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Call Start: 14:00

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Sanchez Energy Corporation (NYSE:SN)

Q1 2013 Earnings Call

May 08, 2013 02:00 pm ET

Executives

Antonio Sanchez – President, Chief Executive Officer

Mike Long – Chief Financial Officer, Senior Vice President

Joe DeDominic – Chief Operating Officer, Senior Vice President

Analysts

Neal Dingmann – SunTrust

Leo Mariani – RBC Capital Markets

Mike Scialla – Stifel

Stephen Shepherd – Simmons & Company

Adam Michael – Miller Tabak

Chris McDougall – Westlake Securities

Ron Mills – Johnson Rice

Dick Kendig – Keeley Asset Management

Edward Okine – Basso Capital

Operator

Good day and welcome to the Sanchez Energy Corporation’s First Quarter 2013 Earnings Conference Call. All participants will be in listen-only mode. (Operator Instructions). After today’s presentation, there will be an opportunity to ask questions. (Operator Instructions). Please note this event is being recorded.

I would now like to turn the conference over to Mike Long. Please go ahead.

Mike Long

Thank you, Chad. Good afternoon everybody. Before we start, we need to remind you that we will be making forward-looking statements within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act, 1995. Words such as will, potential, believe, estimate, intend, forecast, expect, may, should, anticipate and similar expressions are intended to identify those forward-looking statements.

Such statements are subject to a number of risks 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 forward-looking statements.

Joining me today on the call is Tony Sanchez, President and CEO, and Joe DeDominic, our Chief Operating Officer. We’ll start off with Tony Sanchez.

Tony Sanchez

Thank you, Mike. Welcome to our first quarter 2013 earnings and operations conference call. Joe and I will provide you with a brief overview of the company and our operations. After that Michael Long will review the financial results. We will then follow our prepared remarks with a short Q&A session.

We are an independent exploration and production company focused on the exploration acquisition development of oil and natural gas resources in oil-prone areas of the Eagle Ford shale trend in Texas. We own all rights to all depths and zones on the majority of our acreage, including the Eagle Ford shale, the Buda Lime Stone, the Austin Chalk and the Pearsall Shale formations, providing our acreage with upside potential through the eventual drilling of multiple pay zones beyond our current focus on the Eagle Ford.

Our current common market capitalization is approximately $660 million. And at the end of the first quarter, we had $375 million of perpetual preferred convertible stock $270 million in cash and marketable securities and only $50 million in debt. All of our current operations are based in the Eagle Ford Shale trend of South Texas, in Gonzales, Zavala, Frio, Fayette, Lavaca, Atascosa, Webb and DeWitt counties, where we have approximately 94,000 net acres in the black and volatile oil windows of the track.

We believe this acreage position ranks us as the public company with the greatest exposure to this trend, based upon net acres per $1 million of enterprise value. We continuously manage our positions within our three core areas of Maverick, Palmetto, and Marquis to create the largest possible contiguous land positions, which will enable us to focus on driving, drilling and production efficiencies.

In addition, we are constantly reviewing opportunities to our add our position or being mindful of the tremendous opportunity base we currently have. A prime example of this effort is that, during the first quarter, we increased our net acreage position in the Prost area of Marquis to approximately 7,500 net acres in a large contiguous block, which we believe will support multiple years of full scale development, optimize for several rigs, cost-effective operations and infrastructure development.

Our production for the first quarter was approximately 355,000 barrels of oil equivalent, an increase of 106% over the fourth quarter of 2012 and an increase of 320% over the same period a year ago. Revenues for the period were $30.8 million, an increase of 85% over the fourth quarter of 2012 and 303% for the same period a year ago.

During the first quarter of 2013, we spud 10 wells and brought six wells on line. To date since the end of the quarter, we have brought on line another 13 wells and have six additional wells either undergoing completion or waiting on completion. There are currently three rigs drilling, two in Palmetto and one in Marquis with an expected second rig coming into Marquis and another rig at Maverick towards the end of this month.

The operational momentum we established late last year is continuing to accelerate. We exited 2012 with outstanding reserve and production growth and that trend has continued through the first quarter as we have sustained the consistency of our drilling and completion activities.

Construction to expand takeaway capacity in our Palmetto area is complete and we expect to be selling our oil into a pipeline within the next few days. In Marquis we’re building the gathering system infrastructure to support an ongoing full scale development program in the immediate vicinity of our Prost development area.

Our operational focus this year is to drive cost and production efficiencies across all of our core areas and we are making steady progress on this front as a result of moving to larger pad drilling operations with newer efficient rigs, investing in infrastructure development to improve our margins and focusing our near term capital on a highest rate of return opportunities.

For the fiscal year 2013, our current standalone production forecast and capital spending plans called for us to drill 33.5 net wells and achieve a production exit rate of between 8,500 and 9,500 barrels of oil per day. This forecast does not include projections associated with the previously announced acquisition of the Hess Eagle Ford properties which we will now refer to as our Cotulla area and which I will get to in more detail shortly.

As recently announced in our first quarter financial release, our current standalone production rate is already in excess of 7,500 barrels of oil equivalent per day. So we are confident and reaffirm the projections set forth for the remainder of the year.

Regarding the announced acquisition of the Eagle Ford properties in the Cotulla area, we are on schedule to close the acquisition during the second quarter of this year. The Cotulla properties will add approximately 4,000 to 5,000 barrels of oil per day of production and approximately 13.4 million barrels of proved reserves.

Pro forma for these properties we expect to exit the second quarter of this year with over 12,000 barrels of oil per day of production and achieve a year-end exit rate range of 13,000 to 14,000 barrels of oil equivalent per day.

Pro forma for this acquisition, we expect to have approximately 34 million barrels of proved reserves, which consists of 21 million barrels of our standalone proved reserves plus the 13 million barrels of proved reserves associated with the acquired properties.

Upon closing of the acquisition or shortly thereafter, we will provide more detailed updated full-year capital spending and production guidance that accounts for the addition of these new properties.

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

Joe DeDominic

Thanks, Tony. Let me start with Palmetto, where we have 50% working interest with Marathon as the operator. From January 1, we have completed and brought on line nine new wells giving us a total of 25 producing wells associated with this asset.

The new wells had an average IP of 1,380 barrels of oil equivalent per day all initially flowed back on a 1,664-inch choke and the production results to date have exceeded our expectations. Five of these new wells are associated with the 40-acre pilot and those wells IPed at an average rate of 1,485 barrels of oil equivalent per day with average pressures of 3,700 PSI and no indications during the initial testing phase of any material well interference.

In addition to the non-completions, we currently have four wells waiting on completion. There are also two active drilling rigs which are now batch drilling wells on large multi-well pads, which will further reduce our overall well cost. Well costs to date have averaged just under $10 million so far this year with the latest estimates coming in below $9.5 million for our midyear forecast.

As for the processing and handling of the increased production, the central processing facility expansion is now complete and has a total capacity of 20,000 barrels of oil a day plus 30 million cubic feet of gas per day. The new oil pipeline connecting this central facility to the Marcellus sales point is also finished, it is undergoing final testing with expected to start-up, scheduled to occur later this week. Once the line of fully operational, we expect to see not only $3 per barrel decrease in our transport costs but also some improvement in our production volumes due to fewer transport disruptions.

Now, moving on to our Marquis area where we have a 100% working interest in operating. We completed and brought on line five new wells from the start of the year in the Prost area in addition to the Sante well, which is located approximately seven miles to the northeast of our Prost drilling.

The new five Prost wells had an average IP of 1,044 barrels of oil equivalent per day with choke sizes ranging from a 12/64” choke inch choke to a 16/64” chokes and these results are slightly above our forecast. Recent data indicates an early life limited drawdown approach positively impacts the long term production result of these wells.

The Sante well which was the first well drilled outside of the Prost area in the middle of last year has encountered several mechanical problems. The critical issue centers on an ineffective cement job, which resulted in our failure to effectively stimulate the Eagle Ford shale. Attempt was made to complete the well late last year without success. We’ve redesigned the completion following an internal analysis and with consultation from outside experts.

However, we are only able to stimulate three stages in the well and do not believe they were entirely effective. Despite these issues, the well flowed up to a 150 barrels of oil equivalent per day during initial testing and is currently producing 70 barrels of oil per day on artificial lift from these three limited stages. Extrapolating to a traditional 25 stage completion, we would expect an IP in line with our other wells in this area which leaves us encouraged about the future potential from this large block of acreage.

We’re currently planning to drill a minimum of two additional test in the Sante area later this year. During the first quarter, we also experienced a cementing issue on our Prost C #7H well. This was not a mechanical issue, but the result of a service company error which caused a flash setting of the cement in the well bore prior to placement of the cement.

We are currently evaluating options to remediate and complete this well. At the present time, our well cost in this area are right in line with our estimates of $10 million and a forecast of $9 million before year-end.

As Tony mentioned earlier, we have a second rig scheduled to arrive late this month and plan to keep both of those rigs active in this area for the remainder of the year.

Moving on to our Maverick area, we will spud our first well later this month on our Hauser lease which is a large 6,000 acre ranch with significant competitor activity and results in the immediate area. The well will be drilled with a vertical pilot hole to enable us to log and core the Pearsall Shale, then plug back and drilled horizontally to be completed in the Eagle Ford.

We’re also in the process of analyzing the most recent public Buda formation production results and incorporating this data into our geologic model as we have numerous leases within our Maverick area which are prospective for the Buda.

As we have previously discussed, our operational focus this year is on the effective execution of our program while continuing to drive our cost down while also increasing our margins. We are past the inflection point on our production growth curve and are making steady progress on operational efficiencies as we have transitioned to multiple well pads with tighter well spacing and have the infrastructure in place to not only maximize our sales volumes, but to do so at a lower cost. We are comfortable with our 2013 production guidance, which projects an organic increase in full-year volumes of over 400%.

I’ll now turn the call over to Mike Long.

Mike Long

Thank you, Joe. I’d like to start by emphasizing a couple of things that Tony and Joe focused upon in their remarks and then tied them to our expected financial results. By the second week of January of this 2013, we had 34 producing wells, which was a large increase year-over-year, yet it still left our production and cost metrics vulnerable to normal operational events that we all face in this industry.

Downtime on wells, infrastructure issues, or any other foreseen problems all can have a material impact on our results given that low well count. But as you just heard, we now have 49 producing wells with 6 wells in various stages of completion and an active and efficient ongoing drilling program.

Post the closing of the Cotulla acquisition, we expect we’ll have an excess of 100 wells on production. That rapidly growing base of production will earn more predictability and stability to our results. The operational gains we are reporting and forecasting, we believe will steadily translate into improving financial results as we move into the subsequent quarters.

Our press release provided substantial detail about our financial results, so I’m not going to take the time to repeat all of that information here today. But just to emphasize as Tony reported production for the first quarter in 2013, increased a 106% over the previous quarter and 320% over the same period a year ago. The average daily rate for the first quarter was 3,943 barrels of oil equivalent per day as compared to 1,281 in the previous quarter and less than 1,000 in the same period a year ago.

As Tony also mentioned, our current daily rate is now approximately 7,500 barrels of oil equivalent per day. Importantly in the press release, we have begun to provide guidance for the following quarter as well as the full year, and you can see that we are comfortably forecasting substantial quarterly production growth in the second quarter as compared to the good results we had in this most recent quarter and we believe strong increases and our cash margins will follow.

Turning specifically to the first quarter, revenues were approximately $31 million, an increase of 303% compared to $7.6 million in the period a year ago. Overall in the quarter, we’ve received an average realized price before the effect of derivatives of almost $106 per barrel of oil equivalent in the first quarter. Our net realized NGL price of $17.83 per barrel, and a net realized natural gas price of $3.37.

Realized NGL prices were negatively impacted by about $4.53 due to some late December charges from partner that we were not aware of and didn’t accrue for in 2012. 63% of our first quarter production came from Palmetto, 21% from Marquis, and 16% from the Maverick area.

We reported a net loss attributable to common shareholders of $2.1 million for the first quarter of 2013 compared to the net loss of $3 million for the comparable period a year ago. Adjusted net income attributable to common shareholders as defined in our press release was $4.3 million for the first quarter of 2013 compared to $1.4 million for the same period a year ago.

Adjusted EBITDA attributable to shareholders also defined in our press release was $17.5 million for the first quarter of 2013 versus $3.6 million a year ago.

Our hedges are comprised of a series of WTI put spreads as well as swaps as outlined in the press release. We’ve recently added to our swap position. Currently, our 2013 hedges cover approximately 50% of our estimated production from our current total proved reserves, which is the maximum amount we can hedge under our credit facilities and about a similar percentage for 2014.

These percentages do not of course reflect the expected gains in our production based in our drilling program and we expect to continue to use put spreads as only credit exposure is the upfront premium costs as a way of hedging that forecasted increase in production.

As of March 31, 2013, we had approximately $270 million in cash and $15 million in debt. Our second-lien credit agreement remains unchanged and there is no usage under the current revolver, which has $95 million of availability. We expect that revolver availability to increased to $175 million in availability at the time of the closing of the Cotulla asset purchase.

As a result, we believe we have considerable financial flexibility with low debt, a very strong cash position. The increased available borrowing base and our expectations about continued growth in our borrowing base from our ongoing drilling activities, the bulk of which are current proved undeveloped locations leaves us comfortable with our ability to sustain our growing operational and financial momentum throughout 2013 without consideration given to the pending acquisition, which is both fully financed and which we expect will result in even better access to financial resources post closing.

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

Tony Sanchez

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

The 94,000 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 the development drilling. We believe we are unique among companies our size, with our sole oil focus and our drilling inventory and net acreage position in the Eagle Ford trend.

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

Question-and-Answer Session

Operator

Certainly. We will now begin the question-and-answer session. (Operator Instructions). Our first question comes from Neal Dingmann with SunTrust.

Neal Dingmann – SunTrust

Hey, guys. This is Will filling in for Neal. Earlier in the year when you announced the acquisition, you were talking about how you – you had financing commitments for the deal later. I guess it closed in May or June. When you all look out past that, are you – how do you all feel about any additional acquisitions, would you go to look at packages or are you all more open to incremental acreage additions?

Tony Sanchez

I think our objective post this closing is to have a capital structure and financial flexibility that leaves us the ability to pursue what we think are the best uses of that capital. We have tremendous opportunities for organic growth within our drilling program. I think looking at other opportunities within the Eagle Ford is an ongoing process and part of our strategy and we continue to do that.

So it’s – it can be organic leasing, it can be increases in drilling or looking at acquisitions, but the key I think is to follow-up this acquisition with a capital structure that puts us in a position to be able to execute that entire strategy.

Neal Dingmann – SunTrust

Okay. All right. Thanks. And then I guess going to well costs and just wells in general, are you looking at extended reaches on anything? And that and also you’re talking about well costs going down in to $9.5 million estimated towards midyear, what’s the driver of that savings, is it more pad drilling or where do you get in that?

Joe DeDominic

Yeah. First off, this is Joe. We’re not drilling any extended reach well. Some of our laterals are getting a little longer both that we operate and that Marathon drills makes good investment sense to drill extra 1,000 feet if you can get it in the unit that you’ve have already built the pad and drill the vertical section inside the intermediate pipe.

So we’ll do that when we can within the unit. As far as cost reductions, there is a number of ways to get our cost lower that we’re working on. We’ve talked about the multiple well pads that obviously reduces rig moves, you share infrastructure whether it’s roads or ponds or access to materials that saves on the order of 250,000 to 500,000 of well potentially there that we’re seeing.

We’re also obtaining and learning more as we go, we’re still in relatively early days in our Prost area around well 10 on our drilling front. And so we are still seeing continuing improvement in there and we’re also getting improvements in our contracts and our services that are associated with those wells. So there is multiple ways that we’re lowering our cost, but the biggest drivers at the present time are shared pads and shared facilities.

Neal Dingmann – SunTrust

Okay. Great. Thank you.

Tony Sanchez

Thanks.

Operator

The next question comes from Leo Mariani with RBC Capital Markets.

Leo Mariani – RBC Capital Markets

Hey, guys. In terms of the Cotulla acreage which I guess not going to close for a few weeks now, have you guys firmed up any different plans in terms of attacking that. I know in the last call you guys said you’re going to do sense of due diligence on that acreage and just try to take a look to see if you guys wanted to hold any of the acreage that’s going to be expiring in the near future, just wanted to get a sense if there is an update on that?

Joe DeDominic

Yeah. Leo, this is Joe. We have been looking at it, we continue to look at it, we are working with the seller, with Hess, to extend some of those leases prior to close and – but we’re being selective on what we elect to spend our money on. And as Mike said we want to keep some power dry to do other things and so we’re choosing the right leases we feel we can develop efficiently.

Leo Mariani – RBC Capital Markets

Okay. And I guess in terms of Maverick, talk about a rig going out there, I know it’s an area you guys have pull back from, are you guys going to do a couple obligation wells this year or is it going to be a more extended program. Just wanted to a sense of what’s happening in Maverick now?

Tony Sanchez

Yeah. Right now, Leo, we’ve got the one rig coming at the end of this month versus the next month drilled which we described down through the perusal and take a good look of that. We have another follow-up well with that rig in the Maverick area and then we’re in the process of looking with the Northern Cotulla acreage and some of our leases in Maverick, what we might want to do next. We have a number of possibilities whether it’s Buda wells, whether it’s Eagle Ford and so we’re just trying to work those into our program and see what makes the best sense to drill or not drill.

Leo Mariani – RBC Capital Markets

Okay. And I guess in terms of your NGL pricing in the first quarter, you’ve talked about the prior period adjustment if I make that kind of add it back, I’m still getting about $22.36 a barrel this quarter, still seems pretty compared to peers could you guys just helps us out with what’s going on there and how they might change over time?

Mike Long

I haven’t looked specifically at peers in the region. I think all indications that we’ve been getting from marketers and outside sources we’ve talk to is a continued depression of NGL prices industry wide. I can’t comment on how we look at relative to our peers but based on our first quarter significant increase in NGL production driven by the start of processing and principally our Palmetto and Marquis areas after the marketing charges and all the costs associated with it, it’s that – as you said $22 range net of those unusual charges.

Everything I am hearing is that there is not the great upside in NGL prices coming anytime soon, but from our perspective, it is production revenue we weren’t capturing previously and now have the infrastructure and scope and place to do that and it’s additive to our revenue stream.

Leo Mariani – RBC Capital Markets

Okay. And I guess just in terms of your overall production thoughts in the year, I think you guys had said that you’d expect to exit the second quarter at over 12,000 barrels a day. And then, exit year end 2013 at 13,000 barrels to 14,000 barrels a day. Obviously you’ve been in a rapid growth mode, I mean it sounds like, just based on those numbers, they would slow a bit in the second half of the year. Am I not thinking about it right or did I hear those numbers wrong?

Tony Sanchez

Well this is Tony. The guidance we’ve given for the second quarter exit rate is simply summing the acquisition pro forma for what we expect to be a stand-alone basis. As I mentioned, we’ll be providing some updated guidance both from a capital spending perspective, as well as from a production perspective for the remaining of the year, post closing and we’ll get, so we’ll get to that. But right now, you just sum the two.

Leo Mariani – RBC Capital Markets

Okay. Thanks guys.

Operator

Our next question comes from Mike Scialla with Stifel.

Mike Scialla – Stifel

Good afternoon guys.

Tony Sanchez

Hi Mike.

Mike Scialla – Stifel

In one of your presentations earlier this year, you gave us a type curves for both 80 acre and 40 acre spacing in Palmetto. Your 40 acre type curve was lower both for EUR an IP, I think you put a 800 barrel a day type of IP rate and it looks like you’re pilot tests got almost twice of that. Realize it’s too early to forecast the EUR of on IP rate, but can you talk about the thinking that went into those numbers for the type curve, was that based on some surrounding offset operator data that you looked at or were you just being conservative there?

Mike Long

No, I think the way to look at this for this Palmetto area and some of the information that we provided is that the EURs across that acreage block vary from the north to the south and where the 40-acre pilot was drilled and that batch of wells that we brought on line in the first quarter, they were drilled in the southern part of that acreage block which is the best area, it’s the best area of the Eagle Ford.

And so those are the higher EUR numbers. The stuff to the north where we’re currently drilling very few wells right now, those are the lower EUR numbers. So the 40-acre pilot matches up with the higher EUR numbers and the IPs like we talked about earlier, actually came in better than what – a little bit better than what we expected.

Tony Sanchez

And Mike, this is Tony. I think the table you’re referring to in our corporate presentation, you might have matched up the lower EUR with the tighter acre spacing and that wasn’t meant to be. That just happen to be in the same vicinity. The table that talks about EUR ranges as Joe mentioned is based on north to south, so with the southern portion of the position being the higher EUR and progressively getting lower as you move up north has been the acreage spacing discussion, is not necessarily tied to EURs.

Michael Scialla – Stifel

Okay. So you’re not really anticipating with your 40 acres any deterioration in rates and/or EURs?

Tony Sanchez

No not at all, I can see you jumped to that conclusion there, but they should be – they are mutually exclusive.

Michael Scialla – Stifel

Got it. Okay. Thanks.

Tony Sanchez

They are not connected.

Michael Scialla – Stifel

Okay. And in your Marquis area you mentioned you are going to try a couple of more wells in the Sante area. Any other plans to drill sort of delineation-type wells within the Marquis area this year?

Tony Sanchez

Well, we’ve got two development rigs going in the immediate vicinity of the Prost and then have two to four wells planned, that would be “delineation wells” and I would – I like to highlight that Sante well, very clear now that we had some cement issues and where we’re able to get even a partial frac off.

We did produce oil and at pretty good rates and those could be extrapolated and tie almost perfectly with what we’re seeing to the Southwest in our other positions in the Prost area. So it’s highly encouraging to have been able to produce oil and to continue to produce oil out of Sante. And it also, I think the more we work with it more became evident that the problem there is the cement job around the casing and that had prohibited us from effectively completing the well.

Michael Scialla – Stifel

Okay. Maybe just to clarify on that, so it sounded like from what you said, Tony, you’re going to drill couple more wells in the Sante area and then possibly a couple more wells outside of Prost and Sante?

Tony Sanchez

Yeah. That Sante area is on the southern portion of a very large acreage block, so we’ve got a couple wells planned that I would categorize as being in and around the Sante position and then another couple wells planned that would be on a different piece of that large acreage position where the Sante is located. Does that make sense?

Michael Scialla – Stifel

Yup. Thank you.

Tony Sanchez

All right.

Operator

Our next question comes from Steven Shepherd with Simmons & Company.

Stephen Shepherd – Simmons & Company

Good morning. Good afternoon. I guess to start with – going forward what are you guys thoughts regarding the extent to which you’re willing to outspend cash flow to generate production growth. This is more of, I guess 2013 and 2014 question, is there a particular debt metric whether it’d be debt-to-EBITDA, debt-to-cap that you all will target and try to manage the business around going forward?

Mike Long

Yeah. Stephen, I think generically if you look at small and mid cap E&P companies, it’s often rare that they don’t outspend cash flow. In a development stage that we’re in, I think that’s to be expected and we would – our forecast would say we’d be outspending cash flow in 2013 and 2014.

If we simply held well count constant, took advantage of slowly increasing efficiencies such as your drill time goes down, we think we could drill more wells in 2014 with the same number of rigs than we drill in 2013. And theoretically you hold that into 2015, we can model that we would be breaking it over in terms of cash flow neutral relative to capital spending in 2015 if we have held things constant at that level.

I think again it’s our plan at using the growth in assets in production related to this acquisition to provide the financial flexibility so that we can clearly demonstrate to you that looking out, say, through 2014 we can fund that outspend of cash flow and still maintain a relatively conservative financial structure.

Generally speaking at this stage of our life, a debt-to-EBITDA number not to exceed two times is our base comfort level.

Stephen Shepherd – Simmons & Company

Yeah. That’s very helpful. Thank you. I guess next question, can you talk a little bit more in detail about specifically where in Palmetto the remaining wells in 2013 are going to be drilled. Given that, recoveries tend to get lower as you move to the north, I’m just trying to get a sense for, what your expectations are for how the wells might look or how they might trend as you move around drill on different parts of the asset this year?

Joe DeDominic

Sure. This is Joe. For 2013, the plan is with the two rigs that are on the program right now is to largely stay. For those two rigs to stay in the southern part of the acreage block to southern third to a half. And so, we should be getting similar wells to the type we had come out in the first quarter.

There will be likely a third rig potentially coming into drill a few wells in the northern part in the second half the year. We’re still fine-tuning that and discussing that with Marathon and we’ll probably have more information for you at the next call, but that will be an additional rig to handle that.

Stephen Shepherd – Simmons & Company

Okay. And then, given the start off in your NGL processing, do you expect the slope of the NGL production growth is going to change going forward and where I’m going with this is just trying to get a feel for how much of the liquid stream in 2013 might be NGLs versus black oil?

Joe DeDominic

I think you take what we generally showed in the first quarter and keep it fairly constant and project it out based on the volume growth, will be the simplest. But Mike can you add something?

Mike Long

Yeah, I think Joe that’s right and I think we were 78% – between 78% and 79%, 78% and 80% crude in the first quarter, 12% liquids and 10% oil, so 78% on crude. I think that mix is a good estimate for us on the stand-alone basis that mix can change as a result of the Cotulla asset acquisition, and we’ll have a better sense and ability to guide you toward that as we come out as Tony mentioned post the closing that acquisition with updated forecast and guidance post that time.

Stephen Shepherd – Simmons & Company

Okay. And then just for a final question if you could, what was total CapEx and drilled CapEx for the quarter?

Mike Long

Yeah. Total drilled, I don’t know. Total CapEx was about $94 million, included within that was $13.5 million of deposits on acquisitions, the bulk of that being with the Hess acquisition see around $81 million, $81.5 million in total CapEx for the quarter. I don’t have a breakdown of categories of that at this time.

Stephen Shepherd – Simmons & Company

No, that’s fine. That’s all I’ve got. Thanks guys. I appreciate it.

Operator

Mr. Magner you are live.

Joe Magner

Thanks. I just wanted to clarify, you got nine additional wells waiting on completion. Is it, are all those in Palmetto, did I hear that right or is there a breakdown between the two areas?

Mike Long

It’s actually...

Tony Sanchez

Four in Palmetto and two in Marquis, two in Prost, and three drilling. So six waiting on completions, three drilling as of today.

Joe Magner

Okay. And I just wanted to follow-up, there have been some comments about what type of capital structure you are looking to have or the flexibility you want to maintain going forward. Can you provide little more details on what the next steps might be to put that type of capital structure in place?

Tony Sanchez

I guess it’s a little early, Joe, to provide details on what those steps will be but we’ll all coincide and tie in with our plans toward the closing of the Hess acquisition.

Joe Magner

Okay. And have you all provided a breakdown on the north versus the south Palmetto and how you see it breaking down on different types of EURs?

Mike Long

Between, go ahead, Tony.

Tony Sanchez

Well, our corporate presentation that we had a discussion around few minutes ago does, we see that the range in EURs being from 450,000 to up to 750,000 barrels and I would say two thirds of it is in the kind of 500,000 to 750,000 barrel range and the northern one-third is in that 450 barrel range. And so in our corporate presentation which is on our website, we put some well economics and run sensitivities that we display and you can see how given our 450,000 barrel case is highly profitable at current oil prices.

Joe Magner

Great. And you mentioned working with Hess to extend some of the acres in the Cotulla and the surrounding areas, would you be going to provide a percentage breakdown you’d be willing to see go in or is it too early to get into that?

Mike Long

I think it’s too early right now, Joe. We are working with – our land group is working I would say through Hess and their land group to determine what acreage we want to extend and what we want to release. Much of the acreage, it’s coming up for at the end of its primary term this year and early next year has extensions on it.

And so for instance, just this week we decided on some smallest body acreage that we just simply release and not go through the expense of extending it, while we are extending some other larger acreage positions that we know we’ll be getting to or be able to get to within the next couple years from a drilling perspective. So we’re working through that right now. We don’t have firm percentages to share with you all, but I’d say a good chunk of that acreage we’re going to want to keep.

Joe Magner

Great. That’s all I have. Thanks.

Tony Sanchez

All right.

Operator

Our next question comes from Adam Michael with Miller Tabak.

Tony Sanchez

Hi, Adam.

Adam Michael – Miller Tabak

Good morning, guys. I guess do you have any data you can share on the latest five Prost wells as far as 30-day rates?

Tony Sanchez

No.

Mike Long

I’ll give some – we gave some possible averages on IPs. We haven’t provided 30 days yet.

Tony Sanchez

Most of the wells right now are still within that 30-day window. They haven’t rolled over that or crossed that 30-day yet, so we that’s why we didn’t talk about it or did release, but I will tell you that again based on those IPs, which we announced and data – production data to date, we’re like we said we are exceeding, started exceeding our model in our forecast.

Adam Michael – Miller Tabak

Okay. I guess, I just remember that third Prost well that you drilled really flattened out and that30 and 60-day rates looks really good on it. And I was wondering if that was kind of you’re seeing similar results out of the latest batch.

Tony Sanchez

Yeah. Early on, we are seeing similar rates. That well is still, still producing over 300 barrels of oil a day, flowing, so that’s a gangbuster well.

Mike Long

That’s a strong well and it’s probably made over 90,000 barrels of oil in five months or so and still going on naturally.

Adam Michael – Miller Tabak

And then, if I could ask another question. Can you give us a sense of how the Eagle Ford changes from the Palmetto to the Marquis and specifically the Prost area and the Sante area. Maybe as far as like, how deep the formation is and how thick it is and the similarities you’re seeing there?

Joe DeDominic

Well, this is Joe. It changes quite a bit across the whole trend. The area we have with Marathon and Palmetto is the best portion of the whole Eagle Ford. It’s down thrown there, it’s thicker, higher pressured, it’s some of the best Eagle Ford rock in the state. The stuff we have in Marquis, slightly deeper, we’re at 10,000, 5,000 to 11,000 foot measure depth, good pressures, but is not as thick as the Eagle Ford over at the Palmetto area.

Adam Michael – Miller Tabak

Okay. And does that hold on through up into the Northeast like the Sante area?

Joe DeDominic

Yes, it does. The Sante depth wise is just maybe a couple of hundred feet deeper than what we’re drilling at Prost the structure, rather than running east, west there, the structure has turned and comes up towards as we started heading up to the east Texas basin. And so the structure is more northeast, south, southwest trending in that area for the Eagle Ford. And so the structure again, as you move East, it gets a little deeper and but geologically with similar thicknesses.

Tony Sanchez

Adam, this is Tony, I’d like to highlight something that we’ve spoken about previously in conferences and stuff. In just for comparison purposes, when you look at our Palmetto area, sort of averaging out north to south and the different ratios we see of the EURs. You’re in somewhere in between 500,000 to 600,000 barrel EURs average. So averaging those big wells on the south would be 400,000 barrel, 450,000 barrel, ones on the north you end up with just ballparking it, 500,000 to 550,000 blended EURs.

And there we’ve got about 9,700 net acres and so from a valuation perspective we like to highlight just our Prost area where we’ve got 7,500 net acres, so almost as big as Palmetto and 100% working interest. Wells granted were in the first – the early stages of them, but they are tracking that 500,000 barrel plus EUR-type curve. So from a valuation perspective, we’ve already proved up an area that they should be having basically almost the same valuation as Palmetto. So I think we’ve already replicated that once and we’re continuing to march our way out.

Adam Michael – Miller Tabak

Okay. That’s great. And if could, one last question, it sounds like you’re going to take a core to drill vertical well down into the Pearsall and over in the Maverick, do you have any updates on – I think you said that you had a stealth play of about 4,000 acres you had put together. Have you added any acreage in the Pearsall and in any tests, upcoming tests on another properties?

Mike Long

We’ve talked about the test we’re planning. I don’t think there is much stealth in it. We’re adding the 40,000 acres or so via the Hess acquisition or Cotulla. Every bid – everyone of those acreage is prospective for Pearsall. And that’s the thick part of the Pearsall. So I think we’ve taken a pretty big step in that direction when it comes to setting ourselves up for benefiting from the Pearsall, should it be a play that, that becomes commercial in large quantities. So, we added some acreage early on, few quarters ago, but the big one recently is that Cotulla area.

Adam Michael – Miller Tabak

Okay, guys. Thanks a lot.

Tony Sanchez

Thank you.

Mike Long

Thank you.

Operator

Our next question comes from Chris McDougall with Westlake Securities.

Chris McDougall – Westlake Securities

Hello, guys. Thanks for the update. A few questions, just on, you had mentioned some pipeline infrastructure getting hooked up, and I was curious what sort of uplift we should see either in oil pricing or in a reduction to the transportation cost. And if that will become a noticeable at corporate level or if it’s still down just at the field level?

Tony Sanchez

I’ll address the oil for a second here. Yeah, it should be very noticeable. This is, this is an – there is an enterprise line that runs across our Palmetto asset. It ties into enterprise’s marshal complex facility about 8 miles to the northeast. For bashing efficiencies and being able to flow oil at a consistent rate, we decided to basically twin that pipeline. So Marathon and us are sharing the cost 50-50, that Marathon is, I mean that pipeline is already in place. We should be tied in selling oil through the pipeline within the next few days.

Chris McDougall – Westlake Securities

Great.

Tony Sanchez

What that pipeline will do is, it will give us an up charge. It will increase our netbacks by anywhere from $2.50 to $3, so the pipeline itself costs about $7 million, we’ve got half. And when we ran the numbers early on, of the top of my head, I remember that investment itself paying out inside of eight months or so. So it’s hugely beneficial to us, we’re already getting a premium for our well, but we’re going to get more of a premium in that area.

Chris McDougall – Westlake Securities

Great.

Tony Sanchez

And more importantly, I think we’ve cleared some of the takeaway bottlenecks that we had to deal with second half of last year.

Chris McDougall – Westlake Securities

Okay, great. Well, thanks for clarifying that. And then on the NGLs, you had talked before about the pricing and I was curious what the split was between ethane, propane and kind of everything else – if you just kind of have a representative split because then I could just model that off of the prices with those?

Mike Long

Yeah. Unfortunately I don’t have that information available, but we’ll try and – I mean, shoot me an email and I’ll try to respond back.

Tony Sanchez

And fundamentally speaking, those revenues weren’t showing up in our financial statement for the most part, some of them were unable to show.

Chris McDougall – Westlake Securities

Yeah. No, I get that it’s some additive if I was just thinking going forward, but I’ll shoot you an email on that. And then lastly on the down spacing, you mentioned that in these initial tests you weren’t seeing any interference or communication between the wells and I wanted to just get a better sense of how you plan on evaluating that going forward. Do you have any tracer chemicals or any other ways to do it or is it through pressure or what’s your plan?

Tony Sanchez

Well, first off all the wells on the – five wells in the 40-acre pilot microcosmic data was gathered on those wells.

Chris McDougall – Westlake Securities

Okay.

Tony Sanchez

And so that’s in processing and so you’ll have an idea from that work on how far those fracs extended from the well bore and did you have interference with those from that imaging? You also over time will see – we didn’t trace it, but you’ll see if there are some similarities or declines that seem to be interfering with between the wells. You’ll be able to see that in your production history of your wells.

Chris McDougall – Westlake Securities

Okay, great. Thanks.

Tony Sanchez

Yeah.

Operator

Next question comes from Don Crist with Johnson Rice.

Ron Mills – Johnson Rice

Hey, guys. It’s Ron. How are you? Tony, you just answered one of my major questions was on the relative Marquis versus our Prost versus Palmetto, with the higher working interest. It is as meaningful to you as Palmetto is. I know you’re at plus or minus 7,500 acres there. You’ve recently added some. Is there more acreage to pick up in that area and when you look at the performance of those wells they seem to be tracking more in line with what the Southern Palmetto wells have been doing well and too much into the early results or do you think that’s a fair statement because that would be fairly additive as well.

Tony Sanchez

Yeah. I mean it is the point is really to kind of highlight how additive it is. We are – Ron, we’re continuing to add acreage in small bits where we can get it. That part of the trend is, is comprised of some very small ranches and farms and so it really takes a lot of – a lot of land, leg work to put it together. But now that we’ve got some position of scale, we continue to add to it and to be opportunistic. So that’s your first question.

I would say on average, yes, that the wells coming out of Marquis, particularly our Prost area are tracking what would be a blended average EUR for our Palmetto position. But keep in the mind that the wells on the southern end of Palmetto are outstanding, I mean, some of those are tracking in excess of our high case in terms of EUR which is 750,000 barrels. We had a couple that are north of that already. So while those are world class wells I would say my comment earlier about Prost, it’s to be compared to the average Palmetto blended, not necessarily the big huge wells on the southern end.

Ron Mills – Johnson Rice

And then maybe Joe, for you, I don’t know if it’s you or Tony, but the 5-acre – I mean, the 5-well, 40-acre pilot, you’ve talked about a little bit, is that going to be all you in Marathon plan on doing from a 40-acre testing standpoint? I saw in there – Terry, they talked about at least 80 acres and continuing to test 40 acres and 60 acres. Just curious how the conversations are going with Marathon on that?

Joe DeDominic

Sure, Ron. This is Joe. Yeah, our conversations and discussions with Marathon earlier this year, we all want to see the results of the 40-acre pilot, but we were both of the opinion that given data along the trend and the data we’ve seen within Palmetto warranted a tighter spacing than the 80s. And so what we had concluded jointly was that it made sense to go ahead and proceed to tighten the spacing up across initially the whole southern portion because that’s what our focus is right now.

Two, effectively it will be 50-acre spacing as of today and that’s due to the fact that some of the leases in the way units are formed, you can’t lay everything in their perfectly on a 40-acre spacing. And so you’re sometimes spaced that a little broader as you take the amount of acreage divided by number of wells and effectively ends up being about 50-acre spacing and that’s the current execution and planning and wells that are being drilled are based on that.

Ron Mills – Johnson Rice

Okay. And then, Tony, when you closed this acquisition it sounds like you plan on updating CapEx/drilling activity in everything relative to your discussions after the Cotulla acquisition was announced. Is that going to be centered not just on Cotulla but also I know you all have been – you have Marathon have talked about the relative quality of Palmetto. Is this going to be a total capital program evaluation?

Tony Sanchez

Yeah. We’re going to provide a total capital program update. When we – after we close the Cotulla. So we use that opportunity to give a fresh capital budget and production forecast for the remainder of the year.

Ron Mills – Johnson Rice

And then lastly just price the production level, your current one plus where you think to be at the end of the second quarter with Cotulla seems to be a little bit higher than I would have thought, is that just due to some fresh production or is there also some opportunity here where the year-end exit rates that you provided with the two acquisition also have some upside to the extent you continue to seek comparable reserves?

Tony Sanchez

I think they are both, Ron. I think that it’s a combination of some of our wells have been outperforming. There is some flush production built into our current stated production rates, but as we’ve been drilling so actively there’s always going to be flush production incorporated in there. So we’re at 7,500 right now, probably even little bit north of that today.

So, but the wells that we brought on last week are going to be drop and off, but then we will bring some new wells in. I’d say fundamentally speaking, I am very happy with the way the wells have been holding up. They have been tracking their declines like we had expected and in some cases doing a little bit better. We have been doing some testing. So, we’ll take two wells off the same pad and frac them differently. For instance we use a – highway frac job on one well. And the next well will frac with a conventional hybrid job and watch the performance. So there is some of that going on, but for the most part I’d say that our production teams are doing really good job of managing the wells as they do down on the decline curves.

Our operations teams have been really firing on all cylinders. We’ve been bringing on some new people that are very experienced and talented and are able to really drill these wells faster and more efficiently than we had in the past. So, yeah, any given point in time, some of the production in any given number is going to be a flush component but also I think our teams have been doing a really good job of managing the well performance.

Joe DeDominic

Okay. Ron, this is Joe. I’ll add one last thing what Tony just said. In the first quarter we had that one well in the Prost C #7H which had the cement set prematurely, I mean, that’s a well that we expected to have completed and producing online. So we’re actually one well less as far as our productions numbers are too so that our numbers are shaved a little bit into that too. We’ll get that remedied and by producing at some point here, but that gives you an idea where we think our production is too.

Tony Sanchez

So we track it day-to-day and we’re a little bit ahead of where we would have expected to be and that’s with less one well, and that wasn’t entirely due to a service company error where the cement that was being pumped down on the well board to set the casing literally flash that inside the casing itself. So if we didn’t – we couldn’t get it set. So we’re one well behind on a well count where we would have expected to be, but our production is ahead. So we’re in good shape.

Ron Mills – Johnson Rice

Perfect. Thank you guys.

Tony Sanchez

Yeah. Thanks, Ron.

Operator

(Operator Instructions). We do have a question from Dick Kendig with Keeley Asset Management.

Dick Kendig – Keeley Asset Management

Good afternoon, gentlemen. On that well that was screwed up on the cement job, who pays for that?

Tony Sanchez

We’re in discussion with the service company right now and that’s actually a meeting I had this morning. And the direction it’s headed, they’re going to be paying for it. At the same time...

Dick Kendig – Keeley Asset Management

The whole well cost because I mean if it’s set inside the casing...

Tony Sanchez

Yeah.

Dick Kendig – Keeley Asset Management

You can’t do anything with it.

Tony Sanchez

Yeah. We’ll actually what we were able to do, we were able to drill a good amount of that cement out. So what I think and I talked to Joe and our drilling guys this morning, the likely outcome for that well is that we’re going to sidetrack it because we’ve got surface casing, intermediate casing set, and the integrity there is good, it’s fine. So that part’s not wasted. We’ll probably just side track from under there and twin the well lateral and then go to the service company, we’re doing that now.

And they have already admitted that it was literally a chemical mix-up on their part at the surface. They pumped the cement and it set inside the casing itself. There is a little bit of the initial scavenger cement, they got around the casing. But they said, it was their fault. It all has to documented and there is a process to go through. But essentially they’re going to be paying the bulk of the cost. What we’re discussing right now is how to expedite catching ourselves up with that one well.

Dick Kendig – Keeley Asset Management

Well, I would think that they would also have to pay, while you drill out the cement and when you sidetrack until you get into kind of open territory. I mean that’s a big part of cost of that well I would think.

Tony Sanchez

Yeah. Well, Dick, we’re still – like I said, we’re still working with these guys. On the immediately after it happened, they took over the cost of the well. They didn’t even argue with it. So I said, while the rig was still on there, while we’re drilling out some of the cement that hit set, all that was on them. And so they have taken a very cooperative approach but I think you can rest assure that we’re going to be pretty aggressive in getting ourselves made whole.

Dick Kendig – Keeley Asset Management

Tony, don’t forget about loss business or business interruption costs either.

Tony Sanchez

I am not worried.

Dick Kendig – Keeley Asset Management

Okay.

Tony Sanchez

I pretty worked up about it.

Dick Kendig – Keeley Asset Management

Okay. Thanks.

Tony Sanchez

Bye.

Operator

Next question is from Edward Okine with Basso Capital.

Edward Okine – Basso Capital

Yes. You had mentioned that you’ll not spend for this year and next year and intent to be cash flow neutral in 2015. I’m just trying to get some parameters around it. At the moment, you have about $274 million of cash and your revolver line is about $250 million, I believe. Can you give any indications if whether you’re outspending is going to fall between those two tranches with our cash and your revolver. Is there a possibility of going beyond that?

Tony Sanchez

Well, I think first you have recognize the first significant use of cash for us will be to fund the closing of the Cotulla area assets, that will take place in late May. Beyond that, I think it would best for us to hold and talk about where the new program post the closing of that as we’ve talked about within our forecast coming out which would be at some point in June as we move forward.

But it’s excluding that acquisition based on the drilling program we have and the ramp that we are forecasting and expecting in our production, it is I think expected that we would be outspending our cash flow for the next 12 to 18 months and then as I mentioned it’d be clear if we held that program constant would cross over in 2015. In terms of any specifics around what we forecast to be cash flow from operations, production on a longer basis going forward, we need to get beyond the closing of that acquisition come back with our revised new company if you will capital budget program. More to come probably mid June on that.

Edward Okine – Basso Capital

Okay. Thank you.

Operator

There appears to be no further questions at this time, so I’d like to turn the conference back over to management for any closing remarks.

Tony Sanchez

I just want to thank everybody for joining us today and listening and for some very good questions. Everybody have a good afternoon. Thank you.

Operator

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

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