Sanchez Energy Corporation CEO Discusses Q2 2013 Results - Earnings Call Transcript

| About: Sanchez Energy (SN)

Sanchez Energy Corporation (NYSE:SN)

Q2 2013 Earnings Call

August 8, 2013 02:00 PM ET

Executives

Mike Long - SVP and CFO

Joe DeDominic - COO

Tony Sanchez - President and CEO

Analysts

Ron Mills - Johnson Rice & Company

Neal Dingmann - SunTrust

Adam Michael - Miller Tabak

Leo Mariani - RBC Capital Markets

Stephen Shepherd - Simmons & Company

Kelly Loyd - JVL Advisors

David Heikkinen - Heikkinen Energy Advisors

Adam Leight - RBC Capital Market

Joe Magner - Macquarie

Tom Bishop - BI Research

Ron Mills - Johnson Rice

Operator

Good day and welcome to the Sanchez Energy Corporation Second Quarter 2013 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 note this event is being recorded.

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

Mike Long

Thank you, Andrew. Welcome come everybody. Before we start, I would like to advise you that we will be making forward-looking statements within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act, 1995. Words such as will, potential, believe, estimate, intend, expect, may, should, anticipate, plan and similar expressions are intended to identify forward-looking statements.

Such statements are subject to a number of assumptions, risk and uncertainties, many of which are beyond our control, and may cause our actual results to differ materially from those implied or expressed by those statements.

Joining me today is presenters on the call are Tony Sanchez, our President and CEO, and Joe DeDominic, our Chief Operating Officer. We have a lot of items to cover today including detail surrounding our announcements this morning of our entry into the Tuscaloosa Marine Shale trend. In order for the call to flow well, I will star with the quarter’s financial highlights, try to be brief and then turn the call over to Joe for operational highlights and finally will go to Tony for our corporate overview and discussion of our decision to make the TMS acquisition.

Our press release provided substantial details about the financial results but we will not go into a lot of detail here but simply highlight a few things.

Production for the second quarter of 2013 increased almost to 100% from the previous quarter and almost 800% over the same period a year ago. Our reported production was a little over 703,000 barrels of oil equivalent, the amount increased modestly from our operations press release in late July as a result of some late production accruals in our Marquis area.

The average daily rate for the second quarter was about 7700 barrels of oil equivalent per day compared to 3900 in the previous quarter and 859 in the same period a year ago.

Revenues in the second quarter increased 90% to 59.1 million, compared to 31 million in the previous quarter and 6.3 in the comparable quarter a year ago. Overall, we received an average realized price before the effect of derivatives of about $101.42 of barrel of oil equivalent in the second quarter of 2013. A net realized NGL price of $24.48 and a net realized natural gas price of $4.61. 50% of our second quarter production and 52% of our second quarter revenue came from Palmetto, 28% and 28% came from Marquis, 15% and 14% from Cotulla, 6% and 7% respectively from Maverick. Please keep in mind, we only reported one month of ownership for Cotulla for this quarter.

We reported net income attributable to common stockholders of $3.2 million for the second quarter compared to a net loss of 15.6 in the comparable period a year ago. Adjusted net income attributable to common shareholders as defined in our press release was $5.8 million for the second quarter.

Adjusted EBITDA also defined in our press release was $43.2 million for the 2013 quarter versus $2.5 million for the same period a year ago.

Based on our average realized pre-hedge price for barrel of oil equivalent of production which was $84.05, we had an un-hedged cash margin in the quarter of $58.13 per BOE. The deductions to arrive at that number were $9.69 per LOE in marketing, $4.78 per production taxes and $11.46 for G&A.

In that G&A number if you deduct out approximately $3.1 million or a one-time cash acquisition expense in the quarter that equates to $4.36 per BOE, our cash margin would have been $62.49.

Our hedges are comprised of a series of WTI put spreads as well as swaps as we outlined in detail in the press release. We’ve recently increased our hedge positions taking advantage of the recent run up in oil prices and recognizing the change financial risk profile of the firm post to our recent $400 million debt offering. We currently have about 60% of our forecasted balance 2013 production hedge with the combination of swap, Collars and put spreads and we are currently between 30% and 35% of our expected 2014 production, with the plan to move steadily toward 50% and to begin initiating some 2015 hedging over the next several months.

As of June 30th, we had approximately $252 million in cash short term marketable securities and the only debt outstanding was the recent $400 million over debt offering leaving us with net debt of approximately 150 million. In conjunction with Cotulla acquisition and the debt offering, we paid off and canceled our second-lien term loan and entered into a new senior revolving credit facility with group of banks.

Post these are four mentioned transaction, we have an unused current $87.5 million available borrowing base that is currently been re-determined we expect the new borrowing base to be set within the next couple of weeks and we expected to be in amount between $150 million and $175 million.

With that I’ll turn it over to Joe for more comments about operations.

Joe DeDominic

Thanks Mike. Today, I’d like to start with our Cotulla asset or assume full control of operations as of June 1st. As we previously communicated, we made the decision to speed up the conversion of multiple temporary production facilities to permanent facilities to lower our operating cost and minimize production variances.

This resulted in a short term decrease in our daily production over the past two months our wells were shut in for their work and testing to be completed. However, this effort will be finished by the end of the month versus our original forecast at the middle of the fourth quarter.

As we’re a nearing the completion of this conversion work, our net production associated with this area as recently increased 1,500 barrels of oil equivalent from early June when we assumed operation.

We’ve also made quick progress on drilling operations like we just drilled a well from space to rig release in 11 days, a substantial improvement of our plant and our previous wells. We now proceed drilling a total of 14 net wells in 2013 in this asset with our one operated rig which is four more wells than our previous guidance as resulted this drilling improvement.

We’re also starting work on a 40 acre pilot test at Alexander Ranch and with several wells will be drilled and completed in the fourth quarter. However with the existing 80 acres spacing production performance has continue to meet our expectations with our first operated competition flowing at an average initial 30 day rate of 550 barrels of oil equivalent per day.

Currently, we have two wells either waiting or in various stages of completion.

Moving on to Palmetto where we have a 50% working interest with Marathon as the operator. We completed and bottom lined 90 wells earlier in the second quarter at an average initial 30 day rate of 1050 barrels of oil equivalent per day. Five of those wells are part of the 40 acre pilot and they continue to exceed our production expectations with no material interference impacts.

We currently have two rigs that’s drilling wells of large pads and have continued to see a reduction in drilling days in cost in this asset. Given this drilling improvement, we along with Marathon have agreed not to mobilize a third rig to the asset as previously planned. However this is push back the timing on a number of the completions and resulted in a near term impact to the production from this asset.

We are now forecasting participating in a total of 30 gross wells in 2013 with these two existing rigs. Currently, we have 12 wells in various stages of completions or pull backs on this property.

In our Marquis area where we have 100% working interest and operating, we completed and bottom lined three new wells earlier in the second quarter and these wells have performed as expected. Concerning the Prost C #7 which in April experienced a service company air which caused a flat setting of the cement in a well bore prior to proper emplacement, we attempted a completion and subsequent drilling site track; however we have elected to temporarily abandon this well due to numerous operational issues. We are currently in negotiation with the cement provider concerning compensation on this issue.

On the drilling side we have expected a second rate to arrive there may however it was delayed over 90 days due to prior commitments and we decided to source a third rig to allow us to make up for this lost drilling time plus drill three additional wells in this area this year.

In total we are now expecting to drill 22 net wells with the three active rigs in the Marquis area and currently have four wells in various stages of completion of flow back.

We are also continuing to de-risk recent portion of our Marquis position by drilling new wells and participating in non-operated wells offsetting our positions. The Sante well located 8 miles to the north east of the post development and this well is drilled in 2012 at an inadequate cement job which resulted in a failure to effectively stimulate the Eagle Ford. However it has been producing approximately 40 barrels of oil equivalent per day over the past month from the three stages we could complete. A simple extrapolation to the standard 24 stage well would produce over 300 barrels of oil equivalent per day in line with other wells drilled and completed in this area. A follow up to the Sante well has been permitted several miles to the North and we are planning to drill and test its new location during the fourth quarter. We are also participating in a non-operated Eagle Ford well located roughly seven miles to the southwest of the Sante which will also be completed in the fourth quarter.

Moving on to the Maverick area, we successfully drilled, gathered geological reservoir data on Pearsall formation in a vertical section of the hole and we are presently completing a horizontal well in the Eagle Ford on a large 6000 acre ranch which will then be held by this one producing well.

We continue to a corporate Pearsall data into our internal analysis as well as monitor industry activity. We are also evaluating the most recent public Buda formation information and incorporating this data into our internal model. We have numerous leases within our Cotulla and Maverick areas which are prospective from the Buda and Pearsall and are evaluating drilling and testing these targets in 2014. We currently have two wells in various stages of completion or flow back in the Maverick area

With that I will now turn the call over to Tony.

Tony Sanchez

Thanks Joe. Turning to a quick overview, we are rapidly growing independent oil and gas company targeting onshore U.S. Gulf Coast oil resource plays with the current focus on the Eagle Ford Shale.

Our current common market capitalization is approximately $800 million. And at the end of the second quarter, we had $375 million of perpetual convertible preferred stock, $252 million in cash and marketable securities, and $400 million in debt. All of the current operations are based in the Eagle Ford Shale trend of South Texas, in Gonzales, Zavala, Frio, Fayette, Lavaca, Atascosa, Webb and DeWitt counties, where we have proved reserves of 43 million barrels of oil equivalent and current production in excess of 12,000 barrels of oil per day.

We continuously manage our positions within our core areas of Marquis, Cotulla Maverick and Palmetto to create the largest possible contiguous land positions, which will enable us to focus on driving, drilling and production efficiencies. In addition, we are constantly reviewing opportunities to add to our position while being mindful of the tremendous opportunity base we currently have. For example, we recently closed an acquisition in our Marquis area of 10,300 net acres which we call our five mile creek area with interest in seven gross wells located just to the northwest of our Prost area.

We have continued to substantially grow our production and reserves due to new well completions and the closing of our Cotulla acquisition. Our production for the second quarter was approximately 703,000 barrels of oil equivalent, an increase of 98% over the first quarter of 2013 and an increase of 799% over the same period a year ago. During the second quarter of 2013 we spud 15 wells and brought 15 wells online. To date since the end of the quarter we have added another 11 wells including seven wells from our five mile creek acquisition, to bring our total gross producing well count to a 115 wells and have 26 additional wells either drilling or completing. There are six rigs currently running, three rigs in Marquis, one rig in Cotulla Maverick and two rigs in Palmetto.

We have allocated our 2013 operating capital budget of 475 million among our core project areas and now plan to spud seven more net wells this year than previously anticipated due to efficiency gains from our multi-well pad drilling program. For this fiscal year 2013, our operating capital budget now calls for us to spud 75 gross or 54 net wells and to complete 55 gross or 39 net wells. We have issued third quarter average daily production guidance of 11,000 to 12,000 barrels of oil equivalent per day and fourth quarter average daily production guidance of 13,000 to 15,000 barrels of oil equivalent per day.

Accounting for the effects of pad drilling and some minor rig delays on the timing of well completions, in the onset of new production, we reaffirm our 2013 production exit rate guidance of 15,000 to 17,000 barrels of oil equivalent per day.

Turning to the Tuscaloosa marine shale transaction which we announced earlier today we acquired 40,000 net acres in the core of the TMS trend for cash and stock totaling $78 million plus a minimum three well drilling carry. Of this purchase price, $61 million is for the purchase of the interest in the properties held by an unaffiliated private equity firm based out at New York which made its initial investment in late 2010.

Of the remaining purchase of price, out of the remaining purchase price amount Sanchez resource acquisition or SR will receive approximately $13.5 million which will then take our interest up to the 50% level. We have established a 50-50 AMI with SR in the TMS which holds rights to approximately 115,000 gross acres and 80,000 net acres. We have further committed as part of the total consideration to carry SR for its 50% working interest in the initial three gross for a 1.5 net TMS wells to be drilled within the AMI and at our option may carry SR and an additional three gross for 1.5 net TMS wells if we want to participate in additional drilling within the AMI. After the six gross well carry any additional capital will be deployed on a heads up basis.

We have been watching the evolution of the TMS in assessing the technical and economic development of the play for almost three years. With recent low results trending towards 600,000 to 800,000 barrel EURs and IPs ranging from 1,000 to 1,500 barrels per day well cost trending down towards 12 million the core of the TMS has the potential to be a world class play. It is important to note that of the well recovery estimates, over 90% is crude oil, which is priced off of (inaudible). Using some high level industry metrics and assumptions, we estimate that our position exposes us to over 200 million net barrels of recoverable resource potential.

The TMS is the age equivalent of the Eagle Ford Shale, which follows the Gulf Coast from Texas into Louisiana and Mississippi. As such, it is an extension of the same geology we know well from our existing Eagle Ford operations and allows us to leverage our existing experience and capabilities. We are excited about the prospects of the TMS and believe now is a good time to enter given the increasing number of strong well results from other direct offset operators to our position within the core of this play.

The trend is at an inflection point and it would be very difficult to replicate this position going forward. 50% of our acreage is held by production and another 40% does not even begin to expire until 2016 and beyond, and this transaction gives us a unique acreage block in the core of the play. The current plan is to commence our operated TMS drilling plan in early 2014 and represents less than 10% of our anticipated operating capital budget over the next 18 months. So we feel we are adding a very low cost option to our portfolio of opportunities that would add significant net asset value to Sanchez Energy.

We also plan to participate in several non-operator wells for lesser working interest given our proximity to other active operators in the area. We expect to let industry de-risk and delineate this play while we applied base and best practices in our operated program. This is consistent with how we developed our position within the Eagle Ford. I am proud of what the Sanchez team has accomplished this year so far and excited about the potential for our upcoming drilling and completions that are now in progress. Joe talked about the operational strides we are making and I expect those efforts to show up and further reductions in well cost and streamlined operations.

With 140,000 net acres in the Eagle Ford, we are highly leveraged to one of the premier oil plays in North America, which we expect to drive our earnings, production and reserve growth over the coming quarters as we continue to delineate our acreage through development drilling. We have established a core solid position within the core of the TMS, a rapidly developing oil resource basin at a low entry cost with tremendous upside potential.

With that I’ll turn the call back over to Mike.

Michael Long

Thank you, Tony. Andrew, we’re ready to open up for questions now.

Question-and-Answer Session

Operator

(Operator Instructions) First question comes from Ron Mills of Johnson Rice. Please go ahead.

Ron Mills - Johnson Rice & Company

Tony, a question for you on the TMS. Your new presentation shows a map and looks like from geographic standpoint very attractively located relative to EnCana. And good rich activity as you look ahead to 2014, can we make the assumption that you may look to drill all three of those gross wells over the course of 2014, or is there a time frame for which you need to test those wells?

Tony Sanchez

There is not a specific time frame, Ron. The way we’re thinking about this is over an 18 month period. Whether they come on the front end or in the middle or evenly proportioned out, we don’t know yet. I think the important takeaway point is to understand that from a capital perspective we’re talking about well less than 10% of what we see to be our capital budget over the next 18 months. Our land position is very solid. 50% of our position is HBP through some shallow oil wells. And the rest of it does not even start to expire until 2016 and on. So, there is absolutely no rush from a land perspective to get in here and start drilling. We like what we see with well results coming from some of the operators in the immediate vicinity. As you probably know, several operators recently announced IPs in the 1,500 barrel a day range that are tracking EURs of 600,000 to 800,000 barrels. So it's really moving in the right direction, we're going to let that continue. We're available; we will participate if we think it makes sense for lesser working interest as part of pooled units that are either operated by us or other operators.

So the kind of long answer to your question but I would really look at that is coming over the next 18 months or so.

Ron Mills - Johnson Rice & Company

And then with less than 10% of your capital over that timeframe being directed to this area, given especially the past couple of months' worth of well results, it seems this is kind of I think you called it the inflection point time to get it. Can you walk through some of your thought process in terms of comparing and contrasting the plus or minus $100 million including the three well for this property versus incremental spending in the Eagle Ford and how you view the relative return opportunity in conjunction with having a second emerging play.

Tony Sanchez

So we haven't put out a 2014 capital budget yet, but we’re working on one. And inclusive of the purchase price in the well-carry here call it 100 million. If you take what we are going to spend in the Eagle Ford this year for 475 million, extrapolate that into 2014 accounting for a full year of our Cotulla acquisition. It's a number well north of that, but you could see where the capital that we have going through the purchase price plus drilling of the TMS is a small portion of the overall budget over that period of time.

The way we view this is particularly important from the opportunity of providing some portfolio diversification from a return standpoint. These wells, we have run the numbers anywhere from 12 million up to 16 million of D&C costs, and EURs of 400,000 to 800,000 barrels, even though everybody's talking about the 600,000 to 800,000 we really looked at some sensitivities around those. And you really start to generate some very strong returns, as well costs trend down towards the $12 million range and as well histories begin to justify those types of EUR.

So we're looking at this from the standpoint of where can we source opportunities to deploy capital at rates of return that are comparable to what we're getting out of our best wells in the Eagle Ford. And so we look at, my look at what the next several years may hold in terms of drilling inventory. And from a simple standpoint we are drilling the high rate of return wells at the Eagle Ford as quickly as possible. And we view this as a position which will supplement those types of high rate Eagle Ford wells in the future.

It's important to note that this play is not taking any capital out of the Eagle Ford. If anything, we have increased our Eagle Ford drilling because we're drilling faster. So there is no capital that is been taken away from the Eagle Ford and being replaced with the TMS. What we're doing is we're working them in together.

Ron Mills - Johnson Rice & Company

And then last one, and then I will let someone else jump in and come back to you. Relative to your existing operational focus in the Eagle Ford, what's the thought process or how do you allocate your operational capacity between the Eagle Ford and the TMS? Or is it similar to capital, this isn't going to cannibalize any of the Eagle Ford attention. This will have its own technical team working on this play as well.

Tony Sanchez

Yes, it’s not going to cannibalize anything from the Eagle Ford from a technical team perspective. Keep in mind we haven't operate here yet at the TMS. But the origins to this position day back to 2010, the end of 2010. Where our affiliate bought a company out of bankruptcy, that company has oil and gas wells in the area. So we actually have a small field office, in Mississippi. We have got staff and some contract personnel on the ground.

So in the short term where we are now and probably for the next six months, we don't need to hire anybody new, nor do we need to take anybody over from the Eagle Ford and apply them here. If we transition into a more full scale development mode I would anticipate hiring some people specifically dedicated to the TMS. But we have got time to make that decision and base it off well results before taking a leap.

That's what to us operationally the nice thing is that, we’re already there, this part of Mississippi is very oil and gas friendly, we are in that South Western part of Mississippi, northern part of that Louisiana border, so we already there. It doesn’t mean we have to add people or take them from what we are doing in the Eagle Ford.

Operator

The next question comes from Neal Dingmann of SunTrust. Please go ahead.

Neal Dingmann - SunTrust

Tony, just one follow up on the TMS, wondering, I guess I assumed you'll continue through the entire program, whenever you do start that you will be the operator on that entire acreage package, is that fair to assume?

Tony Sanchez

Yes, we have an AMI established, operator of record is Sanchez only gas cooperation, that’s how we operate out of the Eagle Ford. I mentioned in my prepared remarks that we would likely be participating with other operators when the opportunity arises for lesser than a 100% working interest and so we have been in discussions with some of the other groups out here and anticipate that that could come to fruition, whether that results in us operating a well or some other company operating a well I really can’t comment on that yet because that hasn’t been determined but it will be a combination of the two. Over the longer term, I would expect us to operate the majority of our capital spend in this area.

Neal Dingmann - SunTrust

Okay and then just one last question on TMS as far as timing, again or I guess two questions around it, questions sort of why now? I mean the opportunity was there on this acreage piece and you liked where that was and then secondly does this have any effect and will you continue to look for either relatively large or smaller type Eagle Ford deals you know like that at least 10,000 block?

Tony Sanchez

Yes, okay so I answer your second one first. The short answer is yes. We are always looking at different positions. I think we are going to disciplined and opportunistic about how we approach acquisitions, whether it's an acquisition of leasehold or acquisition of producing properties with the leasehold, so yes that will continue. We are continuing to look at positions as we speak, so nothing has changed in that regard. What was your first question repeat that?

Why now? That’s good question I have been asked couple of times today and the main answer to that is in our view that this play has hit a very important milestone over really the last several weeks but started a few months ago and on a consistent basis, companies have been reporting with our very strong, well production results.

Anywhere whether you are looking at Goodrich’s Crosby well or some of in (inaudible) wells, there have now been several that are thousand barrels a day, 1,500 barrels a day and those production volumes are being maintained. One well in particular, I believe the Crosby produced over 100,000 barrels in the first five months and continues to track in 800,000 barrel EUR type curve.

I think we need to step back and understand what the implications of that are. To be out here and to target wells that are tracking 800,000 barrel type curves is pretty phenomenal and that production stream is 90% plus oil, so this is crude oil and its pricing at a premium to WTI.

So from an economic standpoint, the numbers you can see how you can get from marginal to okay economics when it's costing $15 million to $16 million to drill these wells, you know some pretty phenomenal economics as those well cost trend down to 12. and so we thought that right now would be a good point to make this entry to the basin where we believe the risk reward profile is fundamentally changed, yes sure we could have got in several years ago for cheap and taken a flyer or we'd wait a year or two and this year story would have already been played out and we'd have to pay a big number. but we are in this business to add net asset value for the benefit of our shareholders and we think that right now the risk is fundamentally shifted to repeatability, to consistently getting well cost within a range that generates strong rates of return that are comparable that we could get in other basins, including the Eagle Ford and so that’s why we made the decision to enter now.

Neal Dingmann - SunTrust

Did you look at other parts of this play and decide this is the part that you wanted, not necessary how you entered up with the TMS but this particular part of the TMS, Tony?

Tony Sanchez

As you know the TMS is substantially larger than we defined on our core area map. Yes we did look at other parts, we do feel that being in this kind of up deep portion of this particular part of the play is the place to be largely defined by southwest Mississippi in Wilkinson and in mid counties, southwest Pike and and we have focused in on this area as the place to be. We’ve watched well results just take every well that’s IPd over 1000 barrels a day and its right here. So, yes, this is where we want to be.

Neal Dingmann - SunTrust

Okay and then lastly just moving over to Cotulla. It looks like just going through slides, slide nine that shows your rigs running in as far as wells out there, looks like you’re pretty much already blanket a lot quite of bit of that southern acreage. What your thoughts as you move a little bit further north, are you going to potentially that some of the acreage you’ll let go or are you going to start to become, would you move that rig up there and start to hold some of that sooner or rather later.

Tony Sanchez

Where we stated right now is where there rig is on that map is Alexander Ranch, it will stay there mostly here we had some good drilling down there and we got the 40 acre pilot, we’re going to test. However, we have plans to potentially drill some wells in the northern part of LaSalle or possibly to the south. We’re looking at those right now, we have locations pointing of infield locations in those areas and it’s the matter of fitting them indoor capital program where it make sense.

Southern Frio, we have one of those leases are good through next year, the once that are expiring this year we’re taking a hard look again it kind of revolves more on the (inaudible) and their we want to extend and can we walk it up to make a good position.

So, a little bit of lot things going on there looking at potentially drilling that make sense. We have locations to drill extension on existing with other formations but for now the focus it will more on Alexander Ranch.

Joe DeDominic

Yes. I’d like add there a little bit just to reradiate a point made during the prepared remarks. Our production coming out of our for two areas now over 6,000 barrels of oil equivalent per day. When we announce the acquisition it was a 4500 barrels a day and so just really in too short months through good maintenance, through consistent laboring in all wells we’ve been able to steadily increase the production coming off that asset and on the cost side Joe spoke to at some, we’ve accelerated our plans to tackle the LOE aspect of this asset and bring the lease operating expenditure cost from these wells well down in line to where the rest of our assets are being priced.

Operator

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

Adam Michael - Miller Tabak

I wanted to jump back over the Marquis if I could and it’s been about six months since you put out a 30 day rate on the Prost B #1H and I wanted to see if you could maybe shed some light on some of the other wells that have been drilled and how they held up a little long term, are they tracking that well on the day rates and maybe even 60 and 90 days after.

Joe DeDominic

I don’t have the 60 or 90 days in front of me right now but the most recent set of wells we drilled in that Prost area, those recent wells we brought on in the second quarter, the 30 day average for those wells was above 750 barrels oil a day. So, just slightly below the B1 but everything again coming in as expected as we continue to produce those wells.

Tony Sanchez

B1 is an exceptional well; it’s turned out to be really good. I wouldn’t say that’s the benchmark because it’s so good but our other wells subsequent to that are certainly attracting our expectations if not exceeding them to some extent.

Adam Michael - Miller Tabak

And then as far as the tight curves go in the presentation it appears that you dropped your well cost assumption down to 9 million but I didn’t really see the PV10 or the IRRs go up and I’m just wondering was there something commodity price or commodity mix or something that I might be missing there or maybe you can help me out with that.

Tony Sanchez

We’re just taking to our account an update on the differentials of the market, update it to the recent. But we’ve seen, as you noted the cost are continuing to decrease as we drill more and more wells definitely Palmettos seen a bigger decrease, it’s got the largest number of wells that have drilled in it. Marquis is starting to pick up speed and then Cotulla we’ve made good progress already on that piece of business.

Adam Michael - Miller Tabak

And then over with South County, the EOG is pretty active and was I think they’d seen a about a 30% step in well performance in the last 12 months and I was wondering do you see the potential for a step up in performance out of Cotulla and just kind of general trends over there because they’re talking about some pretty big rates of return over in LaSalle County and I was wondering just what your thoughts were.

Tony Sanchez

I quickly looked at their presentation yesterday; I have not had a chance to look at in great detail. obviously that north eastern corner LaSalle, they showed a lot of well results in that area recently yesterday.

We definitely are looking at that hard; we have some acreage up in that part of the country. We think it extends towards Alexander Ranch in that area, we expect to improve our well performance in that area, again our first well, 30 day was 550. We have some other wells that are coming online now that we think will do better. We are working to enhance those completion and well performance.

Operator

The next question comes from Leo Mariani of RBC, please go ahead.

Leo Mariani - RBC Capital Markets

You just talked about 11 wells that you brought on here in the third quarter; I guess seven of those were on the acquisition. Where were the other four wells and then how many wells in total would you expect to bring on in 3Q and 4Q?

Tony Sanchez

That will be eleven. We have a couple, Leo, right now they’re flowing back in Marquis and we have one that is flowing back down in Cotulla. So I think that’s the other four out of those seven. And then we have again through the releasing all wells across all our assets that will be coming on in third and fourth quarter.

Leo Mariani - RBC Capital Markets

Guys, would you happen to have the number of wells you plan to bring on in 3Q and 4Q here.

Joe DeDominic

Not in front of us, no.

Tony Sanchez

Can you track back to the, both Tony’s comments in the press release where we talked about the number of gross and net well spud and the gross and net wells completed, and if do some math, you can do some math, subtract what’s already happened versus what’s still to come.

Joe DeDominic

Yes, with our new forecast Leo you can see how many wells we are going to drill and we talked about how many wells we are going to complete this year which I don’t have right in front of me on top ahead. It is in the scrip that Tony just went through, as where we put it in there. As you can see how many wells we have done already and how many are left. I think you get an idea from there, third and fourth quarter, it will be slightly back and waited as we mentioned with some of the delays and the drilling rig showing up and just the delays and not good at third rig in Palmetto, you know push us back just a little bit more back end loaded.

Leo Mariani - RBC Capital Markets

Okay, make sense. On a 6000 barrels a day in Cotulla, just to be clear, so you went from 4500 to 6000 without any new wells that was just optimization of facility?

Tony Sanchez

That was a combination of both. We did bring on a couple of wells that were drilled in the transition period with (inaudible) two wells there, the well that I spoke about with a 30 day average there of 550 and then it is an optimization enhancement of the wells that we currently took over. We opened up some chokes, we’re lifting them differently, and we’re spending more time with the wells and getting more out of them.

Leo Mariani - RBC Capital Markets

Okay, and I guess on the operating cost that you guys talked about being at $27 of BOE, in the second quarter and trying to bring that number down to in line with I guess the rest of your portfolio which I guess a lot closer to $8 or $9; where are you now on the up cost on Cotulla and how long it will take to get down to the company average?

Tony Sanchez

Right now I think that the last quarter was around $25 a barrel for Cotulla so you can tell its substantially higher than what our standard cost are along the trend. With the conversions we’re also putting some pipelines, we're converting some wells from generators to electrical power, that’s going to take a little bit of time because the co-ops stretch so thin down there, but we expect some time in fourth quarter. it will be dropping borderline with our standard average of $8 to $10 a barrel. And that’s our guidance that we put out.

Leo Mariani - RBC Capital Markets

Okay that’s helpful and just jumping over to the TMS; when do you guys anticipate that you are closing and do you guys have what the average royalty is?

Joe DeDominic

On new acreage? Yes the average there, the net royalty 25%, closing probably by the end of August I think it is. Yes correct.

Leo Mariani - RBC Capital Markets

Okay and what is your second quarter CapEx?

Tony Sanchez

We will find that here, in a second.

Operator

The next question comes from Stephen Shepherd of Simmons & Company, please go ahead.

Stephen Shepherd - Simmons & Company

One clarifying item on the decision to just run the two rigs in Palmetto going forward, in reading your release today it said that that was driven by efficiency gains you have seen in the area, but then in the text, you know we are drilling 30 gross wells now versus 34 before so I am assuming, correct me if I am wrong. The production in wells drill guidance that you had put out there previously, was that predicated on the addition of the third rig, so it’s true to say that four drilled well declined isn't necessarily apples-to-apples, now that you decided not to bring out that other rig in is that, how you would look at that?

Tony Sanchez

Yes, there’s a couple of things going on right, if we would have brought the third rig in we could have drilled wells off the different pads, and right now we just have two rigs which we have drilled wells of pads side by side, so it creates a bigger backlog of drill wells and makes that production come out of that asset lumpier so to speak. And so when we didn’t bring that, elected not to bring that third rig in, it pushed some of those wells back that we could had two or three or four wells, I don’t know the exact number, ex-number of wells come online this quarter rather than pushing them back 30-60 days or something along those lines.

The other thing on the well count is earlier in the year or late last year, we would have said two wells, and we’re going to drill 24 wells in a year, now we’re up to 30. So you can see that increase year-over-year how these wells are drilling. So it’s getting us closer to the number, the number of 34, it didn’t make sense to mow the rig in, pay for that extra fees, everything else to do that given the improved efficiency of the two existing rigs.

Stephen Shepherd - Simmons & Company

Okay, switching over to the TMS, to what extent I mean if at all are you able to kind of utilize information in conjunction with the private partnership when it comes to developing those assets going forward? Is there any kind of strategic relationship there or anything that could serve as competitive advantage relative to other operators in the play or anything you could utilize?

Tony Sanchez

I’d say we share everything and there is a strategic advantage I think that we have entering the TMS via this asset acquisition by virtue of the fact that the origins I may have mentioned this earlier. Origins to this position was an acquisition that SR made in the latter of 2010 whereby they bought a company out of bankruptcy that company’s assets were shallow conventional oil production which is how much of this acreage is HPP already. And so as the TMS developed and remembering back to that time, the TMS was part of the deal everybody know it’s there but it was risky but they made sure to keep it together. And so we did watch that. We do have contract people and a few employees on the ground. We have a small field office there. We’ve been getting well results through our network of contacts in the area and watching pressure data, flow rates things like that activity and permits filed all that kind of stuff that I think is going to give us a leg up as this basin transitions into full scaled development.

Stephen Shepherd - Simmons & Company

Okay, and just one more if I can, obviously, other operators in the play have had some challenges bringing well cost down to get to sort of that consistent ongoing economic threshold. In your eyes what are the immediate challenges that need to be addressed there? What can you do to bring those down from a technical standpoint? Any sort of commentary of inside that you can provide there.

Tony Sanchez

So, I’ll address it broadly and then let Joe comment on it. But, the fact that the initial well cost in this particular basis or really in basin start high and then come on down doesn’t worry us at all. It’s exactly the way it transpires in any other given basin. Our first Eagle Ford well is a very expensive. I’ll give you a little bit of data to correlate to. The first well that we drilled in Marquee a year ago cost us 16 million, now we’re bringing them in regularly for 9.5, and continuing to see where we’re going to drop cost. And that cost reduction comes from a variety of different places but mostly it’s as the individual companies get up the learning curve, start to figure out you’re going to set in our immediate casing where you’re going to set it, what weight of money you’re going to be using. How basically the void drilling problems, how to make the setting of your casing more efficient in order to really reduce the cycle time from spud to TD and rig release. And then the same thing on the completion side, making, figuring out what the formula is for a successful completion stage and then making it more efficient and then building that into your operations process. This, in my opinion, is not any different than what we experienced in the Eagle Ford or what has been experienced in other basins by other operators. And if you see what the end result is getting well cost down to 12 million or 13 million, you can see how the numbers begin to look very compelling.

Operator

The next question comes from Kelly Loyd of JPL Advisors. Please go ahead.

Kelly Loyd - JVL Advisors

Tony, I was just curious, it seems there was a recent Tuscaloosa Marine Shale deal that went for what seemingly a lot less. I didn’t know if you guys looked at that deal and if you could tell us how that compares?

Tony Sanchez

Kelly, I am not going to address it specifically as to whether we looked at it or not. Well, we do know about it and I will say that the position did not necessarily meet our desire to take a measured approach in developing our position within the trend. It was a very large acreage position, our understanding is that a substantial amount of the acreage, 80% or more was coming up for exploration inside of a year. Furthermore as we define the core a big chunk of that acreage well north of 50% if not 80% was outside of what we would consider the core.

And so we looked at this position and we looked at what we had and how we define the core, and then figured, how can we get into this play without diverting a material amount of capital away from the Eagle Ford. And so our decision was not to move on that. I think the company who bought it made a very good decision for them; I think it served them really well. But we just felt that getting into something with such short term explorations was going to require a large amount of capital to either renew leases extend the, or put drilling rigs on there to hold the position together. And that's just not something we wanted to do. We felt that the 40,000 net acres 50-50, actually it was 80,000 net acres; it's over a 115,000 acre gross block within the core. That's a good position, we're not in any rush and we're not certainly driven to re-allocate capital away from the Eagle Ford and order to hold that. So it just fits very nicely with what we wanted to accomplish.

Kelly Loyd - JVL Advisors

And just one more quick one, just wanted to be clear, did any of the cash or the stock in the purchase price go to the related entity or none ort it?

Tony Sanchez

Of the $78 million purchase price which was cash and stock 61 million of that went to an unaffiliated third party private equity group based out of New York. They are the ones that put up a lot of the capital at the start. Of the remaining cash amount approximately 13 million is going into SR acquisition which is our affiliate. That 13 million is ear marked for working capital and for their share of the heads up drilling expecting that that's going to come pretty soon after the six well drilling carriers used up.

So obviously it's not in any press release, but we're not taking any money off the table. If you think about it we’re fully aligned, we're 50-50 fully nobody who is an affiliate is putting any money in their pocket. This play is either going to work or it's not or we're both going to write it. So just to be very clear, I am glad you asked the question, 61 million so well north of 50% of two-thirds of the purchase price amount was to buyout this private equity group that has absolutely no affiliation with us. Does that address your question Kelly?

Kelly Loyd - JVL Advisors

It does.

Operator

The next question comes from David Heikkinen of Heikkinen Energy Advisors. Please go ahead.

David Heikkinen - Heikkinen Energy Advisors

Just going through thoughts on the last year you all have been pretty active in running through our model and thinking about your spending in 2014 with the TMS and ramping activity. How do you balance cash on hand, debt using more perpetual preferred and even potentially common equity given you have used a little bit on this acquisition.

Mike Long

I think we did little over 300,000 shares of common equity in this transaction, I view that as trivial. We don't have any future preferred plans; actually we look at our liquidity with a very rapidly growing totally unused borrowing base, leaving us with we expect liquidity north of 400 million here in a couple of weeks, but it is a capital program with the TMS being a very measured approach in there, less than 10% of operating capital to be a well-funded capital program with our current balance sheet, structure. We take nothing away from the Eagle Ford, you will see our Eagle Ford growing as we're drilling more wells, being more efficient; frankly it’s a very small part of the capital budget that we think we have well-funded at this point.

David Heikkinen - Heikkinen Energy Advisors

And you said the acreage is mostly held by production, how much production is it? Sounds like its pretty small?

Tony Sanchez

It's pretty small David, the production that was originally purchased back in 2010 is shallow, conventional kind of in the oil skimming type production, several hundred barrels, that's not part of this purchase price, we wanted to make this a pure oil resource play and so we excluded that. But we do get the benefit of having that acreage held by those wells. So again, roughly 50% is HPP and another 40% doesn’t even start to come up until 2016.

Operator

The next question comes from Adam Leight of RBC Capital Market. Please go ahead.

Adam Leight - RBC Capital Market

Covered a lot of ground, just one question on the production next couple of quarters. How should we think about the product mix given what you are doing with Cotulla and elsewhere?

Tony Sanchez

Yes, it's roughly the same as what’s you saw this quarter; they are going to be 74% to 75% of oil, 12% or 13% NGLs and the rest gas.

Before we go to the next question there was a previous question about the cap expense so far this year. Guys you will see in the 10Q that we will file tomorrow that, the first half capital spending was approximately $95 million.

Operator

The next question comes from Joe Magner of Macquarie. Please go ahead.

Joe Magner - Macquarie

Just curious to go back to the TMS deal, can you discuss the process that you all went through to determine valuation paid given this was originally acquired out of bankruptcy, it sounds like that position was initially acquired a relatively low cost, is there dollars paid to compensate or what has been spent over the last three years, or just kind of put that in context to the recent transaction, leasing evaluations and other markers that may have served as some support for what was ultimately paid?

Tony Sanchez

The bulk of what ended up being the ultimate purchase price was negotiated between us and the private equity group that I have previously mentioned. This was a process that took a couple of months as you can imagine we had different views and what it should transact at. We ultimately got to a purchase price of $61 million with them so two-thirds of the answer which is two-third of the purchase price is a function of negotiated price that we agreed to, basically to take them out of this position.

And then we looked at what gets us to 50%. So we basically, it was somewhat of a complicated deal and then we had to unravel a private equity investment in an entity and then put it back together as a joint venture that is more typical of the oil and gas deals that we do. So, we did look at what would be our ability to replicate this position in the trend, in the part of the trend where we are and in size. I think the reality is you simply can’t do that right now and then there are other metrics as that other transaction I think you refer to that have taken place that are not really apple-staple comparison you need to make adjustments there to get to something comparable and that involves making assumptions around acres that’s expiring or out of the core and we felt that the ultimate kind of blended purchase price inclusive of the well carries which are spread out over a long period of time are representative of a market transaction in the TMS.

So, taking a little bit broader than that keep in mind we paid $2,000 in acre for our Marquis position when we did the IPO that was 56,000 acres are 100% undeveloped. If you recall further back in that the joint venture we did with Hillcorp in 2009 was roughly about $2500 to $3,000 an acre and so think about where the Eagle Ford was in 2009, you know you had some good promising well results but a lot of figuring out yet to do, back then we repaid 5 million cash and a three well carry for 900,000 net acres.

And so just kind of looking at the broad context it felt like this was a deal that made a lot of sense for this basin, where it is now for the type of position that we wanted to put together and if we were to take capital and try to replicate 80,000 net acres in large contagious blocks you could see it in our map, in this part of the trend I basically say you can’t do that, sure you could go lease a few hundred acres at a time for a cheaper price but that’s not going to give you any measure of scale.

Joe Magner - Macquarie

Can you provide an inside in terms of put private equity back involved, what their original position was and you talked about unwinding that transaction and putting it back together, how involved were they in terms of the SR entity or the their investments that they had made?

Tony Sanchez

There were a large equity owner in SR, I can’t give you particulars as to who the name is, who they are or what there basis was or anything like that that part of the agreement was that we would keep their name private. They made an equity investment over the course of several years and the original strategy was not to go to make it TMS play and as that changed they viewed, the real upside here really in taking some stock and participating with us through their shareholdings in the company and letting us kind of run with it, they looked at what we’ve done in the Eagle Ford.

We’ve taken the Eagle Ford in the year and half when we went public we were producing 600 barrels a day from 10 wells. Now we’re producing 12,000 barrels a day from 115 wells and as this TMS really started to get hot a few months ago, we approached them and we said look guys you guys want to start riding some checks and lets go drill some wells and they said we'd rather take your stock lets figure out how to make this a transaction that could work for everybody and so we had to unwind it and put it back together as a JV in order for it to work as it normally does in the oil and gas base. And so, that’s the history in nutshell, hope it answered your question.

Operator

(Operator Instructions). The next question comes from Tom Bishop of BI Research. Please go ahead.

Tom Bishop - BI Research

With regards to the estimates that are out there I mean the company kind of got spent today on the stock market, I think the market was looking for $0.28 and came in at $0.17. Can you identify what analyst kind of missed there because that was like a consensus of [12] and also are they equally as off the mark on their $0.43 for the next quarter?

And one other comment on that regard is that the estimates for the company a range of $0.24 to $0.65 for Q3 implying that maybe we need a little more guidance or something.

Tony Sanchez

I think Tom, one variance in the analyst forecast is some people use a fully diluted share count on the as if converted on the preferred, others look at the preferred and say they'll call out there for now, still four and half to five years, don’t use fully diluted share counts so that would give you dispersion in their reports. otherwise I can't really speak that much to the ins and outs of how each analyst did it. I think if we look at our projections and where we’ve guided people to as we’ve discussed production things that went on with the operating cost, operating revamp in Cotulla and the C#7 well, we view our production coming in right at the mid-point of the range we’ve guided the street for some time. Nobody can predict certain things like noncash compensation and one-time expenses in G&A for acquisitions are not predictable, as you watch all that out, it’s reasonably close I think.

Tom Bishop - BI Research

Those are excluded from adjusted earnings. Let me ask you about interest. To what extend can you capitalize interest like that 400 million, does any of that go on here or is it all go right to the income statement.

Tony Sanchez

Different companies take different; they have policies and approaches as to what you capitalize and what you expense. Our position has been, we expense all of our G&A and interest and don’t capitalize it.

Tom Bishop - BI Research

Okay. So, we should expect the full amount of whatever those two preferred dividends and all the interest expense will totally be on the income statement, right?

Unidentified Company Representative

That’s correct.

Tom Bishop - BI Research

One other thing I wanted to ask you, what exactly does SR mean? It's sort of whole family of Sanchez companies, right?

Tony Sanchez

Sanchez Resources is that special purpose entity and set up to acquire the assets that were sold back in 2010 as part of the bankruptcy of the oil and gas company that had gotten itself over extended.

So, functionally speaking back then so long before SN was around, set up an entity, managed by my brother and raise some capital hence the entry of this unaffiliated private equity group went through the process as, I believe the stocking horse in that bankruptcy process and won the deal. That's the origin to how it all came about.

Tom Bishop - BI Research

The word affiliate kind of threw me a little.

Tony Sanchez

It isn't an affiliate of Sanchez Energy Corp. The main equity backer is not an affiliate.

Tom Bishop - BI Research

Well so you’re going to get 50% of everything or more?

Tony Sanchez

No, it’s a 50-50 deal.

Tom Bishop - BI Research

With SR, but SR is an affiliate of Sanchez energy; so you see where I am confused? I mean I thought you said that.

Tony Sanchez

Yes, I think what you are asking about is consolidation. So, the money we spend, we book our reserves, we book our production. So we are not consolidating any entities. You are asking about affiliate, I guess, in the GAAP sense.

Unidentified Company Representative

Sanchez Energy Corp does not have an equity ownership in Sanchez Resource's LLC. It has a direct working interest ownership in the properties and the reserves and production to be discovered of that.

Operator

The next question comes from Ron Mills of Johnson Rice, please go ahead.

Ron Mills - Johnson Rice

Could you just shift to the Eagle Ford for one second? Joe, you talked about, you are having six wells drilling in a total of 20 wells in various stages of flow back completion et cetera. Whether for you or Mike, if you look at those, the timing of those completions, how can we look at that in terms of whether it’s by month or over the remainder or the half of this third quarter or the fourth quarter because you talked about it being backed weighted but just curious how it looks like on your calendar.

Tony Sanchez

Sure Ron, yes, I think it’s the way you look at it is there is a lot of those 20 wells are being completed as we speak. We just started flow back on a couple of wells at Marquis and sales this week over at Palmetto, those wells are just finishing up fracking and drilling out operations. So they will be on flow back here the next week or two.

And Cotulla is a little smoother because we are not drilling four, five wells on the pad. So those will come on, we had two come on earlier in the quarter; two that are being drilled out right now. We will have another couple, pretty much two a month there on a more rolling average. So again you kind of see, I think if you look at this quarter, it’s not like they all came on the beginning of the quarter there, they’d come on middle to second half of the quarter, and that’s part of the reason we’re guiding to that 11,000 or 12,000 for this quarter.

Operator

The next question from Joe Magner of Macquarie, please go ahead.

Joe Magner - Macquarie

Just one quick follow up, prior to your interest in this opportunity, had SR sought partnership prior to the recent progress that’s been made?

Tony Sanchez

Yes, it did probably a year ago, in the form of a joint venture in much like what we experienced in the Eagle Ford when we went out to look for a partner, they didn’t end up with a structure that made sense. That was well before well results started to come out. And so they decided to pull the plug on that and wait until there were some data available on the play. And then as well results came out, we go some more information around where well costs were and where they were trending. We automatically then started negotiations around this deal.

Joe Magner - Macquarie

And just to clarify was this going to be another marketed situation or you just wanted to preemptive ahead of that process being started again.

Tony Sanchez

We were trying to be very preemptive. We were concerned about in a positive way. Too many good well results coming out so quickly we knew that some of the other operators were prepping to disclose what recent well results were. We have some insight as to the general direction of those big positives and had decided that we were going to preempt just fundamental stature of the plate shifting and get ourselves in.

Mike Long

Joe, this is Mike. I think if you see that you’ve asked about capital cost, the $95 million I quoted for capital with second quarter year to date, the full six months is a $175 million.

Operator

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

Mike Long

Great, thank you everybody. We appreciate your interest and look forward to giving you more updates as we have them available.

Operator

The conference is now concluded. Thank you.

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