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Sanchez Energy Corporation (NYSE:SN)

Q1 2014 Earnings Conference Call

May 8, 2014 2:00 PM ET

Executives

Antonio R. Sanchez, III – President, and Chief Executive Officer

Michael G. Long – Executive Vice President and Chief Financial Officer

Analysts

Neal D. Dingmann – SunTrust Robinson Humphrey

Brad Heffern – RBC Capital Markets LLC

Phillips Johnston – Capital One Securities, Inc.

Steve A. Furman – Canaccord Genuity Inc.

Adam Ryan Michael – Miller Tabak Co. LLC

Chad L. Mabry – MLV & Co. LLC

Dan E. McSpirit – BMO Capital Markets

Ronald E. Mills – Johnson Rice & Co. LLC

Tom Bishop – BI Research

Operator

Good afternoon and welcome to the Sanchez Energy Corporation First Quarter 2014 Earnings Conference Call. All participants will be in listen-only mode. (Operator Instructions) After today’s presentation, there will be an opportunity to ask questions. (Operator Instructions) Please also note this conference is being recorded.

I would now like to turn the conference over to Mike Long, Executive Vice President and CFO. Please go ahead.

Michael G. Long

Thank you, Nikki and welcome everybody. Before we start today, I’d like remind you that we will be making forward-looking statements. Words such as will, potential, believe, estimate, expect, and other similar expressions are intended to identify those forward-looking statements.

Such statements are subject to a number risks, and assumptions, and uncertainties, many of which may be beyond our control.

With that, joining me as presenters today are Tony Sanchez, President and CEO; and Chris Heinson, our Chief Operating Officer. We’ll start by turning the call over to Tony for introductory comments.

Antonio R. Sanchez, III

Thank you, Mike. Good afternoon to everyone on the call. First quarter of 2014 saw a continued improvement in operational efficiencies, resulting in a substantial decrease in drilling and completion costs. We are leveraging a strong growth in 2013 and realizing strong revenue and cash flows.

Our production for the first quarter was almost 1.7 million barrels of oil equivalent, an increase of 376% over the first quarter of 2013. The company’s current production is approximately 20,000 barrels of oil equivalent per day, with a total of 19 gross wells in various stages of completion, of which 12 wells are scheduled to come online later this month.

During the first quarter, we brought online 20 gross and 14 net wells, the majority of which began producing in late February and March. Revenues for the first quarter were a record $134.6 million, an increase of 334% over the same period a year ago, while adjusted EBITDA was $96.2 million, an increase of 358% over the same period a year ago.

Moving onto some of our operational highlights, we continue to experience a substantial reduction in our drilling and completion costs across all of our assets. most notably on the operated assets of Marquis and Cotulla. Driving these reductions, which Chris will describe in some more detail shortly, is improved efficiencies around rig moves and drilling time resulting from the usage of large multiwell pads and zipper fracs wherever possible.

In the technically challenging Prost asset, for example, we set a spud to TD record for the company, drilling a 17,000 foot measured depth well in 12.8 days, inclusive of intermediate casing. In the Alexander Ranch area of our Cotulla asset, we are realizing sustained cost efficiencies with drilling and completion cost per well coming in consistently around $6 million for the past two quarters. The implications of our lower cost structure immediate across all of our assets, and then what we previously considered marginal or second tier areas have now become competitive for capital on an internal rate of return basis.

As our cost structure has come down, we are adding low-risk, high-return development locations in the areas where we already have leases. Two of these areas are the portion of our Cotulla asset, which is located in Frio, Zavala and northern La Salle counties and the eastern portion of our Marquis asset, where we believe we have added a significant number of drilling locations targeting the upper Eagle Ford in and around our Sante wells.

As will be detailed shortly, we can point to almost 200 new development locations that have been added to our drilling inventory in our Cotulla and Marquis areas. In February, we clarified our well results to the Sante North appraisal well in our Marquis area.

As previously noted, out of the 22 stages of the Sante well that had been fracture stimulated, only seven plays have been successfully drilled out at the time of well test filing. The company encountered mechanical difficulties when attempting to drill out the remaining plugs due to problematic downhole conditions.

As a result of the mechanical issues, production was 215 barrels of oil equivalent per day, during our latest 24-hour test. despite the difficulties incurred. the well has the provided necessary appraisal of the Sante area through its pilot hole and production from contributing stages in the lateral and we now believe that the upper Eagle Ford will provide for development potential in this area, possibly adding upwards of 100 or more new development locations in this immediate Sante area.

With the data gathered from the Sante North and the Sante well, we now have six appraisal wells with a substantial amount of data which has enabled us to evaluate the upper Eagle Ford in this part of the trend and clearly map the expansion of this separate and distinct reservoir. The core and log data obtained indicate an organic rich carbonate member intrabedded with limestone in the upper Eagle Ford of approximately 40 feet of thickness which progressively thickens as you move east from the Prost towards the Sante area.

We believe we now have sufficient data to put together a development program for the Sante area of our Marquis asset and are enthusiastic about the development potential that the upper Eagle Ford provides. We are in the process of developing plans to drill both our first full upper Eagle Ford only test, as well as the first of a series of Austin Chalk prospects defined on seismic. These wells are expected to spud during the second half of 2014.

In the TMS, we expect to spud our first operated well, the Dry Fork East Number 2, later this month. As the industry continues to de-risk the TMS, we’re seeing some encouraging results from recent vintage wells drilled by offset operators. This year, we anticipate spudding up to four gross operated wells and participating in 10 to 15 gross non-operated wells with working interest ranging from 1% to upwards of 25%.

Overall, we are excited with the positive operational developments at the company, as we not only continue to drive manufacturing efficiency but also drive capital efficiency, resulting in a low-cost structure which makes previously marginally economic areas more viable, thus organically increasing our inventory of higher rate of return drilling opportunities.

I will now turn the call over to Chris Heinson, our Chief Operating Officer, who will provide more detail on our operations.

Christopher D. Heinson

Thanks, Tony. I’ll start by providing a brief overview of our accomplishments for the first quarter before giving additional details around each operational area. For the first quarter, we spud a total of 26 wells, 19 operated and seven non-operated, and completed 24 wells, 17 operated and seven non-operated. We continue to see reductions in well costs and have achieved a near 30% reduction in drilling costs in the first quarter, as compared to the first quarter of 2013.

We’ve also achieved major reduction in completion costs as a result of routinely utilizing zipper fracs on our multiwell pads. Completion costs have decreased nearly 50% as compared to the first quarter of 2013. Total drilling and completion costs in Alexander Ranch have decreased from $8.8 million per well, prior to our assumption of operation, to an average of sub $6 million per well over the last 12 wells drilled in the past two quarters. Decreases in total well costs continue to be attributable to improved efficiencies respective to both drilling and completion operations.

In the Alexander Ranch assets, drilling costs continued to decrease due to improved efficiencies around rig moves and drilling timing. This not only results in decreased well cost, but enables us to more quickly bring on production due to the significant decreases in drilling cycle time. In the Prost asset, an area that requires three strained well designs, costs have decreased from the range of $11 million to $14 million during the initial appraisal phase in 2013 to approximately $8 million at the end of the first quarter of 2014.

During the first quarter, we have also started drilling our program in both our Wycross and our Five Mile Creek assets. In Wycross, we have experienced increased operational efficiency with each well drilled and have already experienced decreased drilling costs of approximately 15% prior to our assumption of operation. We have similarly experienced significant operational efficiency over the span of our first four-well pad in our Five Mile Creek asset located in northwest of the Prost area.

Our drilling costs there have decreased over the course of each well drilled with our most recent well coming in at $3.4 million. We are currently in the process of completing that pad. We expect to see similar operational efficiencies carry over as we move south of Prost and begin development in our molten asset c 2014. As we continue to take additional steps in modernizing our rig fleet, we expect to realize additional decreases in both cost and time respective to our drilling program as development continues.

On completions, we continue to see realized savings around zipper fracking and operational best practices associated with pressure pumping. We’ve experienced cost decreases in our completions operation of 15% during the first quarter as previously mentioned, have decreased the costs approximately 50%, as compared to the completion operations at this time a year ago.

From the standpoint of operational efficiency, we continue to experience very high frac stage success and are yielding near maximum efficiency metric with respect to our frac stages pump per day as high as 11 to 13 stages per day on some of our more recent wells. We’ve also seen excellent performance around plug deployment where we have run over 1,000 plugs without failure. Our drilling and completion cost structure is now clearly top quartile driven by our culture of technical excellence and manufacturing efficiency.

I want to discuss how we are working to grow our inventory. As previously mentioned, we have moved to 40-acre spacing in our Palmetto Alexander Ranch and Wycross areas. Although we’ve adjusted our development plans for 40-acre spacings in our undeveloped reserve bookings, we’ll continue to be based on 60-acre development spacing until we’ve had adequate production history to provide reasonable certainty around the reserves associated with 40-acre performance.

We’ve also seen significant potential for the upper Eagle Ford growth in Marquis. We have six pilot wells drilled to date in Marquis, two with whole cores across the entire Eagle Ford and into the top of the Buddha for a total of 360 feet of core. All six wells have high-tech high resolution logs. The initial wireline log calculations of porosity, permeability, water saturation, mineralogy, EOC, and brittleness suggest an upper Eagle Ford oil-bearing zone that is potentially a separate and distinct from the lower Eagle Ford in parts of our Marquis acreage.

Coring logs illustrate organic, which royal material shale interbedded with brittle limestone intervals. A production logging tool run across the upper Eagle Ford zone that was fracked as a single stage and one of our recent Prost development wells showed encouraging contribution from the single stage upper Eagle Ford completion.

The area of potential contingent resource spans the central and eastern portions of our Marquis acreage, overlapping or stacked with the lower Eagle Ford in some areas of Prost and separate in other areas in the east where the lower Eagle Ford reservoir is thin or absent.

Recent mapping shows the potential of a minimum of 101 new locations at a conservative 120-acre spacing assumption that were not previously identified. We are completing ties of core to pilot and regional key wells into 3D seismic coverage in anticipation of a drilling, a standalone upper Eagle Ford in the second half of 2014.

The upper Eagle Ford potential combined with our successful lower Eagle Ford extension work in Prost and Five Mile Creek will continue to drive significant growth going forward. Over the last quarter, we have initiated a campaign to lease and consolidate highly prospective acreage in the Marquis region.

In the last few months, we have now leased over 3,000 acres in Marquis and we’re in the process of forming units. For example, southwest of Prost, we have leased and consolidated a 900-acre position in the heart of 1,000 barrels of oils per day wells. We are calling this new area, Molten, and have plans to commence drilling with three-well pad in that unit later there this month. We will continue to provide updates as leasing efforts result in creation of new units expanding our already considerable footprint in the greater Marquis region. Although most of our effort is directed at expanding our reserve base in these unconventional horizons, we’ve also identified conventional chalk and Buddha prospects that will be drilled later this year in our Marquis area.

Due to our drilling and completion efficiencies realized at Alexander Ranch over the past year, several areas of Cotulla previously considered marginal or second tier have been reevaluated and tested for new resource organic growth. We anticipate returning to Hauser Ranch in late 2014 to drill and complete up to four wells from an appraisal pad.

Although, in an updip position in Western Frio County, the Eagle Ford target zone contains high corosity and excellent oil saturation. We drilled and completed one Eagle Ford pilot in lateral or in mid-2013 at Houser Ranch, which remains on production. up to 70 wells at 50 acre spacing are envisioned for Houser Ranch in full development with potential for up to 100 locations if 40-acre becomes proven. Other large acreage blocks in Frio and Duval County should hold similar potential.

At Talbot Ranch, an area approximately four miles north of Alexander Ranch, we’ve consolidated 640-acre land position and units to allow long 7,500 foot Eagle Ford laterals. The first of two planned 2014 wells is due to spud this week, with an additional eight wells planned to be drilled on 60-acre spacing. At Wright Ranch in La Salle County, we’ve just drilled a 7,800 foot Eagle Ford lateral in 12 days spud to TD. We believe there could be up to seven additional Eagle Ford locations at Wright Ranch.

Moving onto production, during the first quarter, we experienced average production at 18,784 barrels of oil equivalent per day, which fell in the middle of initial guidance of 18,000 to 20,000 barrels of oil equivalent per day. We continue to expect full year production guidance to fall within the range of 21,000 to 23,000 average barrels of oil equivalent per day, recognizing that actual quarter results tend to shift within the range given timing issue associated with multi-well pad drilling.

The completion activity is now picking up again, in May, with an expectation to bring 12 wells on by the end of the month. Our guidance for the second quarter production of 19,000 to 21,000 barrels of oil equivalent per day reflects unplanned pipeline maintenance and shutdowns in May in our Cotulla area.

Now I will turn the call over to Mike.

Michael G. Long

Thanks, Chris. Some of the points I’ll making will reiterate things already said, but just to point out, we ended the first quarter with $111 million of cash and a totally unused bank revolver, which had $400 million borrowing base and an elected commitment amount of $325 million.

As previously mentioned, production for the first quarter averaged approximately 18,800 BOE/Day, an increase of almost 4% over the previous quarter’s daily rate of 18,100 BOE/Day before the impact of some prior period adjustments that increased that reported rate in the fourth quarter. This quarter’s production rate compares to slightly under 4,000 barrels of oil equivalent per day in the first quarter of 2013.

Revenues in the first quarter increased 3% to almost $135 million, compared to the previous quarter and 334% over the same period a year ago. Overall, during the quarter, we received an average realized price before the effect of derivatives of $98.21 per barrel of oil, $33.74 per barrel of NGLs and $4.84 per NCF for natural gas, which equates to an average realized price per BOE equivalent of $79.59.

Our hedges reduced our effective prices during the quarter by $5.30 per BOE $1.59 of that was related to cash settlements and the balance related to non-cash mark-to-market changes. 27% of our first quarter production and 28% of revenue came from Palmetto. Excuse me, 26% and 29% from Marquis; 38% and 34% from Cotulla, and 8% and 9% respectively from Wycross. Our production stream was 72% crude oil, 13% natural gas and 15% NGLs.

Late in 2013 and continuing in the first quarter, the drilling and completion activity was skewed toward properties that had a higher percentage of natural gas and NGLs. We expect our operating activity to return to a more traditional allocation of the course 2014.

Just to give you some perspective, the percentage of oil produced in the production stream from our various areas is as follows: Wycross 84%, Marquis 83%, Palmetto 72% and Cotulla 62%. Adjusted net income to common share holders, as defined in our press release was $9 million for the first quarter. Adjusted EBITDA, as also defined in the press release was $9.2 million for the first quarter and that compares to – $96 million in the first quarter comparing to $21 million in the same period a year ago.

A significant non-cash items impacting our P&L during this quarter in addition to the usual DD&A amounts were stock-based compensation of $9.9 million and unrealized hedge losses of $6.4 million. Our effective tax rate for the quarter was 35%, 100% deferred. At March 31, we had a net operating loss carry forward to $557 million with expirations beginning in 2031. Our cash operating expenses defined as lease operating and marketing expenses, production and ad valorem taxes and cash G&A were $26.81 per BOE this quarter.

Finally, we reported operating capital spending for the first quarter of $152 million, including estimated accruals. Our cash flow statement will report actual first quarter capital spending of approximately $103 million before those accrual adjustments.

Currently, we have about 4 million barrels of oil equivalent hedged for 2014 or about 50% of our middle of guidance forecast. Significantly, we’ve lengthened our hedge position into 2015 with approximately 6,000 barrels a day of oil hedged at an average swap price of approximately $90 and another 3,000 barrels per day hedged in callers with an average floor of $85. We have also added about 8 million cubic feet of gas per day hedged for 2015 at an average swap price of $4.45.

As previously discussed in February of 2014, we completed transaction with certain holders of our series A and series B perpetual convertible preferred stock whereby we exchanged our common stock for 947,497 shares of series A preferred and 756,850 shares of our series B preferred, plus any accrued unpaid and future dividends through the normal call date. The net result is a reduction in par value of outstanding series A preferreds to $103 million with series B to $187 million and a reduction in annual dividends payable of about $4.8 million.

The accounting treatment of those transactions other than obvious adjustments to capital included a non-cash charge for dividends of $13.9 million in our statement of operations to reflect the conversion inducement of paying future dividends with our common stock.

Operator, that finishes our prepared comments. We’re ready to start taking questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) The first question comes from the Neal Dingmann with SunTrust. Please go ahead.

Neal D. Dingmann – SunTrust Robinson Humphrey

Afternoon guys. There’s been a lot of chatter obviously a lot of your peers I guess have reported – have talked a lot about just different upper Eagle Ford success and even I think there was a couple on Austin Chalk success. I’m wondering how you all of you view, I know I think the one I was referring to as Austin Chalk they’re actually commingling the upper Eagle Ford with the Austin Chalk. So as you kind of go forward on your longer-term plan, any thoughts yet today as far as kind of percentages of going after the lower versus maybe some of the upper versus going after the Chalk? I’m just wondering sort any initial thoughts on percentage of your overall prospective acreage that might be for some of this?

Antonio R. Sanchez, III

Neil, this is Tony. I’ll start off by answering. Percentages, I wouldn’t say we’re quite at the stage yet where we have evaluated the entirety of our Eagle Ford position across the play in order to fit it to percentages, but I will say that in the Marquis area, for example, we’re very excited that in large portion of it is becoming perspective for the upper Eagle Ford. I made a comment in my prepared statements that now that we’ve got enough data that we’re able to time the seismic, subsurface data tied in the seismic along with some rock property data from cores, we’re able to clearly map a thickening of the upper Eagle Ford, as we move in a western and easterly direction from the Prost area.

So some of our offset operators in that area to the south and southeast have been reporting some results in the upper Eagle Ford that are very strong, we have been confirming those and mapping them ourselves and tying that back into our data and we’re seeing a lot of similarities and it’s really interesting as you move in that north and easterly direction.

The upper Eagle Ford starts to develop where the lower Eagle Ford thins out. In addition to that, we have just by virtue of having the seismic; several Austin Chalk prospects pop out. It’s not a small number, but it’s not a – on the Austin Chalk side, going to become a resource play. But I think we will be in a position to drill some very attractive Austin Chalk prospects in the second half of this year and into next year.

So to kind of sum that up, it’s certainly developing as a stacked play dynamic in our Marquis area, and as we go into the second half of the next – of this year, we will start developing that out. So within that play, we’ve got 10,000 acres of Prost. We’ve got 10,000 acres of Five Mile Creek that we feel that we are in the process of developing the lower Eagle Ford. It looks like in that area the upper Eagle Ford will be developed as well. And as you move east, then the upper Eagle Ford becomes the dominant play.

Neal D. Dingmann – SunTrust Robinson Humphrey

Okay. Go ahead. I’m sorry, Tony.

Antonio R. Sanchez, III

Nothing to add.

Neal D. Dingmann – SunTrust Robinson Humphrey

And then I was going to ask about – I know you’re starting to do more of the extended laterals and obviously, what I’d call the more efficient completion techniques. I guess based on just sort of the services you have out there now, the six gross growing rigs and the completions that you’re using, are they all able to sort of adhere to that or I’m just wondering would you have to change anything? I mean I get, I know you have a lot of that, you’ve talked about that and you talked about going to more of that. Just wondering if you would have to change anything around in the design, and then a second question around that, Tony is, if you do that, I mean just wondering sort of idea, everybody always asks about service costs in general. Are we seeing – again, by doing that in some of these extended laterals and such, are there additional service costs that are going up quicker with this or is it just sort of blend in with the overall service costs in general?

Antonio R. Sanchez, III

I’ll answer that briefly and then turn it over to Chris. It’s marginal. Going from 6,000 to 7,500 foot in a lateral is a marginal cost. All of the equipment that we’re using from a drilling perspective is fit for purpose. And fracking out in the longer laterals is also – the capabilities are well within the abilities of the service companies that we’re using.

So from our perspective, the longer, the better, when we could drill it, any constraints that come along tend to be lease line constraints that might govern the shorter lateral. So the answer is, we don’t think there’s any additional costs other than few extra days or necessary. What is absolute – what we have found absolutely critical is staying within our targeted zone. In some cases our targeted zone maybe 20 feet. So, extending the lateral allowed 6,000 or 7,000 feet, it’s not just getting out there, it’s getting out there and staying in zone that matters.

Christopher D. Heinson

Yes. Just to elaborate a little bit. We actually have a very modern rig fleet right now. In fact, four out of our five rig fleets right now are quite modern and by the end of this year, it’s anticipated our entirety of our rig fleet will in fact have the high pressure of mud systems that really are optimal for those very extended reach horizontals. So we don’t see there will be any technical limits actually anywhere in our program to get out there 7,000 plus. And in fact, we are doing that now when our acreage is early on in development. So, you should expect to see us to more of that going forward.

Neal D. Dingmann – SunTrust Robinson Humphrey

Got it. and then just lastly, just on continuing to add acreage, Tony, your thoughts on what you’re seeing available in either the TMS or the Eagle Ford and are you continuing to look at – if you are continuing to look at other plays other than those two, would it have to be a rather large block to jump in something else?

Antonio R. Sanchez, III

Yes. I’ll answer that real quick, the short answer is yes to the first part. We’re adding acreage in Marquis. we’re adding acreage down in La Salle County and the other parts of our traditional Eagle Ford area. We're also adding acreage in the TMS. I said most of the acreage that we’re adding to TMS are small blocks that we’re using to fill out, our units that we formed in preparation our drill program. So the quick answer is yes, you may have noticed we’re not reporting on a regular basis where we’re adding acreage and at what price and that’s purely for competitive reasons and I don’t think that’s going to change. So, short answer is yes, we’re adding acreage. We’re picking it up. But we’re not going to be specific right now as to where that acreage is being added.

Neal D. Dingmann – SunTrust Robinson Humphrey

Okay, thank you.

Antonio R. Sanchez, III

Yes.

Operator

Thank you. The next question comes from Brad Heffern with RBC Capital Markets. Please go ahead.

Brad Heffern – RBC Capital Markets LLC

Hey, afternoon guys. In your prepared comments, you talked a little bit about unplanned pipeline maintenance in Cotulla. I was wondering if you could just maybe, provide a little more color around that and maybe, quantify how long things are down for and what the volumes you’re feeling like you’re going to lose are?

Antonio R. Sanchez, III

Yes. There has been three pipeline downtimes that two of which were not planned. they’re just doing some maintenance on the lines and one of which was sort of plans downtime that it’s taken a little bit longer to get back up. Right now, we don’t think it’ll have a major impact on production, but the guidance that we’re giving today factors in to roughly 100 barrels to 200 barrels of oil equivalent impact in the second quarter.

Brad Heffern – RBC Capital Markets LLC

Okay, got you. Speaking about the cost reductions you guys cited as potentially opening up some new areas, it sounds like a lot of the acreage that you’re talking about is the old Maverick stuff, is that correct? And has there been expirations during that time period? I’m just trying to get a sense of potentially how much acreage has been opened up as a cost savings?

Christopher D. Heinson

Some of it is the old Maverick stuff certainly, there is one position there, that’s already held by production called Houser Ranch, which is just under 6,000 acres. We could – we’ve actually been very pleased with our well performance on the first Houser well. The formation is shallower. There’s not as much energy in the reservoir. So we didn’t get a high peak, what we did get was a much flatter decline in the well and are actually – each time we look at it getting more impressed with the performance of that well. As we bring costs down, those wells have moved into 30% to 35% plus rate of return category, which to us is kind of a minimum hurdle rate. So more of that acreage is now becoming available.

we haven’t lost much acreage that we’ve let go in the area, has been let go, because the renewal options were too expensive. But we’ve got landmen out that are picking up some acreage. On a cost effective basis, again, because it's sensitive to costs, we can’t go out there and just pay whatever for acreage and we’re not going to do that. But we still have quite a bit of acreage out there to develop and just to give you some perspective, Houser. the Houser lease, which is in Frio County on the border with Cebala, is less than 6,000, just under 6,000 acres in size.

We think we could fit upwards of 70 or more wells on that position, so a lot of drilling to do with not a lot of acreage. Over in Marquis, same concept, but slightly different, a lot of acreage is now becoming perspective, moving to the eastern Prost. So Prost itself is expanding to the south and the east as we’re drilling more wells, because we’ve had successes in the lower Eagle Ford. But also to upper Eagle Ford as I mentioned in my prepared statement is now perspective. And so, more acreage that we previously were waiting onto be delineated, I think, now it’s much more likely to be developed.

Brad Heffern – RBC Capital Markets LLC

Okay. Got you. And then moving over to Five Mile Creek, I was just wondering if you could provide some color on what your expectations are for those wells. I think it’s a little shallower than Prost, so are you expecting lower EURs but also slightly lower costs? Is that how we should be thinking about it?

Christopher D. Heinson

I think I would be accurate in general. However, in terms of thickness, the thickness of that lower Eagle Ford member looks everybody as good as the whole Prost block. So about the only thing that you’re giving up is a little bit on debt. So, by and large, we expect it to be very similar to the closed results, maybe very, very slightly less, we’re talking like 5%. But they are going to come in, hopefully once again, to development mode, a good kind of 15% less, because we can go out with a two-string approach rather than three-spring design that we see over in the first block.

Brad Heffern – RBC Capital Markets LLC

Okay. Thanks, guys.

Operator

The next question comes from Phillips Johnston with Capital One. Please go ahead.

Phillips Johnston – Capital One Securities, Inc.

Hi guys, thanks. Just on that Dry Fork east well, obviously, you’re planning on 7000-foot lateral, but can you give us any more details in terms of planned stage count, like what kind of plugs you plan to use? Whether you plan to use cross-linked gels or slickwater? And also if you can disclose what the AFE might be and what sort of additional size that might include?

Christopher D. Heinson

So, some things I’ll answer in a general sense. So we’ve looked at the TMS wells and TMS well designed, and we’ve made several changes over what other operators have typically being doing in the last couple of years. Just based on our experience, largely in our Marquis region where we have similar issues with host ability and softer rock. so we’ve gone at it with a little bit beefier casing has a much higher burst pressure than some of the previous attempts. We think that’s going to be a part of our success. And again, on plugs, as I mentioned earlier, in the Eagle Ford, we’ve run over 1,000 plugs without failure. There is few things we do process wise that we think give us an advantage on plug deployment. I think that’s ultimately going to be helpful going over to the TMS as well. I’m not going to go into too much detail on our actual frac design.

Your other question was what are we trying – what are we planning on doing science-wise? We are drilling a pilot. And in fact, as you see with Marquis, we believe taking strategic data collection points early on in the play’s development ultimately sets you up for better development going forward and we are doing that on our first well.

Phillips Johnston – Capital One Securities, Inc.

Okay. And it looks like it’s relatively close to Crosby and has pretty similar depth. Any material differences that you expect in rock quality or anything else like that?

Christopher D. Heinson

We like the TMS zone in fact, the TMS zone itself looks similar in richness to the Crosby. But as you know, there’s some variability but we are optimistic that hopefully we see a similar result.

Phillips Johnston – Capital One Securities, Inc.

Okay. Can you share any details on the Lawson well that you guys participated in and what you might have learned that you didn’t already know about the play?

Christopher D. Heinson

I’m not going to go into too much detail on the Lawson well, because I want to make sure we’re consistent with our partners’ communications publicly. But we are having great success working with the other operators in the TMS. I think we’re working and it’s really becoming a collaborative process going into 2014 with most of the major holders. So we are communicating substantially, because we all know that we benefit from towards unlocking the technical challenges collectively.

Antonio R. Sanchez, III

I’ll add a little bit to that. This is Tony. And without having specific contract in front of me, I can’t get too specific as Chris mentioned, but I will say we’re very pleased with the flow rates out of that well on an IP basis. I’ll say they were very strong, exceeded our expectation. I think it was also a short lateral, 4,500 feet or so.

Phillips Johnston – Capital One Securities, Inc.

Yes.

Antonio R. Sanchez, III

4,900 feet, something like that. I’ll say it exceeded our expectation, probably by about 50%. So we were happy with it. It’s held up nicely. And I think that it certainly provides us data that we can take and apply to our own development efforts. I believe our working interest is only about 2%. After having seen the results, which we had a lot more.

Phillips Johnston – Capital One Securities, Inc.

Okay. Good. Lastly, in sort of the northeastern portion of Marquis, is it safe to say that despite the mechanical issue that you had at Sante North, is it fair to say that you’re more encouraged about sort of the greater Sante area than you were, say, four months ago or so?

Christopher D. Heinson

Yes, undoubtedly. What we found from the Sante North, given our difficulties from a mechanical perspective we were able to pick up some very good results. And almost by accident, we fracked the upper Eagle Ford part of that well. And through some of flow back result, I think we were able to determine that upwards of 20% to 30% of the flow in that well was coming from that one stage in the upper Eagle Ford. So it is something that I think we are very happy to see. Any one piece of data is not definitive, but as we aggregate that with our cores, with the logs that we’re getting from our appraisal wells, with the seismic we’re able to make a determination that the upper Eagle Ford is something that we’re going to be able to develop as a resource play.

So six months ago, you asked, I think we were up in the air, we weren’t sure as the lower Eagle Ford thinned in that direction, how far we could push it out. I think we’ve also in that regard been positively surprised that the lower Eagle Ford is working a bit further than we had expected. And the upper Eagle Ford is kind of taking its place, at least from a science standpoint so far and as we go into development, there are a lot of the indications are that it’s going to be a standalone reservoir that will be a candidate for resource development.

Phillips Johnston – Capital One Securities, Inc.

So what percentage of your total 69,000 net acres in Marquis, do you think is derisked at this point?

Christopher D. Heinson

Well, we’ve got the 20,000 acres between Prost and Five Mile Creek that I would basically, say is derisked. I’d add another 10,000 acres that are mainly around Prost, but are not the core part of Prost, but an extension of Prost and would probably classified as Prost that we can now add to that kind of derisked category based on wells that we brought on even in the first quarter in the fourth quarter last year exceeded our expectations. So that’s about 30,000 acres there.

And then as we move into the area that starts with the Sante area, let’s just say that’s another 20,000 acres there and we could probably look at half of that, maybe 5,000, 10,000 acres that we think based on the data we have now, is likely moving into that derisked category pretty quickly. So that leads to another 10,000 to 15,000 acres that is scattered throughout the greater Marquis area is yet to be determined. So take that out, you’re really talking about somewhere between 35,000 to 45,000 acres in Marquis that we feel very strongly now will be developed in this fashion.

Phillips Johnston – Capital One Securities, Inc.

Great. Thank you.

Christopher D. Heinson

Yes.

Operator

The next question comes from Steve Furman with Canaccord. Please go ahead.

Steve A. Furman – Canaccord Genuity Inc.

Thanks, good afternoon. You gave us some very good numbers on cost savings and efficiencies, et cetera. Could you talk a little bit more about well performance, whether it’s how these wells by area are tracking your type curve or average 30-day rates? Is there anything to give us a little more color on how the wells are actually doing?

Christopher D. Heinson

Yes, this is Chris. By and large, our wells are all hanging in there and maybe in our type curve expectations there is a sort of an interesting kind transition that we’re going to in regard to reserve bookings, in that, our reserves are currently booked on 60-acre development, yet we’re developing wells on 40-acre. And you do see very, very small degradations in performance when you go down to the 40-acre spacing relative to the 60-acre.

You don’t get quite as high as an IP is the original 60-acre wells. So we have that factor sort of working on our current production, yet our reserves by and large don’t reflect the uplift of locations that you would get on the 40-acre spacing that actually make it a value added proposition and moving forward so. Right now, we are in a little bit of transition, but we’re very happy with our performance overall.

Michael G. Long

Steve, this is Mike. Let me add one thing to that. This is how we address reserve bookings. We do every six months, we do full reserve analysis, employ our own work. we work Ryder Scott and do full updated changes to our reserves. In the odd quarters, first and third quarter, we simply do a low forward. We don’t do any reserve bookings tied to activity, nor if it happens as you look at production during the quarter, you run that off. You may be change category. If you drilled a previous PUD well, it’s now PDP. It moves category. But we don’t address reserve volumes and in significant way in those off quarters. So you’re not seeing the impact of what Chris was talking about in our reserve bookings.

Also, if you look at individual quarter depreciation rates, you see the first and third quarters are really an artificial depletion rate. They don’t take up the benefit of what we’re doing on a reserve side. it’s really at the six month and year-end periods where we do that significant true up to depletion rates. So for instance, this quarter’s depletion rate is a probably little higher than people might have expected, it wasn’t because of anything organically, or cost wise going on at the firm. It’s just our methodology of reserve bookings.

Steve A. Furman – Canaccord Genuity Inc.

All right. Got you. And then one question for you, Mike. Based on your preferred dividend comments in your prepared remarks, so going forward, the quarterly rate is $4.3 million, roughly $4.2 million, $4.3 million, based on the amount that’s still outstanding. Just want to be clear on that?

Michael G. Long

Correct. I mean you saw significant one-time non-cash dividend charge in the first quarter and that’s really just the recognition through the income statement of using our stock to prepay the dividends on those early converted shares.

Steve A. Furman – Canaccord Genuity Inc.

All right, great. Thank you.

Operator

The next question comes from Adam Michael with Miller Tabak. Please go ahead.

Adam Ryan Michael – Miller Tabak Co. LLC

Hi guys, A lot of my questions have been answered, but if I could – I had to go back through my notes about almost a year and a half ago to find some of the old Maverick wells and I’m just curious, I know drilling costs have come down over the last couple years, but could you maybe discuss completion techniques and how they’ve evolved over the last year and a half, and what you might try that’s a little different on some of these areas that used to be marginal and may actually be pretty decent now?

Michael G. Long

Yes. We’ve taken approach that completion should be designed to optimize value, okay. So in areas like Maverick, I think the lessons have we’ve learnt once we got into development mode at Alexander Ranch, at Marquis, was going at it with more profit, more stages is not always the best approach. That is there is a sort of an optimum in terms of value that you can achieve by putting an investment. And so what we’re trying to do is number one get well drilled as efficiently as possible and we’ve gotten quite good at that. but at the same time what we’re trying to do is also custom tailor the completion jobs, so that it’s not overstimulating the reservoir that we have.

So with that, we’ve sort of looked at some of these economics and all of areas and we are looking Adam, is that okay, we’re – what are they running at right now, we stopped development there, because they were 15%, 20% IRR. Well, now the biggest factor that changes that is our cost structure. If you can drop $1 million off of don’t completion, your internal rate of return goes up roughly 10% to 15%. So, we’ve looked at what we can do drilling now, I mean looked at what the appropriate completion designs are and now we start becoming confident that we could make attractive wells in a lot of these areas.

Adam Ryan Michael – Miller Tabak Co. LLC

Okay. That's helpful. And then some of these blocks, the Hauser lease, it looks pretty blocky. Like what do you think the optimal horizontal length is on these wells? And like, how do you anticipate drilling them? Is it like a 7,000 foot horizontal or 5,000 or..

Michael G. Long

Yes. So, in the Hauser, it’s a big blocky lease, essentially if you can imagine, there is going to be a low of multi-well pads kind of along the spine of that lease. It’s kind of a big rectangle. And what we’re going to do, we’re going to push long laterals going toe up and toe down from that multi-well pad, and essentially that’s going to be the design. So we’re going to have anywhere from over 7,000 foot laterals, 5,000 foot laterals just depending on the ranch’s actually shape and size relative to where that spine runs.

Adam Ryan Michael – Miller Tabak Co. LLC

Okay. And just quickly on Palmetto, any plans there to test upper Eagle Ford or Austin Chalk?

Michael G. Long

Eventually, I think there some more development work to do at the southern end of the ranch, as we tighten up spacing with Marathon, we’ve talked about it from a high level, I know they’ve got some ideas about developing the Chalk on the northern part of the property and upper Eagle Ford, we’ve mentioned it a few times. But I think in that area that, the well performance is so strong in the south that it’s probably going to be a while before we move away from that and start testing other formations. but absolutely, definitively there is potential for that, but it’s not priority one.

Adam Ryan Michael – Miller Tabak Co. LLC

Understood. That’s all for me guys. Thank you.

Michael G. Long

All right.

Operator

The next question comes from Chad Mabry with MLV. Please go ahead.

Chad L. Mabry – MLV & Co. LLC

Thank you. You mentioned Chalk and Vita locations on your Marquis acreage. Just curious if you could help us quantify the potential there, and then the timing that you are planning to test those formations.

Christopher D. Heinson

Yes. We plan on actually shortly drilling our first Buddha and our first Chalk well over in the Marquis region. Now it’s largely driven by seismic and we see several seismic features that we think are going to lead to the sort of conventional oil and gas potential, ball park numbers, we’re roughly saying maybe half a dozen to a dozen Buddha locations and about the same in Chalk. But we see both potential for them all over our acreage position right now. So I mean there are certain areas that we’re going to focus on initially, but I think we may see exploration over the whole block.

Chad L. Mabry – MLV & Co. LLC

Okay. That’s helpful. And then a follow-up if I could on rig rates, just curious what kind of contracts you have in place, how much term, et cetera, and what you’re seeing on movement on rig rates right now?

Christopher D. Heinson

So, rig rates, we’re still giving rig contract rates and about the same rate that we’ve been getting. Now competition for these modern high-tech rigs with XY walking systems and 7,500 PSI mud system has definitely gotten tighter. They used to be, you could pick up the phone and call you have any rig you wanted that month. Now it takes a little bit of planning. We tend to take the approach that we want short-term rig contracts. And they’re sort of staggered, so that none of your rigs – you don’t get a whole cluster of rigs kind of going off contact at the same time. It’s sort of a staggered approach. So you’re always bringing on a new contract roughly a year. In some cases, 18 months out in advance, and so it kind of ladders.

Now we’ve had success finding other operators that are looking for 12-month type commitments as well. So right now, it takes a little bit longer to find someone that wants the same sort of contract we had, but we haven’t seen much creep in terms of rates yet.

Chad L. Mabry – MLV & Co. LLC

Very helpful. Thank you.

Operator

Thank you. The next question comes from Dan McSpirit with BMO Capital Markets. Please go ahead.

Dan E. McSpirit – BMO Capital Markets

Thank you, gentlemen good afternoon. On the TMS, the company currently owns a 50% working interest and an 80,000 net acre AMI. Is the remaining 50% available for sale at any point? And does the company have any right of first refusal or any other claim to that leasehold?

Christopher D. Heinson

Yes. We don't have a right of first refusal, but we have a right of first offer. And we have tagalong rights. So the answer to your question is it available for sale? It’s going to be a typical answer. It depends. It depends on the price. I will say that collectively here, we’re very excited about the play. There’s no question it’s headed in the right direction. Well results are getting better. Costs are coming down.

And the resource potential of the TMS is massive. That’s why we got into the play to begin with. So it’s headed in the right direction. Is it for sale? I would guess at some point, yes. The way we structured the participation agreement provides for either side to have tagalong rights, as well as why the first offer which we believe to be a constructive right and not one that takes away. I think a right of first refusal often hampers value creation. So short answer to all your questions is yes.

Dan E. McSpirit – BMO Capital Markets

Yeah. I appreciate that. And then just on the subject of inventory, if you could help me total this up, assuming the downspacing test proves successful as well as those targeting the upper Eagle Ford shale, to what number does the inventory count increase? Is the number greater than 300 locations?

Christopher D. Heinson

Well, we pointed to 200 locations or more, simply adding the identified potential locations for the upper Eagle Ford in our Sante area plus around 70 to 75 potential locations in the Hauser lease of our Maverick area – of Cotulla now. So between those two, we’re pushing a 175 to 180 locations, plus you’ve got smaller than 5000 acre blocks in La Salle, also in our Cotulla area, but in La Salle, southern Frio and Dimmitt County that we refer to them by lease Wright Ranch, Talbutt Trust, Cenizo, once you start aggregating those based on typical 60-acre well spacing there, you easily get over 200 locations. And that’s not really counting the already identified locations. The ones that I’ve just mentioned or in addition to what we’ve already – what we’ve already got on our internal books for the next several years.

Dan E. McSpirit – BMO Capital Markets

Okay, great. Then lastly here on the DD&A expense, what explains the somewhat elevated rate? And how could that change over time?

Christopher D. Heinson

Dan, I can give a simple answer. Time will tell a more definitive answer. The simple answer is our rate of booking of reserves, and the rate at which we move a value that’s unevaluated today is in the neighborhood of $250 million to $300 million, the rate at which we move that into the full cost pool. We have defined formulas for doing that that’s based on each quarter’s review of activity and what we think future drilling activity could be and we move percentages in. But our history is we started with this company as a public company with, I think 6 million barrels of proved reserves, 10 producing wells and a lot of undeveloped acreage.

So it’s going to be, we believe, maybe a somewhat along, but steady march down in our depletion rate overtime, as we continue to delineate move to our acreage position. And then periodically, every so often when you do a significant transaction, an acquisition, this kind of a step change in what we’re doing. But specifically in this quarter, depletion rate is really a formula as opposed to operating results driven. And you’ll see – we take different approach to June 30 at 12-31. I can’t give you guidance. We know for certainly looking to the future the depletion rate's going to move from X to Y based on our expectations. That would be unrealistic. But we do expect to continue hopeful steady decrease in that rate.

Dan E. McSpirit – BMO Capital Markets

Got it. thanks, again.

Operator

Our next question comes from Ron Mills with Johnson Rice. Please go ahead.

Ronald E. Mills – Johnson Rice & Co. LLC

Good afternoon. Tony or maybe Chris, just a clarification on the upper Eagle Ford locations you talked about the 170 to 180, the Hauser is pretty clear at 70 plus, but in Marquis, the 100 plus, how much of those do you think are more in the Sante area versus you’re now starting to talk about some opportunities for the upper Eagle Ford, whether it’s in Prost proper or some of the southern extension of Prost and/or Five Mile Creek?

Antonio R. Sanchez, III

Yes. Hi, Ron this is Tony. Let me clarify one thing first. The 170 to 180 location between those two, the locations that we’re talking about at Hauser are lower, traditionally lower to Eagle Ford location. So we’re really having in the start to look at the upper Eagle Ford in that area. That’s just – that’s another mill old-time Eagle Ford. Over at the Marquis area, the bulk of the locations they were attributing to upper Eagle Ford potentially in the Sante area. And some of them are between Sante and Prost. So I would say – Chris, you can confirm this, most of them are in and around that Sante area.

Christopher D. Heinson

Yes. In the eastern Prost block we actually see potential for some dual horizon development where you still see both a true lower Eagle Ford target and a separate distinct upper Eagle Ford target, or maybe some multi-horizon development along that Eastern half of Prost. But by and large, the upper Eagle Ford potential is east of the Prost block itself.

Ronald E. Mills – Johnson Rice & Co. LLC

Okay. And I think in the conference call yesterday, one of the large independents highlighted the upper Eagle Ford up with some results in Lavaca County, at least somewhat on Stryker or moving towards your Marquis position, which is those were south and west of your Prost proper. Does that have any application to any of your additional acreage potentially or is it just too early to tell?

Christopher D. Heinson

It’s a encouraging, I will say that what we’ve seen and we’ve noted from our pilot work is although there is just distinct down this upper Eagle Ford down, it does vary where you are in the play, and it doesn’t look the same, potentially five miles to the southwest, but that gives into the benefit of that actually the pilot work that we’ve gone in fact, we were mapping or development of the upper Eagle Ford across our block. And I think that’s the regional trend is telling you something is developing on the strike. I think it’s going to, we’ve got to find sweet spots along as southwest trends, or upper Eagle Ford can be particularly productive going forward and we are going to be looking some opportunity to grow on that.

Ronald E. Mills – Johnson Rice & Co. LLC

Okay. And then staying in Marquis a little bit, the Five Mile Creek versus Prost, you talked about, but it sounds like you’ve also been either picking up acreage a little bit but also increasing activity in kind of a southern/southeastern extension of Prost. What are you seeing in those wells versus your initial Prost wells? And from a Five Mile Creek standpoint, should we think about them being pretty similar to the initial the Prost wells, just given the depth characteristics?

Antonio R. Sanchez, III

Yes. This is Tony, Ron. I think Chris addressed it briefly vis-à-vis Five Mile Creek in that we expect the reservoir actually get, maintain the quality or even get better is in moving to Five Mile Creek. So that the large portion of Five Mile Creek area we expect to be just like Prost, which we’re very happy with. Moving south of Prost, moving south with our Prost asset, we’ve been very pleasantly surprised by the quality of the wells we’ve brought online with performance and the way they’ve held up.

We are looking, we are adding acreage opportunistically around both of those areas and we’ve had some successes lately, I could say we’ve added a few thousand acreage here and there, not anyone block just because of the nature of the leases that are all tend to be pretty small and are already unitized. So, I don’t think there is a substantial amount of acreage to add. But there is some to add here and there to fill our units.

Ronald E. Mills – Johnson Rice & Co. LLC

Okay. And then over to Cotulla, you talked about both the Wright Ranch and the Talbert Trust positions. I think when you bought the properties from Hess; you had really run the economics based on the PDP and a limited number of pods just at Alexander Ranch. Am I remembering that correctly that these any success in those two areas can only serve to enhance the economics of that acquisition?

Antonio R. Sanchez, III

Yes, definitively. We based that the large majority of our purchase price on Alexander Ranch. and then we gave value to the PDP of the wells outside of Alexander Ranch, but no value to the undeveloped acreage. So the undeveloped acreage was undeveloped that we’re now drilling on is over and above the value. We did some quick and dirty math on that acquisition recently. When we bought it, it was around 4000 to 4500 barrels a day. It’s now producing 7,000 to 8,000 barrels a day. We’ve added reserves, we’ve tightened up spacing predominantly in Alexander Ranch, and we’ve begun to layer in some additional development acreage.

So just kind of using some rough numbers, we think that of our whatever $280 million purchase price, we’ve – I think we can make a case that we’ve already doubled of value that asset inside of a year. So, and I can make the case that we more than doubled it. But I think we’re very pleased with where we are in that asset.

Ronald E. Mills – Johnson Rice & Co. LLC

Okay. And then, two real quick ones, in the Sante area, when do you think you’ll have a rig going back up there? Just from a timing standpoint to start testing the upper Eagle Ford? And when you talked about just pace of completions or timing, you brought on 20 wells in late February and March. You talked about starting I think it was something like 13 here in May. It sounds like you also have some in June. What’s the total number of completion, you think you’ll get on here between now and the end of the quarter?

Antonio R. Sanchez, III

All right. So you have two different questions. Total number of completions between now and end of the quarter, all right, we’re working on that. You asked about when we’re going to be drilling. Let me while these guys are getting some numbers for us. I’ll address the question about when we expect to drill a well targeting the upper Eagle Ford. We said second half of this year, more specifically I would expect it September slight only because we need to work it into our rig schedule. So, right in about September.

Ronald E. Mills – Johnson Rice & Co. LLC

Okay. That’s all for me. Once you get that answer it would be great.

Antonio R. Sanchez, III

Well. We need to answer your question. How many well are going to be there completed this now and June.

Ronald E. Mills – Johnson Rice & Co. LLC

Yes.

Antonio R. Sanchez, III

15 wells to 20 wells.

Ronald E. Mills – Johnson Rice & Co. LLC

Perfect. Thank you very much.

Antonio R. Sanchez, III

All right. Thanks, Ron.

Operator

The next question comes from Tom McCarthy with BI Research. Please go ahead.

Tom Bishop – BI Research

Okay, that’s Tom Bishop. I just a got a few mop-up questions. Given the conversion of some of the preferred, what would the preferred dividend be for the quarter going forward just, so we’re all clear on it?

Antonio R. Sanchez, III

Well, I think some I just went through that. It was about $4.3 million a quarter.

Tom Bishop – BI Research

Okay. Sorry I missed it. $4.3 million a quarter. Okay. And also the non-cash stock-based compensation was $9.9 million just in Q1 alone. That’s great. And this quarter anyway came out to 50% of SG&A. I’m not sure what’s going on there, but as is more importantly what should we anticipate going forward on that?

Antonio R. Sanchez, III

Okay. We’re working through numbers to split it out for you.

Christopher D. Heinson

But generally, the driver of that value is the stock price. There’s also yes, just wrote us a note. So there was some $1.3 million of that value is attributable to our former Chief Operating Officer stock grant that was unvested that is recognized, benefit. Sorry. Vested that was – while he was here would have been amortized over the course of three years. And when he left, that accelerated and recognized in the quarter.

Michael G. Long

Yes. That’s GAAP accounting for that stock compensation. The balance of what you see is there’s is there’s a continual quarterly mark-to-market of value of all unvested, granted but unvested restricted stock. And…

Christopher D. Heinson

But I think we changed that much this quarter.

Tom Bishop – BI Research

I’m sorry. What?

Christopher D. Heinson

I didn’t think we’ve changed that much this quarter. That’s where I was a little confused.

Michael G. Long

If the average stock price previously to that compare hasn’t that much, I guess a year ago

Antonio R. Sanchez, III

I guess a year ago it was different, though.

Tom Bishop – BI Research

But quarter-to-quarter, there’s a substantial change. So I’m looking at a stock price chart here. The first quarter is substantially higher than the fourth quarter of last year.

Christopher D. Heinson

And in January, we do our annual grants of restricted start to employees. And so you’re seeing in this particular quarter, you see the impact of all those new grants hitting and then that gets amortized out over time.

Tom Bishop – BI Research

Okay. Did you say at a completion costs dropped by 15% or 50%? I just didn't hear the number right.

Christopher D. Heinson

Yes. It’s dropped 50% year-over-year.

Tom Bishop – BI Research

50?

Christopher D. Heinson

50, yes correct, it’s significant – a year ago, we were mainly doing appraisal work. So wells tended to be one at a time. Now we’re doing all multi-well pad drilling. Essentially, it’s 98% plus multi-well pad drilling. And so we’re making much better use of our pressure pumping services when we’re doing those multi-wells through that zipper fracs process that I’ve been talking about.

Tom Bishop – BI Research

Okay. I’d like to evaluate the company’s based on – in this case, adjusted cash flow per share. And I missed that number if you went through it. Did you have that?

Michael G. Long

Adjusted flow? Adjusted EBITDA I think was 90

Tom Bishop – BI Research

That one I got, but cash flow per share?

Christopher D. Heinson

We didn’t give that number.

Tom Bishop – BI Research

Okay. I'll check the source on that. And finally, could you say again, what your working interest is on the wells in this year and the TMS? And they’re budgeted it looks like at roughly $20 million each, is that correct?

Christopher D. Heinson

No. So our working interest – no. No, they’re nowhere near budgeted at $20 million. Our working interest in every well we drilled this year is going to be different. The way mineral ownership works in the TMS in our acreage positions is laid out, we may have some wells or we have high working interest. We may have some wells where we have 1% or 2% working interest based on the…

Tom Bishop – BI Research

I’m talking about the TMS, right?

Christopher D. Heinson

Yes, right.

Tom Bishop – BI Research

Yes. Okay. Go ahead.

Christopher D. Heinson

The mineral ownership in a unit can vary from unit to unit. So it's not a uniform land position where you have a flat 100% or 50% working interest in the minerals across the position much more broken up so it’s, I think our budget guidance for total CapEx in the TMS this year, is in a roughly 10% of our total capital budget range which is talking, $60 million to 65 million, there you might have a $14 million or $13 million AFE well, while we have 2% we might have $13 million or $14 million well we have 50% interest. All of those based on our best estimate at this point in time add up to at the middle of the guidance about $65 million capital budget plan for drilling in the TMS this.

Tom Bishop – BI Research

Okay. I think my problem was that I had thought I understood that you were just drilling to wells this year. I guess you're drilling quite a few more than that.

Christopher D. Heinson

So we expect to drill we operate and spud four wells this year. Each of those wells will have a different working interest them. We expect to participate in 10 to 15 non-operating wells drilled by other, but we could have working interest of 1% to 15% to 20%.

Tom Bishop – BI Research

Okay. All right. Thank you very much.

Christopher D. Heinson

Yes.

Operator

The next question is from Steve Marshall private investor. Please go ahead.

Unidentified Analyst

Thank you very much, and congratulations on a good quarter guys.

Christopher D. Heinson

Thank you.

Unidentified Analyst

My question is also associated with stock compensation as a percent of general and administrative cost. And I’m just curious given the fact that stock compensation in the quarter was $9.9 million and the net income was $9 million and I understand that there are tax differences and accounting differences in the way those numbers are represented, but can you can you share with me just a little bit about why the Board and the company felt like taking the restricted stock options went addition to $800,000 from $590,000 last year which represents 35% is warranted?

Christopher D. Heinson

First I like to say couple of clarifying statements you can mind all this compensation expenses, it’s non cash, it’s the way we amortize the expected value of that stock is invested overtime. Over the course of last year, we added approximately 50 new employees to the firm to deal with the rapid increase in activity level and size and scope of the firm. So the commensurate increase in restricted stock brands to that growing employee base, there was nothing materially different in the percentage of grants necessary were made for individual it’s a growing employee base that consumes more debt, stock debt, also plan with a stock available as available as long-term compensation for employees. You are there Steve.

Unidentified Analyst

Yes I’m here. I mean in the 800,000 that was drilled 340,000 to the company, was it not?

Christopher D. Heinson

I think if you look, I don't know the exact number that went to certain people, I don’t think it was that large an amount. Regardless of the fact, if you look at what we accomplished last year, the Board looked at the fact that we essentially doubled the reserve base of this company more than doubled the production of this company. Tremendous increases in EBITDA and cash flow were reflective of the rewards that they thought were appropriate to give.

Unidentified Analyst

And you guys did a nice job, so I don't want to suggest otherwise, it just seems like to the average investor that two numbers I quoted initially seem to be a little bit disproportionate, let me just break that right.

Antonio R. Sanchez, III

Well I think and this is Tony Sanchez, I think that the board took a very thorough approach, particularly comp committee. And I know they lean on a couple of different services take a rather large number of our comps. And based on their compensation metrics zero and on a number and depending on how we do in the year, we get compensated. Last two years I think I’ve been good on the growth perspective, I know that they have really placed a lot of importance on the way we could manage the company, i.e., ramping from basically no drilling to 70 to 80 wells a year, and the addition – the people addition that comes with an integrating those people into our processes have been recognized.

So as Mike mentioned, we added 50 people last year. I know in the first quarter of this year, we looked at what our hiring needs were going to be from the – for the entirety of the year-end. And we brought on about 15 to 20 new people this quarter on a net basis is much less than that, because we’ve also transitioned some out. But, we are growing company and when these good people come around, we make use of our equity availability to bring them on board, because we really think that ties then to management and to the shareholders.

Christopher D. Heinson

And look there is trial on being a long-term holder. So, I’m rooting for you guys. And so I appreciate your candor on that. So, thank you very much.

Antonio R. Sanchez, III

All right. Thanks, Steve.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to the company for any closing remarks.

Antonio R. Sanchez, III

Okay, this is Tony. I want to thank everybody for being with us today. I look forward to speaking and giving everybody an update next quarter. Have a good one.

Operator

The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect your lines.

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Source: Sanchez Energy's (SN) CEO Antonio Sanchez on Q1 2014 Results - Earnings Call Transcript
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