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On Wednesday, Gulfport Energy Corporation (NASDAQ:GPOR) reported its second quarter earnings and discussed the following topics in its earnings conference call. Take a look.
Neal Dingmann – SunTrust: Jim, the first question just on that Wagner when you’re talking about that, I was wondering as far as what percent of load you’ve gotten back from that and kind of what percent you think you’ll ultimately get back?
James Palm – CEO: Neal, it’s just a small fraction of the low I couldn’t give you the percentage off the top of my head, but it’s just a tiny amount. It does suggest that this Utica is a real dry formation in a mode back and it looks like that’s going to be the case, so we don’t have a lot of water disposal issues associated with it obviously. Of course we’re already working on plans to reuse the water that we do make back, we’ll put that down the next frac well, but that’s going to be a minimum problem there looks like.
Neal Dingmann – SunTrust: Looking ahead you mentioned that couple of other wells like Shugert and some of these others now. I guess if you just had a sort of dump that down in layman terms a little bit it does sound like at least the float rate and maybe liquids maybe would be a bit more is that fair to say Jim?
James Palm – CEO: That’s for sure, that shows that as we move west, it’s really coming in just as we expected, further west and the shallower, the more condensate we’re seem to be seeing in the higher BTUs and the gas and I will point out to you too, that of course in the Wagner we have a tubing string in there as well as we’ve got our casing, but on these wells, to me I was really struck by the fact that these are coming up with casing, so they are unloading – casing without the benefit of the tubing, so we’re not getting all fluids out of them, so the rates you’ll see to the west are a little bit lower than you see to it east that’s because there is so much more hydrostatic on the bottom, I think it’s just incredible these are making from just single stage or completely unloading that up, 5.5 and continuing to flow during the test period, so we’re really seeing strong performance over there and don’t let those rates to mislead you, we would be making a lot more gas and liquids if we had tubing whole like we have on the Wagner.
Michael G. Moore – SVP and CFO: Keep in mind; I just want to keep reminding this all of this is – these other rates are just one interval out of multiple intervals on those zones.
Neal Dingmann – SunTrust: Then two more if I could obviously with these appearing to be stellar results just either Mike for you or Jim just want to know if you see these type of results would you start to think obviously the questions are going to come about a third rig, fourth rig, have you already considered that if you would, then I’m sure the questions will come as far as how you would finance that if you would do something like that?
James Palm – CEO: Well, sure we have. Of course we said, we thought we’d have 10 wells producing by the end of the year and the two wells that are still drilling are in the second half of that well cycle. So obviously we’re easily going to make that point by the end of the year. I suspect we’ll probably add a third rig along the way. We actually started the process of looking for that rig a month or two ago in anticipation of having these kind of results on the Wagner, but of course, we’re going to pick our place to put the third one to work when it’s appropriate but it’ll, come I would guess in the fourth quarter, by the time we had a third rig and we’ll just see what happens, but. I’d like to have a lot more going but Mike keeps me on tight leash.
Mike Liddell – Chairman: Neal as we started the year and as we have done historically we said that we were focused on trying to stay within our cash flow for our drilling activities. So, we’re still focused on of course getting those first 20 wells drilled this year in Utica which we said we should be able to do that cash flow. If you’re asking if we’re going to ramp up and how we’d finance that I don’t think we’re quite ready to have those discussions yet. Certainly as we start looking to 2013 and we get some additional wells on and some sustained production then we’ll probably need to start having those conversations. But it always a balancing act between cash flow and drilling your wells and ramping. So, we’ll just have to move forward and make those evaluations when it’s appropriate.
Neal Dingmann – SunTrust: Then lastly Mike to follow-on to add it does sounds like certainly if you would even add a rig or even two with you and Jim’s comments about MarkWest, you certainly have the capacity and processing availability.
Michael G. Moore – SVP and CFO: Yeah. We do. We certainly do and we’re very excited about that relationship, and the fact that they are staying up with us so that we hook our wells up as quickly as possible when we complete those wells, and also making sure we have plenty of takeaway capacity.
Future Well Locations
Ronald Mills – Johnson Rice: On your presentation, you highlight where you are currently drilling and where your recent wells are. You’ve also have highlighted the higher liquids content as you move west to the play as expected. If you look out over the course of the next 10 to 12 locations that you guys plan to spud by year end, which I assume is consistent with maintaining that two rigs throughout the year. What is the location of those wells look like in terms of west versus east and north versus south?
James Palm – CEO: Well, we really like what we are seeing along the line from the Buell well to our Wagner well, and down to this Shugert well, they are basically on depth and we expect comparable results from all those wells. Down through the south with these Ontario wells, they are making reportedly a lot of condensate, which kind of moves the south end of our line over to the east. So, to the south end of our acreage, say in Belmont County and Northern Monroe County, I would think that maybe that liquids-rich line is moving to east of where we had before we got the Onatrio reports. So, most of our drilling will be along that line and to the west, but we are in the delineation phase of our program. So, we’ll drill one or two over on the east side even in what we anticipate will be quite gas here, and we have some ideas that we’ll put to work over there, some experiments that we’ll do on how to frac these gas wells that maybe dramatically lower the cost for our fracking, our total AFEs and such a big part of it. So, we’re still encouraged about the east side on the gas because we think we get cost down a lot over there.
Michael G. Moore – SVP and CFO: So, we are to that point, we are focusing towards the west. I think that that is key here. We do have 50 locations working, seven permits filed another 150 locations identified. So, we are trying to focus west as much as we can.
James Palm – CEO: Yeah. We want to find out about the east, but next year, it is the same it is today, we’ll basically be drilling the west side, but continue to delineate what we got east west north south.
Ronald Mills – Johnson Rice: I don’t think you’re ready talk about well cost yet, but in terms of versus expectations I know you drilled longer lateral than 8,000 foot versus what some of the other wells have drilled that and you had talked about prior cost expectations, but was there anything abnormal in these wells from a cost standpoint or were you pleased with the pace of drilling, the pace of the AFEs or cost versus your AFEs?
James Palm – CEO: Well, the AFEs, we talked about the cost last time and we’re still seeing what we said last time is reasonable since we’re in the science and exploration mode up there for instance sometimes we don’t have an electric log close by, so we have to drill strap test first and then back up from that straight whole portion where we go down below the point pleasant and we’re getting electric log over the interval because the (indiscernible) with that, so then we come back (indiscernible) all that cost more money, so in this phase (indiscernible) is $1,200 for an 8,000 foot lateral and $1,500 per foot for a 5,000 foot lateral to partners and we’re seeing that – here we are in the seventh well and we’ve seen that with AFE’s we’re doing today as we propose wells to partners, and we’re seeing that is what we’re coming out at, so it’s pretty good. In the future though I think we’re probably looking in the next year or so, it’s something like $1,000 a foot for an 8,000 foot lateral, $1,200 per foot for 5,000 foot lateral. Right now these wells that we are drilling we’re building a location, which can sometimes be pretty expensive up there and sometimes we’re building locations that’s — we’ve already got six wells planned off, we’re only, — we’re taking all that cost on the first well we drilled, so obviously pad rigs out there after we do some delineation and we come back to start filling the other five locations, we’re off to a head start. We’ve seen what’s the casing programs are like, pretty much the casing has been — casing designs and everything, working out the way we thought they would, every well we drilled, we’ve got to the TD, we expected to go to, so it seems like it’s going to lend itself very well to a real manufacturing operation as we delineate and learn it’s going to be, it’s really – while I say this, it’s been really a surprisingly consistent and predictable area.
Ronald Mills – Johnson Rice: In the Permian, you talked about the Janey well and now you’re going to spud the (Neil) well as well, in your conversations with Wagner/Daimondback when you think about prospectively is your Permian activity going forward likely going to be more focused on the horizontal and I think you mentioned instead of really just to block some acreage about a 30-year acreage having the horizontal potential. You mentioned now you think your full 14,000 net acres has some horizontal opportunities and are those spread amongst the Mississippi line decline, the Wolfcamp formations like that or just a little bit more color on the Permian?
James Palm – CEO: Well they will transition into as many horizontal wells as they can, as quickly they can, but we’re seeing people drilling all the way up the Andrews County which is kind of on the north end of our acreage drilling various formations up there, some of these are feedback that our guys down in Midland at Diamondback give us from the other operators they deal with. So, it looks like there is multiple zones. For instance, the Spraberry, nobody’s even talked about Spraberry but we conducted some what we call science wells back early when we got into the south end and we after we did 10 stage jobs where we perforated 20 feet and frac through 100 and we’ve in fact swaps the intervals and we’ve found that the Spraberry wasn’t quite as good as the individual Wolfcamp perfs, but they were probably 75% as good those are 1,000 feet of Spraberry there you could probably put three different horizontal wells in the Spraberry. No one has even talked about that yet. So there’s Clearfork going on there’s Cline going on, with all those zones, we haven’t been able to terminate any of our acreage. We’re looking forward to seeing the derisking by the actual wells being drilled and then you can bet the guys at Diamondback will already be doing the land work in anticipation of get on doing their own wells up there.
Ronald Mills – Johnson Rice: On the Janey well I know (Kalen) had an offsetting well that almost 95%, was that production profile also in the 90% to 95% oil and you mentioned it’s been on for another 15 or 20 days from the 30-day rate, is that rate continue to holding there beyond the 30 days?
Michael G. Moore – SVP and CFO: Janey was about 85% to 90%, just pretty much similar to the rest of our vertical wells as a matter of fact.
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