Industrias Peñoles, S.A.B. de C.V.

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

If you'd like to follow along with our Investor Presentation, you can find it on our Web site on the Investor Relations page. As usual, our remarks contain forward-looking statements, so please refer to our earnings release for a discussion of these statements and associated risks, including the fact that actual results may differ materially from our expectations.

We also make reference to non-GAAP measures, so please see those reconciliations in our release as well. And after our prepared remarks, we'll be happy to take your questions.

I'll now turn the call over to Bryan.

Thanks Brad. 2016 was an incredible for Parsley Energy.

Over the past few quarters, we set the pace on both production growth and cost compression. A year ago on this call we were excited to point to expected production growth of around 40% in 2016 versus 2015.

We actually grew production by around 80% last year. And we achieved this on a steady rig count for most of the year.

We're proud that our growth has been capital efficient as we've added more barrels per dollar than our peers. The fourth quarter was a strong conclusion to the year.

As you can see on slide three, we grew production by 5% versus Q3, capping off a year of tremendous production growth. And we're expecting very sharp growth again this year.

Slide four shows that well costs are holding steady despite rising completion intensity in the first traces of cost inflation. And we continued to lead the pack on operating costs, with another substantial quarterly reduction.

The big news of course is our pending acquisition of Double Eagle, which gives us a commanding presence in the Midland Basin. We're acquiring around 71,000 net acres with some production in a number of drilled uncompleted wells.

The inventory potential is tremendous with around 1,800 net locations in our highest priority targets. The Lower Spraberry, Wolfcamp A and Wolfcamp B, and many more locations and other promising formations like the Wolfcamp C.

As you can see on the map on slide five, most of the position is operated and non-operated portions mainly distribute around the edges. And primary development units consist of higher working interest blocks in the interior of the acquired acreage.

On the other hand the non-op acreage averages just 25% working interest, which weighs down the overall average and also makes the non-op acreage look like a bigger component on the map than it actually is. For example, the big non-operated block in the North Central Howard County is only around 1,500 net acres.

We're seeing positive results in this area and around most of the non-op acreage. But given the low working interest, we're actively discussing trades that would add mass and increase net in the main development areas.

The assay is evolving constantly and we feel very fortunate acquiring now. In the transaction like this, you pay for the net but much of the upside is in the gross.

The acreage represents compelling value today. But ultimately, we expect the map to fold inward to the central core operated divisions.

Already, there are years of long lateral high working interest locations in place in the best parts of the basin. We'll drill these locations first.

And all the while we'll be working the rest of the asset, blocking up, extending laterals and increasing our net, which is the same playbook we use to build our legacy Parsley division. Turning to slide six, more than 80% of the net acreage we're acquiring is in the part of the Midland Basin that we've identified as a sweet spot.

This is the area where favorable depth, fitness and thorough maturity profiles combine to yield the most attractive reservoir characteristics. And again, the acreage that lies outside the sweet spot is much lower working interest than the rest.

Parsley has always focused on core acreage. That mindset has served us well and we're sticking to that strategy which is acquisition.

When you look at the pro forma map on slide seven, not only will we have the second largest Midland Basin net acreage position among publicly traded E&Ps, we think it’s the highest quality position as well. As you can see, our acreage is situated in the heart of the basin, mainly inside peer-company footprints.

We truly are in the core of the core. Another important aspect of the acquired acreage is that it’s essentially undeveloped horizontally.

The time to acquire an asset is in its infancy, and will have a lot of virgin rock to drill, which is really positive for expected productivity. It also allows us to optimize layouts for long-term fully down-space development.

We believe this acquisition puts us in a position of strength. As you can see on slide eight, it puts us well over 200,000 net acres.

And it pushes our inventory above 4,000 net drilling locations in the Lower Spraberry and Wolfcamp targets alone. After integrating these assets, we believe we could run around 25 rigs on the combined footprint in the near-term.

That number will surely increase over time with additional infrastructure build-out. So, we’ve definitely increased our peak production potential.

We've seen several larger new packages change hands across the Permian over the last few months. And there aren’t many left, especially in true core areas.

For our part, we feel essentially right-sized and are focused on pulling forward the tremendous value associated with our asset base. At this point, we can truly say that there isn’t a single acreage position of comparable size that we trade out for.

We do believe in the value of scale and anticipate ongoing consolidation in the Permian, but we're entering adjusting period, where we expect to concentrate on optimizing and developing our own portfolio. With this in mind, we plan to add four rigs by the end of 2017, as you could slide nine.

Naturally, this sets us up really well for continued strong growth in 2018. We believe we're entering a sweet spot as a company, large enough to push on cost and capture efficiencies, but not too large to grow rapidly in adjusted changing conditions.

Our recent acquisitions ensure that we have the runway to deliver on the growth potential and also that we’ll be drilling on premium rock for many year. As discussed, our Midland Basin acreage represents the core of the core.

And our Delaware position remains the crown jewel with strong productivity, low cost road to other portions of the Delaware, and the economic uplift of mineral rights on much of the acreage. This means that for a long time, we’ll be able to say that the rock we drill tomorrow will be as good as the rock we drill today.

With that, I'll pass it off to Matt for more detail on the quarter.

Thanks, Bryan. It was another quarter on the operational front.

Our production growth is driven by consistently outstanding well results, which are a function of excellent rock and strong operational performance. We continue to achieve high initial productivity even as we increase lateral lengths.

In fact as you can see on slide 10, several recently completed wells posted company records in both the Midland Basin and the Southern Delaware. You can see on slide 11 that our Midland Basin wells are registering the most revenue per lateral-foot during the first three months of production among Midland Basin operators.

This is a function of leading productivity and an oil weighted production mix. Results like this give us confidence to double down in the Midland Basin, as we’ve done with the Double Eagle acquisition.

Turning to slide 12, in the Midland Basin, we focused primarily on the Wolfcamp A and upper and lower Wolfcamp B targets to-date. But we're starting to see results from other targets that rival the Wolfcamp A and B.

For example, our 2-mile Lower Spraberry Well continues to shine. We show its production history here against the 1 million barrel type-curve that reflects the shape of Wolfcamp A and B wells.

The Spraberry Well started lower as expected but with near-flat production trend, it looks poised to surpass the curve. And based on the production trajectory, we could be looking at a very robust ultimate recovery.

Combined with slightly lower cost and slightly higher oil cuts, our Spraberry portfolio could give our Wolfcamp wells a run for their mine. This particular well is in Upton County and much of the acreage we’re acquiring is in prime Spraberry territory to the north.

So, we expect the Spraberry to be an important part of our development program going forward. Perhaps more notably, we recently completed our first well in the Wolfcamp C formation.

And it posted the fourth highest 24 hour IP rate in Company history. The well is currently making around 75% oil and flowing at over 3,000 pounds pressure.

Yesterday alone, it made more than 1,700 barrels of oil. This is obviously very encouraging result and suggests that the Wolfcamp C could be on par with our other premium locations; so stay tuned for more to come on the Wolfcamp C.

Turning to the Southern Delaware on slide 13, record well results are making us feel very good about our recent acquisitions in Reeves County. Acquiring a block like this adjacent to our existing footprint is a real coup.

Clearly, this sets us up nicely for long lateral development, and the target zones on this block are actually a little thicker than our existing Reeves acreage immediately to the north. The first well we drilled in Reeves posted an IP30 of more than 1,900 Boe per day, representing our strongest Southern Delaware result to-date and the third highest IP30 Company-wide.

Our second drilled well threatens to surpass that mark having turning in the highest peak 24 rate in Company history and more than 2,600 Boe per day. These rates, combined with the minerals we acquired on and around the position have made this asset to match of anything in our portfolio.

You can see on slide 14 that we posted tremendous reserve growth in 2016, growing crude reserves by 80% despite writing-off what remained of our vertical reserves. We added 7 times of what we produced, mostly through drilling and we showcased very strong capital efficiency with PD F&D cost around $8 per Boe.

Like our production growth, our reserve growth is a function of strong and repeatable wells. Several of our PDP wells are booked at EURs over 1.5 million Boe one is booked at over 2 million Boe.

With PUDs conservatively booked and much lower EURs, we have substantial reserve growth ahead of us. The lots of positive trends and development on the operational front, and a lot of exciting results ahead in 2017 with a good portion of our capital going to relatively unproven zones and new spacing configurations.

With that, I'll hand off to Ryan for color on our financial and capital program.

Thanks, Matt. We posted a strong increase in adjusted EBITDA in Q4, up 24% versus Q3 to $117 million, Driven by higher volumes and lower unit cost.

Fourth quarter production came in better than expected at 45.1 in Boe per day, up 5% versus Q3. This puts us within our recently updated guidance range for the year as does reported CapEx of $158 million.

Normalized well cost held fairly steady, so we had particularly long laterals and high working interest on the 21 wells we completed in the quarter. Slide 15 shows our 2017 capital plans, which we introduced several weeks ago and then updated for the Double Eagle acquisition.

We’re keenly aware of the need to earn strong returns on committed capital and our 2017 budget is design to extract value from new and existing assets alike. Our asset base, financial profile and operational capacity position us to significantly increase drilling and completion activity this year, and that's what we plan to do.

We're targeting 130 to 150 gross horizontal completions in 2017 with about 70% of those in the Midland Basin, and the rest in the Southern Delaware. We intend to spend between $1 billion and $1.15 billion this year, translating to annual growth of around -- annual production growth of around 70% at the midpoint of guidance.

We got a rolling start on 2017 growth having added a rig in September, and we’re now running 10 rigs dedicated to horizontal drilling activity. In light of the pending Double Eagle acquisition, we plan to add four more rigs by the end of the year.

So, we expect steady growth through the first half of the year and then steepening growth in the back half of the year, leading into 2018. In fact, we expect net production to average 75 to 85 MBoe per day in the fourth quarter of this year, which would be 77% increase versus Q4 '16 at the midpoint.

We're excited about that growth trajectory and also about the character of that growth. For several reasons, we expect 2017 production growth to be accompanied by expanding margins and healthy returns.

For one thing, we're taking another step-up in average lateral lengths from around 7, 400 feet last year to around 8,000 feet this year. Developing our Southern Delaware acreage with mineral rights should lead to higher average net revenue interest, translating to more revenues per dollar invested.

We also expect an ongoing increase in oil as a percent of total production, which should translate to higher average realizations. And unit cost trends look favorable as well, following significant decline in 2016.

As you can see on slide 16, from a financial perspective, we're well positioned to implement an accelerated growth plan. Pro forma for several recently announced transactions, we project to have more than $1.3 billion of liquidity, including more than $750 million of cash on-hand and a fully undrawn revolver with a commitment of around $600 million.

Turning to our hedges on slide 17, we've been adding to our hedge portfolio since oil rallied on the news of the OPEC cut, and we've added even more in light of our pending acquisition of Double Eagle. Based on our guidance ranges for Q4 and for oil percentage, we're more than 80% hedged in the fourth quarter of this year.

We’ve built a strong position in 2018 and have extended into 2019 as well. We'll even assume a strong hedge book from Double Eagle upon closing.

All this increases our ability to plan, lock-in services and equipments, have relatively favorable rates and execute on our strong growth trajectory. So, to conclude, 2017 is off to a great start with an infusion of high quality assets at attractive prices and substantial momentum towards significant production and cash flow growth.

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

Bryan, I wanted to go back to your prepared comments and get you to expand a little bit. I hadn’t heard that phrase you used, talked about the acquisitions, where I think you said you pay for the net and the upside is in the gross.

Can you elaborate on that and help me understand what that means.

Charles, a lot of is pointing towards Double Eagle because of the average working interest to say roughly I think 60% to 70% average working interest and then operated properties. And there is a lot of bolt-ons that need to be done, find out working interest, increasing our net.

And usually you can get cheaper buys from non-op working interest owners versus operator versus let's say like 30,000 acre and usually you can get non-op for like 15,000 acre. That’s what that comment was about.

So, it's getting that working interest or the gross exposures like toehold to then tack on that efficient -- those efficient net acres subsequently, is that right?

Yes, it provides tremendous opportunity in bag.

And if I can ask question about the Wolfcamp C. Matt and/or Bryan, could you talk about what you saw when you were drilling this well, either in the vertical section and maybe choose this location?

Or what you saw on the lateral and how the well or how the production that you seen to-date fits with what your pre-drill expectations were?

Charles, this has been a long-lead effort by the team, something that geo guys have been very excited about for a few years now, drilled full core in a pilot well and had the full analysis for the data over a year ago. And then with they pull back, you obviously press cause on the lineation wells.

So, it's been in a hue for while. We’ve been excited about it.

All the technical data that we've matched to this point points to a good oil zone, the play fairway in Western Glasscock, Western Reagan; so it falls in nicely I think with all the recent acquisitions we’ve been active on. And the fact that 35% of the acres that we just picked up on the Double Eagle acquisition is driving this fairway, so we’re really excited about this result.

Really pre-drill expectations and then pressures we saw were very good, and then aligned with the completion and the pressures we saw, average treating pressures. And these all is very strong and encouraging and it is falling through on the production results.

And in fact today, yesterday was a 1,700 barrel oil rate, today we said a company that is looking like it's going to traject towards the 1,900 barrel oil rate, which would be a company oil record for 24 hour period on a well. So, we're really encouraged by the pressures and rates and oil cuts on this well over 70% on the oil cut side.

Something you could speak about the strategy around acquisitions and divestitures. And Bryan you said in your prepared remarks that you're going to focus on your core and entering into digestion mode.

Can you just speak to more about what your appetite is and what would make the cut for future acquisitions? Whether you’re focused really on, just like you said, increasing your working interest in what you have and maybe whether you’re considering divesting some larger pieces of the portfolio?

The digestion mode was a single to tell you guys that I think we're pretty much done through 2017. We've done over $3.5 billion of acquisitions, and if you add the two capacity deals plus Double Eagle that’s over 90,000 net acres, a majority of being in the Midland Basin.

We have a lot of work to do. We have a six months MSA master agreement signed with the Double Eagle management team to help us continue swap trades blocking and tackling.

There are some non-op on the out of parameter we swap out of or sell. But it's going to provide opportunity to core up in the center of the area.

I do believe that it's all basically all gone. Double Eagle is basically one of the last crown jewels in the Midland basin.

And we had to take advantage of opportunity for it, we’re in the process. We're very excited about the deal.

There’s probably a couple of others as Felix, north of Jagged Peak that's still there, that's run by EnCap. You can probably see that one go.

And the two large private guys in Midland Basin are family operated I am thinking CrownQuest and Endeavor. You probably see IPOs at the end of ’17 going into ‘18.

So Bryan, it sounds more like swapping and coring up versus actually tacking on larger additional packages. Is that right?

Yes, the B group Dustin offers golf clubs for this year, so that's really focused on leasing and swap some trades.

In your prepared remarks, you talked about seeing the first traces of cost inflation. I was hoping you could expand on that comment.

And what is the expectation on the cost curve shifting away from the Company and the industry over the next 12 to 24 months?

That's rolling into our guidance and our budget for 2017. It's the canary is mostly on the completion side, I think that's common to the entire basin and most operators.

What we're seeing is on the order of 10% to 20%, depending on the area and the other pressures. And then we roll that into the total well cost.

We have a lot of our services and suppliers locked in and committed. So, it's only on the order of about 10% of what we feel on the entire delivered well costs throughout the end of the year.

And again, mostly on the completion side, is where we are seeing a ratchet up. And really that’s to reactivated crews and rigs and they need that additional cost to break the crews back out that accretional start-up cost to breakout additional crews.

And as a follow-up, on slide six of the presentation, you indentified the area in the Midland Basin that screens best for factors like thermal maturity thickness and pressure. What is the range of economic breakeven prices throughout the leasehold today?

And how could that range tighten or change overtime? And maybe just as a follow-up to that question, how would you draw a similar boundary in the Delaware Basin, or is it too early to do so?

No, we’re extremely fortunate that we have a very deep bench of higher returning inventory. On our reserve case, we would need to see sub $30 oil before we reach economic thresholds that would impact it.

And then within this outline, I think that's a good color depending on we have basin leading cost on the D&C side. But if you use basin averages cost, I think that outline is in the 30% to 35% minimum rate of return hurdle to get in the big black line.

If you're leading on cost, you can push those returns up. And then as you core up into the sweet spots within that five county outline, you obviously are pushing rates of return between 60 and 90%.

And yes we have a look at the Delaware, first pass, geology doesn't change one day or the next. So, we have similar maps in the Delaware, and our footprint is definitely inside of that line within the Delaware as well.

I think one way to think about Delaware on returns is the closer you get to the oil window the higher IRRs you're going to see versus going west little more gassy.

Looking at slide 23 on the Double Eagle acquisition, you obviously talked about to tailor fantastic result there, guys. Just wondering your comments that you would suggest about maybe some additional Lower Spraberry in the area, which you think the potential, especially in that part of Reagan?

Or the other way to ask that is, given the tremendous result you’ve had on the Wolfcamp B on the Taylor well, will you continue with that in that area?

Yes, it streams out very well. Our results the competing returns because of the lower cost on the Spraberry.

But the comment on the acquisition on the Spraberry is adding, if you look on slide 24 and 25, is adding in heavily drilled Spraberry areas as well where there are already extremely high proven repeatable well results. So, it's good across the board in this particular area, the Wolfcamp B on slide 23 is the most proven to-date.

I think this area has seen a lot of Spraberry wells, again it's all HBP, and held by primary natural resources their large units that cuts all this. And these acquisitions that we’ve bought over the past two years blocking up West Reagan has all been HBP acreage as well.

And so it’s all legacy titles where operators aren't rushing to hold the leases, and that's why you've seen the slow process hitting the other benches.

And then one for you or Matt, once you add the additional rigs now post this acquisition, I mean you guy are right up there among the most active, all the bigger players in the Perm. How do you think about for service costs, are you able to -- we've heard a few peers on the conference calls mention about trying to lock-in some of their D&C for the remainder of this year and the next year.

I mean again, certainly, now that you’ve got the economies of scale and you guys are one of the more well known in the area. Does that give you ability to do that, or maybe just any color that you can add about locking things in right now versus for the rest of the year?

No, you're absolutely right. You need to be in a sweet spot of activity level in this -- what we’ve seen over the past few years is that we are in that level.

We're an operator of choice for the vendor network. And then it's all about transparency, our supply chain management group and procuring group, forecasting out being good partners with our vendors, telegraphing to them how much same demand we’re going have the third week of November.

And we know all these things based on our projections. We might as well share some with our preferred vendor network and help them on their supply chain side.

And that’s healthy alignment. That’s the way to control cost right there, and we've had a lot of success with that in the past and we plan on doing that in the future as well.

You discussed some of the wells that you have in your reserve report that are between 1.5 million to 2 million barrels. Could you do two things one, discuss what the average EUR on your -- I know if it's relevant just to look at your 2016 program is in your reserve report.

And could you also give us some context of where those larger wells were located in the rational, why those are so big?

Yes I think order of magnitude, it's in North Upton is where the largest wells are on absolute EURs. So that’s just been based on the deposition of the basin and that’s been from the beginning the highest absolute productive area; so, those where the larger wells are.

And then as we extend lateral lengths, of course in Reagan we drilled multiple 10,000 foot plus lateral lengths we’re seeing close to that on the EUR cost of reservoir portfolio. So, I don’t have the exact -- we don’t disclose the exact average of 2016.

But its increasing year-over-year in a positive manner and the PDP EURs are much higher than what we pencil in and what are it is for a PUD until we get them online. So, we always have -- we have positive revisions this year all stemming from PDP performance.

So, we expect that to continue in the future.

And as my follow-up, obviously you talked about the momentum you have building through 2017 and '18. Can you give us a little bit color on what the '18 is shaping up like?

Do you sense, is it still a year where you're going to out-spend to accelerate the opportunity? Or when do you think you could cross the gap of bridging free cash flow neutral?

Essentially, we're keenly focused on returns. We have some of the highest returns in the country and the bench of inventory to affect them.

So, we're a growth Company right now, and you could attack it two different ways, you could get the cash flow and then show by reducing activity or you can actually get there in the long-term by accelerating activity. So, our outstanding drops dramatically year-over-year.

And we're on a trajectory eventually for its free cash flow with a tremendous production growth along a way.

And this is Ryan I’ll just add to that. We're always focused on leveraging liquidity.

So, to the extent that we are outspending cash flow, we're going to do so such that it doesn’t impact the balance sheet at all.

My question has to do with Delaware Basin. I noticed that you have some inventories on the Bone Spring intervals.

So my question is, when would you drill that, and is it going to be this year? And how many spec pays you expect from that part of Delaware Basin, understanding that the pipes are good for oil and gas.

How is the water handling in this part of the neighborhood?

We do have a couple of Bone Spring delineation wells as part of our delineation budget in the back part of 2017, being spud in the back of 2017. And we have an operated set of SWDs that has plenty of capacity for 2017.

So we feel that we can handle our order in 2017 as we ongoing build out in the ratio to the program activity throughout ‘18.

We’re very fortunate on the surface that we own over 30,000 acres of surface. And we’re closer to platform, so we feel like we can maneuver on the water front.

And in the Bone Spring horizons, are you after the sand or the shale, is it second or third?

We’ll be testing the third and the second in the shale.

Just a question on the Wolfecamp C, was that well drilled on a unit that already had existing Wolfecamp B production? And if not, do you see any risk regarding interference between the two benches?

Zero risk of interference appearance we are 580 feet deeper than our Wolfecamp B landing in that area. We do have Wolfecamp B wells on the tailored Reeves, very collective wells, also no zero interactions between the production on those wells and this well.

So the Wolfecamp C complex alone in this area is 700 feet thick, and it's -- which is essentially double the AB complex. So again, we’re 580 feet deeper than our Wolfecamp B it is its own oil fingerprint and its own zone.

And then more broadly, and I guess you need more production history here. But how do you see the Wolfecamp C and I guess the Lower Spraberry as well fitting into your long-term development plan?

And maybe to ask the question in a different way, when do you think you’ll have nailed down your ultimate development plan and associated pad design in the Midland Basin?

We have lots of tackle, it's a good problem to have with as many productive high quality benches, highly return benches as we do have. I'd say we’re probably on -- depending the results of our high density Wolfecamp B pad that comes on mid-year, we’re probably honing in on ideal phasing with the Bs.

But we were probably overall in the portfolio still third-fourth inning on ideal spacing across all of these. So we’re planning long-term on our surface development to handle as I mentioned in previous calls 60 plus wells for development unit.

And this just adds another bench on top of that that we can attack. And then it falls in relatively increasingly activity to pull the value forward from our own footprint.

Sticking on the C bench results here and just kind of the prospectivity of that charter across the basin, Matt I think you mentioned you guys have mapped maybe a sweet spot or fairway in the West Glasscock, West Reagan area. And just wondered when we look at your inventory, I think pro forma you guys are at 900 or so locations in the C.

Do you have a sense of how many of those locations are within that identified fairway?

Probably on three quarters of the C indentified is in that sweet spot fairway.

We don't have Howard or Martin on the Cs.

And for a follow-up find it real interesting on Bryan to your comments on netting up your gross. And it seems like every quarter your average working interest is trending up.

So just curious, is that really a function of you guys maybe aggregating those non-op interest, or even front loading the higher working interest wells? I guess just trying to get a sense for when you guys first our AFE wells, are you guys at 80 for numbers taken and you're bolting up into those high 90s?

Or just trying to get a sense for how that range changes as you guys move forward in the development program?

It's a mix bag, it’s funny that the drill bit when you AFE the drill bit motivates other working non-op working interest owners to sell, or motivates JOA. So that happens always on the fly, so it’s hard to put a sum to it.

But we are also -- those same guys sometimes want to trade or swap out of it. And a lot of them are competitors and a lot of them are old mom and pops non-op operators that have their own properties.

So you can keep on going down the line, it’s just a different make up of each time we drill a well. But we are always focused on higher working interest properties as we move the rigs.

Our legacy horizontal inventory was 90% working interest. And then as we acquired Double Eagle, around 70%.

So those are the type of deltas that come at you as you put the bit in the ground. And as Bryan mentioned, we can aggregate additional working interest.

Last quarter the big news was on the Grace Pad when you did the Upper Lower B stack test. Can you give me an update on the timing on the Upper Lower A stagger test that you all contemplated doing?

Yes, online, still early and looking really good. So, that’s out in Eastern Reagan and more positive news on that front.

So, second in line we think that these multiple stack zones are the ultimate way to go. So, we'll see more of that going forward.

Were you asking about double AA?

Well, the Upper Lower A stagger test that you all were contemplating to see it's basically like to be these two sections?

I thought you're asking about more stacks, stacks A, Bs. Yes, the Upper Lower A comes on mid-year.

And then my follow up question when I look at just the massive outperformance you've got on these Reeves County wells and then you still have the continued outperformance on Midland side. When I look at the production guidance, is that supposed to be indicative of like leading edge or more like indicative of that that 1 million curve you’ve all been shown for months, even though you all are doing wells above it?

We have to -- coming into 2017, we've 20% of our capital to 30%, if you count the down spacing on these delineation projects. So, there is a risk factor coming into that applied on our forecast.

And we hope that it outperforms such as this Taylor well, obviously outperforming base line place holder and budget. The other 20% to 30% of the capital is based risked on the production forecast.

Just wanted to revisit the conversation around how you ultimately think about developing units. How you think about the importance of co-developing up and down the hydrocarbon call on at the same time.

And like the importance of developing out of leases all at once or unit all at once as opposed to having a single well come through. What sort of degradation you think you might see as you do a full out levers of single well on the unit?

Yes, that’s exactly what we're solving in our super-pad. So we've been -- we’ve had the full developed 660s with the offset timing to the side for a long time now.

Now what we're trying to push is the sequencing and the density down to 330 feet between wells and then in turn B. So, really where it only matter is zones that are within the same flow unit.

And we do see -- we've continued to see stress shadowing and benefits between the A and But when you put on these stack-pads. We don’t see necessarily hydraulic communications but we do see interference on the frac complexity.

So, it's resulting in positive production. But we do not expect when we drill this eight well down space pads but then all to meet the parent type curve.

So, we risk each well down about 25%. And we expect that -- but then we look at NPV per section you see a massive uplift.

So, it is additive to NPV.

And we just added a new, may be a potential new component. We might consider drilling up Wolfcamp A, BB and C, those formations.

And how much vertical distance, and I guess follow-up on that. How much vertical distance do you think is required to really communicating between zones?

Wolfcamp A/B stack getting some benefits from each other. But like with the C being as far down as it is.

What's the threshold there as it relates to how much vertical distance you need to think?

So, we don’t get a good selection, we don’t expect any stress shadowing benefits from the C, it's far enough away. We see that we like that 250 to 300 feet between targets.

In between that you see actual hydraulic communication where you might be accelerating same rock.

And then last, and alluded to the max rig count that you guys talked about earlier of 25 rigs that overtime could turn higher with infrastructure and organizational capacity. Is there benchmark rule of thumb you guys think about as it relates to what limits there would be to efficient development on 10,000 acre block if you’re trying to…

No, it's not -- we go by area and we work by the constraining point of water supply, or water disposal. Then you can look at electrical grid capacity and you work inside out to drill that.

Theoretically, with these benches that Bryan mentioned in A, B, C and the Lower Spraberry, you could have four rigs back-to-back to back. But what’s going to limit you use, how much water you can prepare for the frac.

So in some areas, as you build out that infrastructure, if you want to build for that you could have the extremely dense on a 10,000 acre unit. But right now as we go by our entire footprint, we have the capacity essentially today on that water sourcing and disposal to handle 25 rigs.

Wanted to touch on some things out in the Delaware, obviously the results you guys put up in Reeves were spectacular. But I wanted to get a sense of your plans for take-outs given that you got the full benefit of the minerals right outs there.

Just curious if we should expect some delineation results as you move southeast in the coming quarters?

Absolutely. So the 35% of our total B and C is focused on Delaware basin this year and of that, two-thirds is going to take us.

So throughout 2017, you will see development -- I'm sure the permits will start hitting here shortly that can be mapped up. But that goes from the northwest to the southeast and we've always said we’re just building that out on our electrical grid from the northwest to the southeast of our ranch there.

Then switching gears a little bit on the LOE side certainly impressed that you guys got it down to almost 350 per Boe this quarter. Looking at the 2017 guidance some kind of uptick is just baked in understanding you guys never want to be conservative with respect to guidance.

But still I just wanted to make sure there was, or see whether you guys are incorporating either a higher LOE because of more Delaware production being layered in or if you guys are factoring any inflation in operating costs?

The main component there, Sam, is digesting these -- around 400 plus of vertical wells from other operators, getting them up to partially specs and working them over properly from our recent acquisitions. So, there is a lot of unknowns there.

We think we definitely captured that within the guidance range. And then secondary to that as you mentioned is a larger component of our CapEx going to Delaware.

And we do see about double the water rates over there 3:1 to 4:1 per barrel compared to 2:1 on the Midland side. So that's just a mathematical component that increases the LOE.

But the main driver on that guide off is digesting these vertical wells.

Which is -- it's pulling and driven broad parts to remedial squeezes.

Are you still using brown and white sand depending on the area that you're drilling in, or have you tightened this into type of sand?

Yes, still the majority of Upton County is due to the depth that’s white sands, Reagan County, Glasscock County, Howard will be brown sand. We use white on our Wolfcamp C well, again its 580 feet deeper and then all white over in Delaware.

We've had a positive test using brown in Upton, but it's not the main piece of our program in the current budget.

Then looking at the two mile Lower Spraberry, and that shallow decline. Is that two mile shallow decline similar to the one mile that you did which also exhibit a shallow decline, or is the two mile actually declining at a shallower rate than the one mile?

The two mile is almost completely flat, but the one mile has a very low decline, as well had lower IP with pretty low decline. But this one is very flat.

It had a different completion and wellbore design throughout there's some different things on our first well that the one mile that we're restricting some things.

Good morning. Congrats on Double Eagle, and thank you for taking my questions.

Bryan, if the upside is in the gross, I'm just curious how soon investors could potentially see that upside. And so I guess my question is, is there a lot of low hanging fruit with regards to the trades that we should be maybe looking for some core inventory expansion by year-end '17?

Or do those sorts of talks or negotiations take a little bit longer and it’s hard to predict that coming kind of the next six to 12 months?

You know it comes in ways from our land group. For one quarter you don't see much and then another quarter you see a lot coming through.

But fortunately, this Double Eagle team their machines they're in every operator's office. Things like always every week and it’s amazing how they can get in the doors of these larger companies.

So we're going to lean on them as much as we can, because they have this machine going, you want the machine that keep on moving. And there is a lot of swaps being discussed right now, especially during mafic, I think we met with five or six different operators.

So it's hard to put a finger on it. It's going to come in ways.

It could come in within next few months. It could come by the end of the year.

But it just depends on how fast the other operators want to move.

We've already completed, a week after signing they completed a thousand acres of folding-in as we call it, that’s not reflected on the map.

And then my second question, Medallion had a December press release, mentioning you all as an anchor tenant on their Picos to Crane pipeline. I am just curious what level of capacity you all took down, and if you can maybe tell us the tariff level?

We can't disclose the tariff levels, but being an anchor tenant and then tying into our footprint. And our Reagan and Upton area is very favorable to us we believe.

And think it was a win-win for both sides getting their extension over to the Delaware Basin. And they're required to take all of our barrels on the footprint committed, and we've shared projected forecast within, they’re building out for that.

It was just an acreage dedication and not a set at BC?

That’s right.

And I guess just on the tariff, is there a way we should think about realizations for the Delaware Basin? Do you expect those to be materially different from how you’ve been trending thus far?

Yes. So trucking in the Delaware is on the order of $2 a barrel, and it's much more favorable than that.

So Delaware Basin oil realizations will actually improve the corporate level as that total volumes, as the Delaware mix grows is that what you're saying?

Yes.

Bryan just a question on how you think about capital efficiency going into 2018 with the combination of longer laterals, and whatever you’re seeing in service cost inflation. Can you talk about -- where you think that direction is headed?

Well, our program is already in place. Then you could look at the, one of the first slides where we have some serious fork going in the fourth quarter on the production growth.

I don’t see a change much on lateral length going into '18. And the same amount of working interest besides the swap and trades.

So, they should see an increase there. I don’t see much change from what’s normal minimum going into ’18.

I would just use the same model using the '17, back half for '17.

Do you see cost having much of an impact on where you think that will be in '18, or can you…

I think we baked in like 10% to 15% cost inflation for ‘17. Now, if all of this move up to $55 to $60range, yes -- I don’t want to see if we’re just sitting in this range from $50 to $54.

If we’re just sitting here, I don’t see another leg up in service cost. It depends on commodity prices.

If I could just get back to the development question, and Matt I think you said third or fourth inning. But I mean if we think out whatever 19 or 20 putting back half of next year.

Do you anticipate you're starting to be in an optimization as far as the development mode goes. And I mean when do you think you get there, or you can comfortably say hey this is -- I guess you never fully get there, but get close enough and can say, hey, this is the way we can develop this section, we're going to put this many wells in.

But when do you think you could get to that point?

Well, we're trying as fast as we can. But when you drill eight well pads the green light decision on the eight well super-pad was April 21st of last year.

It’s not coming online as you go through the planning process and then the actual side, which is late last year. Not coming online until mid this year then you like see 90 days of production to really change your port.

So, you’re looking at one year cycle times to change full development behavior. So, that’s what we’re up against.

We think we're almost there on the B. We’re just kicking off that process on that A getting into AAs and then we've just drilled into C and very early on and our development on the Spraberry.

Although, we conduct when lean on industry development to get to right spacing on the Spraberry. So, that should have more of that timing.

And hopefully by 2019 timeframe, you back into that 2019-2020 like you said, it should be pretty close to go on full-scale.

And then just as one follow-up. Do you have -- do you care what mixture using as far as the same goes?

I mean you care for 20-40, 30-50, 40-70 as -- do you see a notable difference when you complete these wells?

We actually have not seen a noticeable difference in production, but we see a noticeable difference in treating and the ability to get the sand away. It's just easier the smaller grain size EUs.

Convention would tell you that a large grain size has more conductivity, but it's easier to get to smaller grain size put away. We’re primarily 40-70.

We got to use much hundred mesh to a lot of other industries and 100 mesh. So, it's a mix between those two as mostly favorable in the basin right now.

So it's logistically it's easier but not necessarily, not seeing the well performance, is that…

Not any of that, yes…

Just a quick one, Lower Spraberry. How much of your inventory do you believe is been de-risked for the lower Spraberry in terms of how much do you believe can actually perform in line or better than that Dusek well at this point?

I think that Dusek well is very representative of maybe even the bottom edge of our inventory as we go north it gets into more delineated due to industry offset results, Spraberry results. So, I think you’re looking at 80% plus very comfortable with.