SilverBow Resources Inc (SBOW) 2013 Q3 法說會逐字稿

Good morning. My name is Leah and l 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 speakers' remarks there will be a question and answer session.

( Operator Instructions ).

I would now like to turn the conference over to Mr. Vincent, Director of Finance and Investor Relations. Sir, you may begin.

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 third 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 and 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.

Good morning. Thanks, Paul, and 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. 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 our Austin Chalk and Wilcox working interest and mineral positions in central Louisiana. We have 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 while spending a lower percentage of our CapEx in the Louisiana.

Our performance in South Texas during the quarter was bolstered by a high volume of completions during the second quarter, which tapered off the 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 afford regular production growth from these assets during the calendar year 2014 as we maintain higher levels of drilling activity in South Texas than we have today.

Our production growth has 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 our frac stages in our wells, while decreasing the distance between each stage and increasing the amount of frac sand and proppant 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 more details on the 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 in 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 oil recoveries from our most 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 sand per stage we expect to see further increases in cumulative 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 are pleased with progress thus far. We expect to begin receiving bids during the fourth quarter, but don't expect to close a transaction until 2014. We expect that this transaction, once concluded, will reflect a better valuation of these assets than is implied in our current equity with the proceeds being used to initially improve the balance sheet and also help bridge any gap between internally generated cash flows and expected cash spending in 2014. The sale of Louisiana assets will also allow us to increase the focus of our human capital and CapEx resources in 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 well is currently awaiting completion operations. We have conducted significant levels or science with regard to this well and will monitor the activity going forward and certainly get back with you as we proceed into 2014 with this project. We also continue to pursue a joint venture for a sub-salt test in Lake Washington. We are encouraged in the discussions with potential partners and would 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 a challenging one that has demands every day, but we are focused on improving our productivity while reducing our cost. In our South Texas assets we have 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 activity levels which will allow for production reserves and cash flow growth in our South Texas area. Now I will ask Alton to present our the third quarter 2013 financial results.

Thanks, Terry. 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 to 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 of metrics for the quarter, G&A came in at $3.65 per BOE, which was 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 workovers and transportation and processing costs were well below guidance. As previously mentioned, the net result was income for the quarter of $8.9 million, $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 to 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 a few oil collars stretching into the first quarter 2014. 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 1. As Terry mentioned, we are 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 targets 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 growth second. Further, we're also taking steps to reduce our operating and overhead costs through a number of initiatives including reducing personnel in conjunction with any asset dispositions. As always, we have 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.

Good morning and thank you for listening in. Today, I am going to discuss the third quarter 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 with 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.

For 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 County and 3 of those 11 wells were drilled in LaSalle County. In the company's central Louisiana core area, one non-operated well, which targeted the Austin Chalk, was drilled in the Burr Ferry Field. Also during the third quarter one well, which is an operated well, was drilled to the Niobrara formation in La Plata County, Colorado. We currently have two operated drilling rigs in our South Texas core area, both drilling the 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 2012 levels. Lake Washington averaged 4,583 net barrels of oil equivalent per day, a decrease of 4% when compared to the second quarter 2013 average daily volumes. We expect to conduct recompletion and workover activity at Lake Washington in 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. We'll point out that during October, which is the fourth quarter, both fields in this area were shut in temporarily 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 Olmos 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 2012 volumes. This can be largely attributed to a short-lived increase in drilling activity that happened late in the second quarter which 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. I will 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 2013 which was an increase of 27% over second quarter 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 will now turn the call over to Bob Banks to review further operational highlights of the third quarter.

Thank you, Bruce. In addition to an approximate 10% sequential production growth in South Texas during the quarter, we continued 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 costs 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 costs 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 are also pushing the technical limits of our drilling equipment while reducing nonproductive time through effective pre-drill planning.

On our completion work we have 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 stage and perforation 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 over time 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 all the work we have conducted over the past three or four years.

To tie the two together, in 2010, our average drilling complete cost with average lateral lengths of 4,280 feet was $11.6 million. Through the first half of 2013, that cost was $7.54 million and lateral lengths were 5,562 feet on average. This represents a 35% per well cost improvement with lateral lengths 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 have also begun to test the concept that longer lateral lengths, shorter frac stage spacing and increased volumes of sand and proppant will result in higher production rates and 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 most recent wells. First, the Whitehurst JV 2H well was a 5,200 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, very good pressures. On our second well, the SMR Eagle Ford 11H was completed in the fourth quarter was a 5,066 foot lateral and 20 stages. In this well we tightened the stage spacing from 320 feet to 205 feet and also tightened the cluster spacing within each stage. Initially, 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 a budget or 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 pace 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 the 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 costs. It is our belief that with much of the heavy scientific lifting 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 program. 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.

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 in the same area. We continue to achieve cost savings across our horizontal drilling and completion program in South Texas. We've begun to lengthen our laterals in our horizontal wells, reduce the length of our frac stages and increase the amount of sand and proppant we are using at each stage.

We are meeting our internal timelines associated with the sale of our central Louisiana assets. We have drilled our first test well in the Niobrara formation in La Plata County, Colorado and finally we are expecting to increase drilling activity towards the end of this year to provide momentum for our 2014 operations. With that, we would like to begin the question and answer portion of our presentation.

(Operator Instructions)

Andrew Coleman, Raymond James.

Thanks for taking my question. The question I had was, get a little more color on the asset sale process. You said the data room was going well and I guess with everything slotted to be done in the first quarter, should we be thinking about taking those volumes out then to start a quarter, end the quarter and with that timeline, is there any reason to think the data room will be open longer or if everything is still on track in terms of bid deadlines etcetera?

Andrew, this is Bruce. I want to be careful about -- to the extent that I give you detail because it is 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. We do want to ensure that qualified interested parties do get a chance to look at the data and have an appropriate time to evaluate and make an offer.

Even when you establish a bid date, you are going to get bids in, but then it is anticipated there would be a period of time that you have to negotiate a sale. We don't know if we'll have one buyer or multiple buyers and because you have got mineral interest and working interest there could be some complexities to the structure. We believe it will take time to negotiate an actual purchase and sale agreement. That is why we believe the actual closing will take place next year. We expect it to take place in the first quarter. There are -- the nature of these properties, there is a lot of consents that need to be obtained also so there is a process that we do not think we can work through the holiday period and get all these consents from third parties. We expect it to take place, again, in the first quarter.

In terms of production, we will continue to record the production until the actual closing of the sale regardless of the effective date. From your perspective in terms of including productions, you just need to estimate when you think that is going to close and include production up to that point.

This is Terry. I want to add to that. We believe we have done our job thus far in identifying and presenting the property and additionally we have selected Scotia Waterous and we think they are doing their job. They're a qualified and highly respected firm so we are going to look to them for any movement in our schedules based on getting a better value.

If I think about the production mix on the assets, the Brooklyn piece you sold earlier this year was a 30, 30/40 approximates in gas or oil, NGLs and gas. Would you assume a similar mix for the assets you have out there in this package?

I think we have disclosed the liquid ratio. I think it is about two-thirds liquid, if I recall correctly. I will get you the specific number here shortly. It is roughly two-thirds are liquids. It is a strong liquids property. We think it is a good environment for the sale. It's about 65% liquids.

One of the things I do want to point out is that the NGLs up here don't a lot of ethane in them. It is primarily going to be your propane and butane. So there's actually a higher value NGL that we are getting in Louisiana than say you might get in South Texas.

The last couple of things I want to throw in on this and then I will 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 million to $40 million already been spent for the year.

No. There is no anticipated capital of any significance. I think it is mainly just operating expenses. There are no wells drilling to be more specific with that comment.

Last one was, you had, if I read the 10-K right, it was about 27% PD in the clay TX area. From a book value standpoint, do you anticipate that there is a chance for a gain or a loss on that potential sale? If you could speak to that. Thank you very much for your time.

Thanks Andrew. Obviously it's all about the proceeds and whether we sell all or a portion of it in the mix.

And other things that happen at year end.

Right.

Leo Mariani, RBC.

Clearly had some pretty good Eagle Ford wells this quarter, what with your enhanced completion design. Are you guys seeing any incremental costs as a result of those hardier completions?

It is a combination. We are very early in the process. As I mentioned, while our average first half drilling complete costs were about $7.5 million we've actually delivered a number of wells in the recent three months for about $7 million. We are continuing to drive those costs down.

As we do tighten up our -- when we do tighten up our stage facing and we go down to about a 200 foot, 205 foot versus 320 foot, that does increase a little bit, our frac costs. It is not exactly proportional to the amount of sand that you are pumping because we pump less fluids, we get higher ramp up in our sand concentration. You may add as much as about 20,000 a stage to your completions, but we are doing this selectively right now. We haven't optimized our cost yet and we are continuing to drive down our overall drilling and completion cost along the way as well.

Leo, you bring forward a really good comment in that when we put this 10/10 plan together, we are also trying hard to make sure that we don't focus so much on reducing cost that we not recognize that certain costs can actually improve the wells. We are definitely seeing that there are costs that -- areas that we are increasing such as the amount of sand in some of these jobs, such as the lateral length, those are additional costs. The delivery on production from that we think is where we are optimizing things.

That's helpful. Additionally, your operating costs, particularly on the LOE side, were really down nicely this quarter. Can you give us a little additional color on what is driving that? Can we expect that these can continue to go down further? I have been noticing that your fourth quarter LOE, that your guidance was slightly above your third-quarter level. Should we think of that fourth quarter as a run rate going forward or do you guys think there's more room to the downside here?

We are working through our 2014 budget right now. I think we gave you the guidance on our fourth quarter for LOE, but clearly with the investment that we've put into the 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. I am really proud of our production guys, the way they are driving this and taking this on. I think it would be premature to project that out into 2014 until we get all of our production volumes and mixes and areas sorted out a little more clearly.

In terms of La Plata County, obviously guys drilled the well. Can you tell anything off the log there, any initial thoughts around what you have got there?

I think it is important to note that we have made this a tight hole so we're not going to put too much information out at this time. Let it suffice to say 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 and that type of information. The teams are going through that right now to decide the next steps as relates to completion. I think I need to leave it at that.

Michael Hall, Heikkinen Energy Advisors

Morning. Congrats on some good operational momentum. I wanted to follow up a little bit on the new completion design, curious what other tests you have in the pipeline to continue testing that and perhaps other areas of the acreage position. And then also I didn't catch how much additional sand. You said 2x. I am wondering what the absolute volume was on that job?

The answer to your first part is yes, we are 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 is driving the better performance between lateral length and proppant and fluid pump per stage to number of stages to the way we configure our clusters, to the way we steer in zone. We're really building quite a database to where we can do a lot of correlative work to see what is driving our best performance. That is what is really leading us to test this.

What we are sharing with you today is one of the very first wells where we really tightened 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 proppant pump I think in our normal configuration it is about 4.5 million pounds across the wider spacing. When we doubled up we took that to about 9 million pounds in that SMR 11H.

Great. That's helpful. I'm assuming the SMR 9H is probably the best nearby comp to look at from a well perspective? Recently what is the AFC, say, on the 9H versus the 11H, trying to understand exactly what we are getting for the added cost.

I don't have the exact well costs in front of me on the 9H, but as I mentioned to you, up in this area, DSMR and the PCQ are all in a 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 or three months coming in at about $7 million, completed, hooked up, tubing installation included.

I think what I am trying to tell you is we are continuing to drive our costs down and I think those numbers will show up better in the fourth quarter results. It is a combination of driving cost down, making sure we are getting the optimum completion and trying to get the best economic return on our investment. I think you just have to wait a little longer to see how some of these enhanced completion techniques and our continued decline in drilling costs all play out.

Let me add to that. It is a good point. We really don't want to focus on one well because it can be a really good well or there can be any kind of complications. We want to focus on groups of wells and in particular I will 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 5,000, 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 are getting as much as 20, 21 stages on those. Those are impacting the cost and we are looking at our results in terms of production, both the cum's as well as our anticipated EURs in terms of volumes per lateral length and volumes per dollar invested. That is the way we are shaking it out.

Maybe to try and get at then, what would the cost per stage on the new job be relative or cost per lateral foot? I don't know how you want to try to normalize it. Do you have any color there? If not, that is fine we can circle up later. I'm just try to understand that.

I think I told you on the frac cost per stage, if you really tightened up the way we did on SMR 11 and throw double the sand and fluid concentration, which is really throwing it all at it, that adds about $20,000 a stage.

So in a general range you are looking at 200 to 220 per stage, something like that.

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

Drilling cost would be about the same, yes?

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

That is 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 at a much more optimal zone that is within the Eagle Ford. We have been using seismic inversion to actually do what I would call much more targeted rock quality assessment and steering in that. Basically you have got anywhere from 150 foot 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.

Maybe to give you one other -- I know what you are trying to look at Michael. In the PCQ area, just in drilling costs, our best PCQ well there before was about $3.8 million drilling in pre-complete. This PCQ 12H came in at about $2.7 million, $2.8 million range. Those types of chunks of drilling cost reduction more than offset any tweaks that we are making to the first stage frac cost.

Clearly a good result on the initial productivity. Seems like a positive test. I was just time to understand the apples to apples so I appreciate that color. The other on mine -- would give some good broad strokes around how to think about 2014. That asset sale to bridge the gap between capital and cash flow, should that bridge cover the entire gap? Is that the thought process or how should I think about that as I model things out?

Michael, this is Bruce. One of our challenges in trying to put together 2014 plan internally, much less disclose something to you all is that we don't know exactly what we are going to get in terms of that asset sale and how it is going to be structured. You've probably seen estimates by other analysts out there in the public have a significant range from low to high.

We think we will have some sense of that before the end of the year and can put together a solid budget that incorporates that. I think you 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. We think it is important to strengthen the balance sheet so we're going to try to -- we're going to take the proceeds to obviously pay down debt and then put together a budget that recognizes -- our ultimate goal is to stay within cash flow. But 2014 is a year that we will outspend it to some extent but we've got these sales proceeds designed to help fill that gap. Without knowing the exact amount of that, it's hard to say. Obviously if it's on the lower side we will try to pull back in the capital budget to keep some balance and to strengthen the balance sheet.

Great. That's helpful. I appreciate that color. Two more quick ones on my end. One was on the fourth quarter plan, do you by chance know how many wells you plan to complete in South Texas in the fourth quarter? When the timing of that added rig, does that come on early or towards the end of the quarter?

The rig is easy. The wells drilled from that won't get completed until near the end of the quarter. There might be a little bit of production coming from that. In terms of the number of completions we're going to actually make this quarter --

We are looking at that right now.

We will throw that out here in a moment.

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

I think that's all I've got. Thanks, guys.

Bertrand Donnes, Johnson Rice.

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 BOE ERs?

We have already noted that we have drilled the well and successfully got the initial test data that we were looking for. We really aren't laying out any expectations on a particular rate for this well or a particular volume for this well. We are looking at the overall trend and we do see what other Niobrara plays have been able to do. This is clearly an exploratory well that still has some work to do and the team is working on developing the completion plan for it.

It's also important for everyone to understand that we originally talked about hydraulically fracturing this well so your expectation of rates would be different if you do that. We revised our plan to not initially frac this well. We want to test the productivity of the rock without fracking it so any expectations would be a lot less than if you were to frac the well.

The core data that we have acquired there, it does take time to get that completely analyzed and get it integrated into any future plans.

Just going forward in '14 with an implied flat fourth quarter, should we expect an inflection point ignoring sales with that new rig and possibly some more CapEx in South Texas?

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

Okay. Thanks, guys.

Noel Parks, Ladenberg Thalmann.

Just a few things, for the central Louisiana properties, assuming you sell the entire package, roughly what is the book value you are carrying for those properties?

That is really a hard -- obviously under full cost accounting, the basis in there. We have got a different tax basis and book basis. That is not something that is individually disclosed. Under full cost accounting, your entire portfolio is included in your basis. It is not something that we disclosed.

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

I was getting at implications for tax leakage in the transaction.

There will be none. We don't see any issue, depending on the proceeds, any significant tax affect from this transaction.

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

There was a mention early in the call about Lake Washington and hoping to move forward on the subsalt test there. If I heard right, it was after the 2014 hurricane season? I assume that you meant the spud time as to opposed to when you think you will have some JV in place.

That is correct, Noel. Obviously we will be moving forward before then in terms of making progress on it. I think we just want to be sure we are setting expectations that, that well wouldn't be spudded before the end of the hurricane season. We wouldn't want to have a rig out there drilling during hurricane seasons. If you do not get it spudded really late this year or first thing next year you would really want to wait until about December of next year.

At this point in discussions, for partnerships at Lake Washington, the cast of characters you are seeing, is it essentially the same folks you were talking with say three or six months ago or have the parties changed any?

Lake Washington, certainly as it relates to the subsalt, this has more or less been by invitation only because we are only talking to folks that do those kinds of activities.

To be more specific, we are looking at putting a consortium together, a group together that would properly evaluate the type of test we want to take there. We actually have rights in that area through the center of the earth so there is numerous approaches you could take for a subsalt test. There's also some imaging opportunities in terms of seeing the rock a little differently if we shoot some additional seismic out there. That's 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 is probably enough color on it right now. We are having those discussions, yes.

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 a more conservative, more aggressive attack?

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

Gordon Douthat, Wells Fargo.

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

Yes. That is the current plan. Obviously subject to the finalization of the budget which will be impacted by the proceeds of the disposition.

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 leasehold position -- but generally where are the lateral links, what have they been averaging and where do you see that going in the future?

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

There has been a lot of talk on the cost side of the equation. I am wondering, how many wells do you have under the new completion designs that are on production and then at what point do you feel like you have enough data to start looking at the EUR side of the equation?

I think we said we are 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 length in brittle zone, lateral length in Eagle Ford, the best Eagle Ford zone, we look at proppant and fluid and cluster configurations. 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. We are measuring our 30, 60, 90, 120 day EURs against each of those criteria.

We already believe we have a data set that supports this. You are just now seeing some of the early results of that with that Whitehurst JV where we just increased sand, but more specifically on that last SMR well where we really pumped double the sand and tightened the spacing. That is our early proof that our data will support what our hypothesis is here. I think we have enough data sampling. We are going to start testing it now to make sure that the physical matches what our models are saying.

I am going to add to that, not to further complicate it, but you can only really take something like lateral length if you're going to look at the whole industry and get an answer fast. I think a lot of observers have done that and we certainly have too, that 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. We do see a very significant trend between enhanced or longer lateral's and results.

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 thick is your rock, how porous is your rock? We have very high quality rock in our areas, but each area is different. Precision targeting within these zones -- we have been talking about that. Others are doing that. That is a big factor and of course, as Bob just noted also, the number stages, where you place the stages, the type of treatment you have there. Lots of factors to optimize but lateral length is the one that everybody can see.

It is going to take some time obviously to feel comfortable with a revised type curve when? Is that six months, a year? When do you feel comfortable with that completion design?

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 it any better? I do not know where that is. That is a probably years away but in terms of the big step changes, whether or not we can say they are concrete and they are absolute, certainly in six months to a year you will have those answers.

We are measuring. We want to make sure we are hitting each of our markers, our 30 day, our 60 day, our 90 day, our 120 days. As long as we are hitting those markers on our decline curve, or exceeding those markers, as Terry said probably six month time frame you start to feel more comfortable that you would actually change your decline model based on the new design.

Neal Dingmann, SunTrust.

Morning, guys. I'll try to be brief. Bruce, I might have missed this. Did you all say just in those red areas where you're hitting there in McMullen and LaSalle how many locations you have got left there?

No, we didn't say that today, but I think we've been talking about --

I think we have put that out there in our analyst's --

We'll have to get back with you on that. That is also a factor of down-spacing. So we really need to give that on different spacing assumptions.

I can follow-up off-line on that. One last follow up. On the better part of that Eagle Ford location, I forget now as far as different formations. Is there potential for both upper and lower there?

Yes, think I'll answer that. Definitely potential in the upper, but in some of these areas, not as much as others. For example I think in our Faskin area in South Texas, Webb County, a lot of upper Eagle Ford, I think some other players in that area have noted that you have 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 is still early. We are not touting it by any means, but we are looking at it.

Tom Morgan, Global Hunter.

One last quick one, you touched on this briefly but when you guys go into the longer lateral's in the Eagle Ford and a more complex completions, what does that do on your drilling complete times on those zones?

In terms of going to the longer lateral's and tightening up those spacing, the drilling time in the lateral goes pretty quick. There are days where our guys are knocking out 2,500 feet a day in the lateral section. There is not a lot of added time or even cost for that matter on the drilling side.

On the completion side, the timing is really little difference, how we put the spacing in and how much sand we pump. In fact, in some ways going to the tighter spacing and the tighter clusters we're able to ramp up our sand concentrations more quickly so I do not see any real added time to pumping that different type of job so it is very minimal, if any.

So, Terry I think it was you that mentioned that you've seen drill times going down in some areas. Is that mostly just being able to get the rigs mobilized more efficiently.

Tom, I am sorry, you broke up on us. Could you repeat that?

Terry had touched earlier on that you are seeing some drill times coming down a little bit. Is that just on more efficient rig mobilization?

That is more efficiencies across a whole spectrum of individual operations that are looked at very carefully in the drilling the well. It is a combination of things. It is not just on rig move time or mobilization or how we are walking the rig or any of that. There is a lot of components that are being driven to drive the cost down.

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

David Deckelbaum, KeyBanc.

I'm hopping on a little bit later here, but Terry I was hoping you could clarify a comment you had made earlier about the central Louisiana sale. You said it is a little bit of a different asset, clearly has some conventional aspects to it. The mineral rights, you said that perhaps could be multiple buyers. You had mentioned that maybe a different structured deal. Did you mean in terms of having multiple packages or should we -- how should we think about this and could you add more color on this concept of an alternative structured deal?

Yes, let me add a little more color. First of all, Scotia Waterous has worked with us to put the package together as a single package. It works well as a single package because of where it is located geographically, the kind of rocks, the kind of resource potential that is around it. So in that sense it is a nice area or geographical property package. It has got a lot of the same types of opportunities in terms of horizontal drilling in three different areas.

Within that package it is broken down into three specific areas, Masters Creek, Burr Ferry and South Berry Creek. In that regard, Wilcox, Austin Chalk, it looks and is a traditional package. 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 depths that do not have depth severance. I forget the exact number of minerals of that is in the package but it is over 80,000 acres of minerals in these various areas.

There is also royalty associated in the package that comes from minerals that have already been drilled that are -- predominately 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.

When I say structure, what I mean is you do have to treat even one seller, I mean one buyer would have to work with us to treat these various interests differently in how they are conveyed and we are certainly prepared to do that. We are ready to do that. We will work with whoever the party is that either wants the entire package or if there's some piece of it that they do not want to work with, they will have to take that up with Scotia Waterous and we will see what kind of value propositions there are.

You guys talked about obviously the new completion designs in the Eagle Ford have been very successful. Do you have a sense, preliminarily, what percentage of wells you would put this methodology on as you prosecute the 2014 program or certainly as you go to three rigs now?

I don't want to sound redundant, but there is a lot of factors that optimize production and a lot of factors that optimize your cost from lateral length to number stage of design. Every well is having that approach put to it. As Bob noted, 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. In other areas we control 7,000 foot wells and we think they are going to be extremely good wells with the right kind of completion technology put around them.

Every well is being optimized. That is the first thing to say. 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 deliver ability zone or high drillable zone? Yes and we're going to work that hard. Do we know our hydrocarbon pore volume in every area? Yes and the POC and porosity and thickness zones take a priority. Every well is getting optimized is really the proper answer.

(Operator Instructions )

Andrew Coleman, Raymond James.

David mentioned a second ago or you guys were talking about the royalty piece for those assets. If I'm looking at the PV-10 that you all disclosed in the 10-K, does that royalty factor into that PV-10?

Yes. It would be included in there.

There's a pretty good range. PV-10 is somewhere north of $400 million for those based on eyeballing one of your charts at your analyst meeting a year ago. The production value based on 2.5 thousand barrels a day and 20 million barrels would be a little bit lower than that.

That doesn't sound too far out of the fairway, Andrew.

[Robbie Commep], Global Hunter.

Couple of questions. One on Eagle Ford, I know you haven't determined your CapEx budget but was wondering what each rig would -- how many wells would be expected to drill per year and what kind of CapEx per rig we should think about?

It's a function of a lot of things, as we have been talking. 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, a general number that you can look towards. I think looking at it here a little more carefully, it looks like probably 3 rigs could drill about 45 to 47 wells, something in that area.

What is your average working interest in the Eagle Ford?

Our working interest?

95% to 100%. Sometimes, depending on where the lateral's are you have got a small working interest owner and then in our JV wells, of which a large complement in 2014 probably will not be JV wells, but those are about 50%. We have a 50/50 JV with BHP.

There'll be a small amount of JV drilling next year.

With regards to Southeast Louisiana, what is the estimated CapEx in 2013 and any sort of general thoughts on 2014 directionally relative to that?

I think in 2013 we have had some recompletions. $30 billion to $40 billion I think in 2013 is what the final number will be.

Yes, 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 Clayteks assets.

So $30 million to $40 million this year and about similar amount in '14?

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

Wondering if you have any opinion or outlook for the LOS Brent spread which has gapped out recently?

I think our outlook is probably about as good as anybody. LOS 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 would widens a little bit given where it is today.

There is still obviously a bifurcation.

The market is roughly about $2 plus or minus for both of those right now but you still have a $10 plus spread between Brent and Nymex.

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 flat CapEx in 2014. Is that still the expectation?

You cited some numbers that I do not think we have ever said.

There may be some confusion there. We have not said 15% production growth next year.

Certainly on flat CapEx

Not flat CapEx. That wouldn't make any sense.

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 improve the balance sheet. We are trying to be very thoughtful and not give preliminary guidance for next year. Again, we have noted the Louisiana sale is an important factor in the final determinations of how much growth we would anticipate. Overall we do believe we will be reducing capital spending next year and that we will grow production in South Texas in particular.

Joe Bachman, Howard Weil

Couple quick ones on South Louisiana. One, will you remind us on this potential JV if you're looking at doing it on a prospect by prospect or if it is more of a field level basis?

I'm sorry repeat the question. Are you talking about the subsalt?

Right.

The subsalt prospect would be on a prospect basis. It wouldn't be on a field of basis.

No, we are only looking at the substrata underneath the salt which gets in below the big hum out there which is very significantly determined to be different than all of our Lake Washington horizons.

The last one for me, looking at strategic divestitures, have you had internal discussions about maybe monetizing the one P down in South Louisiana but maintaining the working interest, say 50% or so in that exploratory potential in the subsalt?

That is an interesting thought. Of course we are 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. As to South Louisiana, we do look at different options. We are going through a very rigorous review of the subsalt and even the LI and CC section.

We do not 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 are certainly reviewing that. Again we review it every year, but putting a finer toothed comb on it this year. We need to get through with the central Louisiana divestiture before we make any specific plans for any other assets.

At this time there are no further questions.

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

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