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Approach Resources, Inc. (NASDAQ:AREX)

Q4 2012 Earnings Call

February 22, 2013 11:00 AM ET

Executives

Ross Craft – President and CEO

Steve Smart – EVP and CFO

Qingming Yang – COO

Analysts

Leo Mariani – RBC

Joe Allman – JPMorgan

Jack Aydin – KeyBanc

Gordon Douthat – Wells Fargo

Irene Haas – Wunderlich

Welles Fitzpatrick – Johnson Rice

Steve Berman – Canaccord Genuity

Joe Magner – Macquarie Capital

Mike Kelly – Global Hunter Securities

Operator

Good morning, everyone, and welcome to the Approach Resources Full Year and Fourth Quarter 2012 Earnings Conference Call and Audio Webcast. Today’s call is being recorded. (Operator Instructions) 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 takes 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 full year and fourth quarter 2012 earnings release and have been posted to the company’s website under the Non-GAAP Financial Information page at www.approachresources.com.

Also, a new presentation has been posted to the company’s website and is accessible from the Home page. The company also incorporates by reference the cautionary statement regarding reserves, estimates and resource potential that appear in its presentation and at the bottom of its earnings release.

Now I’m going to turn the call over to Ross Craft, Approach’s President and CEO. Please proceed, sir.

Ross Craft

Good morning, everyone. Thank you for participating this morning and for your interest in Approach.

With me on the call today: Steve Smart, Chief Financial Officer; Qingming Yang, Chief Operating Officer; Curtis Henderson, our General Counsel; and Megan Hays, Manager of Investor Relations. I’ll first review our fourth quarter and full year production and year end estimated proved reserves. Then Steve will discuss the financials. I will conclude with a review of our recent well results, our updated drilling inventory and resource potential and 2013 outlook.

Production for the fourth quarter of 2012 totaled 8.5 thousand BOEs per day, up 21% from the fourth quarter 2011. Significantly, fourth quarter 2012 crude oil volumes were up 75% year-over-year and 20% sequentially. Our production volumes in 2012 hit the midpoint of our guidance, or 2.9 million BOEs reflecting year-over-year growth of 24%. Oil production for 2012 increased over 100% compared to 2011 due to our horizontal Wolfcamp drilling. We first discussed the Wolfcamp shale play with our investors and analysts in late 2010. Since then, we have tripled our oil productions. We believe this is an exceptional performance for an oil gas company of any size.

Year-end 2012 proved reserves totaled 95.5 million BOEs, up 24% year-end 2011. During 2012 we increased our proved oil reserves by 106% to 37.3 million barrels and since year-end 2009 we have increased our oil reserves more than seven times.

Our reserve growth is the result of our horizontal drilling in the Wolfcamp play. At year-end 2012 we had approximately 60.1 million BOEs of proved reserves attributed to the Wolfcamp. We booked approximately three to four PUD locations per proved developed location, which is in line with our historical booking ratio.

Current horizontal Wolfcamp PUD locations represent just two to 2.5 years of drilling inventory compared to our multi-decade inventory of identified horizontal Wolfcamp locations. Due to our horizontal development of Project Pangea, we reclassified 8.9 million BOEs of vertical canyon PUDs as probable undeveloped. We will integrate these wells back into our program once we’ve seen net gas ratings closer to $4.00.

We also had 2.4 million BOEs of negative price revisions due to lower natural gas and NGL prices. Overall, we replaced 1,300% of our production at a drill-bit finding cost of $7.45 per BOE. Our all-in finding cost was $13.90 per BOE.

With that I’m going to turn it over to Steve and then I’ll sum it up at the end.

Steve Smart

Okay, thank you, Ross. Revenues for 2012 totaled $128.9 million. Revenues for 2012 were supported by higher production volumes, but offset by lower NGL and gas price realizations. Our average realized price for 2012 before the effect of commodity derivatives was $44.63 per BOE compared to $46.37 per BOE for the prior year. Our average realized price for 2012 including the effect of commodity derivatives was $44.60 per BOE compared to $47.81 per BOE for the prior year.

Net income for 2012 was $6.4 million or $0.18 per share. This compares to net income for 2011 of $7.2 million or $0.25 per diluted share. Net income for the 2012 period included an unrealized gain on commodity derivatives of $3.9 million. Excluding the unrealized gain on commodity derivatives and the related income tax effect, adjusted net income was $3.8 million or $0.11 per diluted share. EBITDAX for 2012 was $83 million or $2.37 per share compared to $79.4 million or $2.72 per share in 2011.

Well expenses trended higher in 2012, which offset increased in production. Lease operating expense for 2012 was $6.58 per BOE. Operating expense rose due to increases in workover compression, water hauling, well repairs and maintenance. Total production ad valorem taxes were up in 2012 due to an increase in oil, NGL and gas sales. Production ad valorem taxes per BOE however were lower in 2012 at $3.20 per BOE or 7.2% of oil NGL and gas sales.

General and administrative expenses were $8.62 per BOE and increased primarily due to higher personnel costs associated with increasing staff and an increase in share-based compensation. DD&A for 2012 was $20.91 per BOE. DD&A increased primarily due to high production and increased investment in the Wolfcamp shale play relative to the estimated BDP reserves book.

Costs incurred for 2012 totaled $297.3 million and included $240 million for drilling and completion, $44.3 million for pipeline and infrastructure projects, $9 million for acreage acquisitions and $3.2 million for 3D seismic costs. Costs incurred for fourth quarter 2012 totaled $82 million and included $10 million for our oil pipeline project.

At year-end 2012, we had $106 million in debt and $174.4 million of liquidity. We provide our current hedge position in the earnings release. We’ve added to our oil derivative positions and now have oil collars covering 2,300 barrels per day for February 2013 through December 2013 at a weighted average floor of $90.18 and a weighted average ceiling of $102.11. Also in effect to limit our exposure to the Midland-Cushing differential we entered into a swap covering 2,300 barrels per day at $1.10 per barrel for the period March 2013 through December 2013.

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

Ross Craft

Hey, thanks, Steve. In 2012, we drilled 26 and completed 23 horizontal Wolfcamp wells. On our last operations update, we provided well results for seven recent horizontal wells targeting the Wolfcamp B bench. These wells on an average IP of 900 BOEs per day were at 79% oil. We’re very pleased not only with the recent results but with the overall development of our project.

On Slide 12 in our presentation we show production data for substantially all of our Wolfcamp horizontal wells, including the seven recent completions in comparison to our 450,000 BOE type curve. The most significant takeaways are the consistent well performance at or above our type curve and the continued reduction in completed well cost.

In preparation for transitioning into a full manufacturing multi-bench development, we spent $44.3 million for infrastructure projects in Pangea West and North Pangea during 2012. We expect to realize approximately $900,000 reduction on our completed well costs as a result of these systems. In addition, we expect to see improvements in operational efficiencies resulting in improved performance and lower operating costs.

Our average horizontal completed well cost was $6.4 million in the second half of 2012. Current well costs are approximately $6 million to $6.2 million and we expect to reach our targeted $5.5 million per well within the next two to three months.

We’re targeting 30% production growth in 2013. Our 2013 horizontal program includes three horizontal rigs. We moved in our third rig in late January. Due to the timing of the third rig, pad drilling and pad completions, as well as step-out wells beyond our current infrastructure systems we expect a more aggressive production profile in the second half of 2013 as compared to the first half. We also provide the expense guidance which we feel reflects a competitive cost structure for an oil company targeting the Wolfcamp shale play, but which we also expect to meet or beat.

All in all, the horizontal Wolfcamp is exceeding our expectations to date. Based on our horizontal well results our vertical well control and 3D seismic, micro-seismic, whole core and log data we have substantially increased our resource potential estimates for the Wolfcamp shale play to over 1 billion barrels of oil equivalent.

This estimate is based on over 200 identified horizontal locations, 120-acre spacing and multi-bench development, as well as over 700 identified vertical locations and 160 re-completions. Assuming 2013 drilling at 35 to 40 horizontal wells, these locations represent many decades of drilling inventory. Importantly, this drilling inventory does not include any locations in the Southern Pangea acreage area.

We’re off to a strong start in 2013 with three horizontal rigs running in the Wolfcamp play. We’re testing stacked laterals, down spacing and expect to have an update on these results in the first part of the second quarter of 2013.

With that, that concludes our prepared comments. We appreciate you participating. And now we’ll start with questions and answers.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And your first question comes from the line of Leo Mariani from RBC. Please proceed.

Leo Mariani – RBC

Hey, guys. Just curious as to when you think you might be testing the southern acreage?

Ross Craft

Good question, Leo. Right now, based on the activity level adjacent to us to the west and then I think there’s some horizontal activity going on even further south than our southern Pangea acreage. We’re going to basically let those guys do some more R&D on it. What we are seeing on it is in looking back at some of our early on re-completions that we attempted down in the southern Pangea area and looking at the production mix on those and kind of how they’re hanging in there. We think at some point we will be populating this area. But right now, we’re going to let the offset guys do. We HBP most of the acreage down there anyway. I don’t think you’ll see us populating the center of it, but on the edges of it, I definitely think at some point we’ll be doing that, but it’s going to be a while.

Leo Mariani – RBC

Okay. And obviously in your update today, you guys fully increased your inventory pretty dramatically, and I guess the most notable part of that was that you added a substantial number of A and C zone wells. I just wanted to get your thoughts in terms of why you’re so confident in the A and C zones. I know you haven’t done all that many wells in those zones.

Ross Craft

Yeah, you’re right; we haven’t done that many of them. But I’m going to let Qingming answer that. One thing I will say before I turn it to Qingming, this is a really unique play in the fact that open hole logs, new open hole logs, if you calibrate them back to our pretrophysical model, which you can do, they really represent a bunch of – what this reservoir can do. So this is one of the few shale plays I can say that you can actually look in open hole logs and say, hey, that’s going to have some merit here and here and here. With that, I’ll let Dr. Q go into more detail.

Qingming Yang

I think that he’s right. Leo, as you know, Approach has drilled several hundred vertical well bores across our acreages. Obviously, a lot of those wells were initially targeted in a canyon. However, we collected a lot of well logs across these well bores.

Those well logs allow us to correlate the Wolfcamp shale play across our acreages and in addition, we have used well logs from offset operators to correlate them as well. And also we have 3D seismic data covering every acre of our acreages as well. With this 3D seismic data, it allows us to map the continuity of Wolfcamp shale, too. In addition we have found in the micro-seismic data in those Wolfcamp A, B and also C bench, and we feel very comfortable what the well spacing might be, what the drainage area might be. We feel 120 acres per well is a very good estimate right now.

And finally I’d like to say Approach right now has drilled about 40 horizontal wells in the play. We have completed 34, 35 of those wells and some of those wells have production data for a year and a half coupled with the horizontal wells from the offset operators. So we feel very, very comfortable to populate those physical locations across our acreages and based on the initial three wells we drilled in Wolfcamp A bench and it looks like those wells right now are going to be above our type curves on average.

And one of those wells is close to 500,000 BOEs. And for the first Wolfcamp C bench wells we drill and even though we did not line that well optimally but it looks like that well is still going to work into make some money on that well as well. So given all the datas we have, also the well results, we feel very comfortable to populate 2,000 of the locations across the 107,000 gross acres we think we have de-risked.

Leo Mariani – RBC

Okay, that’s helpful, guys. And another question here for you; I know obviously you had some pretty good rates on these last seven wells – 900 barrel a day type of IPs. Can you comment on what type of 30-day rates that you’ve been seeing in your recent wells?

Ross Craft

Yeah. What’s amazing about this play right now is the consistency of the data coming from the wells. If you complete these things right, what I call properly, what we’re doing, at least keep it consistent, your results are going to be very consistent. And likewise, your 30 and 60 and 90-day rates are extremely consistent even though we don’t have 90-day rates on some of these first seven. But if you look at our 30-day rate, it’s going to be up in the mid-500s, about like the rest of the wells we have, and then our 60-day rate on those wells is going to be up in the upper 400s. We don’t have any 90-day rates except on two wells, and I can tell you, on those two wells I think it’s closer to 500 90-day rate.

So everything is very consistent to what we’ve been saying in the past. That’s the nice thing about this play. And actually if you go back and look at the type curve and all the production data that we’ve populated in the presentation, if you go back and look at that what you’re seeing is a definitely a more consistent upper-end range of these wells, and I think that’s important.

As we drill more and more of these wells and we get our, we get this thing into a manufacturing mode where everything is just a manufacturing, everything is repeatable like a recipe, it looks like these well performances are improving. Also, we have more historical data on these wells now even to 400 days and beyond. Plus we have all the data coming out from the Southern Midland Basin as well from other operators. And all this data that you see is pointing to the same thing, that this is a very solid play.

Obviously, our type curve that we use, a 450, some might say it’s conservative. We definitely have wells that are going to definitely beat that. We have wells that are going to be slightly underneath that. We like our 450 type curve only because from a statistical standpoint it’s going to give you a safe number to look at. And knowing, if you know us, and what you do, we try to fill out safe numbers. And so from that standpoint, you know I like the play a lot. Our performance is right in line. When you have as many wells on one scatter plots as we do now and you can all see the actual production, it’s a very comforting feeling that the type curve is holding up like it is and our well performance is improving. That’s exactly what you want to see in a play like this as you progress forward.

Leo Mariani – RBC

All right. Thanks a lot, guys. Appreciate the color.

Operator

Thank you for your question. Your next question comes from the line of Joe Allman from JPMorgan. Please proceed.

Joe Allman – JPMorgan

Thank you. Hi, everybody.

Ross Craft

Hi, Joe.

Joe Allman – JPMorgan

So just a follow-up to Leo’s questions, in terms of the data that you used to come up with the locations for A and the C in particular, it may not hurt to talk about logs and seismic and micro-seismic, but what well data, what horizontal well data did you have to give you the confidence in booking the locations for the A and the C in particular?

Qingming Yang

Sure, Joe. You know for Wolfcamp A bench, we have drilled two Wolfcamp A bench wells in Pangea West. And we drilled one Wolfcamp A bench well in Pangea area, and both of those wells, actually we have plotted the production data from our Wolfcamp A bench well on Slide 12, if you happen to have a copy of that presentation we published late last night. And if you look at the production data over there for the Wolfcamp A bench well, those are the red dots over there. And those two wells right now, it looks like they’re going to beat our type curve of 450. The average is probably about 460,000 BOEs. It looks like those wells, those A bench wells, the performance of those A bench wells are very consistent.

And as I mentioned earlier, so what we do is we compare those three wells with the rest of those acreages to see if there’s any geological similarities or differences. After our correlation across our entire acreages, we find those Wolfcamp A bench wells, a, can correlate across miles and miles and the rocks are very similar, the morphologies are very similar and we think the rock qualities are very similar. We expect similar well results across our acreages as well. And that’s really – those horizontal well results and also the well logs give us a lot of confidence. Again we collected a micro-seismic data, as mentioned earlier, and we are able to map the fracking height and also the weight of those fracking as well. We feel very comfortable how much those wells would likely to drain from that section.

In terms of Wolfcamp C bench, and so far we have drilled one Wolfcamp C bench well, we have several months of production data from that well. Initially we landed the Wolfcamp C bench well a little bit higher. And we think when we landed that C bench well, in the middle part of the C bench, that well should beat our type curve. Our initial well is actually – even though we did not land that well optimally, it looks like that well is going to do – have an EUR of north of 350,000 BOE or so. But if – when we land that well optimally, we think that’s going to beat our type curve. You may also noticed not long ago – just couple of months ago EOG published a well from Wolfcamp C bench as well. That well is actually located in the Reagan County. As you can see, those wells are located miles apart, but however, those wells looks they’re delivering the similar results in terms of – actually that well had an IP of over 1,000 BOEs.

Joe Allman – JPMorgan

Okay...

Qingming Yang

And again, from what we have seen and the well results, the well log correlations, and with 3D seismic data covering all our acreage, the micro-seismic data and we feel populating those physical locations across 107,000 acres is justifiable at this point of time.

Joe Allman – JPMorgan

Okay. That’s helpful. So, yes, I know EOG announced that successful C bench well with its third quarter earnings. Can you think about any other operator or any other EOG wells in the A or the C that you use in your data to help with your location count?

Qingming Yang

That’s right. And, Joe, you remember EOG also drilled successful A bench wells in Irion County as well. Actually drilled several of those successful A bench wells in Irion County. And initially, they also drilled a C bench well and I think at the very beginning those C bench well is just like our initial wells because those wells were not lined in optimally. But once those wells lined optimally those wells give very good results. We think one of the things about the Wolfcamp shale is the thickness across the southern Midland Basin is very consistent, about 1,000 feet to 2,000 feet thick. Each of those benches is about 300 feet to 350 feet thick. And then the morphology; the well performance is very much related – the oil and gas in place, the rock characteristics and also the fractures.

And when we see geologically how consistent the Wolfcamp is across our acreages – actually across EOG’s and also other offset operators’ acreages as well – if you drill those wells and complete those wells properly – I want to emphasize, you have to complete those wells properly. If those wells are completed properly, it looks like those wells are capable of delivering 450,000 BOE or more. I think EOG is forecasting similar EUR for those wells as well.

Joe Allman – JPMorgan

Okay. That is helpful. And Qingming, when you came up with this location count, what kind of risk factors did you put in? So there are probably some at least geometric issues and there may be some geology issues as you go across various parts of the acreage. So if I take the number of acres and I divide it by the spacing, I come up with a higher count than what you’re giving for each category. So what kind of risking did you do?

Qingming Yang

That’s a very question, Joe. Because of that rate – that’s exactly right. If you just use 107,000 gross acres and if you divide in 120 acres per well, you’re going to get higher location count. The main reason for that is in the area, we want to make sure our horizontal wells is going to be approximately 7,500 feet in length. It could be plus or minus a few hundred feet and in the areas, if we have this geometry issue, for example, if we only have half of a section, we were not able to place the horizontal wells and we did not place the horizontal locations over there.

And at those locations we think we can develop those with vertical well bore. And also in the areas where we have canyon wells, canyon PDP producing wells, and we did not place horizontal Wolfcamp locations there either. Because we think in those areas what we can do is, later on we can either re-complete those canyons in the Wolf work section or we can infill with canyon Wolf work wells later on. So we only put the locations in the areas we think with help of the seismic data and with – we can geometrically place 7,500 feet or 7,000 feet or 8,000 feet lateral locations over there.

Joe Allman – JPMorgan

Okay. That’s helpful. I’ll get back in the queue. Thank you.

Operator

Thank you for your question. Your next question comes from the line of Jack Aydin with KeyBanc. Please proceed.

Jack Aydin – KeyBanc

Hey, guys.

Ross Craft

Hey, Jack.

Jack Aydin – KeyBanc

A couple questions. Ross and Qingming, what do you expect to produce first year out of those wells, out of the 450,000 EURs?

Qingming Yang

Jack, in those wells, on average, they’re going to produce about 85,000 to 90,000 per year for the first year.

Jack Aydin – KeyBanc

What do you, how do you compare that kind of production to some other people in your neighborhood? Do you have...

Qingming Yang

Sorry, go ahead.

Jack Aydin – KeyBanc

Do you have data for other operators, what they produce in the first year in any indication?

Qingming Yang

That’s a very good question. If you look at the West area, the operators which have more than a year or 1.5 years of production sheet, it’s probably EOG and Approach. And there’s also a couple of other operators which may have a few wells like that. I think when we compare our wells with the offset operators and our results are amazingly very similar.

Jack Aydin – KeyBanc

Okay. Now...

Ross Craft

In fact, Jack, also on that, we were able to look 21 wells that had history on them and that are within a five-mile radius of us. And those wells in their first year, the data that we have, are strikingly similar to what we have.

Jack Aydin – KeyBanc

Okay. Now the question on the well costs – you mentioned that right now your well costs are about $6 million to $6.2 million. Can you give us a range, the latest AFPs that you’re getting, what was the range? The low end, the high end and then please break down for me the saving of $900,000 that you’re talking about, where are you going to get those savings? Could you break it down for us?

Ross Craft

Yeah, sure. Let’s address the AFP. I think I just signed an AFP that was for $5.6 million. There’s been several that have crossed the desk recently ranging from $6 million all the way down to $5.8 million. But that gives you an indication of where our head is on right now and which direction we’re going. Obviously if you have well issues, it’s going to give you a higher number but we don’t look at these wells when we’re writing AFPs that we’re going to have a well issue. But that’s where we’re stacking out right now. Obviously we’re not going to be finished with the southern piece of the 45 infrastructure program until probably another month and a half and then at that point we’ll have our infrastructure completely in place at least in our major areas.

Now to give you a breakdown in cost and so you can find the $900,000, what you’re going to see and what this infrastructure program is that we’re installing is really a series of transport pipes. We have – since we already know our pad development plans across all of our acreage, we’ve already identified where the pads are. We’re laying water transfer lines to bring frac water, both fresh and saltwater to each location.

We’re also – have in that same area, we have saltwater disposal lines that brings flow-back and saltwater produced the only way and brings it back to a treatment facility. We have gas flip lines on every pad. We have gas lines, oil lines. By doing that what you get to do and also part of our $44 million we spent this year was to drill a bunch of Santa Rosa water supply wells. And we also have I think five saltwater disposal wells and facilities we’ve added this year.

So here’s how you get down to it. When you look at the fresh water cost historically, fresh water out here has been running us anywhere from $2 to $3 a barrel, including trucking in. The further you get away from our acreage, the more expensive fresh water is. We use on average about 250,000 barrels per well. That’s on average. Now, water source is going to be, if you just look at it from the Santa Rosa make-up it’s going to be more like $0.25 a barrel but you’ve got to treat for the Santa Rosa because it’s got some sulfates in it. So your treatment costs to get it to the, what I call frac state, is going to cost you about another $0.80. So right there you’re going to save a little bit of money. That’s a big savings.

Your second biggest savings or your biggest savings actually is saltwater disposal. Saltwater disposal in these wells when you look at these AFPs and look at these wells, you’re going to get about somewhere between 180,000 barrels back in the first six months of the 250,000 barrels you produce, or you inject into it. Commercial disposal sites and trucks in the area to go to a commercial disposal site and the time required, trucking hours, your cost is $5 to $7 a barrel. So when you figure 100,000 barrels, $5 to $7 a barrel, you can eat up a big chunk of it. Now our cost is about $0.50 a barrel. And it’s probably going to be much lower because also in the $0.50 a barrel, that includes operating cost as well. But that’s why we put our own saltwater disposal systems in place.

So now we eliminate trucking, we eliminate any commercial disposal sites. The saltwater disposal wells that we drilled are all deep Ellenburger disposals. We also get to recover the skim-off that would come off these flow-backs, which is anywhere from 3% to 5% of the volumes. That’s a large amount of oil that gets recovered that we’ve been shipping off.

And so when you start looking at that, you’re right there, you’re about $800,000 and then also by having water transfers in place, having our frac pits, our saltwater storage facilities, because we’re going to be using a lot of flow-back water, our goal is to use flow-back and produce water as much as we can. We want to completely try, if we have enough of it, to try to do 100% fracking with the flow-back fluids. And so when you start looking at that savings you’re going to have to save about $150,000 per transfer lines that you normally would have to rent or have a crew in. So that’s kind of where you’re getting to in the numbers, and that’s how that 900 fits in. It’s pretty, pretty much of a very reasonable progression.

Jack Aydin – KeyBanc

Thank you for your – thanks. Thanks a lot.

Operator

Thank you. Your next question comes from the line of Gordon Douthat from Wells Fargo. Please proceed.

Gordon Douthat – Wells Fargo

Hi. Good morning, everybody.

Ross Craft

Hey, Gordon, how are you doing?

Gordon Douthat – Wells Fargo

I’m good. How are you doing, Ross?

Ross Craft

I’m doing well.

Gordon Douthat – Wells Fargo

Quick question for you, since you’ve laid out your location count now and you’ve got a kind of a better handle on the down spacing, the different ventures and how that resource potential looks, I know you’ve been asked this question before, but how do you think about bringing forward value from all these locations as you kind of formulate a longer-term development plan on this asset?

Ross Craft

That’s a good question, very good question. Obviously having this type of deep inventory of locations, it’s a good thing and it creates challenges as well. And the simple answer to your question is more rigs. That’s the simple answer to the question. Now let’s get into how we’re going to bring more rigs in because we as a small company have to be careful. And so right now with three rigs we feel we’re very comfortable with three rigs operating right now. We want to make sure everything runs smooth with that, get our infrastructures in place, make sure we have enough water to be able – to complete these wells with and that’s a big issue. And then our goal is to add a rig every year up to a maximum of six horizontal rigs. That’s kind of our master plan at this point. The grey area is 2013.

Depending on our success in 2013, you know we got off to a late start with the third rig. The third rig didn’t show up until mid to I think the third week in January, so it’s just now getting going and – good. And so depending on results, which we think part of our first half of this year is based on drilling stacked laterals and testing the stacked concepts. Once we get the results back on that then if we want to accelerate and bring in a fourth rig sooner than later, that’s always in the cards. But that’s kind of how you bring the value forward is by adding the rigs.

Now with that being said, you don’t want to get too far ahead of your skis and you want to make sure that the rigs that you bring in you’re actually saving money. And that’s kind of why we’re taking these slow steps. We want to make sure that this manufacturing mode that we’re going into that we don’t outpace the benefits of the manufacturing mode. And so that’s why we’re taking it slow and easy as compared to some of these other operators out there that are putting in seven, eight, ten rigs. But that’s how you bring the value forward.

Also we hope that as we continue forward that we, by having infrastructure, having this economy of scale, that our overall cost structure will drop. And we think that’s a very strong possibility, that the cost structure will come down, LOE will come down, DD&A will come down somewhat. And that’s all part of the plan, but right now we wanted to make sure that the numbers that we’re putting out, make sure that everything we’re doing sets us up for a successful move-forward on it.

And so we’re going to be a little bit slower than other guys are but at the same time I think that every step we make is well thought through. Yeah if you could move faster – we definitely probably could move faster but with our cash flow scenarios and stuff like that we’re going to just have to take it easy. Again six rigs is what we’re thinking about ultimately. That could change up – could come back but six rigs seems to be where our comfort level is.

Gordon Douthat – Wells Fargo

Okay. Is it something that you’d consider bringing a partner in to help you accelerate or for now do you want to keep this asset to yourself?

Ross Craft

Well we all saw the wonderful price that Pioneer received on their joint venture. That was a heck of a deal they did. And so the main thing that we want to do right is complete our evaluation, our testing of stacked laterals. It gets back to the 2,000 locations. We want to make sure we fully understand the upside potential of stacked laterals, the communication between the laterals and we think in the next six months we’ll be able to have a good understanding of that.

At that point then we’ll be in a position to look forward and it could be that we brining in a partner at that point or it could be that we don’t. We retain it all for our self and move forward with some other type of financing. High-yield is definitely an option right now going forward, but I want to make sure I get everything tied together where I feel 100% confident in everything we do and I think that’s going to be about mid-year and then at that point we have all these options that we can look at.

Gordon Douthat – Wells Fargo

Okay. Thanks.

Operator

Thank you for your question. Your next question comes from the line of Irene Haas from Wunderlich. Please proceed.

Irene Haas – Wunderlich

Yeah. Hey, good morning. I have two questions. Firstly, can you give us a little color on your timeline for the stacked lateral, how much time you’re going to spend on it? And in the ideal world, how does it work? And secondarily, just a bigger picture question is really the competitive landscape in the Permian. You guys have captured $1 billion. I’m sure your other competitors have captured quite a few billions too. So it doesn’t take much to add up to a proved oil base sitting right there in the Permian. And how do you think of transportation out of the basin? And importantly, really competition from the other sort of light sweet crude-generating provinces?

Ross Craft

All right. Qingming is going to take the first one. I’ll follow up with the second. How about that?

Qingming Yang

Sure. For the lateral, Irene, what we’re thinking right now, we work into one A bench well stacked right on top of a C bench well. And then for the B bench well, there’s going to be a chevron sort of geometry. So the B bench well is going to be offset in by from A and a C bench well for about 300 feet to 350 feet on a macro view. But for the same bench, so for A bench, B bench or C bench, for the same bench, they’re about 600 feet to 700 feet apart from each other.

And each of those wells, from that same bench, the drainage area is approximately 120 acres or so. And right now, we have just finished drilling four stacked laterals. Those are A, B and A-B pairs. Those wells are being completed right now as we speak. And also we’re in the process of drilling A-C stacked lateral as well. And based on the initial drilling information we got, it looks very, very encouraging, very positive and hopefully we’ll share the results of those wells in the next quarter, second quarter.

And we’re very optimistic about those laterals and because we have the oil and gas in place. When we tested them separately and all those wells are coming in type curves or above or type curves, and now the question is by doing stacked lateral, by doing them close to each other, there’s a very good chance we can enhance recovery factor. Even right now, when we put raised stacked laterals in the Wolfcamp shale, assume they all recover 450,000 BOE per well.

The recovery factors for oil for the Wolfcamp shale is less than 4% and for gas it’s only 10%. The weighted average is only about 5%. That’s a very low recovery factor. By doing stacked laterals, if we can let’s say increase our recovery factor by a percent, then the increase in resource potential is 20%. So it’s huge. That is a raise we would still like to spend a little bit of time in next few months to understand this fully before we launch large scale development. And I think we’re well on our way and we should have those data in the next quarter or so.

Irene Haas – Wunderlich

And would it save on your well costs? Because you are trying to target $5.5 million, when you drill these stack laterals because of the proximity, could you squish the D&C cost downwards?

Qingming Yang

That is a very good question. That’s another consideration obviously in drilling those stacked laterals from the same pad. You know from one pad, we can potentially drill up to six laterals from just one pad. And that’s going to help decrease mob and de-mob costs and also decrease the number of days in terms of from start to finish. And also it helps us to be able to complete those wells in patch as well. So as we drill four wells from the same pad or from two pads or six wells and then we can complete them at the same time in patch. It’s going to delay our initial production a little bit, but in the long run, once we drill enough wells, those production delays will be smoothed.

And definitely that’s going to save our costs, just mob and de-mob alone per well, that could save anywhere between $60,000 to $100,000. And in addition to that, it’s also going to minimize the surface disturbance as well. So there are a lot of benefits in doing pad drilling, doing stacked laterals.

Irene Haas – Wunderlich

Great. Thank you.

Ross Craft

Yeah, now to get onto your question about the activity level and the amount of oil that everybody’s forecasting to come out of the Permian, obviously the Permian – and it’s not just to this area, the whole Permian Basin is, based on its history and based on just the innovation that’s going on in the Basin, has put a whole new life in the Basin. When you look at that and look at the older systems in the Basin, everything’s got to be redone. There’s no question about it. That’s the one reason why we’re joint venture on a 38-mile pipeline, oil pipeline that we should have oil going down it by April. That will help us get our oil out and we think that’s going to be a big benefit to us long term.

But even beyond that, even looking out beyond the West Texas Cushing differentials and staying in that same corridor, let’s say you want to go to the Gulf Coast, you want to go to the West Coast, obviously, the Gulf Coast is the closest place right now. You’ve got the Magellan system that’s crossing right now. There’s been a delay on that system but it’s still going to be I think first half of 2013 it’s going to be operational. There’s a possibility that we’ll get access on the Magellan system via Crane and back down to Houston. That will offer some assistance at that point.

I think one of the bigger and one of the most promising things right now would be to get to the West Coast and get out in that area. And I think there’s a couple of major projects going on right now. There’s one project, there’s a new rail system that is being constructed not too far from us. It’s going to have about a 70,000 barrel a day capacity on it, rough capacity, with a 200,000 barrel storage capacity, plus or minus. That’s going to be a 2014 project.

That’s got options. Also getting on with some of these major oil shippers, the Plains people, things like that, those big guys tying in and coordinating activities with those guys and getting it to long-term relationships with them also helps because then they can deliver into their major systems on the West Coast and I think that’s going to have some benefits at some point down the road as all the oil trash compete for places on the Gulf Coast. So all these things are evolution projects out here based on the success that we’re seeing, and there’s no simple answer.

We’re taking steps. Obviously this pipeline is a big deal we’re doing with 38 miles, would size all of our stuff in on pipe so we eliminate the trucks, also reducing our differentials. And then anything we do beyond that, going west, going east obviously has benefits or we wouldn’t do it. But we’re staying very flexible. This is a very dynamic situation we’re in right now with the amount of production increasing out of the Permian and I don’t think it’s going to slow down anytime soon so – but that’s kind of how we look at it right now.

Operator

Thank you. Your next question comes from the line of Welles Fitzpatrick from Johnson Rice. Please go ahead.

Welles Fitzpatrick – Johnson Rice

Good morning.

Ross Craft

Hey, how are you doing?

Welles Fitzpatrick – Johnson Rice

Good. I thought that the University 45 D 905H was an A well. Is it just, not have a history to really being instructive to be included on the type curve slide? Or was that not an A bench?

Qingming Yang

Yeah. You’re right, that is an A bench well. It looks like that well right now is – we probably should plot that well on this type of curve as well. That well is going to be making about a 410,000 to 450,000 BOE, yeah.

Welles Fitzpatrick – Johnson Rice

Okay, perfect. So it’s right in line with the other guys.

Qingming Yang

You’re correct. Yeah.

Welles Fitzpatrick – Johnson Rice

Okay. Great. And then did you guys ever give the split out of the 35 to 40 wells on A, B, C?

Qingming Yang

Those wells, we have three A bench wells and one C bench well and in addition, recently, those – when we talk about 40 wells, we drilled three additional A bench wells and they’re also going to be some additional of the C bench wells. Those wells are waiting on completions.

Ross Craft

On a go-forward for the rest of the year, though, our mix, we’re going to continue to test the stackeds, the A and the Cs and the B and As, and so there’s going to be probably an even mixture of As and Bs. And then on the flipside of that, we’ll probably have, a third of them will have Cs in it – with stackeds playing with these stackeds.

So what we’re trying to do with the stackeds right now is to calibrate our model on – and it’s kind of the drainage model that we’re using. As we’ve told you all before, we look at this as a volume chamber, and so what we want to see on this is the stacked laterals and how they influence each other. And what we’re thinking is that this volume chamber is going to be what you focus on, and so you look at what the total volume is. And say, 450, three wells on the volume chamber, we want to see how they interact and how they relate. Obviously, the C bench was very interesting.

As a matter of fact, when you look at the logs on C bench, you can make a very good argument that C bench is your secondary target out here because it’s very strong. And having that frac barrier in the C bench is very good. And so we’re going to be playing with that, but like I said, it’s going to be about one and one on Bs, and then you’re going to be mixing Cs in it for the rest of the year.

Welles Fitzpatrick – Johnson Rice

Okay. And does A, B pairs – those are in a chevron or a saw tooth type pattern?

Ross Craft

That’s correct. What you’re going to see is on – if you’re looking at it from a full three-bench development, you’ll have the As and the Cs will be stacked on top of each other, directly on top of each other. The B will be offsetting it, and so you’ll have this little chevron approach all the way across the field.

Welles Fitzpatrick – Johnson Rice

Perfect. And I hate to backtrack a little bit, but just to make sure I heard you right, the 1001H, you said it’s about 350 on the EUR, but EOG’s results in those logs give you the confidence that those are going to end up in the 450 range? Did I hear that right?

Ross Craft

Yeah. What we did, and it gets back to the micro-seismic we ran on it and when we – actually I gave a presentation earlier this week to SBE in Houston about that. And what was – what the micro-seismic showed us – and we didn’t know this, I mean when you look at the logs out here, and they’re easy to correlate over a very large area, you see between the C and the B, you see a little 10-foot dolomitic streak that’s in there. It’s just a type streak. We see that throughout our whole deal, through the B and the A where we landed with the same thought process as we normally do in the B, get in the upper portion of it.

When we ran the micro-seismic on it, it was very obvious, more obvious than any of them I’ve ever seen before, that you see a frac barrier, the frac went straight up, hit the barrier and went out. And to have it that consistent across all 30 stages, it was amazing. And so when you start looking at that and say, okay, we also had problems getting those fracks away because we were overshadowing because we weren’t going up in height, we were going out horizontally. So we were competing, each stage was competing for pressure space. And the whole frac wasn’t very good. We pressured out on several stages. I think we got 16 stages in, something of effective stages. And so when you look at that and dropping it back down about 150 feet into the C bench.

And remember the C bench, we’ve taken cores out of this, it’s saturated just like the B bench and the A bench is. And to go on down in the C bench and actually get effective frac where you’re getting a true 350-foot growth around this well bore than at that point you can start seeing that. I think the EOG well shows you what happens when you land and get down where your frac is more efficient, where you actually break rock and that’s what you’re looking at.

And what we’re seeing right now is there’s not a lot of difference between these zones, initial completions, there’s not much difference. So but to answer your question, yeah, that’s kind of with what we see on logs, what we see from the EOG stuff, what we saw from our stuff, we feel very confident that the C bench will be a large portion of this.

Welles Fitzpatrick – Johnson Rice

Perfect. And one just real quick modeling one. The Midland-Cushing basis hedge looks pretty attractive. Is that a flat $1.10 for the whole contract or is it maybe a little bit higher, kind of dropping in to December like you might expect?

Steve Smart

The $1.10 contract is throughout the year. They priced it that way. So month-in, month-out, it will be $1.10.

Welles Fitzpatrick – Johnson Rice

Perfect. Thanks so much, guys.

Operator

Thank you for that. Your next question comes from the line of Steve Berman from Canaccord Genuity. Please proceed.

Steve Berman – Canaccord Genuity

Thanks. Good morning. Just one more question. On the G&A side, and I know some of this will come from operating leverages is just spreading costs over growing production, but can you just tell us how you’re going to get, in addition to that from the $10.79 per BOE in Q4 to your $7 to $8.50 guidance for 2013, how those costs are going to come down?

Steve Smart

The $10.00 marker you mentioned would be impacted by year-end type activities that wouldn’t reoccur throughout the year like bonuses for our staff. Also to the extent we had not accrued anything for the management bonuses, those things can distort those numbers a little bit. So we really don’t see it being difficult to get to our new guidance range. And as you mentioned, as you increase production you don’t proportionally increase staffing, then it should go down. So we still believe the volume part of it is obviously going to bring it down.

Steve Berman – Canaccord Genuity

All right. Great. That was it for me. Thanks.

Operator

Thank you. Your next question comes from Joe Magner from Macquarie Capital. Please proceed.

Joe Magner – Macquarie Capital

Thank you. Just wondering on the $1 billion BOE of gross un-risked upside, any way to I guess provide a ballpark estimate how that nets down to your interests?

Ross Craft

Yeah, I mean when you look at the $1 billion that’s a gross number, and for the most part what we have out here we have 100% for the most part working interest in the majority of this stuff. And about a 75% net revenue interest out here. So if you use those numbers you’re right in the ballpark.

Joe Magner – Macquarie Capital

Great. Thank you. And then you mentioned that you’ve got some new infrastructure projects coming on soon and the pipeline will be completed, as you look out beyond 2013, what other additional infrastructure needs might you have on laying additional pipes or putting in place processing, anything else you can elaborate and provide us with some info for?

Ross Craft

Yeah. For us, that’s a very good question. Obviously we spent a lot of money this year on infrastructure, but we feel the money we spent was necessary to take us to the next level. When you look at going beyond 2013 in the areas that we would have additional infrastructure spend in, that would be over in the eastern – northeastern corner by our acreage up on what we call the 54, 55 and 56 area in Schleicher County. It won’t be near to the degree of what we’ve already done down to the south because we’ve already put gas lines in it, and so we have 8-inch gas transmission lines through the whole area.

But what we’d need to do there is go in and put water lines, gas lift lines, so we had the complete system. But that would be a 2014 type environment, that wouldn’t be in a 2013. Likewise over in the eastern portion, not the northeastern but the eastern portion of Central Pangea, we probably have five miles of system that we will have to put in at some point over there. But those are all 2014 type venues. If we – if we’re – accelerate that for any reason that means we’re having great success and we’re going to ramp up the program some more. But those are all 2014 type environments, 2015; other than that it’s not uncommon, I think even this year we’ll have $5 million to $6 million in infrastructure carry-on each year, just looking – and that’s normal for us.

Joe Magner – Macquarie Capital

Okay. That’s all I have. Thanks.

Operator

Thank you. Your next question comes from the line of Mike Kelly from Global Hunter Securities. Please proceed.

Mike Kelly – Global Hunter Securities

Thanks, guys. Good morning.

Ross Craft

Hey, Mike. How’s it going?

Mike Kelly – Global Hunter Securities

Good, Ross. You mentioned that you expect production growth to really start to ramp in the second half of the year as you move into development mode and the question for you is that if you were running full out manufacturing mode from day one in 2013 with the three rigs, what do you think the production growth could have been versus the 30% you have out there now?

Ross Craft

That is a good question. When you look at it based on purely – let’s just take it in two steps. Let’s take it based on purely the number of wells you drill and if you can get them online quick enough. And that’s one of the key ingredients because when we go to pad drilling like we’re doing you have a startup delay because what you have to do is drill both pad wells, drill the pad next to you and then move to the third pad before you start fracking the first pad.

And so that delay is the delay we’re talking about right now. And so once you get past that first delay then everything is seamless at that point because you have a manufacturing. So if you were there right now and you had three rigs running you definitely could go much higher than the 30% because you’re bringing everything on much quicker.

Also one thing we have to keep in the back of our heads and that’s one thing that we build into this thing. When we project our growth production, growth volumes because we’re pad drilling now and because we’ve drilled several wells throughout these leases the amount of shut in wells we have to do to frac is fairly large. For example, right now, we probably have a million a day shut in – I mean 1,000 barrels a day shut-in right now while we’re fracking around it. Because what you don’t want to do is produce when you’re fracking next to it. And so we try to shut these wells in about two weeks prior to the frac being initiated.

And we’ll shut in wells up to a quarter mile away all the way around it. And so you have a fairly large amount of shut-ins. We tried to bake that into our production growth this year as well. Because – and that’s where the wild card is because we go onto full development like we are plans are then we’re going to – once we get past this first bunch then at that point we’ll have fewer wells shut in because now we’re moving across the acreage. And so that’s what’s going to hold us up right now is just getting caught up with that. But you should have – if everything’s in a perfect world and you just figure the three rigs running you’ll blow through the 30% pretty damn quick.

Mike Kelly – Global Hunter Securities

All right. Very helpful. Thanks a lot.

Operator

Thank you. Your next question comes from the line of Joe Allman from JPMorgan. Please proceed.

Joe Allman – JPMorgan

All right. Thank you, guys...

Ross Craft

Joe, didn’t I just talk to you?

Joe Allman – JPMorgan

Yeah, about 45 minutes ago.

Ross Craft

Dang.

Joe Allman – JPMorgan

Hey, Steve, in terms of that basis hedge, I think the differential now is below $1 versus WTI so are you afraid that it’s going to blow out again or...

Steve Smart

Yeah. I think they’ll bumps in the road with Magellan coming on. They’ll be bumps in the road on Seaway which we’ve recently seen some announcements around that. And the continuing concerns about bottlenecking because of all that. Bottlenecking up at Cushing, so to me it was a cheap insurance marker to take that hedge out and obviously it’s not 100% of our production, but it gives us some insurance that we can kind of keep that under control. So it kind of is a no brainer in that sense.

Joe Allman – JPMorgan

Gotcha. That’ helpful. And then in terms of your efforts for cost savings and efficiency, all these different infrastructure projects, has the capital pretty much been spent on those? And what kind of infrastructure spending are you expecting for 2013?

Ross Craft

2013 we have some carry over cost on 2013 that originally, and it’s not much, I think it’s probably $6 million that you might see us spend in 2013. And that’s going to be up front 2013. That’s what we’re doing finishing right now. Other than that, there’s no major plans to bring in additional or start construction of any major systems in 2013. With our current drilling focus right now, that’s one reason why we focus these particular systems where we did. Pangea West is completed.

For the most part I think we had 3,500 feet of line we had to lay there, which is nothing. Northern 45, Southern 45 will be completed in about a month. Baker system is up and running. So for the most part everything is covered. The only areas as I said earlier that we’re going to be expanding on as we move out would be the Central Eastern Central and Northeastern areas, and actually we’re drilling a well over there right now. And so once we have this well down and get it online and test it, we’ll be able to design a system around that, but I really don’t think you’ll see anything until 2014 over in that area, any major systems other than just a couple gathering lines.

Joe Allman – JPMorgan

So compared to the $44 million or so you spent in 2012, so what’s going to be total infrastructure spending in 2013?

Ross Craft

Probably infrastructure spending I’d say to give myself room, $6 million to $7 million max.

Joe Allman – JPMorgan

Okay. Gotcha. And then, Ross, will it be in the second quarter – will the second quarter be the first full quarter where we should see the impact of these initiatives in terms of capital costs and operating costs?

Ross Craft

Well, I would say at the end of the second quarter for sure. The reason for that is we’re going to be bringing these systems online at the end of the first quarter. We already have a lot of systems working right now, but to get the full benefit you’ll see it at the end of the second quarter.

Joe Allman – JPMorgan

Okay. That’s helpful. And then just when I do some math I look at your 2,100 or so locations and I multiply it by say $5.5 million per well and multiply that by your work and interest, which I’m using 87.5%. That gets me about $10 billion of capital for your Wolfcamp horizontal program. So that’s obviously a lot of money and I’m not sure how many wells you’re going to drill every year, but you’ve got decades of inventory. So I guess I know you don’t want to outpace the science here and you want to figure out how to do things properly, but at some point you’ve got to accelerate or you need to – I don’t know what the idea is. You bring in a partner, you sell the company or – can you just talk about the different options that you’re thinking about once you got this whole thing figured out?

Ross Craft

Yeah, I mean, what you just said is very correct. When you look at this program from a full development program, and all the way through the end, you’re talking $10 billion to $12 billion. That just – that’s a large chunk of change for anybody. In reality, when you look at this thing, once we get the science figured out and to – and once you get very comfortable in the complete bench systems and everything working together and you want to bring in eight or nine rigs or whatever that is, then at that point, you’re going to have to look for a partner.

Or you’re going to have to look at going out and raising a bunch of additional debt to put this thing on or you can find a JV, somehow a JV or the company can be picked up by a larger company. I mean all of those are possibilities at that point. Right now our focus is to get this thing moving forward, get our costs down on everything. Right now, if we can get our costs which is very close to being at our targeted number right now, get our LOE, our G&A and everything else down and convert this into manufacturing, at that point, it would be very easy to pick which direction we want to go.

Joe Allman – JPMorgan

Gotcha. Gotcha. And then in terms of the 450,000 BOE type EUR, is that a good assumption for all 2,100 locations?

Ross Craft

You know, for right now I’d say that’s the best assumption we have for right now. What we’re going to be doing in the next six months, we’re going to be, as I said, earlier, we’re going to be checking the stacked laterals and how they related to each other. One thing of interest that I’ve noticed here is we can go in and drill on a new area. Let’s say we drill a B bench in a new area, and we have mud logs on them, and the mud log is a good indication we see gas and everything else in the mud log.

Well, once we’ve fracked that well and then let’s say six months later we come back and we offset it maybe 2,000 feet, then we’re seeing maybe a 2x increase in gas on the mud logs. And so that’s the kind of stuff we think, because we think by doing multiple benches out here, what you’re going to do is actually improve the fracturing throughout this whole column. And so that’s what we’re checking at that point on. So for right now, to answer your question, I went the long ways, is 450 is the best number we have right now. As we get through the next six months we’ll refine that, but I think it’s a safe bet.

Joe Allman – JPMorgan

Okay. All right. Very helpful. Thank you.

Ross Craft

And remember, these 2,000 locations, these were resource locations. And we’re going to incorporate those in and we’ll have more risk factors and things as we go through it, but they’re sound locations.

Joe Allman – JPMorgan

All right. Very helpful. Thank you.

Operator

Thank you for your questions, ladies and gentlemen. I would now like to turn the call over to Ross Craft for the closing remarks.

Ross Craft

Hey, guys. First of all, I really appreciate the questions. Obviously we have a – we made a lot of progress in this play. From 2009 to now and having our costs going down like they are, I think for a small company like us is a compliment to the team we have.

We still have a long ways to go, though. This is a major, major project that we have with years and years of drilling, and it looks like, at least right now, that the data we’re getting back is actually improving. But again, we can’t lose focus on cost control, cost control, cost control and that’s what we’ll be streamlining over the next six months. But we really appreciate you all support – your supporting it. I know it’s up and down sometimes, but I think when you look at it as a whole this company, as a small company, has a very nice future ahead of it. With that being said I appreciate it. You all have a good weekend. We’ll talk to you shortly.

Operator

Thanks, Ross, and thank you, ladies and gentlemen, for joining today’s conference. This concludes the presentation. You may now disconnect. Have a good day.

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