Battalion Oil Corp (BATL) 2008 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Quarter Two 2008 RAM Energy, Inc. Earnings Conference Call. My name is Nora and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference.

(OPERATOR INSTRUCTIONS)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's conference, Mr. Bob Phaneuf. Please proceed, sir.

Thanks, Nora, and thank you for joining us today on the RAM Energy conference call to discuss second quarter 2008 financial results and operating results. With us here today is Larry Lee, our CEO, Les Austin, our Senior VP and CFO, Larry Rampey, our Senior VP of Operations, Drake Smiley, our Senior VP of Land and Exploration, Sabrina Gicaletto, our VP and Controller, and I'm Bob Phaneuf.

We have a few prepared remarks today that Larry and Les are going to take you through. The slides to go along with those prepared remarks can be found on our website. And so let me just go through our Safe Harbor dialogue here real quickly and we'll jump into the presentation of prepared remarks.

In our call today, we're going to make statements that are other than historical fact. Information in the presentation and all such statements that refer to management plans or expectations, including the guidance that we have in those slides relating to production costs, CapEx, EBITDA, free cash flow and other industry conditions are forward-looking statements within the meaning of the SEC Act of 1934.

The Company cautions that such forward-looking statements are necessarily based on certain assumptions, which are subject to risks and uncertainties which could cause actual results to differ materially from those indicated today. Further information on these risk factors is included in the Company's filings with the SEC and is enumerated in the beginning of the webcast presentation slides. The management of RAM encourages you to review the disclosure in both these documents. Well, with those prepared remarks, let me turn it over to Larry.

Thank you, Bob, and I want to thank everyone for joining us today on our second quarter highlights. If you'll go to Page 3 on the website, our presentation, I think we feel like we delivered a very solid second quarter. This is our second full quarter after the acquisition of Ascent, which we did late last year, thereby doubling the Company.

And I think we all feel like we're executing pretty nicely on the size the Company is today. Our productions volumes for the second quarter, of course, are 91% above the same quarter last year. We produced 644,000 barrels of oil equivalent in the quarter, which is up a little over 5% sequentially from the first quarter, which was 612,000 barrels of oil equivalent.

Our production gains were really driven in south Texas. We're doing extremely well there. If you look at our developing field as a group, with south Texas it is part of, our sequential production was up 13.1%. Even our mature oil fields, our production was up 4.3% for the second quarter compared to the first quarter and our mature gas fields had a very modest decline from Q1 to Q2 of only 1.1%.

And so the overall production sequential increase was [5.3%]. Of course, prices were significantly higher than they were a year ago. Oil averaged $123.15 for the quarter, natural gas liquids were $60.50, and natural gas, $9.94. So on a BOE equivalent for us, we were up at $89.39, and this is up 69% from the same period a year ago.

If you go to the next slide, kind of our Company overview, the area that we're continuing to operate in, as I've said, south Texas, Barnett Shale, Electra/Burkburnett, Fitts/Allen, and then our plays in the Appalachian Devonian. These are the areas that we continue to focus on and this is where the majority of the production is coming from within the Company.

If you look at Page three, our unconditional resource play, in the Barnett, we had a nice quarter there. We added two new wells on sales, the Etta Burress 3H and [Nawley] 1H in the second quarter. We currently have five wells that are in various stages of testing and will go in production in Q3, and those are the [Dickinson] 2H, 3H, 4H, and 5H wells and the Brown 2H wells. Those wells should all begin to contribute production for us in Q3 and, of course, the Etta Burress and the Nawley, we should get full quarters out of in Q3.

We only got about half a quarter out of the Etta Burress 3H in the second quarter and we got less than a month of the Nawley in the second quarter. So we're continuing to push ahead with our development in the Barnett Shale, continue to work our seismic, our joint shoot with Devon and EOG is signed up and underway, so we continue to look to additional activity for us in the Barnett Shale, during the second half of the year and into '09.

Our West Virginia play, we're very pleased with the results that we've seen so far. We have drilled the first three wells, the C.S. Ball 1H, the R. Mayes 1H, and the M. Jordan 1H. We are currently drilling on the [Sturgeon] 1H and should have that well down in probably another three or four days, then we've already got the next two wells permitted, as well as the subsequent wells to this, and we're moving ahead with the drilling there.

We've been testing various completion techniques out here. The C.S. Ball well, we completed it with pure nitrogen. The Mayes and the Jordan well, we're completing those wells with a nitrogen foam frac.

BJ Services has been helping us in analyzing and designing what we believe to be the proper frac treatments for these wells and so we'll continue to drill and test and complete, and we're expecting that probably early in September or mid September, we should have some additional information that we can share with the market about how the program is going. We continue to be very pleased with the results so far in moving ahead with this plan.

South Texas continues to be a real bright spot for us. We've talked about this is in the past. The Garza Hitchcock 17, which is the most recent well we've completed in South Texas. It came online, I think it was July 18, at 4.4 million a day equivalent and it's by far the best well we've drilled in south Texas so far.

These wells, we do own 100% of and we're getting them drilled and getting them in production and it's proving out what we had hoped to be a bright spot for us for '08 and '09 as we just work our way through the drilling inventory that we have in south Texas.

I would point out that we still have 16 PUD locations in south Texas, 15 probable locations and 45 possible locations. So this is an area that is obviously getting a lot of attention from us, from the geological and geophysical and engineering standpoint, and we continue to be very pleased with how south Texas is performing for us.

If you go to Page eight, our midyear reserves, we historically prepare a midyear reserve report using the same methodology that we do at the end of the year, which is SEC methodology and we had 41.8 million barrels of crude reserves. That compares to 39.4 million barrels at the end of the year. Our PV 10 increased to $1.6 billion using midyear pricing.

If you would reprice that at today's pricing, that PV 10 would be $1.3 billion, so it's still a very, very sizable increase in PV 10. And we did replace 295% of our first half production of 1.3 million barrels with just a little slightly over a $10 cost to create those reserves.

Once again, our portfolio still is very attractive. From a commodity mix, 46% of our crude reserves are oil, 12% are natural gas liquids and 42% of our gas -- our crude reserves are now natural gas; and 65% of our crude reserves are developed, which I think is also indicative of the production volumes that you're seeing in the first quarter and will see, I think, throughout the balance of this year. With that, I'll turn it over to Les to take you through some of the financial highlights.

Thanks a lot. As Larry said, the second quarter was a very strong quarter for us. On Slide nine, we put some highlights there to talk about. For the second quarter, we did $57.6 million in oil and gas sales. This is significantly above last year. It's also sequentially up about 32% versus the first quarter.

Exclusive of the impact of the unrealized derivative losses, the adjusted gross -- the adjusted net income was $14.8 million, or $0.21 a share. Again, compared to last year, last year was $1 million, or about $0.02 per share, and sequentially compared to the first quarter, it was about $3.1 million, or $0.07 a share, in our first quarter.

The free cash flow also up significantly, about $24.8 million, or $0.36 a share, compared to the $0.18 per share that we had in the second quarter of last year and we did about $14.5 million of free cash flow in the first quarter of this year. The EBITDA was up $32 million in the current second quarter. This is up, again, compared to the first quarter of this year, which was about $24 million. That's about a 34% sequential increase. And then, also, the capital spending for the quarter was fully funded from our free cash flow, about $24 million in the quarter.

If you'll turn to Slide ten, you can see what's going on from a debt perspective. We continue to focus on reducing our debt. Our debt-to-cap ratio has gone down from 77% in the first quarter of this year to 57% in the second quarter of the year. Obviously, one of the big drivers was the exercise of the warrant that happened in May but we've also been able to reduce our debt from some of our cash management policies and from the free cash flow.

You can also see on this table the reduction in our interest costs and the reduction in our effective rate. We have had about a 140 basis point reduction in our interest rate from the first quarter of this year to the second quarter of this year, and, year to date, we've seen about a 390 basis point reduction in our interest rate.

If you'll turn to Slide 11, you'll also see that impact on our liquidity. We've given you information at the end of the quarter and also, you can see through July, we've continued to reduce our debt by another $6.3 million from where we were at the end of the second quarter and the liquidity still stands at almost $51 million in July.

We continued to put the next two slides in there. We keep delivering these results and it's almost maddening to look at where we are relative to our peers but you can see the next two slides show the attractive valuation for RAM versus its peers. We've got a price to NAV on Slide 12 and also an EV to crude reserve calculation on Slide 13. Under any major that you look at today, you can tell that stock is significantly undervalued.

On Slide 14, we have tried to articulate the guidance that we put out in the press release yesterday. We are targeting in the second half of the year to continue to see a 2% to 3% sequential growth in our production and we've got that identified and should grow production to 1.281 million to 1.294 million BOE.

The production expenses, we've said, should be about the same, interest expense should reduce. Based on the reduction in our debt, we're projecting about $1.6 million a month for interest expense, which should be around $9.6 million for the second half of the year. EBITDA should grow at the same rate as the production gains in the 2% to 3.5% range, which should put EBITDA at $57 million to $58 million for the second half of the year.

And then, free cash flow is going to be up 15% to 20%, primarily driven by the reduction of the interest cost that we're having to pay. So we should see the free cash flow in the $45 million to $47 million range, which again will more than cover the capital budget that we had originally planned, which is going to be in the $42.6 million range for the balance of the year. With that, I'll just turn it back over to Larry for summary comments.

Well, I do think that our drilling activity is clearly kicking up and improving our growth drivers, as we call them. Our developing fields continue to respond to the drilling that we're doing on them, and our mature fields continue to provide us with a tremendous amount of free cash flow to fund that drilling program.

We still have an opportunity -- a growth opportunity, large inventory. We continue to have this very rich oil and natural gas portfolio of production that we're selling. We continue to control our destiny on an operating standpoint most everywhere. That's important to us and we continue to feel like we've got a compelling valuation and we believe we're demonstrating that we can create value, both with the acquisitions, which we did last year of [percent], and also with the drill bit.

And management continues to own a lot of this Company and we continue to be disappointed at the way the market is valuing us, but what we feel like we have to do is continue to execute, perform, and the stock market will take care of itself in time. With that, Bob, I think, let's open it up for some questions. And --

Nora, we're at the end of our prepared remarks and we'll open it up for Q and A?

Thank you.

(OPERATOR INSTRUCTIONS)

And your first question comes from the line of Neil Dingmann of Dahlman Rose. Please proceed.

Good afternoon, guys.

Hi, Neil.

Hey, guys. Wondering, Larry or Bob, what you guys are seeing right now with activity with Devon and EOG, are you satisfied now with the rate that all that's running at?

Devon continues to exceed the rates we really thought they were going to this year. They have finished drilling with these last four Dickinson wells for the time being. There's indications from them that they'll be coming back toward the end of the year with probably some additional drilling over on the eastern part of that [Rawl] Burress Lease where all this drilling is taking place.

But right now, they've moved just to the west off of our acreage and are drilling next door. We have proposed another well to EOG and I believe that we'll be getting a lot prompter decision-making out of EOG based on preliminary conversations with them, which is very encouraging to us.

Good, good. And then, on Appalachia area, West Virginia, I like how you all are going about it to determine the best frac play. Will there be a certain point where you get enough wells out there and you'll sort of open it up and bring in another rig or is that still a bit off?

Neil, we thought all along that a lot of what the drilling and testing that we were doing this year was still just that, figuring out what's the right way to go about that program with an eye towards adding multiple rigs, assuming that everything works out the way we expect it to, kind of going into '09.

I think one of the things that when we really bust that thing loose, really accelerating it, we'd like to have a little bit better rig equipment than what we've got right now. And we're debating that internally, as to whether that means continuing to contract for rigs or whether we're actually own our own rigs out there, just like we do in [Habit], north Texas.

Okay. If I could just sneak one last one in. Just I like the result, obviously, you saw in south Texas. Is that encouraging enough to become more active there; or given you have all the locations, or what's sort of the plan there?

Well, we very much would like to expand our operating presence in south Texas. We continue to look at opportunities in that area. I think we feel like, and I think we're demonstrating that we've got the technical team to know how to identify what to do down there and the operating team to execute on it. So we feel like that that's an area that we would like to expand on.

And, as I said, we've got a pretty deep inventory right now of PUDs and probables to possible to keep running for a while but, you know, eventually you do run out of locations. So we're looking for additional lease acquisition opportunities or production opportunities in that area.

All right, guys. Look forward to all that activity.

Thanks, Neil.

Okay. Your next question comes from the line of Richard Rossi from Collins Stewart. Please proceed.

Good morning.

Hi, Rich.

How are you doing?

Great.

A couple things. First, you're talking about West Virginia and maybe shifting over to better-quality rigs and/or buying, controlling them on your own. Could you give us some sense of what cost differential that might be in terms of a shift in rigs or adding better rigs, higher-quality rigs, let's put it, and what the capital cost might be to buy your own?

Rich, we're working on that. I would give you the analogy of north Texas, which we have now almost four years of history there. We're currently drilling those wells in north Texas with our own rig at $9 a foot. If we were contracting for that rig, we would be paying $21 a foot.

Now will the gap be that significant between owning our own rig and contracting for rigs in West Virginia? I can't tell you just yet, but that's certainly some of the things that Larry Rampey and the operating team are evaluating and they'll have an answer to that, I think, by the time that we move into early '09.

It clearly has worked for us in north Texas. Our feeling is if you've got a multi-year development program, then it makes sense to consider owning your own rig, having your own people. You can pay them better, you get better results, and it just works wonderfully. But we're not at that point but we may be at that point, going into '09.

Okay. And rig availability up in that area?

It's still pretty tough up there. We're using union drilling and they refabricated one of their old rigs and it's -- we've had to actually have them do a couple of additional modifications to it and we're still working with them on trying to get that rig in the condition that we'd like.

But I'll tell you what the biggest issues that we're seeing really throughout is tubulars are getting to be very tight and just we can get them, but you have to be well in advance of that rig to make sure you've got your tubulars both there, as well as really everywhere right now.

And then, just one final thing. Remind me, do you have a shot at the Marcellus up there?

We've got a thin section of the Marcellus underneath us. We really don't think it is all that prospective but we do have two sections of the Huron. We have both the middle and the upper Heron and Equitable, I believe, has been using dual laterals on some of their Huron wells up there and that's one of the things that we will be evaluating as well.

You know, you talk about valuation. If you just mention the Marcellus, whether you have a shot or not, you'd probably get some multiple points.

Probably so but eventually you've got to report what those things do.

That is the truth. Okay, that's it. Thanks very much.

Thanks, Rich.

And your next question comes from the line of Leo Mariani from RBC. Please proceed.

Hey, guys. Just a follow-up question here on West Virginia. Could you talk a little bit about what you guys are seeing in terms of infrastructure in the area and kind of what your access is to the gas markets, if you guys are able to bring on commercial production from these six wells you're drilling up there?

You know, we've got that polymer plant that we actually had been selling some gas into from those vertical wells that Ascent drilled. Those are early science wells. So we've actually been selling some gas up there and that plant can take up to as much as 9 million a day.

So we've got an intermediate market and we are in the process of getting our taps lined up for the Columbia system so that we'll be able to get into the interstate system as well. And just to remind everybody, the value of that power plant can take the gas stream with a certain amount of nitrogen in it, which helps us be able to get those wells to sale earlier than we otherwise would be able to.

And then, when we do get them cleaned up and they become pipeline quality, we could switch over and go into Columbia. At least, that's our plan and, as I said, we're working with Columbia now to get the two taps in the corn stock area because that's where our initial drilling will take place and then, assuming the play works out the way we think it will, then we'll be working with Columbia for taps up in the [Bug Run] area, probably some time next year.

All right. And what do you think the timetable is on those taps at [Corn Stock]?

Those should be in, I think, this fall. [Shouldn't] they, Larry?

Yes.

I mean, they're underway as far as -- Larry is saying we think we might be able to have those in, in like October/November.

Okay. In terms of your strategy to test your acreage in West Virginia, you talked about a 14 well program, kind of for the 2008 year. Are you basically going to try to test a number of different areas of your acreage here for port activity? Or can you just give us a little more color on the plan?

Well, we're basically trying two areas within the Corn Stock area and we kind of look at that map on the website, where it has the West Virginia acreage. I'll just scroll back up to it. The first wells that we're drilling, first nine, are really around our existing gathering system and where we can deliver into the polymer plant.

Then we're going to jump down into the southern part of Corn Stock and do the drilling later in the year because, at that point, we'll have our nitrogen rejection unit and we'll be tied into Columbia. So that way, we can kind of test a broader area within Corn Stock. And then we're evaluating some opportunities up in Bug Run, which will allow us to hopefully test up there a little earlier than we had originally planned.

That's okay. And can you just remind us of what the EURs are on those wells in south Texas and what it cost you to drill those?

Those wells are costing us between [2.2 BCF] and [2.4 BCF], maybe [2.5 BCF], with the increase in tubulars to drill. We had originally budgeted our estimated EURs at 1.5 BCF and I think we're still sticking with that on EURs until we see a kind of a little longer production run on these. I would think we would be evaluating whether that 1.5 BCF is a little too conservative as we move into the end of the year.

Okay. Thanks, guys.

Thanks, Leo.

And your next question comes from the line of Ron Mills from Johnson Rice. Please proceed.

Afternoon, Larry. Hey. A lot of the operational stuff has been asked. Just a couple of questions on the reserve report. Can you walk through the difference in PV 10 from June to today? If you all looked at reserve adds in terms of volumes, how much of the jump in terms of reserves was related to pricing versus performance and/or (technical difficulty) additions?

Ron, I don't have that. We literally got that hot off the press, Monday night, and I wanted to get that out into the marketplace, the summary. We're looking at that now so I'll be able to give a little more color on that later. Clearly, increased prices, I am sure, added some life extension to our mature oil but I do know that we had quite a bit of adds in the Barnett as a result of the wells we drilled there.

Many of those wells that we've drilled with Devon and the Brown that we drilled were not booked and we have, with the drilling in south Texas, a couple of the probables converted to PUD. So I do know that we've added some reserves there in both south Texas and in Barnett, and I'm sure we've got some extensions in our mature oil fields, but we also have had some adds of new reserves in the Fitts/Allen area, where we kind of did some step outs and it looks like we've been able to extend the aerial extent of some of those fields down there.

Okay. And then, Les --

I did rerun it at essentially $120 oil and it drops it to 1.3 billion feet of PV 10 from 1.6 billion feet.

Right. And then --

From [140] to [120].

Okay. And, Les, for you, just to clarify the guidance, you talked about second half guidance growth of 2% to 3% over the first quarter. The footnote on Slide Number 14 shows that that's before any property sales?

Well, yes, that's what the footnote says. Essentially, what we're saying is if those property sales get done at the very front part of the first part of the year or second part of the year, then that's when you'll see that 2% to 3%. Obviously, if those sales do not happen until the very latter part of the year, then we should see those sequential gains for both those quarters, third and fourth.

Okay. So the footnote should read that the assumption is that you have sold those early in the second half.

That's a more accurate assumption, yes.

Okay. And in terms of the growth, Larry, is the growth coming from the same areas that you expect -- that you benefited from in the first half? Obviously, the Barnett will add here in the third quarter and into the fourth once you have a full quarter impact from all the completions, but is south Texas the other driver up until some time next year when hopefully West Virginia kicks in?

Well I think that south Texas will continue to be the biggest driver and then the Barnett will be probably second. We will be getting some sales volumes out of West Virginia in the second half of this year but that will begin to show up and, surprisingly, to some of us, me, we actually had our mature oil fields up 4.3% sequentially in the second quarter over the first quarter and we may get a little bit of additional sequential growth out of those mature oil fields, which we really weren't counting on. And our mature gas field has continued to hold in there quite nicely with a 1.1% sequential decline. That's pretty flat.

On the -- we have targeted some of our older mature properties that we're going to put on the market. In fact, some of them are already on the market, on the Internet. We had a small sale in the second quarter and we'll have some sales in Q3 and Q4, and we probably will be losing, I'm going to guess, somewhere between 1% and 2% of our existing production as a result of those sales. I think Les has tried to factor that into the guidance numbers.

All right. Thank you, guys.

Thanks, Ron.

And your next question comes from the line of [Barry Sagile] of Gilford Securities. Please proceed.

Hi, gentlemen.

Hi, Barry.

I guess the markets these days are treating us with the adage that no good deed goes unpunished.

Isn't that the truth?

A question -- could you share with us some of your commodity pricing assumptions for your operating and financial forecast for the second half of this year? And do you have an early look into what you might be expecting and budgeting in 2009?

Barry, we have not begun to put together the '09 program. That will be coming up shortly, but we don't really have much to share with you at this point about '09. Our view of the commodities is that the second quarter -- we actually have some numbers that, I think --

We've assumed the average sales price, commodity pricing, for the first six months for the second six months, so that's oil at $109 and NGLs at $57 and natural gas at $8.78. That's the commodity assumptions in the forecast guidance.

Thank you. That's helpful. Also, could you tell us what the sense of your production in PV 10 is self operated?

Barry, I can tell you at the end of the year. I just don't have that number, [630], but there's 94% that was operated at the end of 2007. So my guess is that the percentage is going to be somewhere in that mid to low 90% that we operate. The only area of really any significance that we don't operate is our investment in the Barnett where we're co-investing with Devon and EOG. Outside of that, we really don't have any significant non-operated interest anywhere.

Perhaps I could end up by asking you for some color on what's happening in the acquisition market and, in particular, maybe you could shed some light on what's happening on the mid-continent oil and gas business as a result of bankruptcy of [Simgroup].

Fortunately, knock on wood, we don't have any business relationships with Simgroup so we didn't suffer anything. I do know that some of the smaller producers in and around Oklahoma that sell production to Simgroup have got money tied up in that process. And I don't think it's yet been clarified how that free petition of oil sales is going to get handled and I would expect it would create some concern within the Oklahoma independent producers community.

But fortunately, all of our sales and all of our derivative activities are primarily with Shell. That's our largest single purchaser and so we're a little bit insulated from that, Barry. So I'm not exactly sure how to answer it. I hear a lot of talk about it but I don't have any real hard facts about it.

Have you [actualized] assets, you know, production assets, on the hedges or is this a traditional hedge, where you can have a margin core?

We are doing financial derivatives. We're not really, quote, hedging. And so that's one of the reasons that our counterparty is Shell, because we are able to trade around our physical deliveries that we give them. On any given day, Shell gives us credit for about 50 days worth of oil delivery, which, in the current price environment, is somewhere around $20 million.

Then, in addition to that, we also have a unsecured line with Shell for $10 million. So that's how we (technical difficulty) any collateral issues related to our hedge position. It's been relatively manageable for us. I know it's been a bigger issue for some other operators.

Many thanks.

One just note on that -- the derivatives position turned around to our plus for some $19 million in the month of July. I think we may have mentioned that somewhere last press release, yes.

Certainly worth noting. Thank you, gentlemen.

Thank you, Barry.

And your next question comes from the line of Ross DeMont of Midwood Capital. Please proceed.

Hi, guys. Great quarter. Congratulations.

Thanks, Ross.

Question, on the CapEx budget, I see you've held it at $80 million. I've gotten the sense that there may be kind of sort of bias to the upside of potential for that to move up with Devon running as hard as they were in the Barnett. Is $80 million now the number for the rest of the year or do you think that may move up?

Ross, we're really looking hard at that right now and, at the moment, as we look at our projects and our AFEs, it's a little north of $80 million, but it's not significantly north of it at this point.

Okay.

And so, that's why we're kind of sort of sticking with that until we get a little bit better clarity and decide whether we think we'll bump that up.

Okay. And then just to confirm, I think you said you will get some gas sales out of West Virginia by the end of the year. Up until this point, I don't think your production guidance had assumed anything out of that. Does this 2% to 3% number assume gas sales out of West Virginia?

I don't think we're still projecting any appreciable sales out of West Virginia in those numbers.

So West Virginia would still be sort of upside to those numbers.

Yes.

Okay. And then, can you give me a sense -- my understanding, I guess, you can sort of drill a well in 15 days and then you've got to move the rig and all that, so maybe 20 days all in. So maybe a rig can give you like 17 to 20 wells a year. And I think your presentation says you have something like 500 drilling locations. If you find what you hope to find there and you're successful, will you run, I mean, three, four, five rigs out there? I mean, I guess I'm thinking in order to drill this many reasonable five- to eight-year period of time, you need to run quite a few rigs.

It would definitely be a multi-rig program. How many of those -- fortunately, a lot of our leases out there are fairly long with options. I mean, a lot of them are five with five-year options and, in some cases, we've got eight-year, ten-year leases. But you still would want to accelerate the drilling and we've felt all along that that program works for us, then it would be a multi-rig project for us.

Okay. Fair enough. And last thing, did you get a nitrogen separation unit up there?

It hasn't been delivered yet. We've had it on order. I think it's due in some time around 1st of October, Larry says.

Okay. Very good. Thanks for everything and thanks for taking my questions.

Thanks, Ross.

(OPERATOR INSTRUCTIONS)

Your next question comes from the line of Seth Setrakian of Helios Partners.

Hi, guys. Great quarter.

Thanks.

I guess I'm looking for a little bit of expansion on south Texas. It just seems like the well economics here are pretty impressive. Most of the future locations, it seems -- can you just think we should have growth opportunities between Vicksburg and Wilcox? It just seems like, based on the slide, a lot of it is in Vicksburg, and what is there in Wilcox?

Four of it is in Vicksburg by a fair amount and that's where we've really been having, by far, the best success, is in our Vicksburg play. We're just now actually in the process of drilling and testing, trying to complete our first Wilcox well over there. So that's still yet to come, but most of the locations that we have identified are in our Vicksburg play.

Got it. So all of these [around] Hitchcock, it's all Vicksburg right now.

Yes.

Great. Thank you. Good luck.

Thanks, Seth.

Sir, you have no further questions at this time.

All right. Well, I want to once again thank everyone for joining us. As I said, I think we here at RAM feel like we've got our arms around the Ascent assets. They're performing, we're very pleased with them. We think we're creating value for our shareholders, and we look forward to a good, solid second half and we'll look forward to seeing everyone probably after Labor Day when we make our usual swings through New York. Bob?

You bet. Thank you all for joining us today.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes your presentation and you may now disconnect. Have a great day.