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Executives

Ross Craft – President and CEO

Steve Smart – EVP and CFO

Qingming Yang – EVP, Business Development and Geosciences

Analysts

Jack Aydin – KeyBanc Capital Markets

Irene Haas – Wunderlich Securities

Leo Mariani – RBC

Welles Fitzpatrick – Johnson Rice

Kim Pacanovsky – MLV & Company

Mario Barraza – Tuohy Brothers

Jeff Hayden – KLR Group

Gordon Douthat – Wells Fargo

Robert Miller – Boulevard Trust

Mike Kelly – Global Hunter Securities

Tim Rezvan – Sterne Agee

Liam Kelly – Howard Weil

Approach Resources Inc. (AREX) Q2 2012 Earnings Call August 3, 2012 11:00 AM ET

Operator

Good morning, everyone, and welcome to the Approach Resources Second Quarter 2012 Earnings Conference Call and Audio Webcast. Today’s call is being recorded. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session at the end of today’s conference call.

Management’s remarks today will include forward-looking statements. These statements are subject to many factors that could cause actual results to differ materially from management’s expectations as expressed in those forward-looking statements. Those factors are described in the company’s SEC filings and management refers you to the company’s website or to the SEC’s website to review those filings.

The company undertakes no obligation to publicly update or revise any forward-looking statements. During the call, management will refer to certain non-GAAP financial measures. Reconciliations of these measures are provided in the second quarter 2012 earnings release and have been posted to the company’s website under the non-GAAP financial information page at www.approachresources.com.

Now, I am going to turn the call over to Ross Craft, Approach’s President and CEO.

Ross Craft

Thank you. Good morning, everybody. Thank you for participating this morning and for your interest in Approach. With me on the call today we have Steve Smart, Chief Financial Officer; Qingming Yang, Executive VP, Business Development and Geosciences; Curtis Henderson, General Counsel; and Megan Hays, Manager of Investor Relations.

One of the highlights for this quarter was our sharp rise in oil production which increased a 120% compared to the prior year and 20% compared to the first quarter. This increase is largely a result of our focus on oil rich Wolfcamp shale.

We are also fortunate that we will be working in one of the most oil rich regions of the countries, the southern Midland Basin located in West Texas. Overall, the team is on track to reach our 2012 production target. The quarter total production increased 16% to 7.7 thousand BOEs per day.

Proved reserves at midyear 2012 were 83.7 million BOEs, made up of 28% of oil; 36% NGLs and 36% natural gas. Proved reserves increased 9% from year end 2011 and 25% from mid-year 2000 – from the end of the year 2011 and 25% from mid-year 2011.

Oil proved reserves totaled 23.5 million barrels and were up 30% from year end 2011 and 132% from mid-year 2011. While we are still very early in developing our Wolfcamp acreage, it is having a dramatic impact on the company’s results.

Compared to the third quarter 2010 when we first discussed Wolfcamp oil shale play with you, our oil production has increased by approximately 225% and our oil proved reserves have increased by more than 400%.

We recently completed the horizontal well targeting the Wolfcamp “B” zone and Project Pangea. The University 45 A 703H well, while the initial producing rate of 875 BOEs per day made up of 85% of oil, 93% total liquids. The 703H well has produced an average 30-day rate of 612 BOEs per day. The average 60-day rate for this well is 539 BOEs per day. We have three additional Wolfcamp “B” zone wells and Project Pangea that have been drilled, completed and are flowing back.

During the second quarter, we drilled two pilot wells in Pangea West targeting the Wolfcamp “A”. These two wells although early in the flow back are very encouraging and will be instrumental in transforming the “A” bench from deposit stage to development stage. The 6601H is currently producing 461 BOE per day, made up of 84% of oil and 93% liquids.

This well has only recovered approximately 17% of the 248,000 barrels of frac fluid we pumped. Similarly, the 6602H well has only recovered approximately 14% of the 252,000 barrels of frac fluid pumped. The 6602H well is currently producing 494 BOEs per day, made up of 80% oil, 91% total liquids. Both wells continued to get stronger as the frac fluid recovery increases. We plan to test Wolfcamp “A” and Project Pangea and expect to begin drilling this well in mid-August. In Pangea West, we are also evaluating the Wolfcamp “B” zone. We expect to begin completing a well targeting the Wolfcamp “B” zone within the next two weeks.

During the second quarter, we drilled and abandoned two Wolfcamp “B” zone wells due to mechanical problems resulting from directional tool failures and excessive rig downtime.

We are now 90% complete with our Pangea West frac water disposal and water and gas lift infrastructure project. We anticipate completion of this project in the third quarter. In addition, we are in the early stages of our Project Pangea infrastructure project. We anticipate completing all projects by the fourth quarter. Once completed, we should be able to reduce horizontal and vertical costs to our targeted well cost. Also these projects should have a significant reduction on lease operating expenses.

In the second half of the year, we’ll have two rigs running in the horizontal Wolfcamp play. During the third quarter, we plan to drill two pilot wells in Project Pangea, one targeting the Wolfcamp “A”, and one targeting the Wolfcamp “C”. We also plan to test northeastern Pangea with a horizontal well during the fourth quarter. There are no horizontal locations attributed to the northeast Pangea, however we’re encouraged by the offset operators activity and eager to test this area.

Overall, I’m encouraged by the horizontal Wolfcamp drilling results and excited about the growth opportunities ahead of us. Not only do we have room for production reserve growth as we explore the various stacked pays on our properties, but we are also focused on increasing our recovery factors through tighter well spacing, optimize drilling and completion techniques.

Now, I’m going to turn the call over to Steve to summarize our financial results for the second quarter.

Steve Smart

Okay. Thank you, Ross. Revenues for the second quarter 2012 totaled $29.9 million, a modest increase compared to our second quarter 2011 revenues of $29.1 million. Revenues for second quarter 2012 were supported by higher production volumes, but offset by lower than anticipated oil and NGL price realizations. Our average realized price for the second quarter 2012 before the effect of commodity derivatives was $42.61 per BOE compared to $47.90 per BOE for the prior year quarter.

Our average realized price for second quarter 2012 including the effect of commodity derivatives was $43.12 per BOE compared to $48.01 per BOE for the prior year quarter. Net income for second quarter 2012 was $7.9 million or $0.23 per share. This compares to net income for second quarter 2011 of $8 million or $0.28 per diluted share. Net income for second quarter 2012 included an unrealized gain on commodity derivatives of $9.4 million. Excluding the unrealized gain on commodity derivatives and related income taxes, adjusted net income was $1.6 million or $0.05 per diluted share.

EBITDAX for the second quarter 2012 was $20.1 million or $0.60 per share compared to $21 million or $0.73 per share in second quarter 2011. Total expenses trended higher in second quarter of 2012 as the company prepares for large-scale field development. Lease operating expense for second quarter was $7.13 per BOE, operating expense rose due to increases in compressor rental and repair, water hauling, insurance and other well repairs, workovers and maintenance and pumpers and supervision.

The good news is that severance and production taxes trended lower this quarter to $2.10 per BOE or 4.9% of all NGL and gas sales. Severance and production taxes fell on rising oil production as oil sales are taxed at a lower rate than natural gas sales.

General and administrative expenses were $7.19 per BOE, an increase primarily due to higher personnel costs associated with increased staffing, which was partially offset by decrease in share-based compensation.

D&A for the second quarter was $20.78 per BOE. DD&A increased primarily due to higher production and increased investment in the oil-rich Wolfcamp shale play relative to the estimated proved developed reserves.

Costs incurred for the second quarter totaled $70.3 million and included $65.1 million of exploration and development drilling, $4.6 million for pipeline and infrastructure projects and $600,000 for acreage acquisitions.

Our 2012 guidance for our capital expenditures remains unchanged at $260 million. At June 30, we had a $145.4 million in debt and $124.7 million of liquidity. We provide our current hedge position in the earnings release, quickly though I want to note that we entered into a swap for the balance of 2012 for natural gas covering 360,000 MMBtu per month at $2.70 per MMBtu. We will continue to look for opportunities to continue to hedge more crude oil and natural gas in 2013 and 2014 to add to our existing hedges for those years as we move forward.

Now, I’m going to turn the call back to Ross.

Ross Craft

Thanks, Steve. In summary, we’re making great strides in testing and delineating our Wolfcamp discovery and optimizing our drilling and completion techniques. Our resource potential is currently estimated at 500 million BOEs gross, which is more than four times our current proved reserves. As we optimize our drilling and completion techniques, targets, and wells basin, we believe we’ll have the opportunity to increase our field recovery factors, grow our well EURs and lower cost.

Looking ahead, we have several exciting projects and the work for the second half of 2012 that we anticipate will further increase efficiencies to reduce cost. We couldn’t be more excited about the tremendous opportunities ahead of us in the Wolfcamp and we look forward to keeping you informed about the progress.

That concludes our prepared comments. Thank you for participating and now we’ll take questions and answers.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question will come from the line of Jack Aydin, KeyBanc Capital Markets.

Jack Aydin – KeyBanc Capital Markets

Hey, guys. Good morning.

Ross Craft

Good morning.

Steve Smart

Good morning, Jack.

Jack Aydin – KeyBanc Capital Markets

Ross, how would you characterize your “A” bench wells? Could you elaborate a little bit more with the results and what you expect things to look going forward?

Ross Craft

Sure, Jack. Obviously, the first safety bench, the “A” bench wells over in Pangea West, what we did in those few wells right now, they’re in the early stages of flow-back although the current producing rate is pretty attractive for this early up – this early on the flow-back. When you go back and look at, for example, our very first well that we completed with the – all the right chemicals in the “B” bench over in Pangea which was a 457 number one that well had and I figure around 600 that’s a very good well. What we’re anticipating right now for the “A” bench, obviously, our targeted rates are going to be pretty similar to what you’re going to see in the “B” bench, that’s what we’re looking for.

Now, on that particular set of wells we were also tweaking our frac design a little bit and when I say tweaking, what we’re trying to do is get our chemical mixtures just right, so we don’t over stimulate with chemicals because as you can appreciate chemicals were expensive. And on this one what we did on these two wells, we lowered our surfactants a little bit trying to reduce our surfactant cost.

And so, what we’re going to do in the next two “A” bench wells, we’re going to increase the surfactant just a little bit more. We think that will help in the earlier recoveries and bring this level online a little bit faster. But all in all, I’m pretty excited about the “A” bench, especially on the Pangaea West area. It’s working very good, the wells are improving as the recovery rates continue to go up. And so I’m pretty excited, we’re getting ready to drill another “A” bench well over in Pangaea area.

We should spud that well just here in the next couple of weeks if not sooner, and so that pretty much the “A” bench is going to be a major portion of our development going forward.

Jack Aydin – KeyBanc Capital Markets

Is the cost of those two wells similar to the cost of the “B” bench wells or how much it cost you, each well?

Ross Craft

Yeah, the wells – right now, the wells costs very similar to what we’re seeing in the “B” bench. And as we’ve said before, right now, our current well costs, AFE numbers that just came across my desk on some of the wells were even below – were down in the lower sixes. But we’re still holding to about 6.5 to 6.7 to 6.3 right now. And the “B” bench or the “C” bench or the “A” bench, all will have the same cost because really there is not much depth difference in them, when you’re talking about 1,000 feet total between “B”, the “A”, and the “C”. So you won’t see much cost differential on these wells based on depth.

Obviously, the infrastructure program that we’re building in Pangea West were 90% complete with that program right now. We’ve just started the infrastructure program over in Pangea area. All of that is scheduled to be completed by the end of the third quarter, and once we had that in place, then you should see a pretty substantial reduction in drilling cost on both vertical and horizontal wells.

Jack Aydin – KeyBanc Capital Markets

Thanks. Let somebody else ask questions.

Operator

Next question will come from the line Irene Haas, Wunderlich Securities.

Irene Haas – Wunderlich Securities

Yeah. Hello, everybody. My question really has to do with the Wolfcamp play, there is just so much going on this particular week with Devon’s announcement on the JV and Pioneer’s pending JV. And how big exactly is this play, are there any sort of regional variability from south going to north? And then really my last part of the question is, are you guys still sticking with your sort of per well reserve as of now, sort of in the 400,000 range, as one of your competitor have raised it over 500,000 plus? So these are my questions.

Ross Craft

Irene, I’ll take your second question and then I’ll let Qingming take your first question. As far as the EURs on these wells, and we’ve said this in the past, we feel like a 450,000 BOE EUR is a statistical average. Obviously we’re going to drill wells and we have wells right now producing that are going to have higher EURs in that. We also have wells that we’ve drilled; they’re going to have a little bit lower EURs. But on statistical average, we feel 450,000 is a pretty good number at this point.

If we do make a change in our EUR, it won’t be till the end of the year. Once we have enough data back to support that change. And obviously if you look at the range of EURs and this is just an absolute range, you’re probably looking at EURs ranging anywhere from 350,000 up to 550,000, even maybe as close to 600,000 in some wells. I know I’ve looked at wells, on our wells and other operators’ wells that are up in the upper portion that range. But statistically and something that as analysts you all can, I think the 450,000 is a very safe number. I don’t think you’re going to get in trouble with the 450,000. And at this point in time, I can tell you I don’t have enough data to substantially change that average EUR that I’m looking at.

Qingming Yang

Irene, this is Qingming. As you know, the Wolfcamp is – was positive across the Midland Basin, and both, Southern Midland Basin and also Northern Midland Basin, and we have done a lot of work in Southern Midland Basin and based on the work we have done and we have found that the Wolfcamp in terms of thickness, they are very consistent across Southern Midland Basin. The Wolfcamp A, B, and C, they about 1,000 feet thick in terms of pay zone and in terms of the rock characteristics, they are very similar as well, and until you get to the edge part of the. So we think in the area whether it’s in Pioneer or Devon’s area you’re referring to, or Approach’s area, we think they are very similar.

Irene Haas – Wunderlich Securities

And any sort of (inaudible) and also thermal maturity is pretty uniform across the basin, so really we wouldn’t expect a whole lot of variability till you get to the basin edge, is that the right way to think about it?

Qingming Yang

That’s a very good question. Obviously a lot of people are talking about depths, they are looking into the depths of – the present depth, and as you know, the thermal maturity sometimes are not necessarily related to present depth of the formation; thermal maturity is related to more the temperature and timing instead of current depth, and we have – fortunately we have data – thermal maturity data in our area, and also the area north of us.

When we compare to those thermal maturity data, it looks like they are all in their peak oil generation and also early in a gas generation window. Even though as you get move to the north, the depths increase a little bit, but we think their peak oil generation and also early gas generation window. And other sort of fact we can kind of look at that you say initially oil components and also liquid components, if you look at all the way across Southern Midland Basin and drilled by Approach and also offset operators looks like in the oil component initially our average is about 82% and the liquid together it’s about over 90%, that’s actually across this area, whether it was built by Approach, EOG or Pioneer.

Irene Haas – Wunderlich Securities

So, it’s pretty consistent?

Qingming Yang

I think based on the data we have seen so far, we have started over 59 wells and by looking at the IP, looking at the oil components, and also looking at the liquids component and the results are very, very similar. From well to well, you may see variation, but on average these are very similar.

Irene Haas – Wunderlich Securities

Great. Thank you.

Operator

Next question comes from the line of Leo Mariani, RBC.

Leo Mariani – RBC

Hey, guys. Just a question about the “A” bench wells, you talked about these wells having a very small amount of the frac fluid that’s been produced out of the well, kind of in the mid-to-low teens per well. Based on that, are the production rates of the “A” bench wells similar to what you would see in the “B” bench wells, if a similar amount of frac fluid had been produced at this point.

Ross Craft

Yeah, the range of recoveries right now where these two wells are at versus what we see in the “B” bench over in Pangea area, it’s very similar to a certain degree. What we’re seeing – normally see, whenever you see, recovery rates anywhere from 12% to 16% over in the “B” bench in Pangea, that’s when you start to seeing your production start moving up pretty substantially on these wells.

So, we’re right at the inflection point in Pangea West right now. So it’s going to be – as we see these wells are improving there, they’re running about the same as far as percent increases at the certain percent recovery. But, time will tell when we look at them and see what they are going to do. At this point, we’re pretty encouraged what we’re seeing though.

Leo Mariani – RBC

That’s great to hear. Obviously it looks like you guys are kind of methodically moving around your acreage in hefting a number of different concepts here. When do you guys plan to drill some horizontals in the southern part of your acreage?

Ross Craft

In the southern part, down in the 60,000 acres that we referred to Southern Pangea, where we had no plans at this point at least in the next several months to drill a horizontal well. What we are doing is we’re allowing offset operators to kind of do the R&D down there so we can focus back up to the north a little bit.

What we are doing down in the southern portion of the acreage is continuing our recompletion program. As we’ve talked about a little bit the last quarter, we were getting ready to do three more recompletions down in the southern acreage, which we have completed those that was a Walker well, the Bailey well, and the Davidson well.

And although the Walker well is just now cleaning up the Davidson and Bailey well, we tweak those fracs a little bit and add some CO2 to it and what we’re looking at there, I think the IP rate on the Davidson well was like 77 BOEs per well and that’s right on top our type curve in the JR Bailey 810 was about 51 BOEs per well. What we are planning on doing down there is and if you look at the distribution of these wells from the Davidson all the way to Walker it goes from the very southwestern corner up to the northeastern corner of Southern Pangea.

Now, we’re going to crisscross it the other way and go from the northwest corner down to the southeast corner with another three wells. We’re getting the frac tweak to where the chemicals are just right and that’s critical out here on this shale is having their chemicals just right. And, so I think we’re making progress, but right now we don’t have any short-term plans that put a horizontal down there. Obviously what we’re looking at also on the southern acreage is the area between Strawn all the way up into the Wolfcamp. Obviously that’s got some interest to us as well and that’s probably what we’re going to do our first, what we would call our client test.

Leo Mariani – RBC

All right, guys. Thanks a lot.

Operator

Your next question comes from the line of Welles Fitzpatrick, Johnson Rice.

Welles Fitzpatrick – Johnson Rice

Good morning.

Ross Craft

Good morning.

Steve Smart

Good morning.

Welles Fitzpatrick – Johnson Rice

Qin, can you remind us where you guys are with the downspacing going to 660 to 700 feet apart, when we expect some results from that?

Qingming Yang

As you know, we have been running one in (inaudible) rate until a couple of months ago, right now and most of the time we’re spending our drilling time acreages and we’re trying to do a development well in “B” and also testing both “A” and “C” zone and going forward we’re going through test the downspacing at 600 to 700 feet. We have collected micro-seismic data from three wells, all three wells are telling us that their fracking range is about – it’s only going up for about 350 feet or so, we think 600 to 700 feet well spacing is way to go and looks like that offset operators that’s the well spacing they are tuning right now, we will test the down spacing very soon.

Welles Fitzpatrick – Johnson Rice

Okay. So, sometime this year it sounds like?

Qingming Yang

Yeah.

Ross Craft

Yeah definitely it’d be this year, right. As Qingming said, the one of the deals we brought that second horizontal rig in late March and by the time it started drilling sometime in April, of course you don’t see any production in the second quarter associated with that second rig, and that’s kind of how we had it modeled because of the delay in pad site wells, now having two rigs in place, it allows us to go in and start downspacing, we can use one rig as a delineation rig, we can use other rig as development rig. And so that’s part of our plan going forward.

Welles Fitzpatrick – Johnson Rice

All right, that’s perfect. That’s all I have. Thanks so much.

Operator

Your next question comes from the line of Kim Pacanovsky, MLV & Company.

Kim Pacanovsky – MLV & Company

Hi, good morning everyone.

Ross Craft

Hi, Kim.

Kim Pacanovsky – MLV & Company

Good morning. My first question is on the cost side and last quarter your LOE came in high and you talked about a lot of longer term projects you were putting in place to bring those costs down, in this quarter the cost came in high again and now you have raised the guidance. So I guess I just want to get a picture for what’s pushing the LOE up and when you think some of the cost control measures that you have put in place are going to start to bring that number back down again.

Steve Smart

Yeah, Kim this is Steve, I guess our projects that we talk about that we are putting in place this year, a lot of that will not kick-in until the fourth quarter. And that’s going to save both on drilling costs as well as LOE, particularly in the case of water disposal.

So, for this year, we thought like that we are going to trend higher and we hope that we down somewhat in subsequent years because of the cost saving measures we’re taking. And I think just a fact that we’re becoming more of an oil producer, is going to trend LOE slightly higher anyway. So, that’s why we went ahead and change the guidance on that.

Kim Pacanovsky – MLV & Company

Okay. And what have your water hauling costs been doing as of late, could you just detail that?

Ross Craft

Right now, our water hauling using trucks in a commercial disposal site as we were doing before. Water hauling per barrel is ranging anywhere from $5 to $7 of barrel including trucking and disposal.

Currently, part of this infrastructure program we have in place, we have two company-owned disposal systems with water stations associated with them. That’s the part of the infrastructure we’re laying water transfer lines both from – frac water supply lines, saltwater disposal lines and reuse of frac fluid lines. We’re also laying gas lift lines throughout the field, so we don’t have to use these individual wellhead compressors like we’re having to do right now.

All of this will go into dropping our costs substantially because really when you think about it like for the LOE side on the gas or the compression side on the gas lift, we’ve already – on our discharge points in the field, we’re already discharging at a pressure around 1,100 to 1,000 pounds and we already have our compressor set. So, what we’re going to do is come off the discharge side of that and now (inaudible) supply gas at that pressure throughout the field.

Water disposal for example, if you look at that, once we have our lines in place, we eliminate any trucking or commercial disposal, we will take that cost per barrel down from about $5 to $7 a barrel down to about $0.50 a barrel.

Kim Pacanovsky – MLV & Company

Okay.

Ross Craft

And when you look at that cost because of these horizontal wells and you’re putting 250,000 barrels in a frac, you can expect recovery of about 100,000 barrels in the first year set to substantial savings there, vertical wells is the same. Water supply wells, obviously we are moving away from using a part of the water going (inaudible) water supply. And so, when you look at that we are going to take our costs down from somewhere around $3 a barrel, what it is right now to supply water to us down to about $1.5 or $1.6 a barrel.

And so all of that is going to hit in the fourth quarter and you’ll see that continue on to next year. And that’s one reason why we are taking this – the time to do this and build these infrastructure programs, because this is part of turning this thing into manufacturing facility. I wouldn’t be spending this kind of money on the infrastructure programs if I didn’t feel highly confident that performance will continue to improve. This is just part of setting the stage, it’s a thing into a very inexpensive manufacturing process.

Kim Pacanovsky – MLV & Company

Okay, great. Thanks for all that detail. And a second question, can you just tell us what your current thinking is on the D horizon?

Ross Craft

Well, the D horizon, we really haven’t focused on the D very much only because the A, B, and C looks pretty good. The D is obviously has a lot of hydrocarbons. We drilled there, we see quite a bit of gas in it. I think the D program will be more in tune with, as I said earlier, if we want to test the zone between the top of the Strawn up through and including the D zone and put that together, then at that point that’s when we will be looking at bringing the D zone into it. But it’s going to be part of the program where we complete down in the top part of Strawn and all the way through what we call our Canyon and the shale sections there and then up in the D zone.

Kim Pacanovsky – MLV & Company

Okay, terrific. Thanks a lot.

Operator

Your next question comes from the line of Mario Barraza, Tuohy Brothers.

Mario Barraza – Tuohy Brothers

Hey, good morning everybody.

Ross Craft

Hey, Mario.

Mario Barraza – Tuohy Brothers

Hey. Just had one clarification, You guys mentioned earlier in this call that you have no horizontal locations in northeast Pangea today, is that correct?

Ross Craft

We have – in northeast Pangea, we have no booked locations in Northeast Pangea, that’s the area that we had vertical locations and that’s our University Block 54, Block 55 and Block 56 area. And originally our thought was to develop that with vertical wells. Obviously, based on – the operators are adjacent operators and their well results now – and also looking at microseis and looking at the data, we’ve been able to collect through our vertical program, now we’re converting that area into horizontal area as well. And so, that’s going to be part of the horizontal program going forward.

Mario Barraza – Tuohy Brothers

Okay. So it’s primarily – just a way to look at it, now it’s almost currently like a like-for-like switch and you’re on the 500 million barrels of equivalent estimate?

Ross Craft

Yeah, it’s basically just a switching category and switching type of well, that’s what it is. We were a little hesitant at first because we want to get some more data for that area, we haven’t shot seismic in that area, we’re getting ready to shoot some seismic on that to finalize our full coverage of seismic across our field. But we look at that because running one rig, we can only have so much resources that we could move the rig around to. And, so, we started exploring over there with our vertical rig program. And we collect a lot of data from that. Now at this point it looks very conclusive that horizontal wells will work every nicely over there.

Mario Barraza – Tuohy Brothers

Okay, great. That’s all I had.

Operator

Next question comes from the line of Jeff Hayden, KLR Group.

Jeff Hayden – KLR Group

Hey, guys. How are you doing?

Ross Craft

Hi, Jeff.

Jeff Hayden – KLR Group

Couple of quick questions, one when you’re looking at the horizontal wells in kind of central and northeast Pangea, what zone are you guys going to be targeting in those? And then just to make sure, I’m clear everybody kind to talked about the horizons a little differently, when you guys are talking about kind of Wolfcamp D versus the Cline. I think Pioneer said they view it as the same thing. Do you guys consider that – the Cline to essentially B the D or do you view the Cline as a zone below the D.

Ross Craft

I’ll let Qingming answer that one because there is different schools on what the Cline is right now, but here’s our interpretation.

Qingming Yang

Hi, Jeff. This is Qingming, first to your question about those three locations we placed either in central Pangea and also northeast of Pangea, we were liking to drill those wells initially in the Wolfcamp B zone. And, once we get more data from our pilot well in Wolfcamp A, and say obviously going forward that area is likely to be drilled in the Wolfcamp A and say 2, that’s just something down the road.

And then to your second question in terms of Cline shale and really, as you know, right now in the industry there are two school of thoughts. One school is thinking the Cline shale is basically the Wolfcamp B, equivalent to Wolfcamp D, the lower part of Wolfcamp. The other school of thought is the Cline shale is between, top of Strawn and also below the Canyon. That shale interval below Canyon, and really if you look at the entire section here and there is a shale interval in both places. When we drill through our vertical wells, through those sections, we have same shales in both areas, in Wolfcamp D and also in the shale section between the Strawn and also Canyon. And the shale intervals are there, and I think it’s a just a nomenclature and it’s just depending on which company you’re talking to, what they refer to as Cline shale.

I think in short, what this is, if you look at that from the top of Strawn to Wolfcamp, this entire zone is basically charging with hydrocarbon. If you remember, Approach in the past has been mainly targeting the Canyon sand. Basically the Canyon sand is sand which is right between the Strawn and also the north the Wolfcamp B.

So, if you will, you can probably call the entire interval, top of the Strawn to basically Wolfcamp D, the Cline interval. And I think that probably will make it a lot easier instead of you know – different company are calling them (inaudible), it caused a lot of confusion in the industry. But, it’s really that entire interval, which is hydrocarbon charged.

And some areas is more sand rich like in our area, we have Canyon, the other area is basically shale. I don’t know if that answers your question?

Jeff Hayden – KLR Group

Yeah. That helps, thanks guys. Then, just one other quick one. Ross, you can refresh my memory, how many A zone or A bench locations are included in the 500 horizontal well count?

Ross Craft

There’s no A bench locations in the 500 well count, and the breakup of the B and C is probably two-thirds B and a third C.

Jeff Hayden – KLR Group

All right, great, thanks guys.

Operator

Your next question comes from the line of Gordon Douthat, Wells Fargo.

Gordon Douthat – Wells Fargo

Good morning, everybody. Ross, a couple of months ago we talked or I’d heard you mention potentially gaining access to LLS pricing for your oil barrels, and I was just wondering as you kind of look into, as you develop this asset, what are your options for the longer term take away capacity and the potential to gain access to that pricing?

Ross Craft

Yeah, I’ll tell you what, that’s part of a pipeline project that we’re working on right now. I will let Steve go through the details of that, but our ultimate goal is to be able to gain access through the Longhorn system possibly in 2013 to LLS pricing. But Steve, do you want to...?

Steve Smart

I mean, Gordon, as you probably know the Magellan line runs just north of us – runs through El Paso’s acreage. So, we envision either having a spot on the line and we’re constructing up in the southeastern Rabun County where we connect with Plains for the short term. We envision either connecting at some point across that line or it wouldn’t take much infrastructure costs to get us over to, where they have the (inaudible) connection for the future. So, again as I understand the timing on that is still mid-2013 to late-2013 is the timing on when Magellan should be available for us.

Gordon Douthat – Wells Fargo

Okay. So, you’re currently in discussions to gain access there, is that what currently it is?

Steve Smart

Yeah, that’s correct.

Gordon Douthat – Wells Fargo

Okay. And then one other question from me. As you kind of ramp up or gain momentum in the horizontal program, how do you see your longer term production mix changing from 65% average liquids this year towards, what where might that go as you look ahead in the coming years?

Ross Craft

Yeah, it’ll definitely move up and the 65% liquids is a huge accomplishment for us. Obviously what you’re going to be looking at is somewhere up in the 75% to 70% liquids. When you look at these wells, specially the horizontal wells over a 30-40 year life range, what you’re looking at is, the oil is going to be somewhere around 58% to 60%. NGLs will make up the remaining balance and it will be up around 75% maybe even higher, 75% range total liquids. And we’re going to continue to see that continue upward I think. And obviously a lot has to do with our recovery factors too. If we can improve our recovery factors, which we think we will be able to do with downspacing and maybe some tweaking of the frac design, that should help us bring more liquids out of this play.

Steve Smart

Yeah, I think the other thing too to think about is, we have a base load of production from our historical gas drilling that you blend with (inaudible) and for the short term, we wouldn’t see 75% liquids overall particularly the higher oil content you talked about. Just because we are blending historical production that is still producing as we speak, but over time it’s going to begin to ramp up more and more as we develop the field more and more.

Gordon Douthat – Wells Fargo

Okay. Thank you.

Operator

Your next question comes from the line of Robert Miller, Boulevard Trust. The next question comes from the line of (inaudible) Bernstein.

Unidentified Analyst

Hi. Good morning guys. So, you guys ran through the factors in LOE increase kind of quickly. So, maybe can you just go back through that part of the script again a little bit slower. And then I’m wondering as the areal extent of the water and gas compression infrastructure that you’re putting in, has that grown bigger in the last couple of months. Are you seeing cost inflation from your original plan, if this is a little bit of a surprising increase that you are guiding to and so I’m just kind of wondering what’s going on there and trying to kind of figure out is this the last uptick?

Ross Craft

I’ll address the first question in part. Our expenses were higher and it was pretty much across the board. We break down in our 10-Q and in our earnings release. We give details, that breaks down the different parts of our operating expense.

And, so, we saw quite a bit of decrease across the board. Now one thing that you probably heard earlier in the call here is that two things helped us. One, there’s a certain fixed nature of our LOE that will not increase dramatically, even though production’s increasing. So, on a per BOE basis that works in our favor as we move forward. But also the fact that we are an oil company – becoming more and more an oil company, an oil producer, that tends to make lease operating expense higher.

So, the two things may kind of counterweight each other, but the short-term in this year, we are seeing higher cost.

Steve Smart

And as we talked about the projects and how – particularly in water disposal, we should be making savings as we produce water and dispose of it in our own systems, you probably heard Ross talking about what considerable savings on a per barrel basis that can be. Is that helpful?

Unidentified Analyst

Well, no I guess my question really is Ross has been talking about this on the call for the last few quarters, you guys have gone into a lot of detail on what it is you’re spending on and it just grew significantly. So, what I want to know is what’s changed in the last six months and is it sort of a one-time change and hey! We’re going to get over this hill and then we’re going to see the promised land of leverage of this infrastructure or is there another uptick potentially going?

Steve Smart

We don’t feel like there’s another up-tick coming. Ross, I don’t know, if you want to add to that.

Ross Craft

Yeah, what we’re looking at right now is, we bring more Wolfcamp wells – but vertical and horizontal and recompletion Wolfcamp into the mix. Obviously, the water requirement – the disposal requirements on water continues to go up, that’s why we have this infrastructure program that we are in full swing on. That’s one of the reasons why you saw the up-tick.

Also, the gas compression is a big portion of it too. And as we said, we’re laying gas with lines in to avoid the well-head compression that we’re having to put on some of these wells. And so with all of that, the infrastructure – that’s why you’re seeing the increase right now, because of gas lift, compression, water movement, that’s it.

Unidentified Analyst

And now has the areal extent of this investment grown larger. I mean, obviously, we’ve had some movement around – of areas that we thought would be vertical, now they are going to be horizontal, et cetera. So, have we also sort of grown the size of the infrastructure recently and are we now at the maximum areal extent that this infrastructure is going to take up?

Ross Craft

This infrastructure program that we have in place both West Pangea and Pangea should account for about 70% of our holdings, where we’re actively drilling horizontal and Wolfcamp wells. The only areas that would require an additional line sequence would be up on Block 54, 55 and 56, up in that area, but we’ve already got infrastructure in place, since we had to build new infrastructure. The only thing we need up there is a saltwater disposal well and a saltwater line. Everything else is in place.

Unidentified Analyst

Great. Thanks very much.

Operator

The next question comes from the line of Robert Miller, Boulevard Trust.

Robert Miller – Boulevard Trust

Thank you, gentlemen. I had to come back in, with phone problems. I have two questions for you. Are you using in any of your operations the jellied propane, frac fluid that gas frac has? And the second question is, you drilled a well, I think dedicated specifically to water. Are you using that water in your – to frac your own wells? In other words, you’ve got proprietary water for that purpose?

Ross Craft

Yes, as far as – the NGL using the propane fracs. We did a series of about nine wells using propane fracs early on, most of it was geared around the Canyon – tight Canyon gas – and then we did three Wolfcamp wells. The problem we saw was the cost. The process is very good process. No question about it. But the cost just far exceeded the gains that we’ve realized on it, at least in our initial test. I love the product. I think, it’s going to have a lot of influence and a lot of impact going forward, especially in tight gas and tight oil reservoirs.

So, we’re really not pursuing that at this particular time, once gas prices solidify a little bit and we start going back into a full-blown combination of Canyon development and Wolf block then we’ll look at that again.

As far as sourcing the water, yeah, well, our whole goal is to have our own – strategically placed Santa Rosa water wells scattered throughout our acreage. Infrastructure designed around where those well locations will be, our goal is to completely be self-sourced on water and with a combination of using – re-using frac fluids up to 30% to 40% of the total water volumes and using the Santa Rosa water, we should be able to achieve all of that and see a dramatic reduction in our water transport and our water cost.

Robert Miller – Boulevard Trust

Thanks. And one other question, are you having any difficulty acquiring guar gum for – to make things slippery for you?

Ross Craft

No, we really – actually, we don’t use much guar at all, if any; only thing we do with guar and it’s really a different type of basis – are friction reducing agents. This is a purely a slick-water frac to the most part and so we’re not really being affected by shortage of guar. I know other operators have seen some guar issues, but it’s not affecting us.

Robert Miller – Boulevard Trust

Okay. Thanks very much. You’ll be having other, we bought some more with the decline this morning. Hope it goes back up.

Ross Craft

I appreciate it. Thanks.

Robert Miller – Boulevard Trust

Okay. Good luck, guys.

Operator

Your next question comes from the line of Mike Kelly, Global Hunter Securities.

Mike Kelly – Global Hunter Securities

Hey, good morning, guys.

Ross Craft

Good morning.

Steve Smart

Good morning, Mike.

Mike Kelly – Global Hunter Securities

Questions on CapEx, looks like the run rate in the first half of the year was roughly $70 million a quarter. Just doing the math here, it looks like in order for your guys to hit, the $260 million in CapEx for the year, you got to drop that to $60 million a quarter going forward, just trying to – to understand how you guys do that?

Steve Smart

Well, it’s pretty easy. I mean we did 14 recompletions in the second quarter, which is much more than we had contemplated in the original budget. So, for the second half of the year, we’re going to be doing a lot less recompletions. And the product as Ross mentioned that we’re probably doing those in the southern portion of the play. We also anticipate less vertical rig activity. So, that’s how we’re going to get there. We’re still staying in the $260 million.

Mike Kelly – Global Hunter Securities

Okay. Thank you.

Operator

Your next question comes from the line of Tim Rezvan, Sterne Agee.

Tim Rezvan – Sterne Agee

Good morning, guys. I had kind of a follow-up to that last question. You capped CapEx guidance and you capped production guidance, but you raised cost guidance, could you – is that because of a better well performance that you’re seeing or can you kind of reconcile those moving parts for us?

Steve Smart

Well, what we’ve raised was operating expense, G&A and DD&A, so we talked about operating expense and why that’s – and why we see that for the short-term at least being higher. But it doesn’t have anything really to do well performance at all, it just – that we see higher costs in the 2012 period relative to the production, that we are forecasting, that we’re going to hit there.

Tim Rezvan – Sterne Agee

Okay. Thank you.

Operator

Your next question comes from the line of Liam Kelly with Howard Weil.

Liam Kelly – Howard Weil

Good morning and congratulations on a solid quarter.

Ross Craft

Thanks.

Liam Kelly – Howard Weil

Just a couple of questions, concerning the A-wells, and just kind of booking – that’s a final locations for the various benches. First, how long of those A-wells been online?

Ross Craft

A wells haven’t been online very long at all. We just basically turned them on there’s – I think one’s been online for probably on gas lift for about seven days. The other one’s been online maybe eight days on gas lift prior to that they were – we had them flowing naturally for about seven days and six days, but they haven’t been online very long.

Liam Kelly – Howard Weil

Okay, great. Thank you. And then, just as far as, since you guys have the kind of horizontal location count of about 500, and you said, there’s roughly two-third split between, two-thirds of B, and one thirds of C, and no A locations. What’s the process for A locations – your inventories for the A now that you’ve kind of established production there. And then kind of second part of the question is, how do you think about the overall accrual of locations for all three of your horizontal benches?

Steve Smart

Right now, as we’ve said, we’ve talked about down spacing between wells, we’ve talked about the multiple benches. Definitely since we do not have any A benches in our mix of the 500, nor do we have the down spacing in the mix of the 500 either.

At the end of the year, when we finished our end of the year reserves, we’ll have a couple of years on these wells – some of these wells. At that point, we’ll have everything pretty much where we think we can start assigning additional locations at that point, but I’m hesitant to raise anything until the end of the year; but if you just look at two components as you correctly alluded to, the A bench. Obviously, we’re excited about the A bench, you’re definitely going to see A bench wells in a mix and also the down spacing of that locations as well.

Especially when you’re going from 160 acres to 100 acres to 120 acres, you’re going to add quite a few locations just on physical spacing. So, you would see – you should see the locations can increase, but then none of that – none of EUR adjustments or any of those will take place until we do the end of the year reserves.

Liam Kelly – Howard Weil

Okay. Great. Thank you very much. I appreciate the color.

Operator

We have a follow-up question from the line of Irene Haas, Wunderlich Securities.

Irene Haas – Wunderlich Securities

Yeah, a quick question actually on the Mancos Shale, lately there’s been some rumbling and the San Juan Basin as being looked at as such in New Mexico. Do you guys still have acreage in New Mexico, is that still something you eventually could get interested or are there any sort of land issues as such?

Ross Craft

Yeah, we still have the acreage position in New Mexico. Although, there are issues in that particular region of New Mexico with permitting and getting permits; and so, as far as trying to look forward on that, I really don’t see us doing anything on the acreage that we have at this point, it is just too big of the City Hall, we’re having to fight up there for the rewards we’d get.

Irene Haas – Wunderlich Securities

Got you. Thanks.

Operator

And this concludes the question-and-answer portion for today’s conference. I would now like to turn the call back to Mr. Ross Craft for closing remarks.

Ross Craft

Hi, guys. We really appreciate the good questions today. We really like answering questions about the play. We’re making a lot of progress out here obviously going, if you look back two years, three years back, where we were and where we are now. I think, it’s been remarkable ride for all of us. If you look at the future growth potential of this field, what we de-risk at this point is nothing shy of amazing. Well results have been getting better and better as far as we have more operators drilling like-kind wells and that all substantiate what we’ve been saying for the last two years.

Our progress as far as delineating the different benches is moving ahead nicely. I’m very pleased with the results we’re seeing right now. Our main cost going – our main issue going forward and what we’re going to be focusing on is now getting these costs down as a manufacturing type facility. Now we’re working on driving these costs down, as you would see in any shale play as you progress through and go through the testing phase and going into the developmental phase, then you really start seeing a dollar push on these costs.

Hopefully also with the downward push, we are hoping we see an increase in recovery factors on this, we’re using a very low recovery factor on the oil portion 3%, if we can just move it up to 1% or 2%, that’s a huge increase concerning the amount of well in place.

But again, overall, we’re making great progress, we’re moving forward, it’s a great play to begin and we’re very fortunate to have the play under our acreage. With that, that’s it and I want to thank you all and have a good weekend.

Operator

Thank you, ladies and gentlemen for participating. This concludes today’s conference. You may now disconnect and have a great day.

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