Approach Resources' (AREX) CEO Ross Craft on Q2 2014 Results - Earnings Call Transcript

| About: Approach Resources (AREX)

Approach Resources Inc. (NASDAQ:AREX)

Q2 2014 Earnings Conference Call

August 5, 2014 10:00 AM ET

Executives

Ross Craft – President and CEO

Sergei Krylov – EVP and CFO

Qingming Yang – COO

Analysts

David Deckelbaum – KeyBanc

Brian Gamble – Simmons

Brad Heffern – RBC Capital Markets

Joe Magner – Macquarie

Joe Allman – JPMorgan

Jeffrey Connolly – Finance Mizuho

Gail Nicholson – KLR Group

Operator

Good morning. My name is Tracy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Approach Resources Second 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.

The company’s earnings release and conference call presentation slides, that management will refer to during our prepared remarks, can be downloaded from the IR section of the company’s website at www.approachresrouces.com.

Please note that management’s 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 forward on Slide 2 and in the company’s earnings release. Reconciliations of non-GAAP measures, management refers to and the applicable GAAP measures can be found in the company’s earnings release on the non-GAAP financial information page of the company’s website and at the end the company’s earnings presentation.

Now, I will turn the call over to President and CEO of Approach Resources, Ross Craft.

Ross Craft

Good morning everyone. Thanks for being on the call this morning and for your interest in Approach. Also on the call this morning will be Sergei Krylov, our Executive Vice President and Chief Financial Officer; and Qingming Yang, our Chief Operating Officer.

In the second quarter of 2014, Approach posted some of the best financial results on our history and our strongest daily production average at 14.1 million BOEs per day. Total production rose 58% compared to the prior year period, oil production was up 52% year-over-year.

Given these positive results, we’re looking ahead to a strong second half of 2014. We’ve increased our estimated 2014 production guidance from 4.79 million BOEs to 4.95 million BOEs. This update is estimated at 7% liquids includes oil production at 2.05 million barrels to 2.2 million barrels. Updated guidance estimates are shown on slide 8 of the presentation.

Highlights for the second quarter summarized on slide 4 of the corporate presentation. Key takeaways include 16 horizontal wells drilled and completed during the quarter as our accelerated pace of drilling activity continues.

Our operational team is focused on improving efficiencies and driving cost while optimizing the completion design of our dual-bench wellbore peers. 14 to 16 wells completed in the quarter were drilled at stack peers the word camp BC benches. While once that peer was drilled to the Wolfcamp A, C bench.

Increasing drilling activities combined with higher realized price resulted in a record quarterly revenue we ever got and production. Notably, we accomplished this group while maintaining best-in-class horizontal well cost and without sacrificing our margins.

The company’s unhedged cash margin for the quarter increased 9% over the prior year period.

Moving to slide 5, our DB operations. Our drilling activity resulted in total production of 1,286,000 barrels for the quarter or 14.1 million BOEs per day, a record high. Production for the three months was 41% oil, 29% NGL and 30% gas.

On a sequential basis, our average daily oil buying grew by 15% in-line with our expectations, while our average daily gas and NGL volumes grew by 20% and 24% respectively, exceeding our expectations.

During the quarter, we drilled and completed 16 wells across all three of our Wolfcamp A, B, and C zones dual-stack wellbore configurations. Excluding one short allowed on two wells in the early stages of flow back, the average initial point for wells completed since the first quarter of 2014 was 556 BOEs per day with 65% oil cut.

The IP rates were affected a mild deflation of our completion design – let’s try that again. And I attempt to create a more complex fracture system around the world where we elected to increase our total sand volumes to approximately 400,000 pounds per stage as well as increase the percentage of smaller or 100-mesh sand up to 80%.

Similar to completion and design utilized in the Eagle Ford Shale, we believe the increase in the 100-mesh sand resulted in reduced conductivity around the wellbore thereby limiting the higher initial flow rates in adjacent wells.

Based on production history of Wolfcamp horizontal wells, the wells with initially lower rates, general experience showed declines and therefore in most cases the EUR were similar to what we see in wells with higher initial productions.

We have returned to our 30% to 40% 100-mesh frac design until we have enough production history to fully evaluate the Eagle Ford type design. Consistent with prior quarters on slide 7, we’ve updated the data on our type curve slide. Well data from the Wolfcamp A, B and C zones showed that wells generally continue at or above our type curve of 450,000 BOEs.

Now I’ll turn the call over to our CFO, Sergei Krylov, who will review the financial results.

Sergei Krylov

Thanks Ross. On Slide 9, we’ve summarized our financial results for second quarter 2014. Strong financial results this quarter were driven by higher production volumes and higher sales prices. Our average sales price including the impact of hedges totaled $54.48 per BOE, a 7% increase over the prior year quarter.

We also benefited from a favorable marketing arrangement which allows us to sell our oil in Cushing Oklahoma and the benefit of that contract was evident in the second quarter, resulting in a differential of only $4.79 per barrel relative to NYMEX, a much higher realized price than prevailing Permian price benchmarks.

Net income for the quarter was $3.8 million or $0.10 per diluted share, excluding the realized loss and commodity derivatives and related income tax effect, adjusted net income was $8.7 million or $0.22 per diluted share.

Revenue reached a record $73.4 million, a 74% increase over prior year period. EBITDAX for the quarter totaled $50.6 million, up 65% over last year and 19% sequentially. This represented our sixth consecutive quarter of record EBITDAX.

Lease operating expense per BOE for the second quarter was $6.18 per BOE, a decrease of 16% from prior quarter. Reduction and taxes sold $3.83 per BOE and was 6.7% of oil and NGL gas sales.

Exploration costs were $1.53 per BOE. This is entirely non-cash item which was higher than the prior quarter due to non-core lease explorations. Cash G&A averaged $1.29 per BOE, a 11% decline compared to the prior quarter.

G&A for the quarter averaged $22.21 per BOE a decrease of 1.8% compared to the prior period and roughly flat compared to the previous quarter. Interest expense totaled $5.4 million.

Capital expenses for the quarter totaled $92.3 million consisting of $85.8 million of drilling and completion activities, $3.8 million for infrastructure projects and equipment and $2.9 million for acreage acquisitions and extensions.

On slide 10, we summarized our financial position. At June 30, 2014, we had $1 billion revolving credit facility with $450 million borrowings base and $46 million of outstanding borrowings.

At June 30, 2014, our liquidity and long-term debt to capital ratio were approximately $404 million and 29% respectively.

With the strength of our financial position in the quarter was an increase of our borrowing base from $350 million to $450 million. Our current hedge positioned is summarized on slide 11.

Overall from a financial perspective, I’m very pleased with the first six months of the year. Our production and cash flow are tracking ahead of our expectations. And we’re doing that while staying within our capital budget as we’ve been outlined for the year.

And now, with that, I’ll turn it over back to Ross.

Ross Craft

Thanks, Sergei. Before we open up for Q&A, I want to thank the entire team for their hard works we’re continuing to accelerate the pace of our development. In the first of 2014, we completed 35 horizontal Wolfcamp wells versus 12 horizontals completed in the first half of 2013, which represents almost a three-fold increase in completion activity.

With a strong focus on execution, we’re achieving lower costs and improved margins and sharply higher productions.

With that, we can open the calls.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question is from Irene Haas with Wunderlich Securities.

Unidentified Analyst

Hi guys, this is (inaudible), Research Associate for Irene Haas. I just had a question, could you guys talk about your infrastructure investments and how that’s impacted your price realizations and kind of where you guys see price realizations going forward from here?

Ross Craft

Yes, sure. In terms of infrastructure, obviously the biggest – two biggest infrastructure systems as we’re marketing our volumes to is the oil system that we built on Salt last year. And that allows us to take our crews all the way from our wellhead to NYMEX. We don’t own that infrastructure anymore but would have a favorable margin arrangement.

And as I mentioned before, we’re able to effectively sell all of our crude right now at a differential of less than $5 per barrel, relative to NYMEX which is very strong relative to Permian price index. And then, we also have a very favorable arrangement with DCP who is processing our gas, we’re doing some of the best percentage of proceeds contracts in the Basin.

And so, combination of those two marked generations would have employees allow us to have some of the best differentials in the basin.

Unidentified Analyst

All right. Thanks guys.

Ross Craft

Sure.

Operator

Your next question comes from David Deckelbaum with KeyBanc.

David Deckelbaum – KeyBanc

Good morning everyone thanks for taking my questions. Would you mind giving me a little bit more on the completion tweaks that occurred in the second quarter. I mean, I think we’ve seen some neighboring peers that have seen a benefit for tighter FOREX spacing and increased end concentration, leading to higher EURs and would you still be pursuing these tweaks and how do you see your completion design perhaps different from that of some neighboring peers that have had success?

Ross Craft

Well, our spacing has been relatively consistent stage spacing since we started this. So the only thing we’re re-modifying on this was basically the 100-mesh sand, trying. And obviously the reason why you’re on 100-mesh sand in front of these fracs is to create a more complex fracture system.

So what we’re trying to do is get more of a complex fracture system connect to the wellbore thinking that the way to do that would be more of 100-mesh mix such as 80% 100-mesh and the remaining 40-70.

Obviously, at this point in time, if you look at the way the wells are producing, because 100-mesh is a very smaller sand particle. It looks like it’s conductivity that we see around the wellbore was acting like a choke for these wells. And so, therefore you saw these rates a little bit less than what our previous quarter rates have been.

Although, still very much in line with our type curve, we think that the 100-mesh in such high concentrations was a reason for this. We’re going to evaluate this even further and get some more production history of these wells obviously to see if these by doing the extra 100-mesh had a impact of flatter declines. It’s just going to take some time to tell that.

But what we have seen in the past and through all of our wells and adjacent wells, neighbors wells is that when you start seeing IPs are similar to your type curve, and a lot of cases what we’re seeing out here is a flatter decline rate on these wells. Initial IPs, these high IPs have a huge decline rate in the first 15-20 days.

But with that, I’m very satisfied with the way our bench peers are developing, our flow rates from our benches are extremely good, the 30, 60, 90-day, the 120-day rates are in-line, if not exceeding my expectations. So, I think going back to a sand mixture which is about 30% 100-mesh and the remaining would be 40-70, we’ll do that from the near term. That’s the same recipe that we’ve done in the past.

And we’re always trying to tweak it just a little bit to ensure that we get the maximum output from this, and so we’ll continue to do that. But right now we’re going to go back to what we were doing before.

David Deckelbaum – KeyBanc

Okay. And is there, I mean, is there any – are you also evaluating tighter spacing I guess that we’ve seen more recently I think some peers released some data that was contributing a bit more to some higher EURs?

Ross Craft

No, I think we’re satisfied with the well spacing right now. And so we’re going to stick with our 660s, we think in our particular area that maximizes our recoveries. Again, I can’t overstress where the – we’re very pleased with the stack results. And so, we’re going to continue to work with the stack results and we might at that point, once we get sufficient enough data to make an educated decision on it, we might adjust. But right now we’re very pleased with our spacing.

David Deckelbaum – KeyBanc

Thanks Ross.

Operator

Your next question comes from Brian Gamble with Simmons.

Brian Gamble – Simmons

Good morning guys.

Ross Craft

Good morning.

Brian Gamble – Simmons

To stay on that same topic, Ross, any data that maybe you could provide either with 30-day rates or 90-day rates to compare the last few quarters, just to give us some clarity on how much more shallow the recent wells have declined in those in previous quarters?

Ross Craft

Yes, I’ll let Qingming talk about the rates on the dual-pairs and go ahead Qingming.

Qingming Yang

Sure. As we now compare, we completed five pairs of the collateral in the first quarter of this year. And those wells have been a productive history over four months or so. And it looks like the 30-day rates average of those five pairs it’s about 490 and BOE per day.

The 60 days, it’s about 430 BOE per day, the 90 days rates is about 383. And the 120 days that’s four months of production it’s about 350 BOE per day.

And it looks like those five pairs are average – have exceeded their production of our type curve as Ross mentioned earlier. And we’re very pleased and actually excited to see the results of those stack lateral in wells. And going forward, all our wells right now are stack laterals.

Brian Gamble – Simmons

And then, if you could, do you have 30-day rates for the pairs in Q2 or 60-day rates compared in Q2, how early were those drilled?

Qingming Yang

A lot of our wells are brought online in the second half of Q2. Obviously we needed to keep those, little more production history. And those wells, you probably saw the initial IP for those wells it’s about 500, 56 BOE per day. But we have seen those, initial decline normally for those wells with a little bit lower IP, they decline shallower or a little bit more history to say how those wells performed to say whether those wells won’t decline any shallower than those wells we drilled in the first quarter.

Probably, we should be able to report the 60-day, 90-day and 120-days in the next quarter earnings call.

Brian Gamble – Simmons

Great. And then, one follow-on the service side of things, are you guys running one permanent fracture right now or do you have two partials, how is that situated and what sort of I guess pricing inflation have you baked in for this year, for next year for the frac side of things?

Ross Craft

We’re running two partials right now. Because the timing of the completion is now the way we run rigs. And we let them alternate. As far as pricing, we’ve got – we’re not seeing a lot of pressure on much of an increase in pricing. Because what our fracture is a little bit different than other guys.

And so, as far as baking in any type of 2015 escalation price, we’ll look in to see and we do it would be a marginal increase and cost increase. I don’t think it’s going to be sufficient or anything that’s going to drive our cost up very much.

Brian Gamble – Simmons

Thanks Ross, I appreciate it.

Operator

Your next question comes from Brad Heffern with RBC Capital Markets.

Brad Heffern – RBC Capital Markets

Hi, good morning everyone.

Ross Craft

Hi Brad.

Brad Heffern – RBC Capital Markets

Going back to the new completion design, was there any additional gas or NGL production that was coming from that or is this increase sort of gas and NGL expectations coming more from the Baker area or something like that?

Ross Craft

Yes, no. I mean, what we saw on the new completion design, we saw predominantly the oil rates were a little bit suppressed early on in these wells. The gas was pretty much what we normally would expect.

What we see in the increase and in the guidance, well we’ve talked about the increases. It looks like overall, all of our wells that the gas side of it is performing better than we originally modeled. With the oil rates being in-line with our guidance and in-line with our type curve estimates, which is a good thing, I mean, but that’s where we’re seeing an increase.

And you’re correct, now the Baker area, those are very strong wells and they have high gas rates down at the Baker but they also have in-line oil rates for their type curves but that’s probably where the majority of this is coming from.

Brad Heffern – RBC Capital Markets

Okay, great. And Qingming, do you have any split for the different, the IP rates for the B versus the C-stacked wells this quarter?

Qingming Yang

Those are, in terms of the oil is I think Ross mentioned earlier that oil is in-line with what our expectations are. And it looks like those wells, for the first quarter of the well and also wells prior to that – the guests and NGLs are expecting our expectations.

For the second quarter wells, for the wells we just reported and you probably saw the oil percent is slightly lower. We think that’s related to we increased the concentration of 100-mesh is a result those probably served as a choke that word that Ross used we think that’s a very accurate description.

It’s going to be interesting, they, going forward how those wells will perform once we flow back initial frac water out. And hopefully those wells, the oil rate will come back to what it’s supposed to be.

Brad Heffern – RBC Capital Markets

Okay, got you. I guess, what I was trying to get at is, did you see any differential between the performance of the B-bench and the C-bench with the second quarter wells or do they continue to perform similarly?

Qingming Yang

I think, nobody those wells – the major differences between those high IP wells and the low IP wells based on the production history we have seen for the last three or four years is that mainly first, the 30 days to 60 days. Once those high performing wells, during the first 30 days to 60 days have higher decline. And then they come back to type curve.

And then you get higher gas and NGL production will exceed in that curve. But for the low IP wells and they will also come back to the type curve after about 30 days or 60 days as well. So, for the second quarter wells we just need a little bit more production history to say how those wells will perform.

Brad Heffern – RBC Capital Markets

Okay, thank you.

Operator

Your next question comes from Joe Magner with Macquarie.

Joe Magner – Macquarie

Thanks. I guess, following on some of the questions that have been asked today. I think there is some anticipation that Q3 oil volumes are actually going to be up sequentially given the IP, the higher IPs and the higher oil cup scene from the wells completed in the first quarter and yet overall oil production was down again.

I guess, can you just spend a little more time on flow dynamics of what you’re seeing in those wells that were completed earlier in the year and despite the last three quarters with the Wolfcamp oil cuts coming in 65% to 70% plus overall mix continues to fall. I’m just trying to kind of better handle them the dynamics?

Sergei Krylov

Hi Joe, this is Sergei. I think you said that oil, your numbers I guess at the oil was down, that’s not correct. I mean, oil was up, oil production was up 16% quarter-over-quarter.

Joe Magner – Macquarie

The oil production was up but the mix of raw was down?

Sergei Krylov

Yes, that’s right. So, and then natural gas and NGL, that’s right, our natural gas and NGL volumes were up about 20% to 25%. So, the way I think about this, the way I think about this is are we getting the same amount of oil production as we expected.

And then certainly as validated by 16% quarter-over-quarter production growth mix, and we’re certainly gaining as much oil as we forecasted. We are getting more natural gas and NGLs than we originally forecasted. And that’s the reason for our production to beat this quarter and it’s also been for our overall production guidance increase for the balance of the year.

So the way I think about it is, we’re achieving as much oil production as we expected and we’re getting more gas and oil mix. Obviously it brings down our oil percentage mix lower but that ultimately translates into more overall cash flow because we get more gas than NGL. So that’s what I was focused as CFO.

Joe Magner – Macquarie

Okay. I guess, beyond that with the IP rates coming in, oil initially 65% to 70% plus over the last few quarters. Can you provide a little more specific I guess in the decline rate, the decline curves between oil, natural gas and NGLs?

Ross Craft

Yes, the decline curves, when you look at it and one thing you can also look at is our slide that shows the different ventures and the some physical data points from that slide. But what we’re seeing is the audit line and we’ve said this from the start is will sharper initially than the gas decline and that’s all – based on a mobility ratio of all the gas.

But then, once everything stabilizes out at the first, probably 60 days and the oil decline rate is very similar to the – at least in line with the gas decline rate. Where we really see the divergence is in year one, two and three out, we start seeing oil rate is at the decline that we projected in our type curve but gas rate, it seems to be a little bit flatter.

And so, when you look at all of our wells, for the most part in the B-bench and especially in the B-bench, those wells are all performing above the type curve for the most part. And it’s interesting to see the longer they flow, the flatter the decline rate they have, which obviously, the oil rate thing similar to what we project of our type curves and increase gas rate and NGL rate to get out to ask, does that equate into a recent total EUR for the well.

And our well is outperforming above curve, we’ll probably wait until the end of the year to make any adjustments when we get a little bit more data. But the oil is doing about like what we thought, it’s really the gas flattening out. So, really the way we look at this, everything seems to be in-line and always having one increase more than the other one is always a good thing.

But the ratio, because we have brought on some really strong wells, especially down the Baker, gas rates on those wells even though that the oil rate is in-line with our expectation, the gas rates are quite high on those wells.

Joe Magner – Macquarie

Okay. And then just one follow-up I guess with the increased outlook for 2014, any preliminary thoughts on ‘15 either just directionally spending plans or activity levels?

Ross Craft

Yes, I mean, there is no guidance yet for 2015 which we haven’t formulated our view on the capital budget for next year. So, as we continue – continued throughout the year and then we continue to observe our observations, we’ll make that announcement early.

Joe Magner – Macquarie

Okay. Thank you.

Operator

Your next question comes from Joe Allman with JPMorgan.

Joe Allman – JPMorgan

Thank you. Good morning everybody.

Ross Craft

Hi Joe.

Joe Allman – JPMorgan

Ross, I’m just wondering the market is concerned about the production and the production mix and the IP rates and what not. And so, in past quarters you’ve talked about the impact of frac related shut-ins? Could you talk about how that’s affecting production?

And the production that gets shut in, those wells to get shut in, do those wells come back online at a higher rate than what they were producing before or does that production that gets shut in basically go to the end of the line when you actually produce that production?

Qingming Yang

Hi, Joe, this is Qingming. And when we frac the wells, we normally shut in the direct in offset wells and to perform our fracking. And after fracking, when those wells get back, we initially always get flash production. And that means, it’s only came to push the production, delay the production a little bit. But it actually doesn’t affect the overall recovery of the well.

Based on what we have seen, those wells after the flash production, those wells will come back its initial decline. So far, we haven’t seen the offset fracking is going to affect the recovery of the well. It’s only going to delay the production of the well.

As you can see, and our – we have stated actually in our forecast in the second quarter. And our second quarter came in at 14.1 million BOE per day. And going forward, we think those wells really as both Ross and Sergei discussed earlier, it’s not affecting our oil production but our gas production actually are performing better. And also NGL and gas production are performing better.

Joe Allman – JPMorgan

Okay, that’s helpful. And so, okay, that’s helpful. And then, so, if I heard you correctly, so I just want to clarify. So your oil is in-line with your type curve, the oil production on a per-well basis is on average in-line with your type curve, gas is doing better, NGL production is doing better. So, I mean, all else being equal, at point in the not too distant future, maybe by year-end like you actually might increase your type curve from 450 to something higher?

Ross Craft

Yes, that would – that makes perfectly good fit. And so, what we’re seeing is, our internal projections are increasing. And so, what we want to do is wait till the end of the day. So, have another six months of production data so we’ll have probably now four years of data in some point. And at that point we’ll look at it and make an adjustment.

But you’re exactly right, you’re thinking exactly right. If your curve is in-line with what you expect in your type curve, but you’re seeing flatter declines on your gas and more, it stands a reason that your EURs are going up.

Joe Allman – JPMorgan

Got you. And what’s your best guess at this point in terms of the oil cut on the average well that you’re drilling, just over the lives of the well?

Ross Craft

Right now we’re still holding in the 57% range, up in that range. It depends on the amount of gas that the wells are going to produce. As I said, the gas is going up a little bit more that could drive it down. But it doesn’t change the projection on total volume of oil produced over the life of the well. It just means that these wells might be making a little more gas than we originally thought. But the oil is going to be similar to what the type curve projects

Joe Allman – JPMorgan

Okay, all right, great. Very helpful, thank you.

Operator

Your next question comes from Jeffrey Connolly with Finance Mizuho.

Jeffrey Connolly – Finance Mizuho

Hi, thanks for taking the questions. Can you give us any color on the timing and number of completions in the third and fourth quarter?

Ross Craft

I mean, we’ll still refer you to our guidance for the year, for the full-year, we’re obviously guiding 70 drilled and completed wells. So far, six months into the year we’ve completed 35 which is, exactly half of them. So going forward, we’re still on track to meet our guidance of 70 wells per year.

Again because of tag drilling, you may have quarters where you make to get two or three wells less than what the straight like may imply. But that would be made up in the following quarter. So, from your perspective, that’s the kind of model fairly kind of steady number of completions per quarter.

Jeffrey Connolly – Finance Mizuho

Okay, thanks you. And then, can you give us any details on where on your leasehold do you plan to drill, is that going to in Pangea West and then the North Pangea area or any wells kind of moving more towards central Pangea?

Ross Craft

Yes, good question. Historically and we still do this, we’re focused on drilling where we get the maximum return that’s where our infrastructure is in place. And so, our predominant drilling activities for the year, is going to be centered around Northern Pangea and Pangea West. Although, we have some wells we’re going to drill a couple of wells that moves over to the towards the Central Pangea area. And we should have those by the end of the year.

Jeffrey Connolly – Finance Mizuho

All right. Thank you guys.

Operator

Your next question comes from Irene Haas with Wunderlich Securities.

Unidentified Analyst

Hi guys, (inaudible) here again. I just wanted to ask you a question about the possibilities of taking another look at Wolfcamp D and crocket and Orion Counties. I know Pioneer had some recent success to I think the Wolfcamp D nearby in Upton. So, I just wanted to see if that was in your radar to give it another look again?

Ross Craft

Now, we’re pretty much – when you pretty much are going to stick today B and C, when you look at the, there a lot of people are talking about the D is kind of the difference between the lower Wolfcamp and the Pan or the Canyon where we are. And so, we’re going to stick with A, B and C, we’ve been quite active producing that area below the Wolfcamp, that’s the Canyon area. And so, our main target in this particular area, A, B, and C.

Unidentified Analyst

Okay. Thanks.

Operator

Your next question comes from Gail Nicholson with KLR Group.

Gail Nicholson – KLR Group

Good morning. Are you guys seeing any comp residual mixes between the A, B, and C benches or are they all pretty much the same kind of split between, oil, gas and NGL?

Ross Craft

So far, we see a similar mix obviously we have much longer in the production history for B. And right now, based on what we have seen the mix is pretty same in this area.

Gail Nicholson – KLR Group

Okay, great. And then, I think you mentioned previously maybe in the fourth quarter of ‘13 or in the first quarter of this year that you might be doing an A, B, C stack, is that still on the agenda for later ‘14?

Qingming Yang

That is on the agenda. And hopefully we will be able to report the results of those tests before the end of the year.

Gail Nicholson – KLR Group

Okay, great. And then, just one more – what was the average lateral length during the quarter?

Ross Craft

Those are accepted as shorter in the lateral, we have one of them. And there are between 7,075 feet average.

Gail Nicholson – KLR Group

Great. Thank you.

Operator

Your next question comes from Brad Heffern with RBC Capital Markets.

Brad Heffern – RBC Capital Markets

Hi guys, just a quick follow-up maybe for Sergei on the guidance. I’m just looking at the LOE and the G&A, it looks like you need some meaningful sequential decline from the per BOE rates on both of those to sort of hit the full-year guidance. Can you give some color around how that’s going to be achieved? Thanks.

Sergei Krylov

Well, I think with G&A, we’re pretty much right on line with our guidance. And again, I just want to reiterate that while we’ve guiding its cash G&A not total G&A, the cash G&A for the second quarter was right in line with our guidance. On LOE, obviously we came in slightly higher than the guidance I think for the rest of the year, I’d certainly be pointing you towards the high end of our guidance as a good starting point for re-modeling.

Brad Heffern – RBC Capital Markets

Okay, thanks.

Operator

Your next question comes from Brian Gamble with Simmons.

Brian Gamble – Simmons

A quick one from me Sergei for some color on the disc side, obviously your contract employees for both. But how should we think about both the gas and NGL difference as well, turning for second half?

Sergei Krylov

Yes, I mean, I think it’s going to be – it’s going to be pretty much consistent with what we had in the second quarter. At this point, we have long-term contracts with DCP and we have a long-term contract with our oil marketing our firm. So you wouldn’t expect to see any significant changes in basis differential.

Brian Gamble – Simmons

So, that NGL number should be more consistent with that second quarter number rather than that low first quarter bit?

Sergei Krylov

NGLs, I mean, again obviously it’s subject to where the market it. But the actual differential would be the same or similar.

Brian Gamble – Simmons

How was your internal rate?

Sergei Krylov

For oil?

Brian Gamble – Simmons

Yes, finalize oil just for July, do you do that on a monthly basis?

Ross Craft

Yes. I mean, we’re not going to comment on monthly numbers. But again, the way our arrangement works we pay a tariff to take our crude to Cushing. So the tariff itself did not vary it a lot. So, the differential, this actually was locked in.

Brian Gamble – Simmons

Great, appreciate it.

Operator

There are no further questions in queue at this time. I turn the call back over to the presenters for closing remarks.

Ross Craft

Yes. Thanks for the questions. They were great questions. This has been a great quarter for us. We’re doing more with less. Margins are down, cash margins are up production is up. So, we continue to expect this throughout the rest of the year. One thing that we also want to point out, also the stacked laterals, results on the stacks are coming in as we get more production off of all these wells. They just seem to be getting better.

And so, with that we hope to bring you some good information on the third quarter call. We appreciate your participation. Thanks.

Operator

Thank you for joining ladies and gentlemen. This concludes today’s conference call. You may now disconnect.

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