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Approach Resources Inc. (NASDAQ:AREX)

Q1 2014 Results Earnings Conference Call

May 10, 2014, 11:00 AM ET

Executives

Megan Hays - Director of Investor Relations

Ross Craft - President & Chief Executive Officer

Sergei Krylov - EVP & CFO

Qingming Yang - COO

Analysts

Leo Mariani - RBC Capital

Irene Haas - Wunderlich

Joe Magner - Macquarie

Jeffrey Campbell - Tuohy Brothers Investment Management

Brian Gamble - Simmons & Company

Steve Berman - Canaccord

James Sullivan - Alembic Global Advisors

Dhruv Bhardwaj - Credit Capital Investments

Harris McCraw - Hickory Partners

Dick Feldman - Axiom Capital

Operator

Good morning. My name is Amy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Approach Resources First Quarter 2014 Earnings Conference Call. Today’s call is being recorded. At this time all participants are in a listen-only mode. After the speakers’ remarks there will be a question-and-answer session.

I would now like to turn the conference over to Megan Hays, Director of Investor Relations.

Megan Hays

Thank you, Amy. Good morning and thank you for joining us today. On the call this morning is Ross Craft, our President and CEO; Sergei Krylov, our Executive Vice President and CFO; and Qingming Yang, our Chief Operating Officer.

In just a moment I'll turn the call over to Ross, who will review our operational results for first quarter 2014. Sergei will then follow with a review of our financial results and Ross will conclude our prepared remarks, before we open up the call for Q&A.

Our earnings release and conference call presentation slides that we will refer to during our prepared remarks can be downloaded from the IR section of our website at www.approachresrouces.com.

Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks is set forth on Slide 2 and in our earnings release.

Reconciliations of non-GAAP measures we refer to and the applicable GAAP measures can be found in our earnings release on the non-GAAP financial page of our website and at the end of our earnings presentation, we plan to file our Form 10-Q this afternoon.

Now, I’ll turn the call over to Ross Craft.

Ross Craft

Thanks, Megan. Good morning, everyone. And thank you for being on the call today. On our fourth quarter 2013 call, I highlighted our operational momentum as we began 2014. This momentum is evident in our results for the first quarter 2014, which underscores our team’s focus on execution.

Several highlights for the first quarter are summarized on Slide 4 of our corporate presentation. And they include; first, our accelerated activity level, which led to more horizontal wells drilled and completed in a single quarter than ever before. Secondly, over half of our completions in the first quarter were in the stacked configuration, starting the A and C zones or the B and C zones. Our stacked wellbore completions this quarter provide instrumental data points that contributed to further de-risking of our stacked wellbore development.

Third, accelerated activities and stacked wellbore development did not undermine our focus on cost control. Our horizontal well costs continue to average about $5.5 million per well. Fourth, production growth for the first quarter 2014 was in line with our projections, up 42% year-over-year. Fifth, and as Sergei will discuss later, we posted another quarterly record for EBITDAX and our balance sheet was further strengthened with our new $1 billion credit facility.

Let’s move to Slide 5 in our presentation. We are operating three horizontal rigs. We completed 19 horizontal Wolfcamp wells in the first quarter of 2014. Of the 19 completions, one well targeted the Wolfcamp A, 13 wells targeted the Wolfcamp B and five wells targeted the Wolfcamp C. The average initial producing rate for the horizontal wells completed in the first quarter was approximately 743 BOEs, made up of about 73% oil.

Consistent with prior quarters, we’ve updated the data on our type curve slide, Slide 8. Well data from the Wolfcamp A, B and C zones continue to track at or above our type curve of 450,000 BOEs. 10 of our completions during the quarter were in the stacked configuration. In Pangea West, we drilled a two well pad targeting the A and C zones and in Project Pangea, we drilled four two-well pads targeting the B and C zones.

Going to Slide 7 in our presentation, walks through our transition to stacked wellbore development. We began our horizontal development of the Wolfcamp play drilling single-zone, single-well pads, while confirming the commerciality and returns of the individual Wolfcamp zones. Additionally, we installed large-scale infrastructure systems, including water recycling systems in anticipation of multi-bench development.

Today, we are recycling approximately 30% to 35% of our produced water. We are expanding our water recycling facilities, with the goal of recycling 100% of our produced water. Our focus for the remainder of the year will include drilling two to four wells per pad targeting two zones.

The data we collect from our 2014 program will allow us to fine-tune our operations as we prepare to transition to full multi-bench development of our Southern Midland Basin acreage. The benefits from multi-bench pad development include reduced surface use, reduced rig mobilization costs, completion optimization and completion cost savings.

With that, I want to turn it over to our CFO, Sergei Krylov and he’s going to go over the financials.

Sergei Krylov

Thanks, Ross. On Slide 9, we’ve summarized our financial results for the first quarter 2014. Revenues for the first quarter totaled $61.9 million and were supported by both an increase in production volumes and an increase in commodity prices.

Net income for the quarter was $2.9 million or $0.08 per share. Excluding the unrealized loss on commodity derivatives and related income tax effect, adjusted net income was $6.7 million or $0.17 per diluted share. EBITDAX for the quarter totaled $42.7 million, up 75% year-over-year and represents our fifth consecutive quarter of record EBITDAX.

Lease operating expense per BOE for the first quarter was $7.36 per BOE. LOE was in line with the prior-year quarter, but was higher than fourth quarter 2013. Our LOE per BOE is seasonally driven and was primarily due to extreme weather-related compressor maintenance and work-over expenses. Production and ad valorem taxes totaled $4.2 million and were 6.7% of our sales.

Cash general and administrative expenses per BOE for first quarter were flat compared to the prior-year quarter at $5.51 per BOE. G&A for the quarter was $23.6 million or $22.12 per BOE. In all, despite slightly higher cash costs, our production growth and higher commodity price realization drove a 29% improvement in our unhedged cash margin compared to first quarter 2013 and a 5% improvement compared to fourth quarter 2013.

Capital expenditures incurred for the first quarter were $103.4 million and included $97.1 million for drilling and completion activities, $6.1 million for infrastructure projects and equipment and $200,000 for acreage acquisitions and lease expansions.

On Slide 10, we summarized our financial position. As Ross mentioned at the top of the call, earlier this week, we entered into a new $1 billion credit facility. The new credit facility has an initial borrowing base of $450 million and a maturity date of May 7, 2019. The interest rate under the new credit facility represented 25-basis point improvement relative to our prior credit facility. Pro forma for the borrowing base increase, our liquidity was over $450 million at March 31. Our current hedge position is summarized on Slide 11.

I’ll turn the call back over to Ross.

Ross Craft

Thanks, Sergei. Lastly I want to report that we recently drilled our 100th horizontal Wolfcamp well, which is an important milestone for our company. As I previously stated, our 2014 multi-bench development program is designed to fine-tune all aspects of our operations before transitioning into full development of our Southern Midland Basin position.

Water conservation has and will continue to be a top priority for our company. Our goal of recycling 100% of produced water will not be possible without a large-scale infrastructure transportation delivery system, which includes utilization of non-potable deepwater supply wells, non-potable water treatment and storage facilities and produced water recycling and storage facilities. Our impressive achievements is a result of our team’s innovation and determination.

I’ll turn the call over to questions. Thank you.

Question-And-Answer Session

Operator

Your first question comes from the line of Leo Mariani of RBC Capital. Your line is open.

Leo Mariani - RBC Capital

Hey, guys. Looks like you brought a record number of wells on in the quarter. Can you give us just a little bit more detail in terms of when those wells sort of came on, maybe kind of a month breakdown? Just kind of looking at the production, I would have expected it to be up a little more. So it seems as though maybe a lot of that was back-end loaded in the quarter. Can you guys speak a little bit more to that?

Ross Craft

The performance of the quarter was basically what we advised during the fourth quarter conference call, because of the number of completions that we had to do, which were all tail-loaded for the end of the quarter, majority of the completions, I think, 10 of them were done in March, which we didn’t bring anything on until after that, was one of the reasons for the production being where it was. So pretty much it’s just based on timing of completions. You’ll see this lumpiness as we continue through like this as well.

Leo Mariani - RBC Capital

Okay. And I guess could you guys speak at all to current production and what we should expect in 2Q? I guess based on that, it would seem to be materially higher.

Ross Craft

Current production, as we said, our guidance for the year is to remain still at 4.79. We feel confident in that number. So, with that, and how ended this quarter, I think everything is in line.

Operator

Your next question comes from the line of Irene Haas of Wunderlich. Your line is open.

Irene Haas - Wunderlich

Can you give me a little color as to sort of the weather impact during first quarter of this year on lease operating costs? And what we should be really expecting for second quarter for lease operating?

Sergei Krylov

Sure. Hey, Irene, this is Sergei. We certainly incur higher LOE costs during the winter. That’s just seasonality driven aspect of our business. In fact, if you just look at 2013 for example and you look at quarter-by-quarter breakdown of our LOE per BOE for each quarter, you will see that in the first quarter of 2013, our LOE was $7.14 per BOE.

In the second, third and fourth quarter, that LOE per BOE ranged between $4.89 to $5.38 per BOE. So you can clearly see the first quarter as a standout in terms of additional cost, and that’s just the factor of cold weather.

Specifically to our results in the first quarter, we incurred higher compressor, repair and field maintenance costs and we also had above-average work-over costs, and a lot of that was driven by weather. But we have incurred a lot of these costs anyway because that’s seasonally driven, but in addition to that, because it was really extreme weather, we incurred more costs than usual for the winter.

Operator

Your next question comes from the line of Joe Magner of Macquarie. Your line is open.

Joe Magner - Macquarie

Just back to the sort of the timing of completions, looked like the production mix in the first quarter was a little gassier than what we saw in the fourth quarter, and also sort of below what you're guiding to for the year. Just curious what the timing of those well completions, the impact it had on the mix and what we should expect in 2Q and going forward.

Ross Craft

Obviously, timing is critical. For example, if we -- because of the number of completions, we have to shut-in quite a wells around it. So, you’re going to see this fluctuation. You saw it in the third quarter as well, the fluctuation based on timing. In addition, part of our work-over program was, we worked over some Canyon wells, some deeper gas wells we had.

Obviously, the gas price improvement allowed us to go in and do some work on some of these wells, and I think that’s where you see a little bit of the increase as well. As far as projections, our projections are still in line. We’re still confident in our ratios and I think, as we go through all these quarters, you’ll see it balance out.

Joe Magner - Macquarie

And my follow-up, your highlight of having drilled, or recently drilled your 100th well, I think in the presentation you highlight production from 75 wells in your type curve chart. Just curious, is there much of a backlog currently of wells waiting on pipelines or waiting to be completed?

Ross Craft

There’s not much of a backlog. What we did on those curves -- those curves do not include our short lateral wells, and our first three wells, actually our first four wells that we’ve drilled, I think it’s three wells and then one other, so that’s where you see a little disconnect there and then the rest is based on just waiting on completion.

Operator

And your next question comes from the line of Jeffrey Campbell of Tuohy Brothers Investment Management. Your line is open.

Jeffrey Campbell - Tuohy Brothers Investment Management

The first question I wanted to ask you is, in your press release you said that the average oil cut of the wells that were brought on in the first quarter was 73%. That's I think about 10% higher than in the last quarter. And I assume that the oil cut declines over time over the production of the wells, but that still seems pretty high. So I was just wondering if you could give a little color on the high oil cut? And does it indicate any kind of an effect on the 58% pro forma Wolfcamp oil cut that you've guided previously?

Qingming Yang

Hi, Jeff, this is Qingming. And the oil cut for the initial IP usually ranges from anywhere between 60% and 90% and average work into, say, aberrations from quarter to quarter and 73% is close to what we normally say in terms of average.

In terms of the over the life of the well and our forecast for the oil is 58%. Initially, the oil is going to come in higher and the oil percentage will decline as production goes up. But for the life of the well, we’re still forecasting 58% for oil.

Jeffrey Campbell - Tuohy Brothers Investment Management

And my other question was regarding the C bench. I was wondering have you seen any appreciable difference in C bench performance when it's paired with the A bench as opposed to being paired with the B bench?

Qingming Yang

We have actually plotted the C bench wells and our type curve, and if you look at the page number 8 and some of our C bench wells have been on production for almost half a year. If you look at the performance of those, it looks very, very encouraging. And right now, the average production for all those four C bench wells is basically at or above the type curve.

And the five C bench wells we drilled in this quarter looks very encouraging as well. And it’s in line with the average IP for all the wells we drilled. And as we get more production data, as you know, we have turned B bench into full development, and now A bench as well.

Based on the results we have seen so far, we’re going to turn the C bench into full development. Right now, actually all our wells drilled right now as we go forward are basically B/C bench or A/C bench development. As you can see, we feel very confident about those stacked lateral wellbores going forward.

Operator

And your next question comes from the line of Brian Gamble of Simmons & Company. Your line is open.

Brian Gamble - Simmons & Company

Wanted to stay on that 450-type curve and the 58% for a second if we can, Qingming. The well results may be a little early on the C, but as far as the A and the B and any differences between the two, I know we've talked about 58% as an average. Was there any delta you can give us between the two, now that we've got a pretty significant history for both benches?

Qingming Yang

Absolutely. If you look at the overall shape of the curve, obviously B bench wells, we have more well data. We also have longer history as well. Now, for the B bench, we have more than 25 years of history and it’s interesting to look those wells, especially the wells which have longer history looks like they are actually plotted above the type curve for the B bench well and for the A bench wells and -- in a area in Pangea West area, those wells are very oily.

And also, over there, we have experienced some surface line pressure issues. As you can see, there are periods of time those wells are slightly below the type curve. But right now, they are back on the type curve. Actually, recent data indicates those wells are actually above the type curve.

And in terms of C bench, we probably need more time to watch them. In terms of oil content, so far we have seen the oil content in each of those areas are very similar except the Pangea West. It looks like the oil content in Pangea West is a little bit oilier over there. The wells over there, the initial IP is not as strong as the other areas, come up a little bit slow.

But, however, it will come back to about 500 to 800 BOE. And also, it has a flatter decline in that area as well. If there is any difference, that’s the only difference we’re seeing over there. Overall, it looks like they are plotted either at or above type curves.

Brian Gamble - Simmons & Company

Great, I appreciate the color. And then, on the completions front, 19 for the quarter, obviously puts you on a pretty decent run rate, well above the 70. And I know that the guidance on 70 was reiterated, and you mentioned the lumpiness. With the completions in Q1 being heavily back-end loaded, safe to assume that Q2 may be a little light on completions and so don't necessarily expect quite as many completions. But, you do get the production from the ones that came on very late in Q1. Is that kind of how I should be thinking about Q2?

Ross Craft

Yes, it is.

Operator

And your next question comes from the line of the Steve Berman of Canaccord. Your line is open.

Steve Berman - Canaccord

Ross, $5.5 million has been a long-term goal for you on well costs. You're there. Where do we go from here? I think you might have said $5 million might be the next goal. Can you talk a little bit about that, and how we get down from $5.5 million?

Ross Craft

We’ve talked about reducing it from $5.5 million. But right now, what we’re going to do is stay focused on $5.5 million understanding that we complete wells, drill and complete wells for much cheaper than $5.5 million. So, we have a wide range of wells here. The key, the catalyst will be as soon as we can get our systems up to where we’re recycling 100% of the water. That’s going to be the catalyst. And we’re working toward that right now.

Obviously, our infrastructure systems that we started installing two years ago was in anticipation of being able to reuse our water. Drilling numerous deep non-potable water source wells as makeup water, to eliminate any potable water use is another key we’re doing.

The main thing on reusing produced water is the storage. That’s been a bit of a problem in the state with the permits, but now they’ve waived that and now we can install large-scale surface facilities as well as looking at using underground storage and reservoirs that are depleted. So, once we get into the recycling, get it up to close to 100%, then we’ll reexamine our cost at that point.

Steve Berman - Canaccord

And my follow-up in terms of well results, for wells you've had long enough histories on, more recent wells, can you share any longer-term rates, 30-day rates on some of your more recent wells just over and above the 24-hour rates?

Qingming Yang

Sure. If you look at the slide number 8, for each of those benches, actually those are the average rate for each bench. So, if you look at the first 30 days for the B benches, C benches, they’re probably somewhere between 500 and 600 BOE if you look at those curves. And the A bench, as I mentioned earlier, especially in Pangea West area, they came in a little bit slow, but later on it will climb to about 500 BOE range.

Operator

And your next question comes from the line of James Sullivan of Alembic Global Advisors. Your line is open.

James Sullivan - Alembic Global Advisors

Just want to go back to the expense issue for a second. But this time down to the G&A line, I saw that your numbers were a little higher this quarter on an absolute basis. I know they were, kind of, in line on a BOE basis with the prior year's quarter. But prior-year quarter was kind of a trough volume quarter. So, I understand that that has to do with you guys staffing up at the management level, and getting ready to kind of support your growth, but can you just talk about where you are in that process in terms of bulking up the management team and --?

Sergei Krylov

Yes, this is Sergei. I’ll answer that question. I mean, you’re absolutely right. If you look at our G&A expense for the first quarter, it’s higher. Again, if you look at the history of the company and look at the first quarter last year, you will see a similar trend.

There’s certain costs that we’re incurring in the first quarter that are unique to the first quarter, specifically our -- we pay our auditors and tax consultants for year-end audit work as well as tax audit in the first quarter. In addition, our Board of Directors’ compensation is paid in the first quarter or a significant portion of the Board compensation has been in the first quarter.

In addition, in the first quarter, my employment awards were awarded in the first quarter as well. And obviously, both of the last two items have been disclosed in 8-K filings and the proxy statements earlier, so neither one should have come as a surprise. But going forward, obviously all of these expenses would be incurred except until next quarter obviously. But in terms of staffing, I think we are pretty well staffed at this point. We’ll continue to look for talent on the operational and field level, but other than that, I think we’re in pretty good shape.

Operator

And our next question comes from the line of Joe Magner of Macquarie. Your line is open.

Joe Magner - Macquarie

Thanks for the follow-up. I just wanted to circle back to your comment about moving into full-scale development. And I appreciate that this year, the focus is on A and C or B and C stacks. Any thoughts of testing the triple stack you referenced on the fourth quarter call as a possibility at some point? But just curious, with the success you've had so far, if you're looking at that any closer?

Ross Craft

What we’re going to do this year we’re fine tuning all aspects of our operations with the two-bench development in anticipation of going and testing the three-bench development. That’s going to happen, if we do it this year, it will be at the latter part of the year. And so, but that is part of our plan, is to go in and do the three-bench testing following completion of the two-bench.

Joe Magner - Macquarie

And as you're looking at that, what are the things that have sort of caused you to drill those stacks where you've drilled them? And geologically, what are some of the opportunities or the limitations in the different areas on being able to test that?

Qingming Yang

Hey, Joe, this is Qingming. If you look at the -- our stacked lateral we have so far drilled stacked lateral in Pangea West, northern Pangea, Project Pangea and also central Pangea very much across all those areas in terms of stacked lateral.

Based on well results, it looks like all those stacked laterals are working out very well. And so far, as Ross mentioned, we’re really trying to optimize our execution. Once we get all those optimized, and it’s our plan to test three-stacked lateral. It appears to be each individual benches are working very well and the two-bench stacked lateral so far works very good as well.

And so it’s very natural for us to test a three-bench stacked lateral. It’s just a matter of time and if we’re going to do it this year, it’s going to be latter part of this year once we get all our operation and execution optimized.

Operator

And your next question comes from the line of Daru Baraj of Credit Capital Investments. Your line is open.

Dhruv Bhardwaj - Credit Capital Investments

This is Dhruv Bhardwaj. Thanks for taking my question. I'm looking at your slide deck on Slide 7. Looking at -- you mentioned cost savings from the stacked benches. Could you provide some color on what kind of volumes you can have? And any numbers on that front would be helpful? And I guess my follow-up, my second question would be on the water recycling. You mentioned that the development costs were expected to go down once the infrastructure is in place. Could you give some possible timeline on that front?

Ross Craft

Yes. Not a problem. Obviously, pad development, there’s a lot of savings on pad development. Number one, each rig move, and we have completely rig down a rig and move it even to adjacent pad. What you’re talking about is anywhere from $90,000 to $100,000 just to move it to adjacent pad.

And so, our rig configuration right now is all M rigs basically quick moving, they scope up, so they have a small footprint and you don’t have to rig them down, so the more wells you can drill off a pad, obviously you save that, that $100,000 to $90,000 rig move.

Also, time savings on completions. Obviously, having more wells in a centralized area that you can complete at the same time, means you can complete them faster because everything is right there and your frac crews don’t have to move, so you get a fairly nice savings as well plus the savings on time and time is valuable out here. But those are the types of savings that you see by doing this.

As far as water recycling, a big chunk of our water recycling is, right now, our cost is water movement. Our disposal system that we currently have, we have deep Ellenburger disposal wells. But Ellenburger, it’s a tough zone to dispose in. So we have to use commercial disposal sites for some of our water.

Obviously, by having a 100% recycle where we use a 100% of our flow-back and produce water as frac fluids, that’s in conjunction with the pad development. You can save a lot of money, because the commercial disposal sites and trucking charges can go as high as anywhere from $3 to $5, including trucking. And so obviously you’re really using the water, so you don’t have to take it to the commercial site, is going to save you a considerable amount of money.

Obviously, these wells, the Wolfcamp zone does not produce water. All the water we’re recovering out of the Wolfcamp is based off of what we put in. Our average frac job range anywhere from 250,000 to sometimes 300,000 barrels per well.

So, we get a lot of that water back in the first year. Being able to recycle that water, part of our infrastructure system that we’ve put in allows us to take water directly from one well run it up to our recycle through underground pipes, clean it, bring it right back to an offset pad and frac with it. And so that’s why the water usage of taking our recycled water up to 100%, not only do we save on water transportation in, but we save on water transportation out to disposal sites.

Dhruv Bhardwaj - Credit Capital Investments

And is there any timeline on when you expect to have this 100% recycling capability?

Ross Craft

I would like to think that we will be there by the end of the year. We’re definitely making progress. The big deal has been, as I said earlier, has been storing the produced water since it is saltwater, high chloride water, you have to be careful in your storage.

And right now, we’re storing it in 40,000 barrel surface steel pits on the surface. Obviously, we’ve got a few ideas in mind that’s going to streamline that and allow us to recycle. Some of the ideas include injecting it and then pulling it out of the injection zone. And also, since the state has relaxed the permitting on produced water pits, obviously take advantage of that as well.

Operator

And your next question comes from the line of Harris McCraw of Hickory Partners. Your line is open.

Harris McCraw - Hickory Partners

Quick question on Pangea West. You mentioned that your production so far has been more oily. Can you comment on how many wells you intend to drill in that area the next quarter?

Qingming Yang

We normally don’t forecast which areas, how many wells, we drill exactly. And we work into balance out between Pangea West, northern Project Pangea and also central Pangea. And this year, we’re going to drill and complete around 70 wells. And the first quarter, we have [two of the 16 complete in 19] (ph). And the rest of those wells will be balanced out between the rest of this quarter.

Operator

And our next question is from Jeffrey Campbell of Tuohy Brothers Investment Management. Your line is open.

Jeffrey Campbell - Tuohy Brothers Investment Management

I wanted to just ask a follow-up to your recent discussion on the water disposal. I want to make sure I understood one part correctly and then just ask a question. You said that having to do commercial water disposal costs $3 to $5. Was that on a per BOE basis? And are you able to estimate what 100% recycling will cost on the same basis so we get some kind of idea of the savings that's involved? And I have a follow-up.

Ross Craft

It’s not on a BOE basis. That’s on a barrel of water when I was talking about the cost. As far as savings, recycling the main thing you have to do in the recycling is just knock out the solids if there’s solids in it, and any iron, anything else that happens to be in it.

There’s not much to using produced water recycling if the water is fairly clean such as our water. Because most of this water, majority of it is flow-back water from wells we fracked. So the treatment costs of using saltwater, our produced water is low. I would say probably less than $1 a barrel.

Jeffrey Campbell - Tuohy Brothers Investment Management

And just last question, a little broader. Would you qualify Crockett County as relatively active or inactive at this time? And do you see any opportunities or have any appetite for any bolt-on acquisitions?

Ross Craft

Crockett County remains, Northern Crockett, where we are up into the Reagan and Upton County borderlines has been very active. Actually, I believe there was one publication that came out in the completions for the first quarter, there were more completions in Crockett County, Northern Crockett than anywhere else in the Southern Midland Basin.

So, from that standpoint, it remains active. What a lot of people failed to realize is the Crockett area, the Northern Crockett, where we are has been active since 2009 with horizontals. And if you look at the Southern Midland Basin as a whole, I’m talking of Southern Midland that’s Southern Reagan, Southern Upton Crockett, Crockett has probably been over 1,200 horizontal wells drilled and completed since finding this.

And, so from that standpoint it remains active where all the operators in the Southern Midland Basin area are in full development mode one way or the other.

As far as bolt-on acquisitions, we’re always striving to look at opportunistic bolt-ons. And so we continue to be vigilant on trying to tack on additional acreage, but we stay focused on, it needs to be in close proximity. The last thing you want to do is to act on 1,000 acres that’s way away from your position, because then you don’t have the infrastructure and your cost will be higher, but we still remain very opportunistic as far as bolt-ons.

Operator

And your next question comes from the line of Dick Feldman of Axiom Capital. Your line is open.

Dick Feldman - Axiom Capital

You spoke about how the harsh winter weather raised your lease operating costs. Was there any impact of the weather on your drilling and completion costs?

Ross Craft

No, it’s really more to do with our compression system, the way it’s setup since we take field gas at very low 40-pound pressures and we boost it up to over a 1,000 pound. So anytime we’re doing that operation, you have a big chance of freeze-offs and we’re geared to handle winter weather, normal winter weather, but when it gets down to 20-degrees or in the teens, we have to run a lot of chemicals to keep our lines from freezing up, methanol and additional glycol and things like that.

And then the labor, just to make sure that these big systems we have do not go down and so we have to keep people out there 24/7 in these cold weather-type environments and because we’re one of the few operators that completely take our gas from field level, below suction and boost it all the way up to pipeline pressure where it can go into a plan without inner-stage compression.

And the reason why we do that because we have our own gas (indiscernible) and so that’s why we have to make sure these compressors run and run continuous because that supplies all of our gas lift gas which we use quite a bit of.

Operator

At this time there are no further questions, I turn the call back over to Mr. Craft.

Ross Craft

Hey, guys, we appreciate your interest in the company. Obviously, we are moving and cycling into a new era, drilling our 100th well. Our test of these stacked laterals, B/C, A/C is working as planned. We’ll continue to update our type curve with additional production, so you all can monitor our progress.

Our goal this year is to recycle 100% of our water. Obviously, with the drought in West Texas, we’re as concerned about using any potable water source as anybody. And so there’s no reason why you should not recycle your water and because of our forward thinking back two years ago is allowing us to be ahead of the game on that.

I appreciate it and thank you for the questions.

Operator

This concludes today’s conference call. You may now disconnect.

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Source: Approach Resources' (AREX) CEO Ross Craft on Q1 2014 Results - Earnings Call Transcript
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