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Edited Transcript of RSPP earnings conference call or presentation 3-May-17 6:00pm GMT

Thomson Reuters StreetEvents

Q1 2017 RSP Permian Inc Earnings Call

Dallas May 6, 2017 (Thomson StreetEvents) -- Edited Transcript of RSP Permian Inc earnings conference call or presentation Wednesday, May 3, 2017 at 6:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Alyssa Stephens

* Scott K. McNeill

RSP Permian, Inc. - CFO and Director

* Steven D. Gray

RSP Permian, Inc. - Co Founder, CEO and Director

* Zane W. Arrott

RSP Permian, Inc. - Co Founder and COO

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Conference Call Participants

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* Charles A. Meade

Johnson Rice & Company, L.L.C., Research Division - Analyst

* Daniel Eugene McSpirit

BMO Capital Markets Equity Research - Equity Analyst

* David Snow

* Derrick Lee Whitfield

Stifel, Nicolaus & Company, Incorporated, Research Division - MD and Senior Analyst

* Irene O. Haas

Wunderlich Securities Inc., Research Division - SVP and Senior Equity Analyst

* Jeffrey Scott Grampp

Northland Capital Markets, Research Division - MD and Senior Research Analyst

* John Christopher Freeman

Raymond James & Associates, Inc., Research Division - Research Analyst

* Kashy Oladipo Harrison

Piper Jaffray Companies, Research Division - VP and Senior Research Analyst, Exploration and Production

* Michael Anthony Hall

Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst

* Richard Merlin Tullis

Capital One Securities, Inc., Research Division - Senior Analyst

* Subash Chandra

Guggenheim Securities, LLC, Research Division - Analyst

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Presentation

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Operator [1]

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Welcome to the RSP Permian First Quarter 2017 Financial and Operating Results Conference Call. As a reminder, today's call is being recorded and your participation implies consent to such recording. (Operator Instructions)

With that, I turn the call over to Alyssa Stephens, Director of Investor Relations. Thank you. Please go ahead.

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Alyssa Stephens, [2]

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Thank you, we appreciate you joining us today as we discuss RSP Permian's First Quarter 2017 Financial and Operating Results. On the call today, we have Steve Gray, Chief Executive Officer; Scott McNeill, Chief Financial Officer, and other members of RSP's management team.

Yesterday after the markets closed, we should our first quarter 2017 earnings release and filed our Form 10-Q with the Securities and Exchange Commission. In addition, we've posted a new presentation to our website, which we will reference during the call. The presentation is located at www.rsppermian.com and can be viewed by clicking on the Latest Presentation link on the bottom of our home page.

Before we begin, I would like to remind all participants that our comments 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 our filings with the SEC, including our annual report on Form 10-K and quarterly report on Form 10-Q available on the SEC's website at www.sec.gov.

Today's call may also contain certain non-GAAP financial measures. You can refer to our press release for important disclosures regarding such measures and their reconciliations. You can obtain a copy of our press release in the News Releases section under the Investor Relations tab of our website.

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

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [3]

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Good afternoon, and thank you for joining our call today. I'm pleased to report solid results this quarter, in line with and in some cases, exceeding our expectations. We view 2017 as an important execution year for us given our strategic entry into the Delaware Basin, and we are pleased with the progress we've made particularly in building out the infrastructure necessary to support our ramp in production in the second half of the year. We plan to keep our remarks brief today as we run through a few highlights of the quarter.

On March 1, we closed the acquisition of SHEP II and assumed full operational control over the Silver Hill Delaware Basin properties. Despite moderating our completion pace in the Delaware Basin as we enhance infrastructure, we achieved nice growth in our Midland Basin assets. And with acquired production from the Silver Hill transaction, our quarterly production increased more than 80% over the first quarter of 2016.

I now invite you to turn to Slide 4 of our presentation, which highlights a few notable Delaware Basin wells. Well #9, the Crockett Reese State #2403H, represents our most recent completion and the first RSP drilled and completed well in the Delaware Basin. Early performance looks strong at a 7-day average rate of 1,882 Boe per day and still cleaning up with an average flowing casing pressure of 2,500 psi.

Our non-op partners and offset operators also continue to enjoy excellent results in and around our Delaware assets across a number of target zones. Wells 5 and 8, are Anadarko-operated Hughes Talbot wells, in which RSP owns a working interest. Note that these 4,500-foot wells had strong IP-30s of 1,545 and 1,978 Boe per day. You can see from the choke setting and pressures that Anadarko takes a more aggressive approach to flowing back wells than Silver Hill did.

Slide 5 details some of our recent Midland Basin completions. Number 10 on the map is the Parks Bell 3924H well. This Wolfcamp A well had a 30-day IP of 1,550 Boe per day. This is significant because it is our westernmost Wolfcamp A completion in the Midland Basin today, and we do not carry Wolfcamp inventory in this area. This highly productive well gives us confidence that the Wolfcamp will be prolific in this area and that locations to our inventory in a highly economic drilling target that we'll compete for capital.

The Spanish Trail 3441H Wolfcamp A well completed in December of last year, #3 on the map, continues to impress with 90 day cumulative production of 147 MBoe. On a per lateral foot basis, this is one of our top-performing wells to date. Also of note on this slide is the continued strong performance of the Mask area wells, #1 and #2 on the map, averaging cumulative production of 225 MBoe per well over the first 180 days.

While our Delaware assets have dominated much of the dialogues surrounding our business in recent months, we want to emphasize that the our Midland properties continue to outperform our expectations across the breadth of the position and anchor our growth in the near term.

I'll now turn back to Slide 3 to summarize. We expect to grow production approximately 90% in 2017 and have visibility to 30% plus production growth and spending within cash flow in 2018 and beyond, all assuming a $55 oil price. After closing the Silver Hill acquisition, we have more than 30 years of highly economic drilling inventory, with strong well results and leading capital efficiency metrics and cash margins, our average well pays out in less than a year. Our net debt to EBITDAX is 2x pro forma SHEP II and continues to decline.

We have no borrowings outstanding on our $1.1 billion borrowing base and an attractive hedge position supporting our planned CapEx budget, while leaving significant upside exposure to our oil prices.

Our operational team has proven its ability to achieve a manufacturing type efficiency in the Midland Basin, streamlining infrastructure, managing services and driving down capital and operating costs, and has a clear line of sight to achieving similar efficiencies in the Delaware Basin. And importantly, we've demonstrated our commitment to capital efficient growth, not just growth for growth's sake.

Consistent with that goal, we have been preparing our Delaware assets to accelerate production and reduce costs in the second half of the year. Given progress to date, we've moved up our time line and we will be adding a third rig in the Delaware Basin in May, as opposed to 3Q as originally contemplated. Based on the lag time between drilling and completion activity and the result in production, we continue to expect growth out of the asset to be weighted towards the back half of this year.

And with that, I will hand the call over to Scott.

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Scott K. McNeill, RSP Permian, Inc. - CFO and Director [4]

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Thanks, Steve. Slide 6 provides a snapshot of our drilling and completion activity for the first quarter. We ran 4 rigs for the majority of the quarter in the Midland Basin, with one full time completion crew. In the Delaware Basin, we moved from 1 to 2 rigs with the close of SHEP II and ran a part-time completion crew throughout the quarter.

On our operated properties, we drilled 21 and completed 14 horizontal wells during the first quarter. There were also 2 additional Delaware Wolfcamp A wells completed prior to the SHEP II closing that are not included in our completion count for the quarter, but will impact our production profile. On our non-operated properties, we participated in the drilling of 9 and the completion of 8 horizontal wells during the quarter. We ended the quarter with 18 operated drilled, but uncompleted horizontal wells.

We've been continuing to block up our core acreage positions in both the Midland and Delaware Basins this quarter as shown on Slide 7. We acquired approximately 770 net acres for $17 million, and executed acreage trades for over 2,000 net acres, enhancing our working interest and creating additional long-lateral drilling opportunities.

Turning to Slide 8. This slide summarizes our financial results for the first quarter of 2017, with production growth of more than 80% over the first quarter of 2016 and 50% higher crude oil prices over the same time period. We grew our EBITDAX by approximately 250% to $124.5 million, which exceeded our CapEx spent for the quarter.

On the cost side, per Boe cash operating expenses ticked up slightly this quarter, consistent with our expectations as we incorporated the Delaware properties. We incurred high water disposal cost in the Delaware Basin in Q1, as we continue to truck a significant amount of water to third-party disposal facilities.

We expect next quarter to be a bit higher on LOE per Boe, as we have the full impact of SHEP II in our results. However, we expect these costs to decrease in the second half of the year as we transition from trucking to piping water into our company-owned disposal facilities. We also expect G&A per Boe to trend down over the course of the year, with the full benefit of the SHEP II volume and our production growth in the second half of the year.

In general, we expect to experience some lumpiness in our financial results until we have the full contribution of our Delaware asset as well as the impact of operating improvement that we are working on, and those are incorporated into our results.

Slide 9 summarizes our financial position as of March 31, 2017. With no near-term maturities, $54 million of cash on hand and no borrowings outstanding on our $1.1 billion borrowing base, we feel well positioned to accelerate into the second half of this year.

Turning to Slide 10 that details our hedging schedule. We have approximately 54% of our anticipated remaining 2017 oil volumes hedged to WTI at a weighted average floor price of $44.78, while maintaining significant exposure to upside in crude prices. We continue to monitor the market for opportunities to layer in additional hedges for 2018. Our portfolio of Midland to Cushing basis swaps represents approximately 33% of our anticipated remaining oil volumes in 2017.

Slide 11 reiterates our full year 2017 guidance, which hasn't changed since our year-end update. From our current count of 6 rigs, we plan to add 1 additional rig in the Delaware Basin in May, ahead of our previously scheduled start date in Q3. And as previously communicated, we plan to add another rig in either the Midland or the Delaware Basin in Q4, exiting 2017 at 8 rigs.

We expect our daily production to average between 53 and 57 MBoe per day, with approximately 72% oil and 88% liquids. We anticipate spending $663 million of development capital at the midpoint of the range, with $600 million for drilling and completion and $63 million for infrastructure and other.

Slide 12 is the preliminary outlook into 2018 and 2019 that we put out last quarter. This outlook is based on an oil price range of $45 to $55 per barrel, above or below that [bed] you'd likely see us either accelerate or pull back on activity levels.

Assuming a $55 oil price, our anticipated production growth of approximately 90% in 2017 should result in a slight cash flow outspend with our leverage ratio coming down below 2x. Assuming a moderate ramp in rigs at 2 per year in 2018 and 2019, we have visibility to achieve an excess of 30% production growth per year and would expect to be cash flow neutral at $55 oil beginning in 2018, with leverage less than 2x.

We look forward to reaching these targets in continuing to deliver leading debt-adjusted growth and return to our shareholders. Thanks again for joining our call this afternoon, and now I'll turn the call to questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question is coming from Charles Meade of Johnson Rice.

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Charles A. Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [2]

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I wanted to ask a question about that Parks Bell, the Parks Bell Wolfcamp A well to the West. As I understand it, the Wolfcamp as you move West to the Midland Basin towards the Center Basin Platform starts to thin that way. And I know you guys have made some Spraberry wells over there before. But can you tell us why that Wolfcamp was not in your inventory there? Was it because it got thin in that direction? And if it's going to be in your inventory now, is it just going to be one horizon or one target interval? Are you going to have -- or you going to have Wolfcamp A, B and down?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [3]

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Charles, this is Steve. Keep in mind, originally, everyone was developing the Wolfcamp B over there. And then the B -- the A and the B do get thinner, but they also look -- kind of transition from a shale to a carbonate. So in particular, the Wolfcamp B looks like a carbonate in most places over there and we never felt like it would be productive. However, the Wolfcamp A is still present and it's still a shale for the most part. And so after we drill some really nice Wolfcamp A wells over to the East, we decided that we should probably test it on that side, and it definitely exceeded our expectations. And so as you look at the Wolfcamp A there, we still think we have quite a few more locations along that access and for a mile or so further West. So I asked the [reservoir] engineers what they thought, and they thought we'd probably have 20 or 30 locations over there that we weren't carrying in our inventory that we probably could be now. I don't think the story changes much for the Wolfcamp B. I don't think we're going to be adding that in our inventory for the time being.

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Charles A. Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [4]

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Got it. That all makes sense. That's good detail. And then I'm guessing there's going to be a lot of questions about the Delaware later, so I'm going to ask one more about the Midland Basin. The Calverley well that you guys drilled in the quarter, the 9-4 7H, I know that you guys have made a lot of really good Wolfcamp B wells over there, and that one looks like it's probably on the bottom half of the wells that contribute to the average. Is that the right take? And is there anything to read into that result?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [5]

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Charles, this is Zane. That's just a gas lift well and it's just performing now as we feel within line. It maybe a little less flashy, but it's certainly producing flatter.

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Operator [6]

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Our next question is coming from Dan McSpirit of BMO Capital Markets.

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Daniel Eugene McSpirit, BMO Capital Markets Equity Research - Equity Analyst [7]

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And just turning to Slide #7, where you lay out your bolt-on acquisitions and trades. How much of the Delaware acreage today can accommodate lateral lengths, let's say, 7,500 feet or longer? And where is the company in the process of blocking up acreage, either through purchases or swaps, recognizing that $17 million or so was invested in the quarter?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [8]

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This is Zane. It's quite a contiguous block that has a lot of optionality to it. And we probably can drill 7,500-foot laterals or longer on 75% of it, and we will continue to block it up and make trades.

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [9]

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I'd further say that, I think, in this year's inventory about half of the wells we have planned are 7,500 feet and about half are the 1 mile laterals. So our average for the year is probably 6,200 or so. By next year, it will probably be trending more towards 7,000, 7,500 for the average.

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Daniel Eugene McSpirit, BMO Capital Markets Equity Research - Equity Analyst [10]

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Got it. Okay. Great. And as a follow-up to that, just maybe a question on portfolio management, appreciating you folks are realizing success across your leasehold, both in the Delaware and Midland Basins. If we look at, say, 12 months or so from now, what basin, Midland or Delaware or maybe operating area within those basins, do you expect will deliver superior returns or the best returns? Or maybe put differently, which are candidates for divestiture because they can't compete on returns however economic they may prove to be?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [11]

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Well, if look at what we think we'll be doing, and it's always subject to change, but right now, I think, we're going to exit the year, start next year with 8 rigs running. And we would like to have 4 in the Delaware and 4 in the Midland. If you look at the well cost in the Delaware being a little more expensive than the Midland, that would sort of imply we'll probably spend 60% of our capital next year in the Delaware, although I don't think that would be a firm number yet. But the returns from what we can see in the Delaware, at least in the Wolfcamp, could be superior to what we have in the Midland Basin. So if that holds true, then it would make sense that we will spend more capital over there next year than what we do in the Midland Basin.

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Operator [12]

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Our next question is coming from Irene Haas of Wunderlich Securities.

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Irene O. Haas, Wunderlich Securities Inc., Research Division - SVP and Senior Equity Analyst [13]

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So I'm looking at your Delaware Basin asset, that's always been a fantastic piece of real estate and also noticing that there are some pretty good wells being drilled North of the border. And would you guys have any interest in New Mexico understanding that the federal permitting process is getting a little easier? Just checking.

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [14]

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Yes. Irene, this is Steve. I have operated -- we have companies that operated in New Mexico for 20 years. And so I'm not allergic to operating in New Mexico by any means. And you're correct, just North of us, there are some excellent results. So we haven't seen any compelling reasons to go over there yet that would fit us, but we don't rule it out.

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Operator [15]

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Our next question is coming from Kashy Harrison of Simmons Piper Jaffray.

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Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - VP and Senior Research Analyst, Exploration and Production [16]

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So in the Delaware, it looks like some of your competitors in Winkler County, and here I'm looking at Page number -- Slide #4, Wells #10, 11. The results look pretty promising. I was just wondering, could you provide an update on your current thoughts on the prospectivity of the Wolfcamp B in that county?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [17]

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This is Zane. We like the prospectivity as we know it today in both the Wolfcamp B and the Wolfcamp A. The Wolfcamp A as it trends to the East into Winkler County, loses the XY sands in the upper part of it, but it retains all of the productive shale characteristics like the lower Wolfcamp A. It's being drilled further to the West. Right now we're shooting 3D seismic over that, and so as soon as we have that 3D seismic in hand and can lay down our wells, you'll probably see us more active over there. But we certainly like the positive indicators we're seeing from offset operators.

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Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - VP and Senior Research Analyst, Exploration and Production [18]

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Got it. And then maybe switching gears to LOE. So once all the infrastructure is in place, what do you think the LOE in the Delaware Basin is going to look like relative to the Midland Basin?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [19]

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Yes, I think, it's going to be very comparable. The big driver over there that's making it higher has been -- we're having to truck produce water. And so once we alleviate that bottleneck and can go to our own disposal wells, I feel like the LOE over there won't be materially different than what we're seeing in the Midland Basin.

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Operator [20]

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Our next question is coming from Subash Chandra of Guggenheim Securities.

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Subash Chandra, Guggenheim Securities, LLC, Research Division - Analyst [21]

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How should we think about full field development in the Delaware? Is it going to be a series of pilot testing, the optimal pad and then rolling that out including Bone Spring in that? Or is it -- would you want to induce cash flow growth and do that kind of stuff before figuring out what the optimal pad might look like?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [22]

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Subash, this is Zane. We're not going to be able to give you a straight answer on that today because we are going to be doing some different testing of zones. You'll see us drill complete second Bone Springs, third Bone Springs, a different landing zone in the WA and we're going to be doing some microseismic off of a 3-well pad that we're going to be drilling with that new rig when it comes in. And so those are a number of things we're going to be entering for ourselves throughout the remainder of the year, and we'll just have to give you further details on that later on.

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Subash Chandra, Guggenheim Securities, LLC, Research Division - Analyst [23]

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Yes. No, I appreciate you just got your hands on this stuff. The follow-up is, what's the status of the 3D seismic? And how do you think it might influence how you drill these wells?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [24]

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Well, the 3D seismic certainly helps us in our geosteering models and helps us identify particular landing zones that we're interested in. We have used it very well in the Midland Basin, and we know we're going to be able to use it here. We had existing 3D on the Northwest portion of the properties, but we need 3D on the East and to the South. And that 3D is being permitted right now and we should start acquiring here fairly soon, but we don't expect to have that 3D in hand to be able to analyze it until quite later into the year. But a fair amount of our drilling that we're doing now is utilizing the 3D and we're already changing landing zones that (inaudible).

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Operator [25]

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Our next question is coming from John Freeman of Raymond James.

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John Christopher Freeman, Raymond James & Associates, Inc., Research Division - Research Analyst [26]

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When you all discussed the 8th rig that's going to get, or hopefully added, at the end of the year, it sounds like an ideal world. Steve, you mentioned having an equally split Delaware and Midland with 4 and 4. Is really the one thing you're sort of waiting for is to see what the infrastructure situation looks like in the Delaware before committing to that?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [27]

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Yes. That's right. I think as long as -- Targa bought that gas plant from Outrigger and as long as they've done the expansion work that they've told us they're going to do and we're not having any takeaway issues with gas, then that's where that rig is going. But we're hedging our bet a little bit if for some reason there was a bottleneck, we might go ahead and bring it in to the Midland Basin and drill a few wells and then we could move it over to the Delaware whenever we feel like it's the right time.

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John Christopher Freeman, Raymond James & Associates, Inc., Research Division - Research Analyst [28]

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Okay. And then my one follow-up question. Last quarter, when you all detailed some of the workovers you all have done and putting some of these wells on the list, the one at least, at the time, that it seen the biggest improvement was actually the second Bone Spring. And I'm trying to get a sense of, obviously, that's been the zone that's had probably on you all's area, the least activity. I'm just trying to get a sense of, if that's something in the near term you'd plan on testing here? Like can we get a second Bone Spring well from you all next quarter?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [29]

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We just drilled -- we just finished drilling a second Bone Springs well that is about a 7,000, 7,200-foot well. We drilled it 19 days and we'll be completing it in the not too distant future, in a different landing target than it has been utilizing for.

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Operator [30]

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Our next question is coming from Jeff Grampp of Northland Capital Markets.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division - MD and Senior Research Analyst [31]

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Just want to talk maybe a little bit more about the Crockett Reese well, the first well that you guys both drilled and completed. Can you talk a little bit maybe about the completion that you guys utilized there? And if that's going to be kind of the base case design going forward? Or if there's any tweaks you guys are looking in and trying to optimize completions here in the Delaware?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [32]

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This is Zane. Well, those stages were a little shorter and were more of them than our conventional design, that was because of the casing design of the well. I doubt it will be our typical design, but it was a little bit of a pilot test and we'll just have to wait and see. But it was utilizing the 100 mesh, the 2,500-pound loading and also utilize the higher density of perforation clusters.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division - MD and Senior Research Analyst [33]

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Okay. That's helpful. And then the only other one I had, I think I remember last call you guys mentioning doing a 2-mile Middle Spraberry well at some point this year. I just hoping to revisit that, if that's on the drilling schedule in the near term or when we could hear any results on that well.

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [34]

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There's actually 2 of them that we're drilling over in Spanish Trail, and I'm sure we'll have those results by the end of the year. I think they drill fairly soon.

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Operator [35]

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Our next question is coming from Michael Hall of Heikkinen Advisors.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst [36]

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I'm just curious, can you give us kind of what the real-time well costs are looking like for -- like full drilled, completed (inaudible) in the Southern Delaware and how that compares relative to the acquisition assumptions?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [37]

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Well, I wish I could tell you more about it. But since we've only had our arms around that property for a few days or just a couple of months now, we probably only got one well that we actually drilled and completed, from [soup to nuts] or so. And so I could tell you that one data point came in about how we had expected. But really one data point is not enough for me to tell you what I think they're going to be going forward. So I think, in 90 days, when we do another update, we'll try to come out with more details on where we see cost going. But it's kind of preliminary [gross] to try to speculate right now.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst [38]

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Fair enough. Understood. How about just more broadly or generally as it relates to conversations with your service providers, has that evolved at all over the course of the year with volatility in the oil price?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [39]

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Yes. We, obviously, are seeing some price increases along with other operators out there. In certain spots, it hasn't really changed. In other spots it's changed pretty dramatically. Sand, for right now, has gone up pretty drastically and steel has gone up pretty drastically. So in spots like that, we're seeing some 20% or 30% type price increases. In another spots, it's marginally higher. So overall, we still believe costs of about 10%, 15% from what we saw in the last few years. And I can't really speculate where I think it's going to go from here. I see service cost going up and I see oil prices going down, and so those 2 have to kind of come together somewhere along the way this year. If oil prices stay down, I expect we won't see a whole lot more increase in service cost. We'll see. But right now I think we're still maybe 13%, 15% higher than last year, is where we're seeing.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst [40]

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Okay. That's helpful. Yes, that's kind of what I was trying to understand that dynamic with oil price coming down and cost similarly going up. I guess last time (inaudible) would be just, you all have some basis swaps in place. I'm just curious on how you intend to manage kind of basis risk or your net backs over the next couple of years. Any willingness to sign up for firm capacity out of the basin on any of the announced projects? Or just kind of where you all heads at on all that?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [41]

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No. We're not looking at trying to buy from transportation out of the basin, but we are looking at trying to firm up some barrels longer term with some of our midstream partners that (inaudible) do that firm transportation on those products. So our -- we've never felt like that was a space that we wanted to play until we get bigger. And so we prefer to just partner up with some guys. And we've actually had some really good options come our way for this Delaware Basin asset. We have multiple pipelines in that area that are interested in the barrels and got some options on the table that we're looking at right now. So I think the good news is we've got some optionality there and we're pretty excited about the fact that we really haven't seen the constraints or the issues out there that some people might be concerned about.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst [42]

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Okay. That's helpful. And then, I guess, as a quick follow-up to that, to what extent are you still -- or are you trucking crude on the Delaware Basin side? Any material distances?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [43]

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No. As far as crude oil goes, we're not trucking hardly any of it. It's a -- there's a gathering system [employee].

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Operator [44]

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Our next question is coming from David Snow of Energy Equities.

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David Snow, [45]

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Do you have any updated thoughts on well density, well expansion?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [46]

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Well, are you talking Midland Basin? Are you talking Delaware Basin? Are you talking about...

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David Snow, [47]

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Well, both, whatever I can get.

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [48]

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Well, I mean, you've seen what we put out on the Midland Basin numerous times. And as we said last quarter, we're in the midst of a number of different pilots. We're gathering information on that pilots and we're still drilling out some of those pilots. And we really have nothing further to say about it because we don't have any significant additional data since the last quarter. So -- but we have seen nothing negative on any of our spacing task at this time. It would indicate that we need to move our wells at greater distance apart. That's on the Midland Basin side. On the Delaware Basin side, we're looking at wells people are indicating around us that have done more testing than we have. We're talking about industry leaders to the North, to the West, to the South. And so we're looking at what they're saying and we're planning some additional testing on our sales. And so on the Delaware Basin side, you're just going to have to give us a little bit of time before we really say what our base spacing is going to be. But it fits within what our peers that surround us are saying.

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David Snow, [49]

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And I noticed that your docks are going up, are you going to catch up to those at some point or what's happening there?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [50]

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Yes. It's coming. That's an intentional build as we ride on infrastructure, primarily in the Delaware.

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [51]

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And also, were just talking about that. We added a rig in January. So anytime you add a rig and just, by definition, you're going to have a few (inaudible). It wasn't an intentional build other than the fact that we added a rig and we are (inaudible) a little bit the infrastructure (inaudible). But we'll probably work back down over the next couple of quarters.

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [52]

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Yes. And you'll see us running an additional frac trail on the Midland side in the second half of the year.

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Operator [53]

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Our next question is coming from Richard Tullis of Capital One Securities.

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Richard Merlin Tullis, Capital One Securities, Inc., Research Division - Senior Analyst [54]

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Roughly, how much production do you think could be added in the second half of this year from existing Delaware Basin wells once the adequate infrastructure is in place related to wells currently restrained due to infrastructure restricted chokes, et cetera?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [55]

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This is Zane. That will be fairly minimal because we'll be adding them sporadically as we do our additional completion work. And so I don't think that you're going to see some huge impact. Some of those wells don't need to be put on artificial lift, yet. And so that will be scattered out over the amount of time that you're not going to see some huge incremental impact from that.

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Richard Merlin Tullis, Capital One Securities, Inc., Research Division - Senior Analyst [56]

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Okay. That's helpful. And then just lastly, although its smaller piece of the total cost puzzle, what are the day rates looking like for the newer rig contracts you're currently signing or looking at for later this year compared to, say, what you were paying last year on a day rate basis?

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Zane W. Arrott, RSP Permian, Inc. - Co Founder and COO [57]

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Well, last year, we were still on a -- 2 of our rigs, last year, were still on their longtime contract, it -- over $26,000 a day. Currently, we're anticipating our average day rate for our full rig fleet for 2017 at somewhere from 17,500 to 18,000 a day, so we're actually seeing an average reduction on day rate from last year.

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Operator [58]

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Our next question is coming from Derrick Whitfield of Stifel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD and Senior Analyst [59]

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Bigger picture on the Delaware. Can you outline your key delineation objectives for 2017, 2018 as you think about bringing this asset in house? And what are the key things you guys want to check off for your checklist?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [60]

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The early indications are that the Wolfcamp A is probably going to be the primary target. But as in the Midland Basin, we also look at whether it makes sense to develop one zone or whether it makes sense to develop several zones at the same time. So we've got to transition to pad drilling. We've got to determine what the proper spacing is and we've got to determine which zones we want to prioritize. And those are all works in progress. As Zane said, we'll be testing multiple zones this year. We might spend 70% of our capital in the Wolfcamp A, but the other 30% is pretty well spread out between the Wolfcamp B, the third Bone Springs, the second Bone Springs, not to mention the fact that there's multiple landing zones in the Wolfcamp A. So I expect that we'll spend some time, time is determine which zones we believe are most prolific and what the proper order in which we'd like to develop from this. And at the same time, we're looking at going to pad drilling, whether that's 2 well pads or 3 well pads or 4 well pads. And then at the same time, it's about getting the water infrastructure built out. I mean, it's about working closely with Targa to make sure that the gas takeaway and the gas plant are built out as -- in time to keep up with our drill plans. So I mean those are the main initiatives that we'll be working on for the next 12 months. And I think probably, early next year, we'll have a lot clearer picture on which zones we're going to target and what we believe the proper spacing is going to be.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD and Senior Analyst [61]

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Very helpful. And then still bigger picture. Other than Midstream and science, are there other any gating factors in the Delaware that would prevent you from ramping activity beyond 4 rigs?

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [62]

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Good question. I don't think that there's anything significant other than that, that we've on. I think that all systems are go once we get the infrastructure in place.

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Operator [63]

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At this time, I'd like to turn the floor back over to management for any additional or closing comments.

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Steven D. Gray, RSP Permian, Inc. - Co Founder, CEO and Director [64]

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Thank you, everybody, for joining the call today. I just like to say also thanks to all of our employees for all the hard work they've done in getting the Silver Hill deal closed and sort of getting the properties assimilated. We're looking forward to an exciting year at RSP as we bring those properties in and start to accelerate development on them. If you have any additional questions you have for us, please feel free to give us a call. Thank you again.

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Operator [65]

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Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect you lines at this time, and have a wonderful day.