Gulfport Energy Corporation (GPOR) Q1 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Q1 2012 Earnings Conference Call. [Operator Instructions] As a reminder, today's conference is being recorded. I would now like to turn the conference over to your host, Paul Heerwagen, Director, Investor Relations. Please begin.

Thank you, Sean, and good afternoon. Welcome to Gulfport Energy's First Quarter 2012 Earnings Conference Call. I'm Paul Heerwagen, Director of Investor Relations, and with me today are Mike Liddell, Chairman of the Board; Jim Palm, Chief Executive Officer; and Mike Moore, Chief Financial Officer. During this conference call, participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, future 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 our website. An updated presentation was posted to the website yesterday afternoon in conjunction with today's earnings announcement. Please review at your leisure. At this time, I'd like to turn the call over to Jim Palm.

Thanks, Paul, and good afternoon to each of you. During the first quarter of 2012, Gulfport generated approximately $49.8 million of operating cash flow, $48.6 million of EBITDA and $26.9 million of net income on production totaling 645,000 barrels of oil equivalent. Operationally, we had an active quarter, especially ramping up activities in our Utica Shale play in Eastern Ohio, so I'm going to begin today with an update on the Utica. Having completed the leasing process of our 125,000 gross acres, we are now moving into the delineation and development phase of the project. In April, we TD-ed and set pipe on our first horizontal well in the play. The Wagner 1-28H was drilled to a total vertical depth of 8,673 feet, with a 8,143-foot horizontal lateral. The well encountered an average verticals thickness of 123 feet within the Point Pleasant interval and to date has the longest lateral and longest total measured depth of any well ever drilled in Ohio. At present, we are running 2 rigs in the Utica and are making the curve section of the horizontal lateral of our girl well and getting ready to start drilling the curve on our Boy Scout well. We plan to keep these 2 rigs busy for the remainder of the year and expect to spud approximately 20 Utica wells during 2012. From a completion standpoint, we are scheduled to be in frac-ing our Wagner well on Monday next week. We are learning about the Point Pleasant all the time through a number of data sharing arrangements with our industry peers, service companies and third-party consultants. Based upon the data we've obtained for both the Utica and the Eagle Ford, which is in many ways similar to the Utica, we modified our completion procedures. We will not follow the traditional model of flowing back our wells immediately after stimulation. Instead, we plan to leave our wells shut in for a minimum of 60 days for a resting period prior to bringing them online. This decision relates primarily to the Point Pleasant formation, having one of the lowest, if not the lowest water saturations of any shale formation. Low-water saturation introduces a new variable as it relates to the completion. When the water from the frac is introduced into the formation, the water appears to block the port throats, and during the resting period, the water dissipates from a high concentration near the wellbore to a low concentration as the shale draws the water away from the wellbore. Based upon our understanding of this dynamic, we believe that a 60-day rest period allows the natural pressures within the reservoir to disperse the water and provides for optimal frac conductivity within the reservoir. As an example, the Chesapeake Buell well improved dramatically after being shut in while waiting on pipeline. And by the way, based on the things we are learning, we continue to be pleased with the location of our acreage. Not all acreage in the Utica is created equal. In every shale play, there's a sweet spot and based upon all the evidence that we've seen thus far, we are in the right location. Going into the play, we specifically targeted an interval greater than 100 feet thick, at a depth shallower than 9,500 feet but deeper than 7,500 feet, with an average TOC content greater than 2% located predominately within the wet gas and volatile oil places of the hydrocarbon system. We felt like these reservoir characteristics provided the ideal mix of in place volumes, pressure and deliverability. Meanwhile, with our first well down, we feel even more confident in our position. We recently perforated the toe on the Wagner well and conducted a differential formation injectivity test or DFIT to fine tune our frac job. We were pleasantly surprised when the results of the test indicated significantly higher firm than even our most optimistic estimates. The quality of assets alone is just one piece of the Gulfport story in the Utica. Our goal going forward is to be the most efficient, low-cost operator in the play, much like we've distinguished ourselves in Southern Louisiana. With regard to product pricing, we're not just going to be price takers up there, and we've been actively securing product takeaways. In fact, on the midstream front, we've been delighted with our partnership with MarkWest. They're already laying pipeline. They're constructing, gathering the processing facilities ahead of our drilling schedule. We're not anticipating any delays related to midstream facilities. In the short term, while they finished construction of their cryogenic processing facility, MarkWest will provide 40 million cubic feet per day of refrigeration processing capacity this summer. Meanwhile, they anticipate their first cryogenic Utica plant, a 125 million cubic feet per day facility, to be completed by the end of December this year. MarkWest has secured markets for our NGLs and residue gas. Meanwhile, we participated with our partner in the acreage in the formation of a company called Timberwolf terminals. This will operate a crude and condensate terminal and a sand transloading facility located along the Ohio River in Martins Ferry, Ohio. This facility secures key takeaway for our product in the Utica and provides optionality in marketing our crude and condensate, including the ability to reach refineries along the river system and even the Gulf Coast premium markets. Now turning towards West Texas. During the first quarter of 2012, a total of 5 wells were drilled on our acreage in the Permian. At present, 2 rigs are currently active on our acreage, drilling ahead on the seventh and eighth wells of 2012, one of which is currently drilling a horizontal lateral to test the horizontal Wolfcamp potential underlying our acreage. As we previously announced, Diamondback, the operator of our acreage in the Permian, as well as additional acreage in the Permian, has filed a registration statement with the SEC for its initial public offering. We've agreed to contribute our acreage to Diamondback prior to the completion of the proposed offering in exchange for common stock, representing 35% of Diamondback's outstanding common stock, immediately prior to the closing of the offering and approximately $64 million in cash, subject to adjustment. Our obligation to complete the contribution is subject to various closing conditions, including our satisfaction with the terms of the Diamondback IPO. We have optionality here. If the Diamondback valuation is attractive to us, and we choose to complete the contribution, the contemplated transaction would further serve to strengthen our balance sheet and eliminate our future CapEx needs in the Permian. This would free up capital for investment in the Utica, as well as other opportunities, while still allowing us to participate in the Permian play as an equity holder. As the holder of equity in a public company, we may also have increased flexibility in further monetizing our investment if we choose to do so in the future. Shifting towards Canada. Grizzly continues to be on schedule and on budget in building its first SAGD facility at Algar Lake. Through the end of the first quarter, approximately 47% of the Algar Lake budget had been spent according to plan. Roads, sites, water well and pipeline construction are largely complete with only a few non-critical path items awaiting completion. Central plant modular construction is proceeding at the shops in Edmonton and Grizzly is set to begin in-field facility construction later this month. Meanwhile this month, Grizzly is halfway complete with SAGD well pair drilling to 5 out of 10 pairs drilled under budget and ahead of schedule. Today, Grizzly is only 7 months away from putting steam in the ground and is rapidly moving towards the first oil in mid-2013. Meanwhile, from an exploration standpoint, Grizzly has fully delineated sufficient resource for a commercial project at Thickwood Hills and plans to file a regulatory application for that project later this year. In addition, at Grizzly's newly acquired May River property, plans are being formulated for the upcoming winter drilling season and ultimate development strategy. We believe our investment in the oil sands will begin to be appreciated by the market more and more as Grizzly moves into production and starts to demonstrate the true productivity potential of its assets. Now let's go on to Southern Louisiana. At Hackberry, during the first quarter, we drilled a total of 7 wells, completing 6 as producers, and performed 10 rig completions. We are currently running 2 rigs at Hackberry, drilling ahead on our 11th and 12th wells of 2012. Meanwhile at West Cote Blanche Bay, during the first quarter, we drilled a total of 8 wells, completing 7 as producers, with 1 waiting on completion, and performed 11 rig completions. At present, a barge rig is active at West Cote and is drilling ahead on the 12th well of our 2012 program at the field. Now moving along to Colorado. In the Niobrara, late last year we drilled 3 wells without the benefit of our recent 3-D seismic survey. We're very pleased with our first well, the Ellgen. We initially completed this well as a natural open-hole completion, and we made approximately 26 barrels of oil per day the first 30 days. During this initial 30 days, we experienced sloughing and decided to run a slotted liner. The next 30 days, following rehabilitation, the well averaged 70 barrels oils per day, which accounts for better than a 265% improvement. The production decline on these wells is typically very low, and we expect EURs to be comparable to that of the previous 2 wells we purchased with the original acquisition, the Allen and the State #33. Our third-party engineer, NSA, gives these first 2 wells EURs of approximately 200,000 barrels. All 3 of the wells we drilled within the last year had completion issues that required a change in our procedures. All 5 of our current drill sites were chosen without the benefit of 3-D seismic. We're pleased to have 3 good producers so far. Our expectations are even higher for future drilling. We've completed processing our 3-D data and have identified some exciting targets. We've identified 2 wells to be drilled back-to-back in the Craig Dome area scheduled to start next month. The 2012 budget in the Niobrara is subject to change based upon results, but we've currently budgeted to drill 5 to 7 wells. So to wrap things up, 10 years ago, we were a quiet little Louisiana Gulf Coast operator. By virtue of our unique legacy assets, we successfully harvested significant cash flow from these properties over the years. This has in turn allowed us to follow our bias toward crude resource into some of North America's most relevant oil basins. Grizzly is on the cusp of first production and is working toward a capital plan with the goal of soon becoming self funding. Proposed contribution of our Permian assets into the contemplated Diamondback IPO would eliminate our future CapEx requirements in the play while maintaining continued exposure to the basin. Going forward, the Utica will be our primary focus area. The upside presented by opportunities in this basin are too significant to ignore. Accordingly, our operational efforts are being directed primarily toward Ohio in an effort to develop the Utica into a major core asset for the company. In doing so, we intend to build a solid foundation, vertical integration and the securing of product takeaways in order to ensure we capture the full value generated by this rare asset. Thank you for your time and interest today. And now I'd like to turn the call over to Mike Moore to cover our financial highlights.

Thanks, Jim. And thank you, all for joining us for our call. During the first quarter of 2012, Gulfport generated approximately $48.6 million of EBITDA, $49.8 million of operating cash flow and $26.9 million of net income. During the first quarter, production totaled 645,000 barrels of oil equivalent or 7,089 BOEs per day, which is up 24% on a unit basis year-over-year compared to the first quarter of 2011. Allocated by field, first quarter production breaks out to be 3,452 BOEs per day from West Cote, 2,528 BOEs per day from Hackberry, 997 BOEs per day from Permian and 112 BOEs per day from the Niobrara overrides and other miscellaneous areas. Our production mix for the first quarter was 95% oil and natural gas liquids and 5% natural gas. Subsequent to the first quarter, April production averaged approximately 6,712 BOEs per day. Moving along to the income statement. Revenues for oil, natural gas and natural gas liquids in the first quarter totaled $65.4 million. Average realized prices for the quarter were $107.56 per barrel of oil, $2.91 per Mcf natural gas and $54.21 per barrel of natural gas liquids. Our blended price for the first quarter was $101.42 per barrel of oil equivalent. These operating expenses during the first quarter was $5.8 million or 907 per BOE. General and administrative expense for the first quarter were $3 million or 4.66 per BOE. To consider income statement discussion, EBITDA for the first quarter of 2012 grew 42% year-over-year to $48.6 million. Operating cash flow before changes in working capital increased 47% year-over-year to $49.8 million, and net income grew 27% year-over-year to $26.9 million or $0.48 per share based on average diluted shares outstanding of $56.2 million. In terms of capital expenditures, during the first quarter, we spent a total of $48.8 million on 2012 activities, which excludes the Gulfport's portion of Grizzly's activity and Utica leases. Moving onto the balance sheet. We recently completed our spring redetermination, which resulted in our borrowing base being expanded from $125 million to $155 million. In connection with this process, Gulfport is pleased to announce that Deutsche Bank, Credit Suisse and Iberiabank have joined The Bank Nova Scotia, Amegy Bank, Key Bank, Texas Capital Bank as part of our expanded lender group. As of the end of the first quarter, we had $12.9 million in cash and had drawn $10 million on our revolving credit facility. Currently, we have $30 million drawn on a recently expanded facility. At present, we have fixed price swaps in place for 3,000 barrels per day of production work for the remainder of 2012 at a weighted average price of $109.73 before transportation and differentials. Gulfport's 2012 fixed price swaps hedge Brent crude as the underlying index. And those hedges reflect approximately 35% of our estimated production. Looking ahead to the remainder of 2012, as a result of our newly adopted 60-day post completion resting period for our Utica wells, Gulfport currently estimates 2012 production to now be in the range of 2.9 million to 3.1 million BOEs. Second quarter 2012 production is currently estimated to be in the range of 6,900 to 7,100 BOEs per day. 2012 budgeted E&P capital expenditures for 2012, excluding acquisitions, are estimated to be in the range of $206 million to $221 million. In addition, Gulfport plans to spend approximately $30 million to $35 million on infrastructure and vertical integration projects primarily related to its position in the Utica Shale. For 2012, Gulfport currently projects these operating expenses to be in the range of $8 to $9.50 per BOE, general and administrative expense to be between $3.50 or $4.25 per BOE, production taxes to be between 10% to 11% of revenues. And DD&A to be in the range of $32 to $34 per BOE. Given the strength of our balance sheet and the solid foundation provided by our core assets, Gulfport is well positioned to lay the framework to become the most sufficient and lowest cost operator in the Utica Shale. And that's an area that we expect will be the core growth driver for the company going forward. I thank you again for joining us on our call today, and we look forward to answering your questions.

Sean, if you could please open up the phone line for questions from our participants.

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

A couple of questions. First, Jim, on the Utica, just wondering kind of general area that you're in, any estimates if you would break down on your well as far as percent gas, NGLs and oil going forward on that -- in the kind of that general area?

Well, Neal, as you know, we're going to drill 20 wells this year, and we're drilling north to south to east to west. So we don't actually have the data to break it down. We made some estimates, but one thing we did look at, recently Chesapeake's drilled lot more wells than we have. And they have some lines that they're showing. Based on their lines, that puts about 17% of our acreage in the dry gas. It's about 73% in wet gas and about 10% in the oil window. It will define that as we're doing this year's drilling a little bit more closely.

Okay. And then wondering, just -- either for you or Mike, as far as on the guidance. Just a slight change that it was, just wondering is that just because of the shut-ins that you're talking about? Was that now expect to be a bit more than what you initially thought with -- just kind of wondering your thoughts about the additional 100,000 that you've kind of pushed back?

Right. That completely has to do with this resting period that we're talking about in the Utica as we develop that. We initially did not anticipate that, but that's information that we've learned as we've gone forward. So it did certainly has to do completely with that.

Okay. And then 2 more if I could real quick. Just, Mike, on CapEx, wondering your thoughts if you break that out, the terminal business that had you mentioned, is any of that included in CapEx? And then how much is included in CapEx this year for the oil sands or the Niobrara?

Well, it's not -- the $30 million, $35 million is outside of the CapEx band that I mentioned, the $206 million to $221 million, so that's on top of that. And those are vertical integration activities up in Utica mainly. We're just trying to obviously make sure that we have service and sand available to us, so we're trying to eliminate bottlenecks and have quality services. And then back to your other question, Niobrara, we've talked about drilling 5 to 7 wells. So that's going to be anywhere from $5 million to $7 million to us, considering $2 million well cost there. And then Grizzly, we really haven't changed that amount we're going to spend for 2012. It's still going to be in the $40 million to $45 million range.

Okay. And the last question if I could. It looked like to me, at least based on my estimates, most of the miss that was for the quarter was more on just my realized price estimates. I'm just wondering, I guess was that just a recourse of just what was going on in market conditions? I mean, I guess is it fair to say there was nothing as far as capacity constrain or anything like that affected?

No, that's right, Neal. It's been bouncing around a little bit all over the place as you guys know. So first couple of months actually there was as much premium as had been in the past, but it's gone now the other way. And for instance, in March and April, it ranged all the way from $15 to $20 a barrel premium in Southern Louisiana. So it kind of swung back the other way. Not sure what will happen the rest of the year, may not be quite that high, but it's just been bouncing all over the place.

Our next question comes from Ron Mills with Johnson Rice.

Just one more question on the CapEx. You talked about the $30 million to $35 million. Did you -- when you look at your other Utica CapEx, did you already have some infrastructure CapEx included in your Utica for your gathering systems and -- or gathering lines and the like?

Yes, that's a good point, Ron. Yes, we did. We had talked about that before. We had a small amount. $7.5 million is what we talked about for -- and that's mainly for laying pipe so that we can sell that product.

And is that your CapEx or it was that something that eventually will become part of MarkWest or is that just to get your production to their system?

Well, right now, we're just looking at it as part of the well cost. Still working out all those details with MarkWest. But it's -- we consider it part of the well cost right now.

And we did that last December. We made the MarkWest deal since then. But the terminal came along and that was just a great opportunity to really take control of our liquids takeaway, so we jumped on that opportunity.

Okay. And then Jim, you mentioned you're pretty much done with leasing up in the Utica. You have your 125,000 gross acres, is that -- should we take that to mean you're not doing any incremental leasing? Or are you still trying to pick up pieces here and there? I'm just trying to get a sense beyond your CapEx plus the terminal/vertical integration CapEx, how much remaining leasing? I think I had assumed kind of $95 million to $100 million was going to be paid this year. Is that still ballpark figure?

Ron, we're still leasing. We're primarily then what we call bolt-on as we're putting our units together. And of course, it's still expensive up there, it's about $6,000 an acre a lot of times. But we feel fortunate that we still have about a $3,000 per acre weighted average compared to what the price is going forward now. But the volumes are small enough, it's not going to change our weighted average that much. And it's primarily filling the holes where we're putting the units together.

Okay. And looking at the production levels, particularly, you talked about April production averaging 6,700 barrels a day. What do you have potentially coming online towards the end of April or kind of May, June to get that level up? And is your current production still around that April average?

Last couple of days, we've been up quite a bit, Ron. We've been back up to 7,200, 7,300 today. We've given a range for the second quarter of 6.9 to 7.1. So we've got quite a few things coming back on. Keep in mind, we also have the 2 wells that we drilled on the joint acreage in Hackberry late last year, which have not been brought online yet because we're working on the infrastructure. So we've got quite a few things coming online, quite a few nice thick zones that we think will be very helpful. So we feel very good about the second quarter.

And then the last one just on to continue with Hackberry. What drove that production decline in the first quarter? Is it just the typical multi stacked pays where the bottom zone is not always the most productive? And of your 60 planned completions, you only did 11, so a little bit less than what a quarter would've been. Are those the 2 primary contributors? And what's the pace of recompletions to be able to come back at all?

Really, at Hackberry, we believe we were up. But...

You're talking West Cote.

Yes, West Cote. We -- this was a time we had a lot of decent wells, say 40-, 50-barrel wells that have things like holes in the tubing. We have a lot those kind of things come. That takes your completion rigs away from doing recompletions. You fix one of those, you get yourself back into the lower end of a decline curve. If we'd had more recompletions, we would have brought on more new zones with higher IPs. So it's always lumpy from quarter-to-quarter, that's why we give annual guidance, but it's just normal.

Okay. And then you talked about the frac date for the Wagner wells, 60 days. Sixty days seems like a little bit longer than what some people have been talking about. Is that what industry is moving to? And then as you drilled the well in the lateral portion, anything you can talk about in terms of oil shows or just how -- what the information you gathered during the drilling process.

Well, yes, we really did. As we drilled it, we saw wonderful shows. We saw everything and more that we expected to see, and that DFIT Test that we ran was really important. It concluded -- it showed us that what we -- you never know really what the permeability is going to be until you start getting some reservoir test like that, and that said, "Boy, we've got some really good firm." We thought that test -- there are certain things you look for on the signature while you're doing -- you pump into the formation and then you go instantaneous and then you put in a recorder and you watch it. And we thought we'd probably end up watching it for about 1 to 2 weeks for it to go through the normal cycle that it goes through, showing you're getting all the way out to the far reaches of the formation to see what's going on out there. Instead, we were finished in 4 days. And so we were really pleased to be able to see the things we were looking for in such a short amount of time. So that was really exciting. As far as the 2 months goes for the resting period, the 60 days, I would say, Ron, that's going to change as we go along, but for right now, I think that's a pretty good number. We're talking to our peers. What we're finding is that we talk to the people that are in the gas window, and I think over there in the gas window, when we drill wells over there, it might be a 30-day waiting period based on what we hear from our peers. And then we go over to the West side, and that gets a little shallower and oilier and you've got a certain port throat size and has to have to poke those big oil molecules through there. It all relates to the port throats and the effects of the water on those. While over there, it might take 60 to 90 days. But most of our acreage is in the wet gas. Probably 60 days is a good average, and that's going to change. We're going to find some things. There's already some surfactants at the surface that the surface companies are talking about that might make things happen faster. But that's down the road. Right now, we just think there's so much benefit to shut it in for the 60 days and get them strong pressures and strong IPs and better EURs that we're going to -- and we're also lucky that we weren't the first mover in this thing. We've learned a lot from what the other guys have done, and so we really come into this at a time when we -- had we drilled this well in the first place, we would have done it completely different. I think we're a lot better equipped to do it intelligently now.

Next question comes from Tim Rezvan from Sterne Agee.

I had a couple of ones, quick ones. First, when you think about the Permian assets kind of moving away, kind -- what are your thoughts on kind of backfilling those proved reserves? And related to that, how do you think about how many Utica wells you might complete in 2012 to kind of pad those reserve adds?

So you broke up there, your first question was about losing Permian reserves, is that your question?

Yes, I mean that's a big portion that -- the total proved reserves, how do you think about backfilling that heading into the end of the year?

Well, obviously, it does represent a good portion of our reserves. But the Utica wells, as those are drilled and come on, we'll get 100% of those reserves. And so that will certainly help fill that space that's created by those Permian reserves. Of course, we'll still have equity interest in those reserves. So but then also keep in mind, Tim, that we do have barrels of proved reserves in Grizzly as well. They're not booked reserves, but that Algar Lake Project gave us approximately 20 million barrels of proved reserves. But the Utica will be certainly an area that we'll be able to build reserves on, which is another reason why it's going to become a really key important area for us going forward. Not only do we think there's lots of reserves there, but also it's going to help us check that box to be a reserve growth company.

Okay. And then do you have an idea on how many -- I know it's early. You're talking drilling 20, how many of those you might get completed by year end to get credit for those reserves?

Yes, Tim, this is Jim. I would say that we'll have about 10 wells that we'll be producing by the end of the year. With 2 months -- it takes about a month to drill a well, that time to get it frac-ed is more or less another month, and then you've got the 2 months worth of resting. So you can see anything you spud in September. It won't actually start producing until January. So but we've done the numbers on it and figure we'll have 10 wells producing by the end of the year.

And then just one last one. What are your thoughts on NGL differentials through the rest of the year? We've seen things pull back, obviously, clearly in the Permian. Any insight or guidance you can offer for modeling purposes?

They have been all over the place, haven't they? I think Mike's got some numbers here.

It's a good question. They have been bouncing all over the place, Tim. But what we're thinking at this point is that NGL realizations will be in the range of 40% to 45% of WTI, which I think, based on what we've looked at seems to be in kind of in consensus with the rest of the industry as well.

Our next question comes from Brian Velie with Capital One.

Real quick question. Most of mine were answered, but I just wanted to get clarification on one of those last questions. The numbers, as I've got them now, is 20 gross wells drilled in '12 and 10 gross wells producing at the end of the year, correct?

That's right.

Okay. So it's 10 net 5 net producing at the end of the year.

Well, it'll be 5 net producing. That's right.

Okay. Got you. I just want to make sure that was...

You're right.

That's right, Brian.

The next question comes from Leo Mariani with RBC Capital.

Just trying to get a sense of what -- where the drilling cost came out in your first well in the Utica?

Well, in the last call, we've talked about Utica and gave some formulas. They seem to be holding up pretty well. In general, if you have -- of course it has to do with the lateral length and so forth that makes a difference in the cost for a lot of reasons. But I think, if you'll take the lateral length, if it is an 8,000-foot well, figure $1,200 per foot. And if you think -- if it's a 5,000-foot lateral, figure about $1,500 per foot. And of course we're in the science stage. We're having to drill strat tests and we even cored the first well. So there's a couple of extra cost that we're getting early on, but things are simplifying. And those numbers seem to be settling out real well going forward. We're making AFEs as we're looking to the cost we had, send them on to our partners with proposed locations, and everything is coming down in costs. We got there -- we were really fortunate again to be there as things slowed down in the Marcellus. Because a year ago, we really anticipated problems getting rigs and getting frac crews and so forth. And we have had some really competitive bids on our frac job, which is a big part of the deal. And it's a good time to be completing wells up there. So I would say, long range, on that 8,000-foot lateral, look for about $1,000 a foot; on that 5000-foot lateral, look for about $1,200 a foot as we get past this stage where we have to drill strat tests and log it as we get -- we were 6 miles away from the nearest electric log from where we drilled the Wagner so we have to do that. And the same thing has gone on the last 2. But by the end of the year, we'll have other people offsetting this, and we'll have our own offsets, and that's really going to cheapen up those wells.

That's just your drill cost? That include completion as well?

No, that's drilling complete.

Okay. You guys discussed having very favorable, basically, porosity on that well. Can you give us some quantification on that?

Well, we look at the logs. And when we put a cross section up there, we mark everything that's above 8% porosity. And I can just say there's a lot of red to the left of that line on all 3 wells.

Okay. Any plans for you guys in Thailand?

We've got plans but with the government permitting things, it looks like it's going to be early part of next year before we go drill. So that's why Mike was able to take some of that out of the budget.

Yes. We took that CapEx spend that we anticipated out of the budget and pushed that -- and we'll push that until next year.

Okay. And can you quantify that...

I might mention too that there's some -- our guys were just up in Canada looking at the seismic over on the original Phu Horm, has shot some seismic up there, and they're trying to -- they have some processing techniques that appear to maybe even be showing some porosity, which is obviously what we go searching for up there. So we're not just sitting still on it. There's a lot of stuff that's going on, particularly with regard to the quality of the 3-D that are really going help us when we move into the next phase of drilling.

Can you guys quantify the amount of CapEx that was pushed to next year in Thailand?

It's about $6 million.

The next question comes from Steve Berman of Pritchard Capital.

Most of my questions have been answered. Just Mike, a couple of housekeeping things. I think you said what Q1 CapEx is and I just missed it if you did say it.

Okay. Yes, it was $48.8 million that we spent on our 2012 activities.

All right. And you said March, April LLS premiums are about $15 to $20 bucks over WTI. What do you currently see in there?

Well, for May, it's about a $20 premium, Steve. But if you're asking me what I think going forward, it's going to be -- I think if you use somewhere in the $10 to $12.50 range, it's hard to say exactly at this point, but as we mentioned earlier, it has been bouncing around a little bit.

Okay. And then one question on the Permian deal with Diamondback. If that IPO does not happen, do they still have to pay back the $63.6 million promissory? What happens with that in the case of if the IPO doesn't happen?

No, they certainly wouldn't have the obligation to pay that. That's -- that would only happen if the IPO moves forward. So if the IPO doesn't happen, we go back to growing value for our shareholders through the drill bit and a working interest just like we have been.

But you'd still have this note?

No, the note would go away.

It would go away, okay.

Steve, that note is just something that happens during the process of closing the deal. It's only going to be around for a day or 2, and then they pay us that money at closing. So it's just a part of the transaction. It's just a way to do the transaction. But there's never going to be a note that's going to be hanging around after the -- after the occasion if it happens.

Our next question comes from Dave Kistler with Simmons & Company.

Real quickly, on the terminal you're developing on the Ohio River there. Can you talk a little bit about timing of that, size of that? And then, from a size perspective, as you're ramping up production, do you have the capability to run other people's production through there and get the benefit of that marketing?

Dave, you're right, we would be able to run other people's production through there, and that would be a nice thing to be doing. Mike has more details on it.

Yes, for first quarter, Dave, 2013, it's very scalable. Certainly, we could take other people's production. It does a couple of things for us. We can bring our sand down from our mine up in Wisconsin. We can also take our crude and move it down south and get a better price. So there are lots of advantages to having that terminal.

Okay. And on the sand side of things from Wisconsin, what kind of sands are you targeting for your wells right now? Is there a particular type of profit that you want to be using early on? Or is it just -- it's already fit for purpose with what you'd be bringing down?

Well, the sand that we're getting from up there is going to provide everything we need. It actually -- right now, in the window we're in, we'll run 100 mesh, 40/70 and 30/50 on this first frac job because we're about 8,600 feet. And -- so that's about the -- the 30/50 is about the biggest you want to run at that depth because of crush. But we have a really high quality of sand coming down from that, which is important to us because we go over to the oil side, we want to run like 20/40 sand, which we have copious amounts up there. I mean it's both the size and the strength and the crush of that sand that's so important to us. So I might say, too, we've got other sand in Minnesota that just happens -- at Wisconsin is where we opened up the first facility. So it's all high-quality sand. This is Ottawa's white premium type sand. And so it's a really nice thing to have because it's going to be particularly important when we start running those bigger sizes while we're in the oil window.

Okay. And then with respect to just thinking a little bit through your all's guidance and the potential Permian transaction to Diamondback or the contribution of the assets there, can you give us any sense for how that would impact changes to your production guidance should you execute that agreement?

Well, I'm not sure we want to start talking about that yet, because it all depends on the timing of the closing, Dave. Currently, their production is running about 1,000 barrels a day for us. And I'm not sure exactly how long that's going to take their process. So I'd rather not start talking about that yet. Currently, their production represents 14% of our cash flow. And by the time we get to that point, we should be about ready to have some Utica production on. So we'd rather defer those conversations until a little later, if you don't mind.

I think Utica is going to quickly make up for anything that we lose up there.

Our next question comes from Dan Morrison with Global Hunter Securities.

Most have already been answered. But are you in a position yet to talk about the general structure of your arrangement with MarkWest as far as, if not the specifics on numbers, but the pricing mechanism and whatnot?

Pricing mechanism as in our product pricing?

Yes. Are you getting paid just a percent of proceeds? Like a share in -- how much of the liquids...

We pay a fee to have it processed. But we're anchored tenant on this. This is what -- that's one of the nice things about having 125,000 acres up there. It put us in a really powerful position. And we found a really powerful ally in MarkWest to come in there and develop the infrastructure. So they're out there now laying the pipelines and building the facilities. And so it's worked out really well. We will have -- we're not going to talk about the price we're paying, but I can just tell you, because we're the anchor tenant, we have a very attractive price for the processing. We'll still own the liquids that come out of the processing and we still own the residue gas, but they will be involved to some extent with us in moving those to the best prices.

So again, we will retain 100% of the liquids there, so just to make that point.

So it'll just be a straight fee for service?

That's right.

That's right.

The next question comes from Irene Haas with Wunderlich Securities.

Two questions. Firstly, within your wet gas component, you talked about earlier you got some percentage oil, you're probably mostly in wet gas window. So wet gas, how much is ethane? How much is propane? And which direction would the product go? Is it going to go to the Midwest or Gulf Coast or East Coast? Then my second question has to do with the Diamondback deal. If you guys decide to go forward and all that, do you have a lockup period for your ownership of the shares?

Okay. First question, I guess, on the NGLs, I don't know that we...

Until we see some tests on our wells, we won't know. We can only guess what other people are getting. So we really need to get some first-hand information before we can tell you what the components are going to be. Obviously, based on some of the test results that were released, there's going to be a lot of liquids in there. In fact, there was the production numbers that were released by the state around April 1, and there were some pretty nice gas numbers. We particularly like the gas that showed up on the Buell well, which is just north of our acreage. And that -- they reported about 13,000 barrels in the stock tank, which would be oil or condensate, and they had 1.5 BCF. And I think they only started producing around September. So that was a really strong well. And one thing that does not show up because the state doesn't require you to report it is the amount of NGLs in there. There could even be a couple hundred thousand barrels of NGLs to go with that 1.5 BCF. But that's just a guess. That's just our guess but based on what we think might be happening up there. So I'd be guessing if I said what ours are going to be too at this point, Irene. We'll have to just find out. But there's every indication there's going to be a lot of liquids up there.

So Irene, we're working on short term and long-term ethane solutions. On the long term, we're certainly evaluating several options including the ATEX pipeline and developing export projects as well.

Okay. And then the second question is, Diamondback, do you have a lockup period that you agreed to for the shares?

Yes, I believe that's 180 days.

Our next question comes from Jeff Hayden [ph] with ALR Group.

Real quick one for me. Just kind of curious, how much CapEx is sort of left? Or I guess that's not the right way to ask it, but how much do you still have to spend on the Utica acreage that you've currently got signed up to close it?

Jeff, I think we're looking at $35 million to $40 million at this point.

Okay. And when do you expect to have all that paid for?

It will be within the next probably 60 to 90 days.

[Operator Instructions] The next question comes from Ron Mills with Johnson Rice.

Part of it was just asked by Jeff, but in the first quarter how much did you end up spending on the -- how much cash actually went out for Utica leasing?

$35 million.

And beyond that, you have another $35 million or $40 million?

That's right.

Okay. And then the timing -- what's the timing of the $30 million to $35 million of the terminal expenses? Like how should we layer in those cash expenditures?

Ron, it's a good question. So it looks like I would say pretty evenly every quarter. I think we spent about $9 million in the first quarter. I think the rest of it goes pretty evenly throughout the rest of the year.

Okay. And then lastly, just looking at your -- the first 6 wells or so that you have marked on your map, you're obviously -- the 2 wells you're drilling now are more towards the western edge, the next 3 you move more in a little bit east of the Wagner well. What's the -- Jim, you talked about drilling across your whole acreage position. Is the plan still to concentrate more on the wet gas and oil windows this year? Or will you potentially even drill some in the dry gas?

No, Ron, we will potentially drill over in the dry gas but -- where the first well was. And it's basically in line depth-wise with the Buell, that's kind of what's important on it. And like we said, it's about an 8,600-foot deep lateral that as far as TVD goes. Now the wells we're drilling on now, we've got Brushy Fork, which we call the girl well. And it's going to be about a 7,300-foot lateral. So obviously, it should make more liquids. The Boy Scout that we're drilling on, it's going to be about 7,700 feet. And then the next 2 wells will go -- one of those, the first one is in Guernsey County and then the second one in Harrison County. And then the next wells after that will go back to Harrison County, and we'll have one that's about 8,000 feet, a little over 8,000 feet. And then we'll go down to Belmont County, and that one will be about 8,700 feet or about like the Wagner. So the first ones we're drilling are kind of there in the heart of the wet gas, but we do plan to drill north, south, east and west. And we will go over there and drill into the gas window, because we don't know exactly where it is and we want to start gathering some information on that.

So we'll end up drilling a few gas wells, but we're going to try not to drill many.

I'm not showing any other questions in the queue at this time. I'd like to turn it back over for closing comments.

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

Thank you, ladies and gentlemen, and thank you for your participation in today's conference. This does conclude the conference. You may now disconnect. Good day.