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RSP Permian Inc. (NYSE:RSPP)

Q2 2014 Earnings Conference Call

August 14, 2014 11:00 AM ET

Executives

Steven Gray – Chief Executive Officer

Scott McNeill – Chief Financial Officer

Zane Arrott – Chief Operating Officer

Analysts

Will O. Green – Stephens, Inc.

Michael J. Rowe – Tudor Pickering Holt & Co. Securities, Inc.

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

Ipsit Mohanty – GMP Securities LLC

Jeffrey R. Connolly – Mizuho Securities USA, Inc.

Gail A. Nicholson – KLR Group LLC

Brian D. Gamble – Simmons & Company International

Operator

Good morning and welcome to the RSP Permian Second Quarter 2014 Financial and Operating Results Conference Call. As a reminder, today’s call is being recorded and your participation implies consent to such recording. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation.

With that, I would like to turn the call over to Mr. Scott McNeill, Chief Financial Officer of RSP Permian. Thank you, sir. Please go ahead.

Scott McNeill

Thank you, and good morning, everyone. We appreciate you joining us for the RSP Permian second quarter 2014 financial and operating results conference call. With me today are RSP’s Chief Executive Officer, Steve Gray; and Zane Arrott, our Chief Operating Officer.

Before we begin, I would like to remind all participants that our comments today may include forward-looking statements. It should be noted that a variety of factors could cause RSP’s actual results to differ materially from the anticipated results, or expectations expressed in these forward-looking statements. for a complete discussion of these risks, we encourage you to read earnings release and our documents on file with the SEC.

Today’s call may also contain certain non-GAAP financial measures. You can refer to the press release and Form 10-Q we issued this morning for important disclosers regarding such measures and the reconciliations.

You can obtain a copy of our press release and Form 10-Q under the Investor Relations tab of our website at www.rsppermian.com.

And with that, I’ll hand the call over to Steve.

Steven Gray

Thanks, Scott. I’m going to provide some highlights from the quarter and year-to-date, and I’ll turn the call over to Zane for an overview of our operations and to Scott for a review of our financial results. It’s been a busy and successful year for RSP, both on the financial and operations fronts. Despite the recent market volatility, we had a successful equity offering last week and increased our public float and raised equity capital to help fund our recent $259 million acquisitions in Glasscock County.

To recap the offering, underwriter’s price last week, including the exercise of a full over-allotment auction, RSP and are selling shareholders sold 11.5 million shares priced at $25.55 per share, resulting in an over $115 million of net proceeds to RSP from the sale of the primary portion of the offering. We were happy to see many current shareholders looking for more exposure to RSP and also happy to see some new shareholders join us as we continue to execute our growth plans. We heard good feedback on our solid execution and track record to date and we are confident we will continue to deliver results.

To date, we have executed our drilling plans pretty much as we expected. We participated in drilling of over 79 horizontal wells, 37 of which were operated, targeting six pay zones. In the second quarter, we drilled 17 horizontal wells, seven of which were operated and we completed 16 horizontal wells, six of which were operated. In the second quarter, we added a fourth operated horizontal rig and the third operated vertical rig, and we recently contracted a fifth horizontal rig and are finalizing terms on a sixth horizontal rig contract, which are expected to arrive in late 2014 and in mid first quarter of 2015 respectively.

This is an acceleration from the plan we shared at our IPO only seven months ago. and as a result of our drilling success and our year-to-date acquisitions, we have increased our drilling budget for the year from $350 million to $400 million. We are continuing to drive efficiencies throughout our portfolio by optimizing our drilling designs and utilizing multiple zone development on multi-well pads to drive down costs. We also remain active reviewing acquisition opportunities. We’ve used our acquisition experience and our relationships to find deals, similar to the one we just announced in Glasscock County that brought together six different sellers to combine into one significant and accretive asset package.

In addition we have built a substantial horizontal and vertical inventory position that will serve to grow our production and reserves. In just several months since our IPO, we have made over $300 million of acquisitions and increased our horizontal inventory by 50% to a total of 1,760 locations, up from 1,169 at the time of the IPO. This increase results from both acquisitions and from our evaluation of our well results and technical evaluation of our properties, which has led us to increase our estimate – estimated well density or decrease our well spacing in some specific formations. Our recent horizontal wells have brought encouraging results.

as a result of our wells tracking ahead of our expectations, our quarterly production averaged 10,714 BOE per day, which is a 15% growth over our pro forma first quarter 2014 rate and a 43% increase over our second quarter 2013 on a pro forma basis. Our pro forma results assume the IPO contributions discussed in our IPO prospectus occurred on January 1 instead of on January 22.

As a result of our continued performance, we recently raised our 2104 production estimate range from our previous guidance of 10,000 BOE per day to 11,000 BOE per day, to 11,500 BOE per day to 12,000 BOE per day. We plan to close the acquisition in late August, which will further add to our estimated production volumes for the remainder of the year.

Now, we continue to caution you that our production growth on a sequential basis will be lumpy as we execute on our multi-horizon, multi-well pad development, which results in significant amount of production being put online at one-time. In addition, these completions often interfere with existing production as we shut in offset wells while hydraulically fracking our horizontal wells.

Consequently some quarters may be a little higher than expected and some quarters may be a little lower, but the bottom line is we’re confident in our annual production range. On the acquisition front, we’re excited about the Glasscock County acquisitions as they solidify a new primary operating area for RSP. We will add 6,652 net acres, 156 net horizontal locations and 132 net vertical drilling locations to our inventory. And we will now have almost 50,000 acres of leasehold across our area of operations, or approximately 180,000 net effective horizontal acres.

Getting these accretive acquisitions done was a real testament to our business development team and to our relationships across the Permian Basin. It takes a lot of effort to put multiple sellers together into one single acquisition of attractive undeveloped by groups, and it helps that we know most of the sellers personally, and have had long relationships with many of them. We expect the acquisition will close in late August. so we will have only a prorated portion of the current net production of 1,106 BOE per day, reflected in our third quarter results.

As mentioned in our press release on the acquisition, there is currently one vertical rig running on the properties that we will keep running for the rest of 2014 and into 2015, before initiating a horizontal drilling program. We hope to have a horizontal rig on the properties in the first half of next year.

RSP is in a strong financial and operating position, with substantial growth ahead of us and a tremendous oil resource play that’s in the early stages of realizing its full potential. We’re excited about what we have ahead of us, as we continue to optimize our multi-horizon development plan. We’ve also continue to add a personnel in all departments on our company.

We now have over 65 employees, up from approximately 35 at the time of our IPO. We have been extremely pleased with the quality of the people we have been able to attract both in our corporate office in Dallas, as well as in our operations offices in Midland and I would like to personally welcome our new employees, and thank all of our employees for all they have done to make our first two quarters as a public company successful.

With that, I’m now going to hand the call over to Zane, who will walk through our current operations.

Zane Arrott

Thank you, Steve. This morning, I will give an overview of our second quarter operations and touch on some upcoming activities. During the second quarter, we had six horizontal rigs, four of which were operated, and four vertical rigs, three of which were operated running on our properties. As Steve mentioned earlier, we’ve recently contracted a fifth horizontal rig, and we are in the process of contracting a sixth horizontal rig to accelerate our horizontal drilling program.

During that quarter we drilled 17 horizontal wells, 10 of which were operated, and 18 vertical wells, nine of which were operated. Also during the quarter, we completed 16 horizontal wells, six of which were operated, and 16 vertical wells, seven of which were operated.

All of our operated horizontal rigs will be drilling multi-well pads for the remainder of the year and we expect to complete 13 operated horizontal wells during the third quarter, 10 ten operated horizontal wells in the fourth quarter. As you know, we recently completed a detailed review of the resource potential in the middle and lower Spraberry zones, as well as the projected ultimate recovery of wells that have been drilled within those zones. As a result of this review, we now believe that we need to increase the density of well bores in these horizons. This has not only decreased the well spacing, but also tangibly increased our horizontal well inventory as well as the probable resource recovery.

Based on the results of the review, we increased a number of laterals per drilling unit across the section from five across to seven across, or about 40% in order to increase resource recovery and returns. Our average lateral length for our target horizontal locations has also increased to about 6,700 feet due to new drilling unit arrangements. As mentioned in our second quarter update press release, during the second quarter our most important multi-well pad completion was the Cross Bar Ranch 1717 WA and 1717 WB.

The Cross Bar Ranch 1717 WA which was RSPs first Wolfcamp A well, was fracked in tandem with the Wolfcamp B well from the same pad. No interference was seen between the two completions or in the production performance to date. The 30 day IP rates of these two wells were 928 BOE per day, and 867 BOE per day, and the 90 day cumulatives, or approximately 76 MBOE and 60 MBOE respectively. These two wells are separated by approximately 300 feet of lateral distance and 150 feet of vertical distance.

For an update on the Middle Spraberry, I’d like to highlight the Johnson Ranch 912 MS we reported on last quarter. This well has now produced for five months and has an approximate cumulative recovery of 100 MBOE and is still producing over 500 BOE a day on average.

As previously reported this well had a lateral length of 7848 feet and was completed for the 25 stage frac. And turning now to our future activities on the Cross Bar Ranch lease we are currently fracking three wells in the Wolfcamp A, lower Spraberry, and middle Spraberry on the Cross Bar Ranch 2017 pad that has a producing Wolfcamp B well already present.

During the fracking of these three wells and micro-seismic survey will be performed so that a full study in the Middle Spraberry down to the Wolfcamp B can be obtained. This study will allow us to see the interaction of fracs throughout the column. This will be critical to future spacing and full development scenarios as we go forward to optimize our drilling operations and maximize our recovery of the hydrocarbon resource. The results of these completions and the micro-seismic study should be available for the third quarter reporting.

In our Dawson County area, we have fracked two wells on a dual-well pad that are targeted the Upper Wolfcamp and the Lower Spraberry shales. These wells are in very early flow back and production results will not be available until late in the third quarter. We moved this rig to our Johnson Ranch lease in Martin County and will assess our drilling results as well as that of other operators in the area before determining our future drilling plans in Dawson.

Also, we have begun horizontal development in our Spanish Trail leasehold area. We currently have one horizontal rig operating in the Spanish Trail lease, where we already drilled and fracked a two-well pad targeting the Lower Spraberry and Wolfcamp B. The Wolfcamp B well is in early flow back and the Lower Spraberry well is still on the completions phase. We have also finished the drilling phase of a second two-well pad targeting the Lower and Middle Spraberry shales and these wells are two longest laterals to date, with each lateral to measure approximately 9,900 completed feet.

In addition to our drilling and completion operations, we are in the final stages of acquiring additional 3D seismic data across our acreage to help optimize well bore placement in all zones and to avoid drilling and completion hazards such as faults in our Wolfcamp D zone. As discussed on our first quarter call, we encountered mechanical issues on our recent Wolfcamp D well, as we believe we may have crossed a fault. And finally, on our future activity, once the Glasscock acquisition has closed, we will be integrating the current production in vertical drilling into our operations, and we will be developing a 2015 plan to drill the first horizontal wells on our new acreage, which we'll share with you later in the year.

Turning to the second quarter lease operating cost, we performed several workovers and we also continued to spend dollars on upgrades to our producing wells. These expenditures, along with recurring normal expenses, resulted in about the same lease operating expenses as the first quarter. We continue to expect our LOE rate to come down as this workover and upgrade activity moderates, and we grow our production volumes.

During the quarter, we have seen drilling and completion cost reductions level of from their previous declines. Our cost savings are more minor and incremental in nature and being offset by oil field service inflation.

I'm very pleased with the execution of our drilling program and the continued horizontal results we're seeing across our acreage. We continue to focus on multiple horizontal targets in a thoughtful and efficient manner as we develop our growing inventory of prospects.

With that, I'll turn the call over to Scott.

Scott McNeill

Thanks, Zane. I'm going to review our financials for the quarter. Adjusted pro forma net income for the second quarter was $18.5 million, or $0.25 per diluted share. This excludes non-cash derivative losses of $14.4 million that reduced our net income by approximately $0.13 per share. The adjusted EBITDAX for the second quarter was $53.7 million, which was the high end of the range we communicated in our recent S-1 disclosures.

Production for the second quarter averaged 10,714 BOE per day, up 15% from our pro forma production of 9,339 BOE per day. Our production was approximately 71% oil in line with our first quarter results. As Steve mentioned earlier, we’ve recently raised our production guidance to 11,500 BOE per day to 12,000 BOE per day on the back of both our strong results and on our drilling plans for the remainder of the year. In line with this production increase with the capital spending increase for 2014, we now see a total capital spend of $425 million versus the $350 million to $375 million range we guided to at the end of the first quarter. On the cost side, our lease operating expense was $8.55 per BOE for the quarter, slightly down from the $8.66 per BOE last quarter.

Note that we have expanded our lease operating expense disclosure in our earnings release from last quarter by splitting out our gathering and transportation cost to be similar to other public companies. G&A was $4.34 per BOE on a pro forma basis after deducting non-cash equity compensation cost associated with non-recurring IPO bonus and incentive units, an increase from $2.46 per BOE in the first quarter 2014 on a pro-forma basis.

Our production and ad valorem taxes were $6.12 per BOE compared to $5.02 in the first quarter, and our DD&A was $22.29 per BOE similar to our prior quarter. I would also note that our average differential on oil prices wind in the quarter to $6.77 per barrel compared to $4.01 in the first quarter. The total we spent on capital expenditures was in line with our plans at $95 million, which included about $89 million for drilling completion and capitalized workovers. About 75% to 80% of our capital dollars continue to go towards our horizontal drilling program.

Our balance sheet remains strong, as Steve mentioned earlier, we completed a successful equity offering just last week that provided us with over a $115 million in proceeds net RSP after the exercise on the 15% over-allotment option. In total, RSP sold 11.50 million shares to stock, 6.7 million were sold by selling stockholders and 4.8 million shares of new RSP common stock was sold.

We closed the second quarter with about $125 million of debt; net of cash and prior to the recent equity offering had approximately $117 million of debt outstanding. In May, we increased the borrowing base on our revolving credit facility by 25% to $375 million following our semi-annual redetermination process.

We expect to fund the pending acquisitions in Glasscock County from our credit facility, which is being reduced with the cash from the sale of the primary shares in the offering. As a result of the equity proceeds from the offering and the increase in credit facility, we will have plenty of capacity to close the acquisitions as well as liquidity available along side our growing cash flow to fund our increased horizontal drilling program.

After we close the Glasscock acquisitions in late August, we will assess the possibility of issuing senior notes. In terms of hedges, we have continued to increase our crude hedge positions since the IPO. We currently have about 60% of our remaining 2014 expected oil production hedged primarily through oil swaps and collars at an average floor of $88 per barrel. And approximately half of our 2015 expected oil production at an average floor of approximately $87 per barrel.

We will continue to opportunistically add commodity price hedges to lock in a portion of our cash flow and to protect our economics on our drilling program. You can find our updated investor presentation on our website this morning and we filed our 10-Q with the SEC this morning.

With that, I’ll turn the call back to Steve for our closing comment before we open the call for questions.

Steven Gray

Thanks, Scott, and thanks again, for everybody – to everybody for joining the call this morning. I hope you can tell by our comments that how excited we are about our performance to date and our outlook for the future of RSP.

With that, I’d like to open the line for questions. Operator, please open the lines.

Question-and-Answer Session

Operator

Thank you. At this time we will conduct a question & answer session. (Operator Instructions) Our first question comes from Will Green with Stephens. Please proceed with your question.

Will O. Green – Stephens, Inc.

Good morning guys.

Steven Gray

Good morning.

Scott McNeill

Good morning.

Will O. Green – Stephens, Inc.

So I wonder if we could start on these multi-well pads. You guys talked about how most everything going forward is going to be on multi-well pad, I was going to ask what the standard interval combo looked like, but it sounds like you guys are comboing a lot of different intervals together. So is the way to think about this, two to three well pads at this point and then maybe, once you guys get some comfort add-on from there, and then how far apart are you guys spacing these newer pads that you’re stacking?

So, one of we could started on this – on these multi-well pads, you guys talked about how you know most everything going forward is going to be a multi-well pad, so I was going to ask, you know what the standard you know in of all combo, look like but, it sound like you guys, are you’re (indiscernible) a what a different and wells together so, is the way to think about this, you know 2 well pads – 3 well pads at this point then you know maybe get, once you guys get some comfort and on from there, and then how far apart are you spacing these – these newer pads that they you’re checking?

Zane Arrott

That’s good question, Will. This is Zane and what we’re doing right now, and you were correct when you said, we are looking at a lot of different combinations. so we’re doing a number of different pilots. and I wish I could tell you exactly what our recipe was going to be from this point forward, but we still have a number of pilots that we’re looking at and we’re trying to determine, what we want to make sure is that we don’t do anything, with one zone or another that would preclude us from doing what’s right later on.

We want to be able to take a look at Wolfcamp B and Wolfcamp A, as well as lowest Spraberry, because all of those zones are in fairly close proximity to each other. So we want to make sure that we get that spacing both vertically and horizontally down right, and as you know, we have those spacing pilots going on right now. In fact we are currently fracking that three well pad with the B well is already producing and we have microseismic on it and we’re right now fracking the WA, the Wolfcamp A, the Lower Spraberry and the Middle Spraberry and obtaining that microseismic.

In general, our pads are set up, where they are four well pads, or five well pads, we have two or three wellheads on one side of the pad and two wellheads on the other side of the pad, so that we can drill two zones on the one side and come back later and drill two zones on the other side of the pad after we have fracked those two or three wells that are only one side of the pad. And then we put enough pads across the drilling unit to make sure that we are able to drill a number of wells that we want to put into that unit. Does that answer your question?

Will O. Green – Stephens, Inc.

Yes. It does. That’s great color. So on these next – few tests, are these going to be spaced – is anything going to be similarly spaced as those Cross Bar wells were? Are you guys going as tight as 300 feet horizontally for any of these next tests, or even tighter for some?

Steven Gray

No. We are not going tighter than those. In fact the two on the Wolfcamp A and Wolfcamp B the two of pilots that we have that are currently either drilling or completing the A is one of them the one that we're fracking right now and obtaining the microseismic is 450 feet lateral distance away from the Wolfcamp B. And then over on Johnson Ranch, those wells are 600 feet from the Wolfcamp B, and I know it sounds like we’ve had a – it looks like we’ve had a very successful test on 300 feet and you are probably going why aren’t you just going ahead to stick with the 300 feet, but if we just want to make sure that we don’t see, if we did see depletion in the 300 feet here in the fairly near future we would now that our communication, not depletion. If we saw communication, we would know that that is to close. So we want to do a number of different pilots and it’s going to take well into next year, before we know the final answer to those spacing pilots.

Will O. Green – Stephens, Inc.

Got you. And is there a specific geologic feature up at Cross Bar between the A and the B that I guess, gave you guys more comfort in spacing that tightly?

Steven Gray

No. We were surprised that we didn’t see communication during the frac, because the Wolfcamp A and the Wolfcamp B there, it is very difficult both in Cross Bar Ranch and in Johnson Ranch to distinguish where you leave A and begin B.

Zane Arrott

In other places and some of our other properties, you have a little carbonate interval or a number of carbonate intervals that tell you where you are leaving A and going into B.

Will O. Green – Stephens, Inc.

Great. That’s all I had guys. Thanks for the color.

Steven Gray

You’re welcome.

Operator

Our next question comes from Michael Rowe with TPH. Please proceed with your question.

Michael J. Rowe – Tudor Pickering Holt & Co. Securities, Inc.

Hi, good morning.

Steven Gray

Good morning.

Zane Arrott

Good morning.

Michael J. Rowe – Tudor Pickering Holt & Co. Securities, Inc.

I was just wondering if you could just maybe talk about the Western Glasscock acreage to be acquired for a minute. Obviously, you all had a small piece of acreage there prior to making this acquisition and saw some things in the geology and some of the offset well results to encourage you about that area, but could you maybe just compare and contrast the geology of the Western Glasscock acreage relative to your existing focus area acreage further west in the Midland Basin?

Steven Gray

Sure. As you know, we have – there are offset operators to the – both to the East and the West. We believe that the geology and that part of Glasscock County is very similar to the geology in the eastern part of Midland County. We like it. We see a lot of great things there. In the Wolfcamp, especially, as well as the Lower Spraberry. we did not model wells in the Middle Spraberry in Glasscock in our acquisition numbers, nor in our NAV, internal NAV model.

So what we are modeling there is Lower Spraberry, as well as Wolfcamp A and Wolfcamp B, as well as the lower part of the Wolfcamp or Cline. We also see the middle part of the Wolfcamp there as highly perspective of what people I believe would call it the Wolfcamp C. And so we really like the geology there. We think those are going to be great wells.

Michael J. Rowe – Tudor Pickering Holt & Co. Securities, Inc.

Okay. And maybe just to expand on that a little bit, is there a specific reason why you’re not comfortable with the Middle Spraberry in that part of the Midland Basin?

Steven Gray

Poorly developed with a much lower oil-in-place number and unconventional oil-in-place number than what see in our core area.

Michael J. Rowe – Tudor Pickering Holt & Co. Securities, Inc.

Okay, great. That's helpful. And just last question for me would be, operationally, you guys are making some, I guess some accomplishments, in terms of bringing down well costs as you go to the multi-well pads, but I was just wondering, could you talk about maybe what your latest completion design is in terms of the amount of profit you’re using and the comp position as well as the fracked stage spacing? And any plans that you all have to test this in terms of adding more profit to wells or things of that nature? Just trying to wonder how you all kind of balance optimizing or enhancing your completions with your well cost reduction goals.

Zane Arrott

Okay. This is Zane; I’ll take that one again. I think it’s best to go back to where we started the year at. when we came into the first quarter, we were spacing our fract stages about 320 feet apart with three first perf clusters and we were using about 1,000 pounds of sand per lateral foot. We moved that to – later on, we moved that to 250 foot spacing with four perf clusters. But in the second quarter, we have gone to 225 foot spacing. so we have added more stages, tightened stages, we have stuck with the four perf clusters and we’ve moved our sand volume up to 1,400 pounds per lateral foot. so we have – we’re adding more stages and we’re adding more sand, which of course means a higher cost. But we believe that we are seeing, as well as we are hearing from our peers in the industry, other operators that we’re going to see higher EURs doing that.

Michael J. Rowe – Tudor Pickering Holt & Co. Securities, Inc.

Okay, great. I appreciate the color. Thanks.

Operator

Our next question comes from John Freeman with Raymond James. Please proceed with your question.

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

Hi, guys.

Steven Gray

Hey, John.

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

For a first question, on the one well that – the Cline that had the issues with the fault. And obviously, you’re waiting for the 3D seismic, but if I understood you right, Zane, it sounds like you were fairly confident that it’s – the faulting issue is kind of isolated to the Cline in the Cross Bar area. And I mean, obviously you had no issues with the recent A wells. Am I reading too much into that or is that right?

Steven Gray

Now you are rating in that correctly. and in the last two days, we have actually gotten the first part. we have actually seen, so let’s call it first draft of that 3D and we have now verified, I looked at the 3D yesterday with our geophysicist, we have now verified that we did land that right lateral right in a fairly substantial fault.

So our well fault had happened to us has now been confirmed. And we know from other operators, we heard early on in this that you can see some of this faulting in the client that in the Wolfcamp that’s normally where it’s going to occur and it did, I wish we had, would have the 3D to begin with we would have never drilled that well where we drilled it. so, and looking at just the initial 3D that I saw yesterday geophysicist did not see this fault going into the upper part of Wolfcamp that would affect us in the A and the B nor in the Spraberry of course.

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

Okay. That's helpful. And then, you obviously mentioned a lot of things Zenial are doing differently on the completion side. There's been a few companies that have been experimenting with different choke sizes, looking at some restrictive flow. Have you all done anything on that front?

Steven Gray

No. We have not.

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

Okay. That's it for me guys. I appreciate it.

Scott McNeill

Thanks, John.

Operator

Our next question comes form Ipsit Mohanty with GMP Securities. Please proceed with your question.

Ipsit Mohanty – GMP Securities LLC

Hey. Good morning, guys. Thanks for taking my calls. I'll stick with the Glasscock acquisition for the second and ask you, given that that acreage probably is more perspective to more zones than the Dawson, does the profit strategy change in terms of the development going forward that you did in terms of your location of the rigs versus Dawson? And when do we first see any horizontal rigs for the Glasscock?

Steven Gray

Okay. Well, we'll wait and see what our results are in Dawson before we make a determination of whether we're going to keep a rig up their full-time or not. But whether we do or not, it will not affect when we put a rig into Glasscock. We are currently planning on putting a rig into Glasscock as soon as we are ready with the infrastructure that we need in place to support horizontal drilling such as water supply, and water disposal. And as soon as that's done and we are looking – that will be in 2015, we will be putting a rig into Glasscock and I would say that we will be leaving a rig in Glasscock from that point on.

Ipsit Mohanty – GMP Securities LLC

Thanks. Where are the two rigs in 2014 and early 2015 going to?

Steven Gray

We have not totally decided exactly where that first rig is going to go. We're going to wait and look at – we’ve a number of horizontals that we are just bringing on production or we are currently fracking. We have a number of places we can take that. We have several big leases such as Cross Bar Ranch, and the Spanish Trail which are ready to take another rig. And we are currently looking at – we're going to be looking at some early production data at both of those areas to determine where we are going to put – which lease were going to put that radon and that has not yet been determined, but both

of those leases are ready for another rig.

Ipsit Mohanty – GMP Securities LLC

Sure. And one of the things that works for you guys compared to some of the other operators that you got – contiguous solid blocks of acreage. Do we see lateral length improving as we go forward or do you rest the fields with 7,000 feet? In other words, do we see some extended laterals as we move forward?

Steven Gray

Yes. Certainly, we are – our average lateral length for the third quarter will actually be 30% higher than the second quarter. So we are starting to move and as we mentioned on the call, we have drilled our first 9,900 foot laterals in the Spanish Trail lease and anywhere and those wells went very well for us. In fact we drilled both of those wells on water-based mud, which may be the first in the basin that long with water-based mud, which is the cost savings in itself. But anywhere we can move to longer laterals. we will to do that, in fact we have reconfigured some of our drilling units in Cross Bar Ranch to drill – to knock out an entire row of wells and drill longer wells in there. So we would be eliminating and just drilling the longer horizontals, based on the success we had with drilling those two wells. Yes, you will see us going the longer horizontals where we can, and where it makes sense.

Ipsit Mohanty – GMP Securities LLC

Great, thank you.

Operator

(Operator Instructions) our next question comes from Jeffrey Connolly with Mizuho Securities. Please proceed with your question.

Jeffrey R. Connolly – Mizuho Securities USA, Inc.

Hi, guys. In the prepared remarks you mentioned some service cost inflation. Can you give us some more color on that? And then, are you seeing any challenges scheduling completions or getting frac crews?

Zane Arrott

Okay, this is Zane again. And yes, we are seeing some inflation in costs. I believe we’ve already mentioned that the ring contract that we have signed and are about to sign the other ones, are about 5% higher than what we – the all-in costs are a little over 5% higher than what we saw this time last year on the contracts where we signed.

We recently got an increase in our casing costs that increase was almost exactly 5% higher also. We are seeing upward awkward price pressure in pumping services also. So, there is some inflation in prices, and we have – we’ve already picked up low hanging fruit on decreasing these well costs going to multi-well pads, but we are still fine-tuning that, and getting and still offsetting some of those inflationary costs. Like we said, it’s going to be minor and very incremental from this point on.

Jeffrey R. Connolly – Mizuho Securities USA, Inc.

Great, thank you.

Zane Arrott

As far as access to services, we have not had any problems and we have verbal dedication of crews from our contractors in the pumping services.

Jeffrey R. Connolly – Mizuho Securities USA, Inc.

Okay. Thank you. That’s helpful. And then can you just give us your updated outlook on the M&A market and activity?

Scott McNeill

This is Scott. We’ve been pretty active in the M&A market today. as the public company, we’re continuing to see a good deal flow; we are taking a look at additional deals. I think you’ll see us continue on the acquisition front. It may take a little pause until we get the Glasscock acquisition closed and financed. but you’ve seen our peer group; they’ve been active as well. so we’re still seeing where it makes sense to add-on to our core areas, and we plan to remain active in the – on the M&A front.

Jeffrey R. Connolly – Mizuho Securities USA, Inc.

All right. Thanks for taking the questions, guys. Appreciate it.

Zane Arrott

Welcome.

Operator

Our next question comes from Gail Nicholson with KLR Group. Please proceed with your question.

Gail A. Nicholson – KLR Group LLC

Good morning. Just a question on those 9,900-foot laterals. I was wondering what were the costs of those laterals, you mentioned that the water-based mud was a cost-saving use and I was curious if you’re going to continue to use that on other wells and how much that saved you on the cost side?

Zane Arrott

This is Zane. that’s probably saved upwards of, that’s probably in the $100,000 savings range on that water-based mud. We used that in the two Spraberry shale wells, so both – one of those wells is Middle Spraberry and the other was a Lower Spraberry and we have not yet attempted to use a water based polymer mud in the Wolfcamp A or B, but we will be taking a look at that. And we will continue to use the water-based muds in those Spraberry shales now.

Gail A. Nicholson – KLR Group LLC

Okay, great. Thank you.

Operator

Our next question comes from Brian Gamble with Simmons & Company. Please proceed with your question.

Brian D. Gamble – Simmons & Company International

Good morning, guys.

Scott McNeill

Good morning.

Brian D. Gamble – Simmons & Company International

A couple of follow-ups to some stuff you guys have talked about. You mentioned the current prop volume, current stage length and whatnot. Are we planning on changing that going forward? Or you've been changing it? You've gotten to a point, are you going to test that for a while or does that continue to – proppant volume specifically, continue to increase into the back half of the year?

Steven Gray

We are going to watch some of this production history. These wells that we've done this with because we don't have a lot of history on the wells that we did in the second quarter yet. We certainly like what we see. And believe that we will continue to like what we see, but you could see us moving to higher sand volumes, because we are hearing good things about that from amongst our peers. And we try to stay in contact with our peer group and trade ideas and recipes.

Brian D. Gamble – Simmons & Company International

And what's your current mix of proppant?

Steven Gray

Our current mix, proppant – we initiate with 100 mash. And then we go I think we use. I think it's 30/50 after that and we use very little gel, so we don't really use the hybrid. Some time we – and then we will tail in with a little bit of resin coat just to make sure everything in place.

Brian D. Gamble – Simmons & Company International

Great. And then the wells up in Dawson, I know you don't have any history to speak of, but as far as the drilling, how did the drilling relate to some of the other, I guess, applicable offsets that you've done in both Wolfcamp B and the Spraberry? Is it similar to the rock down south or were the differences?

Zane Arrott

No. It drilled very easily. In fact, we had to pull back the penetration rate, I'm not sure how fast we could have drilled those wells. We had not seen anything drilled quite that fast. I know that they get some very fast drill times down in the Upton. But we were seeing things like that up here in Dawson. It drilled very well and it fracked very well. Also our completion there went as good as it could.

Brian D. Gamble – Simmons & Company International

So from that, those two data points you would expect the flow rates to be pretty good as well? There's no negative correlation there between easy drilling and flow rate, is there?

Zane Arrott

There is no negative. No.

Brian D. Gamble – Simmons & Company International

Great. And then you mentioned – I'm just looking at the oil dif for the quarter. It seemed like it was a little bit more positive for you guys than would be implied by the general dif that you are exposed to. Was there any reason for that? Did you guys have any creative oil selling during the quarter? Or was that just a matter of hedges and plays versus prices that were sitting out there?

Scott McNeill

No, we heard that before in general we – this is Scott, we have some better netbacks on pricing than some of our peer groups and I think we've seen that in previous quarters. We have not done any basis hedging, so that's not the reason we've experienced better relative differentials. So I think that part of it is how you account for some of the things that run through your LOE versus a deduct from revenue, and we may have a little bit more that comes through at least operating expense that other operators have as a reduction in the oil price revenue. So you kind of have to take a look at it on a combined basis. The other part of that is how much that we are gathering into our pipeline versus how much that we are trucking, and on a relative basis, we may have a little bit more on our pipeline that some of the operators do.

Brian D. Gamble – Simmons & Company International

Great. That’s helpful. Thank you.

Operator

At this time, I would like to turn the call back over to management for closing comment.

Scott McNeill

This is Scott. I’ll just wrap up. Thank you everybody for joining us today. We just want to say we're excited about the growth plan that we have in place. We will be presenting at the Barclays conference –our next conference in New York. So we will see some of you there. And thank you again.

Operator

This concludes today’s teleconference. You may disconnect your lines at this time and have a great day.

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