Gulfport Energy Corporation (GPOR) Q3 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corporation Third Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, today's conference call is being recorded. I'd now like to turn the conference over to your host, Mr. Paul Heerwagen, Director of Investor Relations. Please go ahead, sir.

Thank you, Elly, and good afternoon. Welcome to Gulfport's Energy Corporation's Third Quarter 2012 Earnings Conference Call. I'm Paul Heerwagen, Director of Investor Relations, and with me here 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 reference to other non-GAAP measures. If this occurs, the appropriate reconciliations to the GAAP measures will be posted to the website. An updated Gulfport presentation was posted to our website yesterday afternoon in conjunction with our earnings announcement. Please review at your leisure. At this time, I'd like to turn the call over to Jim Palm.

Thanks, Paul, good afternoon to each of you. During the third quarter, Gulfport generated approximately $43.8 million of operating cash flow, $42.6 million of EBITDA and $16 million of adjusted net income on production totaling 655,000 barrels of oil equivalent. Operationally, we continue to make a strategic shift towards establishing the Utica Shale as Gold Gulfport's primary focus area. We've recently completed multiple transactions that provide a significant amount of capital and solidify Gulfport's liquidity position in the long term. Firstly, we contributed all of our oil and gas interest in the Permian Basin to the Diamondback Energy initial public offering. Second, Grizzly Oil Sand secured $125 million credit facility to fund additional infrastructure in SAGD projects. Third, we completed a $250 million high-yield offering of senior notes due in 2020. Together, all of these events provide additional capital that will be directed towards and accelerate our Utica Shale development program. These transactions are major milestones along the road to simplifying the Gulfport story and becoming a Utica-focused company. And now let me briefly update you on our current operations and our plans for 2013 in each of our asset areas. In the Utica Shale, Gulfport continues to develop and delineate our acreage position. Our technical staff did a great job of targeting a position within the core play based on certain high-graded geological and petrophysical characteristics, allowing us to lead a focused acquisition effort. Meanwhile, today, based on our interpretation of the rock properties, the pressure regime and the product phased windows, we believe that our position in the Utica could be as good as the best part of the Eagle Ford based upon the overall productivity and economics. During our initial development of the play, we have collected extensive geological data, including full open-hole log suites and a full core from the Utica, Point Pleasant interval. Recently, in our evaluation of the core, we engaged Ingrain, the Pioneer-focused ion beam SEM, a technique which allows them to produce 3-D digital reconstructions of rock. We have learned a number of things from the Ingrain analysis and you can find slides depicting some of the results of this analysis in our current presentation. Specifically, what our cores show are signs of expulsion fractures created at hydrocarbon generation. This indicates overpressure. And we also found we have principally organic matter porosity, which creates superior porosity and permeability in our rock. We find that particularly interesting that there are no shallow oil fields in our area of the play, a fact that we believe empirically demonstrates an effective seal preventing leak-off and trapping hydrocarbons in an overpressured regime within the Point Pleasant source rock. In addition to sudden pressures, we are experiencing confirmed and overpressured reservoir. Ingrain and I will both be going into further detail on the results of our analysis at the DUG Conference in Pittsburgh next week. In general, the data confirms our original interpretation of the play, and with results from each well we test, it's becoming increasingly apparent that the Utica is a prolific shale play and we are very pleased to have captured a significant position within its core. During the third quarter, we spud a total of 5 gross wells in the Utica Shale, with 2 gross wells completed and in their resting period at the end of the third quarter, 1 gross well waiting on completion and 2 gross wells drilling. We are currently running 2 rigs drilling ahead on our 11th and 12th wells of 2012, and today, we are prepared to release results from our 6th well in the play. Our BK Stephens 1-16H was drilled to a total vertical depth of 8,225 feet, with a 5,276-foot horizontal lateral, and was completed with a 19-stage hybrid hydraulic frac treatment consisting of approximately 550,000 pounds of sand per stage. We're still learning about resting our wells, but I'd like to note that the results I'm about to report came from a rest period of approximately 30 days. The well tested at a peak rate of 1,224 barrels per day of condensate and 6.9 million cubic feet per day of gas on a 32/64 inch choke. Based upon composition analysis, the gas being produced is 1,207 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 rate of 11% and a total rate of 3,007 barrels of oil equivalent per day. In ethane rejection mode, this composition would produce 42 barrels of NGLs per million cubic feet of gas resulting in a gas shrink of 1% and a total rate of 2,652 barrels of oil equivalent per day. As we do not expect to begin flowing the BK Stephens into a sales pipeline until the end of January next year, we've resumed resting the well, and in approximately 30 days, we will test it again. While we are currently still sticking with our 60-day resting period, we are very encouraged to see this level of production from the well following the shorter resting period. Of course, our objective is to determine the shortest resting period needed to make the most economical well. Another note, we recently finished drilling our Stutzman 1-14H well, which was drilled to a true vertical depth of 9,020 feet, with an 8,634-foot horizontal lateral and a total measured depth of 17,282 feet. The Stutzman 1-14 is now the longest lateral and total measured depth with any well Gulfport has drilled. I'm very proud of our technical team's execution on this new play as they are positioning Gulfport as an industry leader in drilling and completion practices. We are big proponents of longer laterals and shorter frac intervals, which we believe will benefit us in the long run by providing higher overall EURs. And our technical team has demonstrated its strength by crafting and executing this strategy. Looking now at the midstream side of the play, while we have reported a number of very successful wells, we have not yet been able to bring any of our wells into full production. In spite of strong efforts, MarkWest has experienced construction delays due to a number of factors, many of which are outside of its control. Permitting and right-of-way acquisition in Ohio in particular are very challenging. We hope to have the first sales from the Wagner and Boy Scout into the Cadiz plant before today, but due to Hurricane Sandy, we now anticipate sales to begin later this month. Due to delays I just mentioned, MarkWest currently anticipates having only those 2 wells flowing into the Cadiz plant at the end of the year. We're all frustrated by these delays. However, I have personally been near daily contact with Frank Semple, MarkWest's CEO, and I'm confident the project is getting the highest level of attention on their end. The good news is that MarkWest is currently nearing completion of several critical gathering trunk lines which have an ultimate capacity to gather in excess of 500 million cubic feet per day. In addition, they are beginning construction of 2 additional trunk lines that will increase gathering capacity to as much as 1 Bcf per day. This gathering infrastructure will reach across the vast majority of our wet gas acreage located in Harrison, Belmont and Guernsey Counties by the end of the first quarter in 2013. From a processing perspective, MarkWest's 60 million cubic foot per day refrigeration plant should be fully operational later this month, which will allow Gulfport to begin capturing the critical NGL uplift. MarkWest's first cryogenic plant, which will have capacity of 125 million cubic feet per day, is scheduled to come online early next year and will capture even greater value for NGLs. Looking even further ahead, MarkWest is already moving forward with the second Harrison County plant, which is a 200 million cubic foot per day facility and should be operational as early as the fourth quarter of 2013. MarkWest's fractionator in Harrison County will come online in the early 2014 and will allow us to fully maximize the value of our NGLs. The de-ethanizer facilities are also scheduled to be completed in early 2014, and will allow us to access the ATEX ethane pipeline. MarkWest Houston, Pennsylvania and Harrison County, Ohio facilities will be the 2 largest fractionation complexes in the Northeast, and will provide tremendous operating flexibility and reliability, as well as market access for our NGLs. By early 2014, we will have the full benefit of having what we believe will be the most efficient and integrated gathering processes -- processing and NGL fractionation and marketing system in the Northeastern U.S. We recently signed a letter of intent with MarkWest to gather our condensate. This is another key element of our midstream solution, and MarkWest will construct an integrated condensate gathering and stabilization system that will consist of gathering facilities, field injection stations, stabilization equipment, storage, pipelines and truck and rail loading facilities. This system will be a companion to the developing rich gas gathering and processing facilities, and be advantaged by the associated multiline rights of way. The integrated solution will enable Gulfport to increase the value of its condensate production by virtually eliminating losses typically related to weathering and/or field transportation. We expect to further enhance the value of our condensate by stabilizing it at the Harrison County plant and marketing the stabilized product to regional refineries or to the Canadian Oil Sands producers for use as diluent. While we were still in the initial stage of the detailed engineering, we are planning to begin gathering and stabilizing condensate through this new system as early as September of next year. Looking ahead towards our development plans in the Utica, during 2013, we plan to continue running 2 rigs through the winter and anticipate adding a third rig in early March. We will likely add 1 rig every 2 or 3 months following, ultimately peaking at about 5 to 6 rigs running at the Utica to exit the year. Currently, we budgeted to spend approximately -- or to drill approximately 50 gross, 25 net wells for a total cost of approximately $215 million to $225 million. With all the excitement about the Utica, we should not overlook the superb asset we have in our core area of production in South Louisiana. This asset has proven to be a strategic advantage to Gulfport over the years, providing a strong source of production and cash flow in a market that enjoys very attractive Brent price realizations. Through the end of the third quarter, we have produced approximately 1.6 million barrels of oil equivalent from Southern Louisiana and realized a weighted average price of around $104.29. This equates to $167 million in revenues and $127 million worth of net cash flow after deducting our cash cost of approximately $25 per barrel. What makes this significant is the fact that we only had to spend around $85 million of CapEx over the same period to generate those kind of numbers. It's very rare to find assets capable of generating this much free cash on such little investment. Moreover, between our significant inventory behind pipe recompletion opportunities and our ongoing drilling programs, we expect to see continued strength from this asset in 2013 and for years to come. At Hackberry, during the third quarter, we drilled a total of 4 wells, completing 2 wells that's productive, with 2 wells waiting on completion at the end of the quarter. In addition, we performed 9 recompletions. We are currently running 2 rigs at Hackberry, drilling ahead on our 20th and 21st wells of 2012. Looking ahead to 2013, initially, we plan to drill 10 to 12 wells and perform approximately 5 recompletions at the field for $24 million to $26 million. Meanwhile at West Cote Blanche Bay, during the third quarter, we drilled a total of 9 wells, completing 6 as producers, with 2 waiting on completion and 1 well drilling at the end of the quarter. In addition, we've performed 15 recompletions. At present, a barge rig is active at West Cote and is drilling ahead on the 29th well of our 2012 program. For 2013, we have budgeted to drill 22 to 24 wells and perform approximately 60 recompletions at West Cote for a total of $42 million to $45 million. Shifting now towards Canada. Grizzly continues to be on schedule in building its first SAGD facility at Algar Lake. In the updated presentation that was posted yesterday afternoon to our website, we've included some new pictures to show progress being made at the site. In-field plant assembly is nearing completion with first steam expected by the end of the first quarter next year. Several years ago, Gulfport made the strategic decision to invest in the Canadian Oil Sands, an emerging play at the time, but was only comparable in size to Saudi Arabia. Through this investment and the investment of our partner, Grizzly has assembled a meaningful position in the play, comprising over 800,000 acres and discovering more than 3 billion barrels of recoverable resource. As the industry understanding of our strategy has unfolded, Grizzly's been able to attract a highly experienced technical staff that has pioneered a unique engineering design as a traditional SAGD model. Grizzly's innovative ARMs development model stands to change the future of SAGD development. This model affords substantial scalability, while also generating significant capital savings versus traditional fixed-plant construction by better managing cost, quality, labor and construction scheduling issues with more effectively -- much more effectively than traditional on-site fabrication. While first production from Algar Lake is now a near-term event, I would like to remind you that this is just the beginning. Grizzly has defined a plan to grow production to over 90,000 barrels per day by 2020 from 3 core multi-phased projects with average productive lives of around 30 years. Over the next several months, we will be entering a new stage in the life cycle of this investment, one in which the true productive potential and scalability of this asset will be revealed. Meanwhile, from an exploration standpoint, Grizzly plans to file for a commercial project at Thickwood Hills by the end of this year. Grizzly has finalized its 2012, '13 winter drilling program and will conduct an exploration program consisting of approximately 20 to 25 core holes primarily focused in the May River area. May River is located in one of the most attractive areas of the oil sands and surrounded by industry-leading SAGD projects. Grizzly intends to drill May River to sufficient density to support the filing of a regulatory -- of a project regulatory application during 2013. Grizzly recently secured $125 million revolving credit facility. This facility, along with cash flow from Algar Lake, will relief Gulfport of any near-term needs for funding beyond the remaining $8.5 million, which we committed to finishing out the Algar Phase I facility. Moving along to West Texas. As I mentioned earlier, Gulfport contributed all of our oil and gas interests in the Permian basis to the Diamondback Energy initial public offering. The IPO will accelerate development in this historically significant basin for Diamondback. At the end of the third quarter, Gulfport had a non-operated working interest in 2 vertical wells drilling on the acreage. Today, Gulfport has a meaningful equity interest in a public company that equates to a market value of $126 million. Diamondback will run an aggressive horizontal drilling program and following the public offering is adequately financed to do so. We continue to be very encouraged by surrounding operators' results and look forward to being a part of Diamondback's future success as they unlock the value of the emerging horizontal potential in the play. To wrap things up, I'd like to mention that I've been in the oil industry for a number of years, and I've rarely encountered anything like what we are seeing today in the Utica. With each new well that we test, I continue to be impressed by the sheer magnitude of the production and the consistency of the resource across our acreage. In the Utica, Gulfport has established itself as a scientific leader, having conducted extensive scientific, geological and engineering evaluations. We continue to focus on execution and strive towards being the low cost producer in the play. With our recent senior notes issuance, the contribution of our Permian assets to Diamondback and Grizzly now standing on its own from a funding perspective, we've freed up significant capital to be redirected toward the development of this once-in-a-lifetime play. The Utica Shale is absolutely a company changer for Gulfport, and we intend to devote the necessary capital to allow to develop to its full potential. 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 third quarter of 2012, Gulfport generated approximately $42.6 million of EBITDA, $43.8 million of operating cash flow and $0.5 million of net income or $0.01 per share based on average diluted shares outstanding of 56.3 million. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $16 million or $0.28 per diluted share. During the third quarter, production totaled 655,437 barrels of oil equivalent or 7,124 BOEs per day, which is up 11% on a unit basis year-over-year compared to third quarter of 2011. Allocated by field, third quarter production breakout would be 2,749 BOEs per day from West Cote; 2,837 BOEs per day from Hackberry; and 1,205 BOEs per day from Permian; 193 BOEs per day from Utica; 140 BOEs per day from Niobrara overrides and our other miscellaneous areas. Our production mix for the third quarter was 92% oil and natural gas liquids and 8% natural gas. Subsequent to the third quarter, October production averaged approximately 6,143 BOEs per day. Moving along to the income statement, revenues for oil, natural gas and natural gas liquids in the third quarter totaled $60.5 million. Average realized prices for the quarter were $101.17 per barrel of oil, $3.09 per MCF natural gas and $36.86 per barrel of natural gas liquids. Our blended price for the third quarter was $92.24 per barrel of oil equivalent. The operating expenses during the third quarter was $6.6 million or $10.13 per BOE, up 18% sequentially on a unit basis from the second quarter of 2012. General and administrative expense for the third quarter was $3.1 million or $4.73 per BOE, down 4% sequentially on a unit basis from the second quarter of 2012. Depreciation, depletion and amortization expenses during the third quarter totaled $25.4 million or $38.72 per BOE, up 9% sequentially on a unit basis from the second quarter of 2012. To finish up our income statement discussion, I would like to provide a little bit of guidance on our income tax expense going forward. In addition to the $15.5 million of deferred tax expense we reported in the third quarter, we currently project tax expense of approximately 36% to 40% in the fourth quarter of 2012. With utilization of our net operating losses, we are only expecting our total 2012 cash tax to be $3 million or $4 million due to our ability to expense intangible drilling costs for tax purposes. Furthermore, based on our current projections, while we expect to continue to accrue tax expense in 2013 and 2014, up 36% to 40%, respectively, we should be able to minimize CapEx. In terms of capital expenditures, during the third quarter, we spent a total of $79.9 million on 2012 activities, which excludes the Gulfport portion of Grizzly's activity and Utica leasing. Moving on to the balance sheet, at the end of the third quarter, we had $12.3 million in cash and have drawn $141 million on our revolving credit facility. Subsequent to the third quarter, Gulfport completed a high-yield offering to be allocated towards repaying outstanding debt that's under the credit facility and fund the portion of future development of the Utica Shale. Gulfport issued 250 million of senior notes at a rate of 7.75%. In the past, Gulfport has been hesitant to raise funds from the debt markets to support development programs in the unproven gas areas. We're looking for sources of funding for the Utica Shale development program. The debt market's proved appealing for a company with low debt and that, as of now, we believe has confirmed resource in place. Prior to completion of our high-yield offering, our full redetermination resulted in no change to our $155 million borrowing base. However, all we needed to do is high-yield and the contribution of our Permian asset to Diamondback, our borrowing base has decreased to $45 million. Gulfport is currently undrawn on our revolving credit facility. At present, we have a fixed-price cost 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 to June of 4,000 barrels of oil per day at a weighted average price of $103.33, and fixed-price swaps for July to December of 3,000 barrels of oil per day at a weighted average price of $104. Gulfport's 2012 and 2013 fixed-price swaps has Brent Crude as the underlying index. As a final note, I would like to highlight that this current level of hedging effectively secures $130 million of 2013 revenues and CapEx, which goes a long way towards securing capital commitment for our [indiscernible] 2013 capital program. Looking ahead to 2013, we estimate full-year units LOE to be in the range of $5 to $6 per BOE, full year unit G&A is expected to be in the range of $1.50 to $2.50 per BOE, and we estimate our DD&A rate to be in the range of $33 to $35 per BOE. Although through the fourth quarter of 2012 and the first 3 quarters of 2013, our DD&A rate will continue to be higher in the range of $40 per barrel. I thank you, again, for joining us for our call today, and we look forward to answering your questions.

Operator, please open up the line for questions [indiscernible].

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

Maybe, Jim, first question. Just wondering, obviously, for you or Mike, it looked like anticipated Utica well cost looked like to be coming down. Just wondering, Jim, your comments on all the vertical integration you all have going on, how this is factored in and if that's going to contribute to well cost coming down?

Well, vertical integration is sure a key to it, Neal, which we've done in South Louisiana and we plan to do it up here, too. So we are in the process of that. And one of the things, too, we're moving into a phase where we're going to drill more pad wells as we go. We'll do some science this winter. That's why we're just keeping 2 rigs running. We'll do science on -- probably go back and drill the Boy Scout for sure. Probably, the Wagner well, too, where we have gas lines in place and hook-ups ready. And we'll probably winter over roughly December, January, February there and drill 3 wells, eliminate the rig moose and test different frac sizes, test things like how far apart we should space the wells. So as we do that, that keeps the cost per well down. And we're still doing some things. There's a lot -- there's too much to go into, but we still got a lot of things to do to try to reduce the cost.

Okay. And then sticking with the cost, maybe for Mike, it looks like, obviously, Mike, on your new guidance, specifically on LOE and G&As coming down quite a bit on a margin basis, is that just because of the higher volumes or is there more that we should be reading into those 2 costs coming down for guidance next year?

Well, that certainly is the big contributor, Neal. I will say that we expect the Utica wells to be fairly efficient to operate, so not a great deal of LOE per BOE there. But obviously, the high total volumes are driving down those unit costs.

Okay. And then just wondering as far as -- Jim, you walked through quite a bit as far as the infrastructure that should be coming on. Based on this, Jim, do you all see -- I guess I'm trying to get an idea of sort of tie-ins. Will there be some delays early next year on the tie-ins? Or I guess, the other way to look at it is on these plants coming on, is that kind of the milestones we should be looking at and do you have sufficient -- will you have sufficient capacity for all of these wells that you are going to drill and potentially complete next year?

Yes, we will have sufficient capacity, and MarkWest is dedicating not just the plants that are in the works, but they've got more equipment ordered. There will be plenty of capacity to process the gas. And then by the end of the first quarter, we'll have the 20-inch trunk lines laid in, in this area where the wells you've seen today, we've got 12 so far. And basically, it covers all that area, which is in the core of our play. And so those will all -- that will all be in place by the end of the first quarter. So even the wells that we're drilling today, of course, by the time we finish drilling these and we frac them in December, the rest of them a couple of months, they're scheduled to be hooked up in March. So anything new that we do through next year, we expect to have a pipeline in place. Because we know where the pipelines are, we've got lots of locations to choose from. First, is we have one up in Harrison County and they won't be finished there until, say, the fourth quarter of next year. So we won't drill those till the first quarter of next year. When their facility's in place up there, then we'll go drill those wells. So essentially, we should be able to have sales as quick as we're ready to put the wells on next year.

Okay. And last one, if I could, before I turn it over. Just, Jim, wondering is there still acreage? Would you look at bolt-on acquisitions in the Utica or you're satisfied with your acreage position?

Well, we're still picking up acreage. If you look closely at the reports, you'll see we went from 125,000 to 128,000 on our tally of what our acreage is now, gross acres, and that's as we are picking up this acreage. Not lots of big blocks, but still potentially, we can find some. But mostly, we're picking up bolt-on stuff that fills out the drilling units that we're putting together.

Our next question comes from Ron Mills of Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: As you guys look at your 2013 budget for the Utica. The, call it $220 million for your net wells. Can you walk through what you think a typical well is going to look like? 8,000-foot laterals or 6,000-foot laterals and how you arrived at that average well cost. Just your typical well?

Well we still think that we'll be looking -- we haven't drilled any at 5,000 feet. But again, today, our number is on a 5,000-foot lateral, $1,500 a foot or $7.5 million for the well. When you go to an 8,000-foot lateral, figure $1,200 a foot or $9.6 million. We think those costs will be coming down as we go through next year. But when you take that and you blend someplace between the 8s and the 5,000-foot laterals, that's kind of how we come up with the number that we've got right now.

I think, to be conservative, we used kind of a 7,500-foot lateral average. That may be a little high, but that's how we came up with our costs, Ron. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then as you look at your production guidance, I'm assuming you're still planning on a 60-day resting period, as opposed to testing the 30-day, and especially as you maintain that 2 rigs. What's the time frame of getting on the remaining wells that have already been drilled and tested?

Well those certainly are going to come on in the first quarter as quite a few of them actually came on towards the end of January. So if your question is what's kind of production look like from quarter-to-quarter, you would expect to see some higher production adds in the first quarter, just based on those 2012 wells coming on, along with the first quarter drilling program. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then finally, on South Louisiana, the focus on Hackberry. I guess, I'm trying to -- [indiscernible] how I want to ask this. At Hackberry, are you still stepping out along that structure? Are you still doing just more lower risk development? How's the process working at Hackberry?

Yes, we are still stepping out in our core area on the east end of the Hackberry dome, and then we have the new exploration area that we're drilling wells on. The first 3 of them made wells and so we're going to do that. That moves west along the south side of the dome there. So we've got a couple of areas that we're still drilling wells in there.

Our next question comes from Tim Rezvan from Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: I want to get back to the Utica, on some of the midstream questions that were asked earlier. First, do you have any idea how many wells, gross wells, you'll be drilling this year?

Well this year, we're drilling a number 11 and 12, and we'll take those rigs and we'll drill 13 and 14. So we should get 14. Last year we said we were going to drill 20, but we were talking 5,000-foot laterals, a year ago when we said, and we are actually going to drill more feet than we anticipated, but with fewer wells. But, anyway, that's the plan, is to have those 2 go in. And actually those last 2 will be on the same pads we're drilling now, so they'll go online. Again, by the end of that first quarter next year, all 14 wells will be producing according to the schedule MarkWest has given us. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay, so is it safe to assume that this production ramp is really going to -- we're not going to see much in the first quarter?

Well by the end of the first quarter, there'll be a 14-well exit rate, if they get their lines in the schedule, which we believe they're going to do. So it'll be a nice exit rate from that. Really, I think of these 2 wells, the Wagner and the Boy Scout, as being producing wells with through the Cadiz plant at the end of 2012, and then think of the other 12 as coming on. Just space them equally across the first quarter and you're probably pretty close on your model. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay, so you think these wells will start coming on, getting put to sales, early in 2013?

Yes, for sure.

Yes. There's going to be varying dates, but really if you look at the ones that are resting versus the ones that are frac-ing now, most of those will come on in the first quarter though. It'll be spread a little bit, but most of them will come on the first quarter.

We've been up there, we have taken a look at what MarkWest is doing. And I can tell you the plant facilities and things come along just fine. And they do have these bottlenecks, for instance, where they've had the Corps of Engineers and the wildlife people, and so they have some things like crossings that are eliminating the pipelines from being functional. But in the meantime, they're still laying pipeline through their right of way, and so it gets down to -- the pipeline's virtually laid, but you've got the one piece that you need to do before it's functional. And so they're quite far along on their pipeline laying schedule. The right-of-way, I'd say essentially all the right-of-way is done, everything is finished up except for a few critical pads that keep them from being fully functional. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. And then just lastly, is there any color you can give on kind of how EURs may be shaping up for these wells?

Well it's still early to say what the EURs are going to be. We do feel like that they have pleasantly surprised us. They're exceeding anything I envisioned, as far as the IPs go. But for the time being, we are still sticking with what we had in 2011, in March, almost 2 years ago, when we started into the play, when we said from 460 to 910 MBOE. But we're just going have to see. When we get them online, we'll see what it is. I can tell you that up north, Chesapeake on the Buell well, gave the Buell 575,000 barrels of liquids and 13 BCF. And so that was from a great well, which I said was the best well I've ever drilled. And by comparison, our Wagner had a 20% longer lateral and we also had 28 frac stages versus their 18, and our IP was about 50% higher than theirs. So how that relates to the EUR figures is hard to say. But that well has been producing now since -- well it's about 15 months. It started producing in July of last year, so there's a nice type curve associated with it, but we want to see own type curves before we start talking our own EURs.

Everything that we're seeing right now just suggest to us that our original estimates are -- we're pretty conservative, but like Jim said, it's just a little too early for us to start moving those around.

Our next question comes from Leo Mariani of RBC.

Just a question on the Wagner well. Could you tell us what the pressure on that well is now versus kind of what it was when you hooked it up in early August?

Well ever since we've put it on, Leo, it's been flowing down in the 4,000 range. We're just making about 4 million a day, out of the well. It goes into the dry gas line, so we've not recovered many NGLs and we just barely cracked it open. We have told MarkWest, I've told them, that we anticipate someplace between 10 million and 15 million a day when we get it into their system. And we don't want to do that now because we don't want to send all those NGLs down the line. I might point out, again, this well is so stout when we first tested it that we started off with 5,200 pounds on the tubing -- or on the casing rather, and 5,100 pounds on the tubing. And so basically the well had been shut in for a few days and it was pretty much all gas on both sides, both in the tubing and the casing. And when we started flowing it, when we got to that 17 million a day rate, the casing pressure had only dropped from 5,000 -- or from 5,200 to 5,000 pounds. Just a tiny little drawdown, 200 pounds, and still was making 17 million a day. So it is a very, very stout well. But it's just loafing along with what we got to do now. And I might say one reason that the pressure is down in the 4,000s is, when you've only got gas in there, if that's all we were making is gas, you'd see that pressure up around 5,000, still, on the flowing pressure. But now we're lifting, still, some water. We're lifting some condensate, and so because you're lifting that, that's the tube in, you won't stay at that 5,000 pounds. If it was just plain old dry gas, it'd still be right there 5,000 pounds.

Okay, that sounds very encouraging. A question on your Stutzman well, it was the longest well that I guess you guys have drilled. What was the drilling time on that?

I think we did that in about it'd be about 30 days.

Okay, that sounds like that, that's come down a fair bit for you all over the course of the last several wells then here?

Yes, it has.

Right. Part of the reason we're projecting our costs to come down a bit, we're becoming more efficient.

Okay. In terms of the acreage that you picked up, I think you all picked up like some around 3,000 or 4,000 acres in the play. You described it as largely just bolt-on, filling stuff to make some drilling units. What are you all paying for that now?

You basically have to pay $6,000, but sometimes you get it a few dollars less. I don't think we're paying more than that. And there's other acreage available that's not the in the sweet spot, as we define it, but you can get cheaper. But to get the really quality stuff, you're still having to pay $6,000. Even if it's just a little bolt on. All the neighbors got that and they have pretty a good network up there.

Got you. Okay, you all talked about October production number. It was like 6,100 and 43 BOE per day I think. Were there still some effects from shut-ins, due to the hurricane, on that number?

No. No, we were for the operational for the most part. So really no effects left there. There are always some month-to-month fluctuations, but no effects in that number.

Got you. Okay. And in terms of the oil sands. Obviously you guys are progressing towards a number of hurdles there. What are your thoughts on sort of a potential kind of maybe partial monetization for you all or some incremental capital raise? I know you guys talked about partners, JVs, IPO, a whole host of things, in the past. Is that still moving ahead? And just kind of any updated thoughts there.

Well it is moving ahead, but remember, when they announced it was February and they said within 18 months, so there's still not quite a year to go. My thoughts are that, when we get the first production on at the end of the first quarter that, that's going to be a game changer. People are still waiting to see how's the ARMS plant work. And I'm firmly convinced it's going to be wonderful because SAGD is just generating steam and putting it down the hole, and then gathering what you get out of your formation. But the ARMS plant, it uses the same boilers everybody else does, but it's how efficiently it's manufactured that makes a difference. Doing it in the shop, not doing it out in the field where you got $80 an hour per well. They're doing it in the shop where he's got $40 an hour, and he's got everything handy. So, really, it's the cost side of the thing, it's not the functioning of the plant that's the big issue. And I think they got a great design there that basically are -- the key is to make barrel of steam cheap, and that's what ARMS does. And that means you're going to make more value from the rocks you've got.

One thing I want to say, Leo, is while we're certainly excited by the potential capital event, we also don't want to minimize what Grizzly has done with the debt facility and also first production from Algar Lake. We are now at a the point that, that's become a self-funding opportunity for us, and so now we can use that money that we're spending in Canada back in the Utica. So that's also been, we think, very accretive for the shareholders this year.

That's good color. I guess last one for me. You guys worked on putting an oil facility there, kind of in the Ohio River, sort of a terminal. Any update on what's going on there and kind of when you plan to potentially use that to market some of your crude? I know you talked about some of the initiatives at MarkWest there?

Leo, it's still going to be next year, some time before we got it going. We really are doing that as kind of a long-range plan to make sure that we have long-range, the capability to get our products to other places, down to other refineries and so forth, but we don't see that the capability's going to be stressed anytime in the short future. So it's just a next year event, sometime.

Our next question comes from Jason Wangler, Wunderlich Securities.

On the guidance for 2013, and it's helpful, do you have an idea? Obviously, the Utica being a big portion of that. Is there just something you're thinking as for as the oil and liquids and gas split or should we look at it kind of what the wells look like so far or maybe any color you can give around there given you don't have a lot of production. I know it's kind of a tough question but just kind of thinking your thoughts there.

No, no, it's a fair question. It's a good question. In looking at the first 6 wells that we have results on, which is the best data that we have at this point, we think the production mix, at this point, although that obviously will change or could change going forward, is about 1/3, 1/3 and 1/3, Jason. That's where it feels like it is right now for next year, and that's the way we're thinking about it. Again, as we get these wells hooked up it could change a little bit.

That's helpful. And then, Mike, I'm sorry if I missed it. When you were kind of giving the updates on the financials, but could you give kind of, give or take, a cash balance that you had now that you've the Permian done and the bond deal done?

Yes, so after all of those activities today, we have $115 million, $120 million in cash, and we have $45 million available under our revolving line of credit. So well funded for our Utica activities next year.

Our next question comes from David Kistler of Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly, kind of following up on that guidance question. When I look at your October production, should I just be thinking about that as kind of heading flat? And the reason I'm going talking about that first is, looking at your capital spending in West Hackberry and East Cote block kind of flat year-over-year. And then when I look at your forward guidance, say all the incremental component is coming from the Utica primarily and apply that 1/3, 1/3, 1/3 mix to come up with sort of production outlook for that full year guidance. Is that a fair way to do it?

Well that's a good comment. So historically, over the last few years, we have had some production growth out of Southern Louisiana. So we are going to spend a similar amount of CapEx there next year. So you will get some slight uptick in production out of that area as Hackberry continues to deliver. West Cote tends to be flat year-over-year. So I think you can think in the range of 6% to 8% growth next year, out of Hackberry, but the rest of it coming from Utica and then you can apply 1/3, 1/3 and 1/3. David W. Kistler - Simmons & Company International, Research Division: Great, that's helpful. And then as we kind of think about regulatory issues and whatnot, can you comment on where you are with respect to permits filed for next year? I think previously you had about 50 permits filed. Do you have enough to cover the wells that you're going to finish drilling and the wells you're planning on drilling for next year?

Well I don't know if we got 50 filed now, but it's pretty good turnaround there on the permitting. And of course, we have a long lead time on where we're going to permit because, as we move into these new areas, we're bringing in other partners and other operators. So we can't drill everything on our own leasehold, so I don't really see the permitting as being a problem. It's just like South Louisiana, you know how long it takes and you just plan it ahead of time and get it done. But the regulators up there have been very cooperative in the sense that they want to operate things in an environmentally safe manner and so forth, just like everybody else, just like the operators do. But they want to see the most oil and gas come out of the ground as possible. They know it's good for royal owners, it's good for the state, good for our industry. And so they work real closely with us up there. They're giving a lot of flexibility here in the first couple of years. Their old tradition was 1,000 feet between vertical wells and they've already approved, for 1 horizontal drilling operator, the technical advisory committee has approved 225 feet between horizontal laterals. So they're doing what they can to maximize the value of the play for everybody's good and we're really pleased to be working up here with them.

The permits themselves are fairly easy. I mean, we're really talking about a couple of weeks. Really what's more important is identifying and putting the locations together. So, as I think we've mentioned before, we've doubled our staff. A lot of that has to do with land. So we're working 40, 50 locations currently, have another 140, 150 locations identified. So filing the permits themselves is just a mechanical function, and very quick and easy to do. David W. Kistler - Simmons & Company International, Research Division: Okay, that's helpful. And on the production guidance, Jim, I apologize. You mentioned earlier kind of leaning on the Buell well as a type curve for us to kind of think about modeling out the Utica. Is that the same type curve you guys used for your forward production guidance for '13?

Well, no. Actually we use an average kind of our first 6 wells for the 2013 guidance.

Yes, but as far as the Buell well goes, we only have a couple points on the Buell well. They are some good points. We know they averaged 8 million a day during the first 6 months. And so we have just a few points on the type curve. But we're basically, from the get-go, modeled this after the Eagle Ford. You can see in our presentation we have Eagle Ford logs and we've got Utica Point Pleasant logs. The reservoirs are very similar. So until we have some more evidence from our wells, we basically use the Eagle Ford type curve to do our economics. David W. Kistler - Simmons & Company International, Research Division: Okay, that's helpful. One last one and I'll hop off. I apologize, but with your gas production ticking up, you talked a little bit about the oil hedging philosophy. Can you talk a little bit about gas hedging and how you think about that moving forward?

Certainly, we're opportunistic and historically we've hedged, typically, 40% to 70% of our production at any given year. I think this year we're about 44% hedged. We looked at that everyday. Right now we just hedged Brent for our Southern Louisiana production. We are talking to different folks right now about what to do on natural gas hedging and also NGL hedging. I'm not sure right now is the time but we'll continue to look at that. And I think you would see us putting in probably some different types of hedges in place going forward. But we want to do it at the right time and just haven't pulled the trigger on anything yet.

Our next question comes from William Butler of Stephens.

On the Utica EURs, what would it take for you guys to sort of reevaluate that in terms of time that the walls have been on, on production or would it be year-end reserves this year? I mean, what do you think it takes for you guys to revisit that?

Well we're probably be revisiting those things during next year. We've got our bank credit line and Mike might want to speak to that, but we'll have redeterminations throughout the year. We'll start coming up with -- of course, the year end will be a year from -- at the end of 2013, we'll have something official, but we'll certainly be taking a look at them. And as these wells come on in early 2013, I can tell you we'll have a lot better idea after 3 months than we have right now, once we see those early parts of the curve. So it just depends on how the wells perform, but I think they're going to be strong wells and I think we'll be leaning towards some real optimistic numbers. But we'll just have to see the wells online and when we see a few months we'll have a lot better idea what they might be.

So we'll do our spring redetermination, William, with our bank group in March. And by that time, we will have some of our wells producing long enough that I think we'll have a better feel for what we think those types of EURs are going to be.

Okay, that's helpful. And then any updated thoughts on the Niobrara. It's not something that seems to be focus. Can you all add some color on that?

Well we're testing our idea about shooting the 3D seismic and that's helping us find the fracture systems, and then making a natural producer. But we finished our Ridge View well and we're very disappointed in what it had to show us. And we do have a little bit of testing left to do on the well and so maybe we'll get a pleasant surprise on the last part of the well as we test it. But it doesn't look like we've done it to get on that theory. Now other people, you can see Shell and Quicksilver up there, they have a different approach and they're drilling horizontal wells, they're frac-ing them and so forth. So it doesn't mean that the acreage is without value or utility. But for the time being, we're sitting back and looking at them making -- going to let them prove up that concept or decide what to do with the acreage, so that's why we haven't budgeted any dollars in 2013 for drilling in the Niobrara. I think we've got a place where the questions are answered and we know we make good wells in the Utica, so for right now, we're just going to take that money and put it in the Utica program.

Our next question comes from Biju Perincheril of Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: A couple of questions. So when you're looking at your I think 50 wells or so for next year in the Utica, how many of that is for holding acreage versus development wells?

Well mostly, we've got the 50 wells we're talking about drilling and the majority of them will be for holding acreage. But, particularly, early in the year, we are doing some science. And as I said, we're still trying to figure out the -- oh, like of the wells we drilled on the Boy Scout. Let's say we might take space one of them 400 feet away from the 1 in the middle or maybe one 600 feet away on the other side and see if we see any signs of interference. We've already got the original Boy Scout and next month we'll start developing that type curve for that length of lateral and then we drilled the second Boy Scout, which we're getting ready to frac. So we'll have 2 type curve wells and then with the 3 that we drill on that pad this winter, we can try some things like we can compare them with the spacing to the first ones and figure out if we're seeing interference and we are definitely going to keep going closer and closer together until we see signs of interference because we want to minimize the spacing between well so we can maximize the recovery over the area. At the Wagner, we'll drill 3 was there that we'll be able to compare to the original Wagner. They'll be far enough away they won't interfere with that. And we might try our normal frac job, we might try another one where we'd put in 1/3 more sand and another one where we'll put in 1/3 less sand. So early on, we're doing some non-exploratory things but the most part, the 50 wells will be holding acreage. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. I was trying to figure out if the development next year or drilling next year will be concentrated in any particular area up your position there. And it doesn't sound like that's going to be the case, that's going to be pretty spread out. So by the end of next year, would it fair to say that you would have pretty much your entire position there delineated?

Well we've got a lot to do, but we are going to go north, south, east and west. For instance we have some acreage up in the north pretty up in Harrison County. We'll put that in the fourth quarter next year because we have MarkWest. That's a new system for them and so we know when it'll be in place so we won't drill far north until fourth quarter. We'll work through the west from the drilled well, we'll drill to the gas side, although we won't drill many gas wells. But we'll go over gassy [ph] to the east and test some of the acreage over there. And we still got some stuff to do down south we've got wells to drill down south Belmont County, so I wouldn't say that we'll have tested to the far extremities of everything, but we feel like we pretty well de-risked the heart of the play right now, so we'll still move out to next year. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. And then on the midstream side, you talked about MarkWest laying this, they got the main lines. Who's responsible for hooking up the wells to those mainlines? Is that -- are you laying those pipes or is that MarkWest's responsibility? I was trying to figure out where you are with the permitting for all those?

No that's MarkWest's responsibility. And again, Mike, we were talking about, we started to put together the working interest in the well and way before we even though the permit, so we have plenty of lead time to tell MarkWest that 3 months from now, we expect to spud this well and 3 or 4 months later, we expect it to be producing. So you can see there's is like we have like 6 months time frame to tell them we're going to need half-mile long lateral or a mile long lateral to go out from the trunk line, so it's not a very -- unless you're just the -- as long as you've got the information available, you tell them ahead of time and we should have all the lines laid by MarkWest sitting there waiting when we put the wells online. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay, that's helpful. And then one last question. On the Wagner well, how would the condensate is that I think when you gave us test rate it was doing something like 25 barrels per million is that still about where it is?

Yes, we've got month of October that's pretty representative, and we were generally making about 4 million a day. We were making a little less than 80 barrels of condensate, and by the way, the water was about 20 barrels a day on the average. So about 1/4 of what we're making in the condensate.

Pardon me, ladies and gentlemen, the time for today's conference call has elapsed. I would now like to turn the conference back to your host, Mr. Paul Heerwagen.

Thank you. Ellie. It looks like we're out of time today, but we'll be available offline all afternoon. We're recording any questions from our participants. A replay of the call will be available, temporarily, through the company's website, you can access it at www.gulfportenergy.com. Thank you for your time and interest today. This concludes your call.

Ladies and gentlemen, this does conclude today's conference. You may all disconnect, and have a wonderful day.