Gulfport Energy Earnings Call Insights: Percent Gas NGLs, CapEx
On Wednesday, Gulfport Energy Corporation (NASDAQ:GPOR) reported its first quarter earnings and discussed the following topics in its earnings conference call. Here’s what executives shared.
Percent Gas NGLs
Neal Dingmann – SunTrust Robinson Humphrey: Couple of questions. First, Jim, on the Utica, just wondering kind of that general area that you are in – any estimates that if you would breakdown on your well as far as percent gas NGLs and oil going forward on that, and it’s kind of that general area?
James Palm – CEO: Well, Neal, as you know we’re going to drill 20 wells this year and we are drilling north to south, to east to west. So we don’t actually have the data to break it down, we have made some estimates. But one thing we did look at recently, Chesapeake has drilled a lot more wells than we have and they have some lines that they are showing, based on their lines that puts about 17% of our acreage in the dry gas, hence about 73% in wet gas, and about 10% in the oil window. But we will define that as we are doing this year’s drilling little bit more closely.
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Neal Dingmann – SunTrust Robinson Humphrey: Then wondering, just either for you or Mike as far as on the guidance. Just a slight change that it was, just wondering is that just because of the shut-ins that you are talking about, was that now expected to be a bit more than what you initially thought. Well just kind wanted to hear your thoughts about the additional 100,000 that you’ve kind of pushed back?
Michael G. Moore – SVP and CFO: Right. That completely has to do with this resting period that we are talking about in the Utica as we develop that. We initially did not anticipate that, but that’s information that we have learned as we have gone forward. So that certainly has to do completely with that.
Neal Dingmann – SunTrust Robinson Humphrey: Then maybe two more if I could real quick. Just on – Mike, on CapEx, wanted to your thoughts if you break that out, the terminal business that Jim mentioned is any of that included in CapEx and then how much is included in CapEx this year for the oil sands or the Niobrara?
Michael G. Moore – SVP and CFO: Well, it’s not – the $30 million to $35 million is outside of the CapEx band that I mention, the $206 million to $221 million, so that’s on top of that, and those are vertical integration activities, up in Utica mainly. We’re just trying to obviously make sure that we have services then available to us, so we’re trying to eliminate bottlenecks and have quality services, and then back to your other question, Niobrara, we’ve talked drilling 5 to 7 wells, so that’s going to be anywhere from $5 million to $7 million to us considering $2 million well cost there. And then Grizzly, we really haven’t changed that amount we’re going to spend for 2012 as they’re going to be in the $40 million to $45 million.
Neal Dingmann – SunTrust Robinson Humphrey: Okay. And then last question, if I could, it looks like to me at least based on my estimates, most of the miss that was for the quarter was more on just my realized price estimates, so I’m just wondering, I guess, was that just a recourse of just what was going on in market conditions. I mean, I guess, is it fair to say there was nothing as far as capacity constraint or anything like that affected.
Michael G. Moore – SVP and CFO: No, that’s right, Neal, you know it’s been bouncing around a little bit all over the place as you guys know, so first couple months actually there wasn’t as much premium as had been in the past, but it’s gone now the other way, and for instance, and March and April it ranged all the way from $15 to $20 a barrel premium in Southern Louisiana, so it kind of swung back the other way. Not sure what will happen the rest of the year, may not be quite that high, but it’s been bouncing all over the place.
Ronald Mills – Johnson Rice & Company: Just one more question on the CapEx. You talked about the $30 million to $35 million. Did you – when you look at your other Utica CapEx, did you already have some infrastructure CapEx included in your Utica for your gathering systems or gathering lines and the like?
Michael G. Moore – SVP and CFO: That’s a good point, Ron. Yeah, we did. We had talked about that before. We had a small amount $7.5 million is what we’ve talked about for and that’s mainly for (laying pie) so that we can sell that product.
Ronald Mills – Johnson Rice & Company: Is that your CapEx or is that something that eventually will become part of MarkWest or is that just to get your production to their system?
Michael G. Moore – SVP and CFO: Right now, we’re just looking at it as part of the well cost, still working on all those detail with MarkWest, but we consider it part of the well cost right now.
James Palm – CEO: We did that last December. We made the MarkWest deal since then. But the terminal came along and that resisted a great opportunity to really take control of our liquids takeaway. So, we jumped on that opportunity.
Ronald Mills – Johnson Rice & Company: Then Jim you mentioned, you’re pretty much done with what you’re seeing up in the Utica. You have your 125,000 gross acres. Is that – should we take that to mean you’re not doing any incremental leasing or are you still trying to pick up pieces here and there? I’m just trying to get a sense beyond your CapEx plus the terminal/vertical integration CapEx, how much remaining leasing – I think I had assumed kind of $95 million to $100 million was going to be paid this year? Is that still ballpark figure?
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James Palm – CEO: Ron, we’re still leasing. We’re primarily at the end of what we call bolt-on because we’re putting our units together and of course, it’s still expensive up there. It’s about $6,000 an acre a lot of times, but we feel fortunate that we still have about $3,000 per acre weighted average compared to what the price is going forward now. But the volumes are small enough. It’s not going to change our weighted average that much, and its primary still in the holes where we’re putting the units together.
Ronald Mills – Johnson Rice & Company: Looking at the production levels, particularly the – so you talk about April production averaging 6,700 barrels a day. What do you have potentially coming online towards the end of April or May, June to get you that level up and is your current production still around that April average?
James Palm – CEO: Last couple days we’ve been up quite a bit, Ron, we’ve been back up to $7,200 and $7,300 a day. We’ve given our range for the second quarter of 6.9 to 7.1. So, we’ve got quite a few things coming back on – keep in mind we also have the two wells that we drilled on the joint acreage in Hackberry late last year, which have not been brought online yet because we’re working on the infrastructure. So, we’ve got quite a few things coming online – quite a few nice big zones that we think will be very helpful. So, we feel very good about the second quarter.
Ronald Mills – Johnson Rice & Company: Then the last one just on the continued Hackberry. What drove that production decline in the first quarter, is it just the typical multi-stacked pays where the bottom zone is not always the most productive, and of your 60 planned completions you only did the 11, so a little bit less than what a quarter would have been. Are those the two primary contributors and what’s the pace of recompletions to be able to come back (indiscernible)?
James Palm – CEO: Really at Hackberry, we’re up. But you’re talking West Cote?
Ronald Mills – Johnson Rice & Company: I’m sorry, West Cote. I’m sorry.
James Palm – CEO: Yeah, West Cote, yeah we – this was a time we had a lot of decent wells, say 40, 50 barrel wells that had things like holes in the tubing. We had a lot of those kind of things come, that takes your completion rigs away from doing recompletions, and you fix one of those, you get yourself back into the lower end of a decline curve. If we had more recompletions we would have brought on more new zones with higher IPs. So it’s always lumpy from quarter-to-quarter, that’s why we give annual guidance, but it’s just normal.
Ronald Mills – Johnson Rice & Company: Then you talked about the frac date for the Wagner wells 60 days. 60 days seems like a little bit longer than what some people have been talking about, is that what industry is moving to, and then as you drilled the well in the lateral portion anything you can talk about in terms of oil shows or just how – what the information you gathered during the drilling process?
James Palm – CEO: Well, yeah, we really did as we drilled it, we saw wonderful shows. We saw everything and more that we expected to see, and that DFIT test that we ran was really important it concluded, it showed us that what we, you never know really what the permeability is going to be until you start getting some reservoir test like that, and that said boy we’ve got some really good perm. We thought that test, there are certain things you look for on the signature, while you are doing – you pump into the formation and then you get an instantaneous, and you put in a recorder and you watch. We thought we’d probably end up watching it for about one to two weeks for it to go through the normal cycle that it goes through showing your – getting all the way out to the far reaches of the formation to see what’s going on out there. Instead we were finished in four days and so we were really pleased that we were able to see the things we were looking for in such a short amount of time, so that was really exciting. As far as the two month goes for the resting period, the 60 days, I would say, Ron, that’s going to change as we go along, but for right now, I think, that’s a pretty good number. We’re talking to our peers, and what we’re finding is that we’ve talked to people that are in the gas window, and I think, over there in the gas window, when we drill wells over there it might be a 30 day waiting period based on what we hear from our peers. And then we go over to the west side, and it gets a little shallower and oilier, and you’ve got a certain pore throat size, and have to put those big oil molecules through there, it all relates to the pore throats, and the effect of the water on those. Well, over there, it might take 60 to 90 days, but most of our acreage is in the wet gas, probably that 60 days is a good average, and that’s going to change. We’re going to find some things. There is already some surfactants at the surface that the surface companies are talking about that might make things happen faster, but that’s down the road. Right now, we just think there is so much benefit to shutting it in for the 60 days and getting strong pressures and strong IPs, and better EURs, that we’re going to – and we’re also lucky that we weren’t the first mover in this thing. We’ve learned a lot from what the other guys have done, and so we’ve really come into it at a time when we – had we drilled this well in the first place, we would have done it completely different, and I think, we’re a lot better equipped to do it intelligently now.