Sanchez Energy's (SN) CEO Antonio Sanchez on Q2 2014 Results - Earnings Call Transcript

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Sanchez Energy Corporation (NYSE:SN)

Q2 2014 Earnings Conference Call

August 7, 2014 2:00 PM ET

Executives

Michael Long – Executive Vice President and Chief Financial Officer

Antonio Sanchez – President and Chief Executive Officer

Christopher Heinson – SVP and Chief Operating Officer

Analysts

Leo Mariani – RBC

Steve Berman – Canaccord Genuity, Inc.

Neal Dingmann – SunTrust Robinson Humphrey

Dan McSpirit – BMO Capital Markets

Ronald Mills – Johnson Rice & Co. LLC

Mike Scialla – Stifel Nicolaus

Operator

Good day, everyone. Welcome to the Sanchez Energy Second Quarter 2014 Earnings Conference Call and Webcast. All participants will be in a listen-only mode. (Operator instructions) After today’s presentation, there will be an opportunity to ask questions. (Operator instructions) Please also note today’s event is being recorded.

At this time, I’d like to turn the conference call over to Mr. Mike Long, Executive Vice President and Chief Financial Officer. Sir, please go ahead.

Michael Long

Thank you, Jamie, and welcome everybody this afternoon. Before we start, I would like to remind you that we will be making forward-looking statements. And that 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 out of the way, joining me today as presenters on the call 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 Sanchez

Thank you, Mike. Good afternoon everyone on the call. The second quarter of 2014 was a successful period for us on several fronts.

Revenues for the second quarter were a record $151.7 million, an increase of 157% over the same period a year ago while adjusted EBITDA was $112.5 million, an increase of 160% over the same period a year ago.

We produced almost 1.9 million barrels of oil equivalent or 20,400 barrels of oil equivalent per day, an increase of 164% over the same period a year ago. With the closing of the Catarina acquisition, our position in the Eagle Ford has effectively doubled in scale and we now have total crude reserves of 117 million barrels of oil equivalent and 224,000 net Eagle Ford acres.

Our production is approximately 37,000 barrels a day from 422 gross wells. We currently have a total of 40 gross wells in various stages of completion and we expect 25 to 30 of those wells to come online in the third quarter.

We have continued to demonstrate small but strong growth in production and have robust cash flows underpinning our development plan. We’re moving swiftly to integrate the Catarina asset, restore its production and delineate its eastern acreage.

After a brief transition period with Shell during the month of July, we have fully staffed Catarina and taken over operations as of August 1st. One rig moved into the western side of Catarina and it spud our first well on July 21st. The second rig will arrive in late August to continue developing the western side with the third rig joining in September to commence delineation drilling on the eastern side.

We have also contracted a dedicated frac spread to start completing the backlog of 22 wells waiting on completion and have already fracked the first two wells of the initial pad. Catarina has also brought us a critical mass to take us to the next level in our cost reduction program which involves the direct sourcing of proppant and chemicals for our completions.

On our existing assets, we are continuing full scale development and have derisked the 10,000 net acre Five Mile Creek area of Marquis by bringing online six wells with initial 30-day average production rates ranging from 450 to 700 barrels of oil equivalent per day at an average cost of about $7 million.

We also drilled our first Buda appraisal well in the Five Mile Creek area and are currently flowing back with strong results that have exceeded expectations. In addition, we will be drilling two Upper Eagle Ford wells in the Sante area during the third quarter with plans for two more Upper Eagle Ford appraisal wells in Fayette and Lavaca Counties later in the year.

In the Wycross area of Cotulla, after drilling one off [ph] appraisal wells near a salt dome in the central part of the asset, we have now entered into full scale development on that position. We are now bringing on large multi-well pads that are being completed simultaneously.

Early flowback data from our first five well [ph] corvette shows rates in pressures commensurate with our expectations for 40 acre development of the asset and which are exceeding the performance of the initial appraisal wells.

In the TMS, our drilling operations have commenced. The rig will run continuously throughout the year, allowing us to spud up the four gross operated wells in addition to participating in 10 to 15 gross non-operated wells. We increased our TMS net acreage position during the second quarter from approximately 40,000 net acres to 58,000 net acres largely through bolt-on acreage positions. We expect other TMS operators to continue wrapping up their activity and further derisk various portions of the play.

On the financing front, we successfully raised over $1 billion in debt and equity during the quarter which fully financed both the Catarina acquisition and our overall drilling problems indefinitely. We have achieved all these accomplishments while maintaining an intense focus on manufacturing efficiency which drives our low cost structuring, ultimately our capital efficiency.

I am extremely proud of our team’s efforts in achieving these goals and I’m very positive on our long-term outlook.

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

Christopher Heinson

Thanks, Tony. I’ll start by providing a brief overview of our accomplishments for the second quarter before giving additional details around each operational area.

For the second quarter, we spud a total of 30 wells, 23 operated and seven non-operated and completed 29 wells, 18 operated and 11 non-operated. As Tony mentioned, Sanchez has now officially taken over all operations at Catarina as of August 1st after a brief transition period with Shell. The transition has gone extremely smoothly and we appreciate the cooperation and professionalism exhibited by Shell staff during transition.

Over the course of the month between close and end of transition, we were able to fully staff Sanchez operations and initiate our development and optimization projects on time or ahead of schedule. We initiated drilling at Catarina on July 21st. We have plans to move in two additional rigs on Catarina in late August and early September with our first Lower Eagle Ford well was drilled with a 6,100-foot lateral and a spud to rig release time of approximately 13 days.

We saw strong shows in the Lower Eagle Ford while drilling the well and are currently drilling our second of the total of three Lower Eagle Ford wells that will be drilled on the pad. We expect to bring the pad online late in the third quarter with a total of six wells, four in the Lower Eagle Ford and two in the Upper Eagle.

We started fracking in Catarina with a dedicated frac spread on July 24th and started the process of working down the backlog of the 22 wells waiting on completion. Completion operations have been successful on our first two wells with 41 stages completed without any profit placement issues observed.

On August 1st, we also started operating a workover rate that will be dedicated to running tubing on wells in Catarina in preparation for subsequent artificial lift installs. We expect these installs to provide stabilization to our base production over the second half of the year.

Moving on to our other Eagle Ford operations, drilling efficiencies have continued to improve in the second quarter. Drilling cost in the Prost area had decreased from $4.3 million per well from this time a year ago to an average below $3.7 million per well over the last seven wells drilled in the second quarter.

One of our more recent multi-well pads in Prost, we average drilling cost of approximately $3.3 million per well and a resulting full pad cycle time of less than 60 days for three wells. Drill times has improved with recent wells taking 12 to 14 days from spud to TD versus the 25 days we were experiencing early in development.

Improvements in drilling efficiencies are attributable to further refinement of our mud and motor systems as well as continued benefit of extensive procedural [ph] planning. In the Five Mile Creek asset, drilling cost have decreased over the course of the six wells we have drilled to date with our last wells coming down below $3 million. This is a significant improvement over the $3.4 million drilling cost that we reported in the last quarter.

In Wycross, we have improved operational efficiency with each well drilled and have averaged a drilling cost of $2.9 million in the second quarter which represents a quarter-to-quarter decrease of approximately 13%. Regarding completions, most of our cost improvement to date has come from efficiency gains and our processed mapping of the fracking process.

Now that we have established critical mass with the Catarina acquisition, we’ve contracted a dedicated frac spread that will be utilizing direct resource proppant and chemical. These consumables typically make up 50% to 60% of the cost of hydraulic fracturing and are often a significant revenue source for pressure pumping vendors.

With direct sourcing and the long-term contract work, we expect average cost per stage to go from $125,000 per stage down to $90,000 per share assuming typical chemical and proppant loading we use currently.

This results in savings of over $700,000 per completion. With regards to total well cost, at Wycross, we have seen decreases to an average of below 6.5 million in our last five well pad. Including the forecasted expenditures for artificial lift.

In the Marquis region, recent porous wells costs have continued to decrease with a Q2 average of approximately $7.7 million. At Five Mile Creek, the average total well cost of our initial development was approximately $7 million.

The average represents a continued decrease over the course of the first six wells drilled and confirms our ability to optimize with increased experience in the area.

In the Prost area, we are continuing to see improvements even after one year of steady development. As one of most recent three-well pads, average of well cost of approximately $7.3 million including forecasted artificial lift.

From the standpoint of exploration and appraisal, inventory has continued to steadily increase. In Marquis, we conducted separate fracks and PLT and two of our Prost lowered [ph] Eagle Ford wells across the upper Eagle Ford interval which served substantial oil contributions.

We are currently drilling our first dedicated upper Eagle Ford well in Fayette County and plan to immediately follow with a second upper Eagle Ford test. We also have plans for additional upper Eagle Ford appraisal wells and Fayette and Lavaca Counties in the fourth quarter of this year.

Based on the extensive pilot hole and 3D seismic data as well as the PLT results, we recognized significant potential in both Marquis, standalone upper Eagle Ford development and stacked lower and upper Eagle Ford development in addition to our current lower Eagle Ford development in the area.

At Five Mile Creek, our first Buddha well, the Crabb Ranch A #2 was recently completed and now is on initial flow back.

In the Wycross area of Cotulla, we completed four wells at an appraisal cost close to the [indiscernible] and an appraisal area south designated to expand their perspective area for future locations. Those wells were brought online during the second quarter, with an average 30-day production rate of approximately 500 barrels of oil equivalent per day.

Confirming that we can expand our planned activity in Wycross at favorable rates and return in an area originally thought to be complicated and risky around the south bend [ph]. As Tony mentioned, our initial rates and pressures observed from our first five well development plan add away from the Dome is currently flown back and are in line with our expectations for 40-acre development in the asset.

In the Talbot are of Northern Cotulla, we successfully drilled an approximately 7,000 foot lateral and achieved initial 30-day rates over 600 barrels of oil equivalent per day versus a significant improvement over the 350 barrel of oil equivalent per day results from the initial wells drilled prior to our May 2013 acquisition.

In the TMS, our first operated well, the Dry Forks East #2 encountered several delays due to mechanical and equipment failures. During cleanout prior to running production chasing, the drill spring parted due to defects in the drill pipe. The well has been side tracked in the lateral and we are in the process of drilling to [indiscernible].

Prior to the failure of the drill pipe, the well was drilled from spud TD at 5,600 feet in 29 days and exhibited strong hydrocarbon shows during drilling confirming our expectation of a good well.

With regards to mid-year reserves update, crude reserves from our assets not including Catarina, increased to approximately 60 million barrels of oil equivalent at June 30, 2014. Inclusive of the Catarina acquisition, the company’s crude preserves total approximately 117 million barrels of oil equivalent as of June 30, 2014. An increase of over 170% relative to the balance as of June 30, 2013.

Crude oil constituted 49% and NGLs constituted 24% of the company’s proven reserves as of June 30, 2014. And 56% of the company’s crude’s reserves were classified and crude undeveloped as of June 30, 2014 as compared to 70% at June 30, 2013.

Moving on to production; during the second quarter, average daily production for the second quarter of 2014 was approximately 20,437 barrels of oil equivalent per day. Above the midpoint of our guidance range of 19,000 to 21,000 barrels of oil equivalent per day.

We experience significant downtime during the second quarter due to unexpected third party pipeline downtime in our Cotulla and Wycross areas. The downtime factor solely affects second quarter results and we do not expect an impact from the related downtime going forward.

As mentioned earlier, we are realizing significant savings with direct sourcing and profit in chemicals. Going into the second half of 2014, we are seeking to maximize the number of jobs we’ve comp at this considerable cost savings.

We have decided to delay several fracs scheduled in the third quarter in order to achieve savings of over 10% of the total well cost, a trade off we felt appropriate to make. As a result of the deferral of these fracs, we are slightly revising our third quarter guidance to 36,000 to 40,000 barrels of oil equivalent per day and increasing our fourth quarter guidance to 48,000 – 50,000 barrels of oil equivalent per day.

I will now turn the call over to Mike.

Michael Long

Thanks, Chris. Some of the points I make will reiterate things that have already been said. But starting at a high level, we ended the second quarter with very strong liquidity, totaling $811 million, which is made up of $386 million of cash and available borrowing capacity of $425 million from the elected commitment under our bank revolver. That was all completely unused of June 30.

Total debt outstanding was $1.45 billion, all long term notes with maturities not commencing until 2021. Net debt to pro forma LTM adjusted EBITDA was 1.63 times and total debt pro forma LTM adjusted EBITDA was 2.23 times.

Capital expenditures inclusive of accruals for the quarter were approximately $191 million. As previously mentioned, production averaged a little over 20,400 BOE per day after giving effect to those pipeline outages that Chris talked about.

Production increased almost 90% from the previous quarter’s daily rate of 18,784 BOE per day and was 164% than the same period a year ago.

Revenues for the second quarter increased 13% to $152 million compared to the previous quarter and were 157% over the same period a year ago.

Overall, during the quarter, we received an average realized price before the effect of derivatives of $100.90 per barrel of oil, $30.96 per barrel of NGLs, and $4.60 per mcf for natural gas. That equates to an average realized price for BOE equivalent of $81.55.

Our hedges reduced our effective prices during the quarter by $17.15 per BOE. $2.87 of that was related to cap settlements and balance was related to non-cash marked to market changes. 27% of our second quarter production and revenue came from Palmetto; 31% and 34% from Marquis; 34% and 31% from Cotulla, excluding Wycross and 8% and 9% respectively from Wycross.

Our production stream was 73% crude oil, 14% NGLs, and 13% natural gas. Adjusted net income to common shareholders as defined in our press release was $11.5 million for the quarter. Adjusted EBITDA also defined in the press release was $112.5 million, and that compares to $96.2 million in the first quarter and $43.2 million in the same period a year ago.

The significant non-cash items impacting our P&L during this quarter, in addition to the usual DD&A amounts were stock-based compensation, a $15.9 million, an unrealized hedge losses of $26.6 million.

Our effective tax rate for the quarter was 35%, of which 100% was deferred. At June 30, we had a net operating loss of Cherry Ford of over $660 million with explorations not beginning until 2031. Our cash operating expenses is defined as lease operating, marketing, production and ad valorem taxes and cash G&A were $18.60 this quarter continuing the trend of decreasing operating expenses.

We reported operating capital spending for the quarter as I previously mentioned of $191 million including estimated accruals. Our cash flow is stable but we’ll report actual second quarter CapEx of approximately $225 million for those accrual adjustments.

Currently, we have about 4.1 million barrels oil equivalence hedged for 2014. It represents about 40% of the middle of our guidance forecast. And we now have about 5.7 million BoE hedged for 2015 which gives us a range of about 25% to 30% of our initial guidance midpoint.

In June of 2014, we completed transactions with certain holders of our Series A and Series B preferred stock whereby we exchanged approximately 975,000 shares of common stock or 166,025 shares of Series A and 210,820 of our Series B preferred plus any accrued unpaid and future dividends through the normal call date. The net result of those transactions was a reduction in the par value of outstanding series A preferreds to $94 million and Series B to $177 million and a reduction in the annual dividends payable of about $1.1 million.

The accounting treatment of those transactions other than obvious adjustments to capital included a non-cash charge for dividends of $3.1 million for the quarter in our statement of operations to reflect the conversion inducement of paying future dividends with our common stock.

Finally, with respect to upcoming guidance, we revised certain guidance metrics as shown in the press release and as Chris talked about with respect to deferral of production in the third quarter for a benefit of further reducing our completion costs. But we raised our fourth quarter guidance commensurately. We also guided downward in terms of operating costs for the third and fourth quarter.

Although we closed Catarina on June 30th, we were not able to show the future benefit of that acquisition in our corporate DD&A rate. Had that transaction been reflected in our full cost pool at June 30th, our effective DD&A rate would have been reduced by about $10 a barrel.

As Chris discussed, although not in our measures, we continue to make excellent strides in all areas in reducing well costs both in the drilling and completion phases of operations.

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

Question-and-Answer Session

Operator

Ladies and gentlemen, we’ll now begin the question-and-answer session. (Operator instructions) Our first question comes from Leo Mariani from RBC. Please go ahead with your question.

Leo Mariani – RBC

Hey guys, a question on Catarina here. I know you started fracking the backlog of uncompleted wells. Are all of those up are Eagle Ford wells or are there any lower wells that you’re going to frack in the short-term? And I guess when do you expect to frack the first Lower Eagle Ford wells there?

Christopher Heinson

Yes, Leo, this is Chris. So the 22 wells that we’re waiting on completion prior to us taking over the asset, 21 of those wells were drills in the Upper Eagle Ford at Shell’s direction and one was drilled by Shell at our direction during the transition period.

So as of today, we’ve drilled two wells and we’ve completed two wells. So we have still 22 wells that need to fracked. The first Lower Eagle Ford results, we’re expecting online late in the third quarter as I mentioned. That six-well pad that contain four Lower Eagle Ford completions of the wells and then two Upper Eagle Ford wells.

Leo Mariani – RBC

Okay, that’s helpful. And I guess in terms of cost, it sounds like you guys are expecting lower well cost in the second half of the year. Is it fair to say you think you’ll get a 10% reduction in all of your wells with these outsourced chemicals and proppants now?

Christopher Heinson

Leo, we’re working very hard to accomplish that in all areas. Right now, we’ve got that secured right now for our Catarina asset. And we’re looking actively over the next few months to contract another long-term pressure pumping spread that service all the other operational areas. But we are immediately starting to directly source chemical and proppant in each of those areas.

So over the course of the second half of the year, I think we’re going to achieve that 10% across the board.

Leo Mariani – RBC

Okay. And I guess would that imply that your 2014 CapEx guidance could be biased towards the lower end of it here?

Christopher Heinson

If we don’t change our activity set and decide to increase activity due to the decrease in the spending.

Leo Mariani – RBC

Okay. And I guess just in terms of the TMS, I can see a whole hiccups there on the equipment side, when would you guys expect to start fracking out well and do you have an approximate AFP for that first of all?

Christopher Heinson

Well, we’re drilling the lateral for the second time right now. We expect it to finish shortly, hopefully by this weekend or early next week. We expect it to be fracked either late August or early September.

In terms of the total additional cost, with these problems, we’ve encountered roughly about $2 million to $3 million in extra cost. We’ve got an investigation going on right now to figure out if there was some quality defects that were associated with the pipe that came into deliver. So that investigation is under way. So we still don’t know what our action exposure is yet.

Leo Mariani – RBC

Okay. And I guess just switching gears, what’s kind of the current plan at Palmetto and is there expected to be any acceleration from Marathon at some point over there?

Christopher Heinson

We still haven’t received official updates for the remainder of 2020 and guidance. So I think we should stick to what we’ve put forward in our capital plan.

Leo Mariani – RBC

Okay, thanks guys.

Operator

Our next question comes from Steve Berman from Canaccord, please go ahead with your question.

Steve Berman – Canaccord Genuity, Inc.

Thanks, good afternoon. Back to the TMS, one clarification, the plants has spud up to four gross operated wells. Does that include the Dry Fork well or is that four additional wells or in above that one?

Christopher Heinson

It includes it.

Steve Berman – Canaccord Genuity, Inc.

All right. When do you think you’ll spud your next operated well? Does that depend on the timing of the Dry Fork well?

Christopher Heinson

It depends on the timing of the Dry Fork well, but roughly it will be six to seven days immediately after we’ve TD-ed that well.

Steve Berman – Canaccord Genuity, Inc.

Okay. And Goodrich had four TMS wells in their release this morning. One of which is just an update on the previously announced well. And two of those four were Encana-operated wells. Are you or TF working interest in any of those four?

Christopher Heinson

I don’t know exactly which four wells that you’re referring to that they released. But we do have interest in a number of the Encana and Goodrich wells.

Steve Berman – Canaccord Genuity, Inc.

Okay, the two Encana’s are the Lewis 7-18H-1 and the Mathis 29-32H-1 if that helps you.

Christopher Heinson

No, we don’t.

Steve Berman – Canaccord Genuity, Inc.

Okay. If Catarina beyond this six-wall pad, do you anticipate testing more of Upper Eagle for there because I’ve gone back to when you announced this acquisition. The talk seemed to be more focused on the Lower Eagle Ford. So has anything changed between then and now and what do you see as far as Upper Eagle Ford beyond this six-wall pad?

Christopher Heinson

Well, I’ll reiterate some of the comments that we made on our acquisition conference call. We are going to focus on the Lower Eagle Ford because we think that has the best opportunity to increase production in the short-term.

However, there’s absolutely nothing wrong with the Upper Eagle Ford across much of Catarina. We will be moving towards the Upper, in fact, a lot of these wells that we’re going to be completing are Upper Eagle Ford completion that Shell drilled.

So we’re going to be looking at just exactly how they perform relative to the Lower Eagle Ford. And we expect to eventually make our way back to the Upper Eagle Ford in 2015.

Steve Berman – Canaccord Genuity, Inc.

Okay, thank you.

Operator

Our next question comes from Neal Dingmann from SunTrust. Please go ahead with your question.

Neal Dingmann – SunTrust Robinson Humphrey

Hey, good afternoon guys. Say, Tony for you or Chris just sort of building on that last question, just wondering – besides Catarina, I’m just wondering and I think you mentioned this on say, North, how much of the I guess just in sort of broad terms, do you have estimate yet of your acreage perspective for – up at Eagle Ford? I mean, I guess that sort of number one. And then number two, what do you see I guess for the next few quarters up at Eagle Ford activity versus lower? I mean, well, still it sounds like it still will be concentrated mostly in the lower, I just want to see if I can get my hands around both those things.

Christopher Heinson

Yes. So of our Marquis position, we’re getting better definition around which area is our perspective. So if you look at our – the entirety of that position, we have roughly 50% of it that is very perspective or proven in the lower Eagle Ford. Roughly we have probably a slightly larger percentage that is perspective in the upper, and there is some overlap between those two.

So there is a certain portion of that acreage, call it 25%, 30%, both of those arising are perspective simultaneously. And on top of that we have also found about 10% of our acreage position is perspective in the Buda. But we’re going to be continuing to explore of those areas across the vast majority of that block.

Neal Dingmann – SunTrust Robinson Humphrey

Got it, got it. And then maybe question for Tony. Tony on this – when you mentioned in the press release about the direct source and the chemicals and propane, I mean, is this – would you go as far down the line as to – and certainly not own the rigs, but take position of sand mines or getting more involve in the services side other than just the direct sourcing?

Antonio Sanchez

No, I don’t think so Neal. I think that we’re approaching it from our stand point in terms of securing the inputs to the completion part of the phase [ph]. We have no intention of owning rigs. We have no intention of owning frock spreads. But we would contract frock spreads as we’ve already done one and they’re looking at another one.

In terms of propane and chemicals, pretty much the same story, probably a little bit tighter in terms of what that contract may entail, because there’s a logistics component around that that’s important. But I don’t foresee us owning chemical manufacturing or propane companies or mines for say. But we could have a strategic alliance with a company that owns mines.

Neal Dingmann – SunTrust Robinson Humphrey

Okay. And Tony, I apologize, maybe you or Chris have mentioned this in the past, as far as for Catarina, well, the spacing that you’ll go after or how you’ll sort of tackle that, after you do these shale wells, is that going to be – so I forget if that’s similar to what you’re doing in the market here just trying to get enough – remind me on the down spacing.

Antonio Sanchez

Yes. We’re going to work our way to figure out what the optimal spacing is, both laterally and either the lower or the upper Eagle Ford, and then in a staggered fashion. So it’s – we’re doing some drilling – some of the drilling that we’re doing is staggered and below some of shale’s existing wells or the prior wells that were there. And then some of the new areas, we’re doing much the same exercise that we’ve executed across some of our other assets in terms of trying to find optimal spacing between the laterals.

Neal Dingmann – SunTrust Robinson Humphrey

Okay. And then lastly on the TMS, Tony, your thought on, I think on this, first, Tony, decide the land about [ph] the rubble zone, just on sort of drilling to completion is it just sort of very sort of by – just happen for that acreage of yours or any just general thoughts as far as the best sort of completion methods or I say before the completion methods where are the sort of target?

Antonio Sanchez

Yes. I don’t – I think that between the two upper above the rubble zone or below the rubble zone. Above obviously offers less mechanical issues that maybe derived from the formation itself. The particular issues that we’re running in to in this well that we run into rather had to do with the drill pipe itself, and we actually got the well down empty did [ph]. And up until that point, until we were cleaning out the hole, everything was going ahead of schedule.

So it wasn’t – we really don’t have any issues drilling with it. We think we may have had some either structurally bad drill pipe joints. We have saved all of that. And we’ll be investigating the issue. But it has nothing to do with the TMS itself, nor whether it was above the rubble zone or below.

Neal Dingmann – SunTrust Robinson Humphrey

That make sense. Thanks guys.

Antonio Sanchez

Yes.

Operator

(Operator instructions) Our next question comes from Dan McSpirit from BMO Capital Markets. Please go ahead with your question.

Dan McSpirit – BMO Capital Markets

Thank you, gentleman. Good afternoon. Regarding direct sourcing of consumables, just trying to get a hand on how this works, that is how you procure and manage the chemicals in propane supplies? I’m just trying to assess any risk related to timing of getting these inputs as you put it to the drill site. And as a follow on to that, can you do the same or will you do the same in the TMS?

Antonio Sanchez

Yes. So this is Tony, I’ll answer from a high level and Chris will give you some specifics. But really our goals in direct sourcing are two-fold, one, to secure a more competitive price through longer term contracting, and secondly, to assure ourselves of the stability of the logistical part of the process. So what we’re really trying to do is achieve the cost savings but assure ourselves better delivery in a just in time manner of the inputs to a completion job.

So those are the two goals. With that, Chris can address some of the specific.

Christopher Heinson

Well, I think, Tony addressed it well. I think the availability of the commodities are out there in the market. I think logistics is the challenge. And getting large term commitments done with either these mines or with the chemical providers, allows you to actually control those logistics. So we’re able to actually plan out several months ahead of time what the work is going to take place, eliminating some of that immediate demand shortages that do occur in the market place.

Dan McSpirit – BMO Capital Markets

Got it. And do you see yourselves doing the same in the TMS at some point?

Antonio Sanchez

Yes.

Dan McSpirit – BMO Capital Markets

Got it. Another question if I may, any current thoughts on fuel lower returns in the TMS based on the larger data set of industry results that we have today? And how do those returns compare or compete to what you’re realizing in South Texas, especially considering the cost reductions involved?

Antonio Sanchez

I think they’re confirmatory of what the initial results were leading us towards, which is on the low-end 40% or 50% IRs [ph] at the well head with kind of $12 million to $13 million well cost. When you – when we spec out of well on a standalone basis, it’s $14 million to $14.5 million as we go into development. And some of that has some buffer built into it. As we go into development, I think the process or the path that the TMS is following merge very much what we saw in the Eagle Ford which is a pretty stiff drop off in cost.

So I think getting the $10 million to $12 million is a highly probable outcome. And if that’s the case, you’re looking at rates of return from 50% to 80% at the well head. And those would be competitive with our programs in the Eagle Ford. So at that point, we just make a capital allocation decision as part of the portfolio. And our view is that the TMS will become competitive for capital and short order.

Dan McSpirit – BMO Capital Markets

Okay, great. And then lastly here, just turning to the balance sheet following the acquisition here recently, where do you see leverage trending in the back half this year, and maybe if you could just sketch for us that the leverage in 2015?

Antonio Sanchez

Yes. This is Tony, I think the way we – I’ll just address how we approach the acquisition and the subsequent capital raise from the perspective of credit metrics and the balance sheet, we try to look at assets that basically allow us to maintain our current conservative and strong balance sheet while keeping a lot of liquidity.

And so, if you look at the asset that we recently bought Catarina, look at the asset we bought from Hess, look at what we bought at Wycross, they all have very similar profile. So it allows us to grow while maintaining that 2 to 2.5 times debt to EBITDA ratio. And this particular asset was much the same.

If we’re at – Mike mentioned, we’re at 2.23 times LPM debt to EBITDA. If on a go-forward basis, we ramp up and expect that to probably pick up to about 2.4, 2.5 times and if production catches up, it will start to trend down towards 2 and then under 2.

All the while, we’ve got over $400 million in uncapped borrowing capacity, so that should also begin to increase as we add more reserves to the books.

Dan McSpirit – BMO Capital Markets

Great. Thanks again for taking my questions.

Christopher Heinson

Thanks, Dan.

Operator

And our next question comes from Ron Mills from Johnson Rice. Please go ahead with your question.

Ronald Mills – Johnson Rice & Co. LLC

Hello?

Antonio Sanchez

Milos [ph]?

Ronald Mills – Johnson Rice & Co. LLC

Hey.

Antonio Sanchez

It’s on.

Ronald Mills – Johnson Rice & Co. LLC

Hey, guys, sorry about that. A question, as it relates to the Catarina properties in particular since that’s a more condensate heavy area, can you just review with us what kind of infrastructure came there in terms of stabilization capacity, processing capacity, et cetera as you increase the condensate production there and how that might apply to the earlier ruling about condensate exports?

Antonio Sanchez

All right, Chris, go ahead.

Christopher Heinson

Yes. There are four actual processing facilities at the ranch. Each of those processing facilities has an actual distillation power. So we’re actually able to process on the ranch. It is in essence a small gas processing plant on the ranch. So we have that to process the condensate barrels as well as we have the other sort of standard dehydration sweetening [ph] associated with additional gas [ph] for sale into those lines.

But, yes, essentially the four processing plants that we described really truly are processing plants I think by the definition of at least what it appears to be IF’s [ph] expectations are.

Ronald Mills – Johnson Rice & Co. LLC

Okay. And then – I apologize, I missed the first part of the call but has this taken over – or is this closing on the deal in June and taking over operations earlier this month? Can you just update me, you have one rig over at West Catarina, you’re at two yet and where are you in the drilling process? And sounds like your dedicated frac spread is working, how many – what does the completion program look like in terms of timing getting through those 22 or 23 uncompleted wells?

Antonio Sanchez

Hey, Ron. We’ve got one rig running right now. It’s already drilled its first well. It’s on well number two. We’re into the lateral on that one.

We have our second rig coming on later this month. That will be our new build. It will also focus on Western Catarina. And our third rig which will actually do the appraisal work in the east is coming on in early September.

As for our first completions, our first pads from the wells that we’ve actually drilled, they’re expected late third quarter.

Ronald Mills – Johnson Rice & Co. LLC

Late third quarter in terms of the completions?

Antonio Sanchez

That would be the timing of our first Lower Eagle Ford wells that we’ve actually drilled we’re expecting in the late third quarter. The wells that we’re completing right now, we’ve got two of those finished already in the Upper Eagle Ford. Those are going to be on this month.

Ronald Mills – Johnson Rice & Co. LLC

And then where does Lower Eagle Ford test that Shell drilled right before you took over the properties lie [ph] in your completion schedule in terms of potential timing on those results?

Christopher Heinson

It’s on that same six-well pad that we’re currently drilling right now. So it’s going to be that – we’re going to bring all six of those wells on late in the third quarter together.

Ronald Mills – Johnson Rice & Co. LLC

Okay. And I’ll jump back in and I’ll get back in line. Thanks, guys.

Antonio Sanchez

Ron?

Ronald Mills – Johnson Rice & Co. LLC

Yes, sir?

Antonio Sanchez

Okay, I think you’re the last one in the queue, so if you’ve got more questions.

Ronald Mills – Johnson Rice & Co. LLC

Well, I may follow up offline since I missed some of the call. I’m sure you addressed the direct sourcing on the proppants and chemicals in terms of what that does to a cost standpoint. But any other color how to frame – how those deals came about, who the counterparties are and are they limited to a certain supply of – or amount of chemicals and proppants and how does that fly –

Antonio Sanchez

Yes. They came about by virtue of our operations group securing the logistical side of it and getting some pricing. It’s by no means accounting for 100% of our usage over a calendar year or anything, but it will account for a significant part of it.

We’re not giving – publicly disclosing any counterparties to that. It’s just a function of us sourcing chemicals and handling some of the logistics with arrangements on the logistics side. So that – does that spell out a good response to your question?

Ronald Mills – Johnson Rice & Co. LLC

Yes, it does. And is there a particular – given all the talk of brown sand versus white sand, et cetera, is there a particular type of proppant that you’re targeting in this agreement?

Antonio Sanchez

Yes and no. Whether it’s brown Brady sand or white Ottawa sand and I think it’s more specific per applications and certain areas getting away with the lower crush strength, cheaper proppant is perfectly suitable. They’re not an issue and those mines tend to be more better situated from a distance standpoint. And so the logistics costs are not as high. But in other areas such as Marquis where the formation is deeper, we do require higher quality sand. So we are using both.

Ronald Mills – Johnson Rice & Co. LLC

How would you approach the appraisal of East Catarina because it’s kind of I guess somewhere in between and how should we think about your appraisal program there? Are you going to offset wells that had already been drilled by Shell on East Catarina or how would you go about starting that program?

Christopher Heinson

Yes. We’re going to be drilling – it’s a large aerial position. I mean it’s close to 50,000 acres just in that east. We’re going to be drilling sort of in trying to hit the position all across it with wells about two at a time. Shell had actually built a number of pads and never drilled any wells on them, so those wells are going to be used as well as going back on pads where Shell had actually landed a well, we think they can be landed in a more prospective zone.

Ronald Mills – Johnson Rice & Co. LLC

Okay. And then, Tony, you may be mentioned this too but any – Rosetta had some pretty positive comments about the Upper Eagle Ford on their call earlier this week. I know the Upper Eagle Ford West Catarina at least is more developed but not necessarily so at all on the east and I know that the central Catarina you’ve downplayed that potential but at the Upper Eagle Ford, it’s present there as well as I recall. Any read through from their comments to your Upper Eagle Ford?

Antonio Sanchez

Well, I think they’re very positive certainly as they pertain to the western part of the asset where we’ve got 38,000 acres or so on the Western Catarina. So, yes, I think that what they’re saying bodes quite well for the Upper Eagle Ford potential on the western side, of which some of the production or a large part of the production for that matter is currently coming from.

We think there are some distinctions that we can capitalize on, such as where the laterals are landed at the Upper Eagle Ford and how the wells are fracked that we’ve got some room for improvement. But the Upper Eagle Ford is certainly – is present across the entirety of the ranch.

What Rosetta has said recently about their Upper Eagle Ford results I think directly impact at least the western part of the ranch where we’ve got about 38,000 acres in that designated section. So whether or not it impacts the middle and the eastern part, we just don’t know yet.

Ronald Mills – Johnson Rice & Co. LLC

And how many – given that Upper Eagle Ford was fairly well developed by Shell, have you looked at the remaining Upper Eagle Ford locations that could eventually be targeted in the future? How many are remaining at least based on 1,000-foot spacing that Shell was developing on?

Antonio Sanchez

On the western side?

Ronald Mills – Johnson Rice & Co. LLC

Yes.

Antonio Sanchez

In the Upper Eagle Ford, there’s at least 80 locations.

Ronald Mills – Johnson Rice & Co. LLC

Eighty, okay.

Antonio Sanchez

And on the eastern side of the Upper Eagle Ford works, there could be another 400 or more. And that’s again that’s just at the Upper Eagle Ford. So you’re talking upwards of almost 500 wells between the western part of the ranch and the eastern part of the ranch with the western part only counting, estimating the Upper Eagle Ford locations that currently haven’t been drilled. There might very well be more than that even on the west side. So that’s 500 locations across the ranch. Nothing in the central, only to the Upper Eagle Ford. And then to that you’d add Lower Eagle Ford potential both across the west and the east. But at this point, our expectations that are in the central would the Lower Eagle Ford is eroded away.

Ronald Mills – Johnson Rice & Co. LLC

Great. And then lastly just on the LOE, huge improvement in the second quarter the second half guidance is a little bit higher. I’m assuming that’s due to the integration of the Shell properties which are probably higher cost than what you would be.

But what drove the dramatic improvement sequentially to where your Sanchez stand alone was in the second quarter? And can you – and so how – what timeframe do you think you can pull that second half guidance down closer to where the mid $7.58 range kind of like your second quarter rate was like?

Antonio Sanchez

Yes, Ron, we are temporarily seeing higher LOE costs in Catarina associated with the transition. Really, we need some time to sort of optimize that asset as we have with our Cotulla asset after we acquired that from Hansen [ph].

We have seen across the board improvements in terms of LOE. I think once we’ve got an established development, I think we’re getting better at addressing sort of the ongoing maintenance issues associated with D12 [ph]. We’re getting getter at knowing how often and how to treat these things [indiscernible] we ever see that.

In fact, we couldn’t large scale infrastructure and much of our assets now that are removing the need to actually move a lot of the fluids around on the actual leases. So that’s really what’s driving that. That’s going to of course continue and once we’ve got through our transition period in Catarina, we expect that to come down.

So all of those cost savings are kind of offsetting sort of the other factor which is your LOE does increase as the wells get more mature. They just need more maintenance. They get sort of production per well.

So those two factors are offsetting, but we expect some gains before that flow will start to increase again.

Ronald Mills – Johnson Rice & Co. LLC

Perfect. If there’s anything else, I’ll check in offline. But thank you so much.

Operator

Our next question comes from Mike Scialla from Stifel Nicolaus. Please go ahead with your question.

Mike Scialla – Stifel Nicolaus

Yes, hi guys. I think Mills almost asked most of my questions there. But I’m wondering if in terms of the geologic differences you may see between the Lower Eagle Ford, you mentioned there’s [indiscernible] the center part of Catarina. But you’ve kind of drawn an analogy to offset acreage. Do you see any sort of geologic differences between the Lower Eagle Ford on east and west versus some of the offset properties?

Antonio Sanchez

Yes. So what Eagle Ford does as you get to the ranch, much of the western Lower Eagle Ford looks very, very similar to those offset operators. So in an instant as you see immediately better results from SN or was that immediately across the lease line.

So in places there is no sort of geologic difference. In general, it does start to get thinner as you go towards the center. We’ve put our number. We said that there is roughly 200 locations in Lower Eagle Ford that we think there’s adequate Lowe Eagle Ford thickness of around 30 to 60 feet in order to make very good wells similar to the other offset operators.

But as – there’s this other bands where it goes from less than sort of that 30-feet thick Lower Eagle Ford down to zero which we hope to actually explore and hopefully we find that the Lower Eagle Ford can be productive even in very thin areas which is what we’ve found in the Marquis area for example.

Mike Scialla – Stifel Nicolaus

Got you, okay. And then I just want to see if you could put some EURs to any of these areas that – some of the new areas where you give us some early time rates, it looks like obviously the cost trend of going in the right direction there. But like in the Five Mile Creek area, are you ready to talk about EUR numbers there?

Antonio Sanchez

No, we’re not. In fact our latest midyear reserves didn’t even include the reserves associated with our Five Mile asset.

Mike Scialla – Stifel Nicolaus

Okay. I assume the same thing goes for Wycross then and you’d said both in terms of near the salt dome and the 40-acre wells away from the salt dome that they were meeting expectations? Can you at least say what the expectations were there?

Antonio Sanchez

Well, the expectations are – and if you go to our guidance, you’d get a good sense for what we were expecting for our typical Wycross development. Now on the salt dome, it’s a little too early to tell. We’re not ready to come out there with the EURs for those locations that are immediately adjacent to that salt dome there.

Mike Scialla – Stifel Nicolaus

In terms of the 40-acre wells, do you see any signs of interference yet?

Antonio Sanchez

It’s too early to tell.

Mike Scialla – Stifel Nicolaus

That’s all I had. Thank you.

Antonio Sanchez

Thanks, Mike.

Operator

And gentlemen, at this I’m showing no additional questions. I would like to turn the conference go back over for any closing remarks.

Antonio Sanchez

Okay, thank you everybody for joining us today. We look forward to speaking in about three months.

Operator

Ladies and gentlemen, that does conclude today’s conference call. We do thank you for attending. You may now disconnect your telephone lines.

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