Range Resources Earnings Call Insights: Primary Performance Drivers and Laterals Placement

Range Resources Corporation (NYSE:RRC) recently reported its first quarter earnings and discussed the following topics in its earnings conference call.

Primary Performance Drivers

Ronald Mills – Johnson Rice: Ray, couple of questions, you talked a lot about the new, I guess, 12 wells or 14 wells in the super-rich area and how they were better than other – your older wells in the area. A couple of questions. You have a little bit longer laterals, maybe some more frac stages, but what were some of the primary drivers behind that performance? And even though you had a little bit longer laterals, you’re still in the mid-3,000 range. Is there the opportunity or likelihood that you would continue to expand that lateral link in the 4,000, 4,500-foot level? And if so, what would your expectations be?

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Ray N. Walker, Jr. – SVP and COO: Ron, great question. I think the drivers of that improved performance are really all of those things combined. Better targeting has certainly been significant, and that involves some of the new focused ion beams, scanning electron microscope, pictures where they model some of this rock at the molecular level almost. And what we’ve seen is being able to use some of these new technologies and really how the technical teams figured out how to apply those, and where we actually placed that lateral in the rock has made significant changes. And these wells, the two 6-well pads that I’ve talked about in the super-rich area nearby the eight previous wells that were – some of them are up to five years old, the difference there is, on average, they’re about 30% longer laterals. And when you combine that with the RCS, that’s almost twice as many frac stages in the – basically, on a per-lateral kind of comparison. So really comparing all those or combining all those things together is really what makes that difference. And I’d like to talk about the fact that this is really a good indication of, I think, what we’re seeing going forward and the application of all the technology. And we’ve gone back, and of course, we’re really excited about all this, and we keep going back and looking at these and how they’re comparing to our overall averages and our type curves. And like I said, it’s really early. But I think it’s really key to point out that these wells on average are close to between 45% and 50% above the type curve that we’ve got in our PowerPoint. So that’s pretty exciting. It’s still early. It’s only 30 or 40 days on some of these wells, but we think that that’s going to be really key. As far as longer laterals, yes. I mean, I think over time, you’re going to see us migrate to that. In these cases, you’re somewhat limited because you were going back in the units, in some cases, that had already been formed around it on all sides, so you’re sort of limited in some of those cases. But remember, these economics are really, really good at the lengths that we’re at today. And they’re good in the PowerPoint, so you got to say A plus B equals C, and they’re going to be a lot better overall. So we’re pretty excited about it. But to answer your question, yes, we are going to be going longer over the next several years, and we are going to continue to refine some of these technologies. We’ve got some other ideas. The technical team is just doing a wonderful job up in Pittsburgh, so we’re really excited about what they’re seeing.

Jeffrey L. Ventura – President and CEO: And Ray, you might mention, when you go back into some of those units and drill some of the efficiencies, you think we might see going…

Ray N. Walker, Jr. – SVP and COO: Yes, and that’s another good add that we’re seeing, too. When you go back into these areas, these new – whether it’s a new pad in that area, it won’t have to pay as much money for water impoundment, for instance, because it will use an impoundment that’s already there. If we’re going back and adding a well on a pad that already exists and say we want to drill a couple of more wells there to go kind of backfill the infrastructure, in a lot of cases, they don’t have to pay a lot of money for new infrastructure. They don’t have to pay for new well – new pad construction or new roads and that sort of thing. So we could see several hundred thousand dollars less on the upfront cost, which is also really significant going forward. And I think all of those things just continue to enhance our story and what really translates down to shareholder value going forward.

Ronald Mills – Johnson Rice: Then I guess a corollary to that and then I’ll let someone else jump on. Is there anything special about this particular area where you’ve drilled these wells within the footprint of older wells or would you expect similar type results as you enter other older areas? And then, you mentioned, you or Jeff in passing a little bit, 80-acre spacing, but you mentioned the potential for 40-acre spacing, do you think that’s going to be prevalent across most of your acreage in Southwest and Northeast PA?

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Ray N. Walker, Jr. – SVP and COO: Well, we’ve got at least a couple. I think there may be three 40-acre pilots that are out there and some of them have well over two years of production now. We have not released any data and don’t really plan to any time real soon, but I’ll tell you they are all encouraging at this point, and just from a pure standpoint of doing this kind of thing for a whole lot of years, a lot of us would tell you that there’s no doubt as you are in these liquids-rich areas that you’re probably going to go to denser spacing over time. So I think the answer is technically yes. I think a good portion of the wet and super-rich area will probably be developed on 40s eventually. But we see that much further down the road. We still got a lot of room to go back in and infill the rest of the 80s, 60s, whatever combination of lateral lengths then distance between laterals that we come up with over time. So to answer your question, yeah, we will be downspacing significantly going forward…

Jeffrey L. Ventura – President and CEO: I think another key thing to say there too, is on – if you looked at our website and we go through it on our pitch book, what Ray referred to earlier, we got 1 million net acres in the state of Pennsylvania, highly prospective for multiple horizons. And you just zoom in on the 540,000 acres in the Southwest, which Ray did in his example, there’s 1,650 wells there, up to 7 years’ worth of history on our discovery well, which kicked the whole play off. And we go through in detail on our website, starting on Page 12, 13 and so on, and we break out all the dry, the wet, and the super-rich. And really, there’s over 1,650 wells that have delineated it, and that acreage is really all high-quality. So we think it’s all very prospective, very low-risk, it’s a big data set. It’s not 7-day rates or 30 or 60. It’s up to 7 years’ worth of history on over 1,650 wells. So on 80-acre spacing, since we think it’s all prospective, potentially 6,750 wells, and like Ray said, we’ve drilled only about 6% of that on 80s. But it’s all highly de-risked with high returns. So we’ve got a lot of drilling. And the good news, there’s data all over the place out there. So we think those techniques that Ray described will be very applicable, really, across that acreage.

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Ray N. Walker, Jr. – SVP and COO: Yeah. And just another final word, just so Jeff doesn’t get the final word, if you look at the 20 super-rich wells that we turned on in the first quarter, those wells averaged about 65% liquids and the IP on those and BOE per day is not a lot different than these wells I’ve been pointing out here. So I think the hints are, yeah, we do expect to see those kind of results. We’re pretty excited about this. This is a big deal.

Ronald Mills – Johnson Rice: And Ray, is there any difference about this particular area you’re going in amongst the older wells or…?

Ray N. Walker, Jr. – SVP and COO: No. Not appreciably, no.

Laterals Placement

David Kistler – Simmons & Company: Real quickly, when you think about the placement of those laterals in the Southwest Marcellus, is that something that you can apply that same technology across your portfolio? And should we be looking to you guys doing that across all the Marcellus and maybe even testing some of that down in the Miss Lime and potentially seeing an uptick from EURs across the board?

Ray N. Walker, Jr. – SVP and COO: The answer is yes. I mean, we are looking at this everywhere where we’re working, in the Cline, we’re looking at applications in every single play. I think what we tried so far, we’ve seen varying levels of improvements. And I think it’s going to vary a lot based on reservoir rock conditions. And I think the jury is still out because we’ve only really been applying this last part of last year and early this year, and so it’s going to take some time. But I think all our experts would tell you, yes, we do expect to see some improvements. But at the same time, we’re going to also be doing longer laterals in general everywhere and we’re also doing the RCS-type completions in a lot of cases, too. So it’s really going to be a combination of all those things, not just the targeting by itself. But I do expect that we’ll try all of those things in pretty much every play.

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David Kistler – Simmons & Company: Then, looking at the Miss Lime just for a second, you’ve put up a couple wells that were very, very strong in your release. EURs look good, but the EURs would generally, based off those IPs that you shared with us on the new wells, showed that there’s some decent variability between the wells, maybe I’m misinterpreting that, but looking in other parts of the Miss’ different geographies, that’s certainly the case. What are you doing to kind of think through or try to avoid having that sort of statistical aberration between all the wells?

Ray N. Walker, Jr. – SVP and COO: Well, the Chat, which is really what we’re playing on the Nemaha Ridge is very variable. That’s not probably not good grammar, but it varies in thickness and it varies in the fact that it’s not everywhere. It’s very prevalent. It’s much more prevalent on the uplift than it is other places. But what we are trying to do with more and more time is trying to determine where that is, we are using our 3D, we’ve got 4,500 historical wells in that area. And one of the original ideas in putting that lease position together was to really stay close to the historical oil production and try to be around the better or historical vertical production, because your horizontal results are always going to be a multiple of your vertical, so best place to look is where the best wells were. So we’ve got a lot of well log history and different things, and the Chat play is really a conventional type play for lack of a better description, which is sort of unconventional in today’s world. But it has high porosity, it has high permeability, it has lots of fractures, and it’s going to be, and I think the standard deviation of results is going to be larger in a play like that, it has to be. So the key is determining why the good wells are good and trying to find more of those as we go, and that’s going only going to come with time, just like we’ve seen in the Marcellus, with more time, more data and more modeling and more understanding of all of these different rock properties, that’s the same thing that we are going to go through in the Mississippian. We are really early. We’ll continue to update the type curves as we get more production at wells throughout the year. But so far, we’re really excited with what we see, and it’s holding on, and it’s going to be a good emerging play, we think. But again, it’s still early.

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Jeffrey L. Ventura – President and CEO: I think the other thing, there’s variability, but I think at the end of the day, the key is what’s the average of the program. So if you look at the average of our – on Slide 26 on our website – if you look at the average of our 2009 to 2011 horizontal wells, they’re 485,000 BOEs type curves or the (zero time plots) here in the back. With the costs, where we think we are or where we’re close to, those generated strip pricing 91% rate of return. So really, the average is the key. Granted there’s variability, really, in all plays. If you look at the average of the 2012 program it’s 600,000 BOEs, and it’s over 100% rate of return. But we’re learning. Just like we did in the Marcellus, we got progressively better with time. We learn with time. We’ll see as we drill forward here how it eventually drills out. And you don’t know until you drill it and you get long-term history. But looking at the old historical wells and looking at the 3D and the data that we have, personally, I don’t think we’ve drilled our best areas yet even. We started around where we started our development in Tonkawa field, and we just expanded around that. Again, I’m very happy with the 2009 through ’11 program and 2012, and we’ll see what it looks like going forward. But we still think it’s a very attractive play. Nothing – because we have 1 million net acres in Pennsylvania and you got stack pay potential, that’s what’s going to drive the 20% to 25% line-of-sight growth for many years. Again, and if you look at the whole Marcellus play, there’s over 7,000 wells and up to 7 years history that will de-risk it, so that’s the driver. But the Mississippian is exciting. Our potential in the Upper Devonian, the Utica, the Cline, and those other – Wolfberry, all those other plays have value, too…

David Kistler – Simmons & Company: One last question just in the Miss. When you talk about your time to drill those specific wells and we look at kind of the initial plan to ramp to 7 rigs, then 10, then 15, it would seem like also, with the increased working interest in wells, you really don’t need to ramp rigs even materially over the next two years to be able to drill your objective of wells. Is that a fair way to think about that? Am I overstepping in terms of – you’re throwing out 20 days to drill a well and trying to work through that math, or how should we think about that as we model stuff out?

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Ray N. Walker, Jr. – SVP and COO: Dave, I think you’ve nailed it. I mean, we just need to quit talking about rig counts because the drillers are just getting too good too fast. And we just like we saw in the Marcellus, we had to quit talking about rig count, and it’s really the number of net wells we’re going to put online each year. And our plan is still to ramp up activity, but you may not see it near as much in rig counts going forward as we thought earlier on because just in nine months, they went from almost in half. And we’ve seen wells 16 days or less and I predict they’ll be a lot less than that a few months from now. So you’re exactly right. I think rig count is going to be really difficult to model. We can’t even do it internally any more. They’re changing too fast.