Battalion Oil Corp (BATL) 2013 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Halcon Resources 1Q 2013 earnings conference call. At this time, all participants are in a listen-only mode. Later we will conduct a question and answer session, and instructions will be given at that time. As a reminder, this conference call is being recorded. I would like to turn the conference over to your host, Floyd Williston, Chairman and CEO. You may begin.

Good morning, everyone. 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 barrels of oil equivalent per day of sold, delayed or flared production during the first part of 2013.

We have some additional divestiture plans beyond what we announced this morning, plus we will be fracking 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 at Halcon in East Texas, and we 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 are 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 that -- there to be significant room for additional improvement there. We are approximately two 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 are in the process of transitioning our rig fleet to deliver batch drilling [efficiencies], then 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 are using perf-and-plug on all wells at this time.

We are conducting completion studies field-wide in integrated reservoir (Inaudible) to optimize our completion design and infill spacing. A few other things we are doing up here include down-spacing tests, 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 six million cubic feet a day in Williston Basin due you to gas infrastructure constraints. We expect to [stage] this down throughout the year, with little or no flaring by 2000 -- early 2014.

Moving on to El Halcon -- which is the new East Texas Eagle Ford play -- we recently brought out (Inaudible). We are focused on defining the footprint of the play, which will guide us as we add acreage. El Halcon is a completely separate play from our Woodbine play, a little bit east --east of there or the Eagle Ford acreage in Fayette and Gonzalez Counties, of which we announced the sale today.

We are excited about our opportunities at El Halcon. Well results in -- well results in this play will continue to improve as we optimize drilling and completion techniques, and learn a little more about the geology. We are running three 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 will add 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 drilled in about six days.

We are still in the process of drilling delineation wells in our Utica/Point Pleasant holding, and expect to complete this process this year. As disclosed in the earnings release this morning, we have commenced production testing on the first Utica well, the Phillips 1H. This well began flowback in early April.

The well recently started cutting hydrocarbons, and rates continue to increase while pressure remains stable. We are very encouraged by this. The oil is coming -- that is coming out is 52 degree gravity, and the gas is over 1,300 BTU.

Currently we [have] one well flowing, four wells resting, one well being completed, and two wells being drilled. We will begin flowback operations on three 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 will focus on drilling wells in the Halliday Field in Leon County. We will drill a few other wells in other parts of the Field, but we are 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 -- reduced spud to target depth times by almost 30% during the first quarter. In addition, footage drilled per day increased by nearly a quarter 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 two vertical wells in the play during the first quarter, and expect to spud an additional six 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, is currently flowing back. The well is located in a normally pressured reservoir, and we are planning to install gas lifts during the next week. Hydrocarbons are being produced from the well as the well [cleans] up. [Flowing tubing pressure] is increasing, so all signs are good.

The Smartt 1 is flowing back after frac. Indigo 3-1 is being drilled. These two 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 provided an update on liquidity.

Thanks, Floyd. Before I get started, I will 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 a first quarter we priced and closed [$600 million] of high yield at -- 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 associated with activities in 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 have announced that we will 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 in future periods.

We still expect the full year drilling and completion spending to be $1.2 billion that we previously guided -- 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 just 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 will look to add some revolver borrowing capacity to Halcon field services.

We provided second quarter 2013 production and cost guidance this morning, the 27,000 to 29,000 BOE a day guidance range includes the impact of the recent South Louisiana divestitures, continued flaring (Inaudible) in the Bakken, to a lesser extent in the Woodbine, and production (Inaudible) time in the Bakken Woodbine associated with the transition to the more cost-effective (Inaudible) drilling operations. The impact and fees items will result in a first half 2013 production level that was [below] -- previous expectations, however, we are confident that the production growth will continue through the second half of 2013.

From a cost perspective, we saw operating expense per BOE declined 8% sequentially to [$10.86] per BOE from [$11.75] in the fourth quarter of 2012. Looking ahead, we expect lease operating expense to continue to improve on a per unit basis as we become more efficient, and our production continues to grow.

Taxes of 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 our other regions. We are projecting taxes other than income to be between $7.00 and $8.00 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. We are guiding second quarter G&A to be between $9.00 and $11.00 per BOE and this rate should continue to decline over the remainder of the year.

Finally, just touching on the hedge program, we do 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 flow price of $90.00 a barrel, and for 2014 we have around 17,000 barrels a day hedged with an average floor price of $88.00 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 $4.00.

With that, I will turn it back over to Floyd.

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

Thank you. (Operator Instructions). Our first question is from Brian Corales from Howard Weil. Your line is open.

Guys. On the Utica, can you -- I mean, is the current plan now to test several of the wells before you release them? What is 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 four wells owned by the end of this month, or testing at the end of this month. What can you tell about how wide dispersed those wells are?

Sure, Brian. First off, we don't intend to release results on the (Inaudible) 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 is happening each day as we watch the results on this first well -- It just takes awhile for these wells to clean up after frac job -- so we will release those result 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 will 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 have seen thus far?

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

Okay, and just one question on El Halcon. The results look pretty good there. How widespread -- or what is the aerial extent of that acreage, and do you have possibility of both Eagle Ford and Woodbine, kind of in the Brazos area it?

Generally speaking, we are adding achage every day. It's very specific, as we always try to be, 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 the Woodbine is a big factor over where we are drilling these Eagle Ford wells.

And how -- how -- 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 to the modern frac jobs that we employ as we have done in other parts of the Eagle Ford play. We are still leasing, so we put out a map that kind of generally gives an outline of the area that we are targeting. As always, we try to have concentrated acreage positions and there is other companies in there at this time, very active with rigs and leasing as well since it is new play, so -- I think that is the best we can could to answer that right now.

All right. Thanks, guys.

Our next question is from Ron Mills from Johnson Rice. Your line is open.

Good morning, Floyd. Can you talk a little bit more about what you -- what your commentary on, not the El Halcon, 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 -- what's the timing of getting some results as moving into the core where you expect to encounter the higher hydrocarbon (Inaudible) volumes that you have discussed in recent presentations?

The commentary on the IP you just get kind of a (Expletive) 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 broad pump or whatever you are going to do or jet pumps, to get a good IP rate -- so we are waiting until the first few days is done getting the artificial lift going and then measuring. It is 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 is being covered by this large 3D seismic (Inaudible), which we expect to start getting some feedback on late summer and fall, I think, and the trick down there is there is a massive section of Woodbine sand that is calculated to have lots and lots of oil in it. We need a little more guidance on how to drill down in there and we are -- we hope this 3D will provide that to us. There is some natural fracturing that occurs that can divert some of our frac job and also have some -- allow some other zones to introduce, produce water into the -- after a completion, so we are going to try to use this 3D seismic to steer around those sorts of obstacles.

Okay, and then in the Bakken, you have 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 is -- you have already got and lot of the -- the increased deliverability, or do you still think there is a lot of -- a lot of running room on applying your new -- your new techniques?

Well, we have had basically a quarter under our belts of owning the entire position up there now, and I would be -- it would be silly to think we are at the end of our process of improvements right now. We have only drilled ten or twelve wells using our new -- our different ideas on them so far, so I would expect to see continued improvements and you will 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 is happening with these frac jobs, and which zones you are accessing, and which ones you are not.

We are pretty interested in downspacing test that we are just embarking on right now. We have got a couple of sections we are going to drill wells that are 600 feet apart, and in the (Inaudible) Bakken, and we are very, very interested in how that works out.

Mark, for you, I know you in -- you have referenced roughly 3,300 barrels of -- of production impact versus when you put the original guidance out. Is it safe to assume that -- 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 -- at what you -- what you think about full year guidance now that we have the -- a more clear picture of what the first half looks like?

The way you are thinking about it is correct and that is why we wanted to put that out there, so you would impact the original guidance by the 3,300.

Is there anything in -- 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 have been doing over the past six months which we have reported on.

Right.

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 have got new properties, we have got 25 wells being fracked 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 fill year guidance, we are very confident we will make our numbers at this time.

And then the CapEx of $1.2 billion on the drilling side, I -- I -- if I remember correctly, that excluded what you -- what you had factored in if you had the Eagle Ford the whole time, you would have spent about a couple hundred million bucks. Is -- is that -- 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 -- on, particularly, the infrastructure side, or is that looking like it is more front-end weighted, just trying to get towards a total CapEx?

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

Alright, perfect. Thank you, Floyd.

And this question is from Jason Wangler from Wunderlich Securities. Your line is open.

Good morning, guys. Was just curious as far as with El Halcon and the Woodbine, how long does it take to get to the point where you bring on the rod pump? Is that a 30 to 45 day, or even longer than that?

Actually, the plans would be to bring them on pretty soon. That all involves some, you know, 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 well bore 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 it just won't work on if they have a higher fluid volume. The idea is to get these things on rod pump pretty quick.

Sure, I mean, I guess that kind of dove tails with the production rates that you guys saw on the IP versus (Inaudible) falling off quick is the rod pump maybe assist that. Then the other question I just had in that same region effectively, is with the pad drilling, is that going to be pretty much all of the rigs now that you kind of HBPed and everything and how long before you start to get that full-scale going in terms of easing the lumpiness, would it be this quarter and maybe even next, is it fourth quarter or maybe even 2014 before we start to normalized that?

The -- normalized is a weird word for us, but should be evened out a lot better this year. We are doing everything from pads right now you in both -- at both El Halcon and in our Woodbine. So the only thing in that area that wouldn't be pad drilling would be either stepouts or new tests of new areas. So everything is on pad drilling now, so the lumpiness has already been occurring as we reported, particularly in Halliday, and the lumpiness is going to we throughout in El Halcon. 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.

Perfect. I appreciate it. Thank you.

Our next question is from Jeff Robertson from Barclays. Your line is open.

Floyd, I think you said you are 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 will that increase in the second half, based on the ramping up and 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 is dependent on results here and there. And that is in our projections on capital. So the 25 wells is probably this month, and maybe next month it will be 18 wells and the month after that it will be 28 wells or something. It is just, you know, 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 one 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 -- spud to release date for rigs. So it is a very active frac schedule right now and for the next several months, it will stay very active all year. It will be 25 wells a lot of the months, a few less, a few more some months.

Okay. And are there --

Keep in mind that the Utica wells are the ones that are -- that have this soaking thing, so we expect to have large production volumes coming out after the frac jobs, and ones that are on pads, we drill them all and frac them all before we put any of them on, just for an efficiency situation, and also to size facilities.

In the Utica, are you all experimenting with the soaking period on the wells that you have got drilled so far?

(Expletive), no. We are doing all 60 days.

Okay.

We will 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 are calling it, longer. It may hurt them to do it shorter, nobody quite has that answer, yet. Given facility construction and just normal operations and we take, as always as in our past, we take a very conservative approach to reservoir drawdown. You might remember that pressure maintenance is -- we have always thought one of the big issues in our business with efficient drainage, and we follow that even in the flowback period. We tend to flow these wells back under tightly controlled circumstances so that all of the frac stages have a chance to equalize and all have a chance to start contributing, and we are 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 is a very methodical approach which isn't always market friendly, but that is just what it is for -- in the oil and gas side of our business.

And then with respect to Halcon field services, are there opportunities in the Bakken for -- for you all to use that to try to improve your operations, decrease cycle times, get more control over -- over getting your production out of the basin?

We are 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. It is a very difficult area for these companies to get permits in, and actually do construction in, both the permitting and damages and all that stuff, but then during the mud season, it is pretty hard to lay -- lay these pipelines. We are working through all that. So I don't think there is 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 -- most of Halcon field services activities are focused right now in the Woodbine, the Wilcox and, of course, the Utica/Point Pleasant.

Thank you.

And the Eagle Ford down in Brazos County.

Thanks.

This question is from Neal Dingmann from SunTrust. Your line is open.

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

The cost on all of these early wells are quite high. We are drilling pilot holes in almost every case, we are 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 costs without pad drilling to be at about $8.5 million, and we would expect pad drilling to lower that dramatically from there as much as 10% or 20%. But we are 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 he don't -- we don't have a lot of issues like you have in higher over-pressured reservoirs. These wells are, I won't say routine, but they are 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 monetized in -- I guess a question for you or Mark -- have you all talked about either monetizing up in the Utica or this other area, because it sounds like it could be, or already is, material when you add it up.

It's definitely material. It is also about the only way to get our products into the right markets quickly. It is a little too early to talk about monetizing them. We have been approached by lots of people. We have laid it out, and we are running -- Rich DiMichele, who runs that unit got laid out to where almost all of the wells will go in production within a few days after this soaking period. We might have one or two that have a little more delay than that, but we won't be testing most of these wells and then shutting them in. We will be testing them with the flare stack and all that but then putting them into sales. So, yes, it as substantial expense but it is a necessary expense in that new play.

We have looked at several opportunities out there to join with other pipeline builders who have customers of their own, and we are evaluating everything that we think makes a lot of sense. We do intend to see what we can do to -- since everyone's acreage out there it more scattered than you have seen in some of the other plays -- we do intend to be in pretty aggressive in talking to people about not having each entity trying to lay a duplicate system because that becomes really inefficient over team. So there is a real -- there is a good consolidation opportunity up there more so than some other plays, because a lot of other plays everybody had more blocked up acreage, and here if you notice all of the maps some of -- most the people's acreage are a little bit scattered.

Great color. Thanks, Floyd.

Our next question is from Amir Arif from Stifel. Your line is open.

Thanks. The modified completion techniques you guys are talking about in the last few wells and that shows an impressive improvement in the IP -- can you give us some color if there is 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?

We are not talking specifics about the completion. It is a competitive landscape out there, and there's some other reasons to make sure that we are fully -- have full knowledge about what is 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 -- in -- in two 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 have been. All the way from a few hundred thousand dollars more to maybe $1 million more. But we are getting enough efficiencies with pad drilling and other cost savings, and shorter times from spud to rig release that we are 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.

That makes sense, Floyd. 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 does it hold up relatively good?

We are seeing IP rates that are higher. Decline rates which are slightly less but similar, but you are just at a little higher level overall. If that holds up over more than a few months, that leads to increased EURs -- which we are 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.

Sounds good. And then just on the 3,500 barrels a day conventional assets you are looking to sell, can you give us a sense of what the oil cut on that is?

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

About 75% oil.

75% oil, okay. And then just a final question on the D&C CapEx. This quarter was [400]. Sounds like you are still comfortable with that coming in around the [1.2]. There is enough capital efficiencies that you guys are seeing from the pad drilling to be comfortable with that still the [1.2]?

We are comfortable with that number.

Sounds good. Thanks Floyd.

This question is from Leo Mariani from RBC. Your line is open.

A quick question on the Utica here. You guys talked about I think 52 API condensate in this well. Just trying to get a general sense of what the -- I know it is 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 are -- we are 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 was expected to close and what the production was on that right now?

You know, the production on that for the past quarter averaged about 1,300 barrels a day -- 1,300 barrels a day. It is a little higher today because of recent frac jobs. I think Steve expects to close it in about two months?

Close at the end of June.

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

It will be in our documents, the proceeds are in line with line with expectations internally, certainly.

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

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

All right, I guess. Any update on the Mississippi in play?

What, Mississippi in play?

Okay, I guess that is the update, then.

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

Okay. Thanks a lot.

Our next question is from Mike Kelly from Global Hunter Securities. Your line is open.

Thanks. Good morning. Floyd, in the Utica, I would just love to hear your expectations of exactly how long it is going to take for you to recover this frac fluid and hit the Max IP rate? And I'm curious as to what operators have seen in the southwest portion of the play on this front, and even if that is an appropriate comp to look at there?

Some of the areas that we have drilled we have a very similar rock section as what you see in the south end of the play, so I think you could draw you some parallels, and some other area of the rock section is quite different. Our holding stretch, I don't think it is 100 miles, but they stretch across 50 or 80 miles so we have some differences there. In a general sense, the gassy wells in the entire play seem to come on quickly, less flowback. The oily wells seem to come on more slowly, and more frac flowback. We are 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 have heard that some of the wells are somewhere between 10% and 20% of frac load recovery before they really turn over to their Max IP rate, and some is of the gas wells are much less than that when they turn over to their Max rate. So we expect to see a few you of each kind, but more on the oily side on our property just because of where most of it is located.

Okay. And can you tell us where you are right now in terms of that frac recovery?

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

Understood, thanks.

We have a follow-up from Jeff Robertson from Barclays. Your line is open.

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

It would 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 costs on the conventional that are four or five times as high as the other, you are going to see that that should have a fairly material mathematical effect on the remainder of the properties. It is \going to take some time for Steve to work that stuff up and get it divested of in a workmanlike manner, so we are not actually projecting that in our numbers at this time. As I said, you could -- it is pretty easy math, and I think Mark could give you some what ifs, if you want to talk to him offline.

Okay. The bulk of the 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 two or three states.

Okay.

Again, it is all pretty good stuff. Just not as -- not as good as these new shale wells.

All right. Thank you.

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.

Thanks for joining today, and you will be hearing from us again soon. Thank you.

Ladies and gentlemen, this does conclude today's conference. You may now disconnect. Thank you.