Sanchez Energy's CEO Discusses Q4 2013 Results - Earnings Call Transcript

Mar. 6.14 | About: Sanchez Energy (SN)

Sanchez Energy Corporation (NYSE:SN)

Q4 2013 Earnings Conference Call

March 6, 2014 2:00 PM ET

Executives

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

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

Christopher D. Heinson – Chief Operating Officer

Analysts

Neal D. Dingmann – SunTrust Robinson Humphrey

Ben Wyatt – Stephens, Inc.

Leo Mariani – RBC Capital Markets

Stephen P. Shepherd – Simmons & Co. International

Chad L. Mabry – MLV & Co. LLC

Steve F. Berman – Canaccord Genuity, Inc.

Dan E. McSpirit – BMO Capital Markets

Tom Bishop – BI Research

Phillips Johnston – Capital One Southcoast

Curtis Trimble – Global Hunter Securities

Operator

Good afternoon and welcome to the Sanchez Energy Fourth Quarter Earnings 2014 conference call. All participants will be in a listen-only mode. (Operator Instructions). Please note this event is been recorded.

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

Michael G. Long

Thank you, Emely and good afternoon everybody. Before we start, I’d like to once again advise you that we will be making forward-looking statements within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. Words such as will, potential, believe, estimate, intend, expect, may, and similar expressions are intended to identify those forward-looking statements.

Such statements are subject to a number of assumptions, risks, and uncertainties, many of which will be beyond our control and may cause our actual results to materially differ from those in the forward-looking statements.

With that, joining me as presenters on the call today are Tony Sanchez, our President and CEO; and Chris Heinson, our Senior Vice President and Chief Operating Officer. I will now hand the call over to Tony for our introductory comments.

Antonio R. Sanchez, III

Thank you, Mike. I would like to first announce that Chris Heinson, who was appointed interim Chief Operating Officer in December has been elected Senior Vice President and Chief Operating Officer effective March 4. He will provide a detailed discussion on operations and will then followed by Mike Long, our CFO who will discuss some of the key financial points.

The fourth quarter and full year 2013 were records for the company on a variety of fronts. In the fourth quarter, total production was over 1.7 million barrels of oil equivalent, an increase of 60% over the third quarter of 2013 and an increase of 904% over the same period a year ago.

Production for the full year came in at over 3.8 million barrels of oil equivalent, an increase of 726% over calendar 2012. Revenues for the fourth quarter were $130.1 million, an increase of 38% over the third quarter of 2013 and an increase of 679% over the same period a year-ago. Revenues for the full year came in at a record $314.4 million, an increase of 629% over calendar year 2013.

Proved reserves increased dramatically throughout the year to 58.7 million barrels of oil equivalent or 177% over the previous year, which had finished at 21.2 million barrels of oil equivalent. The PV-10 value of the reserves at year-end 2013 was $1.47 billion compared to $360 million at year-end 2012. The reserves growth in 2013 was driven roughly 60% through organic operations and 40% through acquisitions. This growth in production reserves was achieved while maintaining a strong and stable balance sheet characterized by ample liquidity.

Effective February 28, 2014, our borrowing basis increased to $400 million, but we elected to keep the commitment at $325 million. However, we have the ability to increase the elected commitment up to $400 million should we determine it is appropriate to do so. This increase in our borrowing base is a result of our strong reserves growth as well as the increased percentage of proved producing reserves as part of the total reserves mix.

The increased borrowing base, which at this time is completely undrawn combined with year-end cash balances of over $150 million positioned the company with substantial liquidity from which to fund its continued growth. Moving on to some operations highlights. We have experienced a substantial reduction in our drilling and completion costs across all of our areas, but especially on operated assets of Marquis and Cotulla. Driving these reductions, which Chris will get into more detail shortly, is the usage of large multi-well pads and zipper-fracs wherever possible.

The consistency afforded these types of operations has translated into steadily reducing costs on the pressure pumping side as well as on the drilling of the wells, which we are now consistently drilling wells much faster than before. An example of this is in our Cotulla area, where on Alexander Ranch, we are now drilling wells, spud to TD in less than 10 days. From a total cost perspective, these wells are coming in right at about $6 million.

To give you some perspective, when we valued the Cotulla asset last year in preparation for a bid, we were targeting $7.5 million, and actual costs at that time incurred by the previous operator were closer to $9 million. This same trend is occurring in Marquis, and now that we are drilling on our newly acquired Wycross Assets, we would expect the same cost reduction to drive an increase in individual well rates of return.

Overall, this is certainly a positive development at the company as we not only continued to drive capital efficiency, but that capital efficiency and low cost structure makes previously marginally economic areas now more viable, thus organically increasing the inventory of higher rate of return drilling opportunities.

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

Christopher D. Heinson

Thanks Tony. I’ll start by providing a brief overview of our accomplishments for the fourth quarter before giving additional details around each operational area. For the fourth quarter, we drilled a total of 27 wells, 15 operated and 12 non-operated; and completed 29 wells, 16 operated and 13 non-operated, which is higher than originally anticipated due to decreases in drill times.

Sustained development across our operated assets has yielded significant improvements in efficiency and further decreases in drilling and completion costs. We have now achieved a 25% reduction in drilling costs in the fourth quarter, as compared to the first quarter of 2013, a substantial improvement over the 10% reduction we cited last quarter. We have also achieved major reduction in completion costs as a result of routinely utilizing zipper fracs on our multi-well pads. Completion costs have decreased 35% beginning in the fourth quarter as compared to the third quarter of 2013.

Total drilling and completion costs in Cotulla have decreased from $9 million per well prior to our assumption of operation to approximately $6 million per well in the fourth quarter. In the Alexander Ranch asset, drilling costs continued to decrease due to improved efficiencies around rig moves. Recently, we pumped between 12 stages and 14 stages per day on zipper frac operations in Alexander Ranch. Job sizes were similar to Q3 designs, but due to increased efficiency we reduced the cost from $120,000 per stage to $90,000 per stage.

White paper designs yielded a maximum efficiency of between 13 stages and 14 stages per day, so the team is operating close to maximum efficiency in this area. In the Prost asset, a more technically challenging area of play, costs have decreased from the range of $11 million to $14 million during the initial appraisal phase to approximately $8.5 million during the fourth quarter.

Drilling efficiency has come from a number of process changes including rig moves, well head changes, and curve building. The costs incurred by our three-stream program is beginning to be offset by some of the efficiency gains around utilizing oil based mud in the intermediate section, which is proving more effective at dispersing soft, sticky play and treating solid.

Additionally, we’ve been able to emulate the curve building performance of rotary steerable systems with the conventional system and are now seeing incremental savings in the curve as we utilize high-speed and high-torque motors.

On completions, the realized savings has been strictly around zipper fracking, although we have seen a 10% to 15% lower market crisis for pressure pumping services in January. Our ability to make step changes in efficiency and challenging areas will continue to be important as we prepare for our first operated wells in the TMS, which we expect to spud in early May.

Going into 2014, we took additional steps to modernize our rig fleet. We now have two out of our four long-term contracted Eagle Ford rigs equipped with 7500 PSI mud system. Additionally, three of these that have the ability to walk in both the x and y directions.

These types of systems are defining a modern rig. We expect to continue to see the benefits as development continues. Our drilling and completion cost structure is now clearly top quartile and is established and is the result of establishing a culture of technical excellence with manufacturing efficiency.

Reserve growth was strong in the fourth quarter, a result of successful step-out programs at Wycross and Marquis where we were able to add an additional 6 million barrels of oil equivalent from extensions. In addition to our extension work, we implemented 40-acre pilots in Palmetto, Wycross, and our Alexander Ranch assets. Results from all three of these pilots are good, and we have altered development plans in all three areas of 40-acre well space.

It should be noted that although we’ve adjusted our development plans, our undeveloped reserve bookings will continue to be based on 60-acre spacing until we have adequate production history to provide reasonable certainty around the reserves associated with 40-acre performance. Expanding on our appraisal work in Marque, as previously announced, we’ve had success expanding Prost asset to the south.

The first appraisal well in the Prost D, E, F, G, and H units have all come in at or above our Prost-type curve expectations. In our Five Mile Creek asset, we are drilling the second well of our inaugural four-well pad in the area with zipper completion scheduled for May. Further Northeast in the Sante north unit, we’ve drilled a pilot hole, taken core and logs, and landed a well in the lower Eagle Ford. After completion, we encountered obstructions during flood drill out.

Decision was then made to produce from a partially open well. We filed the report with the railroad commission for this well based on initial test data and provided subsequent clarification on the status of the lateral during the test. We were encouraged by the initial flow test and have recently drilled out the remaining plugs and are cleaning up the well bore and are in the process of testing the full lateral contribution from the Sante North well now.

The pilot in Sante North is part of a greater program in the Marque region. We now have pilot wells in core from the Crab Ranch, which is part of Five Mile Creek. Sante North, Prost G and Prost H, G, and F. These wells are supplying our geotechnical staff with the data on the potential of the true of the lower Eagle Ford as well as the upper Eagle Ford across our Marque position. We are targeting the test of upper Eagle Ford as well as additional test of the Sante area in the third and fourth quarters of 2014.

During the fourth quarter, we experienced a higher than average number of wells that were completed due to shorter drilling times, resulting in a higher exit rate in quarterly numbers exceeding the high-end of our outlook production. Exit rate for the year-end 2013 peaked at about 20,000 barrels of oil equivalent per day as a result of a large number of completions in December.

One of the results of the variability and completion timing associated with large scale implementation of multi-well pad is that we’ve had no completions in January and very few in February. Additionally, we’ve experienced multiple periods of cold weather, which has increase downtime and maintenance in the current quarter. During the first quarter, Gulf Coast weather, particularly fog, has impacted barge and inner coastal traffic, tanker traffic, causing shortage -- storage facilities to backup.

We've experienced periods where our crude could not be marketed due to temporary receiving facility bottlenecks, which have now largely been cleared. Production in January averaged approximately at the same level as our actual production average for the fourth quarter of 2013.

We continued to expect our first quarter 2014 production to come in within the range of our guidance, while recognizing that actual full quarter results to be up at the lower end of the range given the timing issues associated with pad drilling and the weather related issues I mentioned above. The completion activity is now picking up again in March, as a result of the buildup of 14 wells drilled and waiting to be fracked.

I’ll now turn the call over Mike.

Michael G. Long

Thanks Chris. We ended 2013 with a $154 million of cash and a totally unused bank revolver with a $300 million available borrowing base. As Tony mentioned last week, we completed a regular scheduled borrowing base redetermination. Our bank group approved a new borrowing base of $400 million. We chose to institute an elected commitment amount of $325 million, due primarily to a lack of anticipated need for anywhere near that $400 million level.

Although, also as Tony mentioned, if the situation were to arise where we quickly needed to increase the facility, it would be available to us in very short order.

Our cash balances at the end of February were approximately $105 million such that we continue to have very strong levels of liquidity with our capital budget for 2014 very comfortably funded with an expectation of steadily improving credit metrics.

As an evidence of this on March 4, two days ago, S&P announced an upgrade to our corporate and senior note ratings for a corporate credit rating of single B and a senior unsecured note rating of B-.

We have not deviated from our strategy of keeping total debt to EBITDA in the two times range, and we believe the ratings changes reflected both the progress we’ve made over past year and this adherence to the strong financial management policy. Production for the fourth quarter averaged 18,100 barrels of oil equivalent per day, before some positive prior period adjustments, which increased our reported rate to [18,800] (ph) a day. That number compares to the previous quarter’s rate of 11,800 per day.

Contributing to the rate, which exceeded our guidance, as Chris mentioned, was the fact that we were able to accelerate the completion of several wells originally planned for early 2014 into 2013.

Revenues for the first quarter increased 38% to $130.1 million, that increase compared was 38% compared to the previous quarter despite the fact that oil prices averaged the lowest level for any quarter during 2013 with an average realized price of $93.85 per barrel of oil. Oil prices averaged in excess of $100 per barrel in each of the previous 2013 quarters.

Overall, we received an average realized price before the effect of derivatives of $93.85 per barrel of oil in the fourth quarter. A net realized NGL price of $30.62 per barrel and a net realized natural gas price of $3.14 per Mcf, which is also the lowest price per quarter for all of 2013.

All of that equates to an average realized price of 75.18 per barrel of oil equivalent. Our hedges reduced our effective prices during the fourth quarter by $1.81 per BOE. $0.95 of that was related to cash settlements with the balance related to non-cash mark-to-market changes in our portfolio of hedges.

34% of our fourth quarter production and revenue came from Palmetto, 22% and 24% respectively came from Marque, 45% and 43% from our Couttella-Maverick area.

In the fourth quarter, our reported production stream was 73% crude oil, 14% natural gas, and 13% NGLs. Normalizing for the prior period adjustments, the actual percentage were 75% crude, 14% natural gas, and 11% NGLs.

Adjusted net income attributable to common stockholders as defined in our press release was $11.5 million for the fourth quarter of 2013 and $33.2 million for the full year. Full-year 2012 adjusted net income was $7.3 million. Adjusted EBITDA attributable to common stockholders as also defined in our press release was $98.6 million for the fourth quarter of 2013. That compares to $63.8 million for the immediately preceding quarter and the full-year 2013 EBITDA was $226.7 million compared to $25.6 million for 2012.

The significant non-cash items impacting our P&L during this quarter and the full year were mark-to-market losses on derivatives of $1.5 million for the quarter and $8.3 million for the full year as well as non-cash stock compensation expense of $3.4 million for the quarter and $17.8 million for the full year.

Our effective tax rate for 2013 was 12.91% compared to the statutory rate of 35%. This reduced rate for 2013 was primarily the result of the release of our valuation allowance affecting the third quarter. We expect our effective tax rate in 2014 to be approximately 35%, all deferred.

At year-end 2013, we had a net operating loss carry forward of $480 million, and those losses begin to expire in 2031.

We’ve steadily improved our cash operating margin over the course of 2013. Our cash operating expenses, defined as lease operating and marketing expenses, production, and ad valorem and cash G&A by quarter this year were $26.18 per BOE in the first quarter, $21.56 in the second quarter, $22.89 in the third quarter, and $17.23 in the fourth quarter. The full-year 2013 cash operating expense was $20.41 per BOE; this compares to the full-year 2012 level of $36.74.

Finally, we’ve reported operating capital spending for the fourth quarter of $186 million, including estimated accruals for activity and progress as well as acquisition costs of $220 million. For the full year, capital spending before acquisitions was approximately $541 million and acquisition spending was approximately $630 million.

Our cash flow statement will report actual full year 2013 capital spending of $480 million before the accrual adjustments in acquisitions. The increase over our budget forecast of $470 million was largely due to well completions finished in 2013 that were planned in early 2014.

Currently, we have about 4 million barrels of oil equivalent hedged for 2014 or approximately 50% of our middle of guidance forecast. The details of our current hedges are shown in the press release. Finally, in early 2014, we completed transactions with certain holders of our Series A and Series B perpetual convertible preferred stock, whereby we exchanged our common stock for 947,490 shares of Series A preferred and 756,850 shares of our Series B preferred, plus any accrued unpaid future dividends.

The net result is reduction in the par value of outstanding Series A preferred to $103 million and Series B preferred to $187 million, and a reductions to the annual dividends payable of about $4.8 million.

With that operator, we are ready to open up the call for questions from the audience.

Question-and-Answer-Session

Operator

Thank you. We will now begin the question-and-answer-Session (Operator Instructions) your first question comes from Neal Dingmann of SunTrust. Please go ahead.

Neal D. Dingmann – SunTrust Robinson Humphrey

Hi, good afternoon guys. One just quick question, I was trying to drill down on the efficiency a little bit, yes, you guys gave a good outline of what happens on your quicker drilling days and then obviously on just the cost in general, sort of I am trying to get a sense of just overall when you look at the efficiencies what that can do to just your economics as far as what that means to you not having to bringing that rig in, so I am trying to get a sense of two things; one, production, you obviously had the guidance out there, how much upside potential on that, and then two, just sort of the cost of economics in general with your efficiencies?

Antonio R. Sanchez, III

Yes, this is Tony. I think there is a lot of factors that play in and effects the question you asked. So follow-up, if I didn’t answer directly but, basically we’re getting a big improvement on the drill side and spud to TD, which means in the fourth quarter for instance, we brought forward several wells that we were expecting to complete in January 20, 2014.

So, overall the effect, it does have quite a bit of effect on timing, which will translate into some lumpiness in production as we bring more wells on sooner, but the trend should continue in an upward direction probably at the same rate of increase over multi-quarter period.

The main effect though that we have that we are experiencing is on absolute cost per well. We are able to amortize some of the larger costs over a series of wells, we are able to save directly on drill days per well on the drilling side and then we’ve seen pressure pumping price cost come in some. Some of that is the effect of the dynamics of the pressure pumping market, but other areas are ability to keep those spreads busy and commit to a more study profile of completion job.

So, we have been able to negotiate more favorable pricing on that side. All-in-all, it’s led to less mistakes, less downtime and more consistency as you have seen it on the drilling side and then putting away the frac stages on the completion side.

So, the net effect is the fairly sizeable decrease in cost on the order of 30% plus in these areas, where we are now development drilling. So what that means is keeping the well performance about the same, it’s not increasing, it’s slightly the net effect on rate of returns on a per well basis is very positive.

So, as I mentioned, it does add more inventory that previously, we probably wouldn’t have gotten to under the previous cost scheme. So, kind of the long-winded answer. Does that address your question?

Neal D. Dingmann – SunTrust Robinson Humphrey

No. That answers it. That's what I was getting it. Just two quick ones Tony; one, just on M&A either in the Eagle Ford or other areas, lastly, you are pretty active. Just in comparison how does that look out there for you, you have done a lot of this in your background, how does it look today versus kind of last year before as there were many deals out there?

Antonio R. Sanchez, III

No, I think there are significantly less deals out there now than there was a year ago. We make it a practice to look at packages as they come up whether they are publicly marketed or privately shopped. A lot of good comes from that. We are able to benchmark ourselves how well people are doing and then keep an eye out for good opportunities, but I think it’s clear that the inventory of available deals is certainly lower today than it was a year ago. It feels like this particular basin is going through its cycles and there is just not a lot of deals out there right now that are very appealing. But we are always looking at some stuff. So it’s definitely on the low end of its cycle in terms of volume.

Neal D. Dingmann – SunTrust Robinson Humphrey

Okay, then lastly, I know that TMS is still few months away, just your thoughts as far as two things there, one are you participating near-term in some of these wells, I forget it. And number two, on your wells you have coming after six months down the road, is it too early as you already determined as far as how you want to drill it below the levels now and how you want to try to frac it or complete it? Have you guys started looking at [matters] that still kind of in the process?

Antonio R. Sanchez, III

It’s definitely in the process, Chris, can give you more details here, but it’s always in the process. I mean we’re continuing to tweak our Eagle Ford completions. We’re as high as ever on the TMS. There is a long lead time associated in getting the drilling there as you know. So that’s moving along, we expect to start our first well probably no later than May. The above levels are not below, it looks like below is the preferred way to go right now. We are participating where we can, any places we’ve got leases and formed units by other operators. So we’re committing the capital. We’ve got a team in place to execute and we’re looking forward to doing, I think it’s a basin that can add tremendous upside to our prospects. Chris?

Christopher D. Heinson

Just to expand on the TMS a little bit. It’s well known that TMS is a technically challenging environment to drill and we’ve been working the technical design of our wells for a period. One of the things that Sanchez – we’re shooting to do is we’re not just trying to drill wells for the sake of appraising the acreage. We actually believe we have a good shot of making money on our very first well. And so we have spent a lot of time and effort designing the well. As far as target goes, the so called rubble zone, it’s not actually a real zone.

What it is, is a highly fractured area just above the Richland sand or the Richland silt which is a zone that we look towards. People have gotten themselves into trouble when they have tried to land above that Richland sand because the rubble down is just no telling how far it may extend vertically in the section. So some operators who are trying to avoid it ended up intersecting highly fractured zones when they landed north of the Richland sand. So we will be targeting just below the Richland sand that would be our target. And we think we can actually complete up until that fractured zone.

Neal D. Dingmann – SunTrust Robinson Humphrey

Chris do you have any working interest in any of these non-ops now, or, you’re just waiting for your first one?

Christopher D. Heinson

We are participating for very small interest in (inaudible) well. It’s should be fracking soon. And there are several other wells that are coming up on a non-op basis that we’re participating in

Neal D. Dingmann – SunTrust Robinson Humphrey

Okay. Thanks Tony. Thank you all.

Operator

Our next question is from Ben Wyatt of Stephens. Please go ahead.

Ben Wyatt – Stephens, Inc.

Good afternoon guys. Just kind of sticking to the pad drilling and some of lumpiness that you guys did not experience as we move throughout the year. Do you guys care to may be just give us some guidance on what production could look like as we move through 2014?

Antonio R. Sanchez, III

Yes, I’ll hit it from a high level. I don’t really see much difference in the overall production for 2014 than we’ve guided to in the past. There may be some shifting between quarters and parts of quarters. So it’s really I’m talking about months here and there, not any material change in what we expect to produce this year overall. So our capital program remains the same and our production guidance for the year remains the same. There might be shifts one or two months forward and then back the other way once we start to work our way through that pipeline. In this case today we’ve got 14 wells that are waiting on completion and we’re working through that inventory as we speak. So it’s continuing. It’s nothing we’ve really seen in the past and utilized before, the effect of pad drilling and this is just one of the effects.

Ben Wyatt – Stephens, Inc.

Got it. And how much, what percentage of your wells this year will be on pad?

Antonio R. Sanchez, III

90% of our wells are pads.

Ben Wyatt – Stephens, Inc.

Gotcha. And just a couple more really quick. As I look at kind of the Cotulla acreage dropped about 5,000 acres. Just curious if that kind of 38,000 acres number is a good number to use for the asset going forward or if we’ll kind of see that number, kind of dwindle is maybe leases expire from the Hess acquisition.

Antonio R. Sanchez, III

We will be filing our 10-K Monday, and it has all the updated leases in it. I didn’t actually bring a copy of it with me. We have been selectively renewing and extending acreage in the Cotulla area and in areas where we don’t think we will be able to get to in a relatively near-term. We’ve left some acreage expire. I thought I can’t give you the exact number right now. I just don’t have it with me.

Ben Wyatt – Stephens, Inc.

And then, kind of lastly would just love your commentary on this. But some neighboring peers in La Salle County have talked EURs as high as 800,000. You guys are using kind of a range of 400 to 500, just curious if you guys kind of see, upside to EURs in the future there or maybe should we use for modeling purposes the high-end of that range just love to give your take on that?

Christopher D. Heinson

Yes, this is Chris. A couple of things are going on but there is high EURs. EURs do increase as you go further south towards that condensate and gas window. So you get high recovery on that. But operators are also targeting longer laterals. Our position is pretty well defined in terms of our lands. So we feel pretty comfortable with our EUR range.

Ben Wyatt – Stephens, Inc.

Very good. Thanks guys and keep up the great work.

Christopher D. Heinson

Thanks.

Operator

Our next question is from Leo Mariani of RBC Capital Markets, please go ahead.

Leo Mariani – RBC Capital Markets

Hi guys, you spoke a little bit about the Sante North it sounds like you drilled that out of the frac plugs. Is this going to make this well kind of a normal lateral, just wanted to check to see there is any obstructions at all sort of left in there and then trying to get a sense of what the timing of sort of your release of some of the new information on that well might be?

Christopher D. Heinson

This is Chris. We’ve just recently drilled up a well and we are still cleaning it out putting on test. A couple of things happened when you actually produce partial well and then produce the remainder of it. So it may take us a little while to get a good test once we get all the flow regimes and pressures normalized in that well. We’re still appraising it.

Leo Mariani – RBC Capital Markets

Okay. Is that something you think you would come out with prior earnings and maybe some kind of update?

Antonio R. Sanchez, III

Yes, I think we probably wait until our next operations update, because a lot of people looking at the Five Mile Creek activity there and that’s four well pad. So I am not sure we haven’t even thought about it, Leo, since you just asked the question, I don’t have a direct answer, so we’ll definitely talk about in next ops update, which is before earnings.

Leo Mariani – RBC Capital Markets

Okay, I guess in terms of Five Mile Creek, just want to make sure understood sounds like those wells are fracking in May, is that correct?

Antonio R. Sanchez, III

Yes, it’s a four well pad, I believe we are on well number 2 and then we will frac all four back to back, starting in May.

Leo Mariani – RBC Capital Markets

Okay, you guys mentioned 40-acre pilot results, just trying to get a little bit more information around that, kind of roughly how much production history, you have on those a bit of comment, you are not ready to book PUDs on 40s yet, but you are going to drill on 40s. Maybe you could kind of explain that rationale, it would be better?

Christopher D. Heinson

Yes, this is Chris, on our 40-acre pilots, the first one was done at Palmetto and that one I think we have about six months of production data on and I think we are getting very close to being able to figure out what the performance differences on the 40s versus the 60, they look actually pretty similar. Over on Alexander Ranch and Wycross, those pilots are less than three months old production wise.

We sort of feel we made somewhere around that six months or at least, a very stable decline in order to have some high confidence in those reserve estimates.

Antonio R. Sanchez, III

But definitely moving in the right direction Leo, we purposely kept the PUD bookings at 60, knowing that as we get more and more data, we will have a better certainty into adding reserves as a function of downspacing.

Leo Mariani – RBC Capital Markets

Okay, that’s helpful. And could you guys give a little more color on your pricing in this quarter, so looking at gas, it was down like $0.80 sequentially from the prior quarter and just looking at oil, you guys talked about being the lowest for the year, I am seeing it down about $12 sequentially, can you give us kind of anymore color as to kind of why you think there were some changes in the quarter and how we should think about pricing here in 2014, if you have some insight on that, maybe any kind of year-to-date observations or something?

Antonio R. Sanchez, III

So I think the trends over last year are pretty well known. One thing we didn’t talk about or the trend last year was that, I think as you all know the 95% plus of our oil sold on LOS pricing benchmark and the basis in LOS to WTI about mid-year started coming in pretty strongly. It’s varied up and down a little bit at the end of the year.

I think one of the key drivers in the fall and realized oil price is going from an average of $10 to $12 differential in LOS compared to WTI to a forward curve today that would price it between $3 and $4 a barrel. The winter months here, January and February on a daily basis it’s been as highest spread at $7 and its lowest $4.

Given that oil is 75% of our production probably 95% plus of our revenue stream that’s the biggest impact. First quarter clearly spot gas prices have moved up in response to weather. However, if you look at the 2015 curve for natural gas, it hasn’t moved near as materially or near as much as you have in the front end.

Leo Mariani – RBC Capital Markets

It’s helpful. And I guess, I think I totally understood what you’re saying here on oil, I guess I still didn’t quite understand gas, I mean I know that gas prices were up between 3Q and 4Q just looking at Henry Hub and your prices were down. So is there anything going on there, new processing arrangements or maybe you’re losing more of gas or something like that maybe affecting it?

Antonio R. Sanchez, III

No, there is nothing like that. I actually think gas prices we can late last year and the third going into the fourth quarter, as we have very full storage, it wasn’t until really January to start to see the uptick in prices with this Polar Express events that came down through the country repeatedly. I am not sure.

Leo Mariani – RBC Capital Markets

No, it’s strange.

Antonio R. Sanchez, III

No, there is nothing different going in our production stream processing yields or anything like that.

Leo Mariani – RBC Capital Markets

Okay, thanks guys.

Operator

Our next question is from Stephen Shepherd with Simmons & Company. Please go ahead.

Stephen P. Shepherd – Simmons & Co. International

Good afternoon guys. I’ll try to ask what I think, an earlier caller was asking in a slightly different way. So when I look at the current guidance for 2014, which calls for drilling and completing 70 net wells for about $640 million of spending. I am curious to what extent are these faster drilling times in completion cost reductions that we are seeing in 4Q factored into that guidance.

Is it fair to assume that if the costs from the drill times remain flat from where they are or even improved from here, is it fair to assume that there is upside to the production guidance in the completion schedule for this year?

Antonio R. Sanchez, III

I think the best way to look at it is, if we leave our budget at the planned 70 net wells that we are going to drill that we would expect to come in at the low end of our capital budget forecast as a result of all the things that Tony and Chris talked about.

We haven’t made any decisions at this point nor we are actively contemplating anything at this stage with respect to the revisions to our capital spending plan, number of rigs and how that will flow through into production.

There is appropriate time we’re just two months into the year, not really appropriate to do that yet, but the simple answer is drill the plant that we have 70 net wells and will be fairly at the low end of our capital budget guidance because of those efficiencies.

Stephen P. Shepherd – Simmons & Co. International

Okay, that’s helpful. Thank you. My next question would be, anymore detail you can give about the TMS non-op program for this year, any idea of which well should be participating in, where are those wells are going to be drilled, anything like that you can offer?

Christopher D. Heinson

Yes, this is Chris. We have participated in one well that’s not to be completed actually this Sunday, that’s the loss in well. Additionally, we’ve seen most of dozen locations units formed in an around places where we have some acreage. Now, it looks a little bit difficult to predict, because there is a fairly extensive land process around the unit formation is when those operators were actually drilled.

We’ve seen that most amount of activity in and around Wilkinson county, where we actually have a fair amount of acreage, that’s going to be highly active area, so we expect quite a bit of non-op.

Stephen P. Shepherd – Simmons & Co. International

Okay. One more if I can; we talk a lot about well costs in the Cottulla area and the Marquis area, I am just curious about Palmettos, has there been any additional improvement in costs from that $8 million number in that area?

Antonio R. Sanchez, III

Yes, there has, in fact Marathon has continued to improve on their drilling efficiencies as well. We haven’t quite seen the same kind of reduction in completions that we see on our own operations yet, but they’ve also improved their cost performance as well. Their wells are coming in probably closer to the $7 million range.

Stephen P. Shepherd – Simmons & Co. International

So, it’s reasonable to expect that on an ongoing basis Palmetto drilling somewhere south of $8 million in single well process?

Antonio R. Sanchez, III

Correct.

Stephen P. Shepherd – Simmons & Co. International

Okay. Thank you, that’s all I got.

Operator

The next question is from Chad Mabry of MLV & Company. Please go ahead.

Chad L. Mabry – MLV & Co. LLC

Thanks. A quick follow up on the Sante North question. You’d previously mentioned I think on your last earnings call that you’re still staying in another non-op well in this area, any results yet from that well that you can discuss?

Christopher D. Heinson

Well, I think in the Sante North area there are no non-op wells that we’re participating in. Little bit further to the south, we do participate with a private company Oak Valley, the old Halcon acreage in there, and we’re participating in a series of wells with smaller interest with them, but there is nothing going on currently, immediately, around us, something on location.

Chad L. Mabry – MLV & Co. LLC

Okay. Then a follow up reflected on your forecast for reserves next year. Looking at your PUD percentage that has come down nicely over the past few report. How much of this year’s joint program is going to be PUD focused and what might that imply for your reserve additions in 2014?

Christopher D. Heinson

I’d say the majority of our drilling this year, a vast majority of our drilling is going to be PUD focused. There is some drilling that’s going to be appraisal type drilling, like the Sante well, we’re going to be drilling some more wells in and around that Sante area. We’re continuing to test the upper Eagle Ford. So we don’t have any forecast yet has to what potential reserve addition those types of activities could add, but I would say that 90% plus of our drilling activity is going to be PUD focused. So we’re continuing to focus on conversion of PUDs to PDP and expect that trend to continue and then we would continue to add reserves from down spacing.

Chad L. Mabry – MLV & Co. LLC

Great, that’s helpful. Thank you.

Christopher D. Heinson

Okay.

Operator

Our next question is from Steve Berman of Canaccord. Please go ahead.

Steve F. Berman – Canaccord Genuity, Inc.

Thanks. So most of my questions have been asked, just one for I guess for Mike, your interest expense in Q4 was a bit higher than what I would have thought just based on 600 million of senior notes out. Well, was there something else in that number and what do you see is a run rate there at least currently, why you are still – that’s your only debt outstanding?

Michael G. Long

I think you said it very accurately. Our only debt outstanding is 600 million of fixed rate notes, 7.75% coupon. So the calculation of an annual interest rate is relatively straight forward. I think what you may have experienced was the timing of the add-on of the $200 million additional notes that we did in late third quarter. If you just looked at the previous quarter, and then annualize that going into the next quarter, that wouldn’t be an accurate calculation, but there is no other debt outstanding other than 600 million, so 7.75% coupon the interest expense calculation is pretty simple.

Steve F. Berman – Canaccord Genuity, Inc.

Was there some sort of a derivative number in there to get to the $13.3 million?

Michael G. Long

Well, there is no derivative numbers in there. Part of interest expense is amortization of cost on debt instruments that we put in place earlier, but…

Steve F. Berman – Canaccord Genuity, Inc.

Right, so it must be that then. Okay, all right, very good that’s it from me. Thank you.

Operator

Our next question is from Dan McSpirit of BMO Capital Markets. Please go ahead.

Dan E. McSpirit – BMO Capital Markets

Yeah, thank you. You expressed drilling your first operated TMS well in the context of making a return rather than simply defining the leasehold. What [field lower] [ph] returns are being targeted and how sooner do you see the TMS competing with the returns generated in South Texas?

Antonio R. Sanchez, III

Yes, so we think about it in terms of return that is sure. We are looking at, and I’m speaking off the top of my head here, but early on when we started looking at the TMS, we looked at what the returns would be, add a call it $15 million well cost which would be at the high-end of what a single well should cost out here and then looked at them anywhere from 500 MBoe to 600 MBoe EURs all the way up to 800. What we – based on the type curves that we had build most of which were on actual data and kind of juxtaposing that to what we get in Eagle Ford we got some comfort around the shape of that type curve and we are looking at returns at those high capital costs in the 17% to low 20%. So once we got our hands around that, we figured that’s a positive return from an appraisal well and we started look at the TMS under a development scenario. And because of its leverage to oil prices and the high IP rates you can get those returns then kicked up pretty quickly with the reduction in costs.

So a $10 million well cost at a 600,000 barrel EUR would generate at $90 a 50% rate of return. If you go up to 800,000 barrels, you’re looking at anywhere from 75% to well over 100% rate of return. So it’s – if you use those book-ins to make a judgment on the play which is the way we looked at it we started to get really comfortable with the potential that the TMS has. And then we’ve got some experience to base it on, the first wells that we drilled in Marquis, our first two wells cost a $16 million and then $15 million and now we’re drilling them for under $9 million. So we’ve got experience in dropping well costs from that kind of a magnitude to something substantially lower.

So I think that the price is there. We think that if the technical challenges are solved, that the TMS is going to be offering very competitive rates of return to what we’re drilling over in the Eagle Ford. We’re not prepared to make a decision yet and we probably won’t make a decision to go into full scale development until we have a number of wells under our belt. But all the pieces are in place to turn that TMS into a huge play. And I think with the introduction of several other operators into the area more money being spent by more players generally speeds up the process that I just described. So does that kind of answer your question, Dan?

Dan E. McSpirit – BMO Capital Markets

It does, and as a follow up to that just on that discussion and I appreciate the thoughts on under your base case or may be even under your high case, TMS return scenario, is there - what acreage in South Texas does not compete?

Antonio R. Sanchez, III

Probably the northern Cotulla acreage, so Zavala and Frio County don’t compete. Palmetto certainly would compete, the best part of - in Marquis, Prost and Five Mile Creek would compete, but yeah, those lower IP rate areas where the shale is shallower in the Eagle Ford does not compete to the TMS. The nice thing about how we’ve – the way we’re thinking about timing here is by the time we go into full scale development at the TMS, we will have largely drilled up some of our core positions in the La Salle County area, like Alexander Ranch. There we’ve got about another call it year and a half of drilling there. And then the Southern part of our Palmetto area, so we’ll move up into the middle of Palmetto. We’ll continue our Marquis area development, but we’ll be able to take certain discreet assets that we have already drilled up intensely such as the Alexander Ranch asset will be the key one. That would then generate a very large amount of free cash flow that we will use to fund our TMS development.

Dan E. McSpirit – BMO Capital Markets

Got it. And then as a follow and a final question, if you invested another dollar on leasehold acquisition, where would you put it, South Texas or acquired TMS perspective leasehold.

Antonio R. Sanchez, III

What, can you give me $2 and I’ll put $1 in each. I mean it’s interesting. TMS you can’t really get a good acreage in that core area where we are.

Dan E. McSpirit – BMO Capital Markets

Okay.

Antonio R. Sanchez, III

So we are picking up bits and pieces here and there, but they tend to be either non-full interest, but we’re hoping to get into formed units by other companies, or they’re additive to our units, but we are not being able to pick up big blocks anymore in the TMS, which is why we moved early when we did.

And then in the Eagle Ford, I’d say the tier 2 and 3 areas we’re still able to pick up some acreage anywhere from $1,000 to $5,000 an acre and that's where our drilling efficiencies and our cost reductions really come into play because we view ourselves as trying to achieve low cost, low marginal cost status. And as we do we start now to look at areas that we even six months ago would have considered uneconomic or marginally economic and now they are competing for capital. So we are able to go in there and take leases and make money where other companies can’t.

Dan E. McSpirit – BMO Capital Markets

Very good, thanks again.

Operator

The next question is from Doug Zinser of Henderson Group. Please go ahead.

Antonio R. Sanchez, III

Doug? I think he is off.

Operator

(Operator Instructions) Our next question comes from Joe Magner of Macquarie. Please go ahead.

Antonio R. Sanchez, III

Joe.

Operator

Mr. Magner your line is live. And the next question is from Don Bishop of BI Research. Please go ahead.

Tom Bishop – BI Research

Hi, that’s Tom Bishop. What is the current price that you are actually getting to crude, you mentioned $3 or $4 differentials to LOS, but I didn’t quite know how to translate that?

Michael G. Long

All right, maybe the best way to help you is to point how the pricing contract typically works. So what you see on the screen is the NYMEX trading price, which is a settlement price at Cushing Oklahoma, delivery of those barrels. The way pricing actually works is we receive a field posting for WTI in the areas where we drill based on the purchaser of that crude and that’s I don’t know where that is today but the pricing is you get that field posting get what’s called the P plus or the prompt plus bonus for that pricing. You then get a difference between WTI and the LOS and all of those added together you have a deduct for in your transportation costs and any basis requiring difference in the crude. So on an average right now, we are probably receiving plus or minus $3 a barrel under your NYMEX screen posting which you see for WTI, and of course that varies daily.

Tom Bishop – BI Research

Okay, at one point have you’ve gotten a premium to WTI. I mean I thought you remembered a small premium, but I guess fairly that fluctuates wildly, I thought maybe you had better crude or something?

Christopher D. Heinson

Well, where that has fluctuated in the past has been that the spread between WTI and Louisiana light sweet in 2012 for example, averaged close to $15 a barrel positive, it steadily decreased over this year which I talked about earlier. And today that differential in the spot market is around five bucks.

Tom Bishop – BI Research

Negative.

Christopher D. Heinson

No, that LOS is about $5 higher than WTI in the spot market now, down from double digits six months ago.

Tom Bishop – BI Research

Okay, but you’re getting about 3 less than WTI now, is that…?

Christopher D. Heinson

Yes, and again once you are having trouble with is comparing what you see as a NYMEX price on Bloomberg or pricing service and what actual field pricings are which run off a daily average in the field. So everything adjusts back to a basis.

Tom Bishop – BI Research

We used to get 10% less something in the Bakken but we’re [historically] [ph] down here in the Eagle Ford. And what is the production rate running today? I know you peaked out at 20 and averaged 18.8, but and [inaudible] now here in early March?

Antonio R. Sanchez, III

It’s running in the mid 18s if you account for - right now we are fracking so we’ve got a few well shut in, and so it’s kind of helped stabilizing that area as we’re bringing - and we’d expect it to bump back up as we bring this next set of wells online.

Tom Bishop – BI Research

Okay, I just also wanted to ask about the gas price and that have gotten down really low and now the cold weather and everything, what’s that up to now?

Michael G. Long

I haven’t looked at the screen today. I think…

Tom Bishop – BI Research

Well roughly lately.

Michael G. Long

In the fives, and they peaked at six when New York was absolutely being slammed with cold weather. The average of the NYMEX natural gas price for calendar 2015 right now is right around $4.22 compared to a spot price today in the fives.

Tom Bishop – BI Research

Do you get it at spot or do you have a contractual arrangement?

Michael G. Long

We have - our gas is sold in the field in South Texas and that South Texas gas price typically trades on average $0.03 to $0.05 under what you are seeing is as the Henry Hub - NYMEX price.

Tom Bishop – BI Research

Okay, thanks.

Michael G. Long

Thank you.

Operator

Our next question is from Phillips Johnston of Capital One. Please go ahead.

Phillips Johnston – Capital One Southcoast

Hi, guys thanks. Just following up on plans in the TMS, your CapEx budget for the year is $60 million to $65 million and I think you are planning on drilling and completing two net wells. So I’m just wondering if you can comment on what AFE you are assuming for both of those wells and what other kind of cost here are baked into your full year CapEx budget for TMS?

Michael G. Long

I’ll let Chris talk about what we’re thinking about for our first AFE on our well. We’ve made an – as Tony explained we’ve been AFE-ed or notified that we have acreage in several units that have been formed, we are expecting those non-operated wells to get drilled out into the future. We don’t have a – our deadline is to win any of those non-op wells will start, so our estimate of capital costs is an estimate at this point. So we don’t have precision or control over the non-op. We do know what we want to do on our first well with a lot of science and then what follow-up wells might be, but I can’t speak to the timing or the exact working interest we’ll have on all those non-op wells until the final AFE with a proposed spud -date for them comes in from the non-operators.

Christopher D. Heinson

Yes, our first well is expected to cost just over $15 million, but that includes the costs for the pilot hole associated with that. After drilling that well our next well will not have a pilot hole, so we expect cost to come down a little bit from there roughly about $1.5 million maybe even little bit more if we take up a few efficiency improvements along the way after our first well.

Phillips Johnston – Capital One Southcoast

Okay, that makes sense. And then just over on Prost, nice job on getting the well cost down to $8.5 million. I’m just wondering if that figure is a good assumption going forward for the rest of your Marquis acreage, at least on average; I know it’s deeper to the Southeast and shallower to the Northwest, but on average is that a good assumption to use for the entire sort of Marquis area?

Antonio R. Sanchez, III

I think you’d be conservative and use that; I’d expect the shallower drilling parts of Five Mile Creek are going to be intermediate casing type [setting] [ph] wells. So, that’s the development number at Prost that is deeper and are bigger wells and more complicated type drilling. As you move further up dip, I fully expect that numbers to come off of that. But on a blended basis, I don’t know how that would translate to the entire position. We are looking at the upward Eagle Ford very closely, I think we’re going to be drilling some wells and testing the upper Eagle Ford. And so those if that goes into full scale development it would be less costly from a capital perspective than the 8.5%.

Michael G. Long

Okay, thanks guys.

Antonio R. Sanchez, III

You bet.

Operator

Our next question is from Curtis Trimble of Global Hunter, please go ahead.

Curtis Trimble – Global Hunter Securities

Hi, good afternoon everyone. Just wanted to hopefully drill down a little bit in the Marquis area, towards the north side and see what you can tell us about the differences in Eagle Ford from the Prost area through Sante North over to the West and the Five Mile Creek area, and if you could give us a little bit more detail on the construction at the Sante North well and whether or not you felt it is going to be problematic going forward or just another [enigmatic] [ph] instance of [inaudible]?

Christopher D. Heinson

I’ll talk just very, very briefly about the Prost and Five Mile. We’re targeting the lower Eagle Ford and both of those regions and we’re chasing a low carbonate number that is very well developed on both of those blocks. And that’s what we think is really helping drive the high production over in that area. In Sante North I mentioned earlier, we drilled the pilot and we collected logs, those were, I’m going to be a little quite on those because those are proprietary results and we think we had some leverage on those targets [inaudible].

Curtis Trimble – Global Hunter Securities

Okay, but outside of that carbonate number I’m guessing around somewhat Southeast to Northwest from the Prost area?

Christopher D. Heinson

Correct. It runs through our PVA’s acreage, down to the Southwest.

Curtis Trimble – Global Hunter Securities

Got you, and it’s just absent as far as you can tell as you move more directly north into the Sante area?

Antonio R. Sanchez, III

We actually saw it is present, but I’m not going to comment too much more.

Curtis Trimble – Global Hunter Securities

Got you. Okay. Switch gears over to the TMS, I was wondering if you could talk a little bit about the acreage movements, I know early on maybe there was some discussions about swapping acreage over in Concordia Parish [Unclear] something possibly further South and East. And then, obviously there have been some fairly significant moves in the past few months on non-op any of that surprising, any of that actually occurred and had a little bit of scuttlebutt about possibly some of the better wells the Anderson wells for instance being drilled up again, [salt downs] [ph] and maybe that leading to some incremental natural fracturing that led to better deliverability any opinion or validity to that?

Antonio R. Sanchez, III

I’ll take the first one on acreage swaps. We’re not planning any large scale acreage swaps. Many of the operators have a fairly broken up acreage position. And so what we’re all trying to do to is work together try and make sure we form as many contiguous units as possible. And so there’s some minor trading back and forth but no major acreage swaps trying to move ourselves to a better part of the play.

We have actually what we’ve seen is sort of the core of the TMS is collapsing down into a much narrower window. Looks like the core of the core is that sort of Southern Wilkinson County going into Southern and mid – just across Louisiana State line. But it’s been structurally quite. So we don’t see anything structurally associated with salt downs or anything as being significant contributors for the Anderson.

Curtis Trimble – Global Hunter Securities

[Inaudible]] between what you’ve seen thus far from Lawson drill data and overall depth at Horseshoe Hill area that you guys have a little non-op participation in as well?

Christopher D. Heinson

I am sorry I didn’t hear the first part of your question.

Curtis Trimble – Global Hunter Securities

[Not to beguile you] [ph] in terms of content fitness, anything like that of the target zone in the TMS between the Lawson area and the Horseshoe Hill area?

Christopher D. Heinson

All right, in fact the TMS as a zone is actually relatively predictable. [Inaudible] there is not much structurally going along or over the whole region?

Curtis Trimble – Global Hunter Securities

Because everything else that’s around it [inaudible] upper and lower?

Christopher D. Heinson

Yes.

Curtis Trimble – Global Hunter Securities

Good to hear. I appreciate the color.

Christopher D. Heinson

Thanks.

Curtis Trimble – Global Hunter Securities

Thanks Chris.

Operator

I’m showing no further questions. This concludes our question-and-answer session. I’d like to turn the conference back over to Mr. Long for any closing remarks.

Michael G. Long

All right, everybody thank you very much for your participation and interest in the company. We look forward to talking to you next quarter.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!