SilverBow Resources, Inc.
Q3 2013 Earnings Call Transcript

Published: 31 Oct 2013

[Operator:]

Good morning my name is Lia and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Company Third Quarter 2013 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer session. (Operator instructions). Thank you. I would now like to turn the conference over to Mr. Vincent, Director of Finance and Investor Relations. Sir you may begin.

[Paul Vincent:]

Good morning. I am Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy’s third quarter 2013 earnings conference call. On today’s call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer will review our financial results for the first quarter. Then Bruce Vincent, President; and Bob Banks, Executive Vice President and Chief Operating Officer, will provide an operational update. Terry Swift will then summarize before we open up the line for questions. Also present on the call is Steve Tomberlin, Senior Vice President of Resource Development and Engineering; and Jim Mitchell, Senior Vice President, Commercial Transactions and Land. Before I turn the call over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates, and projections about us, our industry in the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports, to which we refer you along with cautionary statements contained in our press releases and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions. In addition to our prepared remarks, we have also posted a copy of this morning’s press release to our website.

[Terry Swift:]

Good morning. Thanks, Paul. We again thank you for joining our call. The third quarter was a very active one for Swift Energy. We realized production growth in our South Texas area of 10% over the second quarter of 2013 and we continue to demonstrate meaningful cost reduction and performance improvements in our Eagle Ford program. We announced and have opened a data room to accommodate the sale of Austin Chalk and Wilcox working interest and minerals positions in Central Louisiana. We’ve also begun our 2014 budget process and while our 2014 program won’t be finalized until we are further along in the sales process of our Central Louisiana assets we do anticipate shifting the portion of our capital spending in 2014 towards our high value South Texas assets well spending a lower percentage of our CapEx in Louisiana. Our performance in South Texas during the quarter was bolstered by a high volume of completions during the second quarter which tapered off during the third quarter as we reduced some of our drilling activity. While, we don’t expect to experience similar production growth in the fourth quarter, we are expecting to increase our rig count later this year and anticipate this will report regular production growth from this assets during the calendar year of 2014 as we maintain higher levels of drilling activity in South Texas than we have today. Our production growth is come from higher activity and better wells. We are drilling these wells by performing better completions and believe we can improve further our performance by increasing our lateral lengths, increasing the number of frac stages in our wells while decreasing the distance between each stage and increasing the amount of frac sand and profit we use in each stage. While we optimize these measures, we will continue to modify and improve the returns from these wells. We are just a big believer that the technology learning curve is a continual thing that will produce better results as we go. Bob is going to provide the more details on these specific measures that we’ve implemented and some of the things that might be to come as well as talk about the reduced cost and how those relate to overall improved performance. Our PCQ area and McMullen County has been one of our best performing areas where we’ve drilled more than 10 wells. While no two wells are the same, we have seen significant increases in the 30, 60, 90 and 120 day all recoveries from our more recent vintage wells. We believe this is attributable to more precise targeting of our laterals in the lower Eagle Ford Shale section and more precise placement of frac stages in these newer wells. In the future, as we increase these lateral links, shorten our frac stage, intervals and increase the amount of frac Sanford stage, we expect to see further increases in Q1 production in all of our areas. As we previously disclosed, we have hired Scotia Waterous to assist with the disposition of our Central Louisiana assets. The data room has been active and we're pleased with progress thus far, we expect to begin receiving bids during the fourth quarter, but don't expect to close the transaction until 2014. We expect that this transaction once concluded will reflect a better valuation of these assets than it's implied in our current equity, with the proceeds being used to initially improve the balance sheet and also help bridge any gap between internally generate cash flows and expected cash spending in 2014. The CenLouisi assets will also allow us to increase the focus of our human capital and CapEx resources and growing our South Texas properties. Reviewing additional strategic goals we set forth this year, we spudded and drilled a horizontal well in La Plata County, Colorado during the quarter. This was currently awaiting completion operations, we have conducted significant levels of science with regard to this well and will monitor the activity going forward and certainly get back with you guys as we proceed into 2014 with this project. We also continue to pursue a joint venture for our Subsalt test in Lake Washington. We're encouraged in the discussions with potential partners and we hope to move forward on the prospect after the 2014 Hurricane season concludes. I am encouraged by the quality of the work that our people are conducting and the commitment from everyone in our organization to realize further operational and financial performance improvements. Our business is the challenging one that has demands everyday but we're focused on improving our productivity while reducing our cost. In our South Texas assets we've demonstrated the ability to continue to meet both of these objectives. When we finalize our budget for 2014 later this year we expect to maintain the activity levels which will allow for production reserves and cash flow growth in our South Texas area. And now I'll ask Alton to present our third quarter 2013 financial results.

[Alton Heckaman:]

Okay. Thanks, Terry, and good morning, everyone. Third quarter 2013 production was 3.06 million BOE as oil and NGLs came in at or above the guidance we provided. Liquids production comprised 52% of our 3Q ‘13 production versus 48% a year ago. This led our overall financial results for the third quarter 2013 of $155 million in oil and gas sales, income of $8.9 million or $0.20 per diluted share and cash flow for working capital changes for the quarter of $88.5 million. Our realized price per BOE increased 14% from 3Q ’12. Crude oil prices were up 5%. NGL prices were essentially even. And natural gas prices rose 25%. Oil revenue accounted for 70% of our total sales revenue for the quarter. As to our controllable cost and metrics for the quarter G&A came in at $3.65 per BOE to below guidance, DD&A was above guidance at $21.90 per barrel. Interest expense came in slightly above guidance at $5.72 per BOE. Severance and ad valorem taxes were within guidance at 7.5% of revenue. And production cost for the quarter including workover’s and transportation and processing costs were well below guidance. As previously mentioned, the net result was income for the quarter of $8.9 million or $0.20 per diluted share significantly above the first-call mean estimate. Our effective income tax rate for the quarter was 42%. Cash flow before working capital changes for the quarter was $88.5 million, while EBITDA was $101 million for the quarter. Quarterly CapEx on an accrual basis was $116 million. We currently have collars covering a good portion of both our oil and natural gas production for the fourth quarter along with the few oil collars stretching into the first quarter 2014. And as always complete and timely details of Swift Energy’s price risk management activity can be found on the company’s website. We continue to maintain a strong balance sheet and the financial flexibility to execute our plans. Our banks have reaffirmed our $450 million borrowing base effective November 01. And as Terry mentioned, we’re taking steps to better align our capital spending with our expected cash flows to continue to strengthen our balance sheet and enhance our liquidity. We expect a reduction in capital spending target for 2014 to levels more in line with our internally generated cash flow supplemented by any disposition proceeds. Our priorities are financial discipline first and gross second. Further we’re also taking steps to reduce our operating and overhead cost to a number of initiatives including reducing personnel in conjunction with any asset dispositions. As always we’ve included additional financial and operational information in our press release including guidance for the remainder of 2013. With that I will turn it over to Bruce Vincent for an overview of our operations.

[Bruce Vincent:]

Good morning. Thank you for listening in. Today I am going to discuss the third quarter of 2013 activity which will include the production, volumes, the recent drilling results, activity in our core operating areas and our plans for the fourth quarter of this year. Beginning production, Swift Energy’s production during the third quarter of 2013 totaled 3.06 million barrels of oil equivalent which was within our expected range of outcomes. Third quarter production was 6% higher than third quarter 2012 production which was 2.87 million barrels of oil equivalent and was comprised of 33% crude oil, 20% natural gas liquids and 47% natural gas. Third quarter production also increased 10% from the 2.78 million barrels of oil equivalent that was produced in the second quarter of this year as a result of new wells being brought online during both the second and the third quarter. In the third quarter drilling results, Swift Energy drilled 12 operated wells during the quarter and participated in one non-operated well. 11 horizontal wells were drilled in the Eagle Ford Shale in the company’s South Texas core area. 8 of those 11 horizontal wells were drilled in McMullen Country. And 3 of those 11 wells were drilled La Salle Country. In the company’s Central Louisiana core area, one non-operated well which is target at the Austin Chalk was drilled in the Bur Ferry Creek. Also during the third quarter one well which is an operating well was drilled in the Niobrara formation in La Plata County, Colorado. We currently have two operated drilling rigs in our South Texas core area both drilling Eagle Ford Shale wells and we expect to add a third rig to the area during the quarter. In the Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields, production during the third quarter averaged approximately 4,765 net barrels of oil equivalent per day, which was down approximately 6% when compared to the second quarter of 2013 average net production from the same area and down 5% from the third quarter of 2012 levels. Lake Washington averaged 4,583 net barrels of oil equivalent per day, a decrease of 4% when compared to second quarter 2013 average daily volumes. We expect to conduct recompletion and workover activity at Lake Washington during the fourth quarter and are preparing for a small scale drilling program during the first half of 2014 in the field. Bay de Chene’s production of 182 net barrels of oil equivalent per day was down 37% when compared to the second quarter of 2013 production levels due to the natural declines and low levels of operational activity. Before now, during October which is the fourth quarter, both fields in this area were shut in temporally in advance of tropical storm Karen. While there was no damage caused by the storm and production was fully restored once it was safe to do so, several days of production volumes were deferred as a result of this. In our South Texas core area, which includes our AWP, Sun TSH and Las Tiendas Olomos fields and AWP Artesia wells and Fasken Eagle Ford fields, third quarter 2013 production of 25,628 net barrels of oil equivalent per day increased 10% when compared to second quarter 2013 production in this same area and 9% when compared to third quarter of 2012 volumes. This can be largely attributed to a short [layout] increase in drilling activity that happened late in the second quarter that led to an increase in completion activity. We expect a greater proportion of our activity in South Texas in 2014 and believe that the combination of lower drilling, completion and operational cost with improving well performance will lead to a more predictable growth trajectory as we add rigs to our Eagle Ford program and maintain higher levels of activity. Earlier this morning we published specific performance data on wells brought online in this area during the quarter in our quarterly press release. So I'll refer you to that data for more specificity on our results. The Central Louisiana core area, which includes our Masters Creek, Burr Ferry and South Bearhead Creek fields contributed 2,689 barrels of oil equivalent per day of production in the third quarter of 2013, which was an increase of 27% over second quarter of 2013 production in the same area. Higher production levels in this area were achieved as the non-operated Indigo 17-1 well was completed and turned over to sales. I'll now turn the call over to Bob Banks to review further operational highlights of the third quarter.

[Bob Banks:]

Thank you, Bruce. In addition to an approximate 10% sequential production growth in South Texas during the quarter, we continue to make significant headway on our per well cost during the quarter. Our average drilling cost per foot during the third quarter was $201, the lowest quarterly average cost per foot drilled in the company’s Eagle Ford development program thus far. In our Hayes area, we achieved a cost per foot drilled of $176 and realized lower drilling cost of approximately $600,000 per well when compared to our most recent prior activity in the same area in the fourth quarter of 2012. We've also lowered the drilling cost in our PCQ area by $500,000 per well since the first quarter of this year alone. More recently in the fourth quarter we finished drilling a well in the PCQ area for less than $3 million. We are achieving these improvements on the drilling side through gradual process improvement and adoption of industry best practices. We're also pushing the technical limits of our drilling equipment, while reducing non-productive time to effective pre-drill planning. On our completion work we've recently begun logging the horizontal portion of our Eagle Ford wells. By measuring the quality of the rock exposed to the well bore, we can design the optimal frac staging preparation configuration to achieve desired results. We can also identify areas of lower rock quality where we might not want to invest in a completion and either reduce or reconfigure the number of frac stages without compromising the performance of the well. In our two most recent PCQ area completions, we were able to eliminate one frac stage in each well, resulting in approximately $200,000 in savings per well. Again, the reduction of our completion cost has evolved in overtime as a result of the expertise of our engineering team and industry best practices. We believe it would be difficult to be where we are today without the benefit of [cowork] we've conduct over the past three or four years. To tie the two together in 2010, our average drilling complete cost with average lateral links of 4,280 feet was $11.6 million. Through the first half of 2013, that cost was $7.54 million and lateral links were 5,562 feet on average. This represents a 35% per well cost improvement with lateral links that are approximately 30% longer. Additionally, a number of our recent wells have been drilled and completed for approximately $7 million as our cost reduction initiatives continue to deliver results. Recently we've also begun to test the concept that longer lateral links, shorter frac stage spacing and increased volumes of sand and proppant will result in higher production rates in recoveries in our Eagle Ford wells. We are still early in the process, but initial indications are that this concept will allow us to achieve significant improvements in 2014 over 2013, as we alter our completion designs to allow for this type of operation. As an example of the impact these enhancements can have is reflected in two of our more recent wells. First, the Whitehurst JV 2H well was a 5200 foot lateral with 15 stages. In this well, we decided to pump about 25% more proppant and fluid and saw a nice resulting IP of about 2,323 barrels of oil equivalent per day on a 20/64 inch choke at 5,420 psi [varying] pressures. On our second well, the SMR Eagle Ford 11H was completed in the fourth quarter with 5,066 foot lateral in 20 stages. In this well, we tightened the stage basing from 320 feet to 205 feet and also tightened the cluster spacing within each stage. Additionally, we doubled the amount of sand and fluid that was pumped during the job. To-date we are very encouraged by a nice IP of 1,608 barrels of oil equivalent per day on a 16/64 inch choke at 2,250 psi. Looking ahead to 2014, we haven’t finalized the budget of work program yet, but we do expect to maintain a more regular rig count throughout the year. Shortly, we will be at a three rig space in South Texas moving to four in 2014. As of now, that should represent a fairly steady state of activity throughout the year. That will likely result in capital spending levels above our expected cash flows, but as Terry mentioned, we are in the process of divesting our assets in Central Louisiana and expect the proceeds of that sale to cover any gap between cash flows and capital spending. The sales process has gone well to-date. We are encouraged by the level of interest in the properties. A successful sales process will result in our operations being more focused on the Eagle Ford shale and our results being more of a pure measure of our performance in South Texas. As we conclude 2013 work program we remain focused on delivering higher average initial production rates increasing two and five-year cumulative production volumes and lowering drilling and completion cost. It is our belief that with much of the heavy scientific [meeting] behind us, we are at the front end of a multi-year production cash flow and value trend due to the prolific nature of the Eagle Ford shale. We have taken significant steps this year to prepare for continuing the growth of our South Texas [prod] well. When we announce our final 2014 approved capital budget, we will also be announcing our 2014 strategic goals, which will be weighted significantly towards performance and growth of our South Texas core area. With that, I thank you for your attention this morning and I will turn the call back over to Terry to recap.

[Terry Swift:]

Thanks Bob. Before we open the lines for questions, I will summarize Swift Energy’s third quarter results and review some of the highlights from today’s call. In South Texas production was up 10% over second quarter production time area. We continue to achieve cost savings across our horizontal drilling and completion program in South Texas. We have begun to lengthen our laterals and our horizontal wells, reduced the length of our frac stages and increased the amount of sand and proppant for using in each stage. We are meeting our internal timelines associated with the sale of our Central Louisiana assets. We’ve drilled our first test well in the Niobrara formation in La Plata County, Colorado. And finally, we're expecting to increase drilling activity towards the end of this year to provide momentum for our 2014 operations. With that, we'd like to begin the question-and-answer portion of our presentation.

[Operator:]

(Operator Instructions). Your first question comes from the line of Andrew Coleman of Raymond James.

[Andrew Coleman:]

Thanks for taking my questions. The question I had was give a more color I guess on asset sale process, you said the data room is going well and I guess with everything plotted to be done in the first quarter. Should we be thinking about taking those volumes out then the start of the quarter, end of the quarter? And I guess with that timeline, is there any reason to think the data room will be open longer that revenues still on track in terms of deadlines et cetera?

[Bruce Vincent:]

Andrew, it's Bruce. I want to be careful about to the extent that I gave you detail, because it's an ongoing process and we are quite frankly seeing a lot of interest. The data room could stay open a little longer, but not much longer, but we do want to sure that qualified interested parties do get a chance to look at the data and have an appropriate time to evaluate and make an offer. But even when you establish a bid date, you are going to get bids in, but then it’s anticipated there would be a period of time that you've got to negotiate a sale. We don’t know if we’ll have one buyer or a multiple buyers and because you’ve got mineral interest and working interest, there could be some complexities to the structure. So we believe it will take time to negotiate an actual purchase and sale agreement. And that’s why we believe that actual closing will take place next year and we expect it to take place in the first quarter. The nature of these properties, there is a lot of consents that need to be obtained also, so there is just a process that we don’t think we can work through the holiday period and get all these consents from third parties. So we expect it to take place again in the first quarter. So in terms of production, we will continue to record the production until the actual closing of the sale regardless of the effective date. And so from your perspective in terms of including production, just need to estimate when you think that’s going to close and include production up to that point.

[Terry Swift:]

Yes, this is Terry. I want to add to that, we believe we've done our job thus far in identifying and presenting the property and additionally which is elected the Scotia Waterous and we think they’re doing their job, they’re qualified and highly respected firm. So we're going to look to them for any movement in our schedules based on getting a better value.

[Andrew Coleman:]

Okay. And then if I think about the production mix on the assets, the Brooklyn piece also earlier this year was a 30, 40 approximates in gas or oil NGLs and gas, would you assume a similar mix for the assets that you all have out there in this package?

[Bruce Vincent:]

I think we've disclosed the liquid ratio. I think it’s about two-thirds liquids if I recall correctly, I’ll get you the specific number here surely, but it’s roughly two-thirds of liquids. But...

[Andrew Coleman:]

Okay.

[Terry Swift:]

It’s a strong liquids profiting, we think it’s a good environment for the sales.

[Alton Heckaman:]

Yeah.

[Terry Swift:]

It’s about 65% liquids and one other things, I do want to point out is that NGLs up here don’t have really a lot of assets that it’s primarily going to be in propane and butane. So there is actually a higher value NGL that we’re getting in Louisiana, and as I said you might be at in South Texas.

[Andrew Coleman:]

Okay. All right. And the last couple of things I want turn on this, and then I’ll get back in the queue was do you have any additional capital that you are spending in the region between now and when the deal is expected to close or has that $35 to $40 million already been spent for the year?

[Terry Swift:]

There is no anticipated capital sorting of any significance. So there gets mainly just operating expenses, there are no wells drilling, let me be more specific with that comment.

[Andrew Coleman:]

Okay. And then last one was yet, if I read the 10-K right it was about 27% PD in the Clay Tax area. I guess from a book value standpoint, do you anticipate that there is a chance for a gain or a loss on that potential sale and can you speak to that? And thanks very much for your time.

[Alton Heckaman:]

Yes Andrew, obviously it’s all about the proceeds and whether sell all or a portion of it in the mix, so...

[Terry Swift:]

And other things have happening here.

[Alton Heckaman:]

Right.

[Andrew Coleman:]

Okay.

[Operator:]

Your next question comes from the line of Leo Mariani of RBC.

[Leo Mariani:]

Hey guys. Clearly you have some pretty good Eagle Ford wells this quarter with your enhanced completion design, are you guys seeing any incremental cost as a result of those kind of how are your completions?

[Bob Banks:]

Wells it’s a combination we are very early in the process. As I mentioned while our average first half drilling fleet costs were about $7.5 million we’ve actually delivered a number of wells in the recent three months for about 7 million. So we are continuing to drive those costs down. As we do tighten up our and when we do tighten up our stage spacing and we go down to about a 200, 205 foot versus 320 foot that does increase a little bit our frac cost, it’s not exactly proportionally amount of sand that you are pumping because we pump less fluid, we get the higher ramp up in sand concentration. But you may add as much as about 20,000 stage to your completion, but we are doing this selectively right now. We haven’t optimized our costs yet and we are continuing to drive down our overall drilling and completion costs along the way as well.

[Terry Swift:]

Yeah. Leo you bring forward a really good comment and that when we put this 10-10 plan together we’re also trying hard to make sure that we don’t focus so much on reducing costs that we not recognize that certain costs can actually improve the well. So we are definitely saying that there are costs at areas that we are increasing such as the amount of sand in some of these jobs. So such as the lateral link, those are additional costs. But the delivery of production from that we think is where we are optimizing, thanks.

[Leo Mariani:]

Got you, okay. It’s helpful. And just additionally your operating costs taken on the LOE side, were really down nicely this quarter. Can you give us little additional color on sort of what’s driving that and can we expect that these kind of continue to go down further? I mean noticing that your fourth quarter LOE was that your guidance was slightly above your third quarter levels, should we think that fourth quarter as a runway going forward or you guys think there is more rooms the downside here?

[Bob Banks:]

Well, I mean, we are working through our 2014 budget right now. I think we gave you the guidance on our fourth quarter for LOE. But clearly the investments that we have put into infrastructure to handle our water more efficiently that is certainly helping. I think the way we are designing our facilities is better, so that we are getting less downtime, less interruption, less maintenance. So I am really proud of our production guys, the way of driving this and taking this on. I think it would be premature to kind of project that out into 2014 until we get all of our production volumes and mixing and areas sorted out a little more clearly.

[Leo Mariani:]

Okay. And I guess just in terms of La Plata County obviously you guys drilled the wells. Can you kind of tell anything up a long there or just kind of any initial thoughts around what you’ve got there?

[Terry Swift:]

Well, I think it is important to note that we have made this a tight hold, so we are not going to put too much on information at this time. But what suffice that we got the well drilled without complication, we are very proud of the operation out there and we did get a lot of good data in terms of logs and cores in that top of information the teams are going through that right now to decide the much depth size related to completion and I think I need to leave it at that.

[Leo Mariani:]

Okay. Thanks a lot guys.

[Terry Swift:]

Thanks Leo.

[Operator:]

Your next question comes from the line of Michael Hall of Heikkinen Energy Advisors.

[Michael Hall:]

Appreciated. Good morning.

[Paul Vincent:]

Hi, good morning.

[Michael Hall:]

Just congrats on some good operational momentum. One of the follow up a little bit on the new completion designs. I'm curious what other tests do you have maybe in the pipeline to continue testing that and perhaps other areas of the acreage position? And then also just didn't catch how much additional sand and you said 2x, I'm just wondering what the absolute volume was on that top?

[Bob Banks:]

Okay. The answer to your first part is yes. We're looking at this pretty carefully for all of our areas. One size does not fit all in each of our areas, each is a bit unique. But we have sufficient data now to really help us correlate what's driving the better performance between lateral length and profit and fluid pump per stage, a number of stages to the way we can figure our clusters, the way we steer in zone. So we're really building quite a data base to where we can do a lot of quality work to see what's driving our best performance. And that's what’s really leading us to test this. What we're sharing with you today is one of the very first wells where we really tighten that configuration. We do plan to do more of that in our other areas, because we see similar correlations to performance with some of these things. In terms of a pure pump, I think in our normal configuration it’s about 4.5 million pounds across the Whitehurst spacing. When we doubled up we took that about 9 million pounds in that SMR 11H.

[Michael Hall:]

Great. That’s helpful. And so I’m assuming this some of our 9H is probably the best kind of nearby comp to look at from a well perspective recently. What would to that -- is that ASE let’s say on the 9H versus to the 11H just trying to understand exactly what we are getting for the stay out of cost?

[Bob Banks:]

Yeah. Well I don’t have the exact well cost in front of me on the 9H, but as I mentioned to you up in this area the SMR and the PCQ area are all in the similar area. I think what I was trying to allude to earlier is while the first part of the year we were delivering wells on average at about $7.5 million but I've seen quite a few wells here in the past two to three months coming in at about $7 million, we completed, hooked up to the installation included. So I think what I am trying to tell you is we're continuing to drive our costs down and I think those numbers will show up better in the fourth quarter results. So it’s a combination of driving costs down, making sure we're getting the optimum completion and trying to get the best economic return on our investment. And I think you just have to wait a little longer to see how some of these [interim] completion techniques and our continued decline in drilling cost all play out.

[Terry Swift:]

Yeah. Let me add to that, it’s a good point though. We really don’t want to focus on one well, because it can be a really good well or there could be any kind of complications. We want to focus on groups of wells. And in particular I’ll note that particularly as you get in these various areas, some of your lease configurations don’t allow you to have 6,500 foot of lateral, so you may drill a slightly shorter well maybe a 5,050 that will impact cost. You may have 19 stages on one of those wells that will impact cost. Some of the longer lateral wells we’re getting as much as 20, 21 stages on those. So those are impacting the cost. And we’re looking at our results in terms of production both the [KIMs], as well as our anticipated EURs in terms of volumes per lateral length and volumes per dollar invested. So that's kind of the way we’re shaking it out.

[Michael Hall:]

Okay. I guess, so maybe to just try and get out. And what would the cost per stage on the new job be relative per cost per lateral foot, I don’t know how you want to try and normalize it. But do you have any color there, if not that's only we could -- wide open, just trying to understand that?

[Alton Heckaman:]

I kind of told you the frac cost per stage, if you’re really tightening up the way we did on SMR-11 and SMR-12 double the sand in fluid concentration which is kind of really slowing at all at it and that adds about $20,000 of stage?

[Terry Swift:]

Yeah. So in a general range you’re looking at 200 to 220 per stage something like that.…

[Alton Heckaman:]

Just on the frac cost per stage, it’s about $95,000 to $100,000 in the original design and at the new design where you throw it all and add it, it would be about $120,000 per stage on the frac cost per stage which is what we are trying to measure here.

[Michael Hall:]

And drilling cost would be about the same, right being no reinvent?

[Alton Heckaman:]

Well, I got to say the drilling cost, they continue to amaze me what they’re doing there. We just drilled though one just moved the rig for a bit under, quite a bit under $3 million. So when we can get those drilling cost down to $3 million and under combine those with an efficient completion cost structure. I think we are really starting to drive some economic performance.

[Bob Banks:]

And that’s an area where the drilling costs are coming down in large measure because they are drilling them faster, but a good bit of the speed is because they are drilling in a more optimal zones that’s within the Eagle Ford. We’ve been using seismic conversion to actually to what I would call a much more targeted rock quality assessment and steering in that. And basically you got anywhere from 150 to 300 foot Eagle Ford out there, but the actual zone that they are now in is more like a 30 to 40 foot zone and it drills much better than the overall Eagle Ford.

[Alton Heckaman:]

Yeah. And just maybe to give you one other, I know what you are trying to look at, Michael. In the PCQ area, just in drilling cost, our best PCQ well there before was about $3.8 million drilling and pre-complete. This PCQ-12 age came in at about $2.7 million, $2.8 million range. So those types of [chokes] of drilling cost reduction more than offset any tweaks that we are making to the per stage frac cost.

[Michael Hall:]

Okay. And clearly a good result on the initial productivity front. Now it seems like a positive test, I was just trying to understand the apples-on-apples, so I appreciate that color.

[Alton Heckaman:]

Sure.

[Michael Hall:]

I guess the other one might be you get some good kind of broad strokes around how to think about 2014 that asset sale to fund the, our bridge to gap between capital and cash flow. So that bridge there cover the entire gap, is that the soft process or how should I think about that as I kind of model things out?

[Bruce Vincent:]

Michael, it's Bruce. I think one of our challenges has been trying to put together 2014 plan internally much less disclosed up and all is that we don’t know exactly what we are going to get in terms of asset sales and how it’s going to structured. You’ve probably seen estimates by other analysts out there in the public have a significant range from low to high. And we think we’ll have some sense of that before the end of the year and can put together a solid budget that incorporates. And I think if we go back to one of the comments that Terry and Alton made was that financial discipline is going to be more important to us as the first priority and then growth the second priority. And so we think it’s important to strengthen the balance sheet, so we're going to try to, we're going to take proceeds obviously to pay down debt and put together a budget that recognizes that we would, our ultimate goal is to stay within cash flow, but 2014 is a year that I’ll spend it to some extent, but we got these sales proceeds designed to help fill that gap. Without knowing the exact amount of that, it's hard to say, but obviously if it's on the lower side, we'll try to pull back in the capital budget to keep some balance and to strengthen the balance sheet.

[Michael Hall:]

Great. That's helpful. I appreciate that color. And then I guess just two more quick ones on my end. Number one was, on the fourth quarter plan, do you like to [answer] how many wells you plan to complete in South Texas in the fourth quarter and when the timing of that added rig if that come on early towards the end of the quarter?

[Terry Swift:]

The rig is easy, the wells drilled from that won’t get complete until at the end of the quarter, they’re not being low barrel production coming from that. In terms of the number of completions we're going to actually make this quarter....

[Bob Banks:]

We're just kind of looking at that right now.

[Terry Swift:]

We'll throw that out in here in a moment.

[Michael Hall:]

Yeah, okay.

[Bob Banks:]

It looks like just looking through the areas it's probably about plus or minus 10 completions.

[Michael Hall:]

Great. That's all I’ve got. Thanks, guys.

[Bob Banks:]

Thanks.

[Terry Swift:]

Thanks, Michael.

[Operator:]

Your next question comes from the line of (inaudible) of Johnson Rice.

[Unidentified Analyst:]

In Colorado, could you be a little more specific on the timing of the La Plata well? And are you still expecting IPs around 375 to 700 BOE a day and those 250 to 400 MMBoe EURs?

[Terry Swift:]

We've already noted that we drilled the well and successfully got the initial test measure that we were looking for. We really aren’t laying out any expectations on a particular right for this well or a particular volume for this well. We're looking at the overall trend and we do see what other Niobrara plays have been able to do. But this is clearly on the exploratory well that still has some work to do and the team is working on developing of the completion plan for it. It’s also important for everyone to understand that we originally talked about hydraulic refracturing this well, and so your expectation that rates could be different if you do that. We revised our plan to not initially practice where we want to test the productivity of rock without fracing it. And so any expectations would be a lot less if you were to frac the well.

[Bruce Vincent:]

Right. And the core data that we've acquired and this take time to get that completely analyze and get it integrated into any future plans.

[Unidentified Analyst:]

Okay. And just going forward in ‘14 with kind of implied flat fourth quarter should we expect like an inflection point ignoring sales with that new rig and possibly some more CapEx in South Texas?

[Terry Swift:]

We do expect to have growth in 2014 if that’s, I think the implication for our guidance is a relatively flat fourth quarter, but we would actually see growing again beginning in the first quarter. The extent of that growth is going to depend upon the size or a capital budget, the timing of in which wells we drill.

[Unidentified Analyst:]

Okay. Well, thanks guys.

[Terry Swift:]

Thank you.

[Operator:]

Your next question comes from the line of Noel Parks of Ladenburg Thalmann.

[Noel Parks:]

Just a few things on Central Louisiana properties, assuming you sold the entire package, roughly what's the book value you are carrying for those properties?

[Bruce Vincent:]

That's really kind of a hard, obviously under full cost accounting the basis in there, we've got a different tax basis and book basis, that's not something that's individually disclosed under full cost accounting. Your entire portfolio is included in your basis. So it’s not separately disclosed.

[Terry Swift:]

Further comment to that, we do have a fairly good expectation of what, clearly what the production and reserves are associated with it and it is a slightly higher cost properties than the South Texas properties that we’re focusing on our development. So when we look at metrics and may be book value versus metrics, so we do see that this could be a very accretive to us overall in terms of our growth strategy.

[Noel Parks:]

Okay. I was sort of getting at just (inaudible) tax usage and the transaction?

[Bob Banks:]

They will be none. We don’t see any issue with depending on the proceeds, any significant tax effect from this transaction.

[Terry Swift:]

And I do want to emphasize, this is a fairly unique transaction and that it’s got a very substantial amount of minerals, the minerals associated with it, not a small amount, a substantial amount and that in conjunction with the working interest production that’s out there, a royalty interest production that’s associated with that does make a property that may have a structured transaction that maybe different than maybe a typical sale. Certainly, the type of assets are very different than a typical sale.

[Noel Parks:]

Got it. Thanks. There was mentioned earlier in the call about Lake Washington and hoping to move forward on the sub-salt test there. If I heard right, it was after the 2014 hurricane season. So I assume that you meant the spud time as opposed to when you think you will have different JV in place?

[Terry Swift:]

That’s correct, Noel. Obviously we will be moving forward before then in terms of making progress on it, but I think we just want to be sure was that an expectation that well wouldn’t be spudded before the end of the hurricane season. We would want to have a rig out there drilling during the hurricane season. So if we don’t get it spudded really late this year or early first thing next year, you would really want to wait till about December of next year.

[Noel Parks:]

Okay. And at this point in discussions for partnerships at Lake Washington, the characters you’re seeing is it essentially the same folks you were talking with say three to six months ago or had the parties changed any?

[Terry Swift:]

Well, Lake Washington, it certainly relates to the sub-salt. This is more or less than by invitation only because we were only talking to folks that do those kinds of activities. To be more specific, we are looking at putting a consortium together or a group together that would properly evaluate the type of test we want to take there. We actually have rights in that area to the center of Europe. So there is numerous approaches you could take for sub-salt test. There is also some imaging opportunities in terms of seeing the rock a little differently if we shoot some additional seismic after that some of the types of things that are being discussed. We will continue to only talk with companies that are very involved and very expert in that area. So, that’s probably enough cover on it right now. We are having those discussions, yes.

[Noel Parks:]

Great. And as you are doing the budget for 2014 and looking to move to four rigs in 2014 in the Eagle Ford, are you using current strip oil pricing in your modeling or using sort of more conservative, more aggressive test?

[Terry Swift:]

The answer is yes, yes and additionally different. We’ve got probably three or four different pricing scenarios, one, there is the strip, which I think most companies deal with. We clearly do all the SEC pricing, which is the backward curve. We do have some expectation that with the gas market may improve relative to that what we are seeing lately. So we run that to see that. So we are looking at scenarios. I personally think that the strip is probably a pretty good representative right now. So you’ll probably see a lot of our estimates revolve around this strip, but we will be looking at all of the upside and downside.

[Noel Parks:]

Great. That’s it for me.

[Operator:]

Your next question comes from the line of Gordon Douthat of Wells Fargo.

[Gordon Douthat:]

Just clarify on that last question. So, it sounds as if you are going to three rigs of course in the fourth quarter this year. Is the plan still add that fourth rig next year?

[Terry Swift:]

Yes, that's the current plan. Obviously it should lead to the finalization of the budget which will be impacted by the proceeds of the disposition.

[Gordon Douthat:]

Okay, alright. And then jumping back to the Eagle Ford, you also mentioned longer lateral links, I'm wondering if you could talk about generally I know it varies across your leasehold position, but generally where are the lateral links would they have been averaging and where do you see that going in the future?

[Terry Swift:]

I think we tried to touch on that a little bit, I think we're kind of on average in the kind of 5,500 foot range. Depending on this configuration, all the leases are different. Where we can get the longer laterals, that's what we first evaluate. So where we can get the longer laterals, we can see going up to 7000, 7,100 feet doing a well like that. Not all lease configurations will allow that. So I would say that you will see us continuing to push that from that average that you're seeing now of 5,500 feet to up above 6,000 feet, and getting the longer laterals and designing our spacing and plans of development to allow those longer laterals in each of our lease areas.

[Gordon Douthat:]

Okay. And then there has been a lot of talk on the cost side of the equation. I'm wondering how many wells do you have into the new completion designs that are on production? And then at what point do you feel like you have an update as to start looking out to EUR started equation?

[Terry Swift:]

Well, I think we said we're very early on in this. Most of our work has been spent looking at all the different metrics. When we drill a well we measure lateral length, lateral link and barrel zone, lateral link and Eagle Ford, the best, Eagle Ford zone. We look at proppant and fluid and cluster configurations. And so we think we have enough data sampling where we can do some pretty good multiple regression work on what is driving our best IP and EUR performance and then we’re measuring our 30, 60, 90, 120 day EURs against each of those criteria. So we really believe we have a data set that supports this. You’re just now seeing some of the early results of that with that Waterous JV where we just increase sand, but more specifically on that last SMR well where we really doubled the sand and tightened the spacing. That’s kind of our early proof that our data will support what our hypothesis is here. So I think we have enough data sampling. We're going to start testing it now to make sure that the physical matches what our models are saying.

[Bruce Vincent:]

Yeah. I am going to add to that not to further complicate it, but you can only really take something like a lateral length if you’re going to look at the whole industry trend and get an answer fast. And I think a lot of observers have done that and we certainly have to. The lateral length is the most easily obtainable number and you can associate that with either 30-day production cums, 90, 120, even one year cums and we do see a very significant trend between enhanced or longer laterals and results. But when you dig deeper you see a lot of other factors that are influencing it. For example hydrocarbon pore volume, how good is your rock, how sick is your rock, how pours is your rock. We've got very high quality rocks in our areas, but each area is different, precision targeting within these zones, we've been talking about that and others are doing, that's a big factor. And of course as Bob just noticed also the numbers of stages where you placed stages the type of treatment you have there. So lots of factors to optimize, but latter one is just the one that everybody can see.

[Gordon Douthat:]

Okay. And then so it’s just going to take some time. Obviously to feel comfortable with revised type curve. When? Is that like six months, a year, when do you feel comfortable with that completion design?

[Terry Swift:]

I think the way, I would answer that right now is that comfort is one way to describe it, but our confidence levels are improving as we go or increasing as we go, where would be the point, where we would have fully optimized that and feel like we can’t get any better, I don’t know where that is, that's probably years away. But in terms of the big step changes, whether or not we can say they are concrete, they are absolute, certainly in six months to a year, you will have those answers.

[Bob Banks:]

Yeah. And we’re measuring, we want to make sure we’re hitting each of markers or 30-day, or 60-day or 90-day or 120 days. As long as we’re hitting those markers on a decline curve, we’re exceeding those markers. As Terry said, probably six months timeframe, you start to feel more comfortable that you would actually change your decline model, based on the new design.

[Gordon Douthat:]

Okay. That’s it from me. Thanks guys.

[Paul Vincent:]

Thanks.

[Operator:]

Your next question comes from the line of Neal Dingmann of SunTrust.

[Neal Dingmann:]

Good morning guys.

[Terry Swift:]

Good morning.

[Neal Dingmann:]

Okay. Bruce I might have missed this did you all say just in those green areas where you are hitting there in McMullen and LaSalle, how many locations you have got left there?

[Bruce Vincent:]

No we didn’t say that today, but I think we’ve been talking about.

[Bob Banks:]

I think we picked that up in our analyst….

[Terry Swift:]

Yeah and we will have to get back to you on that, but that’s also a factor of downspacing. So we really need to do that on different spacing assumptions.

[Neal Dingmann:]

Okay. I can follow offline on that.

[Terry Swift:]

We will follow-up.

[Neal Dingmann:]

Sur. And then just one last follow up. I forget on better part of that Eagle Ford location, I forget now on as far as different formations, I mean is there a potential for both upper and lower there?

[Terry Swift:]

Yeah. I think I will answer that. Definitely potential in the upper, but in some of these areas not as much as others for example I think in our Fasken area and South Texas Webb County a lot of upper Eagle Ford. I think some other players in that area have noted that you got a big upper section that could bring some upside but focused on the lower. As you get more into Artesia wells and our Northern AWP area maybe not as much, but it’s early. So we are not counting it by any means but we are looking at it.

[Neal Dingmann:]

That’s great color. Thanks Terry thank you all.

[Operator:]

Your next question comes from the line of Tom Morgan of Global Hunter.

[Tom Morgan:]

Good morning guys. Just one last quick one. You touched on this briefly, but just do you guys one of the longer laterals in the Eagle Ford and sort of the more complex completions. What does that do on your drilling complete time on your goals?

[Terry Swift:]

In terms of going to the longer laterals and taking up those pages, spacing. The drilling time in the lateral goes pretty quick. I think there are days where our guys are knocking out 2,500 feet a day in the lateral section. So, there is not a lot of added time or even costs for that matter on the drilling side. On the completion side, the timing is really little different. How we put the spacing in and how much sand we pump. In fact, in some ways going to the tighter spacing in the tighter clusters we’re able to ramp up our sand concentrations more quickly. So, I don’t see any real added time to pumping that different type of job. So, it’s very minimal if any.

[Tom Morgan:]

Okay. So, I mean we are on (inaudible) I think Terry did mentioned that you have drill time coming down at some area, or is that located just be able to get the rig (inaudible)?

[Paul Vincent:]

Tom, I’m sorry. You just kind of broke up on this there. Could you repeat that?

[Tom Morgan:]

Sorry. No, as just Terry touched earlier on that you are seeing some drill times coming down a little bit, is that just on more efficient rig mobilization?

[Terry Swift:]

Well, that’s more efficiencies across the whole spectrum of individual operations that are looked at very carefully in drilling the wells. So, it’s a combination of things, it’s not just on rig move time or mobilization or have a block in the rig or any of that. There is a lot of components that are be driven to drive the cost down.

[Tom Morgan:]

Okay. Yeah.

[Alton Heckaman:]

But the marking tackle of it really that the drilling engineer and the GSI just are working hand in hand real time as we drill these wells, with the 3D data set and staying in a very tight window now of what I would call precision targeting and it is in that zone that the driller has the best opportunity to get a lot of footage per day.

[Tom Morgan:]

Okay, that's very helpful. Thank you guys.

[Operator:]

Your next question comes from the line of David Deckelbaum of KeyBanc.

[David Deckelbaum:]

Good morning guys. Thanks for taking my questions.

[Paul Vincent:]

Good morning

[David Deckelbaum:]

Hop in on a little bit late here, but Terry I was hoping you could just clarify the comment you had made earlier about the Central Louisiana sale. You said, it's kind of a little bit of a different asset clearly have some conventional aspects to it, the mineral rates, you said that, perhaps could be multiple buyers. But you had mentioned maybe a different structure deal that you just mean in terms of having sort of multiple packages or how should we think about this and could you add more color on this concept of an alternative structure deal?

[Terry Swift:]

Yeah. Let me add a little more color. First, Scotia Waterous has worked with us to put the package together as a single package. And it works well as a single package, because of where it’s located geographically, the kind of rocks, the kind of resource potential that’s around it. So in that sense, it's a nice area or geographical property package, it’s got a lot of the same types of opportunities in terms of horizontal drilling in three different areas. But within that package, it’s broken down into three specific areas Masters Creek, Burr Ferry and South Bearhead Creek. And in that regard Wilcox, Austin Chalk it looks and is a traditional package. But within that package you do find this very unique distinction that you don’t find in most packages out there. There is a substantial amount of minerals where essentially we are putting up for sale the right to lease or otherwise hold completely the minerals and obtain future royalties and future drilling to very deep depth that don’t have the depth severance. And I forget the exact number of minerals it’s in the package, but it’s like over 80,000 acres of minerals in these various areas. But there is also royalty associated in the package that comes from minerals that have already been drilled that predominantly don’t have any cost associated with the minerals in the sense of a normal working interest, the working interest has to pay a royalty that royalty is for sale in these packages as well. So when I say structure, what I mean is you do have to treat even one seller, I mean one buyer we’d have to work with those to treat these various interests and differently and how they’re conveyed and we’re certainly prepared to do that, we're ready to do that and work with whoever the party is that either wants the entire package or if there is some piece of it that they don’t want to work with, don’t have to take that up to Scotia Waterous and we’ll see what kind of value propositions there are.

[David Deckelbaum:]

Okay. I understand. I appreciate that. And you guys talked about obviously the new completion designs in the Eagle Ford had been very successful, but do you have a sense I guess preliminarily sort of what percentage of wells you would put this methodology on as you prosecute sort of a 2014 program or certainly as you drill the three rigs now?

[Terry Swift:]

Well again, I don’t want to sound redundant, but there’s a lot of factors that optimize production and a lot of factors that optimize your cost from lateral length to a number stage design. Every well is having that approach put to it. As Bob noted, there are just, there are some differences in the areas in terms of lease configurations, so you get a little different design there, you may have more stages per lateral length there to compensate and try to optimize, but in other areas we can drill 7000 foot wells and we think they’re going to be extremely good wells with the right kind of completion technology put around them. So every well is being optimized, that's the first thing to say, but can every well be a long lateral? No. Can every well have 24 stages? No. Can every well be drilled more precisely in this very high deliverability zone or high drillable zone? Yes. And we’re going to work that hard. Do we know how to [climb] core volume in every area? Yes. And higher TOC and velocity and thickness zones take a priority. So every well is getting optimized is really the proper answer.

[David Deckelbaum:]

Okay. I appreciate that. That’s all I had, guys. Thank you.

[Terry Swift:]

Thanks, David.

[Operator:]

(Operator Instructions). Your next question comes from the line of Andrew Coleman of Raymond James. Mr. Coleman your line is open.

[Andrew Coleman:]

Yes. Sorry about that. Can you hear me?

[Terry Swift:]

Yes. Now we can.

[Andrew Coleman:]

Sorry I had it on mute. David mentioned a second ago you guys are talking about the royalty piece for those assets. You’ve been working at the [PD-10] that you all disclosed in the 10-K, does that royalty factored into that PD10?

[Terry Swift:]

Yes. That will be included in that.

[Andrew Coleman:]

Okay. There is a pretty good range, I mean PD10 is somewhere north of $400 million for those based on this eyeball in one of your charts in your analyst meeting a year ago, where is the production value based on 2,500 barrels a day and 20 million barrels would be a little bit lower than that?

[Terry Swift:]

Yeah. That doesn’t sound too far out of the fair way, Andrew.

[Andrew Coleman:]

Okay. Thanks very much.

[Terry Swift:]

Thank you.

[Operator:]

Your next question comes from the line of Ravi Kamath of Global Hunter.

[Ravi Kamath:]

Hey guys a couple of questions. One, on Eagle Ford I know you haven’t determined your CapEx budget, but I was wondering what each rig would, how many wells do you expect it to drill per year and what kind of CapEx per rig we should think about?

[Alton Heckaman:]

Well, I’d say it’s a function of a lot of things as we’ve been talking, but I guess as a rule of thumb you could probably depending on the area. You could probably talk in terms of 12 to 15 wells per year per rig, something in that order. In terms of well costs, I think we told you where we have gotten to the first half of this year that was about $7.5 million, but I have also noted that we are continuing to progress that and have drilled some recently more in the $7 million range. A lot of it will be a function of lateral length number of stages that type of design. Every well as Terry said will be optimized so each well will probably be a little bit different. But I think that gives you certainly a number of, a general number that you can kind of look towards. I drill about 45 to 47 wells on the net in that area.

[Ravi Kamath:]

Got it. And what's kind of your average working interest to come up in the Eagle Ford?

[Alton Heckaman:]

Our working interest?

[Terry Swift:]

It’s been 95% to 100% sometimes depending where the laterals are you’ve got a small working interest owner. And then in our JV wells, of which a large compliment in 2014 probably won’t be JV wells, but those are about 50%. We have got a 50-50 JV with BHP.

[Alton Heckaman:]

Yeah. There will be a small amount of JV drilling next year.

[Ravi Kamath:]

Got it. And then with regards to Southeast Louisiana, what’s the estimated CapEx in 2013? And any sort of general thoughts on 2014 directionally relative to that?

[Terry Swift:]

I think in ‘13 we've had some recompletions, we drilled three wells....

[Alton Heckaman:]

$30 billion to $40 billion I think in 2013.

[Terry Swift:]

Is what the final number will be.

[Alton Heckaman:]

Yeah. Kind of a bigger picture number, we allocated about 80% to 85% of all of our capital to South Texas, about 15% or so was allocated to Louisiana which comprised both that Southeast Louisiana and the Claytex assets.

[Ravi Kamath:]

Okay. So $30 million to $40 million this year is about similar amount in ‘14?

[Terry Swift:]

It might be a little less than that would be my guess.

[Ravi Kamath:]

Okay, great. And I'm wondering if you have any kind of opinion or outlook for the LLS Brent Spread, which has really kind of gapped out recently?

[Terry Swift:]

I think our outlook is probably is about as good as anybody, I mean LLS obviously has come down pretty dramatically during the course of this year. We don't see it widening next year to the spreads that we saw earlier this year. But we would hope it maybe rise a little bit given where it is today.

[Alton Heckaman:]

Yeah. There is still obviously a bifurcation.

[Terry Swift:]

And the market is roughly about 2 bucks plus or minus for both of those right now, but you still have $10 plus spread between Brent and NYMEX.

[Ravi Kamath:]

Got it. And I guess I was wondering if you could, on the last call I believe you guys had said that you could do 15% to 20% production growth based on the flat CapEx in 2014, is that still the expectation?

[Alton Heckaman:]

You cited some numbers that I don’t think we've ever said.

[Ravi Kamath:]

I think there you.

[Terry Swift:]

Yes. There may be some confusion there. We have not said 15% production growth next year, I don’t.

[Alton Heckaman:]

Certainly on flat CapEx that it wouldn’t make any sense.

[Ravi Kamath:]

On flat CapEx.

[Terry Swift:]

I think again we need to reiterate that our first objective is financial discipline for next year. We do believe we can grow and at the same time improving the balance sheet. We're trying to be very thoughtful and not give preliminary guidance for next year. Again, we've noted the Louisiana sale is an important factor and the final determinations of how much growth we would anticipate, but overall we do believe we’ll be reducing capital spending next year and that we will grow production in South Texas in particular.

[Ravi Kamath:]

Got it. Thanks, guys.

[Operator:]

Your next question comes from the line of Jeb Bachmann of Howard Weil.

[Jeb Bachmann:]

Just a couple quick ones on South Louisiana. One, you remind us on this potential JV if you’re looking at it on a prospect by prospect some over field level basis?

[Bob Banks:]

I am sorry. Repeat the question. Are you talking about the sub-salt?

[Jeb Bachmann:]

Right.

[Bob Banks:]

Yes. The sub-salt prospect would be on a prospect basis, it would be on a field basis.

[Terry Swift:]

No, we're only looking at the sub strata underneath the salt which gets in below the big hum after which is a very significantly determined to be different than all of our other likely (inaudible) horizons.

[Jeb Bachmann:]

I guess the last for me looking at strategic divestitures, would you guys haven’t had -- have you had internal discussions about maybe monetizing the 1P down in South Louisiana, but maintaining the working interest say 50% or so in that exploratory potential in the sub salt?

[Terry Swift:]

Well, that's an interesting thought and of course we’re always open to different thoughts. Clearly our focus next year will be growth in South Texas and the growth incrementally in South Texas should be pretty important for the company. But as to South Louisiana, we do look at different options. We are going through a very rigorous review, the subsalt and even the [LI and CC] traction. We don’t talk too much about that, but I think there is still a lot more opportunity in the mid to deep horizons in Lake Washington. We’re certainly reviewing that. Again, we review it every year, but putting the final (inaudible) on it this year. We need to get through with the Central Louisiana divestiture before we make any specific plans for any other assets.

[Jeb Bachmann:]

Hi, thanks for the comments.

[Operator:]

At this time, there are no further questions.

[Terry Swift:]

Okay. At this time, we would like to thank you again for joining us and look forward to next quarter’s call.

[Operator:]

This does conclude today’s conference call. You may now disconnect.