RSP Permian (RSPP) Q4 2016 Results - Earnings Call Transcript

| About: RSP Permian (RSPP)

RSP Permian, Inc. (NYSE:RSPP)

Q4 2016 Earnings Call

February 28, 2017 2:00 pm ET

Executives

Alyssa Stephens - RSP Permian, Inc.

Steven Gray - RSP Permian, Inc.

Scott McNeill - RSP Permian, Inc.

Zane Wade Arrott - RSP Permian, Inc.

Analysts

Scott Hanold - RBC Capital Markets LLC

Charles A. Meade - Johnson Rice & Co. LLC

Daniel Eugene McSpirit - BMO Capital Markets (United States)

Michael Dugan Kelly - Seaport Global Securities LLC

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

Jeff S. Grampp - Northland Capital Markets

Drew E. Venker - Morgan Stanley & Co. LLC

Gail Nicholson - KLR Group LLC

Sam Burwell - Canaccord Genuity

John Nelson - Goldman Sachs & Co.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Operator

Welcome to the RSP Permian Fourth Quarter and Full-Year 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 turn the call over to Alyssa Stephens, Director of Investor Relations. Thank you. You may begin.

Alyssa Stephens - RSP Permian, Inc.

Thank you. We appreciate you joining us today as we discuss RSP Permian's fourth quarter and full-year 2016 financial and operating results. On the call today, we have Steve Gray, Chief Executive Officer; Scott McNeill, Chief Financial Officer; and Zane Arrott, Chief Operating Officer.

Yesterday, after the close, we issued our fourth quarter and full-year 2016 earnings release and filed our Form 10-K with the Securities and Exchange Commission. In addition, we posted a new corporate presentation to our website, which we will reference during the call. The presentation is located at www.rsppermian.com and 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 Reports on Form 10-K and Quarterly Reports 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?

Steven Gray - RSP Permian, Inc.

Good afternoon, and thank you for joining the call today. I will touch on a few highlights beginning on slide 4, then hand the call over to Scott and Zane for a more detailed financial and operational update.

At the outset of 2016, we focused our efforts on not only weathering the commodity price downturn and managing our balance sheet, but also positioning RSP to emerge stronger in the eventual recovery. We continued to reduce cost while remaining opportunistic on the M&A front, blocking up our acreage and expanding into the Delaware Basin.

On the Midland Basin side, we closed approximately $70 million in accretive bolt-on acquisitions in 2016. Then, on October 13 of last year, we announced that we had agreed to acquire Silver Hill Energy Partners for approximately $2.4 billion, comprised of $1.25 billion in cash and 31 million shares of RSP stock.

We closed the first part of the acquisition, SHEP I, on November 28, and expect to close the second part, SHEP II, tomorrow, March 1. I'm pleased to report that on February 24, our shareholders overwhelmingly voted in favor of issuing the 16 million shares of RSP common stock in connection with closing the SHEP II acquisition.

In 2016, we increased our drilling inventory by 127% to 5,900 gross horizontal locations. We increased our proved reserves by 78% to 283 million barrels of oil equivalent at year-end 2016 pro forma the Silver Hill acquisition. And we increased our production by 39% year-over-year, largely excluding the impact of Silver Hill.

We also achieved record low drill-bit finding and development and cash operating costs through operational improvements that will continue to enhance our well economics as oil prices rise. We exited the year well-positioned to execute our business plan with an expanded hedge profile and lower net leverage.

Slide 5 highlights several points. Our combined Midland and Delaware position gives us significant scale, optionality with capital allocation, and a large inventory of highly economic drilling locations. We expect approximately 90% production growth in 2017 year-over-year and anticipate in excess of 30% production growth in 2018 and 2019.

With one of the lowest cost structures in the industry, we expect to reach cash flow neutrality in 2018, assuming $55 oil, as we decrease our leverage to less than 2 times EBITDA.

Slide 6 highlights our track record of delivering strong growth in both production and reserves, and our significant momentum coming into 2017.

Slide 7 shows our progression in driving down cash costs and increasing cash margins, marked by our most efficient quarter-to-date in Q4 of 2016. Our success is the direct result of the hard work of our operations team and our contiguous blocky footprint, which provides scale from an infrastructure and cost standpoint, and supports efficient long lateral development. In addition, our favorable marketing and logistics arrangements provide us with crude price realizations that consistently rank among the highest in the basin.

As we entered 2017, we are excited about our deep inventory of high-quality drilling locations spread across a number of different zones, and the upside we see in both operating and capital efficiency on our Delaware asset, as we build out the infrastructure necessary to drill longer laterals and begin multi-well pad development.

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

Scott McNeill - RSP Permian, Inc.

Thanks, Steve. Slide 9 provides a snapshot of our drilling and completion activity for the fourth quarter and full-year 2016. On our operated properties, we drilled 46 and completed 53 horizontal wells during the full year, with 13 drilled and 14 completed during the fourth quarter. These numbers include 2 drilled and 1 completed horizontal well in the Delaware Basin, following our close on SHEP I at the end of November.

On our non-operated properties, we participated in the drilling of 35 horizontal wells and the completion of 37 horizontal wells during the full year, with 6 drilled and 13 completed during the fourth quarter. We ended the year with 10 operated drilled but uncompleted horizontal wells, a normalized level given our four operated rigs that we have running on the Midland side.

Slide 10 summarize our financial results for the fourth quarter and full-year 2016, reflecting strong production growth in a lower cost structure that helped support our cash flow stability, despite weaker oil prices during the year. Performance from wells completed with high-intensity fracs continues to exceed our expectations and resulted in production above the midpoint of our revised October guidance at 29.2 MBoe per day for the full year and 35.8 MBoe per day for the fourth quarter.

As Steve mentioned, we were able to manage our costs even lower this quarter, with record low cash operating cost of $9.11 per barrel of equivalents. This represents a 23% reduction from our 2015 average of $11.85 per barrel of equivalents.

We generated $250.3 million of adjusted EBITDAX in 2016 and $90.5 million during the fourth quarter, which was 22% above the fourth quarter of 2015. On the CapEx side, we decreased our development capital expenditures by 25% year-over-year, spending $294.2 million, but increased fourth quarter 2016 development capital by 49% from the fourth quarter of 2015, positioning the company with strong momentum into 2017.

Turning to slide 11. Slide 11 presents a summary of our financial position as of 12/31/2016 pro forma for the close of SHEP II. Last year, in connection with our acquisition of Silver Hill, we accessed the capital markets with a goal of keeping leverage neutral on a pro forma basis. In October, we issued $1 billion in equity, and in December, we priced $450 million of 5.25% senior unsecured notes at par.

In addition, we entered into an amended and restated credit facility that pro forma for the closing of SHEP II will have a $1.1 billion borrowing base and an elected commitment of $900 million. We ended the year with the credit facility undrawn and $109 million of cash on hand, pro forma for the close of SHEP II.

You will find a detailed hedging schedule in the appendix on slide 35. At a high level, we have approximately 55% of our anticipated 2017 oil volumes hedged to WTI at a weighted average floor price of $44.63, while maintaining significant exposure to upside in crude prices.

We've begun to layer in hedges for 2018 and we have begun actively building our portfolio of Midland-Cushing basis swaps, representing approximately 40% of our anticipated oil volume in 2017. To sum up, we feel well-positioned from a balance sheet and risk management standpoint to execute our development plans.

Slide 12 details our full-year 2017 operating plans and guidance. From our current count of five rigs, we expect to add one rig after the close of SHEP II in March, and two additional rigs in the back-half of the year, exiting 2017 at eight rigs.

We expect daily production to average in a range of 53 to 57 MBoe per day, with approximately 72% oil and 88% liquids. Our aggregate per unit costs at the midpoint, including all our expense items, are expected to be lower than last year's average. However, we do expect our LOE and gathering and transportation cost to tick up as a result of higher per-unit operating costs and higher fees associated with our midstream agreements in the Delaware Basin.

We expect to lower our per-unit operating cost in the Delaware Basin over time, as we implement our operational practices and put sufficient infrastructure in place.

On capital expenditures, we expect to spend $663 million of development capital at the midpoint of the range, 125% more than 2016, with $600 million for drilling and completion and $63 million for infrastructure and other. Our capital program contemplates ramping from five to eight horizontal rigs with a range of 85 to 95 operated horizontal completions. Non-operated activity represent 5% to 10% of the total development capital budget.

We expect an average lateral length of approximately 8,500 feet in the Midland Basin and approximately 6,250 feet in the Delaware Basin, and an average operated working interest of 88%. Of the infrastructure budget, we expect to spend $35 million on upgrading field infrastructure in the Delaware to accommodate our rig ramp and our move to pad drilling.

Slide 13 expands on our 2017 guidance and provides an outlook into 2017 and 2019. Our focus continues to be on maximizing rate of return versus achieving specific growth objectives. And with regard to growth, we place more weight on per share metrics than absolute growth.

During the oil price downturn, we elected to slow our drilling pace and opportunistically made acquisitions to build our core position. Assuming prices remain at current levels, our anticipated 90% production growth in 2017 should result in a slight cash flow outspend, with our leverage ratio coming down below 2 times.

Assuming a moderate ramp in rigs at two per year in 2018 and 2019, we have visibility to achieve in 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 2 times.

With that, I will now turn the call over to Zane to provide an update on our operations. Zane?

Zane Wade Arrott - RSP Permian, Inc.

Thanks, Scott. Slide 14 updates our continued improvements in drilling and completion efficiency. We are currently drilling wells in less than half the time we did in 2013, and we've progressed from an average of 4 frac stages per day in 2013 to 7.5 frac stages in 2016. This is just slightly below our 2015 average stages per day, despite pumping about 15% more sand and adding diverter drops. Although service costs are expected to increase, we still see opportunities for additional efficiency improvements in both basins, particularly the Delaware.

Slide 16 highlights several recent wells that demonstrate the success of our latest frac designs. Please note that we have presented aggregate results for two-well pads. Of the results here, I'll highlight the Mask 1004/1005 pad, which flowed a cumulative total of almost 200,000 Boe naturally before being placed on ESP.

The next two two-well pads are located in Spanish Trail and reached a four-well combined 24-hour peak rate of 7,100 Boe per day, and a cumulative total of over 250,000 Boe in less than 60 days. During the fourth quarter, we completed four additional Lower Spraberry wells in our Johnson Ranch spacing pilot using our latest generation frac design.

As you can see on slide 17, of the four new wells, one completes the first half-section drilled in an equivalent of 10 wells per section, while the next three initiate a 14-well-per-section pattern on the second half of the section. Early production indicates performance in line with the previous four completions in the section.

Slide 18 highlights our substantial year-over-year well productivity improvements. 2016 performance came in about 13% above the 2014-2015 average at 360 days. We've calculated a blended average type curve for our 2017 drilling program based on performance to-date from our current well design and plotted the resulting curve on slide 18. With an average lateral length of 8,500 feet, one-year estimated cumulative production is 205 Mboe, and two-year estimated cumulative production is 285 MBoe.

Slide 19 looks at our year-over-year improvement in well productivity based on time to well payout. To-date, over 55% of our wells drilled in 2015 have reached 155 MBo approximate payout in less than a year's time. And notably, 2015 average time to payout is more than 60% less than in 2013.

Returning to the topic of type curves, slide 20 summarizes the updates we've made over our 2015 estimates. The results of our internal and third-party review yielded an increase in the average type curve across our Midland Basin position. Specifically, the early time outperformance of our recent wells supported modifications to IPs and initial decline parameters.

Across the 45 RSP type curves which were prepared by our third-party engineers, Netherland and Sewell, changes ranged from 0% to 60% on first and second year cumulative production volumes and from 0% to 35% on EUR. Certain combinations of area, zone and lateral length warranted more dramatic increases than others, as noted in the graph at the bottom of the page. As Scott said, our business strategy is rate of return-driven, so we're most focused on the early time performance of our wells.

Slide 21 depicts why. Approximately 85% of a well's NPV is achieved in the first 10 years of its life. Variations in a type curve's terminal decline rate or B-factor could have a meaningful impact on estimated ultimate recoveries, but a negligible impact on net present value.

In the illustration on the right side of slide 21, we've run our 2017 type curve at a range of different B-factors. The result is nearly identical production in the first few years, but a range in EURs from 860 to 1,170 MBoe based on B-factors ranging from 1.3 to 1.8.

As summarized on slide 22, our current estimated well cost for an 8,500-foot Midland Basin well is $6.2 million.

Slide 23 provides an update of our well inventory in the Midland Basin. Based on well results to-date, we have increased our base inventory slightly to 2,700 gross, 1,750 net locations, while continuing to remain optimistic about further upside to our location count.

Slide 25 walks through a few of our key initiatives in the Delaware Basin. Since the announcement of the acquisition of Silver Hill, we've been in discussions with offset operators regarding acreage trades to further block up our position and increase overall capital efficiency.

We've made good progress today and see potential to continue to enhance asset value this way. We've also recently acquired the saltwater disposal system supporting our Delaware properties, providing us with a clear line of sight to having all produced water disposed of in company-owned facilities within six months.

In addition, Targa recently announced the pending acquisition of our Delaware midstream provider Outrigger. Targa and Outrigger are already working together to make system upgrades, including larger pipe diameters to accommodate additional natural gas volumes anticipated from a ramp in our development activity.

We have also purchased two recent seismic surveys covering the western two-thirds of our Delaware acreage position, and we are currently shooting 3-D seismic across the eastern one-third of our acreage block.

Slide 26 provides a summary of recent well results and also recent workovers. Most of the Silver Hill wells have been rate-restricted early in their life. We have provided choke size at the time of IP30 and flowing pressure, so you can see the upside potential in IP30 and early production cumulatives for these wells.

Included in the selection was a well that has been on production for almost two years. Although this well, which has only 4,270 feet of lateral length, had a modest IP30, it has produced a cumulative of 266,000 Boe. Also of note here is the distribution of strong well results across five zones, including not only multiple Wolfcamp targets, but also the Avalon and Bone Springs.

The Silver Hill team had successfully drilled and completed horizontal wells in seven zones, and recent offset operator success in the Wolfcamp D suggests potential for an eighth prospective zone on our properties. We are looking forward to future results where the wells are not restricted and utilize the latest in completion design. We expect future wells to target numerous zones across much of the block.

Slide 27 is a case study on two recent workovers in the Delaware Basin. These wells had been online for about 170 to 200 days before commencing these workovers. On January 20, we installed an ESP in the Brunson 1111H 8,000-foot Avalon well, increasing the rate from 460 to 1,035 Boe per day. On February 5, we installed an ESP in the Ludeman 505H 4,400-foot Second Bone Springs well, increasing the rate from 337 to 1,033 Boe per day. These excellent results support our plan for additional workovers to enhance the production rate from existing producers over the coming months.

Our Delaware assets have also yielded substantial year-over-year improvement in performance, as depicted on slide 28. A recent Lower Wolfcamp A well drilled by one of our non-op partners used a larger choke setting, and the well is producing at substantially higher rates of its first 180 days.

The Corsair has a 4,100-foot lateral length and a 180-day cumulative production of 182 MBoe. As we take over operations and upgrade infrastructure to accommodate high volumes from new producers, we plan to move towards choke setting and completion methodologies more in line with offset operators and our non-op partners.

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

Operator

At this time, we'll be conducting a – hello?

Zane Wade Arrott - RSP Permian, Inc.

I was going to say, operator, we're ready for the questions.

Question-and-Answer Session

Operator

Sure. Our first question comes from Scott Hanold with RBC Capital Markets. Please proceed with your question.

Scott Hanold - RBC Capital Markets LLC

Thanks. Good afternoon, guys.

Steven Gray - RSP Permian, Inc.

Hi, Scott.

Zane Wade Arrott - RSP Permian, Inc.

Hi.

Scott Hanold - RBC Capital Markets LLC

Hey. We talked about – as you look at these wells, and you certainly put more emphasis on value in the first one to two years versus whatever happens in the later time. And thinking about industry, and it seems like over the last five-plus years, everybody is trying tighten up the chokes, more reservoir management, although what you're indicating is that maybe the better way to do it is open the choke up a little more. Is it somewhat related to that, or is it part of that as well as how you actually fracture the well?

Zane Wade Arrott - RSP Permian, Inc.

Scott, this is Zane. We've looked at it both ways in the Midland Basin, what people would call somewhat slow back and then pulling them at higher rates. And we've seen better well performance at the higher rates. And certainly our offset operators on the Delaware side, certainly pull them at higher rates.

So we're not talking about excessively pulling the well, but we certainly would see higher rates as having good – not only good for the economics, but we haven't seen any detrimental effects for the wellbores themselves.

Scott Hanold - RBC Capital Markets LLC

Okay. Okay. Appreciate the color there. And then, my follow-up question is, as you discuss 2018-2019 looking more free cash flow neutral with 30% growth, is that the plan or is that just more of conceptually what you're able to actually do? So, let's say, we have $55, $60 oil prices. Would you guys look at potentially continuing to outspend to accelerate the value creation?

Steven Gray - RSP Permian, Inc.

Yeah. Scott, I think what we said in there is we anticipated 30%-plus growth. So we're not necessarily saying it's 30%, but I'd say excess of 30%. And we're not opposed to some cash flow outspend, but rather kind of what we've been focusing on is getting our leverage ratios back down.

So we're probably 2.4 times debt-to-EBITDA right now. And over the next year or so, we see that trending down. And we'd like to eventually see it get back into a range that's a little bit more comfortable, which maybe is like between 1.5 and 2 times. So, I mean, I could see that happening and still be outspending cash flow marginally, not excessively.

And in that case, growth is obviously going to be a function of what oil prices do and how many wells we drill. But in kind of a $55 world, we're talking about excess of 30% growth and leverage going down. And those are the drivers that we're really looking at, not necessarily absolute dead or absolute cash flow neutrality, but seeing the leverage ratios trending down.

Scott Hanold - RBC Capital Markets LLC

All right. Got it. Thanks for that.

Operator

Our next question comes from Charles Meade with Johnson Rice. Please proceed with your question.

Charles A. Meade - Johnson Rice & Co. LLC

Good morning, gentlemen – or good afternoon, I should say. I was curious on your slide 8, you guys have a new, I guess, maybe categorization of your different targets and the returns available by target. And I'm wondering if you could talk a little bit about the thought that went into this or what's behind it, few of the specifics being how big is that Glasscock, Upper Wolfcamp.

I know you've talked about the Calverley wells being the best wells in your portfolio, but kind of what footprint are we talking about there? And what's the distinction that we should think about when we see Upper Wolfcamp versus the Wolfcamp A and the Wolfcamp B?

Zane Wade Arrott - RSP Permian, Inc.

This is Zane. So, yeah, there's no doubt that right now the Glasscock, Upper Wolfcamp, being both the A and the B, are our largest return wells. Now those could be eclipsed by the Delaware as we begin to drill longer laterals out there and get ourself really set up in the Delaware.

So, if you look though back at page 20, you'll see why we're saying that. I mean, the Glasscock wells in the Wolfcamp B were some of the highest percentage of increases in the first and second year IPs and as EURs also. So they're certainly head and shoulders above some of the other wells.

Charles A. Meade - Johnson Rice & Co. LLC

Got it. That's helpful, Zane. And you anticipated one of my next questions about where those Delaware wells are going to go. So, let me ask a different one on the Delaware Basin. And Steve, this is probably either for you or for Zane, I wonder if you could talk a bit about that Bullet well, the Wolfcamp B well in the Delaware Basin that was on the east side of your acreage. What you saw there? Whether it confirms that your geologic model on the acquisition or if it's making you reconsider things? So, just give us the narrative there.

Steven Gray - RSP Permian, Inc.

Well, the Bullet well is a Wolfcamp B well. And remember, Silver Hill drilled that well just before we acquired the property. If you asked us what we think the best target out there is, we'd probably tell you it's the Wolfcamp A or the Upper Wolfcamp.

But nevertheless, that well – the other thing to keep in mind about that well is that it was a pretty short lateral. It was like 4,100 feet long, so less than a mile along. I'd say that it's pretty much right on the type curve we expected it to be, and time will tell. That well was probably the one well that we don't have hooked up on gas sales yet because it's several miles east from our gathering system out there.

So, Outrigger has been working on getting all the wells connected. I think everything out there is just going to the plant now, except for that one well. And it's still on test. But I would say that just looking at the production of the well so far, it falls pretty much right on trend with what we expected. And I think if you were to extrapolate that well to a longer lateral and a more modern completion, which we would do, I think we'd be quite pleased with that well.

Charles A. Meade - Johnson Rice & Co. LLC

Okay. That's helpful color. Thank you, Steve.

Operator

Our next question comes from Dan McSpirit with BMO Capital Markets. Please proceed with your question.

Daniel Eugene McSpirit - BMO Capital Markets (United States)

Folks, good morning. The before and after that's presented to illustrate, I guess, the rate of change on Midland Basin well productivity is very compelling. If we look at the Delaware Basin, how much better can the wells get on the Silver Hill acreage when the current day completion technique is applied? And is the Corsair well itself a good example of how good it can get?

Zane Wade Arrott - RSP Permian, Inc.

Yeah. This is Zane. Certainly the Corsair well is a good example. There are some other wells that are being drilled out there by the non-op partners. And they're able to open these wells up a little earlier in their life and we're seeing some very good rates and some very good early cumes out of those wells.

So, for the Silver Hill properties, I think that using the latest in frac technology is certainly going to be an uplift to the well. But as far as overall economics go, one of the primary things we're excited about is just getting the right infrastructure in place, the right SWD, the right gas takeaway, so that you can produce these wells at an acceptable level and get your LOEs down.

So there's a lot of improvement on total economics to be done on those properties over the next six months.

Daniel Eugene McSpirit - BMO Capital Markets (United States)

Got it. And as a follow-up to that, what Silver Hill type curve is the longer-term outlook base talking about, the 2018-2019 guidance?

Zane Wade Arrott - RSP Permian, Inc.

That's our internal type curve. So we're – and you have to remember that Netherland Sewell & Associates are the ones that reviewed those wells on the SHEP I properties.

Daniel Eugene McSpirit - BMO Capital Markets (United States)

Got it. Thank you. Have a great day.

Operator

Our next question comes from Mike Kelly with Seaport Global. Please proceed with your question.

Michael Dugan Kelly - Seaport Global Securities LLC

Hey, guys. Good afternoon.

Steven Gray - RSP Permian, Inc.

Hey, Mike.

Zane Wade Arrott - RSP Permian, Inc.

Hey, Mike.

Michael Dugan Kelly - Seaport Global Securities LLC

Kind of a general question for you guys. Just I am curious now with the Silver Hill assets under your belt here for a few months, and with the seismic shoots you've acquired. Just general thoughts, how they've evolved on the asset now versus at the time that you made the acquisition? Thanks.

Steven Gray - RSP Permian, Inc.

The one thing I would say, Mike, is that we haven't seen anything we don't like yet. The only challenge is that there is some work to be done on the infrastructure. One of the things that we knew going in is that they were trucking a lot of production water and that the lease operating expenses are going to be higher over there until we get the saltwater disposal infrastructure in place.

So the first thing we did was we acquired a saltwater disposal system that was owned by a third party out there. And so we now own that system 100% RSP and we'll be expanding it. That's going to be a big driver in lease operating expenses. So, when we said going into it the LOE was going to be higher over there, that was the primary reason we thought that. But we now see line of sight to getting that down to where LOE over there may be more competitive with what we have in the Midland Basin. But it's going to take a few quarters to get there.

And then, as far as well performance goes, we've already seen from wells like the Corsair that are operated by Anadarko and there's another well operated by Matador that we're in that's near there, really good early time performance. And we're seeing that some of these Silver Hill wells were not as good early time because they were choked back, and the reason they were choked back was because they didn't have the facilities in place to handle them. Some of those wells at Silver Hill was completing before we bought the property. They were having to flare the gas because they were waiting on that Outrigger plant to get built out and get the gathering built out.

So they didn't have any incentive to accelerate production on wells where they were having to flare gas. So now that we're getting all those wells hooked up and getting bigger facilities in place, we'll be able to accelerate production on those new wells. And I think what people are going to see is that the wells in this area are maybe better than what they thought they were, because they were seeing those restricted rates.

And those two workovers on page 27 are typical of what we're seeing out there on wells that were – some of those wells have been on production for a year or longer were still flowing and hadn't been put on artificial lift. And again, I don't fault Silver Hill for that. If I were having to flare the gas, I would be hesitant to want to accelerate production myself. But now that we've got the wells connected, we'll have a pretty active program. We're getting wells on artificial lift that have been flowing probably longer than they needed to be.

And so I think the PDP part of this deal was understated a little bit. And so we're liking what we're seeing on that. And I would just say that keep in mind, these two wells, one of them was an Avalon well and the other one is a Second Bone Spring well. And if you'd been looking at the public data the last six months, you'd have said, well, they were okay wells. But you'd have been looking at a decline curve of two wells that were just flowing up casing.

So I think these workovers are showing that the potential on these wells is maybe better than what would have met the eye if you had just been looking at public data. So we're actually pretty encouraged by what we're seeing.

Michael Dugan Kelly - Seaport Global Securities LLC

That's great. Appreciate that. To follow up, the workover data certainly was impressive. What's the opportunity set that's left there on that front? I mean, is it meaningful enough for that? You do a handful of these that could actually put you at the upper-end of the guidance range for this year. How should we think about that?

Steven Gray - RSP Permian, Inc.

Well, Mike, here's a statistic that I was really surprised about. There are 35 horizontal wells on this property that are still flowing. And in the Midland Basin, I can tell you how many we have flown at a given time is about one. So there is quite a bit of opportunity for uplift on getting artificial lift on those wells really.

Michael Dugan Kelly - Seaport Global Securities LLC

Okay. Great, guys. Really appreciate it. Thanks.

Steven Gray - RSP Permian, Inc.

You're welcome.

Operator

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

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

Good afternoon, guys.

Zane Wade Arrott - RSP Permian, Inc.

Hey, John.

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

Thanks for all the new information in the presentation, it's really helpful. When I'm looking at the three-year plan that was provided on slide 13 and I think about sort of the capital efficiency over the next couple of years, what's sort of the ballpark kind of CapEx you all are assuming in 2018 and 2019 on those numbers of cash flow neutrality?

Scott McNeill - RSP Permian, Inc.

Yeah. John, this is Scott. We added two rigs per year. We did not go and start inflating the costs. We kept the price at $55 and where we felt costs were going to be at a $55 level. So, obviously, if prices continue to go up then you would hopefully see the oil price go as well. And then the other thing I would say that we didn't build in any additional capital efficiency that we might get on these properties.

So I think it's a question as to where the service costs are going to go, and I think everybody is trying to wrestle with that question. But, in our minds, we put our best guess on the CapEx that we put forth in the plan for 2017. And we carried that forward in 2018 and didn't move our price forecast on that $55 oil either. So it could change if oil prices go up, but we also have more cash flow to cover that.

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

Okay. And then my follow-up, obviously a lot of progress has been made on the infrastructure front on the Delaware, and then over the next six months obviously get a bit more. Can you kind of give us an idea of what the Delaware LOE would look like post once all the infrastructure is online?

Scott McNeill - RSP Permian, Inc.

Well, I think what Steve said earlier is that the LOE over time is going to trend down and it's going to be much higher out of the gates. We're not going to get some of those facilities expanded for another two quarters. And you're going to see it tick down every quarter, probably until we get it within $0.50 to $0.75, probably higher than Midland. But, keep in mind, on these Delaware properties, you're going to be handling and moving a bunch more water. So I don't think it's ever going to quite get to where we are on the Midland properties, but we're going to get it as close as we can.

And I think owning all of the saltwater disposal and infrastructure is going to help us towards that. And then there's other stuff that we're doing in the field also that we pointed out there, and putting the generators on raw natural gas and those types of things. So there's some little things that we're doing that will help along the way, but there's some bigger projects that will help. And it'll take few quarters before we can get there. And then we'll get to almost parity, but not quite on the Delaware side.

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

All right. I appreciate. Thanks again, guys.

Scott McNeill - RSP Permian, Inc.

Thanks, John.

Operator

Our next question is from Jeff Grampp with Northland Capital Markets. Please proceed with your question.

Jeff S. Grampp - Northland Capital Markets

Hey, guys. I was hoping to just kind of get some high-level thoughts on 2018 and 2019 in regards to, you guys kind of talked about adding a couple of rigs per year. And just would love to get your thoughts on how you guys think about allocating between Midland and Delaware Basins for those incremental rigs?

Scott McNeill - RSP Permian, Inc.

Well, right now, the plan that we've put forth is that we're going to be adding a rig as soon as we get the infrastructure in place, and that's going to be sometime in the back half of the year in the Delaware. And then we also have in our plan, towards the end of this year we would add a rig. And then we'll make the decision at that time whether or not the Delaware is ready for another rig or if it would be better off putting it in the Midland side, because it's going to be more capital-efficient until we get some additional infrastructure in place.

And then I think what you'll see, as time goes on, is that we're going to be probably allocating more capital towards the Delaware because, once we get the infrastructure in place, the returns on the wells in the Delaware are going to exceed the wells on the Midland side. And so we'll be influenced by that. And then also the wells in the Delaware side are just more expensive to drill and complete. So you'll have a higher percentage of the dollars going towards the Delaware as a result of the well cost being higher.

Jeff S. Grampp - Northland Capital Markets

Okay.

Scott McNeill - RSP Permian, Inc.

So I think this year you're going to see most of our capital, I think we laid it out there on the guidance slide, towards the Midland side. Some of that is because of the staggering of the close of SHEP II as well as the delay in getting some of the incremental rigs over on the Delaware side this year. And then, next year, you're going to see where we'll spend most likely more dollars on the Delaware side than we will on the Midland side. And then, I think the beauty of this...

Jeff S. Grampp - Northland Capital Markets

Okay.

Scott McNeill - RSP Permian, Inc.

...of having both is that we're going to have the opportunity just to flex our CapEx dollars on either side of the basin, depending on what's going on with infrastructure and how the leases are set up as we continue to grow the rigs. We'll have some opportunities to put rigs in either basin depending on the situation.

Jeff S. Grampp - Northland Capital Markets

Okay. Thanks, Scott. And, just thinking on the Midland side, any kind of sense or preview you guys can give us as far as maybe some new zones or spacing concepts you guys are looking at testing in 2017? I know you kind of talked about doing the – fully developing that Lower Spraberry section at Johnson Ranch and you guys in the past have talked about maybe doing a triple stack in the Lower Spraberry. I mean, are there another tests you guys are excited about going often in 2017 here?

Zane Wade Arrott - RSP Permian, Inc.

Well. This is Zane. So, in 2017, in the second quarter, we'll start drilling the last four Johnson Ranch wells to finish out that pilot. We've got some Lower Spraberry wells we're going to finish drilling in Cross Bar Ranch, where we were drilling those Lower Spraberry wells 500 feet apart over there. We'll finish that section out.

We've got some tests going on down in Glasscock, where we're doing multiple landing zones in both the Wolfcamp A and the Wolfcamp B. When the data is ready, we'll be talking about those, but it's going to take some time. New zones in 2017 in Midland, I don't believe we have anything scheduled for testing any new zones other than the fact that we'll be drilling our first 10,000-foot horizontals in the Middle Spraberry.

Jeff S. Grampp - Northland Capital Markets

Okay. And last one for me, just a clarification one. When you guys kind of talk about being at a cash flow neutral level in 2018 at $55 oil, should we be thinking of that on a full-year basis or like a run rate in the back-half, or just kind of wanted to make sure I'm understanding that comment properly?

Scott McNeill - RSP Permian, Inc.

Well, this is Scott. It's going to be lumpy of course and it always is with horizontal drilling. And particularly when you're adding a rig, you might – when you put a rig in place in a particular quarter, you might outspend. So we're taking a look at that on an annual basis that we would be cash flow neutral. And in any one quarter we might be free cash flow positive. And a quarter that we put a rig to work and spend a little capital, we might be free cash flow negative. But on an overall basis, we would expect to be positive at $55 oil.

Jeff S. Grampp - Northland Capital Markets

Got it. Appreciate the time, guys.

Operator

Our next question comes from Drew Venker with Morgan Stanley. Please proceed with your question.

Drew E. Venker - Morgan Stanley & Co. LLC

Good afternoon, everyone.

Zane Wade Arrott - RSP Permian, Inc.

Yeah.

Steven Gray - RSP Permian, Inc.

Hey, Drew.

Drew E. Venker - Morgan Stanley & Co. LLC

I was hoping if you just give a little more color on the 2017 budget, and the 2018 and 2019 outlook. Any key items there that we should keep in mind in terms of well performance on a normalized basis or otherwise? Whether that's assumed to remain static throughout that forecast period? Any changes in lateral lengths or working interest or anything like that?

Zane Wade Arrott - RSP Permian, Inc.

This is Zane. The only thing I can give you on that is that on the Midland side, our average lateral length for 2017 is currently programmed at 8,500 feet. So, that tells you right there that we're going to be drilling much fewer 1-mile wells and a quite a few 10,000-foot laterals to get the average of that higher, so.

Steven Gray - RSP Permian, Inc.

That'll probably continue into 2018 I would imagine.

Zane Wade Arrott - RSP Permian, Inc.

And that will probably continue into 2018.

Drew E. Venker - Morgan Stanley & Co. LLC

Okay. Thanks for that. And then to follow-up on that Corsair well, the performance really does look very strong. Are you expecting to flow back most of your Delaware Basin wells in that manner this year, or is that baked into guidance, or how are you guys thinking about that?

Zane Wade Arrott - RSP Permian, Inc.

That's not going to happen until we have SWD, and we're currently working on two new SWD wells right now. We've got to get some bigger pipe in from Outrigger. So it's going to be a number of quarters before you see us opening wells – number of months before you see us being able to open up wells like that. We have some wells that we would currently like to open up but we can't.

Drew E. Venker - Morgan Stanley & Co. LLC

So, Zane, probably second half at least before we see that?

Zane Wade Arrott - RSP Permian, Inc.

Probably second half.

Drew E. Venker - Morgan Stanley & Co. LLC

Okay. Thanks.

Operator

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

Gail Nicholson - KLR Group LLC

Good afternoon, everybody. When you look at the ability to be cash flow neutral, $55 environment in 2018-2019, what are the thoughts about hedges on a go-forward basis?

Scott McNeill - RSP Permian, Inc.

Hedging. It's not going to change that much from what we've currently been doing. And if you take a look at what we have been doing, we've been layering in hedges that give us the opportunity to capture the higher oil prices. So the hedges that we have in place, it really protects our downside, where we said we would start slowing which was at $45 oil, but it's left the upside above that's $55 sort of up to $60 sort of cap.

So we've been looking at the hedge market obviously and layering in a bunch of hedges here lightly. And we're I think 60% almost hedged on our oil volumes for next year. So, that's a pretty comfortable place for us as we continue to move forward and we get into 2018. And that really what it does is quite a bit of our PDP gets hedged up and then allows for the growth that we have in our drilling program to capture the current oil price.

Gail Nicholson - KLR Group LLC

Okay. Great. And then on page 14 of the slide deck, you talk about the drilling and completion efficiency improvements that you have seen in the Midland Basin, and the thought that there's incremental opportunities on both the Midland and the Delaware side. Can you just expand on that on what you think those opportunity sets are and then how easy you think those will be attainable?

Zane Wade Arrott - RSP Permian, Inc.

Well, this is Zane. On the Midland side, it's going to be much more difficult to attain further efficiency than what we have today. But every time I say that, our guys seem to be able to squeak out a little more. So, changes in bottom-hole assembly, bit design, et cetera, are always going to help us.

On the Delaware side, there's significant improvement to be made. That improvement is going to come in the form of pad drilling. It's going to come in the form of finding the exact landing zone to put these wells in, once we look at our 3-D and get our model zoning like we did over on the Midland side. There's pretty easily five days to shave off the drilling time there on the Delaware side, as we are able to move into pad drilling.

So those are where some of the efficiencies are going to come from on the Delaware side.

Gail Nicholson - KLR Group LLC

Have you baked any of those efficiencies into the 2018-2019 growth expectations?

Zane Wade Arrott - RSP Permian, Inc.

We have baked some of the efficiency in, but not all of it.

Gail Nicholson - KLR Group LLC

Okay. Great. Thank you.

Operator

Our next question comes from Sam Burwell with Canaccord Genuity. Please proceed with your question.

Sam Burwell - Canaccord Genuity

Good afternoon, guys. I wanted to quickly clarify something I think Mike Kelly brought up on the workovers. Is that whole potential baked into the 2017 guidance or is that represent kind of pure upside?

Steven Gray - RSP Permian, Inc.

Well, it's maybe a little bit baked into there, but not all of it. It's hard to predict how some of these wells will perform when we put them on pump. Some of them are going to be just bigger uplift than others. So, initially in our projections, we didn't include them.

Sam Burwell - Canaccord Genuity

Okay.

Scott McNeill - RSP Permian, Inc.

I think one way to look at it is that we plan to have workovers. I mean, it's always plan to put these things on secondary, but it's – what you're going to get out of it. We don't know yet until we put them on. So we're putting some estimates out there that we believe we're going to get, but maybe not the full amount than what we're seeing today.

Sam Burwell - Canaccord Genuity

Yeah. Yeah. That certainly makes sense. I just asked given how the magnitude of the two that you highlighted. And I guess the follow-up, folks, is a little bit more on 2018 with regards to infrastructure CapEx. I mean, you guys talked about 30%-plus production growth in 2018 and 2019. So, if you're running a D&C program that's going to yield that sort of result, does that imply kind of flat infrastructure CapEx versus 2017? Or does it trend down because 2017 is a bit front-end loaded? Or just how should we think about infrastructure CapEx going forward?

Steven Gray - RSP Permian, Inc.

The way we look at it is that – and if you go back and look at RSP for the last three or four years, we've spent about 6% or 8% of our capital on infrastructure. And this year, because we just went into a new area, we've got a lot to do, we'll probably spend quite a bit more than that.

But after this year, I think we'll trend back to our historical. So we're not going to put in another saltwater disposal system again next year, because we'll have already done it this year. And the tank batteries that need to be expanded will be expanded. So there will be continuous capital expenditures for infrastructure, but this year will be a big year, obviously, because it's a new property for us. So we may spend 10% or 12% of our budget this year on infrastructure and then I expect it will back to 7% or 8% a year next year.

Sam Burwell - Canaccord Genuity

Got you. Thanks for the color, guys. Appreciate it.

Steven Gray - RSP Permian, Inc.

You bet.

Operator

Our next question comes from John Nelson with Goldman Sachs. Please proceed with your question.

John Nelson - Goldman Sachs & Co.

Good afternoon and thank you for taking my questions.

Steven Gray - RSP Permian, Inc.

Hey, John.

John Nelson - Goldman Sachs & Co.

Zane, when you announced Silver Hill back in October, you laid out your 1,000-foot lateral assumptions for the Silver Hill assets that were about 150 to 250 MBoe. I know you guys have kind of just inherited the assets, but we have seen quite a bit of peer activity over the last few months.

Just wondering, if we come back and look at some of those assumptions, would you take a stab potentially narrowing the range? And then, any help you have in how we should think about oil mix within those zones as well would be helpful.

Steven Gray - RSP Permian, Inc.

Well, I will say this, John, is that we're talking about seven or eight different reservoirs. So you can't just say that they're all going to be the same. We're going to have the Wolfcamp is going be maybe on the high-end of that range. And then, some of the shallower zones may be closer to the middle or the lower end of that range.

What I have been pretty pleased with so far is the oil cut on these Bone Spring and Avalon wells is pretty high. So I think we're going to be okay on that. And I think the general consensus is the Wolfcamp wells are going to be really strong. So, I don't know, Josh, the 250 Mboe is probably not out of line on the Wolfcamp, right? But, yeah, it's still a broad range because you're talking about multiple different reservoirs.

John Nelson - Goldman Sachs & Co.

Okay. And just on the oil cuts being really high, think of those in kind of 70% to 80%, or kind of any thoughts on how we should think about those?

Scott McNeill - RSP Permian, Inc.

Yeah. It's 70s on the Wolfcamp wells, a little lower on the Avalon wells. Avalon wells are going to be in the high 60s probably and Second Bone Spring is something like that.

Steven Gray - RSP Permian, Inc.

70%.

John Nelson - Goldman Sachs & Co.

That's helpful. And then, just Scott on the guidance, on the higher LOE to start the year. I guess just as we think about sort of building our models, could we see 1Q or 2Q above the top of the LOE guidance range or is it just...

Scott McNeill - RSP Permian, Inc.

Yeah. I think so. We put that guidance range out there, and it's going to trend down over time. You're not going to have a preponderance of the production coming from the Delaware right out at the very first of the year. You're going to see us start ramping in the back half of the year when we get the infrastructure in place, so.

Steven Gray - RSP Permian, Inc.

We talked about that very thing yesterday, John, and that if we're putting out annual guidance, then it would not surprise me at all if our LOE is higher in the first quarter than what our annual guidance is, because we expect four consecutive quarters of lower LOE over there. And it has basically almost all to do with saltwater disposal costs.

So, yeah, we talked about that and decided, yeah, if you're going to put out annual guidance and you're not putting out quarterly guidance, then you should put out what you think the year is going to average. And so, if we're a little bit over it in the first quarter, it's certainly not going to surprise me.

John Nelson - Goldman Sachs & Co.

That's perfectly clear. And very helpful. Thanks, guys. Congrats on the quarter.

Steven Gray - RSP Permian, Inc.

You bet.

Operator

Our next question comes from Chris Stevens with KeyBanc. Please proceed with your question.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Hey. Good afternoon, guys. It seems like you're already having some success trading acreage out there and extending the lateral length. What does the opportunity set look like to continue doing that. And is there like an average lateral length you think you can get to over time? And is there any bolt-on acreage around your Delaware position that looks interesting to you guys?

Steven Gray - RSP Permian, Inc.

Well, Chris, we don't ever talk about acquisitions, but I can tell you that we've got active trades going on right now. We've already consummated one trade and we hadn't even closed the Silver Hill deal, but we've got a couple more that we're working on. And so it's very conceivable that our average lateral length next year could be 7,000 feet, probably ultimately 7,500 feet would be my guess. I think this year we budgeted 6,250 feet.

So you can see that's already 50% of the wells we drilled are in the 1.5 mile range and 50% are on the order of 1 mile. But my hope is that, by next year, most of them are going to be 7,500-foot wells. So, that seems to be the sweet spot for what we see right now.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Yeah. Okay. Got it. And just if I can follow-up on another question. I think you said there's about 35 wells that are still flowing back right now without the artificial lift. What's the timeframe for getting those on with? And are you going to change that methodology going forward in terms of the timeframe between completing a well and putting them on pump?

Steven Gray - RSP Permian, Inc.

Yeah. I think we'll be more aggressive about getting them all in pump. Again, Silver Hill had less incentive than we did considering that they had a gas plant that was being built on gathering systems that were being built out. But I think once we – now that we've got that plan in place and are selling all the gas that I think we will be more aggressive to getting wells on pump.

Out of those 30 something, obviously some of those are brand new wells that don't need to be put on pump. So it's not like we're going to have 35 workovers in the next three months to put wells on. But I would say, over the next six months, you're going to see us probably get more than half of those on some kind of artificial lift. So, that should give us a little bump in our production out there.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Great. Thanks a lot.

Scott McNeill - RSP Permian, Inc.

Thanks, Chris.

Steven Gray - RSP Permian, Inc.

Yeah. Thanks.

Operator

Ladies and gentlemen, at this time, I'd like to turn the call back over to management for closing comments.

Steven Gray - RSP Permian, Inc.

Okay. Well, thank you everybody for joining us on our call today and thank you for your interest in RSP. I'd like to take a quick moment to recognize the hard work of all our employees over the course of the last year to position us where we are today. I would also like to welcome all of our new employees, both those that are coming over from Silver Hill as well as all the other great new hires that we've made in recent weeks.

And I would like to also thank all of our shareholders who supported our effort and rode for our proposal to finance the Silver Hill deal with equity in the way that we did. And lastly, but not leastly, I would also like to say thank you to the Silver Hill owners, who have just become our newest shareholders, and thank you guys for your confidence in RSP and its management team. We look forward to a great partnership together. Thank you all very much.

Operator

This concludes today's conference. You may disconnect your lines at this time, and we thank you for your participation.

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