Current RSPP Stock Info

$850 million in 2018 CapEx

RSP Permian (ticker: RSPP) announced fourth quarter results and reserves today, showing net earnings of $140.8 million, or $0.89 per share. Like many other E&Ps, RSP Permian saw a boost to Q4 earnings due to the recent tax legislation. For RSP, the tax law resulted in a non-cash income of $144.4 million.

The company earned a total of $232.1 million in 2017, much improved over the $24.9 million loss RSP reported in 2016.

RSP Permian produced 62.4 MBOEPD in Q4 2017, continuing the company’s significant growth this year. 62.4 MBOEPD represents 74% year-over-year growth, and full year production was up 89% to 55.3 MBOEPD.

Positive free cash expected in Q4

The company expects to grow in 2018, but at a significantly lower rate than in the past year. RSP anticipates spending roughly $850 million in CapEx in 2018, to generate production growth of 35%. The company reports that at $50 oil it will generate cash flow beyond spending by Q4 and will exit the year with net debt/EBITDAX below 2.0x.

RSP is running seven rigs currently, and plans to add an eight in April. The company is also using three completion crews, two full-time and one spot crew. Using a spot crew is expensive, as Jagged Peak discussed in its Q3 results, with an incremental cost of almost $1 million per well. RSP has contracted a third full-time crew, which will begin work in May, to replace the spot crew.

RSP Permian Reports 89% Production Growth

Source: RSP Permian Investor Presentation

Delaware Basin delineation continues

RSP continues to integrate the Silver Hill properties it acquired in late 2016. The company reports it is still in the early stages of determining the optimal spacing for its Delaware acreage, and may see significant changes in the future. Drilling inventory results could increase in the coming year, as the company interprets recent micro seismic and 3D seismic surveys, and conducts further spacing tests.

RSP Permian CEO Steve Gray commented “I am proud of our company’s accomplishments in 2017. We delivered on our annual guidance objectives while nearly doubling the size of the company, integrating a new operating area in the Delaware Basin and building out the infrastructure and team to accommodate our increased activity levels and production growth in 2018. We continue to see impressive well results in both our Midland and Delaware Basin assets and this increased well productivity enabled us to meet the mid-point of our production guidance despite completing twenty fewer horizontal wells than we originally budgeted.

“We are well positioned for strong returns in 2018 as we continue to increase our capital efficiency levels and accelerate the completion of our drilled but uncompleted wells carried over from last year’s drilling program. We also expect to generate cash flow in excess of our development spending by the fourth quarter of 2018 while growing production 35% at the mid-point of our guidance.”

Gray also commented on the passing of Ted Collins, Jr., who was a member of the board and the largest individual shareholder of RSP. “Ted was a legend in the oil patch,” Gray said. “He was our largest individual shareholder since we went public and to be honest, he is the reason we are all here today, as he and his partners assembled the lease hold in the initial assets of RSP Permian. I could not have asked for a better board member and mentor than Ted. He was always a gentleman. He was quick with a joke or a complement and always kept things fun. I never heard a word of criticism from Ted, only encouragement. The team here at RSP would like to send our condolences to Ted’s family. We will miss him very much.”

Q&A from RSPP conference call

Q: How should we maybe or how do you guys internally think about that mix of wells maybe changing over the next couple of years, if at all? I mean are there some zones that you guys are maybe excited about that should get a bigger chunk of the pie going forward? Sounds like Middle Spraberry might be one of those, but it would be great to get your thoughts.

Zane Arrott, Chief Operating Officer: We certainly are interested in the Middle Spraberry and we’re committing capital to it. As we’ve said, we’ve got five wells that we’re about to frac there in the Spanish Trail lease that are side by side, and they are over 11,000 feet. So, we are already committing substantial capital there. As you can see, over on the Delaware side, we’re also very interested in the Wolfcamp B. It looks to be strong. There’s been some delineation of the Wolfcamp B, not only to the West, but all the way to the far East side and down into the South. And so, we believe there’s a lot to do there in the Wolfcamp B. It’s a thick zone, it’s highly pressured, so we’re pretty excited about putting some capital towards that. And you’ll see some delineation from us in 2018 in that zone. So those are probably two of the newer zones that are on our radar coming up for the next 24 months.

Q: You all have always done a really good job of being testing the different spacing pilots over the last couple of years, probably more so than almost any of the other operators. And I guess I am just trying to get a sense, just rough numbers, but over the next couple years if I was thinking about the percentage of the activity that would be more thought of as development mode versus either delineation or spacing tests, is just how that mix maybe changes over the next couple years? Maybe you don’t have to do as much of the spacing tests as you all have done previously.

Zane Arrott: I believe that you’re right on that. As we look at the greatest rate of return on the wells, we see that as getting right around about a 450-foot distance between wells, total distance. And so, when you look at that base spacing and you look back in the appendix of how we’ve laid out the Midland Basin, which is the place that we’re most certain of, that we use all the empirical data we have today, as well as others’ data, and we see that when you start getting below 400 feet in total distance, you’re probably going to have some EUR degradation. You might increase NAV, but if you are just looking at pure rate of return on an individual well, you are probably looking at spacings above 400 feet in distance between wells and that’s probably what we’re going to be doing for the next few years.

Q: It seems like there has been an extra focus on Midstream — Permian Midstream this quarter and takeaway over the last couple of quarters. Can you guys just comment on, to the extent that potential takeaway constraints are reflected if at all in your budget, in your guidance?

Steven Gray, Chief Executive Officer

They are not. One of the things that we have done over the last couple of years is, we’ve gotten off of follow-on production on pipeline now. We truck almost no barrels. And so I think that’s a pretty key thing for us because the pipeline connected barrels are going probably be the last to be constrained. And our Midstream providers that we’ve been working with have all been great and we feel like we have takeaway solutions that are as good as anybody. So we don’t foresee that to be a problem in the foreseeable future anyway.

Q: And on the gas side, you guys would just be comfortable flaring if that was necessary for extended period?

Steven Gray, Chief Executive Officer

Well, we’ve never seen that happen before. So I don’t know that I would say we would be happy with it, but it’s certainly not something that we anticipate to happen. We’ve seen times where differentials get squeezed, but we’ve never seen times where we just couldn’t get the takeaway capacity that we needed. The places that we are operating, we’re going to, for example, Targa in the Delaware Basin, Targa has a huge system out there, where they have multiple gas plants that are going to be interconnected with one another. If anybody’s going have takeaway capacity from the Basin that is going to be the big guys like Targa. So, would be the last man standing if that were to happen and we don’t anticipate that happening.

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