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Clayton Williams Energy, Inc. (NYSE:CWEI)

Q2 2012 Earnings Call

July 26, 2012 2:30 PM ET

Executives

Patti Hollums – Director, IR

Mel Riggs – EVP and COO

Michael Pollard – SVP- Finance, Treasurer and CFO

Clayton Williams – Chairman, President and CEO

Greg Welborn – VP, Land

John Kennedy – Manager, Drilling

Analysts

Welles Fitzpatrick – Johnson Rice

Neal Dingmann – SunTrust Robinson Humphrey

Irene Haas – Wunderlich

Andrew Coleman – Raymond James

Mike Kelly – Global Hunter

Sean Sneeden – Oppenheimer

Irene Hass – Wunderlich

Ravi Kamath – Global Hunter

Operator

Good day, ladies and gentlemen, and welcome to the Clayton Williams Energy Incorporated Second Quarter 2012 Results 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. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to introduce our host for today, Ms. Patti Hollums, Director of Investor Relations. Ma’am, please go ahead.

Patti Hollums

Thank you. Good afternoon and thank you for joining the Clayton Williams Energy Second Quarter 2012 Results Conference Call. Participating on our call today is Clayton Williams, President and CEO; Mel Riggs, Executive Vice President and COO; Mike Pollard, Senior Vice President and CFO, and Ron Gasser, our Engineering Manager.

This call will be recorded and will be available for replay on our website at claytonwilliams.com. You can access this replay through the Investor Relations tab and by clicking on the Conference Call link on the top right hand corner of the screen.

During this call, we will discuss our second quarter results and our operations update release that were issued this morning and then, we will entertain a question-and-answer session for as long as time permits. Please be advised that our remarks and answers to your questions includes statements that we believe to be forward-looking statements.

All statements that relate to future results are forward-looking statements that are based on current expectations. Actual results may defer materially from those expressed or implied by these forward-looking statements, because of the number of risks and uncertainties affecting our business, including those discussed in our quarterly and annual SEC filings, and in the cautionary statements contained in our press release and on our website.

With that being said, I will turn the call over to Mr. Mel Riggs. Mel?

Mel Riggs

Thanks, Patty and thanks to everyone for dialing into this call. Format for today is going to be first of all Mike Pollard, our CFO will give us an insight for kind of recap of our financial results. And then after that, Mr. Williams will talk about kind of what has been happening operationally and what he sees into the future and then, we will have questions. We have got a several members of our – to provide the script named. We’ve got several other key members of our management team here today to help answer questions if necessary. So, with that I’ll turn it over to Mike.

Michael Pollard

Thank you, Mel. For the second quarter of 2012, we reported consolidated net income of $32.8 million or $2.70 per share versus net income of $42.7 million or $3.51 per share for the second quarter of 2011. Cash flow from operations net of changes in working capital was $44.9 million versus $86.4 million in 2011. For the six months ended June 30, 2012, we reported consolidated net income of $40.6 million or $3.34 per share versus net income of $34.8 million or $2.86 per share for the same period in 2011. Cash flow from operations was $97.3 million versus a $119.7 million for 2011.

Oil and gas sales for the second quarter of 2012 decreased to $6.4 million with price variances accounting for a $17.8 million decrease and production variances accounting for an $8.9 million increase. Our average realized oil price decreased to $88.06 per barrel versus a $100.07 in 2011, and our average realized gas price dropped to $3.25 per Mcf versus $5.56 Mcf in 2011.

Oil and gas sales this quarter also includes $2.5 million of non-cash amortized deferred revenue attributable to a volumetric production payment.

Our combined oil and gas production for the second quarter of 2012 was 1,411,000 BOE, which is roughly 15,500 BOE per day. That is up 6% as compared to the 2011 quarter. Oil production averaged 10,626 barrels per day up 9% and gas production averaged 23.4 million cubic feet down 6%.

Oil and NGLs make up about 75% of our total production. Our growth rate in oil production is improving as we work through some of our startup drilling and completion issues in the Delaware Basin, Wolfbone play. New production from our vertical drilling program is improving as we are better able to greater target locations in intervals and we’re also very encouraged with the early results from a horizontal drilling program.

Production cost rose 24% to $32.3 million in the second quarter of 2012 from $26.1 million in the 2011 quarter. Most of the increase resulted from higher lifting costs associated with more producing wells and rising cost of field services.

Due largely to the lack of infrastructure in Reeves County we’re experiencing higher than normal lifting cost, particularly costs associated with saltwater disposal. We’re nearing completion of an SWD system, which should significantly reduce our costs in Reeves County as we go forward.

Depreciation, depletion and amortization expense increased 37% to $34.6 million in the second quarter of 2012 from $25.3 million in 2011 quarter. This was due primarily to a 27% increase in the average depletion rate per BOE.

Most of this increase in the depletion rate relates to our Wolfbone play in Reeves County, but again as we work through drilling and completion issues, we expect to realize lower drilling cost in higher reserves and we should see our DD&A rate trim down in the future.

G&A expenses were $4.3 million in the second quarter of 2012 versus $3 million in the 2011 quarter. Breaking this down between cash and non-cash expenses, cash G&A, which excludes non-cash employee compensation expense increased 700,000 from $5.5 million to $6.2 million and that was due primarily to higher personnel cost.

Non-cash employee compensation expense from our incentive compensation plans for the current quarter was a credit of $1.9 million versus a credit of $2.4 million in the 2011 quarter. We recognize our estimated future compensation expense from our AO Reward Plans over the last divesting life of each plan, which is generally between two and three years, but lower commodity prices this quarter resulted in basically a reversal of a portion of the previously reported accrued expenses. So that resulted in the credit to expense.

We reported the gain on derivatives for the second quarter of 2012 of $38.7 million versus a gain of $28.2 million in the 2011 quarter. The 2012 gain was comprised of 845,000 of realized gain on settled contracts. And a $37.8 million non-cash mark to market gain on the changes in fair value of the commodity derivatives. By comparison, the 2011 gain was comprised of $7.4 million loss on settled contracts and a $35.6 million noncash mark-to-market gain. As we have said before, we do not designate our derivatives as cash flow hedges, so all changes in fair value of derivatives flow through the income statement.

Moving to the balance sheet, the outstanding balance on a revolving credit facility increased during the quarter from $275 million to $350 million an increase of $75 million. The total commitment of our lenders entered the credit facility is $475 million. This leaves us with $121 million of availability in ahead of all outstanding letters of credit.

Currently our borrowing base under the facility of $565 million providing us with an additional $90 million of liquidity upon request. However, each lender in the facility must consent to its proportionate share of any requested increase in commitments.

During the first quarter, we spent about $145 million on land, drilling and completion activities – that’s during the second quarter, we spent $145 million on land, drilling and completion activities. 85% of those expenditures were in the Permian Basin and more than 75% of the Permian Basin costs were dedicated to the Wolfbone play in the Delaware Basin.

Of the $145 million of expenditures, land cost accounted for approximately $28 million and drilling and completion costs accounted for $117 million. In addition, we spent about $12 million during the quarter on capital additions to midstream facilities and drilling rig upgrades.

I think that covers the financial overview. So with that I will turn the call over to Mr. Clayton Williams for an operational review.

Clayton Williams

Before we move to operations, let’s have financial questions of – any financial questions? Operator we will take questions for the financials at this time.

Question-and-Answer Session

Operator

All right. (Operator Instructions) Our first question comes from the line of Welles Fitzpatrick with Johnson Rice.

Welles Fitzpatrick – Johnson Rice

Good afternoon.

Clayton Williams

Hey, Welles.

Welles Fitzpatrick – Johnson Rice

I guess this is kind of a blend between operational and financial, but can you talk a little bit about costs moving forward. I remember that you guys had a fracking contract drilling off in June. Is that correct and what do you expect those to be moving forward?

Clayton Williams

Yeah, we – the Halliburton contract expired at the end of June and we’re currently working with other vendors to see where we’re going to go with that. We’ve passed out first round of bids and we weren’t very happy with them, so went back and we’ve changed some of the parameters. We believe that we’re on the end of high prices as forward fracking goes, we’ve seen about a 10 fold increase in horsepower in the Permian basin.

So we’re fully expecting our completion costs to go down and we’re currently awaiting a new round of bids to come in off of our new parameters to see where we’re going to end up and we’re talking about doing it for a shorter term, because we don’t want to lock in at this position in time for the one to two year period that we’ve done in the past. So, we fully expect our costs to come down for completion and on operating costs we expect them to come down because what might refer to where our SWD lines are beginning to be – our wells are beginning to be tied in and we’re seeing a significant savings in our water disposal costs.

Welles Fitzpatrick – Johnson Rice

And do you think that LOE drop with the salt water disposal, is that a third quarter event or should we model in that a little bit later in the year?

Clayton Williams

I would model it, it’s all going to happen during the third quarter. By the end of the third quarter we should have 70% of our wells in the Delaware Basin tied into a saltwater disposal and we’re hoping to have a 100% of our wells in the Andrews County Wolfbone play tied into disposal. So, it’s going to happening during the third, I would kind of model it to be completed by the third quarter and you’ll see that benefit going forward – fourth quarter, going forward.

Welles Fitzpatrick – Johnson Rice

Perfect, that’s all the financial questions I have. Thanks so much.

Clayton Williams

Thank you.

Operator

Thank you. And our next question comes from the line of Neal Dingmann from SunTrust Robinson Humphrey.

Neal Dingmann – SunTrust Robinson Humphrey

Good afternoon, guys. Say, two quick ones, maybe for you, Mike. Just like G&A came down quite a bit both on the cash and non-cash that you’re speaking of, kind of is a go-forward – I know later on you’ll put out some guidance I think is normal, but just kind of one and is that a rate that can stay down there both if you would talk about that a little bit around the cash and non-cash on the G&A going forward?

Clayton Williams

Sure, the non-cash obviously will go up this quarter included a credit, it’s very sensitive to price. And, if prices hold constant through the quarter we’ll probably see a minimal effect on the non-cash and the cash G&A I believe will – it will pick up a little bit. Each quarter has – is kind of cyclical in terms of what the – what happened in those quarters. We had some of unusual type cash expenses in the second quarter of 2011, those will not recur, but we’ll be putting out guidance here pretty quick early August and we’ll make a good attempt to give you some additional color on that.

Neal Dingmann – SunTrust Robinson Humphrey

Okay, that’s great. And then, just one follow up, maybe either for Clay or for Mel, just wondering on – hedging going forward, I know you’ve been pretty opportunistic and you had some great calls when you covered and some added somewhat here the last few quarters, wondering kind of either Clay, Mel’s view as far as on hedging right now would you add some more at today’s level or what do you see for the next several quarters going?

Mel Riggs

I will start and I will let Clayton finish up, but basically on National Tequila Day, Clayton and I made a decision about hedging, but we can’t remember now what. So our game plan right now, we are about 80% hedge for the next 12 months and we feel very good substantially hedged for the next 12 months, we got other hedges in place out there in 2014. So things are we felt pretty good, we don’t know which process is going on, I will let Clayton take it from here.

Clayton Williams

Well you handed me, but you don’t know that I don’t that either. We do paid very closer attention to hedging our future productions, at this point we are living with a good hedge, we made last year and that goes to one more year. I don’t see any real hedging activity unless you say a real fracking prices. We think the low end is pretty well covered.

Neal Dingmann – SunTrust Robinson Humphrey

Clay any reason to monetize and cash that hedge out now that great hedge that you have or do you rather keep it on?

Clayton Williams

Well that’s what I thought this afternoon. I mean I can’t, I will say I don’t know, but this problem is line to keep with as it is. The main reason we hedged in the first was to cover our drilling where we could keep our progress going and I don’t see that changing, now the one that we lifted the hedge, it was such a major hedge over three years, 51 million as I recall. So we thought it is better to take the money in and believe in also at the time that the past worldwide supply in demand of crude is fairly stable.

So I think there, just as long as there I do not see lift in the remainder of the hedge, as we have new production come on, we will consider hedging the new production as it comes on, I am stuck in neutral.

Neal Dingmann – SunTrust Robinson Humphrey

Yeah, we did that our current hedge did get pretty attractive from the standpoint of the potentially taking it off and we had our $40 million put in for profit, but I don’t think we have a very good feeling – in fact a clear feeling of picture where we’re headed and there is a lot of that’ll clear up somewhat as this year unfolds as the election of things – I don’t know which way we’re going and maybe Europe. So, by now, we’re just going to write it out.

Clayton Williams

That’s a windy answer for... we don’t know.

Mel Riggs

We don’t know...

Neal Dingmann – SunTrust Robinson Humphrey

I think that’s a great answer. I will get back in queue for the ops.

Operator

Thank you. And our next question comes from the line of Irene Haas from Wunderlich.

Irene Haas – Wunderlich

Yeah, just a quick question on lease operating cost, are you going to provide us with some sort of full-year guidance? And looking at certain fourth quarter, how many dollars per barrel should we expect lease operating cost to come down?

Clayton Williams

Okay. We will be putting out revised guidance in early August and include that at that time. I can’t tell you right now. We are still looking at it.

Mel Riggs

I am not (inaudible) that you have salt water disposal systems underway, not yet completely. We have natural gas pipelines and oil pipelines that will be picking up overall and save the overhead or increase our profitability. Those are underway but those are not major changes there, $4 or $5 a barrel, something like that. But, they’re still part of running our business.

Irene Haas – Wunderlich

Okay, great. Thanks.

Clayton Williams

Thanks, Irene.

Operator

Thank you. And our next question comes from the line of Andrew Coleman from Raymond James.

Andrew Coleman – Raymond James

Thanks a lot. So, I had a couple of questions. One, could you capitalized interest was if you had any further quarter?

Mel Riggs

It was – my recollecting is around 265,000 or something like, wasn’t much.

Andrew Coleman – Raymond James

Okay. Okay, great and then, the second one is on the – on your transportation and fractionation costs for your NGOs, can you give any color as to what that number looks like on either price cents per gallon or dollar per gallon basis?

Mel Riggs

For the historical last quarter, we were – we saw a $49 per barrel just blended all NGLs that a $49 per barrel differential, a negative differential. So it is – it was up, the differential was down a little bit from the first quarter, first quarter is about $57, and it’s now $49 a barrel.

Andrew Coleman – Raymond James

Okay. And have you guys provided or can you provide the approximate mix of ethane, propanes and makes on the barrel?

Mel Riggs

I do not have that information available Andrew.

Andrew Coleman – Raymond James

Okay. All right.

Mel Riggs

Our focus is our focus have been more directed to oil rather than natural gas, that’s been less than a part of our – I’m not – not that we are not interested, but it is less, less of our focus.

Clayton Williams

Yeah, Andrew. We do have somebody in the company, who could answer that question, (inaudible) he is not in his frame right now, so.

Andrew Coleman – Raymond James

Okay, all right. I can follow-up with you guys in off-line.

Clayton Williams

Thank you.

Andrew Coleman – Raymond James

I guess the last question was you guys broke out some color on the VPP, will you give the guidance on the remaining in terms of – of course that VPP with the August update?

Clayton Williams

I’m sure we can. As you think looking forward into the...

Andrew Coleman – Raymond James

Yes.

Clayton Williams

Rest of the year, 2012, sure. I can, thanks.

Andrew Coleman – Raymond James

All right. Thank you.

Operator

Thank you. And our next question comes from the line of Mike Kelly from Global Hunter

Mike Kelly – Global Hunter

Thanks, guys. I think the operating cost has been beaten to death here. So just jump back into the queue wait for the op segment. Thanks.

Mel Riggs

Thank you, Mike.

Clayton Williams

Thank you, Mike.

Operator

Thank you. And we also have a question from the line of Sean Sneeden from Oppenheimer.

Sean Sneeden – Oppenheimer

Hi, thank you for taking the question. Clayton, I think when you said in your prepared remarks, that you got through $75 million under revolver in the quarter, which leaves you with the call it $121 million of the availability.

Clayton Williams

Yes.

Sean Sneeden – Oppenheimer

Just given the sort of level of rig activity that you guys have been talking about. Do you feel this is an adequate amount of availability to match your spending plans?

Mel Riggs

Yes, we do, that plus the additional $90 million that we do have available to us, if we need to draw on it, but right now we believe that certainly through the rest of this year we’ve got ample liquidity. We’re always and currently looking at other options for adding to our cash burns available for drilling, but we’re okay now. We feel like we have adequate liquidity.

Sean Sneeden – Oppenheimer

Sure. And, then would be fair to say then any use of cash flow that’s been you’d look to fund on the revolver?

Mel Riggs

Yes, we would, for the rest of the year, yes.

Sean Sneeden – Oppenheimer

Okay. And, then just sort of thinking about maybe 2013- just thinking how might look to boost liquidity, would you ever looked to monetize any portion of getting through – perhaps some of your drilling fleet or sort of what’s the larger picture in boosting liquidity?

Clayton Williams

That’s kind under review right now. There are lots of options and we’re really not ready to talk about any of them at this point, but we do have several options.

Sean Sneeden – Oppenheimer

Okay, fair enough. Thank you.

Clayton Williams

Thank you.

Operator

Thank you. And, that was our final question on this subject. We will move on for the operation.

Clayton Williams

Thank you. I’m going to learn out the area by areas and what happening there. First let’s go to the oil getting area in the Eagle Ford shale. Our number one bell curve unit is completed at the results are encouraging. We don’t have enough production to commercial or not, it is encouraging. This is the Austin Chalk where the Eagle Ford is, the formation is immediately under the Austin Chalk where we have a 120,000 acres there and so I can say that if the potential is large – if the potential is large if it works. At this point, we’re encouraged and that’s all I can tell you about that. Into the Permian basin – and I’ll take question on it as we finish up.

And after the Permian, in the Andrews Wolfbone, we’ve drilled 180 wells. We see one maybe two wells rigs drilling there constantly. We think we can keep that drilling going forward probably two years if that’s right. We’re still making commercial oil. On into the East Permian, it has not been a major area but we’ve drilled nine wells.

We’re extending the drilling to horizontal well – horizontal drilling and it’s a competitive area. The economics are very good. The payouts are fairly short. We have 34,000 acres. It is not a major area but I will call it a developing and potential area.

On into the Delaware basin which is really our major effort and the Wolfbone; to date we have drilled 71 wells, 63 vertical and 8 horizontal. There are 6 producing and 11 completing. We have 5 rigs building there to date. We believe that we have and these wells apparently are commercial, we believe them to be.

At this point, we think we will drill either 200 vertical wells more or less, or may be 100 horizontal wells. We’ve completed several horizontal wells, they’re very encouraging. I think they’re probably more profitable than the vertical wells but are still in a wait and see mode but we have about nearly a 100 square miles of leases there, a lot potential – a lot percentage we think will be good. So, roughly 47 acres is perspective and probably drillable. We think today and we’ve had times where we learned better, but at this point we’re very optimistic up there.

So, basically we’re happy with where we are. We have ongoing drilling in the Austin Chalk area. We have increased drilling in the Permian Basin, which now some fall in the Wolf – in the Reeves County – happy with where we are. We are happy 120 or 130, but we are making to do what it is and so I’ll be happy to take your question now. And not to kill the time, I’ll give you the best future production that I can.

Operator

Thank you. (Operator Instructions). Our next question comes from the line of Neal Dingmann from SunTrust Robinson Humphrey.

Neal Dingmann – SunTrust Robinson Humphrey

Hey, Clayton and Mel just wondering on that Delaware Basin now, have you held or where do you sit with Chesapeake acreage? Have you held most of that? Do you still have to drill?

Clayton Williams

Some we must to earn. We’ve actually earned it with the Chesapeake deal. They are still away in either the Chesapeake format where some drilling to do. And to hold acreage, the some of the acreage was expiring, so we have drilling to do. I include that more or less and I say we have a five-well program in the Delaware Basin, covers the Chesapeake acreage and as well the acreage we leased, which is about 40% of the Chesapeake. So, five rigs drilling there steadily will hold the acreage now at some point. We may accelerate it. We have other drilling rig that we are now drilling for someone else. So, as we go further long and see more particular more horizontal reserves, we probably accelerate that program.

Mel Riggs

Greg Welborn who runs our Land Department, he is right here, he can kind of give you a quite a little quick little recap.

Neal Dingmann – SunTrust Robinson Humphrey

Good.

Greg Welborn

We’ve drilled 40 carried wells, so that has earned us 640 acres each time and we get 75% of that, so that’s about 25,000 acres, 20,000 net to the company. And then also in that we have leased another 10,000 acres, once the format came around we got 30,000 acres, where we have where we are with Chesapeake 75% and in another 35,000 we are CWEI has the 100% that we leased before head.

Clayton Williams

So it’s not 50-50 between the two efforts, Chesapeake has their own efforts, so we are doing well, we have earned a lot of acreage.

Neal Dingmann – SunTrust Robinson Humphrey

Okay. And then what – now how many of your own rigs do you have running now, I just want and do you have any of those stat?

Clayton Williams

We have a couple of rigs in Yates, I believe I mean John go ahead, he is John Kennedy who runs our drilling operation.

Neal Dingmann – SunTrust Robinson Humphrey

Hi, John.

John Kennedy

Right now, we have three rigs in Yates, two of them are being refurbished and being worked on. One of them is waiting for work to do and we actually have a well that we’re going to take that rig out to build the work for us pretty soon. The rest of the rigs, we have seven total working for us and the others are all contracted out to other operators.

Neal Dingmann – SunTrust Robinson Humphrey

I got it. And then on any idea you had you are talking about plenty of things was mentioned that he thinks that horizontals in (inaudible) will be a maybe a bit better on economics than the verticals, any idea on just sort of cost that you are seeing now and have you seen those go down I guess, to your point earlier about all the additional fracs there, does that mean that these well costs are steadily going down?

Clayton Williams

Let me answer first that we will continue to drill more horizontal wells. Horizontal wells are more cost effective, but they’re only drilled in the bottom zone, the bottom zone we’re working at. There’s clay up the whole Bone Springs and Delaware that we’ll come back years later to drill. Now the – what was the second question, on the cost

Neal Dingmann – SunTrust Robinson Humphrey

Cost, how much you kind of the cost...

Mel Riggs

Yeah, our current cost estimates for Wolfbone horizontal drilling complete is about $17.5 million.

Clayton Williams

That may come down with decrease in completion costs mainly in the fracking, but then again, it might go up. We started doing more study and determined that we need to put more dirt in the ground to make better wells. So, right now a good estimate to hang your head on as $7.5 million drilling completes.

Neal Dingmann – SunTrust Robinson Humphrey

That helps and...

Clayton Williams

I might add to that that in my experience and boom until something bad happens the prices still keep going up and we have to fight to keep our profit margins that fight is on today.

Neal Dingmann – SunTrust Robinson Humphrey

Got it and then last one. Mel, and the last one if I could for any all on wondering in any of those around on the Delaware, I don’t know that you have any of this, I know some folks not terribly far from you are going after clients strong in Mississippi and any of that that you’re looking at besides the Spraberry and Wolfberry and all that?

Clayton Williams

Well, the client is always in the Permian, not in the Delaware.

Neal Dingmann – SunTrust Robinson Humphrey

Correct, correct that means over in that side.

Clayton Williams

Like the east Permian, that’s where client is and we have some operation going there, but we didn’t talk a lot about them because this is not a major part of our business. So, that means in that East Permian we’ve drilled nine wells over there and we have 34,000 acres and we’re declining in that (inaudible).

Mel Riggs

Yeah, I think we’re studying or we may have already studied, we have not – because we’ve got a client well to drill in that Eastern Permian block that you talked about. It’s a kind of keen off of the activity that patchy and break of the deadwood area. In that – I mean they’re drilling around this. So, we feel that we have a good plan – possibility there.

Neal Dingmann – SunTrust Robinson Humphrey

So, depending that, Mel, you might even go after few more of those.

Mel Riggs

Yeah, if it’s good, let’s see.

Clayton Williams

This is not new. We have been drilling these for a couple of years.

Mel Riggs

Bigger on the Wolfbone – Wolfcamp.

Neal Dingmann – SunTrust Robinson Humphrey

Got it, got it. Thank you.

Clayton Williams

Yeah.

Operator

Thank you. And we also have a question from the line of Irene Haas from Wunderlich.

Irene Haas – Wunderlich

Question has to do with the CapEx. We spent quite a bit upfront. So, my question is are you going to be raising CapEx or are you going to stick with what you have that you’re frontend loaded, and the second question has to do with the three horizontal tests you could get out of the Wolfbone, which horizons did you attack and which you expect higher rate as you spend more time working?

Clayton Williams

Let me talk – on the first – that first the upfront color, mostly behind this now. That’s building pipeline, water injection wells, lease costs for example, the Chesapeake area, these part of wells got those behind this, but I didn’t understand the second part of your question.

Mel Riggs

Great, Irene.

Irene Haas – Wunderlich

Okay. So that – we shouldn’t expect any CapEx creep, that’s what you’re saying. The second part has to do with the horizontal wells, which horizons that you actually tackle?

Clayton Williams

Today, we’re drilling the lower Wolfbone – horizontal. The horizontal drills are holding with (inaudible) in the future and might be the horizontal. We’ve completed several – I think there are five potential places up the hold and the Delaware basin, but we’re focusing horizontal on the lowest, which is the Wolfcamp.

Irene Haas – Wunderlich

Got you. And can you share a little bit of how many fracs stage and all of that stuff you put in there?

Clayton Williams

Here you are pointing more or less, you want to take that.

Mel Riggs

That’s good, 20 more or less.

Clayton Williams

It’s pretty solid rocks. So you just had to frac the hell out of it make it commercial. And I think we have a plenty of different stages, we are correct, and one reason that is we are fracking the mile alone. So because it is such a big area to frac, it takes lots of stages.

Michael Pollard

And Irene, this is Mike again. I don’t want to mislead you there. There will be some creeping up in capital expenditures. We don’t yet have our finalized number for the rigs, but the year we are still talking about for sure, how many rigs, we will do and Andrew, and few variables in there. It’s will be in the 10-Q, and it will also be in guidance.

Irene Hass – Wunderlich

Okay. Thank you.

Clayton Williams

That I missed earlier, the process keeps creeping up, till it goes bust and that was happened there in every time. So if there is a service company, they get greedier and greedier, sometime the balloons have shut down by a process from overseas, sometime and they started from sales.

Irene Hass – Wunderlich

Okay, great. Thank you.

Clayton Williams

Thank you.

Operator

Thank you. And our next question comes from the line of Ravi Kamath.

Clayton Williams

Hello.

Operator

Our next question comes from the line of Ravi Kamath from Global Hunter.

Ravi Kamath – Global Hunter

A couple of questions, one of the Wolfbone, you guys provided an average of 158 barrels per day. Just wondering, what the – what the range is, what the low and the high and you know what’s are there newer wells coming in that higher and?

Clayton Williams

Mike Pollard, is our exploration manager. I’ll let him tackle that. It’s all over the base.

Michael Pollard

You’re talking about the vertical wells.

Ravi Kamath – Global Hunter

The vertical Wolfbone’s that you said averaged 158.

Mel Riggs

We have a range of 100 barrels a day to up to 350 a day.

Clayton Williams

It’s very statistical.

Ravi Kamath – Global Hunter

Okay.

Clayton Williams

I think we’re seeing that every time we do that here.

Mel Riggs

And that’s a 30 day peak average.

Ravi Kamath – Global Hunter

Okay.

Mel Riggs

It’s not that we pull out of this.

Ravi Kamath – Global Hunter

Yes, it’s not an IP.

Clayton Williams

And that’s right on our model that we started with a couple of years ago, we’ve yet to change our model, but we are shooting for lately we’ve had better success in hitting that models. So, we are pretty optimistic going forward that we figured it out.

Ravi Kamath – Global Hunter

Okay. And the model is like 200 to 250 MBOE EUR is that?

Clayton Williams

Yes, that’s correct.

Ravi Kamath – Global Hunter

Okay. And then on the three horizontal wells, I guess just also wondering what the range was on those three wells in terms of the 30 day IP?

Clayton Williams

Well, we – out of those three I think our average was 300. So, you can go 200 to 400 and we gave right in there.

Ravi Kamath – Global Hunter

Yeah.

Clayton Williams

So whole secret there is how long it hangs in there and that’s what we’re sitting here watching right now.

Mel Riggs

So if we were better managed we would just drilled a 400 barrel a day a well.

Ravi Kamath – Global Hunter

That’s a good thought. And is that – at that sort of level do you think those wells are economic the horizontal wells?

Mel Riggs

Yeah as I just said if it continues to hang in like it currently is, and we expect it to then it is extremely economic, but the proof is going to be in the production over the next couple of months. So this is a big time for us as far as the horizontal development goes out in the Wolfbone.

Ravi Kamath – Global Hunter

And then one last one on NGL pricing just wondering what your kind of outlook was or where you are currently relative to WTI as a percent. I know what you average, but just wondering if that has come down significantly from that average?

Mel Riggs

Yeah, for the June 30 quarter, our differential for NGLs was around $49 a barrel and that’s down from $57 a barrel the previous quarter. Going forward, I think we’re going to see something somewhere in that range, it hasn’t jumped. I’d say first quarter was probably the worst, I think the second quarter $50 a barrel would be a good run rate for that, doesn’t affect us greatly because we don’t have NGL volumes but that would be a good run rate for your model.

Ravi Kamath – Global Hunter

Okay, great. Thank you, guys.

Operator

Thank you. And our next question comes from the line of Mike Kelly from Global Hunter.

Mike Kelly – Global Hunter

Hey guys, I was hoping to get maybe a little bit more color on the horizontal Delaware program. You mentioned you are targeting the bottom zone of the Wolfcamp, and really just wondering what’s driving this decision, is this what you think is ultimately the best horizontal zone in terms of results, you would expect or just to hold acreage above it all the intervals above it?

Clayton Williams

There are several items. Number one traditional (inaudible) is to drill the bottom, complete the bottom of the several plays first, that’s part of it. Then it’s a good solid play that’s easier to keep the median target and at this point we think it’s the most commercial now. Having said that, we also have a program there in the limestones under the Wolfcamp which is the (inaudible) zone or the (inaudible) zone as well call it.

Those wells are better cash flow, so at this point we are putting the target more there than we have in the past. Past that that hits the floor then you have the Wolfcamp, then you have several bone spring zone. So there is a number of phases at this point, we could do it vertical and complete several zones but the economics at this point are better than horizontal wells because the flows are better and also when we are drilling the bottom of the potential plays, we are holding acreage above that as well in most cases.

So we’ve got a lot of work to do, you could make a case, I’m not saying that would happen, we might have several vertical wells in zones at the hole at same point in the future. So number one, the most powerful, number two generally will hold a section according to (inaudible), so it also does the job from our land standpoint of holding our acreage as we go forward.

Mike Kelly – Global Hunter

Is that horizontal lateral, is that actually going in the Gomez zone or is that – is that Wolfcamp or is that part of the Wolfcamp?

Clayton Williams

(inaudible) both, we have some (inaudible) is what the lower limestone of Wolfcamp will decide. There are basically, the Gomez is the west side, so sometimes we are doing and also we are still in the learning curve so we are drilling some wells, so we can evaluate what we got. So at this point I would say, it looks very positive on the lower zone, which either of the Gomez or the Merry and the Wolfcamp itself doesn’t have quite as big inflows and some of the Bone Spring potential, I kind of have to say we don’t know which is best yet. Sam you want to pitch in on that?

Mel Riggs

We’re targeting zones that we see continuity that we feel comfortable that we can place the lateral in a interval that we’ve had chose in the vertical lows so that’s kind of how our thinking has been going on these horizontals. So to answer your question, we are using both the vertical information that we gained through the 70 or something wells that we drilled to date. Those that have the best shows and that’s the intervals that we target in our horizontal wells.

Mike Kelly – Global Hunter

Got it. Thank you.

Operator

Thank you. And that concludes our question-and-answer session today. I would like to turn the conference back to Mr. Williams, for any concluding remark.

Clayton Williams

Thanks. And folks we are really on target I’d say. We are on target maybe in the Eagle Ford, there’s drilling there if this well turns up. There is development drilling, we – we are more or less stuck in Andrews, but there is still some work to be done. The main focus is in the Delaware Basin in the Wolfbone.

We are happy with the results. We are working on efficiencies like water disposal wells and our pipelines. Those things are largely underway or have been completed so we are still at this point, we got a lot of work to do, we are focused on efficiencies like gathering the gas instead of flaring it, and we are on target. We are ahead, where we are. That’s all and – that’s all I have to say about that. Thank you.

Patti Hollums

Thank you.

Operator

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

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