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Sanchez Energy Corp. (NYSE:SN)

Q4 2012 Earnings Call

March 07, 2013 02:00 PM ET

Executives

Mike Long - SVP and CFO

Tony Sanchez - President and CEO

Joe DeDominic - SVP and COO

Analysts

Ron Mills - Johnson Rice

Leo Mariani - RBC

Curtis Trimble - Global Hunter

Stephen Shepherd - Simmons & Company

Jeff Hayden - KLR Group

Mike Scialla - Stifel

Richard Tullis - Capital One Southcoast

Paul Grigo - Macquarie

Adam Michael - Miller Tabak

Daren Oddenino - CK Cooper

Tom Bishop - BI Research

Operator

Good day and welcome to the Sanchez Energy Corporation Fourth Quarter And Year-End 2012 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 you now like to turn the conference over to Mr. Mike Long, Senior Vice President and CFO. Mr. Long, the floor is yours, sir.

Mike Long

Great, thank you Mike, and welcome everybody. Before we start I'd like to advice you that we will be making forward looking statements within the meaning of the State Harbor provisions of the U.S. Private Securities Litigation Reform Act 1995. Words such as will, potential, believe, estimates, intend, expect, may 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 which may cause our actual results to differ materially from those implied or expressed by those statements. Please refer to a full set of forward looking statement disclosures in our recent SEC filings.

Joining me on the call today is Tony Sanchez, President and CEO and Joe DeDominic, our Chief Operating Officer. I'd like to first turn the call over to Tony Sanchez.

Tony Sanchez

Thank you, Mike. Welcome to the fourth quarter and year end 2012 earnings and operations conference call. Joe and I will provide you with brief overview of the company and our operations. After that Mike Long, our Senior Vice President and CFO will review financial results. We will then follow our prepared marks with a Q&A session.

We are an independent exploration and production company focused on the exploration development of oil and natural gas resources, the oil preliminaries of the Eagle Ford shell trend of South Texas. We own rights to all depths and zones over the majority of our acreage including the Eagle Ford, the Buda Limestone, Austin Shock and Pearsall formations providing our acreage with substantial upside potential through the drilling of multiple pay zones beyond our near term focus on the Eagle Ford.

Our current market capitalization is approximately $600 million and at the end of the fourth quarter we had $61.9 million in cash and marketable securities and no debt. All of our operations are based in the Eagle Ford shell trend of South Texas within the counties of Gonzales, Zavala, Frio, Fayette, Lavaca, Atascosa, Webb, and DeWitt where we have approximately 95,000 net acres in the black and volatile oil windows of the trend.

We believe this acreage position ranks us as the public company with the greatest exposure to this trend based upon net acres per million dollars of enterprise value. We continuously managed our acreage positions within our three core areas of Maverick, Palmetto, and Marquis to create contiguous land positions in order to maximize drilling and production efficiencies. While organic growth achieved the other drill bid is our primary operational focus, we are opportunistic about adding land positions in areas that we believe will enable us to build scale and drive efficient operations.

In the Prost area of our Marquis asset, we recently increased our net acreage position to approximately 7,500 net acres, forming a large and contiguous block which we believe will support at least two years of full scale development optimized for multiple rigs, cost effective operations, and infrastructure development.

Our average production volume year to date for 2013 is approximately 3,800 BOE, which is in line with the guidance we have given for this year and compares to our average production for the fourth quarter of 2012 of approximately 1,900 BOE. So far this year, we have seen continued strong performance coming from wells that we put online in December and expected as we progressed through 2013, our production growth will continue along the lines of the guidance that we have provided and expect to exist this year at a rate of approximately 9,000 BOE per day.

Total production for the fourth quarter was approximately 172,000 BOE, an increase of 29% over the third quarter of 2012 and an increase of 208% over the same period in 2011. Production for the calendar year 2012 increased 170% from 174,000 BOE for the year ended December 31, 2011 to 469,000 BOE for the same period in 2012.

Nearly 90% of our production is oil and we sell the majority of it at LLS pricing and foresee improvements in our margins as our infrastructure projects are completed during the middle part of this year. During 2012, we drilled and completed 19 wells for a total of 32 wells producing at yearend with two additional wells added in early January in our Maverick area.

Additionally, we currently have 17 wells in various stages of drilling or completion as more fully detailed in our accompanying press release. There are three rigs currently drilling, two in Palmetto and one in Marquis, with an expected second rig coming into Marquis late in the second quarter.

At the end of 2012, our proved reserves as calculated by Ryder Scott were 21.2 million BOE, an increase of more than 200% compared to December 31, 2011. Of these, oil constituted 86% of our proved reserves, 18% were classified as proved developed and 82% classified as proved undeveloped.

Now, I would like to turn the call over to our Chief Operating Officer, Joe DeDominic, who will talk about our operations and key objectives for the year.

Joe DeDominic

Thanks, Tony. I’ll provide a high level overview and then cover some of the details on each of our project areas. Our main operational objectives are to continue to grow our production and reserves while decreasing our cost per well and improving our operational execution and efficiency.

We have made the decision to move from 80 acre well spacing to 60 acre well spacing in both Palmetto and Marquis based on an analysis of recent data. This new well spacing will not only increases our reserves on our existing acreage but will also assist in our transition to multiple well pads and shared facilities. We also plan to continue to further delineate Eagle Ford across our acreage position while allocating a portion of our 2013 budget to testing additional prospective horizons.

At Palmetto where we have a 50% working interest with Marathon, we added production from nine new wells in 2012, giving us a total of 18 producing wells at yearend. Currently, there are two rigs working with an expectations of drilling a minimum of 25 gross well in 2013. At the present time, we have eight wells currently waiting on completion, five of which are on one pad and represent the 40 acre pilot and three on an adjacent well pad.

We will be collecting micro-seismic data on multiple wells while testing variations to the completions and the spacing. Initial production from these wells is expected by early May. We are also upgrading the central production facility on this asset to increase the total capacity to 20,000 BOE per day in $30 million cubic feet of gas per day.

As part of those facilities upgrades, work is ongoing to install a new crude oil pipeline to deliver oil to a third party tank facility which will result in a $2 to $3 per barrel decrease in our transportation cost. In our Marquis area, where we have a 100% working interest and operate, we drilled three wells in 2012 and all of them are currently producing to sales.

We currently have one rig running in the Prost area of Marquis and expect to add a second rig in the next quarter as Tony mentioned earlier in the call, and we plan to drill 19 additional wells this year. Currently six wells are either undergoing completions operations as we speak or will be completed within the next 30 days.

We also expect initial production from these six wells in April. We are collecting micro-seismic on two of the wells and coupled with the forthcoming 3D seismic over this area. we will be analyzing results and new data for further changes in well spacing and well completions potential enhancements to our completions.

Finally, in our Maverick area we added production from seven new wells in 2012, for a total of 10 producing wells at year end. We currently plan to drill two Prost wells in our Maverick area in 2013. We exited 2012 with a growing production stream of standing reserve additions and a backlog of wells which will be completed in producing within the next few months.

Our operational focus is to continue to drive our cost down, and increase our operating efficiencies across all of our areas. We are making steady progress on this front as a result of moving to multi-well pad drilling with newer more efficient rigs, investing in infrastructure development to improve our margins, and focusing on near term capital on high rate of return opportunities.

We expect to drill a total of 33.5 net wells in 2013 and we are comfortable with our 2013 production guidance, which projects and increase in full year production volumes of over 400% and an increase of our expected year over year production exit rate of a 100%.

With that I will now turn the call back over to Mike Long, who'll discuss our financial results.

Mike Long

As Tony mentioned, production for the fourth quarter of 2012 increased 29% over the previous quarter and 208% over the same period a year ago. For the year, production increased a 170% to an average of 1,281 BOE per day, compared to 476 BOE for the same period in 2011. As we have previously reported our 2012 production growth ramp was pushed back later in the year than originally forecast, as we began the move to more pad well drilling and encountered some temporary takeaway constraints. Revenues in the fourth quarter increased 259% to $16.7 million, compared to $4.6 million for the fourth quarter of 2011 and for the year revenues increased a 197% from $14.5 million in 2011 to $43.2 million in 2012.

Revenues were driven primarily by our increase in production; however we did see an average realized price per BOE increase about 10%, year over year. Overall, we received an average realized price of $92.07 per BOE in 2012. That compares to $83.57 for the same period a year ago, approximately a 6% increase and that was slightly offset by a decrease in average realized prices for natural gas between the two periods. 64% of our 2012 production in revenue came from our Palmetto area, with the addition of the new wells Joe described.

Production from our Maverick area where we added seven new wells this year was 19% of our 2012 total production and contributed 20% of our total revenue. In the Marquis area where we added our first three wells late in the year, these contributed 14% of our 2012 production and 16% of our revenue.

In Palmetto and Marquis you may recall that our oil sales are made on a LLS pricing basis. The average gravity or crude production in these areas is approximately 45 degrees and is purchased and marketed under contract as crude oil.

For the month of February 2013, at Palmetto and Marquis our oil was sold based on the conical Phillips WTI field posting which averaged $92.04, plus the Argus posting plus marker which averaged $2.78 plus the WTI LLS differential, which for the month of February was $18.07, less $7.25 for transportation and quality. That gave us a realized price for this month of February this year, a little over a $105 a barrel. We have just recently amended our purchase contract at Marquis to reduce the deduct from $7.25 to $6.75.

Generally for the month of February at Maverick are all over sold off plenty Flint Hills, Eagle Ford west posting which for the month of February averaged slightly over a $100 plus the Platts P-Plus average in that area of 276, less a $1.50 for a realized price in that area of almost a $102 a barrel.

We reported a net loss for the year to common shareholders for the quarter of $1.1 million in 2012 compared to the net loss of $1.4 million for the comparable period in 2011. For the full year December 31, 2012, we reported a net loss attributable to common shareholders of $18.4 million, compared to net income of $2 million for the same period in 2011.

Adjusted net income attributable to common shareholders as defined in our Press Release was $1.6 million for the fourth quarter, compared to $607,000 a year ago. Adjusted EBITDA attributable to common shareholders also defined in our press release was $8.2 million for the fourth quarter of 2012, compared to $2.1 million in the same period a year ago.

For the full year 2012, adjusted net income as defined in our Press Release was $7.3 million and adjusted EBITDA as defined in the Press Release was $22.8. This compares to the 2011 period for net income of $2.4 million and the EBITDA of $6.7.

At the end of the year our hedges that we had in place were comprised of a series of WTI put and put spreads as well as some oil swaps. Our put and put spreads currently outstanding consist of a 95/75 put spread for a 1000 barrels a day for calendar 2013, and an additional 90/75 put spread for 1000 barrels a day for the second half of 2013.

In addition during the third quarter we added a fixed price swap for oil at $97.10 for 500 barrels a day, January to December 2013, and in the fourth quarter we added an additional fixed price oil swap at $88.90 WTI for a1000 barrels a day for all of 2013. Currently our 2013 hedges cover approximately 40% of our estimated production for this year.

Subsequent to year end we entered into two additional oil derivative contracts. It covered approximately 15% of our estimated 2014 production. In January, we entered into a derivative contract covering 1500 BOE per day for all of calendar year 2014. It was a three-way costless collar consisting of a long $85 WTI put, short a $102.25 WTI call and a short $65 WTI put.

In February of 2013, we entered into an additional three-way collar covering 1000 BOE production for all of 2014. A same three-way collar, this one was done on a LLS pricing basis with a long $95 put, a short $75 and a short $107.05 put.

As of December 2012, we had approximately $61.9 million in cash and available for sales securities and no debt. Our credit facilities which were put in place in the fourth quarter of 2012 included a first lien credit agreement and a second lien credit agreement. Under the terms of the second lien in credit facility, the commitment of $50 million would have expired on January 31, 2012 unless drawn.

We did draw that on the 31st, leaving us with 50 million of outstanding debt but we still no usage under revolving credit facility. Then in this first quarter of 2013 as previously announced our available borrowing base under the $250 million first lien credit agreement was increased from $27.5 million to $95 million.

Our second lien credit agreement remained unchanged and there is still no usage under the first lien revolver. We believe as a result that we have considerable financial flexibility with low debt and a very strong cash position.

The increase and available borrowing base and our expectations about continued growth in our borrowing base from our 2013 drilling program leaves us comfortable about our ability to sustain the growing operational and financial momentum that we’ve talked about throughout this call through 2013.

With that review, I’d like to turn the call back over to Tony for any closing comments.

Tony Sanchez

Thank you, Mike. We’re proud of what the Sanchez team has accomplished this year and excited about the potential for our 2013 drilling and execution that is now in progress. Joe talked about the operational strides we’re making and I expect those efforts to show up and reduced well costs and streamlined operations as we progress throughout this year.

With 95,000 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 believe we’re unique among company or size with our so oil focus and our extensive drilling inventory focused on the prolific Eagle Ford shell trend.

With that I’d like to open up the call for questions.

Question-and-Answer Session

Operator

Thanks you, sir. We will now begin the question-and-answer session. (Operator Instructions). And the first question we will have comes from Ron Mills of Johnson Rice. Please go ahead.

Ron Mills - Johnson Rice

Couple of questions for you. On Palmetto, you walked through the infrastructure additions in terms of getting the capacity of 2000 barrels a day and $30 million a day. How does the timing of that looping of the truck loading facilities to fit in with the scheduled completions for the upcoming eight wells at Palmetto and also how does it fit into the timing of the enterprise oil pipeline that’s going to be serving that area?

Joe DeDominic

It’s all kind of running concurrently. Marathon is out there prepping the wells for completion at the present time. They’re also currently on the central production facility, expanding and looping the gas line to the transport for sales and then currently starting on the oil pipeline to the enterprise marshal station. So it’s all occurring at the same time.

Ron Mills - Johnson Rice

And at Marquis, the Prost acreage additions, you increased the acreage there by 70% - 75%. Can you just provide a little clarity in terms of how contiguous it is to your existing position, what it does in terms of adding drilling units and when you talk about a multi-rig program of two plus years of drilling, is that based on a two rig program because you do more, just how do you approach it now as you core up Prost.

Joe DeDominic

Essentially what we have done is fill in some, I’d hate to call them holes that some available acreage that was in there to help us form another three additional units which are directly a budding, the current three units we have and then also added some acreage adjacent to that which we are in the process of working to add additional units on to those.

So it’s all one large contiguous block which will help us with our pads. We foresee drilling wells off of pads in both directions in units to the north and to the south which will give us some obviously cost savings and then our gathering system, which we’re already out there right now putting in place, we’ll be able to tie those new units and the new wells that we just acquired the acreage on, right into that existing system that we already have in place and that savings of course will flow right down.

Tony Sanchez

Let me add to that. This is Tony. I like to highlight our last well in that area and really explain why we were so excited about the Prost position in Marquis in general. The Prost B number one, we did include a table in our last Press Release and that well came online. We put it online on a 14/64s choke and we left it there for two months and so the well had an IP of about 1100 barrels a day and a 30 day average of about 936 barrels a day.

What we didn’t include in the press release was a 60 day average for that well, which was over 800 barrels a day and for us that’s an outstanding completion and it being the third one in that particular area, there is even room to improve over and above that but if you look at the 7500 acres that we now have, a 100% working interest in with well results, trending in the direction that they are, I think this asset is proving to be as valuable to us as Palmetto.

We are also going to be down spacing to 60 acres in that particular area. So there is a lot of upside to be had. There's operational efficiencies that will drive cost down. The well performance here from an EUR perspective is tracking north of 500,000 barrels and if you kind of do the adjustments to compare apples to apples, our net acreage here is substantially larger than our net acreage position in Palmetto and so far we have been getting wells that are performing as good as they are in Palmetto. So we are really excited about this particular area, hence why we are willing to dedicate at least two full time rigs to it in the near term.

Ron Mills - Johnson Rice

And you stole my last question, I was going to ask you about that well and also the impact on the EURs in that area and also if you had any comments on; now that you have some of the latest Marathon wells, the Palmetto wells online now since November - December; how are those tracking the tight curve relative to your 500,000 to 800,000 barrel to 450,000 to 750,000 barrel type curves that you are expecting in that play?

Tony Sanchez

I think in all cases, what we are saying is the newer wells are continuing to outperform the older wells. And so both the Prost area Marquis and in Palmetto, the newer wells, and with Marathon and in some cases you are seeing 20,000 barrels more production in 60 days, out of some of the newer wells versus some of the older wells. So we are very comfortable and you can see the production on these wells meeting or exceeding our estimates.

Operator

Next we have Leo Mariani of RBC.

Leo Mariani - RBC

Just looking for little more information on Prost. Clearly has been going well for you guys. Did you pick up all these acreage, kind of year-to-date here in 2013? Did you pick up some maybe late last year and do you see any other expansions possible there. Can you keep picking up acreage kind of in and around and blocking it up?

Joe DeDominic

So, the answer the answer is yes to both; heard all of the questions. We have been picking up acreage there. The position itself is in an area where it is made up of a lot of small track. So we have been trading some acres of offset operators that might have been stranded for us; but good for them and vice versa.

We have also been picking up some leases, straight leases and then blocking out our prost area and making it larger and more contiguous. But we are continuing to expand on that. So I think the answer is we have picked up leases both in 2012 as well as in 2013. We are continuing to lease out there. I think we are very fortunate in that the makeup of this area is a lot of small mineral positions. With our large one it's very difficult for anybody else to establish a competitive position here. And so if anybody else wanted to come in and lease they would be left with small blocks, whereas for us, now that we have a big block it's easier to add to it and to form large enough blocks that lend themselves to efficient development.

Tony Sanchez

I'll add one other comment on top of that. I think what you're starting to see in some of these areas is, as the plate matures, operators are, including ourselves are willing to trade acreage to build up these contiguous blocks and help our operations and drive costs down and so we're actively in discussions with several other owners in the area on trades and so we perceive doing more of that.

Leo Mariani - RBC

That's helpful for sure. I guess you guys started breaking out NGLs on your results here in the fourth quarter. Just wanted to get a sense, are those all coming from you know the Palmetto area? Did you get your kind of gas processing going maybe late in the year and what type of NGL yield do we expect kind of going forward from the Palmetto area?

Joe DeDominic

The NGLs reported to date have largely come out of overrides in positions that we have scattered across the areas as opposed to any processing we are really doing anywhere in 2012. We do now have a new processing contract in place for the gas at Marquis, processing through energy transfer in the LaGrange plant and also with the new lines at Palmetto, So it's going to be more of a 2013 event in terms of growth of NGLs, and Leo right now, in terms of the yield of those, I don't have a good answer for that, I'll have to research that and get back to you.

Leo Mariani - RBC

Okay, just looking at your G&A, it was up quite a bit in the fourth quarter on a cash G&A basis, kind of run in, few million bucks a quarter in 2012 that went to five million bucks. Was anything kind of unique there, maybe yearend bonuses or something like that? Where should we expect that to be in kind of the next few quarters?

Joe DeDominic

First I’d say a unique situation $5 million for the first quarter, that's not a run rate nor is it repeatable. I think within the range of our guidance that we've provided out there, we're looking at roughly $3 million a quarter in G&A and that's going to be very level loaded barring any unusual thing that we can't foresee.

And largely late last year was a combination of not accruing as our first years - full years of public company, not accruing ratably throughout the year, for yearend compensation expense for all employees, a substantial uptick in employees in the fourth quarter to handle the increased activity that we had then and foresaw. So there are lot of one time things in the fourth quarter, you are going to see at level loaded as we go up throughout this year and not at that level.

Tony Sanchez

I know it was basically Leo booked all at one time, as opposed to amortized over the year. In 2013 all of this here will be amortized out so it’s not representative of a run rate.

Leo Mariani - RBC

And in addition, I just noticed that you're gas volumes were down in the fourth quarter versus the third quarter. Your oil production is obviously up. Was there anything going on there or maybe some wells got situation where you just couldn’t sell as much gas, maybe you kind of lost some compression or something, just any thoughts you had around that.

Joe DeDominic

There is two principle drivers each going in a different direction Leo. The primary gas production starting out had been the one Haynesville shale well that we had which is well down in its production stream and its volumes are really tailing off in normal decline.

Coupled with the fact that at Marquis, in particular as we brought all those new wells on, we did not have the gas gathering facility in place for those wells. So all of that gas was flared. So it gave you a distorted percentage of oil versus gas in the fourth quarter, which with those infrastructure issues being taken care of, you won't see going forward. So I think we will be back at the traditional 85%, 86% or 87% oil and the balance gases as we roll through this year.

Operator.

Next we have Curtis Trimble of Global Hunter

Curtis Trimble- Global Hunter

I was hoping I may get a little bit more color on the difference in the completion methodology on the Prost B team number one or is it just simple pressure management that’s leading to the improved result over time on that one.

Joe DeDominic

All right, there are two factors I guess. First off, the first two wells as everyone has experienced, as they get a new area, you learn a lot on those first couple of wells. We had some operational issues on the first two wells, both running in the liner out, getting the cement job done and with the completion of the combination. So those first two wells, if you look on the report of stages in the lateral length, aren’t these great as on the 2H.

Now on the 2H it was, everything went as according to plan, And problem drilling, no problem going through the line or cement the liner, and it was a 25, 26 stage well for memory to me here, 26 stage well. So, we had a very good depletion job put way, conventional completion job and then we have as you see here and as Tony mentioned, we’ve kept it short back a little bit that’s one of the things that’s being analyzed and discussed through operators throughout the play, what’s the right choke setting and how much we open it up to not cause issues down whole. So we were a little more conservative with this well and in the future we think we’ll step it up slightly and then try and find that that light point on the efficiency frontier.

Curtis Trimble - Global Hunter

That’s been nothing significant on the mechanical changes anything like that Just a better execution on the same operation, same completion point etcetera, no highway frac type changes anything like that.

Joe DeDominic

No. No, on that why we did not. I can say that at present we are doing a few wells out there with a highway frac technology that Schlumberger and actually what we’re doing is on couple of dual pads and we have two wells at the same pad, we’re doing one with Schlumberger’s highway system and one with the conventional and we’re going to compare those two to see what performance difference we might achieve with that.

There were some tricks in the design of the individual stages that I think added to efficiency of putting the whole job of way and so we did tweak it as went across those three ways continuously, changing our prop and types and volumes and how we delivered those into the individual stages and did get more efficient, which is why you see more stages put away and subsequent wells. We want 14 stages, 17 stages, and then 26 stages.

Curtis Trimble - Global Hunter

Good deal. Drilled down a little bit on the pad drill inside, what percentage of the wells would your forecast issue being drilled on pads and then can you give me a range of expectations for wells awaiting completion or inventory if you will as we execute 2013?

Joe DeDominic

2013, we’ll have to check that another number on that on top of my head. As far as No. 1 well drilled our pads. Pretty much every well outside of few that we will be testing some of the outline areas as we discussed. There’ll be a few wells, we’re going to test some different horizons. Those will be single row pads. But everything in the Prost area, everything in Palmetto will be multi well pads.

Curtis Trimble - Global Hunter

Good any update on expectations plan on the Sanctity Well?

Joe DeDominic

As you’re probably aware the initial completion how had a lot operations issues that was maybe roughly about third of well. There was an attempted completion, it actually did flow oil at a lower rate, no water and further study of that well again showed, we believe showed some issues around the cement job, we’ve gone back looked at it in more detail, got it some third parties in there to help us look at. We have a design in place to go in there and complete the remaining two thirds of that well here actually within the next 30 days. It’s also enough to complete that well. We just have to get the frac spread out there to do that work.

Curtis Trimble - Global Hunter

And other expectations on timing for results from the northern portion of Marquis?

Joe DeDominic

We are currently in the final stages putting our plan together on exact XY where we’re going to drill those wells. We have several wells planned, both to the southeast and to the northeast of the Prost area in the Marquis acreage in addition to the completion on the Sante well. We’re going to drill a well to ourselves. We are also in discussion with other operators to potentially share some wells, to get more test in for less dollars.

Curtis Trimble - Global Hunter

This is kind of an acreage sort of basis.

Tony Sanchez

Yes in those cases and in couple of case we’re talking we’ll pool some acreage into a unit 1 unit and everyone will keep their other acreage outside that and we’ll split operations on a couple of units again to try and get you know one or two new wells, but will actually end up four wells day or something.

Joe DeDominic

Its most test for the same dollars.

Operator

And next we have Stephen Shepherd of Simmons & Company.

Stephen Shepherd - Simmons & Company

I was wondering if you could walk us through your expectations regarding the one key completion schedule. So looking at the earnings release, have been only two wells completed both in Maverick during 1Q and they’re 15 wells waiting on completions. I am just wondering, how many wells, do you all expect to bring to sales in 1Q cube area? Will there any incremental wells on top of those two?

Tony Sanchez

Yes, there will be. On the Press Release, in the lower table there where you see Marquis, where it says waiting on completion; we actually have frac spread out there right now. We have got essentially almost two wells completed and should be falling back in the next week to ten days. We have another frac spread moving in this weekend to complete two more wells and then a third frac spread moving in probably in about two to three weeks.

So, we will have several wells in Marquis falling back here middle to late in the month. That will be included in the first quarter. At Palmetto, they are prepping those wells, they start the completion practice and that’s scheduled for later this month but I won’t don’t those to be fallen back in the first quarter.

And that’s according the plan Steven, the guidance we have provided for 2013 incorporates basically this backlog that build up in the first quarter and then at the end of the fourth quarter last year and as we work our way through this backlog to bring these wells on line, that went into calculating what our 2013 guidance was based on. We track this on daily basis and we are pretty much tracking the plan on any given day.

Stephen Shepherd - Simmons & Company

Okay that’s helpful. I guess in just as a general rule, what are the factors that are determining how long these wells remain drilled but not completed? Is it infrastructure issues, is it service availability that’s causing any slowdown, or is this entirely just a kind of function of pad drilling?

Tony Sanchez

I’ll start, then turn it over to Joe. But it’s mostly a function of pad drilling. Services are really our issue, they are abundant supply I would say. So, getting our wells fracked is not an issue. The timing of when we drill and bring wells on is more of a function of getting the drilling rig off the pad and then moving the frac spreads on. So, it’s more of a function of pad drilling and how we’re able to both complete the wells and flow them back and what may be fracking offsetting those.

Joe DeDominic

And I will expand upon a little bit. On those wells you see, again on the Press Release for Marquis all those are two well pads and so again we have to get both of those drills, the rig moved off, the wells prepped, location prepped and we also went out at the first of the year and rebid all of our completion work. As you are probably aware again the market softened considerably as times progressed here, we have gotten very progressively.

As Times progressed here, we’ve gotten very competitive beds wells and seeing a reduction on the pressure pumping side to our cost for completing these wells and we are using different vendors for different wells and so we are driving our price down and trying to get better services and better results out of our wells.

And so it is a little bit of juggling there, but what we foresee, and we expect to occur as we roll into these multi well pads, as we get the two rigs rolling and they will pretty much alternate and we’ll be able to have one rig or one pad rolling off to completing those wells, or the other rigs on the other pad. We will get a good rhythm going here and we’ll have less in between. Plus our well count will increase and there will be a less ups and downs and lumpiness to our production.

Stephen Shepherd - Simmons & Company

Now that’s great and can you quantify what that service cost, renegotiation reduction was in percentage terms?

Joe DeDominic

It was on the order of 15% and again we are just talking about the pressure pumping side. As you know there is other associated services that go along with the completions also and like Tony mentioned, we are always looking at the completion design, what prop, how much prop you pump, how many stages, stage counts, spacing, all those types of things. So it’s constantly involving or we are trying to improve and tweak and improve our results and economics on these.

Stephen Shepherd - Simmons & Company

Okay and then kind of along the same line, one more if I can. What type of profit do you all use in the Eagle Ford and how much on a per stage basis are you using in each of these wells, if there is any kind of commentary you can provide to that effect.

Joe DeDominic

Yes it's all white sand. Sometime we’ll tail it with a resin or something and then on pounds per stage; we are using around 200,000 right now. Again it’s variable though and this is a conventional job with White Sand. If you go to Schlumberger’s Highway Technology it’s less per stage and that's driven by their proprietary technology they use.

Operator

Next we have Jeff Hayden of KLR Group. Please go ahead.

Jeff Hayden - KLR Group

A lot of my questions have been answered; just a couple of quick ones. Tony, just want to make sure I had it right, the acreage account you are throwing out there, does that include the additional acreage in the Prost area?

Tony Sanchez

Yes it does Jeff. We are still netting out at about 95,000 acres and this is inclusive of it. We have, as I had mentioned, traded some away in order to block out some areas. There is some acres that I would classify as more stranded acreage that we simply are just letting go. So our land department's also high grading acreage and we just happened to be still at about 95,000 net acres. But that includes the trades and some of the releases and things like that.

Jeff Hayden - KLR Group

Okay and then Mike, one for you, any color you can give us on how we should think about DD&A this year?

Mike Long

That's a very difficult one to, really to project. It's so tied to reserve ads off the wells and costs but our modeling is just to assume it's going to stay flat.

Jeff Hayden - KLR Group

Okay, kind of flat with the Q4 or flat with the year?

Mike Long

I'd say with the year.

Jeff Hayden - KLR Group

Okay, and then just one last one for me. Any thoughts about doing a Pearsall test somewhere on your acreage this year?

Tony Sanchez

Yes, I think there are thoughts right now, but it is possible. It likely would be combined with an Eagle Ford completion, where we would take the vertical section of the whole down, and core log and run some tests around the Pearsall and then come back up and land the lateral and the Eagle Ford, complete that well, take our time in analyzing and putting a plan together, but yes we do have a team that's mapping the Pearsall. We think that if it comes to fruition as a commercial play, it could be very substantial and a large portion of our acreage is perspective for Pearsall.

Operator

And next we have Mike Scialla of Stifel.

Mike Scialla - Stifel

You'd mentioned that you’ve seen some data that causes you want to drill on 60 acre spacing in both the Palmetto and the Marquis area and then you said you're planning on doing some micro size in Marquis. I guess what data have you seen in the Marquis area specifically that's led you to go to 60 acres right away?

Tony Sanchez

Yes, we, couple of things, probably three different things I guess I would talk about. One is obviously for a broader brush, you're seeing other operators in the Eagle Ford trend, talk about their spacing and what data they have. So obviously that's useful data that's both publically available and some that we gained through trades and private discussions with other operators. Two, we've seen some data close by our area which indicates somewhere between 40 to 60 acres as the right spacing. And we have incorporated in our work. And then already acquired micro seismic on one well in Marquis, and the preliminary data on that shows that 60 acres is the very conservative. We may be able to go further in that but we have to get a little more data from the 3D and the other micro-seismic well. We are going to do micro-seismic, going to incorporate all that in to feel comfortable moving out in there.

Mike Scialla - Stifel

Okay and then it sounds like that second rig when it comes to the Marquis area, is going to go right around the Prost wells, you talked about getting a rhythm there. Is that the idea at least initially for the second rig?

Tony Sanchez

Yes. Now that’s exactly the case. We are actually finishing up the title work there. We will start building up a pad, where they have a couple of pads. We will do another pad for that rig coming in and both those rigs we will be drilling there throughout the year. The other wells we talked about to the southeast and northeast, we will again be partnering with some of the operators, what we will do ourselves, we may bring in a third rig, but it will be one or two wells type of deal there to take care of that.

Mike Scialla - Stifel

And I guess where I believe I'm trying to get a handle on, how much acreage you feel confident in the Marquis area now, or you would say, okay we are going to the development mode and then are there any lease expiration issues with some of the more stranded acreage that’s further away from where you are doing the development?

Tony Sanchez

We have a lot of term left on those leases, in excess of 18 months to 24 months roughly. So we have plenty of time. We have actually laid out a development scenario for all the large contiguous blocks on that, not only from a drill it to make over those 24 months, let’s say to hold everything that we want but also to build out our gathering system, which again we’ve already got partially in place at Prost but then to connect that up with the rest of the acreage and that’s where we are working the acreage trades and acquiring some additional interest to help pile this together and it will be a very large development case that we will end up with.

Mike Scialla - Stifel

In terms of the Prost area right now, can you say what do you think that encompasses in terms of acreage?

Tony Sanchez

Well right now with the latest trade that we will have approval for, will have six drilling units in that area that will have roughly 10 wells each at the 60 acres spacing but could go down from there, again based on results of the additional micro-seismic data that we’re gathering and then also some production history to see if encounter any interference through the wells which at present time we have enough wells to say that we don’t suspect we will, but that’s a starting point.

Mike Scialla - Stifel

Then the last one for me, you said in your press release that you, based on the results you saw from the third Prost well that you’re moving your EUR up to the high end that you’re planning range. I’m just wondering if is that the same as the high end of the range of reserves that you put out in your presentation for the Marquis area which I believe was 550,000 BOE or is that a different number, because I think said Tony had said you’re feeling like this area might even as good as Palmetto.

Tony Sanchez

I think at the present time with over 90 days of production we’re comfortable with that, 550,000 number at the present time. It’s decently tracking on that range but it get it’s the third well. If you look at the history of those three wells, each well has been substantially better than the previous one and again that we continue to tweak our recipe, gets some improvements in the completions, we feel like we could see additional gains on those wells as we go forward.

Operator

Next we have Richard Tullis of Capital One Southcoast.

Richard Tullis - Capital One Southcoast

Just a couple quick questions. I apologize if some of this has been touched on already. Just looking at the well count over the year, it sounds like about 12 net wells would be online by April. Is it fair to say that the remaining say 21 net wells will come on in chunks toward the end of quarters 2, 3 and 4?

Joe DeDominic

Again, I would say because we’re going to the pad drilling, it’s going to be a low lumpy but they’re going to come on in batches of three or four at a time, and you’ll see that throughout the year but it’s going to be evenly spread in these batches through the year.

Tony Sanchez

It will come on Richard, over the next few weeks and then the internal forecast we’re working have been coming on pretty consistently throughout the year, though they are still coming on in batches.

Richard Tullis - Capital One Southcoast

Okay. How many acre spaced wells are you planning for this year?

Tony Sanchez

We’ve already not only ourselves and Marquis which we operate but with Marathon over at Palmetto, we’ve all agreed to from this point forward to drill everything on 60s. In fact some areas because of the current configuration and spacing of the wells are actually probably be drilled on 40s or 50s and again based on some of the micro-seismic we will be obtaining with Marathon and ourselves and you know the 3D and rolling all this out with some production histories, we could foresee even down spacing further but we’re just not quite there yet.

Richard Tullis - Capital One Southcoast

Okay and then just lastly, could you give the current well costs by area then, what do you think you could see by year end?

Joe DeDominic

Right now in Maverick we’re about 6 million and this is drilled complete hook up to sales. Palmetto initially we are forecasting 10 but it’s already trending under that. I would say to that 9.5 to 9.6 range and I’ll give you the current numbers and I’ll give where we’re headed to. Marquis, we’re right around 10 right now again still fairly early and then looking forward, in the Maverick area we think overtime we get down about 5 million and then both Palmetto and Marquis we see dropping to 9 or below that potentially longer term.

Tony Sanchez

Let me add to that a little bit because to put it in context, the numbers that Joe has just outlined, we’re already below the numbers that we had put out as guidance on an average well basis. So we’ve seen some cost reductions coming about fairly aggressively, in large part driven by two factors our service costs across the board coming off also operational efficiencies that we’ve been able to experience and so in either of these cases at Marquis and I think we have $10 million or so is a type well cost.

We’re already consistently coming in just below it and the plan would be that over ensuring several months and years so we could drive it to closer to 9 million. We’re seeing the same thing as Marathon drill wells much more efficiency and we have got the plan down. The biggest change I think as Joe mentioned is over in our Maverick area where our last few wells were coming in it right at 6 million and even slightly under. So I think that as we continue our development in Maverick we will be consistently hitting wells with a five handle on their cost side.

Operator

Next we have Paul Grigo of Macquarie.

Paul Grigo - Macquarie

Two quick one’s for you. First on the, Soliz #1V you guys had as an initial flow back, at least back in January in the Maverick area and I don’t see that currently. Could you give update on that where that well stands?

Joe DeDominic

Yes that was a vertical completion. Let me get that number for you? What’s your next question while I pull that number up.

Paul Grigo - Macquarie

And then the other one just a bit of a housekeeping question, where was CapEx at for fourth quarter for you guys?

Mike Long

I’ll dig that up for you.

Joe DeDominic

I’ll hit that Soliz well now. It was a vertical well, about 100 barrel a day IP rate.

Operator

The next question we have comes from Adam Michael of Miller Tabak.

Adam Michael - Miller Tabak

Wonder if we could go back to the Palmetto just for a moment. How many maps locations do you have in that Barnhart area, which kind of seems to be the sweet spot there?

Joe DeDominic

I don't have the exact count on that, but roughly if you have our account, that'd be forward 80 acres spacing. 60s to 80s is about 20% increase in the well count rough. So you can maybe look at that. But I don’t have the count on top of my head on what it is like.

Tony Sanchez

In the southern Palmetto block.

Joe DeDominic

I also lost that on top of my head.

Adam Michael - Miller Tabak

And then I believe you have a couple of wells, I think that's the 5 and the 6. The Barnhart well sort of been on for over a year, can you maybe just give an update on how those wells have performed and how they tracked versus your tight curves?

Joe DeDominic

Yes, those wells have been outstanding. I believe 5 and the 6, both have produced well over 200,000 barrels inside of a year and some of the rough data I'm looking at right now shows those wells queuing production in the year timeframe is about 250,000 barrels. One of them is actually about 260, other one is at 240. So on average between those two wells about 250,000 barrels of oil. Our current estimate in terms of EURs for one of them is over 700,000 barrels and the other is closer to 900,000 barrels of oil.

They are very stout. I will tell you the question was asked before about drilling locations on the south side of the ranch; we didn’t have it spilt out on to the south side of the ranch but as we down space, we were clearly planning on 50's and 60 acre spacing. We could ultimately see on the order of anywhere from a 115 locations to 235 locations across the asset itself. And I would say about two thirds of that is the middle and the southern part where we are seeing these very strong well results. If you take the midpoint, about a 150 wells I would say total and two thirds of those are going to be on the south side of the ranch; middle and south side of the ranch.

Adam Michael - Miller Tabak

And then another, if you put a timing about the hedging; 15% of estimated 2014 production and that's sort of implies an average production for 2014 over 16,000 barrels. I was just wondering is that a different model in (inaudible) is it kind of hold the CapEx the same as 2013, to get to that number?

Joe DeDominic

Yes that is assuming a kind of a consistent 350 million a year CapEx spending rate.

Operator

And the next question we have comes from Daren Oddenino of CK Cooper.

Daren Oddenino - CK Cooper

My questions have been answered; I thought I popped out of the queue so I apologize.

Operator

And next we have Tom Bishop of BI Research

Tom Bishop - BI Research

Just to clarify something, did you say production? What was the year-to-date production level in 2013?

Joe DeDominic

Yes, year-to-date production, average production level of about 3,800 barrels, 3,800 to date average. We ramped up into the close of 2012 and have sustained that high production rate through January and February of this year-to-date.

Tom Bishop - BI Research

Well wasn’t the exit rate 4,600? How do you get from one to the other?

Joe DeDominic

We hadn’t brought any wells online so we got this big backlog and then there is just a natural decline taking effect. Some of the wells that we brought on in mid-December, they come on high rate and over the first 30 days or so, they start to lose some of their initial production. You could see that in that table of our press release so you will see our 30 day rates and that’s the effect.

Tom Bishop - BI Research

And you are doing a lot of Pad drilling but I would think that some of these pads are becoming online, getting completed. So I’m not quite sure what's causing the backlog bulge right now.

Joe DeDominic

Actually it is all related to pad drilling. We had four rigs, run in at year end and they were drilling wells on pads that you can't get a completion crew in there while you're still drilling, you have to finish all the wells on that pad, move the rig off, then you have to prep the wells to get them to be completed, so there's just that timing shift in between those periods.

Tony Sanchez

And one of those, most of the multi well pads that we drill are two or three wells off one pad. One of those pads in Palmetto had five wells.

Joe DeDominic

Actually, you got to drill all five wells before we're moving the rig off then come back and start fracking them.

Tony Sanchez

Palmetto is a five well, 40 acre spacing pad, and then there's a three well pad, that's the eight at Palmetto and we have three two well pads at Marquis.

Tom Bishop - BI Research

And so at year end there is 15 gross and 11 net wells, and where are now, waiting on completion?

Joe DeDominic

We're actually at that, at the same.

Tony Sanchez

Now it's about 17 gross wells and 11 net wells that are already being completed. So frac spreads as of today, we've got multiple frac spreads out there, completed, working their way through this backlog.

Tom Bishop - BI Research

Okay and just to summarize, you drilled some wells and completed two and there's two that are about to start flowing before the end of the quarter, so there'll be four more wells flowing in Q1, by the end of the quarter.

Tony Sanchez

Yes, I think that's about right.

Tom Bishop - BI Research

And then the big log jam breaks up in April, is that what I hear?

Joe DeDominic

Yes, in terms of bringing them online that's correct. The work to bring them online so the frac spreads are out there now starting that work. So our plan basically has production in the first quarter basically being about flat at this level where we are now and then coming in second half of March, early April begins to ramp up, and knowing what the schedule is of wells coming on throughout the year, it's pretty smooth. So it's consistent, even though they are in batches we talked about this earlier, it's still the batches are coming on fairly consistently throughout the year.

Operator

It appears that we have no further questions at this time. We'll go ahead and conclude our Question and Answer session, I would now like to turn the conference back over to management for any closing remarks. Gentlemen.

Tony Sanchez

Just want to thank everybody for being here today and taking the time to listen and we look forward to speaking to you'll soon. Thank you.

Operator

And we thank you sir for your time, and also to the rest of management. The conference is now concluded. We thank you all for attending today’s presentation. At this time you may disconnect your lines. Thank you and take-care everyone.

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Source: Sanchez Energy CEO Discusses Q4 2012 Results - Earnings Call Transcript
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