Industrias Peñoles, S.A.B. de C.V.

Thank you, operator, and thanks, everyone, for joining us today. With me this morning are Bryan Sheffield, our Chief Executive Officer; Matt Gallagher, our Chief Operating Officer; and Ryan Dalton, our Chief Financial Officer.

From time to time, we'll be referring to our Investor Presentation, which you can find on our website on the Investor Relations page under Events and Presentations. During this call, we'll make forward-looking statements intended to be covered by the Safe Harbor provisions under Federal Securities laws.

There are many factors that could cause actual results to differ from our expectations, including those we've described in our news release and SEC filings. We may also make reference to non-GAAP measures, so please see the reconciliations in our earnings release and Investor Presentation.

On the agenda this morning, Bryan will give an overview of the quarter and an update on our outlook. Next, Matt will discuss our accomplishments on the operational front.

Ryan will then discuss our Q2 financial results and full-year guidance. And after that, we'll be happy to take your questions.

With that, I'll turn the call over Bryan.

Thanks, Brad, and thank you all for joining us. We continue to build significant momentum in the second quarter, showing the type of execution and results that will enable Parsley Energy to flourish across market cycles.

We increased production by 18% quarter-over-quarter to 22.2 MBoe per day, despite pulling just a handful of wells on production in Q2 and we're raising annual production guidance again on the strength of ongoing outperformance by our horizontal wells. The ability to rapidly grow volumes without much help from new wells shows the strength of our existing production base.

Our base decline rate already benefits from our older vertical production and we're seeing that our horizontal wells are holding in strong as well. Turning to slide four, the one million Boe type curve we published last quarter has more data points in their earlier months than later in year one.

And with our more recent wells outperforming our earlier wells, we certainly hope for its uplift in the latter portion of the year as our newer wells move to the right. Sure enough, as you can see on the chart on the left, we're starting to see some positive separation between our actual results and the type curve in months six through 12.

This drove higher than expected volumes in Q2 and shall continue to support a strong production trend even at relatively depressed activity levels. For this reason, we're raising full-year production guidance from a range of 20 MBoe to 21.5 MBoe per day to a range of 21.5 MBoe to 22.5 MBoe per day.

This represents 55% year-over-year growth at the midpoint despite sharply reduced activity over the first half of this year. You can see our quarterly production trends in the upward progression in annual guidance on slide five.

When you consider that we've gone from 11 rigs running in Q3 of last year to just one rig running for part of Q2, it's pretty remarkable that we've run production 45% during that time. As you know, after dropping to one horizontal rig early in Q2, we ramped up the four rigs in June.

One month earlier than we originally planned. Obviously, this is right before the most recent down draft in crude prices.

Fortunately, our hedge position helps insulate us from the effect of the most recent drop in oil prices. We estimate for the rest of this year, a 20% decline in oil price from $50 to $40 would cause just an 8% decline in rest of the year EBITDA.

And for 2016, a $50 to $40 oil price decline would reduce EBITDA by just 11%. So, we're fortunate to be so well-hedged and we think this sets us apart.

While we believe that Parsley is positioned to really shine in recovery scenario, we also want to emphasize that we're well-positioned to outperform in a lower for longer environment. In addition to our strong hedge position, it's also worth noting that our well economics continue to improve as our drill times and costs come down.

For example, slide six shows that even at $50 oil, the estimated NPV for Wolfcamp well and our focused area is close to $5 million, with a return around 40% and payout in under two years. Throughout the last quarter, cost savings have pushed the NPV on our Wolfcamp wells up around $0.5 million and returns up around 10% at a given oil price.

With strong returns and a substantial hedge position, we're comfortable with the current plans around four rigs through the remainder of the year. One of our horizontal rigs is on a month-to-month contract.

So, it would be easy to drop a rig. But, we intend to hold steady.

In light of the shorter of drill times, running the same number of rigs will mean drilling and completing more wells than previously planned. For the year, we now expect to drill approximately 10 more horizontal wells than we expected at our last update.

We also expect to kick off activity in the Southern Delaware on a Trees Ranch prospect in northwest Pecos County. We've seen strong oil production on our vertical exploratory wells and our proprietary 3D seismic shoot shows abundant potential for long lateral development.

So, our three-year extension on the majority of our Southern Delaware acreage gives us flexibility on the development timeline, everything we see is so encouraging that we're going to go ahead and move forward. As a first step, we'll participate in a non-operated horizontal well near the edge of our acreage.

The next step will be to drill our own horizontal well later this year. Naturally, we'll take a cautious approach with these wells, and we'll do some research.

So, we're not sure exactly when results will be available, but we're excited to see how the wells perform. With more activity planned in the Midland Basin and the Southern Delaware, we're raising our CapEx guidance to the range of $325 million to $375 million.

Looking at CapEx in the context of our production growth, we're adding around 8,000 Boe per day this year, all organic, for around $44,000 Boe per day. Put differently, you can get about 23 Boe per day for every $1 million of CapEx.

As you can see on slide seven, this puts us near the head of the class for 2015, despite a back-half-loaded production ramp that reduces year-over-year growth metrics. And Parsley screens even better next year.

We haven't provided 2016 guidance, but based on consensus estimates, we're expected to show the most efficient growth in 2016. We felt no urgency to add to our acreage position given going rates and our strong inventory.

But as you can see on slide eight, that doesn't mean we haven't been actively high-grading our asset base. For example, we've channeled a lot of energy into acre-for-acre-trades.

We've also divested some lower priority assets in Gaines County and redeployed a portion of those proceeds to a smaller bolt-on in our core area. In aggregate, we netted over $4 million since the beginning of Q2, while adding around 30 horizontal drilling locations and extending our average lateral length by more than 300 feet.

We're still working on all these fronts, and we think there is a good bit more to come in terms of costless additions to inventory and lateral lengths. While it's an uncertain time for our industry, there is certainly a lot of exciting things on the horizon for Parsley.

We're transitioning to pad drilling. We're high-grading our asset base, and we're looking forward to delineating the Lower Spraberry zone and our Southern Delaware acreage as well.

Matt and Ryan will elaborate on these things. I want to end my remarks by recalling that from the time we discussed our 2015 plan, we stated the shape of activity would generate significant momentum heading to 2016.

Even more so than before, we believe that would be the case. With that, I'll turn it over to Matt.

Thanks, Bryan. On the operational front, we have a lot to be excited about.

As always, the bottom line is our well results, which continue to be exceptional. We put five Wolfcamp B wells on production in Q2 and these wells averaged 189 Boe per thousand stimulated feet, in line with our program average to-date.

Strong IP rates are important, but we put even more emphasis on cumulative production. Based on the benchmarking we've done, we believe our Wolfcamp wells match or exceed the six-month cumulative production of any zone drilled by any operator in the Midland Basin.

On slide nine, you can see that our Wolfcamp wells have higher 30-day IPs and higher 180-day cumulative production than our peers' Wolfcamp wells. Interestingly, as you can see on the right-hand side of the slide, our 30-day IP rate is very strong predictor of six-month cumulative oil production.

And there's no evidence that this relationship breaks down farther out. While we only have a few wells with a full-year of production data, the R-squared between 30-day IP and 360-day cumulative oil production is 87%.

So, we think our exceptional initial production rates are a good reference for the productive capacity of our wells. It is important to highlight that production rates from our Wolfcamp A wells are holding up especially well, on track to match our Wolfcamp B wells in terms of cumulative oil production around the nine-month mark.

So, we're seeing strong economics across the board on our Wolfcamp program. We're also encouraged by what we're seeing from our Wolfcamp wells in Reagan County.

For example, IP rates from our Reagan County core wells are coming in around 10% lower than our Upton County core wells, and costs are lower by about the same factor. So, the economic profile of our Wolfcamp wells is very robust across our entire core area.

This also points to strong economics in the Reagan County acquisition we announced earlier this year, especially since we've already drilled a well, and we're about to turn that well to production. The big theme for Parsley this quarter is drilling efficiency.

We've mentioned it before and now have more conviction in the durability of the cycle time compression we've seen. Turning back to slide six; at the same time we've increased our lateral length by 18% over the last two quarters, we've decreased our spud to rig release days by 30%.

On top of this, we have moved in a fit-for-purpose rig to preset intermediate casing, which allows us to use a much cheaper rig to drill the intermediate section of the well. Overall, drilling and completion costs for the current period activity continue to decline in Q2, coming in around $6.5 million for a 7,000-foot completed well, down from about $7 million a quarter ago.

The data we're seeing suggests this is hard to beat when you consider the depth and pressure we encounter in our core area and our higher sand loading per well. But, we're certainly still pushing on the cost front.

For example, working off our tubular inventory should save us a couple hundred thousand dollars per well in the next month or so. The net impact of these operational gains is more wells per rig at a lower cost per well, all of which enhances capital efficiency of our drilling program.

Now that we're back to running four horizontal rigs, we're ready to kick off our first pad project, which will be a three-well pad consisting of two Wolfcamp B wells and a Wolfcamp A well. We can point to meaningful full cycle cost and time savings with the use of pad drilling, so this is the first project in a gradual transition to what will likely become a majority pad drilling program.

This is another component of our conscious effort to optimize development of our assets. On the infrastructure takeaway front, oil volumes on pipe continue to grow, now up to more than 5,000 net barrels per day.

And our average transport cost per barrel of oil dropped by 6% in just one month from May to June as the benefit of putting oil barrels on pipe starts to flow through. Our water disposal network build out is ongoing hindered a bit by surface constraints in Q2, but still on track for significant savings in the second half of the year.

We're now holding just 29% of our water, down from 45% in the first half of the year, with further reductions to come. A quick follow-up to Bryan's comment on our drilling inventory.

We're very pleased to see our average lateral length climbing as you can see on slide 10. And looking beyond the average to the details, it's important to understand that our core locations are about 700 feet longer than our Tier 1 locations.

Not only that, our core Wolfcamp locations have the longest average lateral length of any area and zone combination in our inventory. So, our priority drilling targets include an abundant supply of longer lateral locations that will likely drill earlier in our development program.

This means that for the next several years, our average lateral length should meaningfully exceed the average lateral length in our inventory overall. Next up on our Midland Basin inventory delineation plan is he Lower Spraberry, where other operators have had a good deal of recent success.

We've talked before about how our Wolfcamp is advantaged in terms of thickness, and you can see this on slide 11. In the Spraberry, however, logs suggest that in terms of both depth and thickness, the Lower Spraberry is pretty consistent from north to south in the heart of the Midland Basin.

You can see this by tracing the line of section from top to bottom on the map and finding a corresponding points on the profile. So, we expect favorable results from Lower Spraberry on our acreage and look forward to drilling our first Lower Spraberry well pretty soon.

And, of course, we're very excited to get to work in the Southern Delaware as well. On slide 12, you can see how concentrated and continuous our 30,000 acres are and how those acres are situated in what we like to think of as the catcher's mitt, the favorable characteristics for sediment accumulation.

We'll target the upper Wolfcamp interval on our initial well consistent with the line of strong wells that extend from the northwest in Loving County, through ward county straight toward our acreage in the northwest corner of Pecos County. In summary, we see lots of value creation ahead of us, and we continue to drill great wells, drive down costs and de-risk new zones and areas.

Now, I'll hand off to Ryan to cover our financial results and outlook.

Thanks, Matt. Several favorable trends led to a significant increase in our bottom line in Q2.

Adjusted EBITDAX increased 48% versus Q1, driven by higher volumes and realizations as well as lower per unit operating cost. Oil volumes increased 16%, but mix was a bit of an anomaly in Q2.

Higher plant efficiencies supported relatively stronger NGL volumes, so oil, as a percent of total production, dipped from 59% in Q1 to 58% in Q2. In terms of the broader trend, we continue to expect a fairly rapid increase in oil, as a percent of total production eclipsing 60% the next couple of months or so and pushing closer to 70% next year.

LOE is trending in the right direction though at a slower pace than we had hoped due in part to the delays Matt mentioned on our water disposal project. For Q2, LOE was down 5%, in Q1 to $9.12 per Boe, while reported LOE is burdened by higher than anticipated prior period costs.

A detailed review of our LOE suggest a current period of expense close to the $7 per Boe. And LOE on our horizontal wells is averaging just a couple of dollars per Boe.

With all this in mind, we expect to trim down to our original guided range of $6 to $7 per Boe for the next couple of quarters. In the meantime, we're raising full-year LOE guidance to $7.50 to $8.50 per Boe to reflect higher reported expense year-to-date.

Meanwhile, G&A is tracking near the bottom of our guided range at $6.09 per Boe in the second quarter. As planned, we cut CapEx significantly in Q2, down 38% versus Q1 to $75 million.

Spending would have been even lower had we not used our top setter rig to spud several extra wells near the end of the quarter. Higher average working interest limited to second quarter CapEx declines as well.

Turning to our outlook for the rest of the year. As Bryan mentioned, we're increasing CapEx guidance to a midpoint of $350 million to the count for the extra wells we expect to drill and complete this year.

Newly planned activity in the Southern Delaware also represents a meaningful portion of the increase. For the year, we plan to complete 45 to 50 gross horizontal wells in the Midland Basin, up from the previous estimate of 35 to 40 wells.

We now think average working interest on horizontal wells for the rest of the year will come in at the high end of the 85% to 90% range. Even without a significant contribution from the wells we're adding, most of which will come online later in the year, we're raising full-year production guidance to a midpoint of 22 MBoe per day.

We expect second half production to be significantly weighted towards Q4 with production climbing rapidly towards the end of the year and into 2016. This means our growth rate should pick up at a time when production growth at many companies is slowing or reversing.

We have ample liquidity to fund our drilling programs with $476 million available at the end of the quarter. We're still a couple months away from the fall redetermination, but having shown strong production growth since the spring borrowing base review and with substantial hedge protection in place, we believe we're well-positioned heading into the fall redetermination process in October.

Bryan discussed the way our hedges insulate us in the event of oil price declines, and it's important to remember that the structure of our hedges allow us to retain the majority of the upside in the event of an oil price recovery. We've also been adding to our hedge position in 2017, which provides more visibility a couple of years out.

And with WTI Midland tracking closely with WTI Cushing lately, we've walked in from attractive bases hedges in 2016 to 2017 as well. Finally, I'd like to mention that in addition to our recent divestiture in Gaines County, we've engaged the same to begin marketing and package of high-quality-but-lower-priority assets in Martin and Dawson counties.

This sale would enhance our liquidity position and strengthen an already healthy balance sheet. With that operator, we'd like to take questions.

Good morning, guys, and good quarter.

Good morning, Brian.

Good morning.

Wanted to focus, really, on the rigs. Particularly in back half and rolling to the next year, you made some nice comments.

And your slide seven alludes to really our projections other than your estimation for next year, but do you think we're very far off? Any color would be appreciated, but I'm assuming given the discussion of the back half of the year and the insulation on EBITDA next year that a four-rig run rate for all of next year seems the most appropriate starting point.

Does that lend itself to that 30% growth on production or should we be thinking differently about that?

Yeah, Brian, it's Ryan. We're not prepared to talk about 2016 officially here.

We'll see what conditions look like. But if we were to keep rigs flat four rigs in 2016, we're now showing about a 35% to 40% growth year-over-year and that equates also to about 35% to 40% growth exit-to-exit.

And this is really without any further efficiency gains.

And at that new well costs, we're talking $6.5 million per well, a four rig program for next year implies what from a CapEx standpoint?

Yes. It's about $100 million per rig.

Per rig? Okay.

Is there any reason to think that there'd be meaningful changes to the infrastructure cost year-over-year?

No. Not known at this time.

Okay. And then my kind of follow-up track, if I may, the discussion of the Delaware Basin, in this pricing environment, regardless of how strong those wells have been, just seems a little bit ambitious.

What's the thought down there, just general thoughts on going at that during the second half of the year?

This is Matt. We have a long-term project going on out there.

We've taken a very marketed approach to developing it, gotten our own 3D seismic in-house and then methodically taken zonal tests across three vertical wells. So, one test well over a 30,000-acre position we don't think is getting out over the skis, especially after having in-house for this timeframe.

And then like you mentioned and we mentioned, the upward slope of the results that are coming our direction are very encouraging. So, we think, even on an exploratory basis, it's an economic prospect at these costs and then once you get in there, and drill a few wells you bring those costs down and it can potentially compete with the Midland Basin.

So, it's just a long project that you have to work. We don't think one well is too aggressive.

Hey. This is Bryan.

There's a lot of operators getting closer and closer to us and we like what we're seeing. And they're basically offsetting our acreage, we put that in the slide in the last quarterly release.

And also, I feel like we really don't get NAV from you guys on that and there's acreage trading in that area, north of $10,000 an acre. So, that's another reason why we're pushing forward.

Great. Appreciate the color, guys.

Thanks, Brian.

Thanks.

Good morning, guys. Say, Bryan, I'm just wanting your thoughts now with M&A.

After the recent success, not only with that, obviously, that attractive acquisition you all did, but then the follow-up just on acquisitions you've had now. Your thought on further acquisitions versus the organic growth that you and Matt have talked about in this environment?

You can see that this quarter, we were very focused on the drill bit. And I would like to continue trades with these larger companies are actually contacting us, I think, about a year ago in conferences and even our IPO.

I got that question. Can you get trades?

And I always said, no, because it just seemed like every time we contacted them, they just wouldn't move on it. Now, they're contacting us.

And it's a win-win situation. And we're in the middle of talking to two or three larger companies on trades.

And when we trade, we just get a value out of – we just get – it's basically like almost free locations in a way. And they do, too, when we swap these 160s.

So, we're going to continue on the land front focusing in that sort of area. On larger acquisitions, we've seen some data rooms opened from larger acquisitions.

We're interested. But I just don't see us doing anything with our inventory count right now.

I feel like we've got large inventory count to keep moving forward.

And when you're looking at things, are you looking both at Midland and the Southern Delaware or in both the Basins?

We're looking in both, but we have run brokers in the Southern Delaware, and it seems like it's all leased up.

Interesting. Okay.

And then just lastly, you guys have done a real good job, obviously, like some other peers of yours on bringing these costs down. I think the last question was talking more just on LOE.

Your thoughts on what you can put pressure on the services and some other costs going forward through the end of the year. Can we see that go down, in your opinion, if this kind of environment holds?

Bryan, can we see that go down another 10% or so?

I think that's a reasonable goal and I think we can push past that. For example, we have line of sight on the spot rigs, they're 40% off versus what were contracted today.

Our pipe roll-off, that's going to be a 30% on spot pricing versus the cost we had mentioned today. And so, we have line of sight on some mechanical things that we'll roll off.

And we've had real good back and forth with our vendor network. They really came to the plate and made some adjustments in the first quarter and second quarter.

That was key in getting us back to work a month early. And they got down to, probably, what we would think is a $60 price environment.

And now, they kind of need to reboot and make another leg down, and we're working on that, as we speak.

Okay. And then, just one last one, I noticed on the press release, it looked like you guys talked about that five-well Wolfcamp B came on with an IP of 189 Boe.

It's still excellent, but just a little bit lower than the first quarter. Was that more just had anything to do with more completions or geology?

Or any comment you can make around that?

Yeah. It was a reduced activity quarter, but actually, it was an increase of our average over the – of first quarter.

The 231 Boe a day was our North Upton area and we are highlighting the improvement of our completion intensity, which we continue to see that correlation hold true. But on the whole, it went from 184 Boe a day to 189 Boe a day.

So, still pretty consistent outpaced results here.

So, great details. Thanks, guys.

Good morning, guys.

Morning, Will.

I wonder if you guys could comment on the way the depth profile looks in the Southern Delaware where you guys are going to be testing that first horizontal. It does look it may be a little bit shallower than you guys are used to drilling over on the Midland side.

If that is the case, do you guys still see this as an over-pressured reservoir where you guys are and how would you guys potentially change the completions or drilling operations versus how you are drilling over on the Midland side?

Sure, Will. It's actually about the same depth.

On that map there, that's a subsurface map. And you add about 2,800-feet surface location before you get to sea level.

So, we're down around the 9,500 feet to 10,000 feet range on our Wolfcamp depth position. We do see overpressure on our three vertical wells, so we'd actually anticipate higher pressures than we would see on the Midland Basin side both on an absolute surface pressure and on a gradient basis.

So, we're pretty excited about the in-place capacity of the oil over there.

Got you. That's great color.

And then, you guys have kind of touched on LOE a couple times, I guess. It sounds like you guys will be in the range of that initial guidance at some point, just maybe a little bit later than you'd hoped.

Water hauling sounds like it's yielding some dividends here. Can you talk about any other projects that may help you get there and where do we see a run rate in to next year on LOE?

Yeah. The big driver there is disposal cost, which is our number one item and having that hit really – that drop going from 45% to the 29% hit really in the last week of the quarter.

We were anticipating that to be finished a month or so sooner, and that's really going to drive cost down especially with the larger fracs that we're putting on these wells. We want to limit the amount that we truck haul away.

So, that is really a nice tailwind for us. It just came about a month later than we were anticipating.

Other items are kind of across the board on working down equipment failures. We changed some of our coating systems on our pipe as it reduce – early indication, it's reducing just rope, soap and dope tubing failures that happen commonly.

And so, our failure trend is going down on that side and that's a direct reduction in our work over expense. So, going forward, as Ryan mentioned, these horizontals are extremely low on a per barrel basis in the $2 range.

So, as they become a larger component of our production as they will in 2016, we still feel pretty good about the originally stated LOE range that we had out there before updating it today, $6 to $7.

Got you. So, we wouldn't be out in left field to expect maybe even possibly exiting at a run rate on the lower end of that initial guidance range, kind of toward a $6 per barrel type number?

That's our goal.

All right. Great.

Thank you, guys.

Thanks a lot.

Hi. Good morning.

Morning.

Morning.

A couple quick modeling questions for me, you mentioned the oil cut, about 58% of output this quarter. Can you help us think through the commodity mix moving forward and how you forecast that trending over time?

And then one more if I may, just thinking about these Wolfcamp wells, when you look out 30 days, 180 days, want to see if we can get a good census to the cuts you're seeing there as well?

This is Ryan. I'll address your mix – your first mix question.

As I mentioned, we do see the next couple of months, oil getting up to 60% in some production, and 70% next year. And this is really just a result of us putting on more horizontal wells.

As you know, we've got 600 vertical wells that some of which are Atoka and a little bit gas here. But as we drill more the horizontal, you're going to see the oil cut increase.

Now, when you profile the well, you're just under 80% in year one on these Wolfcamp wells, and that will trend off, as the GOR increases, to around 75% in year two. And life of the well is probably somewhere around 70%.

Great. And just to confirm, that is oil only, that's not oil and NGLs?

Crude only.

Great. Thank you, guys.

Thanks.

Good morning, guys.

Morning.

Morning, Charles.

I wanted to ask a bit about the guide up on 2015. And Ryan, I think some of your comments touched on this.

But, I wonder if you could give us a sense how much the incremental 10 wells you're adding for 2015 with this bump up in guidance, how much of that actually contributes to the bump up in production guides on the year? Call it 1,200 Boe, 1,300 Boe a day on the midpoint?

Yeah. It's really not driven by these 10 incremental wells, just given that they're going to be back-weighted in the back part of this year.

It's really driven by the current well performance of the horizontals that we've put on and expect to put on in the next quarter.

Got it. Got it.

That's the color I was looking for. And then shifting over to the Delaware Basin, can you guys talk a bit about what a good result would look like over there and maybe alternatively, what a head scratcher result, something that would send you back to the drawing board, what that would look like?

I hate to put markers out there, but I could give a range. I mean, we want to see something comparable on productivity-wise to what the Midland Basin is averaging and that would be a starting point.

But I think the capacity has – what we're seeing with offset wells is that it should be higher on a production basis per foot. And that would be – if we see that on our first well out of the gate, it would be very encouraging and to work from there.

And if we see something less than the Midland Basin, that would be the head scratcher for us.

Got it. That's helpful detail, Matt.

Thanks.

Morning, guys.

Morning.

Most of my questions have been answered, but I have one question regarding the pad project. Have you guys seen how much of savings you could catch by going to a full pad development project in the future?

We see savings in line to what others mentioned maybe just slightly less on a per well basis until we actually get a few under our belt. That's anywhere from 150k.

We've seen as high as 500k of savings mentioned per well and we – depending on where we are, we see those savings on a spreadsheet model. So, we just want to make a transition as our production profile gets larger below us.

I would like a large stable production base below us, because we do have some impact or some lumpiness production as we transition to pads.

Okay. Appreciate the color.

Thanks.

Thanks a lot.

Hi, guys.

Hey.

Hi, John.

Just kind of a follow-up on some of the questions that Charles was asking. On the last quarter, you all had given a slide that sort of showed your quarterly CapEx breakout.

And I'm just trying to get kind of a sense of what the fourth quarter CapEx run rate would look like, given that these wells are going to fall, primarily in the fourth quarter?

Given that we're running four rigs from the drilling side, it's going to be pretty even. I think we do have a little bit more completions back weighted in Q4 than we do in Q3.

So, of the increase in guidance, I think you could split that a little bit more towards Q4 than Q3.

Okay. And then just my one follow-up, on the production for the second half of the year, last call you all mentioned sort of a 30% year-over-year growth in fourth quarter 2015 versus 2014 and since you just mentioned that most of these 10 incremental wells don't really have any impact on or not much of an impact on this year's production.

How would you sort of articulate fourth quarter now for 2015?

Fourth quarter for 2015?

Yeah.

As you recall, we ramped back up to four rigs in early June. So, completions are back-half-weighted.

This quarter, they're really starting. So, we really see Q4 production ramping up and bringing full-year 2015 production up, through the first half we're at 20.5 MBoe per day.

So, we've got some work to do to pull that up to our guidance.

I mean, I guess, just said differently, I think last call, you all had said if you did sort of a 30% year-over-year growth in fourth quarter 2015, it would get you to like around just under 24, so if I just take the production guidance that you up ticked it by and use a similar percentage, is that kind of a good way to think about it?

Yeah. I think that's a fair way to look at it, John.

Okay. Appreciate it, guys.

Thanks a lot.

Sure.

Sure.

Good morning, guys. Thanks for taking my questions.

Just...

Good morning.

...I know you guys have a great hedge portfolio next year. Just trying to understand how you all are thinking about outspending, should strip be correct?

Just trying to get a sense for your thoughts on managing the balance sheet next year.

Sure. We are outside of where we traditionally would have said our comfort levels are with leverage.

However, considering oil prices have been cut in half and we're just outside of our range, we're a little shy of three now. We're actually feeling pretty good about where we sit today.

Leverage is certainly and always will be a key consideration as we look forward. The hedges you mentioned, I think in one of our slides, we've got consensus 2016.

I mean we're 90% hedged. So, we feel good about where we are.

And then, also, this marketed acreage sale that I mentioned at the end should help the balance sheet as well.

Great. And then last one for me, I know you've got a low decline rate supported by all your vertical production.

Can you talk about the capital required to keep production flat from exit 2015 levels?

Sure. We've looked at that and basically, if we ran two rigs in 2016, we still see a modest growth exit-to-exit from 2015 to 2016.

One rig will let you grow year-over-year, but the exit would decline. So, it'd be something shy of two rigs.

Okay. That's helpful.

Thanks a lot.

Yes. Hi, good morning, guys.

Good results. Most of my questions have been answered.

But just on the Delaware Basin drilling, I'm just wondering if you like what you see with kind of the well this year? What kind of allocations should we maybe thinking about for next year?

We haven't come out with a 2016 allocation. But you got to measure it versus our 50% returns in the Midland Basin So, we're seeing 30% returns.

Maybe we drill a few wells. If we start to see something that challenges our 50% returns in the Midland Basin, you could see more activities in the Delaware Basin next year.

All right. Great.

That's all my questions. Thank you.

Thanks.

Good morning, guys. Thanks for taking my questions.

First question, on that pad drilling you guys plan to drill, what spacing assumptions are you guys using for the Wolfcamp B bench?

660 feet between wells.

Okay. Thanks.

And that Lower Spraberry, which county are you guys planning to drill that first well?

In North Upton.

All right. Thank you so much.

Sure.

Hey, guys. I couldn't get enough this morning.

I had to ask you another. I want to pick up on a hint or a thread you guys dropped in your presentation about the Wolfcamp A and get your thoughts on it.

I'm looking at slide four, when you guys say the Wolfcamp A is on track to match the B at month nine on a cumulative production. When I read that, I see a graph with a crossover in my mind where the Wolfcamp A is outperforming the B after nine months on a cumulative basis.

And there've been some other operators who have hinted and have had the results like you guys that the Wolfcamp, the A, is every bit as good as the B and perhaps in some spots, even better. I'm wondering how does that fit with your thinking and is that the right read to make on that bullet point?

I think it's very encouraging, like you mentioned and what we see is that they start off lower and they stay in longer, so when you roll it into an economic profile, they're matching each other quite nicely. Our Bs are still a couple of percentage points higher on an IRR basis even with that mapped decline in the As just on a present value basis.

But it's a tremendous resource there, all the logs and a sidewalk horizon – the original oil in place is higher in the A, so that's encouraging. And the original oil in place is very high in the Lower Spraberry as well.

So that's encouraging. You're just fighting the reduction in pressure and containment of fraction both of those, but they're showing very well.

So, it's all good news, we think, across our acreage footprint.

So Matt, it sounds like perhaps the right way to think about the Wolfcamp A for now, it's just analogous to the B or maybe just up a de minimus decrement from the B?

Yes.

Okay.

Yes.

Thanks, guys.

And that slight decline that's in there is really a – kind of as Ryan mentioned driving our production uplift in our guidance. And just wanted to re-clarify that we do see that our exit rate versus 2014 would be north of 30%.

Got it. Thanks.

Thanks, Charles.

I just want to thank everyone for joining the call, and we look forward to seeing you all in the fall conferences. Thanks again.