RSP Permian (RSPP) Steven Gray on Q2 2016 Results - Earnings Call Transcript

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RSP Permian, Inc. (NYSE:RSPP)

Q2 2016 Earnings Call

August 09, 2016 11:00 am ET

Executives

Scott McNeill - Chief Financial Officer & Director

Steven Gray - Chief Executive Officer & Director

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Analysts

Michael Dugan Kelly - Seaport Global Securities LLC

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

Scott Hanold - RBC Capital Markets LLC

Jeff S. Grampp - Northland Securities, Inc.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Will O. Green - Stephens, Inc.

Kashy O. Harrison - Simmons Piper Jaffray

David G. Snow - Energy Equities, Inc.

Operator

Welcome to the RSP Permian Second Quarter 2016 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 will like to turn the call over to Mr. Scott McNeill, Chief Financial Officer of RSP Permian. Thank you, sir. Please go ahead.

Scott McNeill - Chief Financial Officer & Director

Thank you. We appreciate you joining us today as we discuss RSP Permian's second quarter 2016 financial and operating results. With me are RSP's Chief Executive Officer, Steve Gray and Zane Arrott, our Chief Operating Officer.

Yesterday, after the close, we issued our second quarter 2016 earnings release and filed our Form 10-Q with the Securities and Exchange Commission. In addition, we posted a new earnings presentation to our website, which we will reference during the call. The earnings presentation is located at www.rsppermian.com and viewed by clicking on the latest presentation link on the bottom of our homepage.

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 Reports on Form 10-K and Quarterly Reports on Form 10-Q available on 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 the 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?

Steven Gray - Chief Executive Officer & Director

Thank you for joining our call this morning to discuss our second quarter 2016 financial and operating results. I will touch on the highlights of the quarter and a few slides before handing the call over to Scott and Zane for the financial and operational update.

As you can see on slide four of our investor presentation, we grew production by 7% in the second quarter compared to the first quarter of 2016 and by 33% over the second quarter of last year. We also continued to achieve low cash operating expenses of $9.99 per Boe.

As a result of our production growth and realized oil prices averaging $42.50 per barrel, we generated $58.5 million of adjusted EBITDAX and spent $57.6 million on CapEx in Q2. So even with sub-$45 oil, we generated more in EBITDAX than we spent in capital. It is this strong capital efficiency and lean cost structure that positions us well to handle the recent pullback in oil prices and to excel as oil prices recover.

As you know, coming into 2016, we slowed our drilling pace. At the beginning of the year, our board approved a $200 million to $260 million capital budget that contemplated us running two operated rigs with a potential to add a third rig late in the year if commodity prices improved. Our operating plan entailed utilizing our drilled but uncompleted well backlog to backfill and keep our dedicated completion crew busy on a full-time basis.

We had intentionally built up a sizable backlog of drilled but uncompleted wells to provide us with flexibility to operate at a lower rig count. During our first quarter earnings call, we discussed that $45 oil represents an inflection point for both the returns on our wells become more attractive and adding a rig begins to de-lever the company.

As a result of prices moving above $45 during the quarter and us putting in additional $45 puts, we contracted a third horizontal rig in Q3 for a one-year term at $13,500 a day. We continue to have flexibility, however, with our rig cadence as our two existing rigs come off contract in early 2017. So should oil prices deteriorate, we can easily elect to moderate our drilling pace in the first quarter of next year.

During the quarter, we more than doubled our hedged oil position for the rest of 2016. We now have 67% of our remaining 2016 oil volumes protected with $45 puts, which limit our downside while leaving upside in oil prices to the benefit of the company.

As you can also see on slide four, we have increased our production guidance for 2016, and at the movement point, we expect to grow production by 31% over 2015. Our increased production guidance is a result of better-than-expected production growth year-to-date and our expectation of strong future well results due in large part to our improved completion designs which Zane will discuss in more detail.

We also expect to see a minor production impact in 2016 from increasing our completion activity in the back half of the year, specifically, we are raising our production guidance 10% at the midpoint as Scott will discuss in more detail in a moment.

Slide five highlights how all of our wells completed year-to-date performed relative to our weighted average type curve. You can see that our actual results track well above the average type curve. We included several R&D wells in our 2016 results where we didn't attempt to maximize rates and the wells' upfront performance was impacted by testing different completion or production methods, or holding back production to perform various analyses.

The continued outperformance of our wells enables us to feel comfortable raising our forecast for the remainder of this year. I would also like to point out that our technical work should continue to lead to better well results, tighter spacing of laterals, higher recoverable reserves and lower overall costs as we proceed through our development of this world-class asset.

Slide six highlights our acquisitions this year. So far in 2016, we have spent $55 million primarily on bolt-on acquisitions to our existing asset base. You can see that these acquisitions have been highly accretive at attractive acquisition costs. We are frequently asked about potential M&A. My response is simple, we have been active historically and we will continue to be active. However, RSP is fortunate to have a deep inventory of high-return horizontal locations and decades of inventory life, so we have the ability to be patient and selective.

Slide seven shows our significant historical production growth. We have more than tripled our daily production since our IPO. And you can see that, even through the downturn, we have continued to grow despite moderating our CapEx. However, as we have said many times before, we focus on generating strong returns on our invested capital and not just growth for growth's sake.

So as you can imagine, the recent volatility in oil prices creates a fairly large range of potential outcomes for the company next year. With this in mind, we provided slide seven to help illustrate how the company might look on an annualized basis at various oil prices.

Although, we cannot say for certain how many rigs we will run next year or what our growth might be, slide seven shows that at $55 oil, we would be comfortable ramping up to five operated rigs where we would expect to grow production by approximately 30% or more and achieve a leverage profile under two times EBITDAX.

Slide seven also demonstrates that at a $40 to $45 price, we could still grow our production and have a leverage profile under four times EBITDAX. So, in either scenario, we are growing and doing so without jeopardizing our balance sheet.

With that, I will now turn the call over to Scott McNeill. Scott?

Scott McNeill - Chief Financial Officer & Director

Thanks, Steve. Turning to slide eight, we've highlighted a few financial and operational items. Our production averaged 26,407 Boe per day during the second quarter; 73% oil, representing a 33% increase from the second quarter of last year, and a 7% increase compared to last quarter. As Steve mentioned, our 2016 wells continue to exceed our expectations and have allowed us to drive production growth despite our moderated CapEx program.

We generated $58.5 million of adjusted EBITDAX during the second quarter, which was 64% above last quarter and 19% below the second quarter of 2015. Including the impact of hedges, we had higher realized pricing on our oil and NGL volumes and lower realized pricing on natural gas as compared to last quarter, with oil up 37%, NGLs up 99% and natural gas down 10%.

We maintained our efficient cost structure this quarter with cash operating cost of $9.99 per Boe. This represents a 26% reduction from a year ago and is consistent with last quarter. We lowered our LOE, excluding gathering and transportation, to $5.37 per Boe, representing a 30% reduction from the second quarter of last year and a 3% reduction from last quarter.

We decreased our development capital expenditures by 61% from last year's second quarter and by 15% from the first quarter of this year, spending $56.5 million on drilling and completion and $1.1 million on infrastructure and other. We spent a total of $14 million on acquisitions this quarter, primarily to acquire additional interests in our core areas.

Turning to slide nine, note that we ended the quarter with $33 million of cash on hand and an undrawn $600 million revolver. With no near-term debt maturity and moderate leverage levels, we have significant financial flexibility and we'll remain selective in our use of the capital markets.

Slide 10 provides an update on our current hedge position. Over the past quarter, we have layered in incremental $45 per barrel deferred premium puts that more than doubled our existing downside protection at $43.44 per barrel, net of deferred premiums, while retaining upside to potential oil price increases. To-date, we have hedged roughly 67% of our estimated oil production for the second half of 2016 based on the midpoint of our guidance range. We will continue to opportunistically increase our hedge profile in 2017.

Slide 11 details our revised annual guidance versus our previous guidance and actuals for the first half of 2016. We are pleased to report that each item fell within our original guidance range or better during the first half of the year. We have raised our production guidance to a range of 26,500 Boe to 28,500 Boe per day for 2016. We are also increasing our full year CapEx to a range of $285 million to $315 million, which includes the addition of a third operated drilling rig in Q3 and increased the number of operated completions to 54, at the midpoint of the range, and an increase to our non-operated capital budget from approximately $20 million to $40 million.

Our non-op CapEx in the first half of the year was about double what we had originally forecasted early in 2016, and we expect the other operators to continue at a more elevated pace. One thing I want to emphasize on our revised guidance is that the large majority of our additional investment and completions in the back half of the year will not significantly impact our 2016 production, but will serve to increase our operational momentum and growth profile coming into 2017.

With that, I will now turn the call over to Zane to discuss our operations. Zane?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Thank you, Scott. Slide 12 provides a snapshot of our activity this quarter. On our operated properties, we drilled 10 horizontal wells and no vertical wells. We completed 11 operated horizontal wells and one vertical well. Of the 11 operated horizontal completions in the quarter, 10 were in the Lower Spraberry and one was in the Wolfcamp.

On our non-operated properties, we participated in the drilling of 10 horizontal wells and the completion of six horizontal wells. We ended the quarter with 19 operated, drilled but uncompleted horizontal wells, representing a 5% decrease from last quarter. On the non-operated side, we ended the quarter with 24 drilled but uncompleted horizontal wells, representing a 20% increase over last quarter. Our inventory of wells waiting on completion is distributed across our core acreage position.

Turning to slide 13, you'll note that we're on track to complete 52 to 56 operated horizontal wells this year, 22 of which were completed in the first half of the year and we expect to exit the year with eight to 12 operated wells waiting on completion. We ran a second frac crew for a short time in early 3Q in order to accelerate the reduction in our drilled but uncompleted inventory that had grown due to us drilling more wells on multi-well pads. Over 50% of the completions planned for the last half of the year will target the Lower Spraberry.

Slide 14 highlights our continued progress in reducing well cost. During the first quarter, we were writing AFEs for 7,500-foot horizontal wells at $5.25 million and seeing naturals very close to that amount despite significant R&D expenditures on many of the wells and our two rigs at a day rate far above current market rates.

During the second quarter, we generated additional well cost reductions and are now drilling and completing 7,500-foot laterals for approximately $5 million. Although, our latest generation frac designs are approximately 25% more expensive than the prior vintage, we still expect to drill and complete future wells for approximately $5 million.

Slide 15 describes our approach to optimizing stimulations and the evolution of that work to-date. For the last few quarters, we have tested numerous high-density completion designs. We have systematically varied a number of key drivers in the stimulation design such as cluster count and configuration, sand volume and mesh size and diverter agents. The graph at the bottom of the slide shows that we have seen robust increases in well productivity as our frac design has evolved, while simultaneously realizing a reduction in our average well cost.

Ultimately, our goal with this testing is not only to increase productivity and EURs per well, but also to increase per section or per acre recoveries. As we experiment with tighter spacing, we plan to simultaneously decrease the potential interference between neighboring offset wells. Our focus is to more intensely stimulate near the wellbore and thus increase our recovery of oil in place within a smaller rock volume, allowing us to meaningfully increase well density within a given development unit. The results we have seen today support this approach.

Slide 16 highlights the outperformance of our initial Calverley wells in Glasscock County in comparison to our expectations. As you can see, our two initial Calverley wells performed significantly above our peer estimated type curve of 1 million Boe. Despite early time R&D efforts on the 9-4 Lower Wolfcamp B and 9-3 Lower Spraberry wells, both are quickly approaching the 1 million Boe type curve after just over four months of production. We have two additional Lower Spraberry wells which are on electric submersible pump and in the early stages of flowback and two additional Upper Wolfcamp wells scheduled to be drilled in the second half of this year.

Also, on slide 17, we've shown the outperformance of our two Woody area wells as compared to the 1 million Boe benchmark. Notably, both of these wells have lateral lengths of just under 5,000 feet. We want to note this is actual production data and not normalized to 7,500 feet, which would have yielded approximately 1.5 times greater results. We have two additional Upper Wolfcamp wells planned for the fourth quarter of this year, which would utilize new vintage completion techniques.

We are conducting spacing test across the entirety of our core acreage position. Slide 18 focuses on one of our more significant side-by-side spacing pilots located in the Johnson Ranch area, where we are testing a 40% increase in well density over our original spacing pattern in the Lower Spraberry.

Today, we have four wells on production, four wells currently drilling, and the final four wells scheduled to be completed sometime next year. Due to the number of wells remaining to be drilled and the amount of production data required to draw conclusions on well interference, we do not anticipate having any final results from these products in the near term.

With that, I'll open the call to questions. Operator, please open the lines.

Question-and-Answer Session

Operator

Thank you. Our first question is from Mike Kelly from Seaport Global.

Michael Dugan Kelly - Seaport Global Securities LLC

Hey, guys. Good morning.

Steven Gray - Chief Executive Officer & Director

Good morning, Mike.

Michael Dugan Kelly - Seaport Global Securities LLC

Appreciate the scenario analysis for 2017. And my question is really, I guess, for Scott here, and when you're modeling this out, just curious how much credit you baked in for the success you're seeing on the enhanced completion front within that 10% to 30% growth rate in that $45 to $55 scenario? Thanks.

Scott McNeill - Chief Financial Officer & Director

Yeah. Not much, Mike.

Michael Dugan Kelly - Seaport Global Securities LLC

So how...

Scott McNeill - Chief Financial Officer & Director

We're still using our existing type curves when we're baking in our forecast for 2017.

Michael Dugan Kelly - Seaport Global Securities LLC

Okay. Good to know. And then just, Steve, you said that you expect you guys to continue to be involved in the M&A front and just wanted to kind of get your gut feel on a couple of the trends that we're seeing across the Permian right now, I think, one, just this move to the Delaware Basin. I know that you've been involved there in the past. You screened a lot of deals there. Just curious if at $30,000 an acre, if that's a price that you think RSP would be willing to establish a position and pay that sort of price or do you think the industry has maybe gotten a little bit of ahead of itself in paying those types of numbers? Thanks.

Steven Gray - Chief Executive Officer & Director

Yeah, that's a good question, Mike. I think that there is probably places in the Delaware Basin and it's not a blanket statement, but I think there's places in the Delaware Basin where those kind of values may be justified, but it's going to boil down to de-risking enough of those different benches over there that you'd feel comfortable paying for them and I think that's where it's headed. Obviously, the well results are improving faster in the Delaware Basin and they are kind of closing the gap. And so, we don't doubt that you're going to see more transactions in that price range.

And I think, selectively, there probably are places, but to justify those kind of prices you have to feel pretty comfortable about several different benches working. And I think it's getting there and parts of the basin, I think, they'll continue to de-risk some of the other zones over there. And so, yeah, we've been a little bit surprised by some of the prices we've seen, but I can understand that as their well results improve and they get their drilling costs down, why that gap is closing.

Michael Dugan Kelly - Seaport Global Securities LLC

Got it. Appreciate it.

Steven Gray - Chief Executive Officer & Director

You bet.

Operator

Our next question is from John Freeman from Raymond James.

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

Hi, guys.

Steven Gray - Chief Executive Officer & Director

Hi, John.

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

Just following up on Mike's questions, when looking at that rig sensitivity slide on slide seven, how do you all sort of think about sort of the costs in the, let's say, the $55 plus type oil environment? And obviously to Scott, a great deal getting that one-year term on that rig at $13,500 a day, I'm just curious when you're thinking through kind of leverage metrics and everything, how do you factor in what costs do?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Hey, this is Zane. Well, we are – our completion costs have probably increased a little bit because of the type of completion we're doing now. But we see two rigs coming off long-term contract early next year that right off the bat are going to reduce well cost $200,000 per well at least.

We see some price pressure in all likelihood as rig utilization rates increase, but we don't see much at all yet. We know pressure pumping at some point will have to have some increase in what they're charging, but until you get a much higher utilization rate, we don't see that occurring either. So, 2017 is not much of a concern to us, as we model out higher oil prices, we do model in some increasing cap cost.

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

Great. And if I could, just my one follow-up, when I think about the 2017 scenarios, should we assume that the mix between the various zones basically stays pretty similar to what the current mix is?

Steven Gray - Chief Executive Officer & Director

Yeah.

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

In terms of capital allocation?

Steven Gray - Chief Executive Officer & Director

Yes, for capital allocation, you'll probably see us running about 50% LS and 50% Wolfcamp – with the Wolfcamp being...

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

Thanks, guys. I appreciate it.

Steven Gray - Chief Executive Officer & Director

Sure. A few Middle Spraberry possibly.

Operator

Our next question is from Scott Hanold from RBC Capital Markets.

Scott Hanold - RBC Capital Markets LLC

Thanks. Good morning, guys.

Steven Gray - Chief Executive Officer & Director

Good morning.

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Good morning, Scott.

Scott Hanold - RBC Capital Markets LLC

Could I ask a question on the evolution of your completion designs. You're talking about now testing tighter spacing and, obviously, trying to break up the rock around the wellbore. Can you talk about like the amount of tonnage and stage spacing that implies relative to, I guess, your base assessment at this point?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Our frac design a year ago was 210-foot spacing on frac stages, four clusters and I think we were up to about 1,600 pounds per lateral foot. All of this year, we have gone through a number of variations of that. We really haven't changed the stage length, but we have been increasing the number of clusters, and we have increased the pounds per foot. I think we've been as high as 2,100 pounds, but that's just been one-off or two-off, we're probably 1,950 pounds right now.

Not that we're saying that that's where we're going to end up, that's just where we're at today, a lot more clusters, diverter, of course, all that has a cost, right? We dropped resin coat, but then we added more sand and a lot more diverter. And so that has increased our frac stage cost a bit. But we don't want to give out our exact recipe, so we're going to be fairly vague about it. Few of our partners are going to know, because they're in the wells with us, but that's just where we're going to sit today.

Scott Hanold - RBC Capital Markets LLC

Okay. And then just to clarify then those spacing tests that you're going to do as a staggered spacing test in Johnson Ranch, but wouldn't be taking that to the next level or will it be kind of consistent with what you've been doing there in 2016?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

As we increase to the tighter spacing on the west side of Johnson Ranch, we will be using our latest frac designs, whatever that will be at the time.

Scott Hanold - RBC Capital Markets LLC

Okay, understood. And then...

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Because we will then get – the spacing will be more dense and so we will really be concentrating on the high density completion techniques.

Scott Hanold - RBC Capital Markets LLC

Understood. And then as my follow up, obviously, you guys are making a case that a number of your wells look like they are modeling toward a 1 million barrel EUR. I know, obviously early (28:30) this year you guys updated your EURs and pushed to call it around 800,000. What all do you need to see to get confidence in the latest completion designs and to put the higher EURs in both your guidance and in sort of longer-term expectations?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Right now, we're going to stick with our current type curves. If we did choose to increase or change them, we would do that in accordance with the third party engineering report at year end. But what we're concentrating on right now is not an individual unit being an individual well, we are concentrating on what do these wells look like once we get the spacing that we want in there? So, right now, we're trying to increase the recovery out of a full development unit.

Scott Hanold - RBC Capital Markets LLC

Okay. I understand that. I appreciate it and look forward to some of those results. Thanks.

Operator

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

Jeff S. Grampp - Northland Securities, Inc.

Good morning, guys. I wanted to talk on may be these Calverley wells getting back on this million barrel curve. Just kind of wondering when you guys – and we kind of saw the IP rates with some of the R&D efforts several months ago. Did you guys kind of internally have that expectation that it would get back on the curve, is that a surprise to you or did you guys kind of do anything in particular to end up getting those shallower declines?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

No. We did not do anything in particular. Of course, the Wolfcamp well was just held back because we weren't letting – we didn't put it on artificial lift for quite some time. We were letting it flow naturally under a restrained choke so we could run the fiber optics on the coil tubing and get some data there for this high density – high intensity frac design. But we had assumed that the Lower Spraberry well, being on gas lift, would eventually start catching back up to the others. And have a shallower decline just because it shouldn't have changed the EUR being there, it was just going to take longer to get the product out of the ground with the gas lift and, of course, our next two wells are on production and they're on ESP.

Jeff S. Grampp - Northland Securities, Inc.

Okay. Makes sense. And then on the bolt-on acquisitions that you guys have been able to do, certainly accretive like Steve pointed out. But going into the year, I'm just trying to handicap, was this – would you view the first six months as more or less kind of successful from the bolt-on front given how competition is in the Midland Basin? I'm just trying to get a perspective on the outlook of similar types of transactions going forward?

Steven Gray - Chief Executive Officer & Director

Well, obviously, the bolt-on acquisitions are always the best. But they were small, but they were also properties that we'll be drilling immediately, so they do add value – they bring forward value immediately. So, I would say that we were pleased with the acquisitions that we did, although they were fairly small. One of them was in an interesting situation where there was an operator that was a little bit over-levered and needed a partner on a couple of wells he was drilling. So we were able to step in right at the time the wells were drilled and completed, so there was no time delay from the time we bought the deal to the time we brought on the production.

So those are good, nice bolt-ons and they're easy. Obviously, the bigger deals that bring more attention are more competitive and that's the reason you haven't seen us make any substantial acquisitions this year. It's not because we haven't been in the market. This is simply because it's been a pretty competitive market. Bid out spreads were a little bit wide and I think they're narrowing right now. I think that over the next year I'd be surprised if you don't see us do an acquisition that's material. But, as I said, we'll be selective and wait for the right deals to come along.

Jeff S. Grampp - Northland Securities, Inc.

Okay, great. And then last one for maybe just more of a housekeeping one. On those upcoming Woody wells, are those going to be 5,000 foot laterals again or are you guys looking to maybe drill a little bit longer than those kind of 1 miles?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Well, I think the next ones coming up are 5,000 foot. We are trying to make some deals right now with offset operators that would extend those lateral lengths and we do have some longer laterals planned in the Woody area.

Jeff S. Grampp - Northland Securities, Inc.

Okay, great. Thanks for time, guys.

Operator

Our next question is from Irene Haas from Wunderlich Securities.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Yeah. Hello. I would like to ask you about two questions if I may. Your 2017 hedging, are you going to probably use the deferred premium puts? And secondarily, how do you like the diverting agent? Is it working for you? Do you see X percent of uplift? Does it work across different targeted horizon?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Irene, this is Zane. I'll start out on the diverter. The diverter is something we started experimenting with Halliburton early in the year. And at first, we used a fairly soft small amount of it. I think we probably tripled the amount that we're using and we certainly didn't start using more because we disliked it. I'll put it that way.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Okay. And this is specific to the certain horizon like, for example, is it just a Wolfcamp A, Zane, or can you use it in the Lower Spraberry? Are there certain conditions where it's best to use the diverters?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

As of this point, we have not yet found where we would not use it.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Okay, great. Thank you.

Scott McNeill - Chief Financial Officer & Director

Irene, this is Scott. On the hedging question, we would probably use deferred puts going into 2017 when we start hedging. It's just that those premiums have been really high. And as time goes on, those will come down. We'll probably start protecting $45 oil again and then if the strip continues to move up and we see some opportunities to lock in some attractive collars with kind of a $45 floor and maybe something in the – with a six-handle on it on the ceiling, then we'll probably institute that kind of structure on the hedge program going into 2017.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Thanks. Great. Thank you very much.

Operator

Our next question is from Will Green from Stephens.

Will O. Green - Stephens, Inc.

Good morning. So, again, great color on the different scenarios – the annualized scenarios. I wanted to get a sense for where you guys are thinking about OpEx? I know you mentioned on well costs. In kind of the high case, you were thinking about putting in some escalators in the cost there. How are you guys thinking about OpEx on those? Are there unit cost deflators because of the growth? Are you guys assuming you lose some of those efficiencies or cost reductions you've been able to achieve on the unit cost side? Just help me kind of think through that.

Steven Gray - Chief Executive Officer & Director

In our model, we think our LOE will be relatively stable or relatively flat on a per unit basis over the next year or so. We're cautious that for a quarter or two, you could see them up a little bit, simply because when oil is low, $30 or $40, you have marginal wells that go off production that you don't immediately put back on. And so, I'm sure we're like every other operator, there's some deferred maintenance on some of your marginal wells that as oil prices recover, you might want to go put those wells back on and so there will be some well maintenance costs.

So, I could see a couple of quarters where maybe our operating costs are up $0.50 a barrel or something like that. And then I think we'll be back down to our normal that we've been seeing for the last two quarters or three quarters. So that's kind of how we're modeling it. And I don't see pressure on operating costs going up other than just taking care of some maintenance that's been deferred.

Will O. Green - Stephens, Inc.

Great. And then, being mindful that you guys would probably look to lock in rigs earlier rather than later, at least if you guys are thinking about long-term contracts, I kind of take this as loose guidance for next year, when would you guys kind of formalize those plans? How should we think about you guys kind of unveiling kind of a formal guidance plan for 2017 being mindful that if you guys were looking at adding a fourth or fifth or more rigs, you would be looking at kind of a long-term commitment there? So, how should I think about that timeline of events of when you guys unveil that?

Scott McNeill - Chief Financial Officer & Director

This is Scott, and I think in our CapEx guidance that we just updated, we left ourself a little bit of flexibility in that range. So, if commodity prices continue to improve towards the back half of the year, you could see us bring in a rig a little bit earlier, a fourth rig perhaps, also knowing that we have two rigs that come off in the first part of next year. So, we have some flexibility if commodity prices were to retreat on us.

But, remember, we're going to be looking at the strip and we're going to look at the ability for us to hedge out into the future. So, it's not necessarily just today's spot price, we're going to be looking out into the future and that will dictate whether or not, we elect to bring an additional rig in. And then sometime in January, consistent with what we've done the last couple of years, we'll come out with our formalized budget for 2017. So I think that's how I'd kind of look at it.

Will O. Green - Stephens, Inc.

Great. I appreciate the color.

Operator

Our next question comes from the Kashy Harrison from Simmons Piper Jaffray.

Kashy O. Harrison - Simmons Piper Jaffray

Good morning and thanks for taking my questions. On page 18 of the presentation, you highlight how the Johnson Ranch wells are performing relative to your type curve there. Is that the 830,000 barrel Lower Spraberry type curve?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

It should be, yes. That would be our standard type curve for a 7,500 foot well, which these are.

Kashy O. Harrison - Simmons Piper Jaffray

Okay. And then just one quick follow-up for me, and then on page 14, you also – you highlight just the amazing reductions in well cost since the fourth quarter of 2014. It looks like it's down about 46%. How much of that is attributable to efficiencies or in other words structural versus cyclical?

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Well, certainly, a tremendous amount of it is due to efficiencies, reduction in the number of days to drill these wells, going from achieving five frac stages per day with a frac crew to eight frac stages to nine frac stages a day with a crew, but then, like you say, a lot of it is cyclical because of the goods and services. We will retain a tremendous – a significant amount of that cost reduction even as price pressure is applied. It's not so much of a function of oil prices as it is a function of rig utilization rate. So, I think it's going to take a significant increase in the number of rigs running in the U.S. before we see a tremendous amount of pricing pressure.

Kashy O. Harrison - Simmons Piper Jaffray

All right. That's it for me. Thanks, guys.

Zane Wade Arrott - Chief Operating Officer & Co-Founder

Thank you.

Operator

Our next question comes from David Snow from Energy Equities.

David G. Snow - Energy Equities, Inc.

Yeah. You've noted a few areas, Calverley and Woody in particular that you're outperforming the type curve, is this you're just picking the two best or is it more broadly evidenced as you've been drilling through the year?

Steven Gray - Chief Executive Officer & Director

So, on page five of our investor presentation, that's the average of every well we drilled in 2016 versus our average type curve. And the point of the slide is, we're 20% – after 190 days, we're 20% above our type curve on every single well we drilled this year on average.

David G. Snow - Energy Equities, Inc.

Wonderful. Yes. Perfect answer. Thank you.

Steven Gray - Chief Executive Officer & Director

You're welcome.

Operator

Ladies and gentlemen, we have reached the end of the question-and-answer session. I'd like to turn this conference back to Scott for closing comments.

Steven Gray - Chief Executive Officer & Director

This is Steve. I just want to say thanks to everyone for joining the call today. I know, in general, it seemed like a fairly quiet quarter for RSP this quarter, but I can tell you, it wasn't quiet for all of our folks out there working hard behind the scenes and getting these wells drilled and completely like we did. So, I just would like to say thank you to everybody on the team here at RSP and thank all of you for joining today.

And as always, if you have any other questions that didn't get answered today, if you like to reach out and give Scott or Zane or myself a call, please feel free to do so. Thank you very much.

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