Parsley Energy (PE) Bryan Sheffield on Q2 2016 Results - Earnings Call Transcript

| About: Parsley Energy, (PE)

Parsley Energy, Inc. (NYSE:PE)

Q2 2016 Earnings Call

August 04, 2016 9:00 am ET

Executives

Brad C. Smith - VP-Corporate Strategy & Investor Relations

Bryan Sheffield - Chairman, President & Chief Executive Officer

Matthew Gallagher - Chief Operating Officer & Vice President

Ryan Dalton - Chief Financial Officer & Vice President

Analysts

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Drew E. Venker - Morgan Stanley & Co. LLC

Irene Oiyin Haas - Wunderlich Securities, Inc.

Jeff S. Grampp - Northland Securities, Inc.

Charles A. Meade - Johnson Rice & Co. LLC

Will O. Green - Stephens, Inc.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

John A. Freeman - Raymond James & Associates, Inc.

Kashy Harrison - Piper Jaffray & Co. (Broker)

Sam Burwell - Canaccord Genuity, Inc.

Gail Nicholson - KLR Group LLC

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Jeb Bachmann - Scotia Capital (NYSE:USA), Inc.

Eli Kantor - IBERIA Capital Partners LLC

Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc.

David R. Tameron - Wells Fargo Securities LLC

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Operator

Good morning, ladies and gentlemen. Welcome to Parsley Energy's Second Quarter 2016 Earnings Call. My name is Jesse, and I'll be your operator today. As a reminder, this call is being recorded. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation.

And now, I'm pleased to turn the call over to Mr. Brad Smith, Parsley Energy's Vice President of Corporate Strategy and Investor Relations.

Brad C. Smith - VP-Corporate Strategy & Investor Relations

Thank you, operator, and thanks to 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 website on the Investor Relations page.

As usual, our remarks contain forward-looking statements, so we refer you 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 the reconciliations in our 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.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thanks, Brad, and thanks for joining us this morning. I think it's safe to say that Parsley Energy is firing on all cylinders. Production increased 23% this quarter versus last quarter. And taking a broader look, we've grown production 16% per quarter since our IPO in early 2014; almost exclusively through the drill bit.

You'll notice on slide three that a recent production growth has come without adding rigs, which makes it even more impressive. We're raising full year production guidance for the second time this year. We previously increased guidance by 15 Boe to 100 Boe per day to account for acquisitions, including flow unit production and drilled wells to be completed. We're now increasing guidance by 4,000 Boe per day at the midpoint to a range of 36 Mboe to 38 Mboe per day, reflecting strong productivity and more wells.

We're now planning to complete 15 more gross horizontal wells this year, which is almost like adding a rig for full year and only increasing CapEx by $50 million or roughly half of what it would take to run a rig for a year.

As proud as we are of a top line growth, we're equally proud of our progress on the cost front. D&C costs per 7,000 foot well are now less than $5 million. And as you can see on slide four, we've reduced operating costs per Boe by 40% over the past year. We're lowering full year guidance on LOE per Boe and G&A per Boe by more than $1.50 combined.

Turning to slide five, recent transaction metrics certainly speaks of value of acreage position we've established. We feel fortunate to have added to this position in recent months at prices that look more compelling all the time. All told, over the past few months, we've added around 33,000 net acres for around $12,000 per acre after backing out PDP value. This includes significant leasehold in both the Midland Basin and Southern Delaware.

We also recently closed our acquisition of mineral interests in the Southern Delaware, which increases our production and cash flow torque by adding incremental barrels without incremental activity or costs. In fact, as we stay on slide six, if you compare the contribution of one rig running for a year on mineral acreage versus drilling on acreage without mineral rights, the rate running on mineral acreage contributes around 400,000 more Boe and roughly $16 million of extra cash flow in one year.

To give a sense of our tremendous growth potential, we framed a set of acceleration possibilities on slide seven. Obviously, given the declining nature of shale production, you can't grow rapidly if you can't increase the number of wells you bring online. As the chart suggests, we have sufficient inventory and operational capacity to add several rigs over the next couple of years.

At the lower end of the spectrum, if we were to add just one rig per year, we estimated that we could generate a compound annual production growth rate of approximately 30% over the next two years. If instead, we were to add three rigs per year, we'd likely generate something around 60% compound annual growth rate for 2018. The reality is likely to lie somewhere in between and will obviously depend on a number of factors, including the commodity price environment.

We're not going to commit to anything at this point. So if we had to handicap it today, the most likely scenario for 2017 would be to run six rigs, three in the Midland Basin and three in the Southern Delaware, with two of the rigs in the Southern Delaware drilling on our mineral acreage. However it plays out, we're very excited about the possibilities as our team continues to execute.

And now, I will turn it over to Matt for an update on the execution.

Matthew Gallagher - Chief Operating Officer & Vice President

Thanks, Bryan. We truly are firing on all cylinders with robust well results across our acreage position. Turning to slide eight, this is the first time we've put Midland and Delaware type curves together and I think it's instructive, for a 7,000 stimulated foot Delaware well we're showing an 880 MBoe type curve provided by our reserve auditors.

As you can see on the chart, while the EUR is lower than our 1 million Boe Midland Basin type curve, initial productivity is higher on the Delaware curve than on the Midland curve. The fact that our initial setting Delaware wells are outpacing this curve, helps explain why we're so excited about our Southern Delaware position and why we project very strong returns from our Southern Delaware wells.

Meanwhile, Midland Basin Wolfcamp well results continue to impress, especially as you extend through the first year of production. A great majority of our Midland activity is focused on what we call our core area. And, in fact, all of the wells be completed in Q2 in the Midland Basin were located in the core.

So we've broken out the performance of our core wells in particular. And as expected, they show higher cumulative production rates than when they're blended with Tier 1 results, which yield returns in their own right. As has been our custom, we've included all of our Wolfcamp wells in the dataset, so there's no selective sampling involved.

It's worth noting that roughly 80% of our Wolfcamp A and Wolfcamp B inventory in the Midland Basin is in our core area. And given the results we're seeing and Reagan County, we think that for the Wolfcamp the core extends farther east than we currently show on the map. In fact, we plan to redraw our map to reflect our latest petrophysical analysis and well results, so you can be on the lookout for that in the near future. There's a lot of information on this chart, but the takeaway on this slide is that we're completing really strong wells across our acreage footprint.

Turning to slide nine, we continue to push on development cost and are still seeing favorable drop down trends. As Bryan mentioned, Midland Basin D&C cost for a 7,000 foot well average less than $5 million in Q2; and we accomplished this despite an increase in our average completion intensity. In fact, a well on our Cormac lease set a company record for lowest Wolfcamp D&C cost at less than $550 per foot, which would be less than $4 million when normalized to 7,000 feet.

In addition, we're seeing very rapid rate of change in the Southern Delaware well cost, which have historically been the biggest drag on development economics on that side of the platform. Our first Southern Delaware well was burdened by a number of startup and one-time costs that are standard for the first well in a new area. We're already drilling faster in the Delaware, as you can see on the chart at the bottom; and our current costs are trending toward our Midland Basin well costs. We may not quite get all the way there because of greater depth and treating pressures in the Delaware, but we expect ongoing conversions.

In surface rights, on a good portion of our Southern Delaware acreage, we'll shave another couple hundred thousand dollars per well associated with the water sourcing and disposal; a key differentiator for us in the Delaware that will further narrow the gap between Delaware and Midland well cost.

Moving to slide 10, we've talked before about the cost savings associated with our transition to pad drilling and also our belief that completing multiple wells at the same time could boost productivity as well.

Recent results, especially in the Wolfcamp A target interval, suggest that this productivity uplift could be significant. Our Wolfcamp A wells completed on pad in conjunction with Wolfcamp B wells are showing higher 30-day IP rates than our stand-alone Wolfcamp A wells. And a couple of our Wolfcamp A well pads in Upton County set company records, not just for Wolfcamp A, but for the company as a whole.

The Wolfcamp A well on our Hirsch lease, for example, registered a 30-day IP rate of 284 Boe per 1,000 feet, while a Wolfcamp A well on our Atkins lease produced 130,000 Boe in 90 days. So while our Wolfcamp B wells have long set the pace in the Midland Basin, our Wolfcamp A wells are certainly in the same league and in some cases showing even higher productivity with a higher oil cut to boot.

Together, the outstanding productivity and cost performance we've discussed yields a truly compelling return profile across our Wolfcamp portfolio. You can see on the first chart on slide 11 that at standard 75% NRI projected Delaware returns aren't far from our world-class Midland Basin returns, with the shape of their respective type curves accounting for increased separation at higher oil prices.

Factoring in mineral interests in the Southern Delaware provides a huge boost to returns, catapulting these wells to the top of the return spectrum. It's a similar story on NPV. But with more cash invested and more cash generated, Southern Delaware wells show a higher NPV even before incorporating mineral interest.

Bottom line, at strip prices, you're looking at returns of 60% to 90% and NPV of $7 million to $12 million on our 1,500-plus Wolfcamp locations, which certainly justifies the type of production growth we've generated and are preparing for.

Turning to slide 12, we previously shared tremendous results on the first couple of wells on our Trees Ranch position in Pecos County; and these wells continue to perform well. We're also very encouraged by initial results on our more recently added acreage position in Reeves County. We recently completed a well drilled by the previous operator; and through the first 60 days, results are outpacing the Delaware type curve and on trend with the Trees Ranch wells. We actually flowed the Ranger well back pretty conservatively, as you can see. It really came on strong in month two.

We think the offset results we show at the bottom of the slide are more representative of the resource potential in the area than the wells that were previously completed by another operator on our acreage, which used a different completion design than we used; weren't necessarily in the same landing zone that we would target and had some facilities-based flowback constraints.

We've accumulated a deep inventory of high-return drilling locations; and on slide 13, we point to significant upside potential as we evaluate additional target intervals and tighter spacing scenarios. We continue to appraise our Southern Delaware position analyzing a whole core sample we took and triangulating with the seismic data and well logs. Our current best estimate of the inventory in the Delaware attributes locations to four discrete target intervals, two in the Wolfcamp and two in the Bone Spring. For now, we're counting eight wells per section in the Wolfcamp and four wells per section in the Bone Spring.

We have a lot of inventory upside in the Midland Basin. We currently count just 16 total Wolfcamp A and B locations per section in the Midland Basin. And over the next few quarters, we're going to test potential for up to 45 locations per section in the Wolfcamp A and B alone.

First, we're going to work vertically, evaluating the interaction between the Wolfcamp A and two Wolfcamp B target intervals. Then, we are going to test horizontal spacing, completing a set of eight upper and lower Wolfcamp B wells at 330 foot spacing. At 850 feet thick, our Wolfcamp A/B complex is the thickest you'll find in the deep portion of the basin. So we're optimistic about adding to our Wolfcamp inventory as these tests unfold. So we continue to have a lot to be proud of and a lot to look forward to when it comes to unlocking value of our asset base.

And now, I'll turn it over to Ryan to discuss our financial results.

Ryan Dalton - Chief Financial Officer & Vice President

Thanks, Matt. It was a very strong quarter from a financial perspective. Adjusted EBITDAX increased by almost 50% quarter-over-quarter, benefiting from higher volumes and realizations, as well as lower cost. We exited the quarter with ample liquidity, including a fully undrawn borrowing base of $525 million.

On slide 14, we reduced our cash balance to account for the closing of our mineral rights acquisition after the end of the quarter, resulting in a pro forma cash balance of $189 million and total liquidity of more than $700 million. Leverage is very favorable, with a net debt to annualized adjusted EBITDAX ratio of 1.7 times.

Slide 15 shows that we continue to have a substantial hedge position in place with the majority of our expected barrels hedged through the remainder of the year. Then, we're back into our more typical range of 40% to 70% of barrels hedged for the first half of next year; and we've been building our position in the second half of 2017. Our hedge position certainly dampens the impact of the recent pullback in oil prices on our bottom line. I'll also note that in light of strengthening natural gas prices, we recently added some costless three-ways that give us a bit more visibility on the revenue front.

We've made several changes to our full year guidance, as you can see on slide 16. Production guidance is up 4,000 barrels per day at the midpoint. As Bryan mentioned, we're planning to complete around 20% more wells this year, but only increasing CapEx by around 10% at the midpoint. CapEx this quarter came in at $136 million, up just $26 million versus Q1, despite the fact that we completed 10 more wells this quarter than last quarter, with longer lateral lengths as well. Bryan also mentioned the changes in unit costs. We're reducing guidance for LOE per BOE by more than $1 at the midpoint; and for cash G&A per BOE by $0.50 at the midpoint.

We think it's clear that maintaining our activity and momentum over the past few months when many operators slowed down has allowed us to capture a lot of value. We're realizing the benefit of increasing scale, spreading cost over a larger production base. All of the pieces are in place to continue these trends and we expect to continue delivering a compelling combination of growth and returns.

With that, operator, we'd like to take questions.

Question-and-Answer Session

Operator

Thank you. Our first question is coming from the line of Neal Dingmann with SunTrust. Please proceed with your question.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Good morning, guys. Say...

Bryan Sheffield - Chairman, President & Chief Executive Officer

Good morning.

Matthew Gallagher - Chief Operating Officer & Vice President

Good morning, Neal.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Bryan, could you talk about how you try to complete the Delaware any different than your Midland Basin wells?

Bryan Sheffield - Chairman, President & Chief Executive Officer

I think in the beginning we just applied our Midland Basin completions very similar and probably more sand per foot, closer to 1,800, 1,900 pounds per foot more than at the time 1,600 pound to 1,700 pound per foot in Midland, but that's the only difference. And we're using full slick water frac, hardly any gel. So very similar to Midland Basin, but I do see us increasing the same content in the Delaware.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

All right. Thanks you all. Nice update.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Operator

Thank you. Our next question is coming from the line of Drew Venker with Morgan Stanley. Please proceed with your question.

Drew E. Venker - Morgan Stanley & Co. LLC

Good morning, everyone.

Matthew Gallagher - Chief Operating Officer & Vice President

Good morning, Drew.

Drew E. Venker - Morgan Stanley & Co. LLC

I was hoping you could provide some more color on the development scenario as you laid out through 2018 in your slide deck. What kind of commodity prices would each of those matchup with and any other subject you could detail, like well costs or well performance assumptions?

Bryan Sheffield - Chairman, President & Chief Executive Officer

I think if I kind of look at the slide – and this is derived of probably the last week's strip and I think it's fair to think every $10 – we've said before in other quarters – every $10 we would add a rig. So that would be on top of our mentioning looking into 2017 with six rigs. So if we start seeing the oil price rally, you could potentially see an additional rig every $10 increments.

On the service cost, we all know that service cost will eventually bump upward and hopefully it's in line with an oil price rally. But at times it's not, so we have to prepare for that. So that could be a drag on my earlier comment.

Drew E. Venker - Morgan Stanley & Co. LLC

Okay. And just to follow-up on Neal's question on the Delaware Basin completion design. As you ramp-up next year, do you expect just a slow increase in your proppant loadings or can you just talk about how you plan to test different completion designs next year?

Matthew Gallagher - Chief Operating Officer & Vice President

No. We're legging up quite a bit. Recent designs are going to be 2,500 plus pounds per foot. And then we have a multitude of specific tests down the spectrum of line items on that side, but we want to start with the baseline with our Midland Basin completion technique. On the Midland, we continue to incrementally push. But the Delaware with the offset results and the vintaging (18:35) of where they're at over there, we're kind of legging up in a larger step fashion.

Drew E. Venker - Morgan Stanley & Co. LLC

And, Matt, to follow-up on that. Have you seen a strong relationship between much higher proppant loadings and much better well performance in the Delaware Basin?

Matthew Gallagher - Chief Operating Officer & Vice President

We have. When you vintage it over time on the broad basin analysis that we look at, you do get a positive correlation to increase the rates and then project it out to EURs with more sand loading. But there're a lot of different variables that go into it, but that's one with the higher correlation.

Drew E. Venker - Morgan Stanley & Co. LLC

Okay. Thanks for the detail.

Operator

Thank you. Our next question is coming from the line of Irene Haas with Wunderlich. Please proceed with your question.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Yeah. Hi. One more question on the Delaware Basin well. What was the cluster spacing for the Ranger well? And also in terms of landing zones, how does this well differ from nearby wells?

Matthew Gallagher - Chief Operating Officer & Vice President

So the stage spacing is one of those variables that will definitely be pushed on. We're still at the 160 foot, 170 foot stage spacing with our initial wells out of the gate over there. And then we have identified four to six discrete targets to land in depending on the area; and this most recent well was landed in – well would be kind of equivalent – we're still zeroing in on a naming convention – but to the upper portion of the Wolfcamp and it was held flat there. Don't know if it was actively geo steered before we took it over. So that will be implementing our geo steering practices going forward; and we look forward to that in our individual landing zones going forward.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Great. So we should expect better results with time, as always?

Matthew Gallagher - Chief Operating Officer & Vice President

That's always our drive.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Great. Thanks.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Operator

Thank you. The next question is coming from the line of Jeff Grampp with Northland Capital Markets. Please proceed with your question.

Jeff S. Grampp - Northland Securities, Inc.

Good morning, guys. Great quarter.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Jeff S. Grampp - Northland Securities, Inc.

Wanted to touch back on the outlook into 2018 that you guys put in the slide deck and maybe just to ask a little more specifically to the prior question. On kind of type curve assumptions or well productivity, should we think about that model basically baking in kind of that 1 million barrel Midland Basin and 880 barrel in Southern Del or are you guys baking in given the fact that it looks like results are tracking ahead of expectations there?

Bryan Sheffield - Chairman, President & Chief Executive Officer

I think if you want to model it, I would stick to those type curves as we zero down these sections. It's a safer bet. Don't increase. We're still in tracking this year because you never know what's going to happen in two years.

Jeff S. Grampp - Northland Securities, Inc.

Okay, perfect. And then back on the Delaware side, Matt, I know you guys highlighted some similar positive productivity improvements from doing zipper fracs on the Midland side. And is that something you guys see as a potential down the road to start testing and getting some uplift on similarly on the Delaware side? And if so, can you guys just talk about any potential timing for when something like that makes sense to start to test out there?

Matthew Gallagher - Chief Operating Officer & Vice President

You hit the nail on the head. It took us two years to methodically work through our processes in the horizontal gain on the Midland side; and I think it took us two months on the Delaware side. So we just completed our first Zipper frac of two well pad last night and are essentially moving forward in pad development mode in the future on the Delaware.

Jeff S. Grampp - Northland Securities, Inc.

Perfect. Good to hear. And then, if I can just sneak one more in. You guys kind of touched on the average lateral length of your Midland wells this past quarter. Can you guys just kind of remind me what the average lateral length is assumed for your core inventory if you guys have that offhand more or less?

Bryan Sheffield - Chairman, President & Chief Executive Officer

Probably around 6,500 feet.

Jeff S. Grampp - Northland Securities, Inc.

Okay. Perfect. Thanks, guys.

Operator

Thank you. The next question is coming from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Charles A. Meade - Johnson Rice & Co. LLC

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

Bryan Sheffield - Chairman, President & Chief Executive Officer

Good morning.

Charles A. Meade - Johnson Rice & Co. LLC

If I could get you to go back to that slide seven that you put in your slide deck, which I thought was a really interesting slide. It's really helpful about laying out what the future could look like for you guys. Can you talk a bit more about – I mean the way the slide is set up, this talks about maybe adding rigs in 2017. I know you guys are at four rigs right now. Can you talk about your current thinking is for the back half of 2016, when you might add rigs or what you're thinking of maybe Q4? And more particularly talk about what's your timeline for making that decision and what the variables would be outside? I mean you mentioned the oil price and that's an obvious one, but are there are others and what's your timeline for thinking about that?

Bryan Sheffield - Chairman, President & Chief Executive Officer

Yeah. So in the call – the script, just now we talked about that a little bit about potentially adding two rigs in 2017. And also these four rigs that we have running, I remember they're accelerating right now. We just added 15 more wells. We could accelerate even more. So I think it's best to just kind of stick with the plan. We were more aggressive in beginning of the year with this aggressive rig program and CapEx program. And so, the high is adding the two rigs going into 2017. Now that doesn't mean third quarter or fourth quarter. We're just going to continue going with this four rigs. Does that help with your timeline?

Charles A. Meade - Johnson Rice & Co. LLC

Yeah. That does, Bryan. And to clarify, you talked about adding a rig for every $10. That's on top of the base of $50 oil?

Bryan Sheffield - Chairman, President & Chief Executive Officer

I think that's fair thinking there.

Charles A. Meade - Johnson Rice & Co. LLC

Okay.

Bryan Sheffield - Chairman, President & Chief Executive Officer

We're talking of $0.01. But if oil moves up $10, we could potentially add another rig sometime in the following year.

Charles A. Meade - Johnson Rice & Co. LLC

That's good. Thank you, Bryan. And then, if I could ask a question about those up and coming Wolfcamp A wells? Obviously that's a great result to see from those wells and I'm curious, though, to what extent did you anticipate a result like this or did this 18% uplift surprise you? How many kind of data points do you totally have across this Wolfcamp A to be confident that this is up – or how confident are you, at what point would you become more confident that this is something that you can put in your plans going forward?

Matthew Gallagher - Chief Operating Officer & Vice President

Yeah, Charles. We converted to pad drilling in essentially this time last year, September of last year, bit in the ground. And at that time, we were actually conservatively forecasting slight degradation in the stack scenario. So this was a slight surprise. There are some conceptual modeling that forecasted it could be the case, but we wanted to see it into the tanks. We now just have under 10 wells that have shown these types of results. So we're building our dataset. We like to have a little bit more than that, but we're trying to share the results of how we see to-date; and it's definitely encouraging to-date.

Charles A. Meade - Johnson Rice & Co. LLC

That's helpful, Matt. Thank you.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thanks, Charles.

Operator

Thank you. Our next question is coming from the line of Will Green with Stephens. Please proceed with your question.

Will O. Green - Stephens, Inc.

Good morning, guys.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Good morning.

Will O. Green - Stephens, Inc.

Great detail on what the mineral acquisition does for the NPVs out in the Delaware. So I guess the question I would have now is, is when you guys are adding rigs and looking at the 2017 budget and even looking out to, say, 2018, should we think about the Delaware getting an increased portion of the CapEx or how are you guys thinking about CapEx allocation? Would we be in a scenario where you guys are moving rigs from the Midland to the Delaware or just simply every rig addition goes out to the Delaware? How are you guys thinking about that? Is there anything that prevents you guys from capitalizing on that great advantage you guys have out there?

Bryan Sheffield - Chairman, President & Chief Executive Officer

Yeah. In the script, we mentioned potential three and three in Midland Basin and Delaware; and two of the three in the Delaware on the mineral acreage. If you ask me today, I would think more rigs adding the percentage would increase in the Midland Basin because we have a larger footprint; and more operations is more intact and more fracked, the midstreams in place and the frac pits are in place. So you'd think you'd add more rigs in the Midland Basin, but the percentage of CapEx maybe it goes to 60-40. 60 Midland, 40 – through time maybe a little bit higher and that just comes down to footprint.

Will O. Green - Stephens, Inc.

Okay. Thanks for that. And then I wanted to talk about the potential horizons down there in the Southern Delaware. You guys gave some color on that in the prepared remarks as well. We hear a lot about geologic complexity being greater in the Delaware, certain Bone Springs areas seeing water saturated. When you guys targeted this position, how much mapping did you do? How confident are you guys that Bone Springs gets developed independently? And is there a reason that the First Bone Springs isn't included within those targeted horizons?

Matthew Gallagher - Chief Operating Officer & Vice President

I think it's key to note that we mapped and have been gaining data here since 2013. That's when we entered the position. And then we've been methodically taking all the right steps, full seismic proprietary shoot across our Pecos County position and then market seismic across the Reeves County position, whole core throughout the Wolfcamp interval.

So the only reason the shallower zones, the Avalon, the Bone Spring, First Bone – of course, it is sourced from the north, so we think it'd be different in our area, but there is still significant oil in place in those zones in our area. But we haven't done that type of work yet. We started with our primary target in the Wolfcamps. And, over time, over the next year or so, we'll be grabbing additional core and triangulating it with our well logs and our sidewall cores and doing the work in a methodical fashion.

So it is candidly more geologically complex. We've been building the team out since 2012, the entry position, and we think we have a good understanding; and we think there is a lot of upside out there and excited about the entire column.

Will O. Green - Stephens, Inc.

Great. So nothing precludes you guys from ultimately maybe developing 1st Bone Spring, maybe even Brushy Canyon or Wolfcamp C even at some point. So it sounds like there's still some even additional inventory upside from what you guys are talking about?

Matthew Gallagher - Chief Operating Officer & Vice President

Precisely, there is a lot of shallow shows from older vintage wells all across our footprint, but we do know to-date, very similar to the Midland Basin, but we have significant overpressure in the Wolfcamp even creeping up into the 3rd Bone. And we probably lose a little bit of that in the 1st Bone and shallower, but you can still have very economic wells without overpressure as evidenced in the Midland Basin and in the Lower Spraberry.

Will O. Green - Stephens, Inc.

Right. Well, I appreciate all the color, guys.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Operator

Thank you. Our next question is coming from the line of Michael Hall with Heikkinen Energy Advisors. Please proceed with your question.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

Thanks. Congrats on a good update. I guess just keeping on that question around the inventory picture in the Southern Del, what sort of timeline would you say you have to test the intervals you've got in that slide; I think it was slide 13?

Ryan Dalton - Chief Financial Officer & Vice President

Well, we're returns focused, so out of the gate we're seeing tremendously strong returns and then on our minerals. So I think we always take about a six-month approach of recouping our investment costs and returning cash to investors – well, to our portfolio and then methodically testing the column there, but we want to get the core sampling done and then triangulate that to physical well testing. So it will be a 12-month to 18-month process. There's a lot of column here, but we're definitely going to target the two discrete Wolfcamp flow units early in 2017.

Bryan Sheffield - Chairman, President & Chief Executive Officer

I think it's important to point out, in the past when we de-risk zones, we try to – we lean towards around 3%to 5% of our CapEx. So we're really focused on this growth and this operation momentum and on the 1,500 Wolfcamp locations that we feel like are lower risk and higher returns.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

Okay. Yeah. Plenty to lean on. That's helpful color though. And then I guess my only follow-up would be – I only get one, the operating cost – I mean, it came in very nicely in the quarter, obviously with guidance down (32:09) as well. But trying to get our head around how sustainable these cost improvements we're seeing across the space are and just how sustainable the whole cost structure shift is about to be. So particularly on the operating cost side, just curious how sticky or sustainable do you believe these improvements could be as we think through that 2017, 2018 timeframe and kind of reacceleration from the industry?

Matthew Gallagher - Chief Operating Officer & Vice President

First, I want to note, I mean it's truly a testament to the energy, excitement, innovation of our employees; a product of wholesale processes they put in place a year ago and we're seeing the fruit of that improvement. So to that extent, the process improvement, these are things tying into our own SWD infrastructure and wholesale mine shifts that are sticky, that are going forward for us.

So no doubt, if there is a aggressive recovery in the oil price or activity levels, you will see pressure on different line items, but we have a structural advantage now with our footprint in the Midland and the things that we're putting in place in the Delaware that we think will be able to mitigate and hedge against some of that recovery. So we are preparing for that kind of creep. But I think historically you look on the operating cost range, it lagged a little bit, the oil price run, but it does come, on the order of 10% or so, in that manner. But we had a 26% reduction even from last year on D&C and over 50% reduction on LOE; and that's just an amazing testament to the teams.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

Yeah. That's great, and I appreciate that. Matt, I'm sorry, the 10%, what was that in reference to? Like in terms of potential inflation I guess, is that what you're referring to, or 10% of the cost would be exposed to?

Matthew Gallagher - Chief Operating Officer & Vice President

I think about 50% of our cost – of our line item would be exposed to unit cost appreciation; and then I think that boils down to in a moderate recovery about 10% creep from whenever we hit our base. We are – wells that we're just putting down right now are still cheaper than wells that we put down in the second quarter. So we are not at the bottom yet, but we are seeing fringe line items with cost pressures when these guys are below their cash costs. So we're trying to work with them to keep them around. So the order of magnitude into the cost reductions are slowing; and then that 10% was in reference to the 50% of line items that we think are exposed to unit cost appreciation.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

Okay. That's super helpful. Appreciate it and congrats again.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Operator

Thank you. The next question is coming from the line of John Freeman with Raymond James. Please proceed with your question.

John A. Freeman - Raymond James & Associates, Inc.

Good morning, guys.

Matthew Gallagher - Chief Operating Officer & Vice President

Hey, John. Good morning.

John A. Freeman - Raymond James & Associates, Inc.

When I look at slide 13 and the plan for 2017 of doing the upper and lower Wolfcamp B stack and downspace test, how should I think about that approach and how you kind of juggle that with obviously the big uplift you show on slide 10 when you complete the Wolfcamp A and Wolfcamp B in tandem?

Matthew Gallagher - Chief Operating Officer & Vice President

It is important that we're not expecting that kind of uplift within the Upper B and Lower B. We still have significant height to work with. But as we've started modeling on our Upper A – or I mean our A and B test, we expect individual well results to be slightly off from a stand-alone well in our forecast, which is kind of baked into those sensitivities going forward. We hope to be surprised to the upside, but it's just reasonable prudent to expect individual well reductions. But we're looking for the whole system, maximizing MPV per section. So you get into a much more efficient surface development situation when you go to this type of spacing and then of course capturing additional resource through that discrete bench in the Upper B.

John A. Freeman - Raymond James & Associates, Inc.

Okay. And then if I shift over to Delaware, Bryan, you've always been really candid on what you're seeing in sort of the A&D arena. And obviously when we look at the acreage price as you picked up acreage on the Delaware and the Spring. And then as recently as the last quarter's call you sort of said in the Delaware you were seeing acreage prices like $10,000 to $15,000 acres; and obviously last month, we've basically seen like a double.

And I'm just curious from your perspective, like what you think drove such a huge increase just all of a sudden? Is there anything you can point to in terms of confidence of additional zones, costs or anything like that?

Bryan Sheffield - Chairman, President & Chief Executive Officer

John, I'm still a little bit in shock what I've seen in the past couple months. I mean we just paid – last April came out – and you look at April, we paid around $9,000 an acre, and I know some of these sellers, recent transaction sellers paid about equivalent. About six months ago or nine months ago if you look at like the (37:29) and research you can kind of put together what the transaction is six months later. So it's truly amazing. We've gone for $9,000 acre print to the $25,000 acre print and now a $35,000 an acre print. I think we're in the world of $20,000 to $25,000 in the Delaware. I really think that that's the reality. Anything north of $30,000 I think that's kind of – I just don't – we can't get to it on the map in the return on acquisitions.

John A. Freeman - Raymond James & Associates, Inc.

That's really helpful. Congrats again on a nice quarter.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Operator

Thank you. Our next question is coming from the line of Kashy Harrison with Piper Jaffray. Please proceed with your question.

Kashy Harrison - Piper Jaffray & Co. (Broker)

Good morning, and thanks for taking my question.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Good morning.

Kashy Harrison - Piper Jaffray & Co. (Broker)

Given the increase in the mineral inventory in the Delaware Basin with the potential to take that even higher over time, how are you guys thinking about extracting the most value for those assets? Specifically, do you think that spinning a yield vehicle over time would you give the most value or do you like the idea of keeping the minerals within Parsley as is?

Bryan Sheffield - Chairman, President & Chief Executive Officer

I think it's kind of early. I think it's very early to even really wrap mines around that. I do kind of fear the investment bankers will start coming in about a year saying we should spin it off or do a similar venom. And we need to be open-minded. We've got to look at it and we've got to access. And if it's the way to access capital and increase our rig count, we need to look into it. But right now I think we'll remind you we're well underneath 1,000 barrels on the minimal acreage. And so, we really need to get up to 7,000 to 10,000 barrels to really even think about anything like that.

Kashy Harrison - Piper Jaffray & Co. (Broker)

Thanks for that. That's excellent color. And apology if this was mentioned earlier, but you guys are making excellent progress driving drilling and completion costs lower in the Midland. Do you have any thoughts on where those could be by the end of the year?

Matthew Gallagher - Chief Operating Officer & Vice President

Well, we mentioned a well that we've got under our belt, sub-$4 million, 7,000 foot. That was a good well. Everything went right and had great cycle times on it. But that does appear to be repeatable and we're continuing to make EHA and improvements throughout the process. But on an average, I'd expect a slight downtrend from our $4.8 million average that we just printed on our core wells. And remember, every well we drilled was in the core, which is our deeper, higher pressure area and historically higher drilling costs. So it's really a larger cost savings than just the math would show. So at least in the third quarter and continue to slightly turn down.

Kashy Harrison - Piper Jaffray & Co. (Broker)

Okay. And then just the last one for me, on page 13, those downspacing tests that you've planned in the Midland Basin next year, what part of the year – what's the timing of those in 2017?

Matthew Gallagher - Chief Operating Officer & Vice President

It takes a long time to bring these things online, and then we're going to be doing a lot of data gathering as well. So realistically it would probably be the back half of the year before we'd see results there.

Kashy Harrison - Piper Jaffray & Co. (Broker)

Okay. All right. Well, thanks and that's it from me; and phenomenal quarter guys.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Appreciate it.

Operator

Thank you. The next question is coming from the line of Sam Burwell with Canaccord. Please proceed with your question.

Sam Burwell - Canaccord Genuity, Inc.

Good morning, guys.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Good morning.

Sam Burwell - Canaccord Genuity, Inc.

I want to dig in a little bit more on the efficiency gains that obviously drove the outperformance in Q2 and then the guidance raise in the back half. Is there like a go-forward assumption that we should use for the amount of wells per rig per year in the Midland. Has that changed dramatically?

Matthew Gallagher - Chief Operating Officer & Vice President

It has. We're down around 20, 21 days full cycle on average per well. And then I think this time last year we were up 28 to 30 and our wells are getting longer, so that's key there. And then we expect that to continue to grind down as well.

And then on the Delaware side, tremendous rate of change over there. Teams have done great. Our fourth well that we just TD-ed, it's not on the chart, was quicker cycle time than the first three wells. So progressive improvement over there. We hope to compress that to the Midland Basin cycle times and we're well on our way. So we're in the 24-day to 25-day range over there in the Delaware.

Sam Burwell - Canaccord Genuity, Inc.

Okay, great. And then if I could take sort of the flip side of the question that's been asked a few times. Bryan, if I heard you correctly, it seems like you said $50 is sort of what underpins the six-rig plan for 2017. If we are looking at WTI in the low-$40s at this time six months from now, let's say, does that change that plan materially? Would you take it down? And if you did, would that change the sort of 50-50 split between the rigs in the Delaware versus the Midland?

Bryan Sheffield - Chairman, President & Chief Executive Officer

Well, I mentioned every $10 we would probably give it a hard look adding a rig on top of the scenario that you're seeing. But I also mentioned that we need to remember about service cost and service cost increase, so that could be a tailwind on that thinking. But we're really focused on adding the two rigs in 2017.

Now and the last part of your question was on allocation, right? Allocation of capital, yeah. It's just we have a larger footprint in the Midland Basin. So I just imagine us – if you want to add rigs and modeling that would first add an extra rig in the Midland Basin. And then moving forward, I would think 60% to 70% of our capital would still be in the Midland Basin mainly because of footprint, but I still feel like the returns are superior than the Delaware.

Sam Burwell - Canaccord Genuity, Inc.

Okay. That's all fair. What I was really trying to get at though is there a price where you would decelerate from the six-rig plan?

Bryan Sheffield - Chairman, President & Chief Executive Officer

Yeah. We're hedged pretty good, 100% hedged for the rest of the year 2016. I think first half 2017 we got 60% hedged. So we are in the position of strength on our hedge book. And if we start seeing low-$30s on oil, I'm going to anticipate there is going to be some more pressure on the cost. But you might see us dial back to additional rigs in 2017.

Sam Burwell - Canaccord Genuity, Inc.

Okay. Well, that's the answer I wanted to hear. Thanks, guys.

Bryan Sheffield - Chairman, President & Chief Executive Officer

All right. Thank you.

Operator

Thank you. Our next question is coming from the line of Gail Nicholson with KLR Group. Please proceed with your question.

Gail Nicholson - KLR Group LLC

Good morning, everyone. Bryan, you mentioned that you could have accelerated more in 2016 if you wanted to. Was that on the current forward program or was that under the assumption that you've added a rig?

Bryan Sheffield - Chairman, President & Chief Executive Officer

No. I think that was on the previous question – that was just on acceleration of the four rigs and adding will count on the four rigs. We do not plan on adding a rig this year.

Gail Nicholson - KLR Group LLC

So on that four rigs and if you wanted to do more completions than the already uptick of the 15, like how many could you actually do if you're completely maxed out?

Matthew Gallagher - Chief Operating Officer & Vice President

I think it's just a function of cycle time improvement. So what we are mentioning is that that 15 rig count is at our current cycle times today. But over the last 12 months, month-by-month, quarter-by-quarter we've seen efficiency gains on cycle times. So we hope with that same four rig count to deliver more than the 2015 as we continue to improve cycle times.

Gail Nicholson - KLR Group LLC

Okay, great. And then looking at the Trees Ranch well versus the Ranger, was there any difference in the compositional mix that you've seen over the 30-day, 60-day timeframe on oil?

Matthew Gallagher - Chief Operating Officer & Vice President

Yeah. As we go west on our position, we're going to be slightly less oily. We are probably the highest in the basin on our oil content on the Trees position. You're 90% crude on a two-stream basis. As we get over to the western position, it's – the very western edge would be 70%, 75% on crude. So still very high oil content.

Gail Nicholson - KLR Group LLC

Okay, great. And then just one last one. Looking at the potential rig acceleration on the one rig, to two rig, the three rig per year in the 2016 to 2017, 2018 timeframe, do you need to add more personnel to accelerate that rig count or do you have enough personal currently on staff to handle those three scenarios?

Matthew Gallagher - Chief Operating Officer & Vice President

I think it's a scalable model. And we have a system in place where methodically as your well count grows, you're going to need key personnel in the field that can only handle 40 or 50 wells per person. So it grows scalably, but the core structure is in place. And it would definitely not increase the G&A per barrel. Nothing structural would need to be changed. It would just be scalable adds.

Gail Nicholson - KLR Group LLC

Okay, great. Thank you so much.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Operator

Thank you. Our next question is coming from the line of Dan Guffey with Stifel. Please proceed with your question.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Good morning, guys. Just piling on to a previous question. I guess, what type curves are being used to drive your production guidance in second half 2016 and sensitivity through 2018? And then, obviously, with the clear outperformance across all of your acreage, at what point might you raise your average type curve and/or EUR?

Matthew Gallagher - Chief Operating Officer & Vice President

Well, we have probably around 24 discrete curves by area. So to try to blend it down to an average is a little tough, but we're still in that – essentially using that average that we're forecasting on our slide deck on slide eight in both basins. And the reason being, as Bryan mentioned, and we are doing additional downspace testing. When you blend it altogether, there is still the unknown on those spacings. So we think it's sufficient to use that curve for the long-term on a broader modeling sense, but we do have discrete curves by area internally.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Okay. That's helpful. And then can you provide a cost difference for the central Upton, Reagan to northern Upton wells because of the depth and pressure differences?

Matthew Gallagher - Chief Operating Officer & Vice President

A year ago, it was around $500,000. We're probably in the $100,000 to $200,000 absolute range for a 7,000 foot well.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Okay, great. And then just last from me, any near-term plans to test the Lower Spraberry?

Matthew Gallagher - Chief Operating Officer & Vice President

Yes. We have a well flowing back right now, doesn't have its 30-day rate, because it's still cleaning up. But very good rates right now; extremely encouraged by it and look forward to updating everybody with that result when it gets a 30-day peak.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

So looking into 2017, will that be an active part of your program?

Matthew Gallagher - Chief Operating Officer & Vice President

It appears to be returning competitive out of the gate, because as you go to the shallower intervals your D&C costs come down even further. So it would be a component of CapEx, but probably a pretty small component, just trading one equivalent return for another. So it would be a small component, yes.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Great. Thanks for all the color today guys, and congrats.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Matthew Gallagher - Chief Operating Officer & Vice President

Thanks.

Operator

Thank you. The next question is coming from the line of Jeb Bachmann with Scotia Howard Weil. Please proceed with your question.

Jeb Bachmann - Scotia Capital (USA), Inc.

Good morning, guys. Just a couple of quick ones from me. First, where are the early 2,500 pound propane tests going to be located on the Midland side?

Matthew Gallagher - Chief Operating Officer & Vice President

That's going to be in northwest Reagan; and again that is flowing back, hasn't hit its 30-day peak either, still cleaning up. We did also do quite a bit larger water volumes as well. Also, encouraging results, so that will probably come hand-in-hand with our Lower Spraberry results.

Jeb Bachmann - Scotia Capital (USA), Inc.

And I guess just to clarify, you guys have a Wolfcamp C test later this year, is that right?

Matthew Gallagher - Chief Operating Officer & Vice President

Spudding, yes.

Jeb Bachmann - Scotia Capital (USA), Inc.

What county is that in?

Matthew Gallagher - Chief Operating Officer & Vice President

Should be in Reagan County.

Jeb Bachmann - Scotia Capital (USA), Inc.

Great. Appreciate it, guys.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thanks a lot.

Operator

Thank you. The next question is coming from the line of Eli Kantor with IBERIA Capital. Please proceed with your question.

Eli Kantor - IBERIA Capital Partners LLC

Good morning everybody.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Good morning.

Eli Kantor - IBERIA Capital Partners LLC

Just wanted to follow up on the A&D conversation. Can you kind of touch on the similar acreage valuation thoughts with regards to the Midland Basin, that's what you mentioned in the Delaware.

Bryan Sheffield - Chairman, President & Chief Executive Officer

There is an outlier out there and it made everyone perk up a little bit. I think certain companies need to – if they want to get into the basin, you've got to break in to be an outlier. That one asset is a very nice asset in southern Martin County, nice, blocky, all benches. But it's hard to gauge right now since there hasn't been another Midland transaction with that outlier price. So I really couldn't tell you. My guess would be $25,000 to $35,000, since there's an outlier pulling the range up, but we just haven't seen anything yet.

Eli Kantor - IBERIA Capital Partners LLC

And at what price point do you start to struggle internally with making the wellhead economics work?

Matthew Gallagher - Chief Operating Officer & Vice President

I think it comes down to what kind of rig program you can throw at any acquisition. With both basins with the type of productivity and the well costs multiple operators are seeing right now, it comes down to adding tail inventory or adding – where you're adding it in your inventory cycle. But any acquisition on a stand-alone, if you put enough activity at it, you can pull that value forward. So what you are seeing now are different people coming at different acquisitions, at different cycles and their company and their inventory and how aggressive they can be with their activity once they make the acquisition.

Eli Kantor - IBERIA Capital Partners LLC

And in terms of the number of packages and the size of the packages available for sale, can you just give a sense of what the opportunity set looks like, comparing Midland Basin versus the Delaware?

Bryan Sheffield - Chairman, President & Chief Executive Officer

Midland is a lot tighter because we've seen a number of acquisitions in the past three, four years. It seems like we are all bumping into each other a little bit. So I really haven't seen any packages in the Midland Basin, so it's more homegrown leasing and pooling and trades. There might be a few more left that just pop out of nowhere, some of those old operators from – family operators out of Midland, Texas.

Now in the Delaware, there is a lot of private equity with companies that have a lot of acreage all around us, all over Southern Basin. I'm hearing there is potential IPOs still even though one of them got taken out. So you're going to see more activity probably on the A&D side in the Delaware because of the strength of the private equity acreage.

Eli Kantor - IBERIA Capital Partners LLC

Makes sense. Last one from me just on the well cost front. And you guys continue to sort of drive down your overall AFEs, very impressive. I'm curious as to what the duration in prices of your current surface contracts are. What you're expecting for these two rigs that are scheduled to come online for next year and if you have any appetite or interest in locking in other components, whether its rigs or frac crews for an extended period of time?

Matthew Gallagher - Chief Operating Officer & Vice President

We only have two of our rigs contracted at long-term rates; those were carryovers from the previous high cost era, the rest are at spot rates. And we see the market anywhere from 14,000 to 16,000 a day depending on what type of bells and whistles people are adding on to the rigs.

And then, we'd be open to extending contracts on the new pricing regime given our base level of activity even in a reduced commodity price environment. So we would look at term out, the rig side. We have not, as a management team, been in favor of anything termed out on the frac side; just very tough to incentivize and get alignment there historically as an industry, and motivation seems to lag. So we will probably continue using four to five vendors at any one point and competitively working the process on that side.

Eli Kantor - IBERIA Capital Partners LLC

Makes sense. Thanks very much.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Operator

Thank you. The next question is coming from the line of Jason Smith with Merrill Lynch. Please proceed with your question.

Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc.

Hey. Good morning, everyone, and congrats. I know we've covered a lot of ground, so just a quick one from me. I appreciate all the color on slide 22 on the infrastructure in the Southern Delaware. Can you maybe just help us frame what your potential infrastructure spend looks like if you ramp to three rigs? And especially on things like water supply and disposal? And I guess combined with that, I mean is there a need for further a build-out in the near-term if industry does add rigs as aggressively as it seems they're beginning to in the play?

Matthew Gallagher - Chief Operating Officer & Vice President

So our corporate approach is to let the experts focus on that and spend mineral cost on infrastructure and focus on our high return wells. So a lot of these – you can't create a compelling midstream entity on your own. But when you look at your returns on the wells, we seem to be outpacing that. And we are fortunate we can do that in high density areas with a lot of competitive build-out on the infrastructure side.

So really when we are on top of our D&C costs we are around 10% on what we call facility and infrastructure, which is essentially well level facility to the connect points. On the Midland – I mean on the Delaware side, for the next 18 months I predict that to be in the 15% to 20% range just as you're just building out some additional – the physical roads to connect to those SWDs. We do drill our own SWDs and have that infrastructure and water gathering in-house.

So then the other thing to note on our Delaware position is we own the surface. So water sourcing is going to be very beneficial to us. And we see on the order of $200,000 of savings per well just due to our surface ownership there as we look at building out or water sourcing and gathering and disposal systems out there. So really, we are talking about oil takeaway and gas takeaway and electrical inbound; and we're in a very good position for all those three line items in the Delaware.

Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc.

Got it. Thanks. And just a quick follow up, you guys touched on rigs rates a minute earlier. Just are you seeing any upper pressure yet from service companies on pricing in the basin now at this point?

Matthew Gallagher - Chief Operating Officer & Vice President

We essentially are not, but the order of magnitude of the reductions are lowering. So it's more competitive around a singular price right now.

Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc.

Got it. That's all I got. Appreciate the color and congrats again, guys.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Thank you.

Matthew Gallagher - Chief Operating Officer & Vice President

Thank you.

Operator

Thank you. Our next question is coming from the line of David Tameron with Wells Fargo. Please proceed with your question.

David R. Tameron - Wells Fargo Securities LLC

Good morning. Nice quarter. Bryan, as you think about the big picture and you talked about obviously acquisition continues to heat up. How do you think about where you're at in your portfolio, how much bigger do you want to get? How should we think about the way you're thinking about the way the board is thinking about the evolution, if you will, probably over the next, call it, two to three years?

Bryan Sheffield - Chairman, President & Chief Executive Officer

For now, we look at the Wolfcamp locations. That's our highest return project and we kind of do the math on four-rig. How many years? For 12 years to 14 years out in four rigs; and if you add a couple more rigs, how many years? And we'd like to stay at least seven years to 10 years out on this. I think in a couple years it's going to be harder and harder and we're going to have to make tough choice as a company. But right now, with the downspacing project and the BBs, that could delay it. So we don't really need to worry about it right now, but it is something to watch. But right now, we have 1,500 locations right now. So you can do the math. We're in a very good position with a lot of running room.

David R. Tameron - Wells Fargo Securities LLC

Okay. Everything else has been asked, so that's all I had. Thanks. Appreciate it.

Bryan Sheffield - Chairman, President & Chief Executive Officer

Okay. Thanks. Take care.

Operator

Thank you. Our final question is coming from the line of Chris Stevens with KeyBanc Capital Markets. Please proceed with your question.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Hey. Good morning guys. Quick question on the Delaware Basin. Do you know what the average lateral length is going to be as you start putting rigs to work there in 2017? And then also on the Midland Basin side, should we assume the lateral lines pretty much in line with the 7,000 foot from this year?

Matthew Gallagher - Chief Operating Officer & Vice President

Well, that's a good question. And because we have our average around 7,000 feet on our potential locations on the Delaware side that really we are going to frontload our 10,000 foot or so. Our Pecos County position is all 10,000 foot development. That's on our 30,000 acre ranch and we will have a high percentage of 70%, 80% of 10,000 footers. On the Midland side, we also tend to frontload it. And then, a lot of success from the teams on these trades that are extending lateral lengths month in and month out. So to the extent possible, continue frontloading the longer locations on the Midland side as well. So that should probably grind up on average program lengths.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Okay. And then just finally on the M&A side, if you guys were to continue adding out in the Delaware Basin, are you pretty much only focused on that southern area near Pecos and Reeves where you are right now or would you sort of venture out and maybe look at other areas of the Delaware Basin closer to the state line area or into New Mexico?

Bryan Sheffield - Chairman, President & Chief Executive Officer

Good question. We've always had the strategy for bolt-ons in close radius of our operations. You have a huge edge and advantage when you stay close to home and where your field offices, where your plumbers and foremen are, and where your engineers are focused on and especially on the rock and if you understand the rock in a certain area. So we're just going to keep on pounding away on anything that's close or continuous up to maybe a 15 mile radius, and that is the same strategy we've applied in the Midland Basin also.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Great. Thanks a lot. Good quarter.

Bryan Sheffield - Chairman, President & Chief Executive Officer

All right. Thank you.

Operator

Thank you. Ladies and gentlemen, we have reached the end of our question-and-answer session. And this does conclude today's teleconference. Again, we thank you for your participation. You make disconnect your lines at this time, and have a wonderful day.

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