Gulfport Energy Corporation (GPOR) Q2 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corporation Second Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the call over to your host, Paul Heerwagen. Please go ahead.

Thank you, Stephanie, and good afternoon. Welcome to Gulfport's second quarter 2012 earnings conference call. I'm Paul Heerwagen, Director of Investor Relations, and with me today are Mike Liddell, Chairman of the Board; Jim Palm, Chief Executive Officer; and Mike Moore, Chief Financial Officer. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and business. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we may make certain reference to other non-GAAP measures. If this occurs, the appropriate reconciliations to GAAP measures will be posted to our website. An updated Gulfport presentation was posted yesterday afternoon to the website in conjunction with today's earnings announcement. Please review at your leisure. At this time, I'd like to turn the call over to Jim Palm.

Thanks, Paul, and good afternoon to each of you. I'm pleased to report that Gulfport reported strong second quarter 2012 results, generating approximately $49.8 million of operating cash flow, $49.4 million of EBITDA and $25.1 million of net income on production totaling 663,000 barrels of oil equivalent. Solid production and free cash flow generation, both hallmarks of our core Southern Louisiana assets, characterize the second quarter, allowing us to further advance the number of high impact projects that are expected to provide both significant near-term catalysts, as well as long-term opportunities. While Southern Louisiana continues its role as our cash flow cornerstone, our future is being shaped today as we reach milestones daily in our development of the Utica Shale, the Horizontal Permian and the Canadian Oil Sands. As many of you are aware, Gulfport made a strategic decision during 2011 to devote significant capital and operational attention toward establishing the Utica Shale as a principal focus area for the company. Throughout 2011, we focused on putting together our acreage position, targeting the core of the play based upon certain high graded geological and petro physical characteristics. By the end of 2011, we amassed a position totaling 125,000 gross or 62,500 net acres, making Gulfport one of the top 3 public companies most leveraged of the Utica Shale on a per share basis and possibly the most leveraged of the core of the play overall. In 2012, we shifted from acquisition to drilling mode. We've drilled 5 wells and currently have 2 wells drilling, 1 well frac-ing, 3 wells under resting period and our first well was recently brought on production. Given the sample data we've collected thus far, we are now in a position to provide production results on our Wagner 1-28H well, as well some initial data points from our ongoing test and resting program on 3 other wells. Our Wagner 1-28H well, which was drilled to a total vertical depth of 8,673 feet and with a 8,143-foot horizontal lateral, was completed with a 28-stage hybrid hydraulic frac treatment. The well was brought online in early August and tested a peak gross rate of 17.1 million cubic feet per day of gas and 432 barrels per day of condensate. Based upon composition analysis, the gas being produced is 1,214 BTU rich gas. Assuming full ethane recovery, this composition would produce 110 barrels of NGLs per million cubic feet of gas, resulting in a gas shrink of 18% and a total rate of 4,650 barrels of oil equivalent per day. In ethane rejection mode, this composition would produce 41 barrels of NGLs per million cubic feet of gas, resulting in a gas shrink of 8% and a total rate of 3,755 barrels of oil equivalent per day. Meanwhile, frac load water recovered was minimal, averaging about 1.5 barrels of load water per barrel of condensate in the tank. The striking thing about this test was the strength of the Wagner well. We started with 5,100 pounds shut-in tubing pressure and 5,200 pounds shut-in casing pressure. At the end of the first hour, we were producing at the rate of 12.2 million cubic feet with 4,200 pounds flowing tubing pressure and 5,100 pounds flowing casing pressure. 8 hours later, we have set the well up to a rate of 17.1 million with 3,100 pounds flowing tubing pressure, and we still had 5,000 PSI flowing casing pressure. The strength of the well was demonstrated by the fact that the flowing casing pressure only drew down from 5,200 to 5,000 PSI, even when we were producing over 17 million cubic feet per day. We're currently selling gas and we will be flowing this well at a rate of about 10 million cubic feet per day through safety units until mid-September, at which time we plan to redirect production in the MarkWest to this processing plant. In addition to the production results from the Wagner 1-28, we have collected some preliminary information from the other wells that we finished frac-ing. We've modified our completions to allow us to both test and rest our well. Before we frac the final stage of the lateral, we set a permanent plug which isolates that final stage so we can test our last frac stage while we let the rest of the frac stages rest. We call this our test and rest procedure. Using this approach, we can look at the initial productivity, the gas composition and other information from the last frac stage soon after we finish frac-ing the well. Then we come back periodically for additional tests, which will help us determine how long the resting period is appropriate for our wells. While the results of these tests are very preliminary, we're prepared to share some of the information we've collected with you today. First is our Boy Scout 1-33H well, which was drilled to a total vertical depth of 7,704 feet with a 7,974-foot horizontal lateral and was completed with a 22-stage hybrid hydraulic frac treatment. Immediately following completion, we proceeded to test the final isolated frac stage, and while the test lasted only a total of 7 hours, preliminary indications were very positive. Of note is that the single stage kicked up, cleaned up on its own. We started out with around 136 barrels of water per hour, and 7 hours later, at the end of the test, we were only making 41 barrels of water per hour. We saw first natural gas minutes into the test and measured a maximum rate of 470,000 cubic feet of gas per day. After about 5.5 hours, the pullback through reported the wells started making condensate, and about 1.5 hours later when we concluded the test, the well had made 40 barrels of condensate. We also counted gas samples as part of this process, and composition analysis showed it to be 1,310 BTU rich gas. Assuming full ethane recovery, this composition would produce 142 barrels of NGLs per million cubic feet of gas and results in a gas shrink of 25%. In ethane rejection mode, this composition would produce 84 barrels of NGLs per million cubic feet and result in a gas shrink of 17%. I would note that in such an early stage of the well's pullback, it's very rare and we found it very encouraging to see such high condensate volumes and low water recoveries. And remember, this is from only 1 of the 22 frac stages in the well. We currently anticipate bringing this well online flowing into gas sales line by mid to late September. Next is our Groh 1-12H well that was drilled to a total vertical depth of 7,289 feet with 5,414 foot horizontal lateral and was completed with a 15-stage hybrid hydraulic frac treatment. Following completion, we elected to test the final isolated frac stage. Again, the stage kicked off on its own and water production was minimal and gas and oil came quickly. From this one stage, we measured a peak rate of 384,000 cubic feet of gas per day and 192 barrels per day of condensate. Based upon composition analysis, the gas produced was 1,289 BTU rich gas. Assuming full ethane recovery, this composition would produce 145 barrels of NGLs per million cubic feet of gas and results in a gas shrink of 24%. And in ethane rejection mode, this composition would produce 67 barrels of NGLs per million cubic feet of gas and results in a gas shrink of 11%. With the data we collected, we hope to establish a scientific basis for the link in which we decide to rest our future wells. We currently plan to have this well producing and flowing into the gas sales line by the end of September. And finally, onto our Shugert 1-1H well, which was drilled to a total vertical depth of 8,661 feet with 5,758-foot horizontal lateral and was completed with a 16-stage hybrid hydraulic frac treatment. Following completion, we set a permanent plug and pulled back the last stage. From this one stage, we measured a peak rate of 2.9 million cubic feet of gas per day. Based upon composition analysis, the gas being produced is 1,204 BTU rich gas. Assuming full ethane recovery, this composition would produce 100 barrels of NGLs per million cubic feet of gas and results in a gas shrink of 17%. And in ethane rejection mode, this composition would produce 40 barrels of NGLs per million cubic feet of gas and results in a gas shrink of 9%. We currently expect to have this well producing and flowing into the sales line by the end of September. While we're very pleased and encouraged by these initial results, I'd like to caution you that these are very preliminary numbers. Ordinarily, we would not provide these types of limits to data points, but we know everyone is hungry for data on the play and given the significance to the play of Gulfport, we felt it's important that the market know exactly what we know. And now turning towards the midstream side of the play, we're very pleased with our partnership with MarkWest. They have an aggressive construction program for both pipelines and processing, allowing us to begin flowing our wells and receiving revenues much faster than our counterparts. We're devoting significant attention towards refining our drilling and completion practices and are actively securing our takeaways so as to maximize our returns from this blossoming play. Due to a number of strategic arrangements, Gulfport has positioned itself to control the quality, timing and availability of its service and takeaway needs of the play. The Utica Shale is a huge part of Gulfport's future, and we are preparing to execute accordingly. Now turning towards West Texas. During the second quarter of 2012, a total of 7 Diamondback operated wells were drilled on our acreage in the Permian, and at present, we are drilling ahead on the 15th well of 2012. In June, Diamondback brought online the Janey 1-16H, the first horizontal well in the play. The Janey well was drilled to a total vertical depth of 8,850 feet with a 3,840-foot horizontal completed lateral and was completed with a 16-stage slip water hydraulic frac treatment. The well tested at a peak rate of 618 BOE per day and went on to produce a sustained rate of 486 BOE per day over the first 30 days it was on production. Diamondback is currently putting together its next horizontal lateral on this lease, the Neal 8H, which is planned to have a 7,000-foot lateral. This well is expected to spud in the late fourth quarter, and the target will be the same Wolfcamp B zone produced in the Janey 16-H well. In addition, we continue to be encouraged by the horizontal drilling activity of our peers in the play and are actively benefiting from their success as we participate in wells with them and share data to better understand the optimal development strategy. Based upon the early indications of success by other operators nearby, Diamondback is also looking at horizontal potential within a number of different zones. We are moving up the learning curve quickly, and at this point, all of our acreage appears to have horizontal potential. Some generalizations so far are: first, the drilling and completing of the Janey 16-H in the Wolfcamp B interval in the Upton County confirms the viability of horizontal development across our blossoming acreage block of 8,200 gross acres. On a 16O-acre spacing, that translates to over 50 additional gross future locations. In addition, if the Wolfcamp A interval proves out, that well count easily doubles. Although there's still less than 60 days of productive data from the Janey 16-H well, I expect virtually all future development in this area will be horizontal. This well pad also had 5 vertical wells in close proximity, and we've not seen any interference in those wells supporting the theory that you can have both vertical and horizontal wells in the same section. Something I believe our colleagues at Pioneer have also alluded to. Secondly, formations under the -- in the Wolfcamp are being tested. We are participating with a small interest in a horizontal Clearfork well in [indiscernible] County. This well was successfully drilled and completed in a 4,000-foot lateral, with pullback operations currently underway. This is only the second horizontal well ever drilled in the Clearfork in the Midland Basin and could stand to unlock other ventures of play for horizontal development. And finally, we are participating again with a small interest in the first horizontal cline well in Midland County. This well was successfully drilled with approximately 4,000-foot lateral length and is scheduled to begin frac-ing in mid-August. In summary, Gulfport is either directly or indirectly involved in 3 of the first modern horizontal wells in a multicounty area in the Midland Basin, and within the next 90 days, we expect to have meaningful production tests from 3 different horizons. When you look at this level of participation in untested intervals across multiple counties, I firmly believe Gulfport and our partner, Diamondback, are leading the way to access the economic viability of horizontal development. Diamondback is aggressively moving towards horizontal drilling as a major component of its drilling program as rapidly as activity from Diamondback and others in the industry can de-risk both areas and the zones that which the horizontal well will be drilled. Shifting down towards Canada. Grizzly continues to be on schedule and on budget in building its first SAGD facility in Algar Lake. Grizzly has finished drilling all 10 SAGD well pairs and is currently in the process of completing and plumbing up those wells for SAGD injecting and production. Meanwhile, having largely completed sites civil work, simple processing facility modules are now being shipped from the fabrication yard near Edmonton to the Algar Lake location. As you can see in some of the pictures we've included in our updated presentation, these modules are already being set on piles and joined together. We anticipate this process to continue on into the fourth quarter with commissioning scheduled to begin in late fourth quarter. Meanwhile, from an exploration standpoint, Grizzly continues to work through the goal of filing an application for a commercial project at Thickwood Hills by the end of this year. In addition, Grizzly has laid out the framework for its plan to have 70,000 barrels per day producing from its recently acquired May River property. This production is expected to initially come online at 13,600 barrels per day in the 2016, '17 timeframe and is expected to drill by 20,400 barrels per day increments in 2018, '19 and '20. Grizzly is currently finalizing plans for our winter drilling program to support this strategy. And now on to Southern Louisiana. At Hackberry, during the second quarter, we drilled a total of 7 wells, completing 2 wells as productive, with 2 wells waiting on completion and 2 wells drilling at the end of the quarter. In addition, we performed 4 rig completions. We are currently running 2 rigs at Hackberry, growing ahead on our 14th or 15th wells of 2012. Meanwhile, at West Cote Blanche Bay, during the second quarter, we drilled a total of 9 wells, completing 4 as producers, with 2 waiting on completion. And we had 2 wells drilling at the end of the quarter. In addition, we performed 13 recompletions. And at present, the barge rig is active at West Cote and is drilling ahead on the 18th well for 2012 program at the field. Moving along to Colorado. In the Niobrara, we recently finished drilling our first well based upon the results from our recent 3D seismic survey. The well is waiting on completion, and our second well should spud near the end of this month. We are currently in the process of permitting a number of other locations along clearly defined faults which we identified from our 3D seismic survey. So to wrap things up today, I want to make a quick observation about our position in the Utica. By now, everyone has heard about Chesapeake's Buell well, which is located on the northern end of our position. No doubt, it's a very impressive well. Meanwhile, we're hearing about some very strong rates being generated by Antero from its first 2 wells in Monroe and Noble Counties towards the southern end of our position. The Hess well in Jefferson County to the east of our position, while dry gas is highly economic at 11 million cubic feet of gas per day, and with our recent results from our Groh and Boy Scout wells, things on the western edge of our acreage are looking very strong. Meanwhile, I can say without a doubt that our Wagner well is by far the strongest well that Gulfport has ever drilled. So from north to south and east to west, we're starting to feel like we're already finding the sweet spot, and we continue to see that our acreage seems to be located right in the middle of it. We believe there is a high volume of recoverable reserves packed into each acre in this very repeatable play. And if you run the numbers, you'll see that Gulfport stands -- that the Utica stands to be a real company changer for Gulfport. And thank you for your time and interest today, and now I'd like to turn the call over to Mike to cover our financial highlights.

Thanks, Jim, and thank you all for joining us for our call. During the second quarter of 2012, Gulfport generated approximately $49.4 million of EBITDA, $49.8 million of operating cash flow and $25.1 million of net income or $0.45 per share based on average diluted shares outstanding of $56.3 million. During the second quarter, production totaled 663,626 barrels of oil equivalent or 7,293 BOEs per day, which is up 17% on a unit basis year-over-year compared to the second quarter of 2011. Allocated by fields, second quarter production breaks out to be 3,385 BOEs per day from West Cote; 2,630 BOEs per day from Hackberry; 1,128 BOEs per day from the Permian; and 150 BOEs per day from the Niobrara, overrides and other miscellaneous areas. Our production mix for the second quarter was 95% oil and natural gas liquids and 5% natural gas. Subsequent to the second quarter, July production averaged approximately 7,121 BOEs per day. Moving along to the income statement, revenues for oil, natural gas and natural gas liquids in the second quarter totaled $66.3 million. Average realized prices for the quarter were $106.86 per barrel of oil, $2.50 per MCF of natural gas and $36.25 per barrel of natural gas liquids. Our blended price for the second quarter was $99.84 per barrel of oil equivalent. Lease operating expenses during the second quarter were $5.7 million or 8.61 per BOE, down 5% sequentially on a unit basis from the first quarter of 2012. General and administrative expense for the second quarter was $3.3 million or $4.92 per BOE, up 5% sequentially on a unit basis from the first quarter of 2012. As we ramp up the Utica, our G&A will outpace production slightly, temporarily leading to higher unit costs until production catches up with the staff we've added to support it. Our 2012 full year G&A guidance remains unchanged at $3.50 to $4.25 per BOE, as our forecasted production growth in the third and fourth quarters should offset our growth in G&A. Depreciation, depletion and amortization expense during the second quarter totaled $23.7 million or $35.64 per BOE, up 7% sequentially on a unit basis from the first quarter of 2012. DD&A was up quarter-over-quarter as a result of the company having drilled a large percentage of on-book locations. In terms of capital expenditures, during the second quarter, we spent a total of $56 million on 2012 activity, which excludes Gulfport's portion of Grizzly activity and Utica leases. Moving on to the balance sheet. As of the end of the second quarter, we had $6.6 million in cash and had drawn $68 million on our revolving credit facility. At present, we have fixed price swaps in place for 4,000 barrels per day of production for the remainder of 2012 at a weighted average price of $107.29. In addition, Gulfport has been solidifying its hedging program for 2013, locking in fixed price swaps for January through June of 4,000 barrels of oil per day at a weighted average price of $103.33 and fixed price swaps for July through December of 3,000 barrels per day at a weighted average price of $100.04. Gulfport's 2012 and 2013 price swaps hedge Brent crude at the underlying index. As a final note, I'd like to highlight that this current level of hedging for 2013 effectively secures $130 million of revenues for 2013, which will go a long way towards securing our capital commitments for our contemplated 2013 capital program. Meanwhile, I will close today by mentioning that we are aware there's been a lot of focus on NGLs as of late and a number of analysts have published some very good reports recently. The biggest question revolves around ethane and propane, so I will limit my comments to those products. We are estimating at this time that our rich gas production will contain between 2.5 and 3.5 gallons of ethane per thousand cubic feet of gas. We do not disagree with the ethane experts who believe U.S. ethane supplies could outstrip demand over the next couple of years. However, a number of new world-class crackers have been announced, and we believe that by 2015, 2016, demand will outgrow supply. If this is true, producers will soon need to maximize ethane recovery throughout the country in order to meet the new ethane cracking demand from the new crackers that have been announced. All of our gas will be processed at MarkWest, Harrison County cryogenic processing plant, and we anticipate delivering our ethane into the enterprise ATEX Express pipeline for delivery to the Gulf Coast buyers starting in 2014. Propane is a slightly different story. We expect our rich gas to contain between 1 and 2 gallons per cubic feet of propane and heavier components with propane being a little over half of the stream. Again, there's been a lot of discussion about propane supply and demand in the Northeast and a number of good analyst reports. Our view is that for the short-term, propane in the Northeast will continue to command a premium for at least the majority of the year. This has been a difficult year for propane, as supplies have grown significantly, combined with a historically warm winter. The good news for propane is that a number of significant propane export facility expansions in the Gulf Coast will be completed this year and will certainly help propane balance, and as a result, prices. At this point in time, it is probably worth mentioning that one of the reasons that we have partnered with MarkWest to process our gas and to fractionate our NGLs is that MarkWest has been the largest NGL fractionator in the Northeast for over 20 years. We believe their NGL marketing and storage infrastructure is simply far better than any other facilities in the Northeast. I thank you again for joining us for our call today, and we look forward to answering your questions.

Stephanie, please open up the phone lines for questions from our participants.

[Operator Instructions] Our first question comes from Neal Dingmann from SunTrust.

Jim, 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?

Neal, it's just a small fraction of the load. I couldn't give you a 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, and we didn't expect to get much load back, and it looks like that's going to be the case. So we won'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 minimal problem up there, it looks like.

It sounds great. And then looking ahead, you mentioned a couple of these other wells like the Shugert and some of these others now. I guess if you just had a sort of dumb that down in layman's terms a little bit, it does sound like at least the flow rate and -- that you maybe -- liquids maybe would be a bit more, is that fair to say, Jim?

Well, that's for sure. That shows as we move west, it's really coming in just as we expected. The further West and the shallower, the more condensate we seem to be seeing, and 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 the casing. So they're unloading up the casing without the benefit of the tubing, so we're not getting all the fluids out of them. So the rates you'll see to the West are a little bit lower than you see to the East, but that's because there's so much hydrostatic on the bottom. I think it's just incredible that these rates with all these wells above the [indiscernible] are making from just single stage are completely unloading that up 5.5 and continuing to flow during the test periods. So we're really seeing strong performance over there. And don't let those rates mislead you, we'd be making a lot more gas and liquids if we had tubing in the hole like we have on the Wagner.

Keep in mind, I just want to keep reminding this -- all of these, this is -- these other rates are just one interval out of multiple intervals in those zones.

Yes. And then 2 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 this 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.

Well, sure we have. Of course, we've said we thought we'd have 10 wells producing by the end of the year, and the 2 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 third rig a month or 2 ago in anticipation to having this 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 will come, I would guess, on 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 a tight leash.

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 it out of 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's always a balancing act between cash flow and drilling wells and ramping up, so we'll just have to move forward and make those evaluations when it's appropriate.

And then lastly, Mike, to follow on to that, it does sound like certainly if you would add a rig or even 2, you -- your and Jim's comments about MarkWest, you certainly have the capacity and processing availability.

Yes, we do. We certainly do. And we're very excited about that relationship and the fact that they're staying up with this so that we can hook our wells up as quickly as possible when we complete those wells and also making sure we have plenty of takeaway capacity.

Our next question comes from Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: On your presentation, you highlight where you're currently drilling and where your recent wells are. You've also highlighted the higher liquids content as you move west through 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 2 rigs throughout the year, what does the location of those wells look like in terms of West versus East and North versus South?

Well, we really like what we're seeing along the line from the Buell well to our Wagner well and down to the Shugert well. They're basically on depth and we expect comparable results from all those wells. Down to the South, we these Antero 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 may be that liquids-rich line is moving to East of where we had it before we got the Antero reports. So most of our drilling will be along that line and to the west, but we are in the delineation face of our program, so we'll drill 1 or 2 over on the East side, even in we anticipate will be quite gassy areas. 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 may dramatically lower the cost of our frac and 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 can get the cost down a lot over there.

But we are, to that point, we are focusing towards the West. I think that is key here. We do have 50 locations working, 7 permits filed and another 150 locations identified, but we are trying to focus west as much as we can.

Yes. We want to find out about the East, but next year, if it's the same it is today, we'll basically be drilling the West side. But we continue to delineate what we got, East, West, North, South. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And I don't think you're ready to talk about well costs yet, but in terms of versus expectations, I know you drilled longer lateral than -- the 8,000-foot versus, what, some of the other wells have drilled at and you'd 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?

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 hole portion where we go down below the point pleasant, and we got an electric log over the interval because we have to stir with that. So then we come back up, sort of plug, which stopped well all that costs more money. So in this phase, rule of thumb is $1,200 per foot for an 8,000-foot lateral and $1,500 per foot for a 5,000-foot lateral. And we're seeing that, here we are in the seventh well and we've seen that with the AFEs we're doing today is we propose wells to the 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 at something like $1,000 a foot for an 8,000-foot lateral, $1,200 per foot for a 5,000-foot lateral. And, of course, right now, these wells that we're drilling, we're building location, which can sometimes be pretty expensive up there. And sometimes, we're building location that's -- we've already got 6 wells planned up as it grown -- we're taking all that cost on the first well we drilled. So obviously, when we put pad rigs out there after we do some delineation, we come back to start building the other 5 location. We're off to head start. And we've seen what the casing programs are like. Pretty much, the casing has been -- casing designs and everything, it worked 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 been really -- well, I'm not going to [indiscernible] while I say this, it's been really a surprisingly consistent and predicable area. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Good. And then in the Permian, you talked about the Janey well and now you're going to spud the Neal well as well. But in your conversations with Wagner/Diamondback 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 the blocks of 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?

Well, they will transition into as many horizontal wells as they can, as quickly as they can. But we're seeing people drilling all the way up to 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 done in Midland at Diamondback gave us from operators they deal with. And so, it looks like there's multiple zones. For instance, the Sprayberry, nobody's even talked about Sprayberry, 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-ed 200. We went back to swab the intervals and we found that the Sprayberry wasn't quite as good as the individual Wolfcamp perfs, but they were probably 75% as good. There's 1,000 feet of Sprayberry there. You could probably put 3 different horizontal wells in the Sprayberry. Nobody has even talked about that yet. So there's Clearfork going on, there's client going on, with all those zones, we haven't been able to eliminate any of our acreage. We're looking forward to seeing the de-risking 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 getting on and drilling our own wells up there. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then Janey well, can you -- I know Callon had an offsetting well that was almost 95% oil, is that -- 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 hold in there beyond the 30 days?

Yes, Janey was about 85% to 90%. Just pretty much similar to the rest of our vertical wells as a matter fact.

Our next question comes from Jason Wangler from Wunderlich Securities.

A question on the Utica, you kind of hit on a bit from Ron's question, but just wondering the permitting situation, is it still okay there and maybe how many do have in hand and how many do you think you have as you move forward?

Well, we have I think 7 in hand right now, but it's -- no problems at all with the permitting. It's still a pretty efficient, easy process for us in the State of Ohio. We actually have a full-time permitting guy now as we've staffed up. But we're working, like I said, our Land Department is working 50 locations right now, another 150 identified to get to the 200 that we're going to drill over the next 4 years. But we've not really experienced any problems there, Jason.

Great. And then just maybe you as well Mike for this one, obviously, the oil hedges you laid on. As we see the Utica start to contribute more and more to the production by all accounts as these wells, if they come on like they look like they will, the gas and the liquids will move up. What are the thoughts on hedging gas and maybe even NGLs as we maybe get into '13 or even beyond as that number starts moving higher?

Jason, that's a good question and it's a possibility. I mean, we are feeling a lot better now about going into 2013 considering that we have $130 million of our revenue locked in, and which is probably a significant portion of our CapEx spend next year. But as we get these wells on and we see the product mix -- the exact product mix and as we move to 2013, I think we will start looking at that seriously. It's just too early to say what we might do. We do think there could be some recovery in gas prices, so we don't want to get too far ahead of ourselves here. But we would consider it just as we consider oil hedges.

Do you think it may be, again, it's down the line as you said, would it be maybe similar to what you've kind of done in the past where it's a call around 1/3 of production or something like that or would you maybe even to 1/2 or probably not too much more than that because you do have minimal fixed cost that you have to cover?

No, that's right. And, of course, historically, we've been anywhere from 40% to 70% hedged, I think typically about 1/2 is where we usually end up. But you would -- it would seem logical for us to do something like that. But again, it all depends on what we think forecasts for gas prices, NGL prices, so all those factors have to weigh into it as well.

Our next question comes from Tim Rezvan from Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: A couple of quick ones for you. On, first, Wagner well, when do you start kind of booking volumes on the well?

Well, we're selling gas now. Is that what ... Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Oh, you're selling gas now. Okay. And the condensate as well?

Correct. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay, okay. And that just started a couple of days ago?

Yes, really. Actually, after we did the $17.1 million through the atmosphere, then we started pinching the well back, so we could put it in the sales line.

Yes, just started a few days ago, Tim. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay, great. And then, what's your -- you have a 50% working interest, what's your net revenue interest in these wells?

Overall in the play, it's about 81-plus, a little over 81%. So if you take $10 million, then we'll have -- we have a 50% partner and we've got the royalties to pay, so we'll net $4 million out of that $10 million, plus a little.

This well is definitely 81%. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. Okay, it's helpful. And then, If I heard you correctly in the call, you said second horizontal well in the Permian would be spud in the fourth quarter, was that correct?

Yes, that's right. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. Just curious, is there a reason for that delay?

Well, mainly it's land related. Usually in the Permian, you have leases, and they usually say there that they won't be putting a unit that's more than 40 acres. So you have to get people to modify the leases, which you can obviously tell them we can drill a horizontal well, you have a piece of it, and they will, but it just takes time. But also we're moving. At 7,000 feet, you're drilling into 2 different sections, so it's just a different situation than your routine well that you permit there.

But remember also, Tim, we are now participating with others on -- in 2 horizontal wells. So it's not like you don't have any horizontal activity right now, but so we do have 2 non-operating horizontal wells going on right now. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: And if you were to kind of grow activity in advance of a Diamondback IPO, so that would seem like more of a 2013 event?

That's right. Well, let me say it too, though, that it's possible, like on the north end, we have for instance, a bunch of University of Texas acreage, and this does pretty blocky. So if we want to drill a horizontal well up there, there may be places where we can put one that would come together a lot quicker. So some operator moves in and proves up the potential up there, we might manage to beat that -- the start down on the south end where it's more conventional acreage by going north. So I wouldn't say that's the only well we're going to drill by the end of the year horizontally. They could do more than that.

Our next question comes from Leo Mariani from RBC.

Just a quick follow-up question on the Wagner well. You guys talked about it producing 10 million a day, is that just the gas rate? And if so, what's the condensate rate on that well right now as well? I know that you're somewhat limited in the very short-term in terms of the NGLs you can process out of that, but how much are you able to sell today out of that well?

Well, if you're making 10 million a day, like we said, the full stream's 110, but that includes ethane and other NGLs. Then we've got about 41 barrels per Mcf of -- or per million cubic feet of the other components on the NGLs. So you can just do the math on that. Then you have to shrink it by the factor that we gave you, that would be about an 8% shrink. And so you won't sell the full 10 million as gas, you'll sell 9 or 10 -- about 8% or 9% less than that by the time you shrink it because you made it to NGLs.

Whatever we're selling, Leo, the condensates reduce proportionally.

Yes, everything that we gave you in there, just reduce the 17 million in those numbers that we gave you proportionately, and you'll have what 10 million is.

Got you, okay. I guess in terms of the Shugert well that you guys talked about, you mentioned 2.9 million a day of gas. You didn't say any about condensate. Was there condensate in that well also?

There is some condensate, but I got to point out to you again, this one's coming up the casing. Because it's on the East side, we expect less condensate. And we didn't get a test like this on the Wagner, so we really don't have a apple and an apple to compare here. So I think it's remarkable the well's cleaned up, but there's undoubtedly a lot of liquids down there. And so, it's also about -- actually the average depth on that well is about 40 feet shallower than the Wagner. So I think it's going to be just like the Wagner or maybe have slightly more condensate richness to it. The test we got on it, this initial test that we got yesterday, which was shortly after we started producing the well is right in line with the Wagner test. So Wagner, Buell, Shugert, they all ought to be similar I think in terms of the way they produce because they're basically all of the same depth.

Yes, Leo, so just to reiterate what Jim just said, it's early. I mean, sometimes the condensate shows up after a little bit, so we just started testing midday yesterday. So it's very early.

Got you. All right. And I guess in terms of the Janey well, to try to get sense of what the well cost there was?

The Janey well was about $6-plus million, about $6.5 million I think.

Okay, got you. And when do guys plan on frac-ing your first Niobrara well that you have with the 3D there?

I don't know that we'll frac any of them, but the 2 best wells up there that are 6 miles east of us over on Buck Peak made 1.5 million barrels a piece and they're natural. They hit the fractures and, of course, that's why we -- there's a lot of other wells drilled over there. There are some darn pretty good ones, but there's some dry holes too. So that's the reason we shot the 3D. We hope that we'll -- I'd like to duplicate a well like that, but we don't really expect that we need to frac. We may frac, but right now, we think the most important thing is to hit the fracture so you don't have to frac.

All right. I guess, when do you expect that well to go on production, then?

Yes, the well we just finished drilling, the rig is -- the drilling rig is still setting on it. It's going to Quicksilver, and they weren't quite ready to take it. So we're just waiting for them to get the rig off and anticipate within about a week, we ought to do that. Then with these wells, since we don't frac them, the only thing we have to do to produce the well is put a completion rig on, run the tubing, run the rods, run the pump. But it's pumping and we're ready to go. Natural completion.

All right. And I guess in terms of these next 3 wells, you guys were good enough to give us some preliminary data on in the Utica, are we going to have to wait for third quarter earnings to get more data on that? Or will you guys put out a release ahead of that once those wells are on production?

Well, what we'll do, for instance after a month, we'll go back and run another test on these wells on our -- to test and rest. So if we have time, we'll go back and run a second test, and we're doing that to try to figure out how long it's appropriate to rest them, but as we've pointed out, they're all going into the pipelines at the end of September. So by the time we have the next call, we should have some -- probably have some production data for you.

Leo, we probably this next time would want a full test. So we probably won't wait until the end of the quarter. We could give you some information ahead of that, but we probably need to get -- want to get a full test this next time to give you guys a full set of information.

Our next question comes from Brian Velie from Capital One Southcoast.

Just a couple of quick questions, most of mine have been answered. I want to make sure that I'm thinking about this right. With such a positive well coming on and you mentioned a couple more that will probably come on this year maybe than you had previously anticipated, would it be right to think that the full year guidance didn't change more because it would be difficult with such early results to know what to change it to or is it because focus in other areas like South Louisiana, maybe some CapEx that would've gone there is going to go into these additional wells in the Utica? Is it more other stuff that's going to come off a little while you focus in the Utica or just that -- how would you pick a number?

It's a good question, Brian. We moved -- we did move CapEx around a little bit just to be what we thought was a good representation of the last 6 months of the year. So what we did was, in west, it looks like we're going to drill a few more shallow wells this year, which frees up some CapEx, move that over to Hackberry. We knew at this point we're going to drill more that the 10 well we announced, so we knew that we were going to spend more money over there. But we could've started moving guidance around and production around based on this first well, but we just don't like. It was a little early to start doing that, Brian. And so, I think it's probably more appropriate in the third quarter to give you guys some updated guidance for the full year as we get these wells online. We just -- at this point, it just seems early.

All right. And then the other question, I just wanted to kind of dig into a little bit, all the test results from the western test wells that you mentioned, I was trying to get them down on paper as quickly as I could. I have to go back and check the transcript. But would it be fair to say that the numbers that we should probably be focusing on would be those that have more to do with the production makeup in terms of liquids content than any of the rate because of the casing issue and then the fact that we're trying to extrapolate just 1 stage wouldn't be really a good idea or lead to much accuracy?

No, that's right. The big takeaway is that just as we expected, we're getting oil here, we're getting better BTUs. Everything is moving to the West. When you go to the west, you get more of those liquid components, and that's the best takeaway we've got. The rates, you're right, the rates are not important takeaway over there because with all those liquids coming up 5.5, the well can't unload. So I think it's just really impressive to me that with 5.5, you really don't usually manage to get a well that will continue to test the way these things do without putting tubing in the hole, and yet they're strong enough from just 1 zone to really come on and make those kind of rates they've got. If we had tubing in the hole, you'd be seeing the gas rates there that would be more comparable to the gas rate over on the East side when we did Shugert just from that 1 zone.

Our next question comes from Adam Lawlis from Simmons & Company. Adam T. Lawlis - Simmons & Company International, Research Division: On the -- on your water results in the Permian, your horizontal Wolfcamp result, does that change your thoughts of participating in the Diamondback IPO or Diamondback's timing for the disclosed plan 2 IPO?

That's a good question. I know where you're going with that, but we continue -- our understanding is that Diamondback continues to work through the process with the SEC to be in a position on that IPO when the market is ready. Its, certainly, positive horizontal results are good on both ends. So I don't really think it changes that for us. And Jim, what would you add to that?

Well, I'd say too that if the IPO goes through, we are not out of the Permian, we're not out of Diamondback. We still will have a significant -- and we'll have stock in a company that looks like it's going places. We won't have to provide any more capital to it, and we'll have the appreciation and the stock that we've got there. So that's how we'll -- either way, we're a winner, we'll either continue to have, if it doesn't go through, we'll to continue to be a working interest in a great play. If it does go through, we'll continue to write stock. So it's a win-win either way.

And of course those results are -- they're just out. We're just talking about those results today. So the market needs to get time to digest that and decide what they think and decide how it might affect the potential valuations there. Adam T. Lawlis - Simmons & Company International, Research Division: All right. That's helpful. And then switching gears, with your initial Wagner results in Boy Scout, Groh, Shugert, all the testing results in there, how did those tie into the 450 to 910 MBO EURs that you guys estimated earlier?

Well, it makes -- it actually makes those initial estimates on the low side of what's possible. The best thing I'd direct you to is what Chesapeake had to say about the Buell well. And they said on the Buell, which had a 3,000 BOE per day initial rate, and here we are about 1.5x that. They said they anticipate that they're going to make 575,000 barrels of liquids and 13 Bcf of natural gas. And we have a lateral that's about 20% longer than theirs. They had 18 frac stages, we have 28 frac stages. So I'd certainly be satisfied to have those numbers they're talking about, but given that they're at the same depth and with those parameters to go with our well versus theirs, I think the numbers that they drew out there times whether we want to take it or whether we want to gross up by makes for some monstrous numbers, so -- I mean, I'm almost embarrassed to come out with the numbers that you get when you gross that up. You could do the math on the thing, you'll see that it's a huge well. Adam T. Lawlis - Simmons & Company International, Research Division: All right. That's very helpful. And how are service costs trending in the Utica and the Permian?

Well, in the Utica, it's a pretty good time to be in the Utica now because of the slowdown in the Marcellus, so -- and we've actually seen people really sharpening -- sharpened their pencil with regard to the frac jobs and things. And so, we're not seeing that we're going to have a hard time finding good rigs at a reasonable price if we decide to add rigs in the Utica. And then, when we go to the Permian, last year, it seemed like there was more of an escalation in the cost, they were climbing. I can't say now they're coming down, there's probably a little more constraint as far as services go. They are adequate, but there's not so many of it. There's I think -- what I'd say, we're seeing the prices come down a little bit in the Utica. It's probably more flat in the Permian, I'd say. But there's not the crisis that there was a year ago and people couldn't get frac sand and things like that. But these things run in cycles, and so we expect that even though today, for instance, on the drilling rigs in the Utica, a year from now, that's going to look a lot different, there'll be a lot more going on up there. You will be having trouble getting things like frac sand, that's why we're glad we've got an interest in our own frac sand line that we've got an interest in. So we'll be frac-ing with our own sand before the year is out up there. And we're kind of good and prepared for our long-term future up there with takeaways and furnishing our own sand, having an internal takeaway oil and so forth. So it's going to be quite a play for us in the Utica.

Yes. And so, just to add to that just quickly, like we've done in our other areas that we operate, we do try to vertically integrate. Jim mentioned some of the ways that we've done that up in Utica. So we do that to first of all make sure we have availability of those services and supplies, but also to make sure that we can ensure the quality of that service that we're getting. So that is one of the way we de-risk as an operator when we're getting in plays and operating. Adam T. Lawlis - Simmons & Company International, Research Division: Great. And one last quick one, can you guys talk about the M&A A&D appetite in the Utica and the Permian? Just across the industry.

Well, I think it's pretty huge in both places. We still see things going on. It's really -- up in the Utica, of course, Chesapeake is doing some things, but we see a lot of interest still in acquiring acreage up there. I can tell you that with the acreage we've got up there, it will take a huge multiple though for us to come out of it now. It's -- there's a lot of interest. There's a lot of people that aren't in there. If they aren't in there, in both the Permian and in the Utica, they've got to buy in to somebody's position before they can get in there. So I would say there's a real strong interest in it, and you're going to see -- I'm sure you'll see some transactions and things, but they're both strong places. Everybody wants to be there.

Our next question comes from Jeff Hayden from KLR Group.

A lot of my questions have been answered. Just a few quick ones. One, what was the choke size on the Wagner when it was its kind of 17 million day rate?

Jeff, normally, we would give out a choke size, but in this case as I'll explain, it was not something that was really meaningful. The pressures really tell the story. The reason we aren't giving the choke size out, it was such a strong well that we had to have 2 million BTU line heaters out there, so we could heat the gas enough to keep the well from freezing up so we can get that kind of test. So we actually had 2 choke sizes, even though we record one. So your normal comparison wouldn't mean anything. The important thing is that even at 17 million, the casing pressure was tied. There's factor in that well, and so, that was tied right into the bottom hole, and it only moved from 5,000 to 5,100 pounds while we were flowing that or -- it never got down more than -- from the 5,200 down to 5,000 pounds during the entire test. So it was really a stout, stout well. But as evidenced also by the fact that we have had a split stream between 2 line heaters to even get a good test on it.

Okay. And then, just kind of looking at your acreage and the results kind of from these 4 wells, I mean it's kind of sometimes it's tough to eyeball from the math, but given this, can you kind of split your acreage maybe kind of bracket it, what percentage your acreage might have liquid yields like we saw in the Groh versus how much -- what percentage your acreage maybe more like the Boy Scout or the Wagner, et cetera?

Well, I think we gave some numbers like that before. There were kind of based on Chesapeake's experiences -- Chesapeake. And I think that we have figured about -- based on their lines, we have 18% or so that was over in the gas line.

We think at this point, Jeff, 18% or 17% dry gas, 73% wet gas and 10% of the oil window. Again, our wells are also just coming in, so that may change a little bit going forward, but that's still where we kind of think we are.

Okay. So no major changes there right now. And then, jumping over the Permian real fast, you thought about kind of moving to horizontals, you got a lot of potential locations, you referenced on the vertical side. How should we think about how those vertical locations could be impacted based on a shift to more horizontal drilling?

Well, we've got 5 vertical wells right next to our first well, and we haven't seen any effect at all on those. And it kind of make sense if you'll think about it, there's only where we went horizontal in that particular zone, that particular wellbore and most of our perforations that we hit about 200 feet apart. So you might get close to 1 perforation set in the process of doing that, doing the horizontal well. So it kind of make sense that it wouldn't really affect it, and that's been our experience so far. We haven't seen any affect at all for the offset vertical wells how we're producing those new horizontal well.

Okay. And most of those verticals are on 40s right now, so would it impact all of your ability to get on 20s if you're drilling horizontals as well?

I don't think it would have any impact on it because now if we had 10 sets of perforations in a well and if we did, maybe we'll end up doing 10 horizontal wells right next to it. If we put a horizontal well bore right next to each of those 10 sets of perforations. Remember, there's 2,000 feet from the Strawn up to the top of the Sprayberry. There's more or less 2,000 feet, it's a good number in there. And then, you still got things like Clearfork above it, you got the Strawn down below it. There's a big, big interval in there. Like I said, we've got close to 1,000 feet of Sprayberry interval that nobody's even talked about a horizontal well then. But from our test and vertical wells, we've swabbed tested and found that those are -- they look terrible on the logs, it looks like -- it just looks like a rubble zone. There's nothing striking about it. And they still produced nice rates. We swabbed Sprayberry at 2.5 barrel an hour from the 20-foot set of perforations, so if you take -- I don't see why we won't be drilling horizontal wells in the Sprayberry. Obviously, if we got 10 zones and you drill 10 horizontal wells, well then it should have some effect on the ones offset here, but right now, I don't see a limitation to it.

Our next question comes from Biju Perincheril from Jefferies & Company. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: A couple of questions. One, can you give us some additional color on your midstream? What projects MarkWest has coming up, the timing of it and your committed volumes for those projects?

Well, the first thing that's coming up is they have their Cadiz plant, and it's going to open up about mid-September, and that will be a refrigeration plant. And then, they'll have -- toward the end of the year, they'll add also a cryogenic plant, and that's supposed to come out end of this year. So, of course, those are really meaningful things. We'll get a deeper cut with our liquids on every one of those things, so that's the basic plan. That's for the first ones. I mean, they've got expansions in the works, numbers that go up into the hundreds of millions per day of capacity that they are -- obviously, it's to their benefit to keep ahead of us and our ability to produce liquids because that's good for both of us. So they've been performing today like they mean it. And they were actually out there cutting pipelines, clearing pipeline right-of-ways before we ever did the -- before we ever inked the final parts of our agreement, so they've -- they were actually on board and performing before we even inked our deal. So we don't think we're going to have any trouble with them keeping ahead of us.

So we've got priority service on all capacity. Third quarter, they've got a refridge coming on; and first quarter of next year, they've got cryo. And then -- yes, so they're certainly staying ahead. They've got plans to expand the Harrison plant up to 200 million a day. So they're absolutely committed to growing their capacity up there and staying ahead of that. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: I think that the first plan that's coming on is something like 60 million a day, is that all committed to Gulfport or is that sort of like [indiscernible] stages?

Again, and maybe, you didn't catch this earlier, Biju, but we have priority service, so they're committed to taking care of us.

Yes, we're the anchor tenant on the pipeline. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay, got it. So if you look at your 2013, I mean, obviously you're off to a pretty nice start in terms of delineating the acreage, if you take capital out of the equation for a moment if you look at your midstream, your internal personal capabilities, how many rigs you think is realistic next year?

Biju, you probably wouldn't want to hear my numbers, I think we're worried about how we're going to afford it. But we can -- there's not a real limitation on how much we can do, but if we think ahead to just the basic development part of our package, if we're going to drill 50 wells next year, I think by the time we get out of this exploration phase, I think we'll be looking at a well per month per rig. So it takes 4 rigs to accomplish 50 wells. The next year, we're talking 70, so that takes about 6 rigs to accomplish that. And then in addition, by that time, obviously, we'll be putting some pad rigs in there. But we've already been hiring people for up there, new drilling capability, move people up there. Personally, the most wells I've ever had -- that I've ever drilled, I had about 17 rigs running at one time in one of my previous places at rigs exploration, these were wells down as deep as 22,000 feet. So we've been there and done that, and we won't have any trouble being the best and most efficient operator out there I think.

Realistically, Biju, we've talked about a 4 to 6 rig program next year to get those 50 wells drilled. We're really not yet prepared to talk about ramping up beyond that. But I will tell you that we've doubled the number of employees at Gulfport, that doesn't even include some contract deal personnel. So there are lots of people available, both here in Oklahoma and also up in Ohio. We get a lot of resumes, a lot of calls. So it seems like there are plenty of qualified engineers, geologists, operations people available to us. And so, we're certainly staying ahead of those needs up there to staff up to be prepared to execute on that program. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay, that's helpful. And as a follow-up to that, Mike, now that you have more of a unpredictable asset in the mix, at what point do you feel comfortable taking on some high yield debt?

It's a good question. We've talked earlier in the year about what point it made sense and early stage Utica development, it seemed premature to take on some long-term debt that's more expensive. But I would say, 2013 is the time to begin thinking about whether are not some long-term debt makes sense. We are still one of the most unlevered, if not the most unlevered, producer, I think, out there that I know of. So it make sense for us at some point, Biju. We're not quite ready, but we'll continue to look at that and look at the markets.

Yes, Biju, Mike is right. I mean, it's -- we're in the delineation phase. We're learning about the thing. When I talk about these pads for instance, so like the Boy Scout where we have 1 pad and we have 6 wells mapped, and we've only drilled 1 of them, those 6 wells are 1,000 feet apart. So if we were drilling pad wells, obviously, that's the kind of thing that's low risk, you've already tested it and we've got some so much to learn, though. There's -- I'll tell you something, this past, at the Technical Advisory Committee of the ODNR up in Ohio, just a couple days ago, one operator came in and asked for an exception to the 1,000-foot apart well and they asked to be able to drill a particular unit in Harrison County at 225 feet apart between wellbores. So obviously, we do something like that, and that 6 rigs is even more, so -- or 6 wells is even more on that pad. So those kind of things, low risk, we've already tested it and we feel really comfortable in going to something like the high yield debt on something like that. It's a little bit different than the exploration phase we're in now. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay, got it. And one more question on the Wagner well. It's been flowing, I guess, a couple of days now at 10 million a day, so that's constrained by your JT unit, I suppose?

JT units are the constraint on the well. Also, that just seems like a comfortable place to flow the well at this point. But, yes, the JT units will be the constraint. And then, by the time we're in mid-September and we're ready to go over to the MarkWest plant, we'll look at the pressures and so forth and we'll decide whether or not we ought to change that rate to something else. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. So that rates for few days are the -- can you comment at all on what you're seeing on the pressures and you're holding the choke size steady?

Well, so far -- yes, the well is real strong. The pressures are steady. They're virtually back up to the shut-in pressures. It's looking really stout. But we're real early, like to see a little more performance. It's kind of a nice opportunity. I mean, you don't want to just rush out and pull a well open. We feel it's real important not to pull the wells too hard, not to flex the formation down there. We'd like to keep things consistent. Anything we change, we change it slowly. We don't want to pull bottom hole pressures down for a lot of different reasons. It hurts your wells. So we're being real careful with them. We'll do that with all of them.

Ladies and gentlemen, that's all the time we have for today's Q&A session. I'll now turn the call back over to Paul Heerwagen for closing remarks.

Thank you, Stephanie. I believe that concludes this afternoon's call. A replay of the call will be available temporarily through the company's website, and can be accessed at gulfportenergy.com. Thank you for your time and interest in Gulfport Energy this afternoon. This concludes our call.

Thank you, ladies and gentlemen. That does conclude today's conference. You may now disconnect, and have a wonderful day.