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 can be found on our website. 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. 2017 was a transformational year for Parsley Energy.

We took on a lot and we delivered a lot. Our accomplishments in 2017 extended a multi-year run that is nearly unrivaled in the industry.

As you can see on slide 4, we've consistently grown production, reserves in cash flow while reducing cash costs. And we've done all of this while adding almost 100,000 net acres, coring up that acreage, doubling our activity pace and unlocking a new resource play in the Midland Basin.

During this expansion phase, our growth has accrued to shareholders as we paved the field in terms of production growth per debt adjusted share. When thinking about the value we created in 2017, we thought it'd be helpful, especially for non-specialists, to focus on something concrete.

So slide 5 walks through the increase of the value of our proved developed reserves as included in our 10-K. The chart shows that our $1.2 billion capital program, funded in part by outspend, added basically twice as much value as we spent.

Backing out the increase in net debt associated with the outspend leaves abundant excess value. Healthy growth throughout 2017 enabled us to benefit from an increasing oil price environment.

And in the end, based on audited data, we generated a 70% organic return on our capital program on a debt adjusted basis in 2017. This translates to roughly $840 million of added-value.

To borrow from Warren Buffett, the best companies invest large amounts of capital at high rates of return. And that's exactly what we did in 2017.

We're on a path to substantial free cash flow generation as our outspend evaporates, but during our outspend phase, we've created more value by investing more capital. Turning to slide 6, we've set ourselves up for ongoing value creation by building what we believe is the premier Permian acreage portfolio of its size.

You can see on the map that the majority of our Midland Basin acreage lies toward the center of the basin relative to that of our small and mid-cap peers. We run a bigger operation on a larger footprint than these peers and we've built the type of scale that affords us ample resource life and opportunities for various efficiencies and savings.

For example, as our asset and production growth accelerated over the last two years, our cost of debt has decreased by around 200 basis points. Moving to slide 7, several things define our – an attractive E&P company and we screen favorably across the board.

We believe that companies with the ability to grow efficiently on the highest quality acreage will win over time. This graphic shows that we rate among the elite on the characteristics that the market values.

These include measures of efficiency, commodity weighting and growth. We've set ourselves up for long-term value creation, but the near-term priority is to deliver on our expectations.

While we achieved a lot in 2017, we'll be the first to admit that we expected even a bit more. The delta between our performance and our expectations was primarily a function of two things.

The first is changes to our development schedule that affected our well mix and timing. The second is weaker than anticipated results on certain downspacing tests.

The acquisitions we made at the beginning of the year were designed to position us for the next decade and they have. Along with acreage trades that followed, the acquisitions also prompted some 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 as we've mentioned before, many of the wells to which we pivoted were in new areas where we had a learning curve ascend.

The other drag on the results relative to the expectations was our down-spacing test. There were a couple of dynamics here.

One was significant delays on our biggest project of the year and eight well pad at 330 foot lateral spacing and even tighter vertical spacing within the same target zone. And when the well did come on, they came on with a less favorable production mix.

We saw the same type of results in subsequent tests on smaller, high-density projects later in the year. Despite these challenges, we added 35,000 Boe per day from Q4 2016 to Q4 2017.

And the good news is that these things are behind us now. For a company with our inventory depth, 330 foot spacing is a luxury that might make sense at some point in the future.

We're certainly not writing off the possibility and we have some ideas on ways to make it more effective that's not in our current plans. And more generally, we're anticipating a more stable development program this year.

I'll turn it over to Matt to elaborate on what we've learned and why we believe we're poised for a return to Parsley standard performance in 2018. But before Matt gets started, I wanted to take a quick moment to share my excitement for the future of Parsley Energy, as Matt readies to take the reins as CEO early next year.

I'm confident Matt is the right person to guide Parsley through the next phase of its growth and development. And I look forward to working with him in our new roles as we strive to maximize shareholder value.

And now, I really will turn it over to Matt.

Thanks, Bryan. It truly is an honor to build on the foundation that Bryan has established over the past decade and I'm excited to carry the torch with our world-class team early next year.

For now, though, we are all focused on executing at the lofty levels we're accustomed to. 2017 was an ambitious year by any measure.

As you see on slide 8, we integrated close to 100,000 net acres, executed the largest activity ramp in the Permian and allocated substantial capital to delineation activity. As Bryan outlined, we accomplished a lot, but at times, it came at the expense of our top rate operational efficiency.

2018 looks dramatically different. While we continue to optimize our portfolio, our drill schedule is essentially locked in through the end of the year and any changes we make will be discretionary.

Last year, we added rigs and crews throughout the year, as you can see on the chart. Every quarter, we completed more wells than the quarter before.

This year, we're expecting a steady development pace, bringing on around 40 wells online per quarter. Given the potential for labor tightness, we feel fortunate to have secured the frac fleets, rigs and associated personnel we expect to need this year.

In 2017, roughly half of our pads involved some type of delineation in a new county, new target zone or new spacing configuration. You can see on the map that our delineation activity was distributed across our footprint.

This year, our delineation activity should only constitute around 10% of our program. We're also honing in on preferred target zones this year and going back to many of the same areas as well.

And as Bryan mentioned, we're back to lateral spacing of no less than 660 feet between wells. We're also shifting back to smaller pads to reduce capital concentration and get barrels online quickly in a backwardated market.

For all of these reasons, we believe that we are set up for a strong year on the execution front. Turning to slide 9, when we announced Double Eagle acquisition early last year, we commented that we expected the map to evolve over time and it certainly has.

We continue to be very active on the trade front, executing trades that block up our acreage in some of our very best areas. We added several hundred thousand more lateral feet to our horizontal inventory in the fourth quarter, bringing our post Double Eagle total to around 3 million lateral feet.

This equates to 300 2-mile-long drilling locations. These trades continue to facilitate step changes in our average completed lateral length, which should enhance our capital efficiency.

Our ambitious 2017 delineation program paid off with our success in the Wolfcamp C horizon, which is the focus of slide 10. A lot of technical work went into the launch of this significant resource play.

We talked earlier about obligatory changes to the development schedule last year. One discretionary change we made was to add a few more Wolfcamp C wells to the schedule in the back half of the year.

We now have several Wolfcamp C wells online and together they have outpaced our Midland Basin reference curve. I'll reiterate that while these wells are making a lot of oil, they're gassier than our other wells, so the shift to more Wolfcamp C wells shifted our production mix last year as well.

Recently, we completed a couple of step-out wells that expand the aerial delineation of the Wolfcamp C to the north and to the southeast. Results are encouraging, supporting our preliminary outline of the fairway of the play.

And we're closely watching results in other largely untapped zones on offsetting acreage, all of which reinforces the value proposition of core Permian acreage. To summarize our operational status and outlook, we pushed the limits in a lot of ways last year, but we accomplished a lot and we learned a lot.

We've aggressively addressed every challenge we encountered in 2017 and now we're looking forward to applying what we've learned. With that, I'll hand off to Ryan.

Thanks, Matt. Higher volumes and commodity prices as well as lower operating costs in the fourth quarter translated to a 32% quarter-over-quarter increase in adjusted EBITDAX.

Reported CapEx increased to $417 million in Q4 versus $307 million in Q3. The 35% increase in CapEx reflects a 41% quarter-over-quarter increase in net completed footage, as well as higher facilities and infrastructure spending and non-operated development.

Unit cost trends were favorable with both LOE per Boe and cash G&A per Boe at or near company record levels. Slide 11 summarizes our 2018 capital program, which reflects the simplification we've discussed.

Even at a steady development pace, we expect to deliver 50% annual oil growth at the midpoint of our production guidance range. And that would come on a smaller spending increase of around 20% at the midpoint and less than 30% at the high end of the range for capital expenditures.

This places us near the top of the list of oily E&Ps when it comes to capital efficiency. We expect activity to be weighted toward the Midland Basin, with around three-quarters of the wells we intend to bring online on the Midland side and the remainder in the Southern Delaware.

This year, we expect the downtrend in G&A per Boe to continue, while LOE per Boe should be relatively stable despite an increasing average well age and some cost pressure that typically lags broader inflationary trends by a couple of quarters. Slide 12 shows that we continue to enjoy a simple healthy financial position with ample liquidity and low leverage.

We're well hedged, as you can see on slide 13, benefiting from downside protection while also capturing the value of currently higher oil prices. Slide 14 highlights very strong reserve growth, with proved reserves up 87% in 2017.

A first rate recycle ratio demonstrates ongoing capital efficiency, and positive technical revisions to PDP on both the gas and oil sides demonstrate the stability of our asset base. To conclude, with expectations recalibrated and a simplified and straight-forward development plan in our sights, we look forward to delivering the type of results and value you've come to expect from Parsley Energy.

With that, we'll be happy to take your questions.

Good morning, guys.

Good morning, Matt.

Just a quick question. Two things you highlighted in the release we thought were interesting, the acreage swap in Upton County and the strong well results you're seeing in Martin, which in particular are quite oily.

Could you talk a little bit about the ability to high grade your development program heading into 2018 and beyond, given the Double Eagle transaction and some of the swaps you've been working on?

Yeah, Matt. I think you've seen just a tremendous track record of that high-grading throughout the year aggressively getting to it after we closed on Double Eagle.

And you bring up a good point there with the Upton County trade had some of the best returns in the company. And we artificially delayed activity there throughout 2017 because we knew that this trade would come through and we didn't want to compromise geometry of the lease configuration there for the long-term.

So that's folded back into the mix into 2018 and beyond. So we were just kind of holding off there as we locked up.

And it was already some of the highest rate of returns at 1-mile laterals. And now, we have 2-mile lateral development units throughout our North Upton County block, so extremely excited about.

We really did a lot of the heavy lifting on our development units throughout 2017. There'll be continued optimization and roll-in from some of the smaller positions through – sorry, in 2017, but throughout 2018, there'll be continued optimization, but it's outside of the drilling schedule for the next 18 months, whereas immediately when you closed on Double Eagle, a lot of stuff was in flux in front of the drilling schedule.

So that was added to some of the challenges last year, but this year, it's pretty much locked in.

Hey, Matt, I just want to shine a little light on the trade in Upton County, and I've talked about it in previous calls about these trades, from small operators to the large companies. And that was particularly a larger company.

And that trade probably took a year, year and a half to really get it done. So these larger companies doing the trade with, it takes a long time to get it done.

And that's what kind of holds up the drilling schedule, but because obviously you look on the map and it's just juicy acreage, and you just can't – you've got to be patient to get those sections to fill in the holes in Upton County. In the future, like Matt said, I see a lot of – we're doing more trades with smaller companies through 2018.

Great. And just for my follow-up question, something that seemed to hinder the program a bit last year on capital efficiency with some of the non-op activity, I think you guys ended up paying for some wells that weren't necessarily turned in line in 2017.

Just curious how you guys are thinking about risking that into 2018? And are there any tailwinds that you might benefit from on the non-op side, in particular, on production?

Yeah. We risked the timing there on that front.

And you're right. We spent a lot of capital especially in the fourth quarter on non-op and got no benefit on the production side as they go through their process of tying into their facilities, et cetera.

So, we have projections from the multiple non-op partners and then, we try to put a two to three month buffer on that just for the unforeseen, since it is out of our control.

Thanks, guys.

Thanks.

Good morning, guys.

Good morning.

Matt, I wanted to ask a question about the Wolfcamp C and I recognize that you guys have an edge on your insight here, so that might limit what you want to say. But I wonder if you could talk a little bit about the variability that you're seeing across these seven wells.

And it seems to me that it's a little more variable than perhaps what you're seeing in your Wolfcamp B or Wolfcamp A, your more kind of traditional development zones. And I wonder if that's the case and you can maybe decompose this average you've seen and can perhaps talk about that well you did right up there against the Glasscock Nose?

Yeah. I think that's the right way to couch it.

As you go deeper in the column, we generally see more variability, more distribution along the results. But what's nice here is you obviously have internal petrophysics and rock properties and it is aligning to the results of those projections.

So in areas that we still see as perspective, but don't see as good of petrophysics, the well results are reflecting the same. So internally – obviously, on slide 10, we have a pretty generalized map, but internally, you have the detailed mapping, and the well results are, for the most part, aligning with that.

In the Northwestern Reagan area, pretty consistent results. We do have the biggest well result there in the Taylor that was probably a top 5% well in the entire Permian Basin.

So you wouldn't anticipate that to really be replicated time-in and time-out. Really, that Northern star, all the way up in the Glasscock, was a very solid result, clipping over 1,000 barrels of oil a day.

And that Southeastern star, clipping over 1,000 barrels of oil a day. So if you just had to pick the worst on the map, it's the Southwestern star, but that's an area that matched with the petrophysics of that anticipated result.

Got it. I think I understand it.

It's fitting your – you feel good about your predictive model.

Yeah.

And then, if I could ask a question for you guys to elaborate a little bit more on your decision-making about go into these smaller pads, it makes sense that – I think it's pretty obvious that you're going to reduce your cycle times when you go to these smaller pads. But can you talk about what were the trade-offs you guys evaluated as you went that direction and whether this is something that we're going to see, be a feature of your program through 2019 or 2020, or if this is kind of a back-up and then you're going to rebuild again towards bigger pads going forward?

It's a spreadsheet tradeoff, as you go to larger pads, in your budgeting process, you do earn back 2 to 3 points on the rate of return scale. However, that doesn't include the additional risking factor.

And what we have seen across the basin is the tightness in labor and a dilution of the labor pool. So now, you're just exposing that capital for a longer period of time right now, as the industry is reengaging the labor pool.

So I think it's a response to the market conditions in the basin. And then, I think as things stabilize, 2017 was a re-activation year for all the service providers, and as they stabilize, as well as our own operations, we think that is more of a temporary thing.

Over the longer term, you start adding a couple of wells per pad. You have a larger stabilized base production and you also have lower corporate decline rates as well.

Got it. Thanks for the detail, guys.

Thanks.

Thanks. Good morning, guys.

Good morning.

First of all, Bryan, congratulations on, obviously, putting together pretty strong company. And obviously, we look forward to Matt taking over in the not too distant future.

Can you give us some color on, over the next year, what is this transition look like and how are you looking at the COO role and looking to source a new obviously member of the management team?

Yeah, I just want to first say there was a lot of soul search in the past couple of years. And as we walked into this year, I was talking to the board about a year ago for a while and my feelings about this.

But we hit a $10 billion enterprise company within 10 years and it just seems more natural as we shift to manufacturing mode, that Matt, he's a superstar. He's been partners with me from the beginning, and I think everyone else agrees with me, everyone thinks highly of him.

So it just seemed very natural. Now, there was a lot of soul searching on this.

So, as for the transition, if you know me, I'm always barking in the hallways. I'm in Matt's office.

I'm in (24:29) office. I will still have an office around.

And as the transition goes into 2019, I go as a Executive Chairman, I think of that as I will be on the e-mails and more long-term strategy in 2020, transition to a more – working with Matt on long-term strategy in the future years.

Yeah. And Scott, on potential COO replacement, you saw in the press release, we've added – Larry Parnell has been promoted to SVP-Development Operations.

That takes care of all of our drilling and completions CapEx. And then, we have Paul Treadwell, Co-Founder of the company.

He's been here from the beginning, SVP of all of our production operations, so that's on the LOE front. So we've really buttressed the operations capability with two 30-year plus candidates there.

So, we have a good structure in place and we'll just evaluate that as time unfolds, but nothing eminent.

Okay, understood. And my follow-up question, I think last quarter, Bryan, you discussed more of – I felt there was more of, I guess, a theoretical view on when Parsley could actually turn free cash flow positive.

Obviously, commodity prices have strengthened a little bit. What is your view on that right now?

And looking forward, obviously, with oil price above $60 right now, what is your plan of attack here over the next year or two? I know 2018 is steady as she goes for now, but what is a little bit more of view into 2019 and a perspective on when Parsley could be free cash flow positive?

Well, first of all, it's hard to just drop the cash flow neutrality right away because we're always fighting that decline. So we're trying to baby step into that flatter production base.

So that's the most important thing. And obviously, these high returns that we're talking about the sweet spot in Upton County and our minerals in Trees.

So, as time shifts, there is an eye on the price and we're all looking at it. And yeah, I think with the oil price run up, I think we've mentioned back of 2019, now, we shave off a couple of quarters, if oil stays above $60.

I think this is very exciting for Parsley. I mean, you're talking about billions of dollars of cash flow and what are you going to do with it.

And these are a lot of questions that some of our peers are countering right now. So we're just not there yet.

In about 12 months, we should be at the same point. I saw Diamondback's dividend, the $50 million dividend.

And as a shareholder, I think that's something to look at.

Thank you.

Okay.

Thank you.

Thanks. Good morning, guys.

So I have a couple of guidance-related questions and then a big picture. Matt, could you talk about or provide any color on 1Q volume, any weather or operational issues to consider?

Yeah. In our operational update that we released, we did note that we were impacted by weather in the first half of the month there and then that rolls into our corporate guidance throughout the year.

So there'll be a little bit of an impact there, but it's all molded into the updated guidance. So we feel good about that.

Okay. And a fairly wide range for LOE costs for 2018, what are the drivers that could bias us to the low end versus upper end of that range?

We had a historic low failure rate of your wells in the fourth quarter. So we'd expect just as the wells vintage out a reversion to the mean.

We have a great group of artificial lift technicians that keep that rate low, but a reversion to the mean there would be a component of it. You also just have the natural aging of the wells that require more service.

We started our horizontal program in 2013, so now they're three to four years into their lifecycle and you take some preventative steps to keep those on a flat decline. And then, as we build out our development in the northern part of the Midland Basin, use more ESPs, so we'd anticipate a higher run cost on those ESP.

So those are all kind of factored into that range.

Okay. And a decent uptick in exploration cost sequentially and year-over-year.

What is driving that?

It's primarily expirations of non-core Midland Basin acreage. And I'd note that we didn't have any inventory or reserves associated with this acreage that expired.

Got you. And then my big picture question, some of the other operators had recently discussed falling EURs with a larger number of wells per section.

Can you comment on this phenomenon as it applies to your acreage and parent child relationships?

Yeah. Our base EUR program and our forecast and our reserves are based off of 660-foot lateral spacing essentially.

So a lot of that is already in our numbers. What we did test in 2017 was the next level, the 330-foot spacing, which is not in our reserves, not in our inventory.

And we did see excessive degradation versus forecast over time. You're just depleting the tank – the pressure at an accelerated rate.

So you do get a component of acceleration versus just pure reserve adds. So as the industry zeroes in on the right spacing component, there naturally would be per well degradation, but probably an increase in section-wide recoveries and everybody just needs to find the right method for their own development space.

And right now, we're at 660-foot spacing. And actually, we saw positive revisions on our oil curve reserves from 2016.

So that's a good sign for us.

Great.

Morning, guys. Could you just talk about potential for self-sourcing sand and just service cost inflation in general?

Well, there is regional sourcing. We do own 28,000 acres of surface across the Permian Basin.

I think that's a little bit differentiated for us, but there is no intent to actually self-source on our owned surface, but you could make deals with the regional and go direct to some of the mines. Through our agreements and our contracts that we have with our service providers, it's more beneficial to us to allow them to make those contracts.

And we have a very low negotiated pump-through fee, but that allows them to take on all the logistics and the upstart there, which we have done. We've got one well of regional sand down and into the ground.

So we'll be looking at it. We're not budgeting for that across the program until we see some production results and look at the long-term decline.

So, back half of the year, we'll be making that decision on how much of a component of regional sand to use. Broad-based inflation has been moderated for us, really, since November timeframe.

You have a few things to the positive and then a few things offsetting beneficially to the negative. Labor is tight, so you think about wireline crews, things that take technical ability on the labor front.

We're making sure that the service providers have good quality hands and we've increased the supervision 24x7 across some components. So that's really the only component that we're seeing some inflation on right now, not really on any of the hard goods.

Good point. And then, Matt, one follow-up if I could.

Just on – I know you're not doing many, but could you talk about – I think you're doing a few larger pads. Maybe if you could just discuss if you are doing that and then sort of what the timing and size of these are?

They're already in flight. We have two four-well stacked pads that compromise the entire 160 wells projected for the year.

So, eight out of 160 are associated with pads larger than two or three well pads. And that's just seeing some of our thicker areas in, say, Spraberry, Wolfcamp A, Wolfcamp B and potential Wolfcamp C stack.

Thank you, folks. Good morning.

Morning.

How are cycle times expected to change or improve over the course of 2018? And what might that mean for the number of wells put online per quarter, recognizing you're pointing to an average of 40 pops per quarter for the year?

Sure. We're using the same run rate we had in the fourth quarter.

We're not anticipating any improvements throughout the year in the current budget that we have in place. We think having – running the flat activity level with both the frac spreads and the rig crews that we're all going to get better day-in and day-out, but we're not budgeting for that right now as we assess the labor condition out in the basin.

Okay, got it. And as a follow-up to that, what is the PDP decline rate on oil, both in the Midland and Delaware basins, and maybe how is that expected to change over time?

And what might that mean for capital intensity here going forward?

The shape of the declines are relatively uniform. You just start from a higher absolute volume in the Delaware.

On oil, our PDP is in the 45% to 47% range as of year-end. And then, on the gas side, you're in the high 20s, and corporately, you're going to be in that 30% corporate decline on PDP upper 30s.

And then, over time, that just – this should be the highest component of our corporate decline. And as we transition the program to the cash flow neutrality and pull the foot off the accelerator pedal a little bit on the growth, you're going to see that flattening naturally over time.

Yeah. Good morning, guys.

Wanted to ask you about the Strain Ranch well that looks like a pretty positive test from some stack wells, can you talk about how that maybe compares to the earlier tests you did in 2017? I'm just wondering why this one seems better.

Do you think you saw more lateral communication in the earlier tests or something else that you did differently here?

In this area, in the Strain, all tests have been very strong and confirmatory and positive. We've had some additional stack test in other areas of the basin that are inter-zone.

So the target zone were stacked directly on top of one another, again, pushing that density in 2017. So these were kind of stacked separate target zones, but confirmatory that in this area, they performed very well under this geometry.

So, really, there was logic behind getting out across the broad basin in 2017. It's not one size fits all.

You need to understand the development geometry. And we think we have a good assessment of that now and we have that rolled into the program going into 2018 and beyond.

So it sounds like just more of variability in geology that allowed it to work there rather than some other parts of the basin.

That's right. You're talking about 150 miles from North to South.

So that's exactly right.

And then, Charles asked you about the Wolfcamp C and I just want to maybe see if you can elaborate a little bit more on what your plans are for 2018. Any more significant step out wells to delineate that or are you mostly going to stay within the area that you've delineated so far?

We have about 10 on the books for 2018. The economics are extremely robust.

There is a higher gas component and nobody wants to see gas cut in this landscape. So that's why you're not increasing the component of Wolfcamp Cs.

It's not going anywhere. It's held in our inventory.

So we're excited to have it. Out of those 10, the majority of them will just be around known areas.

We think this Northern step out and the Southeastern step out helped define the prospectivity for us. We'll be assessing if we want to do one kind of on the Western edge, which we know is thinner over in the Upton County.

But the – although it's thinner, the petrophysical properties are very rich in a thin area. So we'll be deciding on that later in the year, but that's just a one well decision.

Hey. We're laser focused on the Wolfcamp C inside the black line area on slide 10.

And I'm seeing around 5% to 6% of our CapEx devoted to the Wolfcamp C program.

Thanks. Good morning.

I guess just to follow-up a little bit on the spacing thoughts. I'm just curious, understanding 330 feet seems to have pressed the limits, is there something in between 660 and 330 that you could potentially test anytime soon, or is it basically you'll hold back on the 330 feet for a later date and 660 allows that configuration at a later date?

No, there are a lot of footage options between there, but for a developmental situation when you're looking at your slots across and you're permitting, there's no – we would not go below 660. So then, into 2019, 2020, oils $70, and you're looking at testing 330s again, we would simply pull back on the frac sizing and really accentuate the near wellbore complexity of the frac design.

We intentionally kept a lot of variables the same to only answer the spacing component. So, we put the 660 foot frac on all of our 330 tests.

So that would be the variable, not necessarily augmenting our spacing.

Okay, understood. And then, I guess separately, Wolfcamp D hasn't been talked about at all.

One of your peers had a pretty compelling Wolfcamp D test. Seems like you guys might be in a pretty good position for some of that.

From a propectivity standpoint, any commentary there or plans to test the Wolfcamp D any time soon?

No testing on our end. I think it's kind of worked out nicely.

You have some of the industry is testing different zones and we're testing the Wolfcamp C.

Yes.

So, all sides are probably watching each other and I think that's prudent for us for now, no additional testing on the Wolfcamp D, but we're excited about the results that we've seen.

Morning, guys. Wanted to touch on well costs and inflation a bit more and I guess just using slide 11 as a reference.

Can you guys give us a sense maybe where kind of well cost stand today relative to that year-end number and then the 2018 well costs? I mean are you guys kind of within that 2018 band already or is there some extra inflation that you guys are maybe anticipating or budgeting for that maybe you're not quite seeing the field today?

We'd anticipate it to be linear throughout the year to get to that component. I mean the deltas on quarterly spend are going to be your activity levels.

And we're able to pick up – after the weather event, we're able to continue with the spot fleet, some additional activity in the first quarter. But on the unit cost side, we'd expect it to be linear throughout the year as this $60 oil hangs in there.

Okay, perfect. And then a quick one on hedging strategy.

It looks like, at least in the near-term maybe you guys have shifted maybe a little bit more away from the put spread into the three-ways. Is that a change in longer-term strategy or is that just more a result of kind of how the curve has evolved?

And I guess just generally, how are you guys thinking about building the book more into 2019 and beyond?

Yeah. I think we're always looking for ways to cheapen our trades.

So I think you're seeing that as we put on more three-ways. We're highly hedged for 2018.

2019, we've got a baseline out there. We'll continue to add opportunistically.

But I don't think you'll see us go back to being 100% hedged as we've done a year or two in the past. After we IPO-ed, we were more of the 40% to 60% of our expected oil production.

And I think that's probably the strategy we'll revert to 2019 forward.

Okay.

And, Jeff, I do want to follow-up with you. We talked about kind of shape of the year and activity levels.

With our rig count and activity in the fourth quarter in the Delaware, the completion activity is going to be higher in the first quarter in the Delaware as well versus the run rate for the rest of the year So we'll be down to about a three horizontal rig cadence and a completion cadence over in the Delaware Q2 and beyond. So it's front-end weighted in the Delaware for us in Q1.

Got it. Appreciate it, Matt.

Thanks for the time, guys.

Hey. Good morning, guys.

In the prepared comments you mentioned about 10% of the 2018 budget is going to be focused on delineation. Can you just maybe give a little bit more color on what's included in that delineation?

We have two wells in the Delaware Basin going after the Bone Spring. We have – those two four-well stacked pads that I mentioned, we would count one of the slots in there as delineation and then an extra Spraberry zone in the northern part of the basin that we hadn't completed in that area yet, although it looks good by offset operators.

So it's just a smattering of small localized test.

Okay, got it. And then, you guys do have a pretty sizable amount of cash there on the balance sheet, which obviously it's a nice position of being here.

Are there any plans to – I mean, I guess what's the plan for that cash? Is it just to fund the future cash flow deficits or is there anything else you guys are considering using that on?

We've been vocal about the cash on the balance sheet. It's mainly to execute through 2018 plans and 2019 plans.

Now, we're very fortunate with the increase in oil price that helps as a buffer of another couple of hundred million, I think. But that was the plan for that cash.

It's not for an acquisition. We've acquired a lot of acreage for the past couple of years and we just needed to focus on execution with this simplified plan.

Okay, got it. Thank you.

Yeah. Hey, guys.

Can you talk a little bit about some of the acreage trades that you guys have done? Obviously, very prolific success in 2017, added, I guess, a lot of increases in lateral feet to the program.

Can you talk about what you expect for 2018? Is it going to be as robust as 2017 or is it going to be something just a lot smaller in terms of your ability to sort of do that?

Just really trying to get a sense of what's left.

Yeah, I don't think that 2017 will be as impactful to the near-term as – the trades in 2018 won't be as impactful to the near-term as what we set out to do in 2017. It was a very aggressive format in 2017.

We saw where we could go with this and got after it aggressively to set us up for long-term. So now, it's all optimization around the fringe, low interest artifacts, non-operated artifacts that may have came with the previous acquisition slugs and trimming around there.

So the teams are just as active because it takes the same amount of work to work through a small trade as a large trade. So from a count perspective, it will be similar.

But corporately and what the external world sees, I don't see nearly as large of a impact in a go-forward basis.

All right. That's helpful.

And you guys talked to the completion cadence there in the Delaware saying that essentially you'll see more completions in the first quarter versus the rest of the year. Can you talk to that same dynamic in the Midland, in terms of how that plays out?

Yeah. And then, you transfer the – the rig count has essentially transferred to the Midland today, so then the completion counts follow and just you get into the run rate about Q2 for the rest of the year.

Good morning, guys.

Good morning, John.

Last quarter, you all had highlighted the really encouraging results you all had had on the compressed stage design that you all had done on three different areas across the Midland Basin. And I'm just curious with kind of this more simplified 2018 plan, sort of how you all think about incorporating that this year.

I know there was originally several additional tests that were planned for that design.

Yeah. As we go through the budgeting process, it goes down to, cumulative production days on any given timeframe.

So when you look at an annual timeslot, cumulative production days, and how many do you have the opportunity to put on, and that was the key driver of moving to smaller pads. And also, we see about a four-day delta in cycle times on the compressed stages.

So it just pushes out some of those volumes. We did see a 10% to 15% productivity uplift.

So it's something we'll look at. We're actually evaluating – it's been industry standard for about a year now, more of the chemical diverters and the fiber diverters versus the mechanical compressed stages that we tested last year.

So we don't have a large component of those compressed stages planned. We're all about executing on a timely fashion, getting these wells online.

Great. And then just my one follow-up question.

When I look at slide 17, it sort of highlights, specifically in the Midland Basin, the development zones that you all are going to be focused on. Bryan already gave rough percentage allocation on the Wolfcamp C.

Can you just give just the ballpark allocations of the remaining three zones, Wolfcamp A, Wolfcamp B and Spraberry, for 2018?

Yeah, John, we'll be in the Midland Basin primarily weighted to Wolfcamp A and Wolfcamp B, with then the balance would be equally split between Lower Spraberry and Wolfcamp C. In the Delaware, it's going to be pretty much focused on one flow unit within the upper Wolfcamp or Wolfcamp A, whichever you prefer, on that side.

Good morning, everyone. In your prepared remarks, Bryan, you talked about that outspend evaporating over time.

And Matt, in your remarks, you talked about transitioning to a plan in 2018 that would make development more efficient and more consistent. I'm thinking about the longer term to when you, I think, do transition to free cash flow at some point, what are the key elements that help get you there?

And is it some of what you're doing in 2018? Is it some transition to bigger pads or full section development or can you talk about what you're thinking about beyond 2018?

Yeah. So if we just replay the history, the long-term outlook, the vision of the company was to protect this tsunami of cash flow that we see coming our way.

And we put in the hedges in place. We issued the notes last October to bridge to get there.

We went through a large acquisition phase and then the most aggressive ramp-up in the entire Permian Basin. And it was all with the end game in sight.

And now, when we say what components are needed to get there, we've done the heavy lifting. It's just a matter of time and naturally letting this thing unfold.

And you can see with our activity projections, running the same amount of rigs and crews throughout the year, it just naturally happens. So we're really excited about this inflection point in our model, really, the inflection point and the corporation's maturity throughout the model.

So, there's really not a lot of high-risk components that need to happen internally for this to unfold.

Okay. And that makes sense, Matt.

And just to clarify, beyond 2018, would you expect to be drilling a lot of bigger pads and full section developments? Is that maybe beyond 2019?

I think you just feather it in throughout time. And we have the operational template in place now.

We did the SIM Ops on our eight-well pad and know how to orchestrate those types of larger scale developments at one time. So you'll just – you wouldn't flip a light switch and go all to once type of development So I think in 2019, you'll see how your pad counts, then in 2018, well counts per pad, and in 2020, you'll probably see higher than in 2019 and methodically throughout the long-term.

Thanks for the color.

Thank you.

Good morning. You guys talked about in 2017, in certain areas you had to move up the learning curve.

When you look at the portfolio now in the current context, where do you feel like you sit on the learning curve? I mean, what areas, if any, do you think you still need to move up that curve and how could that lead to maybe some efficiency improvements?

I think Wolfcamp C was a huge success, so you throw 5 to 10 projects on the wall, and if you can land one of them and create that kind of value, that's a huge, huge opportunity. Now, right now, it seems like creating NAV and adding locations isn't the main focus.

So that's why we're pivoting toward a simplified program in 2018. The stack – now, you're talking about – maybe you're mentioning this, we got a lot of science in from this four-well stack and the 330 spacing.

And we've mentioned earlier on the call, we talked about 330 spacing. What would you do differently?

And so you use this data. And what would you do differently?

You come in maybe in 2019 or 2020 if oil prices are higher, you do look back on your 330 spacing, how the wells are producing over a couple of years and maybe we shouldn't have fracked so hard. So it's mainly the data that we've collected in 2017 that will help us in potential future projects in 2019, 2020.

I guess it was more – let me rephrase the question. From the standpoint of the importance of landing zone targets and staying in zone, when you guys looked at 2017, did you have this – was the accuracy above 90%?

Do you feel like there was area that you had to figure out the appropriate zone? Now, you have that clued in, with the test that you've done now 2018 forward, that landing staying in target will be more consistent?

We have about a 95% plus in target achievement. So it was the identification of the target.

So we were literally testing new targets across the entire footprint. So we had about 11 discrete targets in 2017, and you get data from those as they come back.

So, already we're going into seven. We only have seven on the plans for 2018.

And when you look at our inventory, essentially, we are testing additional targets and benches outside of that – those zones labeled development zones. So there were targets down in the delineation zone.

So they were in target. The whole time they were just after a new target.

And with the depth of our inventory on that development zone, we have over a decade plus of runway on these premium locations. So kind of to Bryan's point, there's not a need – an inherent need to extend that inventory runway by delineating additional zones at this point.

You got to execute – and this can be a multi-year thing where you focus after the bread and butter and keep that delineation down in that 10% range.

Good morning and congrats again on the leadership transition announcement.

Good morning, John.

I wanted to circle back to the comments you had and kind of dissecting why expectations – why you fell short of kind of expectations in 2017. And so I think back to kind of guidance earlier in the year, you guys were looking for exit rate production of about 80 Mboe to 90 Mboe a day.

You came in at the low end of that. If the delineation activity had come in versus planned, where would you guys have been?

Looks like we were about 5,000 barrels a day on the year shy on projections on our delineation capital. So we put a risk forecast in on all of those as you go into a budgeting – these are the 11 zones, so four additional zones in the density spacing.

You put a risk forecast in, but you're going off of very little – you're in new territory, new world. You're going off very little data.

And then, as the production unfolded – actually, early time rates were meeting, but as production unfolded in a lot of these zones and a lot of the density test, the declines exceeded expectations.

And is that just delineation or....

On top of that – in that 5,000 barrels a day, on top of that, you obviously have the ramp up throughout the year. And there is a delay component that recurred throughout the year.

Earlier in the year, it was cycle time degradation. That stabilized mid-year.

But then as you broke out new equipment, ramping from seven rigs to at a peak 17, including non-horizontal focused rigs, you just have the equipment breakout delays, which is all behind us as well. So, it was a big program in 2017 and we didn't meet our historical norms for our expectations.

No, that's really helpful. And I guess not to harp on it, but just to be clear, in that five is, say, well delineation pad and then also maybe some of the Wolfcamp Cs.

I'm just trying to get a sense what was in that number or not?

Yeah. That's right.

I think going into the year, the Wolfcamp C would have been considered delineation, although they kind of probably outperformed expectations. But with those and the eight-well pad, it nets to that five range and the delays.

Hey. John, on slide 8, slide 8 basically explains everything.

And I think this is a big slide and there's a huge story to tell here, what went on in 2017, transformational, and lot of it was Double Eagle and adding to rigs and moving frac crews out, and these 11 derisk programs, but focus on 2018, our new simplified program. I think there's a huge story here.

So I just wanted to point this out. I think this is a great slide.