Battalion Oil Corporation (BATL) Q1 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to Halcón Resources 1Q '13 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I'd now like to turn the conference over to your host, Floyd Wilson, Chairman and CEO. You may begin.

Good morning, everyone, and thanks for joining this call today. This conference call contains forward-looking statements intended to be covered by the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. For a detailed description of our disclaimer, see our earnings release issued this morning. We had a solid quarter -- first quarter 2013, with improvements or enhancements on every front. We produced a little over 26,000 barrels of oil equivalent per day. And we are projecting to produce at a rate up to 10% higher for the second quarter, even though we continue to expect to experience nearly 3,500 barrel of oil equivalent per day of sold, delayed or flared production during the first part of 2013. We had some additional divestiture planned to -- beyond what we announced this morning, plus we will be frac-ing up to 25 wells a month for the next few months. We need to absorb some of this activity before we consider additional changes to full year production guidance. In the first quarter of this year, we announced a new play, El Halcón in East Texas, and we have several rigs running there today. And we began flowback from the Utica/Point Pleasant up in Ohio and Pennsylvania. Activity has really accelerated during the past couple of months, and we will frac about 25 wells across our holdings this month. We're currently operating 16 rigs and expect to add several more by year end. The Bakken/Three Forks is one of our anchor plays, and we believe there to be significant room for additional improvement there. We're approximately 2 months into implementing a number of drilling completion modifications designed to improve the overall economics of the wells we are drilling in the Williston Basin. Early results are encouraging to say the least. On the drilling side, we're in the process of transitioning a rig fleet to deliver batch drilling efficiencies and optimizing the motor bit configuration, drilling with back pressure to improve penetration in the curve and lateral section, and using dedicated spud rigs to preset surface casing. On the completion side, which is the primary driver for the early-stage improvements we are witnessing in the Williston Basin, we are testing several different methods. In Fort Berthold area, we have increased the amount of profit per stage, increased stage density, changed the fluid design, and we're using perf and plug on all wells at this time. We're conducting completion studies field-wide and integrated reservoir modeling to optimize our completion design and infill spacing. A few other things we're doing up here include down-spacing test, using tracers to provide a qualitative understanding of interference and connectivity, and researching and comparing different ceramic products that have become available lately. As referenced in the earnings release, we continue to flare approximately 6 million cubic feet a day in the Williston Basin due to gas infrastructure constraints. We expect to stage this down throughout the year with little or no flaring by early 2014. Moving on to El Halcón, which is the new East Texas Eagle Ford play we recently brought out as the fourth core area. We are focused on defining the footprint of the play, which will guide us as we add acreage. El Halcón is a completely separate play from our Woodbine play, a little bit east of there, or the Eagle Ford acreage in Fayette and Gonzales counties, of which we announced the sale today. We are excited about our opportunities at El Halcón. Well results in this play will continue to improve as we optimize drilling and completion techniques and learn a little bit more about the geology. We're running 3 rigs there now. Our most recently drilled well, the Bumble Bee 1H in Brazos County, was drilled in 25 days, spud to rig release, and included a pilot hole. This well had an effective lateral length of just under 9,000 feet, which is much longer than prior wells. The curve was drilled in 24 hours and the lateral was drilled in about 6 days. We are still in the process of drilling delineation wells in our Utica/Point Pleasant holdings, and we expect to complete this process this year. As disclosed in the earnings release this morning, we have commenced production testing on our first Utica well, the Phillips 1H. This well began flowback in early April. The well recently started cutting hydrocarbons and rates continued to increase while pressure remained stable. We're very encouraged by this. The oil is coming -- that's coming out is 52-degree gravity, and the gas is over 1,300 BTU. Currently, we have 1 well flowing, 4 wells resting, 1 well being completed and 2 wells being drilled. We'll begin flowback operations on 3 additional wells this month up in Ohio and Pennsylvania. Based on extensive technical work and recent well data, we expect our Woodbine results to continue to improve. We'll focus on drilling wells in the Halliday Field in Leon County. And we'll drill a few other wells in other parts of the field but we're waiting on a large 3D seismic survey, which we hope to receive this fall before we really kick off a lot of drilling south of Halliday. Generally on the drilling side, we significantly increased spud to target depth times by the -- reduced spud to target depth time -- to target depth times by almost 30% during the first quarter. In addition, footage drilled per day increased by nearly 1/4 for wells spud between January and March. Based on drilling results and 3D seismic, we recently decided to dedicate more resources to our Wilcox play in Louisiana. We spud 2 vertical wells in the play during the first quarter and expect to spud an additional 6 vertical Wilcox wells throughout the balance of the year. We are currently evaluating the potential to drill horizontal wells on our acreage. The Smartt #1 was completed in April and is currently flowing back. The well is located in a normally pressured reservoir, and we are planning to install gas lift during the next week. Hydrocarbon are being produced from the well as the well cleans up. Only tubing pressure is increasing, so all signs are good. The Stump #1 is slowing back after frac, Indigo 3-1 is being drilled. These 2 wells are located near our successful Columbia Land & Timber 9-1 well. Mark Mize will now give you some stats on first quarter financial results and provide an update on liquidity.

Okay. Thanks, Floyd. Before I get started, I'll just point out that the first quarter results of operation does represent the first period where we had a full contribution from the Williston Basin asset, acquisition that closed in December of last year. And as a reminder, the first stock issued to Petro-Hunt to partially finance that deal did convert to just under 109 million shares of common stock in mid-January. From a financing perspective, during the first quarter, we priced and closed $600 million of high-yield add-on offering to our 8.875% senior unsecured notes due in 2021 in a private offering, that did price at 105 to yield 7 7/8. The proceeds from the offering were used to repay the outstanding indebtedness that we had on the senior secured revolving credit facility, as well as to fund a portion of the 2013 capital program. We spent approximately $400 million on drilling and completion CapEx in the quarter, 70% of that was associated with activities on our core Bakken, Woodbine, Eagle Ford and Utica areas in drilling. And approximately 20% of the first quarter drilling and completion spending was associated with Eagle Ford assets, which we've announced that we're going to be divesting of. And we had also a portion in our conventional properties with some dollars spent to collect science on wells, which, at some point here, would not be continued to be recurring at future periods. We still expect the full year drilling and completion spending to be $1.2 billion that we previously guided to. And we also spent about $150 million on leasehold, seismic and infrastructure in the current quarter. With regards to liquidity, we ended the quarter with right at $720 million of liquidity. Consisting of available borrowing capacity on our credit line, which we did recently reaffirm with our lending group, the available borrowing base of $850 million on the $1.5 billion facility. As we continue to build out the midstream infrastructure and grow the EBITDA of that business, we'll look to add some revolver borrowing capacity to Halcón Field Services. We provided second quarter 2013 production and cost guidance this morning. The 27,000 to 29,000 BOE a day production guidance range includes the impact of the recent South Louisiana divestitures, continued flaring of gas in the Bakken, to a lesser extent in the Woodbine, and production shut-in time in the Bakken and Woodbine associated with the transition to the more cost effective pad drilling operations. The impact of these items will result in a first-half 2013 production level that was below previous expectations. However, we're confident that the production growth will continue through the second half of 2013. From a cost perspective, lease operating expense per BOE declined 8% sequentially to $10.86 per BOE from $11.75 in the fourth quarter of '12. Looking ahead, we expect lease operating expense to continue to improve on a per-unit basis, as we become more efficient our production continues to grow. Taxes other than income were $7.44 per BOE for the first quarter, which was up from $5.69 per BOE in the fourth quarter of 2012. The increase reflects the growing contribution of oil production from the Bakken/Three Forks properties in North Dakota where production taxes are higher than some of the other regions. We're projecting taxes other than income to be between $7 and $8 per BOE for the second quarter. First quarter G&A expense of $11.72 per BOE was higher than anticipated, primarily due to increased professional fees related to A&D and integration efforts here at the company as we continue to build it. And we are guiding second quarter G&A to be between $9 and $11 per BOE, and this rate should continue to decline over the remainder of the year. Finally, just touching on the hedge program. We do to continue to target a hedge portfolio, which 80% of the expected production is hedged for the next 18 to 24 months. We will look to add hedges, and we have layered in some gas hedge contracts over the past few months. As we sit here today, we have nearly 24,000 barrels per day of oil hedged in 2013 at an average floor price of $90 a barrel. And for 2014, we have around 17,000 barrels per day hedged with the average floor price of $88 a barrel. On the gas side, we currently have right at 20 MMBtu a day hedged in 2013, at around $3.80, and we have 35 MMBtu hedged in 2014 at a floor of just under $4. And with that, I'll turn it back over to Floyd.

Thanks, Mark. Part of our strategy as we build this company is to manage our portfolio by selling non-core assets as we increase production from our core areas. So beyond this Fayette and Gonzales sale that we announced today, we expect to divest an additional 4,500 barrels of equivalent per day of conventional production by the end of this year or early next. Operator, with all that, we're ready for questions.

[Operator Instructions] Our first question is from Brian Corales from Howard Weil.

Guys, on the Utica, can you maybe -- is the current plan now to test several of the wells before you release them? What's kind of the thought process from that standpoint? And could you also maybe talk about how much of the acreage is being tested over these? I think you have 4 wells on by the end of this month with -- or testing at the end of this month. Can you tell about how wide dispersed those wells are?

Sure, Brian. First off, we don't intend to release results on any of the wells until they basically turn over, as we say, which means that the frac water production declines dramatically and the gas and oil production inclines dramatically. That's happening each day as we watch the results on this first well. It just takes a while for these wells to clean up after frac jobs. So we'll release those results as soon as we have them. We drilled wells all the way from the south end of our holdings to our north end, so we've delineated the entire package already. Our flowbacks are happening in both ends of the play and the middle. So you'll see a representative testing of our entire acreage position through the course of this next few months.

And have you seen anything that gets you -- that is discouraging or encouraging based on logs or what you've seen thus far?

We've got some of the best log results and core results that we've experienced in the entire play on a couple of wells that we're just getting ready to frac. This flowback is awesome that's going on in Phillips well, so we're extremely encouraged about everything up there.

Okay. Just one question on El Halcón. Results are pretty good there. How widespread -- or how -- what's the aerial extent of that acreage? And do you have possibility of both Eagle Ford and Woodbine kind of in that Brazos area?

Generally speaking, we're adding acreage every day. It's very specific, as we always try to be, with -- based on the research that our exploration group has done in advance of buying acreage. The Woodbine, generally, is pretty thin as you travel west of Madison County and almost gone in most places. And it thickens dramatically as you head east from Brazos County, so we don't particularly think that Woodbine is a big factor over where we're drilling these Eagle Ford wells.

And how big do you think this play could be?

An add-on to what I was just saying, the good news about the Eagle Ford, it's a traditional shale, widespread over a fairly large area with consistent thickness, and it looks so far to be fairly consistent quality. So very susceptible for the modern frac jobs that we employ as we've done in other parts of the Eagle Ford play. We're still leasing so we put out a map that kind of generally gives an outline of the area that we're targeting. As always, we try to have concentrated acreage positions. And there's other companies in there at this time, very active with rigs and leasing as well, since it's a new play. So I think that's the best we could do to answer that right now.

Our next question is from Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Floyd, can you talk a little bit more about what you -- your commentary on, not the El Halcón, but the Woodbine and being low energy? Is that also up in the Halliday Field as you decide to move or as you begin to move into the core? And just from a timing standpoint, what's the timing of getting some results as moving into the core where you expect to encounter the higher hydrocarbon pore volumes that you've discussed in recent presentations?

Well, the commentary on the IP, you just get kind of a bulls*** IP thing if you look at the first couple of days because these wells tend to load up quickly. And you need to install gas lift or rod pump or whatever you're going to do or jet pump so -- to get a good 30-day IP rate. So we're waiting until those first few days is done, getting that artificial lift going and then measuring. It's just a method of making the -- particularly internally, making the results more definitive as we move forward in there. The core of the play, as you mentioned it is what's being covered by this large 3D seismic view, which we expect to start getting some feedback on late summer and fall, I think. And the trick down there is there's a massive section of Woodbine sand that's calculated to have lots and lots of oil in it. We need a little more guidance on how to drill down in there. We're going to -- we hope this 3D will provide that to us. There's some natural fracturing that occurs that can divert some of your frac job and also have some -- allow some other zone to introduce -- produce water into the -- after a completion. So we're going to try to use this 3D seismic to steer around those sorts of obstacles. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then in the Bakken, you've seen some pretty good early results from changing some of the drilling and completion methods. Where do you think you are in that learning process as you continue to drill more up there? Do you think there's -- you've already gotten a lot of the increased deliverability. Or do you still think there's a lot of running room on applying your new techniques?

Well, we've had basically a quarter under our belts of owning the entire position up there now. And I would be -- it'd be silly to think that we're at the end of our process of improvements right now. We've only drilled 10 or 12 wells using our new -- our different ideas on them so far. So I would expect to see continued improvements. And you'll see that across the basin by all these operators as they get away from single-well drilling and into the more efficient pad drilling and have more time to really think about how the -- what's happening with these frac jobs and which zones you're accessing and which ones you're not. We're pretty interested in this down-spacing test that we're just embarking on right now. We've got a couple of sections, we're going to drill wells that are 600 feet apart in the middle Bakken. And we're very, very interested in seeing how that works out. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Perfect. And then Mark, for you. I know you've just referenced the roughly 3,300 barrels of production impact versus when you put the original guidance out. Is it safe to assume that the original guidance, both the top end and low end, should be reduced by that amount, in terms of your 40 to 45 down in the 36.5 to 41.5? Or how should we look at what you think about full year guidance, now that we have a more clear picture of what the first half looks like?

The way you're thinking about it is correct and that's what why we wanted to put that out there so would you would impact the original published guidance by the 3,300. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And is there anything in -- are there any allowances at all for any of -- whether it be the Eagle Ford or the conventional asset sales, in that? Or will those sales also effectively reduce that further once you get those proceeds in?

Ron, the only impact has been the miscellaneous smaller-scale sales we've been doing over the past 6 months, which we've reported on. So future divestitures are not included in these numbers. As -- again, as I mentioned a few minutes ago, we have so much activity going on. We've got new properties. We've got 25 wells being frac-ed this month and next. Divestitures going on. We just need to get a little bit more of this under our belt before we think about additional changes to full year guidance. We're very confident we'll make our numbers at this time. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then the CapEx of $1.2 billion on the drilling side, if I remember correctly, that excluded what you had factored in, if you had the Eagle Ford the whole time you would have spent about a couple of hundred million bucks. Is that correct? And then on the infrastructure/leasing you spent plus or minus $150 million here in the first quarter. Is that a pretty good run rate on the -- particularly the infrastructure side? Or is that looking like it's more front-end weighted? Just trying to get towards a total CapEx.

Well, again, we're not projecting CapEx or infrastructure. That is definitely front-end weighted based on our own expectations this year, which we've told people, of about a couple of hundred million dollars for the year. First part of your question, basically, we've migrated CapEx from the Woodbine area since our leases are largely HBP'd in Halliday Field and we're waiting on seismic in the central part of the play. We migrated CapEx from there to -- and rigs, from there to El Halcón. So net-net, no real change in CapEx guidance for the overall region. We've just switched over to drilling more of these great Eagle Ford wells.

Our next question is from Jason Wangler from Wunderlich Securities.

I was just curious, as far as with El Halcón and Woodbine, how long does it take to get to the point where you bring on the rod pump? Is that a 30-, 45-day? Or is it even longer than that?

Actually, the plan would be to bring them on pretty soon. That all involves some dealings with electric co-ops and whatnot. So you need artificial lift quickly on those kind of wells. When we say low energy, we just mean that they produce enough fluid into the wellbore that it can't lift itself after a week or a month or whatever. So you might as well get those things on artificial lift quickly. Gas lift will work for a few months up to a year on some of these wells and some of them just won't work on it if they have a higher fluid volume. So the idea is to basically get these things on rod pump pretty quick.

Sure. And I mean, I guess that kind of dovetails with the production rates that you guys saw on the IP versus maybe they've fallen off quick. Is the rod pump maybe assist that? And then just the other question I just had in that same region effectively, is with the pad drilling. Is that going to be pretty much all the rigs now that you're kind of HBP and everything? And then how long do you think before you kind of start to get that full scale going in terms of easing the lumpiness, I guess. Would it be, obviously, this quarter and maybe even next, or is it fourth quarter? Is it more even '14 before we kind of start to normalize that?

Could be -- normalize is a weird word for us but it should be evened out a lot better this year. We're doing everything from pads right now in both -- at both El Halcón and in our Woodbine. So the only thing in that area that wouldn't be pad drilling would be either step-outs or new -- tested new areas. So everything's on pad drilling now. So the lumpiness has already been occurring as we reported, particularly in Halliday, and the lumpiness is going to be a few out in El Halcón. But if everything is going on pad drilling, that lumpiness, as you say, would tend to work itself out since everything is on pad drilling.

Our next question is from Jeff Robertson from Barclays.

Floyd, I think you said you're going to complete or frac 25 wells this month and next. Is that pace what is anticipated to continue over the balance of the year? Or would that increase in the second half based on the ramping up in the rig count?

Well, our rig count is not really ramping right now. We intend to add a few rigs towards the end of the third quarter and that's dependent on results here and there. And that's in our projections on capital. So the 25 wells is probably this month, and maybe next month it'll be 18 wells. A month after that it'll be 28 wells or something. It's just these wells -- these rigs are all getting these wells drilled more quickly over time and that has a huge impact when you look at months and months of work compared to just 1 month. So you end up having more wells to frac in the second half of the year than you would have planned on in the first half because of reductions in spud to release date for rigs. So it's a very active frac schedule right now. And for the next several months. It'll stay very active all year. It'll be 25 wells a lot of the months, a few less a few more some months. Keep in mind that the Utica wells are the ones that are -- have the soaking thing, so we expect to have large production volumes come out after these frac jobs. And the ones that are on pads, we drill them all and we frac them all before we put any of them on just for an efficiency situation and also to size facilities.

And in the Utica, are you all experimenting with the soaking period on the wells that you've got drilled so far?

S***, no. We're doing all 60 days. We'll experiment later. We just want to get that unit flowing and have the oil and gas getting into the marketing situation before we start thinking about that. We have determined to our satisfaction that it doesn't hurt your wells for them to stay soaking, as we're calling it, longer. It may hurt them to do it shorter, nobody quite has that answer yet. So given facility construction and just the normal operations -- and we take, as always, and as in our past, we take a very conservative approach to reservoir drawdown. You might remember that pressure maintenance is, we've always thought one of the big issues in our business with efficient drainage, and we follow that even in this flowback period. We tend to flow these wells back under tightly controlled circumstances so that all the frac stages have a chance to equalize and all have a chance to start contributing. And we're running tracers on most of our wells so we actually know which stages contribute early and we check it every week or so and we know which stages contribute later. So it's a very methodical approach which isn't always market friendly, but that's just what it is for the oil and gas side of our business.

Then with respect to Halcón Field Services, are there opportunities in the Bakken for you all to use that to try to improve your operations, decrease cycle times, get more control over getting your production out of the basin?

We're looking at trying to use that, but generally speaking, our predecessors had arrangements with good companies, but the immense production increases in the Williston Basin in general have overrun, in particular the gas takeaway capacity. And it's a very difficult area for these companies to get permits in and to actually do construction in. Both just the permitting and the damages and all that stuff, but then during the mud season it's pretty hard to lay these pipelines. So we're working through all that. So I don't think there's a huge opportunity for HFS to help up there. We are looking at them installing some water systems that aren't in place just yet, but most of the Halcón Field Services activities are focused right now in the Woodbine, the Wilcox and of course, the Utica/Point Pleasant and the Eagle Ford down in Brazos and Burlington County.

And the next question is from Neal Dingmann from SunTrust.

Floyd, just a question up on the Utica. I was wondering what are your costs now running on those wells? And how are you completing them as far as lateral length and frac stages?

The cost on all these early wells are quite high. We're drilling pilot holes in almost every case. We're doing a lot of extra work. Some people call it science, we just call it our business. The costs are running a good $10 million on these wells, but we expect our cost without pad drilling to be at about $8.5 million. And we'd expect pad drilling to lower that dramatically from there as much as 10% or 20%. But we're just not quite there yet in that play. So these early-stage wells are a little more expensive than you would expect overall. The great news up here is, we don't really have that much trouble drilling these wells. There's not a lot of obstacles. We don't have a lot of issues like you have in higher overpressured reservoirs. These wells are, I won't say routine, but they're going along real well in the drilling phase.

Okay. And then just lastly. You mentioned earlier just on this previous question as far as midstream and infrastructure. How much now do you have built up, I guess I'm wondering, in the Utica and these other areas and would you perceive monetizing? I guess a question for you or Mark. Have you all talked about either monetizing up in the Utica or all this other area because it sounds like it could be, or already is, pretty material when you add it all up?

It's definitely material. It's also about the only way to get our products into the right markets quickly. It's a little too early to talk about monetizing them. We've been approached by lots of people. We've laid it out and we're running -- Rich DiMichele, who runs that unit, we've got it laid out to where almost all of our wells will go in production within a few days after this soaking period. So they might have 1 or 2 that have a little more delay than that, but we won't be testing most of these wells and then shutting them in. We'll be testing them with a flare stack and all that but then putting them into sales. So yes, it is a substantial expense, but it's a necessary expense in that new play. We've looked at several opportunities out there to join with other pipeline builders who have customers of their own, and we're evaluating everything that we think makes a lot of sense. We do intend to see what we can do, too, since everyone's acreage out there is more scattered than you've seen in some of the other plays. We do intend to be pretty aggressive in talking to people about not having each entity trying to lay a duplicate system because that becomes really inefficient over time. So there's a real -- there's a good consolidation opportunity up there, more so than some other plays, because in a lot of other plays everybody had more blocked-up acreage. And here, if you noticed all the maps, some of the -- most people's acreage are a little bit scattered.

Our next question is from Amir Arif from Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: The modified completion techniques you guys are talking about in your last few wells and that showed a very impressive improvement in the IP, can you just give us some color if there's a difference in the completion costs and how the curve on those wells is relative to the previous wells that you drilled using the other completion?

Yes, we're not talking the specifics about the completion. It's a competitive landscape out there, and there's some other reasons to make sure that we're fully -- have full knowledge about what's going on. So the early-stage results, and this is wells anywhere from a few weeks to a few months, are dramatically improved all the way from 40% higher to 90% higher and in 2 distinct areas of the field that the modifications are very different from each other. These frac jobs are all more expensive than the prior run rate of frac jobs would've been, all the way from a few hundred thousand dollars more to maybe $1 million more. But we're getting enough efficiencies with pad drilling and other cost savings and shorter times from spud to rig release that we're not, overall, experiencing increases in net costs from what we would have thought a few months ago, if that makes any sense. So the frac jobs are higher, many of the other components are lower. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: That makes sense, Floyd. But for the wells that have been on for a few months, how is that decline curve relative to the other ones? Does the IP come in faster? Or is it up [ph] relatively good?

We're seeing IP rates that are higher, decline rates which are slightly less but similar but you're just at a little higher level overall. Now if that holds up over more than a few months, that leads to increased EURs, which we're not prepared to get public about all that yet. But at the very least, the higher IP rates that hold up, that leads to certainly increased IRRs. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. Sounds good. And then just on the 3,500 barrels a day conventional assets you're looking to sell, can you give us a sense of what the oil cut on that is?

That's about 4,500 barrels a day. We don't know if it would be 1 group or 2 groups. I think -- Steve's sitting here. What is it, Steve?

About 75% oil. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: 75% oil? Okay. And then just a final question on the DMC CapEx. So this quarter, it was $400 million. It sounds like you're still comfortable with that coming in around the $1.2 billion. So there's enough capital efficiencies that you guys are seeing from the pad drilling and other stuff to be comfortable with that number still, the $1.2 billion?

We're comfortable with that number.

Our next question is from Leo Mariani from RBC.

Just a quick question on the Utica here. You guys talked about, I think, 52 API condensate in this well. I'm just trying to get a general sense of what the -- I know it's early days, but what is the condensate cut relative to the total hydrocarbons here?

We haven't put that out, Leo. These are fairly early-stage results. We're flowing oil and condensate and natural gas at nice rates.

Okay. And I guess the Eagle Ford, it sounds like you guys inked a deal to sell the South Texas piece of that. Wanted to get a sense of when that is expected to close and what the production was on that right now.

The production on that for the past quarter averaged about 1,300 barrels a day? 1,300 barrels a day. It's a little higher today because of recent frac jobs. I think Steve expects to close it in about 2 months.

Yes, close it at the end of June.

Okay. That's helpful. And I guess you guys didn't disclose proceeds on that. Is that something you guys plan to do once it closes?

It'll be in our documents. The proceeds are in line with expectations internally, certainly.

Okay. And I guess on the conventional asset sales, 4,500 barrels a day, is that kind of the bulk of your conventional properties? Are you basically getting out of that business at this point?

Well, at this point means sometime over several quarters, but yes. It's been our plan all along to -- as we grow the production from our shales and our core programs to divest of those properties. They're very good properties. The profile is high operating cost on those kind of properties, they're mature, a couple of big water floods included, which have low oil cuts but they're still very profitable. But our production growth is sufficient enough now from our other activities to look forward to selling those properties and making good money from it and plowing those proceeds back into the -- our core areas.

All right. I guess, any update on the Mississippian play?

What Mississippian play?

Okay. I guess that's the update then.

No, we've drilled our 5 wells. We might drill a few more. I think I've told you before, we had one good well, a couple of stinkers and a couple of okay wells, high water cuts, nothing for us to be all excited about. There's some results in the area from other operators that are sort of a mixed bag as well, which we're just not -- it's not one of our focus areas. We're certainly not sitting on some kind of a hotspot or great area like some of these companies seem to be on. So we've done okay there, but it's not anything we'll be focusing on by any means.

Our next question is from Mike Kelly from Global Hunter Securities.

Floyd, in the Utica, I just wanted to hear your expectations of exactly how long it's going to take for you to recover this frac fluid and hit the max IP rate. And I'm curious as to what operators are seeing in the southwest portion of the play on this front and even if that's an appropriate comp to look at there.

Some of the areas that we've drilled, we have a very similar rock section is what you see in the south end of the play, so I think you could draw some parallels. In some other areas, the rock section is quite different. Our holding stretch, I don't think it's 100 miles but they stretch across 50 or 80 miles, so we have some differences there. In the general sense, the gassy wells in the entire play seem to come on really quickly, less flowback. The oily wells seem to come on more slowly and more frac flowback. We're seeing that in our first flowback, that this well has been growing in production almost every day since we started and growing in pressure. As the pressure increases, we step up the choke size and wait for the pressure to stabilize again and then we raise the choke size again. Anecdotally, we've heard that some of the wells are somewhere between 10% and 20% of frac load recovery before they really turn over to their kind of a max IP rate. And some of the gas wells are much less than that when they turn over to their max rate. So we expect to see a few of each kind but more on the oily side on our property just because of where most of it's located.

Okay. Can you tell us where you are right now as far as that frac recovery?

Well, no, we're -- if you think about it, the Phillips well is an outpost in this entire play. We have -- basically everybody in the industry up there is watching the well and we're very particular about who we give that information to right now. We'll make a full report on it as soon as it's producing in its full and kind of final state and that shouldn't be very long from now. But we tend to want to not report any halfway remarks about it.

We have a follow-up from Jeff Robertson from Barclays.

Floyd, you referenced the lifting cost on the properties you all are -- have earmarked to sell on the conventional side. Can you talk about what impact that may have on overall LOEs once you get those sold?

It'd be fairly linear. If you have a 26,000 barrel a day here in the first quarter and you have around 4,000 or 5,000 barrels a day coming out of conventional and you have lifting cost on the conventional that are 4x or 5x as high as the other, you're going to see that, that should have a fairly material mathematical effect on that remainder of the properties. It's going to take some time for Steve to work that stuff up and get it divested of in a workman-like manner so we're not actually projecting that in our numbers at this time. As I said, you could -- it's pretty easy math and I think Mark could you some what ifs if you want to talk to him offline.

Okay. The bulk of those properties, are they the water floods you all have up in North Texas?

About half of it and about half of it some other fields that are scattered around 2 or 3 states. Again, it's all pretty good stuff, it's just not as good as these new shale wells.

Thank you. We have no more questions in queue. I would now like to turn the call over to Floyd Wilson, Chairman and CEO, for closing remarks.

Well, thanks for joining today, and you'll be hearing from us again soon. Thank you.