Gulfport Energy Corporation (GPOR) Q4 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Gulfport Energy Corporation Fourth Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I'd like to introduce our host for today, Mr. Paul Heerwagen, Director of Investor Relations. Sir, please go ahead.

Thank you, operator, and good afternoon. Welcome to Gulfport Energy's Fourth Quarter and Year-End 2012 Earnings Conference Call. I'm Paul Heerwagen. 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 businesses. 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 the GAAP measures will be posted to our website. An updated Gulfport presentation was posted this morning to our website in conjunction with yesterday's earnings announcement. Please review at your leisure. At this time, I'd like to turn the call over to Mike Moore.

Thanks, Paul, and thank you all for joining us on our call. I am pleased to report that Gulfport recorded strong fourth quarter results, both operationally and financially, producing 608,000 total barrels of oil equivalent or BOE, generated approximately $50.8 million of EBITDA and 34 -- $35.5 million of operating cash flow and $15.9 million of net income. As a result, in 2012, Gulfport generated approximately $191.4 million of EBITDA, $178.8 million of operating cash flow and $68.4 million of net income on production totaling 2.5 million barrels of oil equivalent. In the fourth quarter of 2012, production averaged 6,614 BOEs per day, which was a decrease quarter-over-quarter due to the contribution of our Permian Basin assets. For the year ended December 31, 2012, production averaged 7,029 BOEs per day, which was a 10% growth in production over 2011. Allocated by field, fourth quarter production breaks out to be 3,195 BOEs per day from West Cote; 2,366 BOEs per day from Hackberry; 757 BOEs per day from Utica; and 296 BOEs per day from the Permian, Niobrara, overrides and other miscellaneous areas. Our production mix for the fourth quarter was 90% oil and natural gas liquids and 10% natural gas. Our full year production mix consisted of 93% oil and NGLs and 7% natural gas. Subsequent to year-end 2012, production during January of 2013 averaged approximately 6,614 BOEs per day. Moving on to the income statement. Revenues for oils, natural gas and natural gas liquids in the fourth quarter were $56.5 million. Full year 2012 oil and gas revenues totaled $248.6 million, which was up 9% year-over-year. Average realized prices for the quarter were $101.89 per barrel of oil, $3 per MCF of natural gas and $42.51 per barrel of natural gas liquids. Our blended realized price for the fourth quarter was $92.80 per barrel of oil equivalent, and our blended realized price per barrel of oil equivalent for the full year 2012 was $96.63. Lease operating expense for the fourth quarter was $6.1 million or $10.04 per BOE. For the full year, LOE was $24.3 million or $9.45 per BOE. G&A was $4.4 million or $7.29 per BOE for the quarter and $13.8 million or $5.37 per BOE for the full year. Depreciation, depletion and amortization expenses during the fourth quarter totaled $20.3 million or $33.40 per BOE and $90.7 million or $35.27 per BOE for the full year. To finish up our income statement discussion, I would like to remind you of our prior comments surrounding the income tax expense going forward. We currently still project tax expenses of approximately 36% to 40% in 2013, but still expect our actual cash taxes to be minimal, if any. In terms of capital expenditures, we spent a total of $250 million in 2012, which includes $175 million in 2012 drilling and recompletion activities, with the rest attributable to 2011 wells and facility costs in all of our fields. Moving on to the balance sheet. As of December 31, 2012, we had $167 million in cash and $299 million of total debt outstanding, and we're completely undrawn our revolving credit facility, which has a current borrowing base availability of $40 million. Today, we have approximately $270 million in cash. At present, we have fixed price swaps in place for 5,000 barrels per day of production for the remainder of 2013 at a weighted average price of $100.90. I would like to note that this current level of hedging effectively secures $184 million of 200 -- of 2013 revenues, which goes a long way towards the capital commitments for our 2013 capital program. Turning towards reserves. As of December 31, 2012, our total proved reserves on lower 48 were 8.25 million barrels of oil and 33.77 billion cubic feet of natural gas or 13.88 million BOEs. In Canada, Gulfport has 16.75 million barrels of proved reserves attributable to our 25% interests in Grizzly's Algar Lake SAGD project. In addition, third-party engineers have issued a probable report estimating 12.84 million barrels of oil and 80.62 billion cubic feet of natural gas or a total of 26.27 million BOEs of probable reserves associated to our lower 48 and 17.75 million barrels of probable reserves attributable to our interest in Grizzly. Moreover, third-party engineer GLJ has provided an updated year-end resource report of some of Grizzly's properties and has identified 765 million barrels of best estimate contingent resource net to Gulfport's interest. Using SEC pricing of approximately $91.32 for oil and $2.76 for natural gas, the PV-10 value of our lower 48 proved reserves was 43 million at year end. However, to give some sense of relevance in our earnings release this morning, we provided a comparison of the estimated PV-10 of our lower 48 proved reserves using SEC pricing to a December 31, 2012, price held flat, as well as a comparison to a December 31, 2012, NYMEX price. Compared to our $437 million year-end SEC Case, the Flat Price Case resulted in a PV-10 value of $447 million while the NYMEX Case yields a PV-10 value of $458 million. Including our probables, the NYMEX Case totals over $935 million. Looking ahead to 2013, I would like to take this time to discuss our 2013 guidance, which includes capital expenditures totaling $458 million to $512 million. We estimate full year LOE to be in a 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 a range of $33 to $35 per BOE. All of these remain unchanged. We currently anticipate production during the first quarter of 2013 to be relatively flat quarter-over-quarter at 6,800 to 7,200 BOEs per day due to the infrastructure constraints we've experienced. While production from the Utica has been lumpy and choppy over the past few months, it should even out considerably after the first quarter. By mid-April, our Utica assets are forecasted to be generating more net production than our other existing areas and should be allowed to grow free of midstream constraints as MarkWest infrastructure buildout leads our drilling program. Thank you for your time and interest today. I'd like to now turn the call over to Jim Palm to cover the operational highlights.

Thanks, Mike, and good afternoon to each of you. 2012 was a transformational year for Gulfport. Having secured our acreage footprint in the Utica Shale in 2011, we shifted towards drilling in early 2012. Our initial focus was aimed towards exploring and derisking the play. With results in hand and having solidified our thesis of the play's exceptional potential, we, first, firmed up gas gathering and processing arrangements with MarkWest. In addition, by virtue of our substantial acreage position in the core of the play, we've since secured anchor tenant status in a high-value condensate gathering-stabilization splitting system. With that capability, our condensate will be processed into high-quality light diluent for sale in the premium Canadian market and the stabilized heavies can be transported down the river to the highest-value opportunities, which may include the premium Gulf Coast markets. With substantial expertise in both these markets and a solid partnership with MarkWest, we believe we're well ahead of the market with regard to an integrated petroleum -- to an integrated midstream solution and purity product takeaways. Meanwhile, with positive results, extensive science under our belt and the ability to market our products, we took advantage of an opportunity to further consolidate our core acreage position, making a series of acquisitions that effectively doubled our net interest in the play. And finally, looking to the future, we solidified our liquidity position by contributing our Permian assets to the Diamondback IPO and with our inaugural senior notes offering. Together, these efforts ensure our capabilities to ramp up our activities in the Utica and efficiently develop this rare asset while staying within cash flow from operations and our current available liquidity. During 2012, we spud a total of 14 gross wells in the Utica Shale, with 2 wells producing, 8 wells completed and in their resting period, 2 wells waiting on completion and 2 wells drilling at year end. Turning towards operations. Our third horizontal rig is rigged up and is planned to spud probably next week. In addition, we have been drilling with one top hole rig, and we have a second top hole rig that's on location and will spud shortly. We plan to accelerate our 2013 drilling program in the Utica by operating top hole rigs alongside our horizontal rigs. The top hole rigs are relatively inexpensive to operate and will allow the most of the vertical section of each well to be drilled before a horizontal rig ever comes on-site. Under this enhanced process, we stand to save $25,000 or more per day on the top hole work versus the big rig. In the Utica, we are tailoring our drilling program to ensure that we're able to have wells online and flowing to MarkWest sales as quickly as possible while also enabling us to do some science at the same time. During the first half of the year, we will be actively pad drilling, typically drilling 2 wells off the same pad location at once. Many wells will be drilled off of existing pads, which will enable us to capitalize on the existing pipeline, the infrastructure and accelerate spud sales cycle times and revenues, by drilling more wells on locations that are currently in service or soon will be in service. The total number of wells to be drilled during 2013 currently remains the same at 50 gross wells, but we just ramped up our drilling rig count earlier, giving us a head start if we decide to accelerate drilling later in the year. We continue to explore the optimum well spacing in the play and plan to conduct science to determine the most efficient drilling and completion techniques. We believe it's critical to test and determine the optimum well spacing early in the play's development as it will ensure we maximize the value of our acreage. Spacing will vary from east to west, but we believe the optimal well spacing is considerably less than the statutory 1,000 feet between vertical wells. If we are able to prove closer spacing, we stand to unlock literally hundreds of additional locations for us to drill, substantially increasing the ultimate impact of the Utica to our story. And finally, I'd like to provide some color surrounding our plans to secure takeaway and reach premium markets and prices for the product that we generate from the Utica. Previously, we've detailed our plans for our rich gas gathering and processing via our partnership with MarkWest. This partnership affords us anchor tenant status on the Utica leg as the largest and most integrated rich gas system in the northeastern United States and the extensive network of purity product markets for natural gas liquids in the region. Meanwhile, we are forecasted to bring online significant condensate volumes in the Utica, and we have secured anchor tenant status in a condensate gathering, stabilization and split system. This system and the splitter, in particular, helped us realize 2 goals. First, diluent demand in Western Canada for heavy oil blending is real, recently trading at a 15% premium to WTI. And the high-quality lights then will be -- which will be generated from our system, are perfect for Canadian-spec diluent. In 2011, Canadian producers imported 140,000 barrels per day of condensate diluent. And this demand is forecasted to grow to 180,000 barrels per day in 2014, 330,000 barrels per day in 2020 and 450,000 barrels per day by 2025. We already see this demand generating a market-driven projects. And of which, Canadian-demand side provides the infrastructure necessary to close the supply-demand gap. We believe the markets will make the necessary volume commitments and back them with producer purchases in order to diversify diluent supply away from the Gulf Coast and to secure a better quality product. We expect this condition will drive up local competition for supply and local market prices. Moreover, we believe ourselves to be location advantaged, as Utica producers will receive a better condensate netback than producers to the east by virtue of proximity to the end market. Secondly, the heavies that are generated by the splitter are location advantaged with regard to the Ohio river and are an ideal project to be barged down the river and sold into high-value markets. And now let's move on to Canada. Grizzly has seen an active winter drilling season. At May River, the current program has been expanded from 25 to 28 core holes as per-well cost were under planned costs, allowing for additional drilling within the scope of the original budget. The resource quantified and the quality identified through this year's exploration program exceeded Grizzly's initial projections. Sufficient resource have been identified at May River to justify an additional 12,000 barrel per day development. At the end of the year, Grizzly received the third-party resource report from GLJ reflecting 16.75 million barrels of proved reserves at the Gulfport's interests in Grizzly's first SAGD project at Algar Lake. On top of that, we also had exposure to 17.75 million barrels of probable reserves and 765 million barrels of best estimate contingent resource attributable to Gulfport's interests. And remember, that represents only 35% of Grizzly's acreage. Following completion of Grizzly's winter exploration program next week, data will be provided to GLJ, Grizzly's reserves engineer, who will update the year-end reserve book to reflect this year's drilling results at May River. Meanwhile the planned date for first steam at Algar Lake has slipped into the second quarter. The root cause of the slippage extends from a decision made by the Grizzly management team to ship modules to site that had not been fully completed and send craft labor on-site to finish constructing the remaining small bore piping, insulation, heat bracing and electrical work on-site. At the time, Grizzly estimated and reported that the cost and schedule impact of moving the remaining work to the field would be minimal. However, the ramp-up of craft labor did not occur until January, and it has since become apparent that the productivity of field construction labor was very low compared to Grizzly's initial projections. As a result, site service and support costs for the craft labor ramped up rather than ramping down through the coldest months, which further impacted productivity. To our disappointment, these issues have led to delays, and delays cost money. This underscores the importance of effectively implementing the ARMs model, and efforts are underway to design even more of the components for shop versus field fabrication. Looking forward to first production at Algar Lake, Grizzly has developed in a robust infrastructure to support rail movement of crude to the U.S. Gulf Coast. Grizzly expects to net Brent minus $50 at the plant -- $50 at plant gate for bitumen versus Brent minus $80 that would be realized in Alberta for trucked bitumen today. Fixed rail transportation rates have been secured for 10 years between Northern Alberta and the U.S. Gulf Coast, and sufficient rail cars for Algar Phase 1 has been ordered for delivery in the second quarter of 2014. Sites have been acquired, one in Northern Alberta for the development of a rail car loading facility and one on the lower Mississippi to facilitate transloading of rail cars to barge or ocean tanker. Infrastructure costs are factored into our netback estimates. Now turning to Southern Louisiana. At Hackberry, we continue making some solid wells and are pleased to report we increased production by 39% year-over-year. During 2012, we spudded 24 wells at Hackberry, completing 19 as producers with 2 wells drilling at year end. In addition, we performed 32 recompletions. Currently, we are running 2 rigs at the field and are drilling ahead on our third and fourth wells of 2013. At West Cote, we continue to see steady success. In 2012, we spudded 31 wells, completing 27 as productive. In addition, we performed 61 recompletions. At the completion of our 2012 drilling program at West Cote, we released the rig in mid-December to return to port for scheduled maintenance. We recently brought the rig back to the bay and are currently drilling ahead on our first well of the 2013 drilling program at the field. To wrap things up, I'd like to reiterate again that the Utica is our primary go-forward focus, and we are allocating our capital accordingly. We're currently running 3 horizontal rigs and 2 top hole rigs in the play and are currently in the process of contracting our fourth horizontal rig, which we plan to add in April. In the Utica, we've identified a high-return opportunity that has an enhanced value if we develop at a faster pace than current levels of activity. Our forecasted cash flows and liquidity position support our ability to ramp up activities in the future if we choose, thereby, continuing to create value for our shareholders. I thank you again for joining us for our call today, and we look forward to answering your questions.

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

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

Jim, I guess this be first one for you. Jim, I know on February 6, you all reported that Wagner well had an -- had EURs of 1.8 million per Ryder Scott. I was just wondering, at this time, if you could, best you could, walk us through the depletion rate, if you could, on that well, including the components or what you're able to tell as at this point.

Sure, Neal. Let me say that back in 2012, which was the data Ryder Scott had to work with, we weren't going into the plant, so we did pinch back the well and constrained it back then. But just kind of give you a feel for what we did, 2012, we produced for 129 days. We averaged 5.2 million cubic feet per day and 95 -- 94 barrels of oil per day. And then towards the end of the year, we got into the plant and so we started to open up the well a little bit. We don't -- all these wells we're kind of taking the approach to our first wells in the field. So we tend to start off and ramp our way up as opposed to just opening the well up, because we're trying to make sure we don't damage our reservoirs. But in January, we averaged 5.4 million per day and 105 barrels of oil per day. And then in February, for the month to date, we've averaged 6.4 million per day and 110 barrels of oil per day. But just the last 7 days, we're producing at 7.2 million per day and 126 barrels of oil per day.

So it didn't appear to me -- I mean, I guess it's very early still, obviously, Jim, especially the way that well has been going as on and off earlier. I mean, is it fair to say, I mean, when you look at depletion rates, I guess, for that or the way you just estimated down the road? I know there's a lot of speculation that maybe the NGLs and some of the condensate might deplete quicker. Is there any speculation that you all have or estimates on that at this point?

Well, so far, we've seen that the condensate per million -- barrels per million is hanging right in there, generally, in the 17 to 18 barrels per million range, and it's been consistent through the whole things. So that's -- of course, that's the longest data that we've got so far, but it seems pretty clear that the condensate's not dropping off relative to the gas. And we're just working our way up and seeing where we'll end up. So we'll be more aggressive about completing wells on in the future. But these first couple of wells, we're just taking it easy.

Okay. And then just one -- now when you all step back and look at the -- your entire position there, 120,000-plus, what do you see as far as like -- if you'd just kind of ballpark. And then I have to say the dry gas versus lean condensate versus the risk condensate versus oil kind of by your acres, do you have any sort of guesstimate, I guess, or if you don't want to get that specific, maybe just sort of liquids versus gas? I know there's some speculation that some parts of the play are gassier?

Well, certainly, they're going to be gassier as you move east. But as you know, we haven't moved that -- we pretty well have been on a line -- the east side of our drilling has been on the line from the Chesapeake Buell well down through to the Wagner, down through the Shugert's. It's a little bit further east in the Stutzman, but we haven't got a -- we haven't really tested it much. So we don't know exactly what's going to be to the east of us. We're still going by the -- Chesapeake has done a lot of drilling north of us, and they published some lines. Until we drill out there and see a reason to change it, we're sticking with that. That makes -- according to those lines, we have about 17% of our acreage in the dry gas and we had about 70% in the wet gas and then we had 13% in the oil window. But as we drill more, of course, those percentages could change. Right now, we don't have any data to change that.

Got it. Then to 2 last ones, quick, for Mike. Just, Mike, on that production guidance you put out there, what gives you the confidence on the midstream? Is it just as far as you said it's going to ramp up or you'll have -- you won't have the issues that you had -- that you're having in the first quarter? Is this because of the locations of wells or just the fact that you know that more of the MarkWest is already going to be coming on by April or May or June?

Yes. That's a good question, Neal. So first of all, we do have a lot more confidence now that MarkWest is very close to getting us hooked up and for the wells that we drilled in 2012. So that's right around the corner. That well -- those wells are going to impact our production dramatically. We get the majority of those wells on, actually, in late March, early April, with a few remaining wells coming on in June. So we do have some confidence now that we're right around the corner from having the major hurdles overcome with MarkWest. But also, we've gotten a little smarter with our drilling plans and are certainly modifying our drilling plans to a certain extent, to make sure that we drill wells that we can hook up immediately. And so we have spent a great deal of time recently changing our drilling plans, talking about pad drilling and -- but making sure we're drilling in areas where we can hook the wells up immediately, which also gives MarkWest time to work on some of the outlying areas that we're not currently drilling in.

Okay. Then last one, just real quick, Mike. Just on the credit facility upcoming redetermination, do you foresee that going up or you just kind of ask to keep it the same? Or what's your thoughts on the credit facility?

That's a good question. We only had the 2 wells producing at year end. We had the Wagner producing and then, to a smaller extent, the Boy Scout. You could see some growth in the credit facility. I don't think you should expect a large growth just because we don't -- we didn't have that many wells producing, and they look at only PDP part of the reserve not the total proved reserves. So while there was certainly some PDP reserves assigned to us, I think this redetermination, you could see a small increase. But I think the bigger change to the credit facility would be later in the year when we have a sustained production from a lot of these wells. And we have talked to you about doing another third-party engineering report this summer. So we could ask for a special redetermination at that time, if we wanted to, to get credit. So not a big change probably this time, but a pretty dramatic change later in the year.

And our next question comes from the line of Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Jim, probably for you. You've -- a lot of people have been settling on 60-day resting periods. I know you've done one as little of as 12 days, especially when the -- once infrastructure is in place. Can you walk through your current thought process or views behind the resting period and whether or not you think 30 days can be ample resting period or if you need less? Or just what do you think you're going to do going forward?

That's a good question, Ron. We really -- we can't figure out what the best resting period is until we got the pipelines in there, until we can test the wells. So we're just now really approaching the point where we can look at production and where we can see what the real answer is to that. There's no doubt in my mind that if you rest the well for 12 days, like we did on the Stutzman, that when you come back after 30 days, it'll be a stronger rate and a stronger pressure. And after 60 days, it'll be even stronger on the rates and pressures. Now whether or not you're better off, though, to rest them at all or resting for 1 or 2 months, after a year, they may produce the same. So we have to get some production history before we know whether we would need to rest the wells. My gut feel is that a month is about right. I think 2 months, there's going to be marginal increase over one month. We've been really surprised. Well, if you look at the Boy Scout 5 test, we only tested that -- and it's an old well and we only rested it for 11 days and we had a really nice IP, in my opinion, for an 11-day rest period. So I think 30 days is probably my number. I think Mike has 60 days in his model when he models production. But I think it can be shorter than that. So that's where we're headed at this point. But again, that's my opinion, and we've got to get some production to kind of verify it. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And, Mike, I was going to ask -- he just mentioned it. But if you look at your guidance, it sounds like you are using 60 days. But can you provide just a little bit more color behind how you approach your guidance for '13 that shows really strong growth for the year? But assume -- what are you assuming from a resting period? I know you also -- like how are you -- what are you using from an expected IP rate and/or before you forecasting any delays? So I'm just trying to get a census of the conservatism of that guidance?

Okay. Yes, we feel like we've been very conservative, Ron, when we modeled. We, first of all, used a decline rate that is actually steeper than Eagle Ford, not because we believe that's what it's going to be, but because we wanted to be conservative in our modeling estimates. We used a very low IP rate. I won't tell you specifically what that is, but I will tell you that when we looked at our first 7 or 8 well results, we took our bottom well there, although all those were very good wells. We cut that in half and compared it to the data that we were putting into the model. So that suggested to us that we were still being very, very conservative. I was actually still below in my production estimates, what, 50% of that rate was from those -- from that worst well we had. So we looked at it a lot of different ways. We also built in 5 months, basically, from spud to first sales, so that accounts for not only a 60-day resting period, but probably more than 30 days to drill a well, which is -- we've actually cut down our drilling time and then become more efficient at drilling these wells. So there are a lot of moving pieces this year. And you just heard Jim talk about the potential of a 30-day resting period in -- as opposed to a 60-day resting period. So all I'm suggesting is we felt like we've built a lot of conservatism into the model. And that's why even though we were challenged in the first quarter, from the infrastructure perspective, we still feel, at this point, comfortable about the total year-end guidance. The other thing we're doing, we haven't really talked about much yet, is bringing in a rig a little earlier than we anticipated and so it seems like we're going to accelerate bringing those rigs in compared to what we talked about earlier. So again, a lot of moving pieces. But we felt like, originally, in our modeling, we were very conservative. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And you mentioned, I guess, Jim did, roughly 70% of your acreage is in that wet gas/condensate window, which, as I understand, that's where a lot of the infrastructure is going in, and you mentioned about shifting kind of some of the drilling plans. Is the focus going to be in that liquid/condensate window, A, because of the infrastructure? And then, B, is there any impact on that on the eastern and western acreage from an HBP status?

Well, we've got plenty of time to protect our HBP status. But actually, what we're doing now, I mean, we're producing the Wagner, but we're rigging up to go drill 2 more Wagner wells. So they'll go right into the pipeline that's there. And we're producing the Boy Scouts, but they're shut-in today because we're rigging up to start drilling 2 Boy Scout wells. So obviously, that well is going into -- those 2 wells will be going into the existing line. So that's where we're concentrating our production or our drilling in the first half of the year. Except we are drilling a well over on the east side to look at the gas, but there's a dominion line post close by, and it won't need to be processed, so that'll be a quick hookup. But at the rest of the wells that we're drilling in the first half are primarily like pad wells, drilling 2 at a time, drilling, in most cases, on existing pads or else ones that are right by the pipeline that's been laid to the existing pads. And so we should have immediate hookups on all this. Now one thing I think is pretty good with the schedule we put out from MarkWest a month ago, it shows everything hooked up by June 1. And that goes from the Groh well on the far west back to the northeast Harrison -- that's in Guernsey County, back up to Harrison County that's northeast of that. That's a 20-inch line. That 20-inch line is capable of moving 360 million cubic feet of gas per day to our plant at Cadiz. And then on the south end, the Stutzman is supposed to be hooked up June 1, and so that is also going to be producing. It'll be a 20-inch line. In the meantime, by April -- today, we've got 3 wells producing. By April, we'll have 10 wells producing, and we'll have those other 4 on by June 1. So we're having a -- we're going to have a nice ramp-up, starting really at the beginning of the second quarter. We've got some wells coming on in March and a lot coming on in April. So now -- so we know those lines are going to be there, so that's where we're doing our drilling. We're doing science in there, too. That's why we're going back to the Boy Scout because we're trying 2 different spacings, so we can determine how far apart to put our laterals. And we'll talk some more about our science before the call is over with. I'll tell you about a well called the Darla that we're going to drill right next to the Wagner and go into that line. But for right now, we'll move on to the next question.

Yes. And the good news is we, like MarkWest, are focused on certainly developing out that infrastructure, first, in the highest-return opportunity area, which is where we're focusing our drilling on right now for 2013. So that will be a core area for our drilling activity this year is that liquid window. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then one clarification, just on the Canadian contract -- the rail contract that Grizzly has. That's a 10-year contract with CNR, I believe. And is that -- is the 10-year contract -- is the Brent minus $50 for the total 10-year period, or how is that pricing written? Or is that just over the -- for the initial part of the production?

Well, that's a contract for the rail rates. And of course, what turns out to be the price at the plant gate is going to depend on what's happening to the various components that move in the meantime. But it's a transportation rate contract fixed. That's a big piece of the puzzle though. So having that, and as we said, they've also contracted for their cars. And we won't get into too much detail on that, but there are several kinds of cars there in the works. And it's a great solution. We've got an expert up there, a guy that's been in the rail business for a long time. And I think that you'll see the Grizzly's at the leading edge of trying to solve the realization problem up in Canada.

And our next question comes from the line of Jason Wangler from Wunderlich.

Nice update as far as the Wagner. Is there any way to kind of differentiate what you saw in terms of condensate when you were in the temporary [ph], which I assume was basically 0 versus when you got into the plant now? If you're able to strip out what you're seeing as far as the gas versus, actually, the condensate or NGLs.

Well, the numbers we were giving you were wellhead numbers and tank numbers. In other words, the -- it's the gross gas volume produced at the wellhead. Early -- until we got into the plant on the Wagner, of course, we were going to say a Dominion line. And -- but those are the sales numbers. We weren't getting the NGL proceeds. And now that we're in the plant, we are going to be getting the NGL proceeds. But it's -- we're so early in the stage that we haven't gotten statements and so forth and so forth. So I can't tell you what the NGLs are this moment. But those numbers that we gave you are the condensate in the tank and the gross gas produced at the wellhead.

Okay, understandable. And you obviously updated the first 10 or 12 wells and that the schedule is still as it was about a month ago. After that, do you have just at least an indication? Is it going to be a pretty steady state of completing 2 or 3 wells a month or something of that nature? I guess what are we looking like after we get to June 1.

Well, after we get to June 1, we're going to have a lot of rigs running by that time. Each rig should be producing about one well per month. If we could choose -- if capital were no constraint and we're going to move on to a new location and if we had room to drill 5 wells, I'd just as soon drill 5 wells at one time. But by the time we frac them and rest them, it would be 7 months from spud to first revenue. So when we look at our alternatives, we've kind of come up with drill 2 wells on a pad, move to the next pad, drill 2 wells there, move to the next pad. So that's kind of what you'll see with our drilling rigs, and we should be moving pretty fast. These top hole rigs can actually drill that first vertical part of the well quicker and obviously cheaper than the big rigs. So by the time we get them lined out to doing things our way, we've got a one new one coming on. Having 3 horizontal rigs and 2 top hole rigs will not start off as equivalent to 5 rigs. But by the time we get to the third quarter, that's about where those should be. So -- and we're going to add some rigs in between, already one scheduled to come in -- one horizontal rig to come in, in April. So moving, moving at a pretty good clip by the third quarter and if we continue to see the kind of results that we've got and if the wells are online to MarkWest, as we -- as I've said they will be. One thing about June 1 that I think's really pretty neat is that every well we drilled in 2012 is scheduled to be online by June 1. Now how many wells are sitting around in the Utica and how long they have been drilled. It's been there -- we are way ahead on the curve, even with the delays that we've had so far. MarkWest has got their feet on the ground now. They've been through the regulatory stuff. They've been through the landowner right-of-ways. So we've got the pipeline right-of-way to lay our condensate gathering system in. There's so many things in the way of infrastructure that are in place. So the first 6 months, we're going to stick right in that developed infrastructure. And remember, a well that we start drilling in April, even if you just drilled one well, you drill it in April, frac it in May and rest it in June, so you can see that any drilling after that, you don't even get the wells on until the second half the year. So anyway, we like [indiscernible], and it should be going fast.

That's kind of what I was just curious about is, obviously, you're running the 2 rigs in the first couple of months of this year. You'll get that third going. So as we get to June 1 and all the first wells are all online from last year, there's an inventory of maybe 10 or 12 wells that would be ready to go if you had the midstream. Is that about right?

Well, except those 10 or 12 wells will be -- everything we drill in the first 6 months is basically right where the infrastructure is in place now. And so we're going to go back to the pads that we've already drilled. We're going back soon to the riser. We've already tested that well. We're going back to that one. We're then going to go back to the clay. We're going to drill 2 more wells on the clay, 2 more on the risers. So what we're drilling in the first half is going to use this -- the same infrastructure that's going to connect the first 14 wells. And then, of course, by the time you -- we're really looking toward the wells that we start spudding in July and August to stretch out the MarkWest infrastructure a little bit. But first, the wells we're drilling on July and August won't get on until September, October.

Sure. Okay. And then as -- Mike, I'm sorry didn't catch the guidance for first quarter. Could you just give me that again?

6,800 to 7,200 a day. Sorry, we're having some microphone trouble here this morning.

And our next question comes from the line of Brian Velie from Capital One.

I did have a question. I was going to dig in just a little bit on the Grizzly project. I think I missed when you were speaking, Jim. You mentioned that there's a delay to the first production number. Did you say when the new expectation is?

Yes. So right now, it looks like it slid a little bit. So we're -- right now, the first steam has slid over into the second quarter, which means, probably, first production slides over into the third quarter. We're not sure exactly where inside, but there does seem to be a little bit of slide, a lot of last minute details to take care of. And it's still really cold up there, so they're still fighting some very, very cold weather.

Sure. The only other question that I have about that was the anticipated capital then that we've been talking about, that we were thinking around midyear. Do you think that we should probably view that as kind of sliding out along with first production?

Well, that's logical. You would certainly want to see first production ahead of that project or that capital event. So that would be probably a logical conclusion.

And our next question comes from the line of Tim Rezvan from Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: I had a quick following up. I appreciate the color on the Wagner well. I'm not sure exactly when you shut in the Boy Scout pad, but you probably had some pretty good production from that area if you got it on at year end. Can you kind of talk about what you saw in terms of production and kind of how the condensate held up?

On the Boy Scout? Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Yes.

Well, actually, we had some more sustained production at the end of 2012. 2013 has been so choppy with the rigs moving on and off, and the pipeline is going in, getting to the plant -- into the plant. We actually only got into the plant about 2 weeks ago with our 2 Boy Scout wells. So we really don't have very good data to give you for 2013, but I can tell you what we did in 2012. We started producing the Boy Scout, and this was just that one by itself. We started producing the Boy Scout 1 November 27. And through December 31, that was 34 days, and it produced for about 29 of those 34 days, again various start-up things that go on with -- that you normally have with the well. And so during that time, we averaged 3.4 million cubic feet a day. We averaged 933 barrels of condensate for a total of 1,498 BOEs per day. And again, keep in mind, we like to -- that's the first oil well, just like the Wagner was the first gas well. We like to ease into these things. So we don't try to put on our wells and rock them open. But I don't think I would be -- I don't think I'd really want to produce too much more than that anyway, just because we make sure that we don't harm the reservoirs to get these things on. So then we've got a bunch of choppy bits and starts in 2013. As you know, Tim, you were out there, I think, on the field trip, but it was shut in and frozen off at the day we were out there on the field trip. And keep in mind, it's heavy liquids. It takes gas to flow this thing. We'll be producing it while we're we drilling out there. With all the liquids that we make, I think we're eventually going to have to have our artificial lift on these. We've got the horizontal laterals and so forth. So I anticipate -- I don't know how long it'll flow before we need to have some artificial lift, but we won't be able to do that for a couple of -- if it does affect it, we won't be able to do anything about it while we're drilling the well. But in any case, we're really pleased with the way it started off. We thought that was a nice rate and look like it was hanging in good. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. So you're not seeing anything -- the condensate ratio seems to be stable from your limited...

Yes. So far, everything's pretty much constant, just like it was over on the east side, although we do have a lot -- there's a lot less gas over here. So I suspect that you're not going to see as good a correlation and as flat a correlation over here as you are going to see over on the east side. But I don't know that for sure because we have so little data consistently. So again, we're just in the early stages of gathering data and really don't have a type curve for the west side, where it's wetter.

But, Tim, at this point, to add some additional color, we are not seeing any degradation in the EURs. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. I appreciate that color. And then just final question to clarify what you've mentioned earlier on the -- talking about kind of the impact in April of the Utica. If we look at kind of your production now, 6,600 a day total, Utica is roughly 800 and then 5,800 from everything else. When you talk about kind of that big ramp in the Utica, so is that what -- when you say Utica's going to be bigger than everything else, you're saying that should be 5,800 or more relative to 5,800 of the rest of your portfolio by April? Is that kind of what you were -- just trying to put some numbers kind of that -- to the...

Well, I think in the second quarter, it's certainly conceivable that our production will be double what we are in the first quarter with the -- bringing on those Utica wells, if that's your question.

And our next question comes from the line of Leo Mariani from RBC.

Just wanted to clarify what you said on that last answer there. So are you saying your Utica production is going to double in the second quarter versus the first quarter, or total production?

No, total production.

Okay. And just -- could you guys speak to well costs in the Utica? I think you've talked about starting to reduce drill times. You've talked about bringing the spudder rigs to save money. What are the well costs now, and where do you see those going as a result?

Well, we're still -- the base well cost that we're looking at is still about what we said to be for a long time. If you're drilling a 5,000-foot lateral -- of course, it does depend on how deep it is. That that makes a difference. But so much of your cost is related to the completion and the frac jobs that are -- rule of thumb is if it's a 5,000-foot lateral, figure $1,500 a foot or $7.5 million. If it's a 8,000-foot lateral, then figure $1,200 a foot or $9.6 million. But we're still doing a lot of science, and I don't know if that answers your question about the cost. We will see it come down in the future. But right now, we're trying to keep our drilling well design and so forth pretty constant because of the different science things we're doing. And if that answers that question, I'm going to tell you something about the Darla, which will be extreme. You might call it an extreme science well, and you'll see some of the other costs that can come on top of that at this early stage. Does that satisfy your question about the drilling cost for each well?

Yes. Jim, obviously, you guys talked about science in these wells, which sounds like once you're in developing mode, that goes away. You talked about selling our saving $25,000 a day using the spudder rigs. So just trying to get a sense of where these well costs could go by the time we're at the end of the year or early next year in development mode?

Well, they'll certainly be down by then. But right now, that's pretty well the base figure. And of course, where we drill, it depends on whether or not you're on the east side or the west side, because it's deeper and so forth. But on average, that's probably the best numbers that we have right now and pretty much what we had expected and where we still are. But that's -- I mean, I haven't got anything else to say about that. But if you want me to tell you something about the science, I can tell you about some of the additional costs there that we're experiencing

Sure.

We have a well called the Darla that we're going to drill. After we drill these 2 wells on the Wagner, we'll take that rig up to the new location that's just barely north of the Wagner. And this one, again, it's like "throw the kitchen sink" worth of science, but we think it's money that'll be well spent at this stage of the game. We talked about -- we're trying to figure out the best way to frac the wells, and we're trying to figure out the best way to him space the wells. And so the Darla is sort of a unique situation because we're going to drill 3 wells off of that one pad, and they're going to be sort of fan-shaped array when we drill the wells. In other words, the -- as compared to the middle well, back near the heel, one of the laterals will be 300 feet away from that well. And when we go to the toe, it'll be 1,300 feet away. So we're obviously going to have -- when we frac the well, we're going to have quite a wide range in there of the distances between the wellbores. Then when we frac it, we're going to use 3 different frac designs. Two of them will have 550,000 pounds of sand per stage. Stages are about 240 feet long. And the other one will have about 300,000 pounds of sand in that stage. But the -- one of the -- one's that 500,000 pounds will have CARBO Ceramics in there, which may make a better well. We also will be putting in radioactive tracers, so we can go back after we frac the wells, seeing where the frac actually went. So there'll be different tracers for different stages. We're also putting in chemicals that will allow us to see if there's communication between the wellbores and whether or not we communicated at 1,300 feet or whether we communicated at 300- or 400-foot spacing. So we're also putting in optical fiber, and that optical fiber will allow us to tell from temperature readings, which intervals are producing. Right now, we frac a well and we have all these perforations down there and we don't really know whether we're producing from the heel, from the toe, whether it changes from day-to-day, from month-to-month. Now we'll be able to real-time what's going on down the hole and which perfs are actually giving up the hydrocarbons. And another thing we'll do with optical networks, we'll be able to put a pressure transducer down there. So today, all we know is what the -- what's going on at the surface on the well. And so we will be able to fill now what our flowing bottom hole pressures are for the well. So that gives us more valuable information that we don't have today. So just the pressure transducers and the optical cables that go down there, that'll be about $600,000 per well. And then we'll also do microseismic while we're frac-ing it, and that's going to give us valuable information about where our fracs go according to be microseismic. And if it says the fracs are reaching out and touching the other wellbores, the chemicals will tell us if they really produce, even though the frac may have -- we might see frac energy going out there, but may or may not connect the wells. So that's going to help us figure out how far just apart to space them. So if -- it's really key, though, that we get in here and figure things out like the spacing on the wells and the best frac design early. If it turns out that we can give less sand and still make as good a well, just think how much money we can save in the future as we frac them. And if we can space them closer together, then we can drill that many more wells on our acreage. So I know this sounds like a lot to spend, but that's why -- we're not through the development stage yet. When we do, we'll see it go -- we'll see the cost go down. But right now, we're still doing -- I know it seems like we've done a lot of science and we have, but we're not through yet, and that's kind of what we're concentrating on this first 6 months.

No, that was helpful for sure. And I guess just want to clarify on the Cadiz plant. Has that started up yet? I think it was scheduled to start up in March. And I guess as the plant gets up and rolling, you think that's going to eliminate all of the production constraints on your wells?

Well, we really don't anticipate we're going to have any construction -- or production constraints. Right now, we have 60,000 -- or 60 million cubic foot a day capacity. That's through the refrigeration plant. And MarkWest is scheduled to start the cryo plant, which will have another 125 million a day capacity at the end of the third quarter. And so we're going to have plenty in the short term. In addition, actually, there'll be a Seneca plant that starts up in the third quarter down south, and we will actually probably send some of our southern wells down to that plant. MarkWest is really putting in -- it's not a single plant. They're actually going to have 2 plants in there, and it's really just one big giant plant system, which we are preferred user on and which we get a preferred rate on and we can go to either plant. But they're going to have another 200,000 -- or 200 million cubic foot a day capacity down there in the third quarter and another 200 million in the fourth quarter. And then early next year, there'll be another 200 million. So we're going to be up pushing 800 million a day capacity pretty early in 2014. So we've got charts where we ramp up what our wells could be doing versus what the plant capacity is. And I can assure you, there's plenty of plant capacity. And as I said before, our pipelines are capable of carrying 360 million a day, north and south, and so we've got plenty of capacity. We will not outrun their ability to take our gas.

So -- and I just want to clarify, we don't have -- there are no current production constraints related to plan or takeaway. And just to remind you, by year end, MarkWest should have 800 million a day of processing capacity in service. So we think that we certainly have a plan for all of our takeaway.

No, that was helpful. And I guess just lastly, what are your current plans for your Diamondback stock?

No current plans. We certainly like the Permian Basin. We like the management team over there. We like what they're doing with their horizontal program. I think I just announced some nice results yesterday. So no current plan. Obviously, we have a great deal of liquidity already. We think we're well funded for Utica. So I guess long way to answer your question is that we have no current plans with that stock.

And our next question comes from the line of Jeff Hayden from the KLR Group.

Most of my questions have been answered, but just kind of wanted to jump back to the guidance. If we look at kind of that about 7,000 for the Q1 and about double that for Q2, that implies you're averaging 32,000, 33,000 a day for the back half of the year. I mean, should we think of -- does that put you on exit rate about 40 -- somewhere around 40,000 a day? Am I thinking about that right? Any comments on how we should think about production when we get to the end of the year?

That's a good question. I think I would think about exit rate more in the 35,000 to 38,000 BOEs per day, Jeff. That seems a more reasonable number to me at this point. So what you're going to see this year is some lumpiness from quarter-to-quarter. You're going to see a big group of wells coming on in the second quarter, so you'll see -- you should see a big growth in the second quarter. I would say probably a fairly big growth in the third quarter, and then maybe a little leveling out to some extent -- still growth in the fourth quarter, but maybe not quite as dramatic as the second and third quarters.

And our next question comes from the line of Mario Barraza from the Tuohy Brothers.

All my questions have been answered.

And our next question comes from the line of Biju Perincheril from Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Couple of questions. On the reserves that you booked out of Utica, I think it was something like 6.6 million barrels, can you talk about how many of PUD locations you booked and how many PDP or PDMP locations?

I don't recall the exact number of PUD locations. Most of the reserves, Biju, were attributable to the Wagner well and offset locations that we got from the Wagner well, also the Boy Scout. When they performed these reserve evaluations, you get 2 offset locations to each well. So most of all the reserves were attributable to -- the larger part of the reserves were attributable to the Wagner and the Boy Scout, mainly the Wagner. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. And then I guess you were -- at year end, you only had 2 wells producing, the Wagner and 1 Boy Scout, is that...

That's correct. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: So if I think of just PDP, only 2 PDP locations, correct?

Right. There may have been a few other outliers that they gave a small amount of PUD locations, too, but really not very relevant.

Yes, I think they gave some -- particularly over on the east side, where the Wagner was, where we actually had some production history. I think they gave some locations that have been tested some validity. So like Mike said, the Wagner and associated wells would be the ones that got the most reserves. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. And then the Darla pad that you were talking about, Jim, what's the timing of that? And once those wells are online, what do you think -- how many months of production would you need to answer some of the questions that you're after there?

Biju, we're going to drill the -- those 2 Wagner wells first. So that's going to take about 2 months to do that, and then move up to the Darla and then we'll drill those 3 wells. That takes about 3 months to do that. We'll shortcut that a little bit by going up there with the top hole rigs, and we'll set -- we'll already drill some of that. So we'll probably take actually less than the 3 months. But then it's going to take 3 or 4 weeks to frac the wells. They're going to be 8,000-foot laterals, so there'll be 30-some stages of frac to do. So that's going to take a while. I think really resting for a month up there is plenty, so that's more or less 5 months before we get ready to go down the sales line. So -- and with 2 months to drill on the Wagner, that's close to 7. So you can see it seems like a lot of science to do early, but it takes a long time to do science. Now when we start producing it, we would normally expect to have to wait 4 or 5 months to see the impact on decline curve if the wells are close together. So that's why we've chosen to put in the chemical tracers. And let's say there's going to be 30 stages, we'll probably have like 15 different chemicals and put a different one in for the first 2 stages of the toe. And then as we work back -- and this will be able to be identified distinctly. So we'll probably put those in the middle of the 3 wells. And then instead of having to wait for production to tell us we were too close together, if the chemicals that come back from the 300- or 400-foot spacing or if they're -- if we started getting chemicals back from when we were 500-feet apart, then we'll know soon after we start producing the wells that we did communicate and that the frac from the middle well got into the well to the east or the well to the west of it. So we're shortcutting our learning curve there. We have -- we still -- we'll obviously take longer. I mean, if we're going to frac some wells with 500,000 pounds of sand and some with 300,000 pounds of sand, it's obviously going to take 4 or 5 months to see a negative impact if one of them is better than the other one as far as a regular production decline. But we did think those chemicals are going to tell us a lot sooner whether or not we're communicating between the wellbores, lots of science going on. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Very good. That's very helpful. Are you still planning on drilling then the -- I guess the tighter spaced wells at Boy Scout, or are you going to wait for the -- these wells to do that?

Well, we're going to drill one that's about 600 feet away from the south well and one that's about 800 feet away from the north well. I would like in time to test 400 feet. And some of the -- we're having some work done by Von Gonten that's suggesting that maybe 400 feet would not be too close. But I think we're going to hold off on that one for now, because we've got this Darla test that will give us some insight, even though it's a gas well. And then we can come back later if we don't see communication and drill a 400 footer between the 2 north wells. The one we're drilling now, as I said, is 800 feet apart, so we could still come in and drill there. So right now, we're only going to drill 2. Part of that is driven by the fact that on the Boy Scout, we need to be out of there by June 15. I kind of would like to try 3, but we need to be out by June 15. Then we want to make sure we can get the wells frac-ed, and we'd like to have them producing before the Boy Scouts come in for summer camp. So 2 wells is what we're going to do right now.

And we have time for one more question. Our final question comes from the line of David Beard from Iberia.

Maybe just talk a little bit about another question that asked before, but the timing that you'd want to run the Darla well before you could better understand well communications, because that actually could happen in a -- after a couple of months of production, if I'm not mistaken.

Well, that's true, and that's why we went with the chemicals. And again, let's say we do 30 stages and we use 15 different types of chemicals, if chemical A is at the toe for the 1,300 feet apart, I wouldn't expect we'd see any chemical A show up put in the -- well, we'll put in the middle wellbore and if -- and we wouldn't expect to see it show up from the toes. I'd be real surprise if it showed up in the other 2 wells. But when we get down to 500 feet apart and maybe we're on chemical K, and it shows up, then, of course, you'd expect that the closer ones, those chemicals would show up, too. So the chemicals will give us a head start on determining whether or not we're communicated. It could be that will frac fast there. That's why we're running the microseismic. We might see a frac event go past the wells in certain places, but that doesn't mean necessarily that your production will show up there. It may take a long time before they actually show up as communication. But we think these chemicals will be a lot better marker. If we didn't run the chemicals and -- then we'd really have no way to tell how they were communicated. So for this particular well design, in the fan shape, the chemicals made a lot of sense to us.

And that concludes our question-and-answer session today. I'd like to turn the conference back over to Gulfport Energy for any concluding remarks.

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

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program, and you may now disconnect. Everyone, have a good day.