we can sustain our drilling and completion performance while spreading facility cost over more wells and taking steps towards an optimized full-scale development approach. The transition to larger projects will likely moderate our POP cadence somewhat over the back half of the year, which is why we still expect around 40 POPs per quarter even though we average slightly more than that so far.

Meanwhile, we continue to optimize our acreage footprint for efficient development. Since early 2017, we've added the equivalent of more than 20,000 net acres, primarily through costless trades, and secondarily, through bolt-on leasing activity and working interest buyouts.

This impressive acreage total actually understates the impact of these additions. As you can see on the map, almost all of the acreage we've added is connected with or overlaps existing acreage, allowing for longer laterals, shared infrastructure and facilities and higher working interest, all of which translates to increased capital efficiency.

Turning to slide 8, we continue to stay ahead of the game on the takeaway front. The new agreements we're going to discuss are a continuation of a longstanding strategy of deliverability and diversification.

Early last year, long before the current Permian bottlenecks emerged, we intentionally diversified our oil pricing to insulate us in the event of widening Midland, Cushing differentials like we've seen. But the foundations of our takeaway strategy go back even farther.

The foundation of an advantage marketing platform is an attractive production stream. When purchasers look at our track record of growth and the quality and quantity of our asset base, they have confidence in our ability to deliver the barrels we commit.

When they have the flexibility to connect at Crane, Midland, or Colorado City, their end-market possibilities are multiplied. And when purchasers can count on consistent oil gravity in the refining slate sweet spot, they know there will be healthy demand for those barrels.

These characteristics make for an attractive production stream. Turning to slide 9, our attractive barrels have assured us a prominent seat at the takeaway table and enabled us to secure firm transportation at good terms.

We already had a strong takeaway position as of our last quarterly update and we're finalizing new agreements that will ensure our ability to forge through any downstream constraints. We expect these new agreements to increase our firm transportation capacity through the expected bottlenecks in 2019, reaching around 165,000 gross operated barrels of oil per day.

Our available takeaway exceeds our volume commitments, giving us plenty of room for growth without forcing us to accelerate if it doesn't make sense. So we have a lot of flexibility as we contemplate development plans for the next couple of years.

Our priority has been to ensure delivery during the worst of the anticipated tightness. Beyond 2019, we've opportunistically established a baseline takeaway position at good terms, but we've chosen not to build out a full long-term position during this period of worry and constraint.

This is why you see our committed capacity decline at the beginning of 2020. We think between now and then, there will be plenty of capacity available at favorable terms.

Moving on to slide 10, the reward for our proactive diversification strategy is a peer-leading oil price realization. As you can see, we realized more than $64 per barrel this quarter, setting the pace among peers that have reported.

We also expect favorable pricing going forward. Even using current futures prices which show challenged Midland pricing for the next few quarters, we would consistently realize around $60 per barrel through the end of 2020.

Ultimately, given the structure of our new agreement, we expect to realize a very narrow discount to the Gulf Coast prices as we move into 2020. So, in the same way that transportation bottlenecks are unlikely to constrain our development plans, neither should realized oil prices.

Turning to slide 11. Most -- every quarter we like to highlight a particular operational area.

We've been active in Glasscock County lately, and are encouraged with the productivity trend. As you can see on the map, at this point, we've brought wells online across much of the position.

In Q2 alone, we placed 14 wells on production, including one with an extended lateral of more than 12,000 feet. We also brought on a very productive Wolfcamp A, B stack with especially healthy oil rates.

Overall, our Wolfcamp A and B wells in Glasscock are looking strong with productivity improving every year and wells brought online since 2017 outperforming our Midland Basin reference curve in the aggregate. We view these results as another validation of our acquisition activity over the last couple of years, a good portion of which consists of Glasscock acreage.

And we expect Glasscock to be a significant contributor to our growth for many years. So, overall, we're performing well across the areas and business units.

And on that note, I'll hand off to Ryan to discuss our financial performance and outlook.

Thanks, Matt. We posted strong bottom-line growth again in Q2.

Adjusted EBITDAX increased 20% quarter-over-quarter on top of a 30% increase last quarter, driven by a robust volume growth and strong realizations. And not only are we realizing higher prices, we're also keeping more of those proceeds than ever.

As you can see on slide 12, we posted company-low operating costs in the second quarter, driven by peer-leading LOE per Boe, and ongoing contraction in G&A per Boe as well. Among other things, advantaged LOE costs are driven by ownership of a substantial portion of our water gathering and disposal network.

We're also benefiting from reduced power costs associated with a new electrical substation in the Delaware Basin. Favorable G&A trends are a function of a stable development pace following a period of accelerating development activity.

All told, strong realizations plus low operating costs translated to a company record operating margin percentage of almost 80%. Slide 13 details changes to annual guidance including revisions to both production and CapEx estimates.

We reported capital expenditures of $477 million for the second quarter. $10 million of this total is associated with spending by non-op partners.

The increase in total reported CapEx versus the last quarter relates primarily to delivering more net wells. We brought 44 net horizontal wells online during Q2, up from 40 in Q1.

Drilling and completion costs per well came in at the high end of the range, reflecting inflation driven by labor tightness, fuel costs and steel tariffs. Facilities and infrastructure spending was elevated in Q2 as we proactively add to our water disposal capacity.

We always look to stay well in front of potential constraints whether its takeaway capacity or water needs. During the second quarter, our efforts on this front include a number of SWDs in various stages in a water recycling pilot in Martin County.

With oil prices up substantially year-to-date, higher service and equipment costs don't come as a surprise. Previously, we indicated that prolonged oil price strength would be accompanied by inflation pushing CapEx to the top of our initial range of $1.35 billion to $1.55 billion.

That was our expectation and that's exactly how things played out with inflation running at around 10%. What's new is our higher net well count.

So, inflation gets us to the top of the previous range and faster cycle times and higher working interest get us to the new range of $1.65 billion to $1.75 billion. Relative to the high end of the prior range, the midpoint of this new range represents an increase of $150 million, which corresponds directly with the additional 14 net wells we expect to deliver this year.

We're also raising production guidance both in terms of oil and Boe. Again, this is a function of healthy cycle times and higher working interest.

Relative to the excess growth we've delivered over the last couple of quarters, we don't expect quite the same production trajectory over the back half of the year, especially as we move through Q4. Moderating growth is typical when you hold activity flat for an extended period, and will be reinforced by our moderating POP cadence as we transition back to larger pads and break ground on a couple of more sizable projects later this year.

But the tradeoff is enhanced capital efficiency over the long run. Revised production guidance also incorporates the possibility of a small PDP sale that would be part of an acreage trade in process.

The guidance table also shows substantial reductions to LOE per Boe and G&A per Boe on the basis of the accomplishments I noted a moment ago. As you can see on slide 14, our balance sheet is in good shape with cash on the balance sheet, a fully undrawn revolver, and no near term debt maturities.

This translates to an advantage liquidity position relative to peers. We show our hedge position in the supplementary slides and it's worth mentioning that our oil price realizations won't be constrained by swaps.

This means there's no chance that our hedges will end up underwater. It's also worth noting that since our last update, we've hedged a portion of our exposure to Midland oil pricing in 2019 through a combination of put spreads basis swaps.

So, to conclude, we're executing according to plan in 2018 and are well-positioned to weather any midstream constraints that may affect the basin. With that, we'll be happy to take your questions.

Good morning, Bryan, Matt, and Ryan, and to the rest of the team there.

Morning.

Good morning, Charles.

Hey, I wanted to – since you guys highlighted those Glasscock assets, I wanted to ask my first question around there. My understanding is a lot of that for a good portion of that Glasscock acreage, the Wolfcamp section there, I guess, the Upper Wolfcamp A and B together is thicker.

And I wonder if you could talk about if you see that same thing if that played any role in the – that the thicker section played any role in your stimulated rock volume for those completions you see on the Bronson pad and if there's a chance for perhaps more than one landing zone within the A or the B over there?

Yeah, Charles. It is thick in relation to farther Northwest Midland, Martin and Howard County.

Of course, our thickest Wolfcamp A, B complex is going to be in North Reagan and North Upton, but it's still a very thick package. We feel pretty good in that 1, 2 landing zone, the A, B stack the way we have it right now.

What we're really encouraged about is the development of the Wolfcamp C all the way up throughout this runway here in Glasscock. We've had good follow-through results on our Wolfcamp C across the portfolio there in Glasscock and kind of buttresses our nice Reagan results.

Of course, it's a very small portion of our program but really good results there to date. Latest wells are flowing back over 1,000 barrels of crude in that area in the Wolfcamp C.

Hey, Charles. I want to follow up on that and just give kudos on our multiple acquisitions on West Glasscock County.

I think we were acquiring just only a few – a handful of wells drilled and we gave credit to Wolfcamp A and B and this Wolfcamp C is just like free credit and we keep on hitting these Wolfcamp C wells on West Glasscock, so it's very exciting.

Got it. That's helpful detail.

And then the second question, you guys usually have some pretty good insight into what's happening on the ground out there in the Midland Basin, actually the larger Permian. I'm wondering if you could offer us any anecdotes or kind of indications you're getting about either tightness you're already seeing or impending tightness on the oil takeaway, like perhaps you having to drive to a more distant delivery point to be able to drop off your crude or whether you're hearing of perhaps it's not happened to you but to other operators not being able to get trucks to come unload their tanks or anything of that nature?

We're really focused on our own operations, but we do have – we have not seen any physical rejections. We truck a very small portion of our barrels as we build out probably the final maybe 10% in far west Delaware connect that to pipe – our far west Delaware position, which is far eastern Delaware in respect to the rest of the position.

We do truck over to a delivery point near Crane. So, that yields a little higher trucking cost just on the miles, but that's been that way since that asset's been in place and we're methodically building up pipe to that small piece.

So, no physical tightness to where there's an absolute bottleneck, but the labor market across the board, as everybody references, is very tight.

Good morning, guys.

Hi, Matt.

Good morning.

Not sure if this is a question for Matt or Bryan. But you provided a new slide, which touches on regional inventory depth.

I was curious as you look across the portfolio in the organization with 16 rigs running today, is there an optimal level of drilling activity that you might reach over the next four years to five years so that you optimize your inventory depletion while maximizing operational efficiencies and infrastructure build-out? Just trying to get a better sense of kind of the trajectory of your capital allocation program on a go-forward perspective over the medium- to long-term.

Sure. It's really ratable.

We can essentially double that position with no operational constraints over that timeframe. But the governor for us will be financial constraints and how we want to proceed with the model.

So, we feel really good about our inventory and the spread of our footprint there. We're not drawing down any one particular honey hole overly aggressively.

So, what you see kind of, from us, on a productivity standpoint, should be what you get from us barring no technological innovations, which we're working on all the time. Those well results should be a proxy for the program for the foreseeable future.

The scary thing is, if you look on the slide, is the potential other benches that haven't even been de-risked, and then also, 330 spacing. So, there's so much more upside on inventory even looking past this many, many years of drilling with this current rig count on Parsley's acreage.

Great. And then, as a follow-up, Bryan, this might be a question for you.

Not sure if it's too early to have a conversation around this or not, but as you maintain kind of the measured discipline around capital acceleration, it appears that at strip pricing the organization starts to throw off a material amount of free cash flow in 2020, especially as barrels start to link to Brent pricing. I was wondering if you have any updated thoughts around the potential use of those incremental dollars from a capital allocation perspective, and I guess specifically trying to think about accelerating the drill bit versus potentially establishing a return of capital strategy that might fit into the Parsley story over the medium-term.

That's a good question. It seems like it's been a reoccurring theme the past previous calls and conferences.

I think we'd mentioned in the previous calls potential close to cash flow neutral when we're at $50 oil, but now we're at $70, $75 and it's been service cost inflation. But at the same time, we've seen great margins and great returns.

But going into 2019 and 2020, it's an eye on the prize I'd say more in 2020. My gut tells me to continue to plow it into higher return projects but at the same time we're juggling to find that cash flow neutrality into, I'd say, 2020 like you've mentioned.

Thank you. Good morning.

Good morning, Scott.

Hey, Matt. You talked about moving to a strategy of a little bit larger pads now that you've got operations where you think you could – where you want them.

And can you remind me, is this sort of an acceleration to what you had expected in earlier this year? And related to that, it looks like you put a little bit more dollars into infrastructure to help support some of that possibly.

Is there any other things we should start thinking about or that you guys are thinking about as you do these larger pads, concentrate more production in smaller areas? I know some of your peers in the basin have run into some constraints here and there that were seemingly unexpected as they concentrated their activity.

How are you looking to mitigate some of that?

It's a great question and you capture really our sentiment in that question with the infrastructure spend preparing and to mitigate all those concerns. In fact, we've done large pads before late 2016 and coming into 2017.

And so we know when you flow back these large pads what it looks like and what kind of challenges you need to have in the first 30 days, 60 days, 90 days, this pool -- this adjustment into 2018 of simplify the game plan was nice on many levels. It allowed us to regain our efficiencies and actually surpass them.

I'm impressed that we're back to pre-acquisition levels as quickly as we are but allowed a lot of future planning to get out in front of the transition back to kind of the full scale development of pad. So the teams are taking steps on all those fronts and we really, if anything, just bought additional time throughout 2018 and we feel like we're in really good shape in tying slide 7 with our activity footprint on slide 5.

You can see that we are distributed across large area and we have the pre-planning and the infrastructures in place to be able to handle these pads.

Okay. And is there a certain amount that we should expect that various points in time where you're going to have a slug of more infrastructure spend as you move more activity in this area -- at this area.

I mean how – what is the progression of that over the next couple of years?

On a – as we get into 2019 we'll probably try to give a little bit more color around if there is going to be any sort of slug that we can identify in one quarter to the next on the infrastructure spend. But we've -- around that 14% to 16% run rate has seemed like a pretty good average.

And then we do anticipate that it can actually go down on a percentage basis when we go to these larger pads. So right now as we're preparing for larger pads, the percentage is out of whack because larger pads haven't popped, but that's a good placeholder percentage.

And then, as we get into 2019, we'll try to – if we see a slug, we'll try to communicate that.

Good morning, guys. Matt, maybe can you talk – as you guys kind of transition to these larger pads, can you maybe give us a little bit more sense of kind of how big – where are you guys going from and to, and maybe how that potentially sets up the 2019 development here, and is it fair to think that the POP schedule – I understand that there will be kind of a transitionary period, but maybe there's some upward bias to that 40 a quarter number in 2019 once you get some momentum with the change?

Yeah. It all depends on – so, right now, we're at two and three well pads.

And I'd say the majority of the program will go to three to four well pads. And we have a handful of six well pads that we're contemplating.

And actually, it's – now is a perfect time to implement this because it delays POPs, if you look at it that way versus running a two to three well pad program delays POPs during the foreseen tightness period in the Midland pricing on the largest differentials forecasted. So, it does bring them on later in then versus Q1 2019 or something like that.

But it's not a light switch where every program is flipped over and going to six well pads. It's – we're feathering these things in.

All right, great. And for my follow-up, it kind of sounds like – Matt, based on your prepared remarks that you guys have the option on the secured takeaway kind of in excess of your base case needs and I'm just curious if that could potentially be an asset in this environment from an acquisition standpoint and then maybe just generally if you guys can kind of talk about your thoughts on M&A right now.

Yeah. I think if you think of it as marketing it to market it's a huge asset that we have.

Our whole marketing agreement and anything has the ability to be used in our advantage. So we do have plenty of flexibility on that front.

Looking at as you can see there on the chart 110,000 barrels ramping up to 165,000 barrels of crude on the takeaway front with some flexibility on top of that. And there's even some triggers that could pull some of that that wedge forward that we're looking forward to.

So we're really fortunate with the component that we have without MVCs. That gives us large flexibility to allocate towards analysis like you mentioned.

On the M&A front, our BD group has now officially turned on their light. They're looking across multiple basins and we're being active at looking at things.

But I would say that could be later in the 2019-2020 but we are being proactive looking at things. We are -- still have our – if you look at that slide 5 our inventory, we have a long runway.

So we don't need to buy anything right now and we don't need to acquire. But we just need to be proactive understanding what's going on.

And on the private side it seems like there's not many things out there. I mean there's a couple – maybe one in the Delaware side on the East side and maybe one or two private equity positions in the Midland Basin side.

But it's come a long way from two years to three years ago where there were just multiple attractive assets for sale in the both basins.

Morning all. Matt, and for you, Bryan, my question, I know on the – I think it was the last set of slides you all had in the first quarter you had that obviously the spotlight then was all that the massive minerals position you have.

Could you talk a bit about, one, if you've been able to continue to boost that? And then number two, thoughts about potentially bringing that out?

The market is very ripe right now. That's for certain.

Especially with the way you've seen in the structure changes of the entities over to C-corps. So, we're still evaluating.

We have a massive position on the minerals front but it's also very early in the production and cash flow ramp on that company. So, it's internally tracked asset within our company and we'll let it mature and see how the markets play out.

Matt, on that, does that change, I think, on your map it shows the three rigs on that area. Could you just talk about does that mean you'll continue to ramp in that area or I guess just the thoughts on activity in that area.

No. We'll – well, it's not only in that area.

We have about 20% of our position is in the Midland Basin as well. But no, we would not change.

It's a byproduct of our capital allocation at the working interest level. So, that's priority one.

And then the schedule fallout drives the mineral uplift however it lands.

Okay. And then, Bryan, just last question.

You mentioned – you all mentioned you look out of the basin. I'm just wondering given your massive inventory position, you have timing on that or why look out of the basin given the size of inventory that you certainly have now for end and in the future?

I must've misspoken out of basin. I meant the two basins, Delaware Basin or Midland Basin.

We're just watching the activity. We are not looking out of basin.

I mean we're a pure-play. There's room to expand in the Midland Basin and Delaware.

I agree. Thanks, guys.

Nice job.

Thank you. Folks, good morning.

Good morning.

The reinvestment runway slide is a creative way to present inventory so tip of the cap to Investor Relations assuming they were responsible for it. What comes to mind is the challenge of bringing forward the value of those locations.

I guess two questions on that front. How do you address that same challenge especially when including the zones not fully de-risked and how might the plot of the rig counts look in the out periods assuming they'll be directed to the highest returning assets?

We really have a tight spread of returns across these donut holes. So, I think you'd see ratable increases in rigs across each area.

Now, obviously, you can't add six rigs at once, seven rigs at once, so we'll pick separate areas based on a myriad of input factors but it will be ratable increase across the footprint due to our pretty tight spread of returns in the entire portfolio.

Got it. Thank you.

And maybe as a follow-up to that. What is the dock inventory today and where will it stand at your end, and how might it trend in 2019 with respect to your comments about delaying POPs during the period of tightness ahead?

We look at it as kind of inventory ahead of the frac spread. And right now, we have five spreads running, and we run really tight anywhere from 0.5 to one pad ready, one well ahead of every pad – sorry, every spread.

As we transitions to these larger pads, it increases to a nice working capital level of 1 to 1.5. So, we get kind of an uplift there, and that's just a natural transition as you go to larger pads, but no intentional DUC building by design.

Thanks. Good morning.

Matt, you mentioned in one of your responses that you potentially have the ability to trigger some of those later dated 2019 from volumes forward. Just curious if you can provide any color on that, and then also in that context, yeah, just kind of like what additional firm you think you can bring in just to help with flow assurance in the first half of 2019 and how should we think about that?

Oh, that was just the – the projects have a lot of triggers that could – we think we're using a late estimate on project timing for that wedge that comes online late in the year. So, we're already seeing some indication of some of those projects hitting a month to multi-months earlier, and we're not using those dates in that projection.

And then, in front of that flow assurance in early 2019, we're moving 67,000 barrels of crude on the quarter. We have over 110,000 gross and then all of those they do have a plus or minus percentage in the contract.

So, we have plenty of wiggle room there and then some fringe walk up ability. The key is our connectability.

Our inter-basin gathering really ensures delivery to every key in-basin destination on the long haul pipes. So, we have a lot of flexibility to get the barrels where they need to go.

Even in that extremely tight moment, there's always seems to be open areas in certain pipes.

Okay. And then on the – I guess, as my follow-up on the activity front, I mean, you guys have been running a pretty even loaded program now for a bit and obviously for the full year that's the plan.

How should we think about bringing on additional rigs for 2019? I know that's counter to a lot of conversations right now but how are you thinking about that?

What would be the timing of that? Should we think about 2019 as kind of pushing into that schedule that you have on slide 9?

Or yeah, just trying to think through the cadence next year, I guess.

Yeah. I think given the cash flow ramp and we'd be able to moderately increase activity and still keep all the other financial objectives well within line, so, very healthy on continuing to lower the leverage position.

So, I think you could look at anywhere from flat activity depending on how much the – how many of these efficiencies continue to gain to maybe a one to two rig addition. And that's kind of the framework of our sensitivities that we're running into 2019 analysis.

Hey, guys. Just wanted to follow up a little bit on this kind of incremental new oil contract you guys talked about for 2019.

I mean I don't want to put words in your mouth but it sounded like you guys have got major terms and negotiations done there. And it's just a matter of maybe the lawyers sort of papering this thing up at this point.

I'm just trying to get a better sense of sort of where this is at. And then just following on, does that incremental piece that you guys are working on, is that primarily going to send volumes to the Gulf Coast in 2019?

Yes. So all the – there have been term agreements signed in everything we're talking about with lawyer sign-off and it's the full finalized agreement that would be in place on one to two.

A couple of them are already completely finished. So it's far along in the process on that front.

Just a few i's to dot and t's to cross. And then all go to the Gulf Coast.

Okay. Got it.

Helpful.

Yeah.

And just I wanted to follow up on sort of the infrastructure here. I certainly heard that some folks in the Midland have seen some modest impacts and some potential bottlenecks just around gas processing and some line pressure issues.

Just trying to get a sense if you guys have seen any of that in the Midland.

You know we haven't seen it. From our sources, it seems like there are localized areas of the basin that were seeing it but it did not impact our results and there's another large plant coming on in the September-October timeframe that just buttresses that processing capability.

So, it did not affect our operations.

Thanks. Good morning.

I had – my first question is on oil cut. 2018 guidance would imply roughly 64%.

My question is how does – do you see this changing into 2019? And Matt, any updated thoughts on your Wolfcamp C program in light of some recent industry results?

Within a couple of percentage there, I think that's fair to use on the oil cut front. Low 60%s should be the run rate.

And then on Wolfcamp C, just a handful continuing the program, really liking the results we're seeing. But again, it does have on top of the oil that I mentioned a gassier component.

So we're just not going to lever up on that bench right now until gas prices recover.

Great. And my follow-up is on the cycle time improvement which clearly is quite meaningful.

Matt, could you quantify or frame for us the improvement either in stages per day or days to drill complete? Any color on that would be helpful.

We really look at footage because we're tweaking every stage in the design. We have engineered in geo, completed fracs so they can be larger and smaller based on the density of the well.

But when I look at the daily reports, we're now clipping off anywhere from six to 10 stages a day on our active fleets depending on the design. And I'd see a number one to two lower stages in months past.

And then on the cycle times on the rigs, we've seen one to two days reduction on that front.

Good morning. In your prepared remarks, you guys talked about water recycling.

When you kind of look over the next three years, what's the addition of the percent of water recycled, the usage, and then can you talk about the cost benefits of that for you?

We're really excited about that kickoff program, that pilot program for us. It's actually been a cost-neutral endeavor.

And when we started analyzing this back in 2012, it was anywhere from $3 to $4 a barrel full cycle, and it just wasn't – the technology wasn't there. It wasn't ready yet.

We have tremendous volumes of freshwater available to us. It's never been a need for us.

But we'd like to go this route if we can see an economic neutrality or benefit to it. So, it's been nice to get this pilot under our belt, and we will scale it up as needed throughout the next few years.

It just lowers the demand on additional infrastructure build-out as far as additional wells, additional SWDs in that front.

And then looking out the inflation with the steel tariffs and labor tightness; was that evenly split or was it more driven from labor tightness versus steel. Can you just quantify?

I think more labor tightness than steel. You have about a – on a total well cost at 2% hit on – if there is 10% inflation, about 2% of it was probably the steel tariffs.

The remaining 8% is from what we're seeing labor tightness.

Yeah. Good morning, everyone.

Thanks for taking my question. The slide 9, I believe it was Matt who basically touched on the potential for overcapacity in terms of takeaway 2020-2021.

Just really wanted to get your comments as to where you see this going in terms of supply demand for the play. I mean specifically where do you see Permian oil production going as a whole, where do you see total takeaway capacity going as a whole to kind of justify that oversupply comment.

Well, it looks Permian growth kind of moderates from the 1 million barrels a year growth down to 700,000 barrels a year. And we're seeing up to 2 million barrels a day of additional pipe being added in the 2020 timeframe.

So you see a window there where people need to fill those pipes and things get very competitive again as very similar to when we are counter-cycle on our initial agreements and that timing cycle just plays in our favor again at 2020 timeframe.

Thank you. That's very helpful.

The other question I had was specific to your 2018 guidance. We talked about CapEx up and op cost lower, et cetera, but I was hoping you could quantify your changes in terms of production.

I mean your oil targets are up, call it, couple of percent, midpoint to midpoint, but on a Boe basis you're up about 6% midpoint to midpoint. So, just wanted to see what the incremental gas contribution the source of that?

It'd be ratable across all the wells. It's just a byproduct of how we forecast oil and gas and increasing GORs.

We put a placeholder in the reserves and we want to meet or exceed both on the oil volumes and the gas volumes. On top of that, we have gone into more of an ethane recovery mode so we're getting a higher percentage of residue that drives 1% or so of that.

Good morning and thank you for taking my questions.

Good morning, John.

Good morning, John.

Bryan, I wanted to first come back to some of your earlier comments on M&A, and if I think about some of the historic deals Parsley has done, you could argue it was to some degree more focused on building up this big inventory that you've now kind of put in pictorially for us on slide 5. As we think about the go-forward potential future deals, would this be maybe more focused on high-grading the acreage base or be – specifically being opportunistic with respect to valuation or can you just talk to us generally about what the ideal acquisition is and if it's changed from maybe what Parsley has done historically at all?

I think every oil and gas company tries a high-grade and you select your inventory, the highest rate of returns, and you always want to replace them. So, I kind of answered your question like if we are going to acquire, it needs to be something very close to our acreage and needs to compete with the current inventory.

And obviously, if the acreage – sometimes the little operators – acreage comes loose, which were similar returns from two years ago. But there's still some fresh acreage that haven't been down-spaced yet or even drill 650s, HBP acreage, old legacy acreage, that's what I'm really referring to.

Does that mean potentially the Delaware Basin as a more attractive one rather than the Midland or was it not necessarily that simple?

No. I don't think so.

I mean, you could look at the Midland map, and we have a larger footprint, so that should provide more opportunities because of the larger footprint. In the Delaware Basin, we have a smaller footprint, so we're more focused in that little tight area.

That's helpful. My next question was can you just update us on how much in-basin sand you're using today, and if that could have a potential tailwind on 2019 CapEx, or should we still think about that 17 as being kind of a good placeholder for the time being?

2019, when you look at – it's the right way to cash is questioning 2019. We're about 20 to 30 – 20% to 40% in 2018.

We went the route of not putting large volumes in the ground in 2018, but we're testing it. We feel comfortable with it.

There's plenty of data points out there now so we're hopeful that it could be a larger component of 2019.