SilverBow Resources, Inc.
Q2 2013 Earnings Call Transcript

Published: 1 Aug 2013

[Operator:]

Welcome to the Swift Energy Company Second Quarter 2013 Earnings 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) I would now like to turn the call over to Mr. Paul Vincent, Director of Finance and Investor Relations. Mr. Vincent. Please go ahead.

[Paul Vincent:]

Good morning. I am Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy’s second 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 of 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’ve also posted an updated corporate presentation to our website this morning.

[Terry Swift:]

Thanks, Paul. And thank you to everyone for joining us on the call today. Swift Energy Company took significant strides towards achieving our 2013 operational goals during the second quarter. Our primary goal this year is been to improve the initial average productions rates and EURs of our South Texas assets by approximately 10%, while reducing our average cost per well by 10%. We are now realizing these results and took step in the second quarter to accelerate our activity in the Eagle Ford, our highest value acreage area. Along with other goals that we have this year, which we’ll describe today. Through an acceleration of drilling and completion activity during the second quarter, we achieved a daily production rate in South Texas during July of approximately 26,000 barrels of oil equivalent per day. Roughly 10% higher than our second quarter average daily rates in the same area. Improved performance, lower cost and demonstrated production response from higher activity levels have led us to commit to maintain at least two drilling rigs in this area, through the end of 2013. We expect this additional activity to add approximately $50 million through our 2013 capital expenditures. Most of the production impact from this additional activity will be felt in 2014 and will support a lower risk production risk profile in the future. We had previously announced that we were contemplating funding this accelerated activity with a joint venture or strategic partnership. After evaluating potential partners interested in developing our acreage with us, and experiencing continual improvement other performance of these assets. We’ve determined that from most attractive financing option available to us, is through a sale of our Central Louisiana, Austin Chalk and Wilcox assets. The sale of these assets what was expected within the next six to 12 months should provide us with adequate capital to fund activity in South Texas as we grow production and cash flows in this area. Any additional capital expenditures incurred before these assets are sold can and will likely be funded through our existing credit facility. We are committed to being a leading Eagle Ford shale player and operator and these steps should reinforce that focus. As we streamline our asset base, our production and cash flow growth profile should become more predictable. We’ve also achieved major milestones with a remaining primary operational goals for 2013. In the second quarter, we drilled and completed a horizontal well testing Wilcox oil sands in Louisiana. We encountered mechanical difficulties during completion activities that will limit the productivity of this well, but we have obtained important information from the formation that convinces this that horizontal drilling and multi-stage completion technology can be used in the development of this oil rich area. With this evaluation data obtained, we believe this asset is a viable candidate for divestment and will be included in planned asset sales over the next six to 12 months. In South West Colorado, we planned to spread our first well testing the Niobrara during the third quarter. With over 50,000 net acres in this area early drilling success may lead to significant upside from this oil rich area. Finally, we have begun working with potential partners on drilling a Subsalt exploration test in our Lake Washington field. Responses from potential industry partners with respect to this prospect had been well received and have exceeded our expectations. There remains a lot of work to do, before we are in a position to drill this prospect, but we believe we’ve cleared the first hurdles of industry peer review. Over the next several months, we will work on a much more detailed technical level with potential partners to prepare the prospect for drilling. We remained on track to have partners identified and committed before the end of the year. With good progress made towards achieving our strategic goals this year. I look forward to the second half of 2013 and to 2014 with excitement. Improved performance in our Eagle Ford operation justify maintaining activity levels in 2013, that should grow us and allow us to meet production levels in 2014, of 15% to 20% growth and increase our total production by 8% to 10% net of divestments. Divesting higher cost, lower priority assets should also improve our base production stability next year and will increase our capital allocation towards our highest reward risk adjusted return projects. We are not satisfied with simply hitting our targets. We will continue to target performance enhancement, cross-savings and value enhancements wherever we can identify such opportunities and now I’ll turn it over to Alton to present our second quarter 2013 financial results.

[Alton Heckaman:]

Okay, thanks. Terry and good morning. I’ll quickly recap our results for the second quarter. Our production came in at 2.78 million and was 53% liquids. Oil and gas sales were $141 million. Income was $6.7 million or $0.15 per diluted share and cash flow for the quarter was $1.67 per diluted share. Our realized price per BOE for the second quarter increased 12% from 2Q ‘12 driven by a marked improvement in natural gas prices. The crude oil revenue still accounted for two-thirds of our revenue for the quarter. As to our controllable cost and metrics, G&A cost came in at $4.03 per BOE which is below guidance. DD&A was slightly above guidance at $21.40 per barrel. Interest expense came in at $6.12 per BOE in line with guidance. Severance and ad valorem taxes were well below guidance at 7.5% of revenue and production cost for the quarter, which include workover’s with the high-end of guidance, well transportation and processing came in well below guidance. As mentioned, the net result was income for the quarter of $6.7 million, or $0.15 per diluted share well above the first-call mean estimate. Cash flow before working capital changes for the quarter came in at $73 million or $1.67 per diluted share while EBITDA was $89 million for the quarter. Quarterly CapEx on an accrual basis was $154 million which includes credit for the sales proceeds received along with the associated asset retirement obligations that were assumed by the buyers from a previously discussed sale by book on assets. We currently have oil collars covering a good portion of the third and fourth quarter expected crude production, along with very attractive collars and floors covering a meaningful percentage our nat gas production for the remainder of the year and as always complete and timely details of Swift’s price-risk management activities can be found on the Company’s website. We continue to maintain a strong balance sheet with the financial flexibility to execute our plans. Our banks reaffirmed a $450 million borrowing base in May providing us with ample liquidity for entered [ph] period $450 million borrowing base in May providing us with ample liquidity funding needs and as always, we’ve included additional financial and operational information in our press release, including guidance for the remainder of 2013. And with that, I’ll turn it over to Bruce Vincent for an overview of our operations.

[Bruce Vincent:]

Thanks, Alton and good morning and thanks to all of you for listening in. Today, I’ll discuss second quarter 2013 activity including our production volumes, our recent drilling results, our activity and in our core operating areas and our plans for the third quarter and full year of 2013. Beginning with production, Swift Energy’s production during the second quarter of 2013 totaled 2.78 million barrels of oil equivalent, within our expected range of outcomes. Second quarter production was 5% lower and second quarter 2012 production of 2.92 million barrels of oil equivalent, but a significantly different production mix of 33% crude oil, 18% NGLs and 47% natural gas compared to 31% crude oil and 15% NGLs and 54% natural gas a year ago. Second quarter production decreased to 1% from the 2.82 million barrels of oil equivalent produced in the first quarter of 2013 that was primarily due to delays associated with drilling operations in our Fasken field along with the mechanical failure of the non-operated Austin Chalk well. The temporary abandonment of the Jelly Bowl well and the completion issues encountered by our horizontal Wilcox test. Let’s talk about drilling results for the second quarter. Swift Energy drilling 14 operated wells during the quarter. In South Texas, all operated horizontal developmental wells were drilled in the Eagle Ford shale formation in South Texas. Six of these wells were drilled in La Salle County, four drilled in McMullen County and two were drilled into Webb County. In Swift Energy’s Southeast Louisiana core area, one well was drilled in the Lake Washington field and the Company’s South Bearhead Creek field on well was drilled during the quarter. We currently have three operated drilling rigs South Texas drilling Eagle Ford shale wells. In the Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields, production during the second quarter averaged approximately 5,075 net barrels of oil equivalent per day, which was up 2% when compared to the first quarter of 2013 average net production in the same area. Lake Washington by itself averaged approximately 4,785 net barrels of oil equivalent per day, an increase of 3% when compared to first quarter 2013 average daily volumes. Average daily production in Lake Washington for the quarter was in line with our expectations. We expect to perform minimum levels of recompletion workover activity with no new drilling activity in Lake Washington for the remainder of this year. Bay de Chene production of 290 net barrels of oil equivalent per day was down 8% when compared to first quarter 2013 production levels due to natural declines and low levels of operational activity. In our South Texas core area, which includes our AWP, Sun TSH, and Las Tiendas Olmos fields, and our AWP Artesia wells and Fasken Eagle Ford fields? Second quarter 2013 production remained flat when compared to first quarter 2013 production in the same area. Averaging 23,328 net barrels of oil equivalent per day. During July however, our daily production rate averaged approximately 10% higher than our second quarter 2013 average. Second quarter South Texas production was also relatively unchanged when compared to second quarter 2012, but as I mentioned our production mix value is been enhanced by the greater percentage of production being crude oil and natural gas liquids than it was a year ago. During the quarter, we did experience drilling delays in our Fasken area and Webb County Texas causing produced natural gas volumes to be lower than we had anticipated at the beginning of the quarter. Earlier this morning, we published specific information on wells brought online in this area, during the quarter in our quarterly press release. So I’m going to go through those at this time. In the Central Louisiana East Texas core area, which includes our Masters Creek, Burr Ferry and South Bearhead Creek fields contributed 2,110 barrels of oil equivalent per day of production in the second quarter of 2013 that was a decrease of 24% over first quarter 2013 production in the same area. Lower production levels in this area, are primarily due to the mechanical failure of the non-operated GASRS 29-1-10 well which we drilled earlier this year, along with the sale of the Brooklyn field, which occurred during the quarter. I’ll now turn the call over to Bob Banks to review operational highlights for the third quarter.

[Bob Banks:]

Thanks, Bruce. First and foremost and as Terry already mentioned. We are increasing our capital spending on our South Texas Eagle Ford assets based on the continued improving performance of those assets, that strategic decision leads us to proceed with adjusting our Central Louisiana assets. We believe these are high impact high quality assets that, during the near-term will not compete for capital with those South Texas Eagle Ford program. There is strong market demand for these types’ only assets that have an inventory of development drilling and performance enhancement opportunities as well as exploration appraisal upside in untested horizons. We are early in the divesture process and expect to finalize the sale of these assets in the next six to 12 months. These asset sales will enable us to redeploy capital to our highest value South Texas Eagle Ford assets, while managing debt under the bank line. We’ve established a very solid base of Eagle Ford production and believe we can grow South Texas production starting [ph] with accelerated levels of activity. In example of this potential is our July production in South Texas which is tracking approximately 10% ahead of our second quarter average. I’ll recap our South Texas activity and strategy further after the brief review over Louisiana assets. During the quarter, we did drilled one well, the LL&E #6 which is located at the southern extent of the Lake Washington field. This well encountered more complex geologic conditions during drilling operations than were expected. As a result, we decided to temporarily abandon the well to collect more data and totally assess the potential to either reenter or re-drill the well at a later date. Also in Louisiana, our first horizontal test to the Wilcox formation in their South Bearhead Creek field, the James O. Dolby 1H well was drilled during the quarter. We successfully proved that this field can be effectively exploited with horizontal drilling and completion technology. We offloaded continuously for 10 days at a rate of 200 barrels of oil per day, in spite a part in the casing that occurred while running the expandable packer system. This first well did achieve a number of our valuation objectives as we were able to retrieve valuable core, log and flow test data. It does confirm the horizontal Wilcox development at South Bearhead Creek has great potential for the future. In Vernon Parish, our partner recently drilled and ran the completion assembly in the Indigo 17-1 well in the Burr Ferry field, after this well is tested and in production during the third quarter. We anticipate no further activity in the area by us or our partner for the rest of 2013. As mentioned earlier, the temporary abandonment of the LL&E #6 well in Lake Washington and the impairment of the Dolby, Wilcox well in South Bearhead Creek, will lower our full year 2013 production volumes by approximately 220,000 barrels of oil equivalent. Moving onto South Texas, due to faster drilling times lower Wilcox and the availability of equipment. We did briefly deploy five drilling rigs and two frac crews during the quarter. This additional activity was focused primarily in our LaSalle and McMullen County acreage, where we have demonstrated 18% and 15% higher initial production rates of new wells respectively, as well as 54% higher two-year expected reserve recoveries in LaSalle County and 25% higher two-year expected reserve recoveries in McMullen County. We’ve begun using the two-year reserve recovery metric for each of our areas to ensure that our early time production time data is performing to or exceeding our model total EURs for each of our development areas. When these performance improvements are coupled with well costs that are routinely at least 10% lower, then wells drilled in the same areas last year, we came to several conclusion. The first thing that we are convinced that focusing on our lowest risk, longest life, crude and liquids rich reserves and production assets will be the most accretive growth activity for our stakeholders and at monetizing our less predictable Central Louisiana assets will allow us to finance gaps between cash flows and capital spending over the next 18 to 24 months. This is important because as of today, excluding any dry gas acreage at all. We believe that we have an inventory of 500 high quality Eagle Ford drilling locations with expected initial performance, reserve recovery in cost similar to the wells we disclosed today in our press release. We are continuing to explore various strategies to develop our highest value Eagle Ford dry gas acreage as there continuous to be interest in these assets. In that regard, we’ve recently successfully downspace two wells in the Fasken area to approximately 60 acres and are very encouraged by the results thus far. We have also completed a third-party reserves assessment for our Fasken area and this work has confirmed to us, that this is some of the best Eagle Ford geology in the trend. We have done the difficult work required of a company developing it’s for shale play and are prepared to accelerate the growth of our Eagle Ford asset methodically and cost effectively. We expect to fund our growth through cash flows and non-core asset sales and will be in a position to deliver double-digit production growth from our South Texas assets alone for the next several years. We made strides towards achieving our strategic goal this year, but are very much aware that we have to continue to focus and gain efficiency in our South Texas Eagle Ford assets. As these assets that will form the foundation through our performance in growth over the next several years. With that, thank for your attention this morning and I’ll turn the call back to Terry.

[Terry Swift:]

Thanks, Bob. Before we open the line for questions. I’ll summarize Swift Energy’s quarter results and review some of the highlights from today’s call. In South Texas, we are on track in meeting one of our primary goals for the year of improving our initial production rates and EUR estimates by at least 10%, while at the same time reducing our cost per well by at least 10%. Due to improved performance on lower cost, we have increased our activity level in South Texas to afford for higher levels of growth in that area. We have committed to a strategic shift in our operations through the divesture, we’ve initiated of our Central Louisiana including our Austin Chalk and Wilcox properties. This asset sale should provide additional capital for us to increase our focus on our best acreage, our liquid rich area, the Eagle Ford shale. We expect to spread a horizontal well to test the Niobrara formation and La Plata County, Colorado during the third quarter. We also expect to announce that we’ve secured a partner interested in drilling a Subsalt exploration test in our Lake Washington field before the end of the year. Finally, we are expecting third quarter production levels to increase over second quarter by 9% to 13%. With that, I’d like to begin the question-and-answer portion of our presentation.

[Operator:]

(Operator Instructions) our first question comes from the line of Welles Fitzpatrick with Johnson Rice.

[Welles Fitzpatrick:]

On the Jelly Bowl and Dolby, should we be applying that on 110 only to those, directly to the second half guidance or is that going to be offset by the Eagle Ford, I think you said you already, 10% ahead of 2Q in the Eagle Ford already?

[Bruce Vincent:]

Yes, we are quickly the guidance we have out today is adjusted for everything, we’ve learned as of this date. Obviously I think, inherently implies that we are increasing production estimates in some areas to compensate for some of that, but the guidance we put out is reflective of what we know today.

[Welles Fitzpatrick:]

Okay, great. And then just one modeling one, do the $36 million of the Central Louisiana CapEx is that basically all out the door, is some of that going to be able to offset, the $50 million in the Eagle Ford?

[Bruce Vincent:]

In terms of capital spending, I think that’s been the capital spending program in that area. So there is not any net down, but I do want to reiterate that we still do have some fairly nice activity and recompletions in South Louisiana, some things that are going on that will keep going and again that’s all in our guidance, both the capital and the progression.

[Welles Fitzpatrick:]

Okay, perfect. One last one, can you give us a reminded the 88,000 mineral acres that you guys have in Central Louisiana. Where are those and do you have a broken out PV-10 for the Central Louisiana assets?

[Bruce Vincent:]

We don’t have a broken out PV-10 for you at this time and of course the way all that’s done, it’s getting a little stale as it is right now. We will update that year end, but more importantly the acreage that you’re referring to is located generally in the Burr Ferry and between Burr Ferry and Masters Creek slightly to the Northwest of Masters Creek. A lot of it is free acreage, some of it’s never been drilled. A fair portion of it has been in our Burr Ferry and Anadarko venture as we get a little farther along putting the assets and allowed to, that will become very clear to everyone.

[Unidentified Company Representative:]

Some of it’s actually, north of the Anadarko. It’s not part of that AMI.

[Welles Fitzpatrick:]

Okay, perfect and thanks so much.

[Unidentified Company Representative:]

Sure.

[Operator:]

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

[Noel Parks:]

Good morning.

[Terry Swift:]

Good morning.

[Bruce Vincent:]

Good morning, Noel.

[Noel Parks:]

Just wanted to get some background from you on the Eagle Ford evaluation process you went through. I believe, you did get us as far as the opening a data room and so forth. So I’m just curious about, what sort of buyers you saw and also what was missing in terms of what you needed to see in order to feel comfortable getting a deal?

[Bruce Vincent:]

It’s Bruce. I’d probably break that up into two pieces. One; let’s talk about the perspective buyers and the process we went through. We retained J.P. Morgan and we really identified perspective candidates in two caps of the strategic buyer mainly the Asian buyer that we are seeing back typically in 2010, ‘11 and ‘12 and then more of the financial institution buyer, which is institution’s cooling [ph] capital to invest in this business. And we did have a lot of good conversations with a number of those people. We did have people in both the strategic side and the institutional side interested in doing something, but that process also brought us to do a full strategic review of all of our assets and look at our various opportunities for growth. And in the end, realistically the JV market is not today what it was in 2010, ‘11 and ‘12. While there are some players, they’re not paying the kind of premiums that they were back in those days. Those that had basically paid the premium for strategic reasons to technology transfer and things like that, we’d already done that. So they were looking at things, a little bit differently. And what we really ended up looking at, was the fact that our Eagle Ford assets were really the best assets on a risk adjusted basis that we have in this company. And when we looked at, you have to get a significant premium to the valuation, to justify parting them, even a portion of those assets because that in our view is our lowest risk areas for substantial growth over the next several years. And so we made really a more of the strategic decision based on where we wanted to direct our capital and then as a consequence to that. We wanted to fill the funding gap. So we really made a decision to liquidate one of the areas that we’ve been involved in long time and still has a lot of opportunity, but we’re looking at our capital allocation. We are not going to be able to devote much capital to the Central Louisiana area, so it made a lot more sense to put it out for disposition, where it be worth more to someone else, it was the road [ph] capital to it. And then we can focus our capital in the area of South Texas Eagle Ford, where we are having tremendous success. We are making great strides with improvement, we are increasing performance, increasing IPs, we are increasing EURs. We are increasing the two-year measure of recoveries that we are looking at, which we think is actually much more accurate, than looking at full term EUR and we are decreasing cost. And we believe we can continue to do that, particularly as we take it into manufacture and so our decision ultimately came more from strategic thinking about it. Where we are best served accomplish growth particularly on a low risk adjusted basis then it did about creating a joint venture, which is in fact selling a portion of the asset to somebody else.

[Terry Swift:]

Yes, this is Terry. Let me just kind of reinforce what Bruce said, with just a thumbnail comment. We never said, we were going to divest of our Eagle Ford assets. We always said, that we would be looking for partner who would help us accelerate that, a joint venture partner and in that process as Bruce has noted, the market change, other things change but one thing became very apparent that a lot of folks that are now out there in the joint venture market are really looking for gas that got a longer term horizon. They’re more interested in 2016 and ‘17 and so that maybe an area that we continue to look for some of that kind of activity, but as to our liquids rich or Eagle Ford acreage. It’s prime and ready for us to develop.

[Noel Parks:]

Do you envision, running more active Eagle Ford is getting you back to being able to have a dedicated frac crew full-time then?

[Terry Swift:]

The dedicated frac crews are not as necessary, if necessary at all compared to early time horizon. If there’s a lot more horsepower available out there. Certainly we do pay a lot of attention to which crews we get in particularly efficiency of those crews, the ATSE [ph] issues but at present I don’t think that’s necessary to run a program. Let’s say two to five rigs. We just don’t have that necessity anymore.

[Bruce Vincent:]

Yes, I think it is fair to say though well. Well, all the plan for the remainder of this year is have to two rigs exactly down there. Our correct preliminary plans for 2014 have a more aggressive level of activities in two rigs.

[Noel Parks:]

Okay and then just the last one for me. Just to maybe put some numbers to this, when you compare to what you were thinking in back and say March timeframe about getting a partner at the Eagle Ford. Can you give us a sense of maybe the relatively stronger returns, you now foresee from efficiencies and your progress of completion compared to maybe best case of what you were looking to get out of Central Louisiana.

[Bob Banks:]

This is Bob. Let me take a crack to that as Bruce I think said, in a risk adjusted basis. One of the issues. I’m sure everyone is seeing is, the consistency and repeatability in some of the Louisiana assets and so when we take a risk adjusted basis. Obviously improving these IPs, improving the two-year EURs, lowering our drilling cost in some cases substantially, even prior to getting into the pat and manufacturing drilling. It really starts to stand out that the liquids rich areas of the Eagle Ford are highly valued. And I’m thinking South Texas in general is probably now with some of these improvements in the 60% to 80% rate of return range. So when we risk adjust that’s really fantastic, now the Austin Chalk and Burr Ferry with the minimal interest. Those are very strong economics, but we’ve continued to have some repeatability issues in those assets.

[Terry Swift:]

This is Terry, to leave it off what Bob has said. You know it’s hard to be all things to all people and clearly one of the things a smaller company like Swift Energy has to do is focus and the shale play requires a tremendous amount of focus and we’ve honing our skills, the service company alliances that we’ve had whether they’ve been formal or informal, they become very valuable in developing the shale and so a large part of it’s also that we are focused on South Texas now and for an operator that would focus on the Austin Chalk or North Louisiana assets. There’s a great opportunity there, but we just can’t be all thanks to all folks.

[Noel Parks:]

Thanks, that’s it for me.

[Terry Swift:]

Thanks, Noel.

[Operator:]

Our next question comes from the line of David Deckelbaum with KeyBanc.

[David Deckelbaum:]

Good morning, everyone. Thank you for taking my call.

[Bruce Vincent:]

Good morning.

[Terry Swift:]

Hi, David.

[David Deckelbaum:]

I guess my first is, the decision now that you look to divest to Central Louisiana. You had I guess, a geological success at Wilcox. Do you really think that now is, an appropriate time to be divesting that asset based on what is known of the future potential there? Do you think it’s realistic that you’d be able to get anything more than and a value for production. I guess is there, can you give us an estimated range of what would be acceptable in terms of proceeds that would allow you to accelerate the Eagle Ford program?

[Terry Swift:]

Well, this is Terry. First note, the assets that we’re going to put out there in Central Louisiana are a diversified set of assets that have production from the Wilcox and the Austin Chalk, but also have significant upside potential and other types of targets. The Saratoga has been a potential target in that area for some years. You’ve got deeper horizons, when you look at minimal interest. It’s a whole different evaluation that goes on because we own those in fee, we’re almost owning in perpetuity, the way they’re constructed and there you have basically the center of the earth and you don’t have a three-year, five-year lease terms with those, you own them. So it would be likely that you would see this package as we put it out, broken out then to its constituent part and obviously our desire would be to have, one better come in and pay the best value for all the parts, but as we go through this process. We will see what the optimum value is for undeveloped probable types of opportunities, producing opportunities, (inaudible) they’re sitting there ready to drill and minimal acreage that can be held on almost perpetuity and lease and released in royalty taken far and so. So I think it’s premature for us to say, here’s what we think the market is going to bring to us. Other auction folks that are going to make some estimates. People already making estimates, based on metrics that are out there on per barrel or per acre type metrics. So those maybe meaningful to use, but I think we are going to go through I know we’re going to go through a process that’s going to get the best value for all the individual assets in there.

[David Deckelbaum:]

Okay and I guess, you made some mention earlier about, all the work that’s been done in Webb County and the downspacing believe that’s some of the rock in Eagle Ford, but obviously it’s a gassy [ph] area. Is that considering that you’re trying to grow on the liquid side, do you think there’s an opportunity just divest of the Webb County acreage to accelerate the liquids portion of the portfolio?

[Terry Swift:]

You know that’s probably one of the best questions, I’ve heard because I actually struggle with that. Our strategy is always been to be balanced in both liquids and gas. And if Fasken were a different type asset, I might quickly answer yes, but it’s such high value, high quality, Eagle Ford rock that even in this environment. It gives reasonably good economics even at $354 gas, not near as good as the liquid though as you point out. So to the extent that we could have a joint venture that would accelerate Fasken. I think that’s definitely something we would consider even pursue, but in outright sale of it, in today’s market, with today’s gas prices probably not likely.

[Bob Banks:]

There is one other thing, this is Bob. Is that we have earned all of that acreage in Fasken, so we are really not obliged to drill at a pace that we are not wanting to drill at.

[Terry Swift:]

Yes, your other question related to the downspacing activity that we’ve conducted there, the results we have. I’ll pass that directly to Bob. He can give some more color on that, but we did have a third-party come in because we are again a company with a strategy to make sure over the long-term horizon. We do have balance. We are definitely liquids focused at the moment, but we have a nice inventory of what I call parked gas that we continue to make some profit from certain areas in that parked gas. We had an evaluation done specifically in Fasken, where went to a third-party just to get another sense test and compare this rock to other types of shale plays and the numbers came back extremely good and whether they hit our numbers or not, they were within 10% roughly and the whole issue really is, how successful will downspacing be, where there our numbers are right there, but we are still little upwards at the 800 Bcf range in that area, in terms of growth reserves over that area. Bob and that’s not a proven number in today’s gas price environment that’s just the potential number there. Bob?

[Bob Banks:]

Yes and just to add on that a little bit at 60-acre spacing, so far we are liking what we are seeing from these down spaced wells. If we can drills these on 60-acre spacing, that’s about 122 locations there. We’re equivalent to around a TCF of gas, when you run the sensitivities on gas price for an asset like that, the way the returns improved dramatically with small moves in gas price is quite amazing. Add to about 450 gas is an example, we are in the 80% rate of return range for this Fasken type of asset. So if Terry said at $4, we can make money but at $4.50 the rate of return really start ramping up, anything more from there, it gets really, really good. So we are looking at some strategic options for that particular position, but we are not ready to just let go of that totally you missed, the type of returns that we can generate out of an asset like that.

[David Deckelbaum:]

Okay and if I could just ask one more, I guess you mentioned that your run rate, I guess July so far is been 10% above the 2Q average in South Texas, how much of that is attributed to bringing on the two wells in the Fasken towards the end of the quarter?

[Bob Banks:]

Well some of that is been there, but we’ll also note that our liquids has grown in the equivalent amount, so I think that’s really in the corporate presentation. I think you might have access to this slide 10. You can see that, at first quarter you continue to splitting’s between gas and liquids and you can see that, we’d increased our liquids 10% as well.

[David Deckelbaum:]

Thank you, gentlemen. Have a good one.

[Terry Swift:]

Thanks, David.

[Operator:]

Our next question comes from the line of Neal Dingmann with Suntrust.

[Neal Dingmann:]

Hi guys.

[Terry Swift:]

Hi, Neal.

[Neal Dingmann:]

First question probably for Terry more just kind of Terry, a strategy question I guess or maybe for your, Bruce. When you see kind of going forward, I guess when you look at just sort of, I guess just looking at free cash flow. Are you trying to balance now, I mean depending I guess what happens with the Central Louisiana assets is that going to impact just by how much you continue to accelerate your South Texas. I guess, I’m getting it, trying to get an idea as we look at sort of an yearend extra rate or beginning next year of how to look at sort of, what you guys are even melting [ph] or modeling this far as cash flow versus CapEx.

[Terry Swift:]

Obviously, when we say 12 to six months in terms of asset sales sooner is better than later and as we look at the value that would come from that asset sale, we want the highest value, but internally we have different numbers. Certainly, if there are pieces of that package that don’t get the right kind of value. We won’t let go of them, but overall we think, we’ve constructed the strategy that ought to bring significant capital into ensure that we can get into ‘14, have some good success, get rigs and momentum up to about four to five rig level and the cash flow, of course that comes from that factored in and deliver corporate production growth in the 8% to 10% range next year, with preliminary numbers. We are not to (inaudible), these numbers for the reason I stated, preliminary numbers that would have a capital budget similar to this year, that’s kind of the big picture drivers. We clearly will use our line of credit somewhat as a bridge through this and there are other activities that we have under way that, we are going to make sure that we are comfortable with our spending next year to accelerate the Eagle Ford.

[Bruce Vincent:]

I mean, Neal I think expectation Neal is that the disposition of these assets would cover the funding gap next year. The funding gap between now and the end of the year, will obviously be drawn a line of credit, but we think we can have a level of capital spending next year that accomplishes 8% to 10% growth, but it’s fairly neutral given the asset disposition.

[Alton Heckaman:]

Even the funding this year, when it gets us up below half the current borrowing base and obviously with success to borrowing base skills up, we are toward the top of our leverage appetite but, we’ve got the liquidity cover this and get more toward a cash flow neutral position going forward with success.

[Terry Swift:]

I think, Alton is sitting on some of the financial strategies there that we really don’t want to become more levered and we are showing you that we are taking the steps to see that doesn’t happen and again, we are going to push with all of our metrics financially to actually lower the use of our borrowing base in terms of the percent of the liquidity used and then in terms of a liquidity availability being stronger.

[Neal Dingmann:]

Great response guys and then moving over to just South Texas looking number one, maybe for Bob just kind of averaging, how much it seems like some of our Wilcox maybe had come down a little bit and then secondly as we look at La Salle, Webb and McMullen, where do you sit as far as just holding acreage there? I think, if I recall you’re in pretty good position.

[Bob Banks:]

Yes, we’re in pretty good position. As I mentioned earlier in Webb County, we are holding that entire position. We were able to earn all of that in kind of the Southern AWP area, which is more into the gas and the condensate. We are holding that under some different kinds of arrangements for a while. So we’re in reasonable shape there, so what we are really constructing for next year Neal is to drill most all of our activity in that North AWP area, where we are getting some really good results. We’ve showed you the, some of the PCQ results and that we are getting there. We are also going to concentrate in that bets [ph] area out in Artesia wells you can see the kind of rates we’re getting there. In terms of Wilcox, we’ve brought those down now or anywhere from about $6.5 million to $7.5 million in these liquids rich area. So the guys are doing a phenomenal job in bringing our cost down in drilling and completions and it’s some of that performance improvement on all sides of this that has us very encouraged about focusing into those liquids rich areas.

[Terry Swift:]

And Neal, by the way if everyone listening. We’ve refreshed our corporate presentation. It’s currently out on our website that you pulled down and slide 11, is really compelling slide that shows how we work those well cost down in South Texas.

[Neal Dingmann:]

Very good. Thank you all.

[Bruce Vincent:]

Thanks, Neal.

[Operator:]

(Operator Instructions) our next question comes from the line of Adam Light with RBC.

[Adam Light:]

Just on Central Louisiana. First of all, have you got an updated mid-year reserve estimate?

[Bruce Vincent:]

Adam, we mentioned earlier that we don’t have a refreshed net present value approve and report, that we want to refer to right now. We are working with various parties and we will be coming out with a complete brochure then goes through all the reserve opportunities that are there in the various types of categories, producing metrics versus probable reserve metric, so that’s going to be forthcoming pretty quick. But we don’t have anything, to show you right now.

[Adam Light:]

Okay, I got no PV. I didn’t hear the reserve report. Can you give us a sense of as of last year, what the proved developed component was there and what the current mix of production is?

[Bruce Vincent:]

We’ll look that up and put in, Alton is going to give you a number here.

[Alton Heckaman:]

And that should be all right in the 10-K, Adam.

[Bruce Vincent:]

But I think the production right now is about 2,500 barrels of oil equivalent and probably about 50% liquids, 50% gas that’s kind of a general metric.

[Adam Light:]

I guess, one of the things I was trying to get at as if, what you might seeing the borrowing base change with a sale, would it be a dollar-for-dollar?

[Bruce Vincent:]

Believe me, we looked at that Adam among a number of things and for example in the second quarter, the assets we’re talking about represented about 8% of our revenue. As Terry mentioned, was trying quantify that you’ll clearly undervalue these assets.

[Terry Swift:]

That area averaged 2,110 barrel of oil equivalent per day during the second quarter.

[Bruce Vincent:]

There you go. Yes, I think generally speaking. We need to know that again it makes it so flip up, a lot of different components. So crude producing yes, there is some undeveloped opportunities that are proving yes, there are some but it’s got a tremendous amount of mineral acreage that really shouldn’t be evaluated in the same context of working interest, fee acreage that’s in perpetuity as well as lot of potential reserves and probable reserves. So we need to go to the market and find some folks to focus on those types of things to give them opportunity to bid on it.

[Terry Swift:]

And specific Adam to your question about the borrowing base, again one the things that we clearly look at in and something like this. We think that will be more of an offset by the success, we are having in South Texas.

[Adam Light:]

Right and I got that. Okay and I didn’t hear if you said, when you might be opening up the (inaudible)?

[Bruce Vincent:]

As we are indicating, we expect to have this done in six to 12 months getting ourselves some room there. Obviously as Terry also said, the sooner is better than later. We are in discussions with several intermediaries we’ve not selected winners, as of yet. We expect that to happen in fairly near future and then we’ll go through that process of doing all the work, to get the data run together and we hope to have that batch early fall.

[Adam Light:]

Okay, that’s great. Thanks. I’m going back to Fasken for second, you said 80% returns at 450, give us a sense of where the breakeven or 10% type of return breakeven might be able to ask prices.

[Bob Banks:]

Yes, I think we looked at that just on believe it or not on pure economics. Yes, we think it’s around PV-10 by $2.40.

[Adam Light:]

Okay, that’s great and then on subsalt.

[Bruce Vincent:]

We’re not going to drill $2.40, won’t breakthrough capital.

[Bob Banks:]

Yes, we are not drilling on.

[Adam Light:]

Good. On the subsalt, do you have a timetable for when you might have a decision on what’s going to happen?

[Bruce Vincent:]

With regard to Fasken or (inaudible)?

[Adam Light:]

No, Subsalt sorry.

[Bruce Vincent:]

Subsalt, what we’ve indicated as we’ve – these processes take time and while we are getting good feedback and as we noted in the call that believe that we passed those first test in peer review and such, realistically it’s going to take till the end of the year to get an actual joint venture both agreement and papered and then a plant to go forward as to (inaudible).

[Terry Swift:]

Yes, I would add that, our approach has been to only really good at top tier companies that we believe are well and priced of what kind of target and what kind of risk and rewards, what kind of operations were involved. So they necessity will have a big role in how we put this together. So as we began our discussions with such companies, we are giving them some latitude to also shape the kind of project they’re going to be in.

[Bruce Vincent:]

It’s not designed to send this out to 50 or 100 people. I mean, we’re really going to talk to probably at single-digit side in terms of the number of people we talk to, but very high quality names and doing in a very methodical way. You want the right partner, not just a partner.

[Adam Light:]

Right, okay. That’s great for me, thanks.

[Terry Swift:]

Thanks, Adam.

[Operator:]

Our next question comes from the line of Andrew Coleman with Raymond James.

[Andrew Coleman:]

Thanks a lot folks and good morning. We had the question – could you just run it through again just the ranking exercise, that you guys for the side arms in the Central Louisiana versus South Louisiana or pieces there are of – targeting for divestiture and would you consider down the road, if you need more capital next year to kind of look at those assets too?

[Terry Swift:]

Well I think the ranking process really starts with Texas performing so well. We are just very, very pleased with Artesia, AWP, liquids area, our condensates areas. As we noted, we are very pleased with Fasken, albeit it’s not the right time to go into for development there. So when we look at the growth profile, the company, the risk profile, the company. We really decided that we need to make sure, the capital got allocated to the best assets. So what that meant, look at the other assets, see what their allocations of capital might be in order for them to be developed and compare those development plans and capital needs to South Texas and the first one that kind of hit the ranking was the Central Louisiana assets. One respect is because there’s a lot of upside potential there and a lot to do in the way of development or appraisal and even exploration along that acreage play, but that’s not where we would be putting our capital. So it really rose to the top in terms of near term opportunities, where capital can be deployed quickly in that area and growth can occur, but it needs more activity and we are not just prepared to be doing that compared to our other asset. South Louisiana on the other hand, still quite a cash cow for us in its own right. Lots of small opportunities to do in the way recompletion, that are just great capital projects and of course we have the subsalt activity going on there. Your final question really is, would we consider other divestitures to fund our best growth projects. I think the answer has to be yes, but are they necessary at this time. Our conclusion is no and should we continue the process of looking at other assets and capital allocation. It’s going to be done the same way, where does the best capital go and like Washington is certainly been a great assets for us, so if the next time we make these decisions. It’s got great capital opportunities, then it will stay in the fold. If not, then we will take appropriate steps.

[Andrew Coleman:]

Okay, up other ones on the Central Louisiana assets and do you measure partner there in the JV, how many roafers [ph] or would the fact you have a JV there providing sort of complication that kind of divesting those assets.

[Bob Banks:]

Yes, Andrew it is Bob. You know actually, some of the leases are beginning to expire that we granted to that partner. So it’s kind of mixed bag, some as already back with worth 100%, others still have time to play out. They have clearly diverted their capital for the remainder of this year, so we just still have to work through some of that with our partner, but the answer to your question is kind of mixed, as to making this, a clear transaction going forward.

[Terry Swift:]

I’ll add to that. We’ve all not to avoid using their name, but we’ve always had good relationships with Anadarko. They’ve operated these wells and certainly have a lot of respect for them as a company, they too have capital allocation things going on, I’m sure, but at the end of the day. We really are the big mineral owner and fee owner in this area. We are the ones that collects the royalty on a substantial amount of this production and so as we are looking at the plan and development, we want a more substitute plan and development going forward. Should we remain royalty owner there or we sell it to someone, who will get that substitute plan and development.

[Andrew Coleman:]

Okay and can you give us a little bit of flavor on just the interest that you all have seen so far, I guess may break it down into perhaps a mix of unsolicited interest versus kind of what you got in sense, perhaps the press release in the last couple of hours and I guess or have you been surprised by some of the interest that you’ve seen so far?

[Bruce Vincent:]

Andrew, it’s Bruce. We are not engaging intermediary at this point and I didn’t putting anything out. So obviously, so the market even be aware they’re planning to show these assets, they’re going on a couple of hours’ notice. So we are not having any enquiries to this date, but we in conversations with a number of intermediaries, we are going through that selection process. They believe, that there will be a very strong interest reduced properties. There’s they’re not just approved producing component, but there is a lot of upside to it and they’re very oily property. So our belief is that, we have very good interest for these. I don’t know whether it’s a single buyer of multiple buyers. They’ll know at this point in time, but we feel pretty confident we will go through a pretty good sales process and have good competition.

[Andrew Coleman:]

Okay and the last question is, again the Masters Creek does the actual minerals on there, I guess is that is this only area in the company where we all own out right and yes? I guess that’s just.

[Terry Swift:]

Yes, outside of Louisiana really is the only place where we have any significant outright single ownership and specifically to Masters Creek. We don’t have a lot of minerals directly in the field, we do have minerals north and Northwest in the field.

[Bruce Vincent:]

And that’s in addition to the Burr Ferry mineral acreage, not to get those confused. So both are significant.

[Andrew Coleman:]

Okay and could you, I guess confirm then you’re looking to sell that mineral of acreage fee, you guys wouldn’t keep override or small piece of it just for auction right now around.

[Bruce Vincent:]

Well it all comes to the value that comes out of the transaction but I will say this. We made a strategic focus decision to focus in South Texas and so any residual interest that we might have keep in that area will be only because of our need to, want to monetize in the most favorable way. We are not focused on also Louisiana going forward strategically.

[Andrew Coleman:]

Okay, thank you very much for your time and good luck.

[Bruce Vincent:]

Thanks, Andrew. Thanks.

[Operator:]

(Operator Instructions). Our next question comes from the line of Tom Morgan with Global Hunter Securities.

[Tom Morgan:]

Hi guys, just a quick question about the Eagle Ford. Just with the in efficiency improvements, did you have seen there and the plans to increase the activity awareness second half of the year? Just wondering, how many wells do you guys are looking at completing the second half of this year versus what you plan on drilling that might be pushed backed into 2014?

[Terry Swift:]

Yes, I mean with the two range. We are probably in the range of another 10 to 12 wells in terms of completion and probably in the five to eight range within this year, with the remainder early next year.

[Tom Morgan:]

Okay.

[Bruce Vincent:]

And most of that well in the year.

[Terry Swift:]

Yes, towards the late end of the year.

[Tom Morgan:]

Okay. And just a quick revisit to Central Louisiana. Do you guys plan to carry those assets as discontinued operations going forward or not?

[Bruce Vincent:]

No based on our current accounting practice, that would not be necessary, not significantly.

[Tom Morgan:]

Okay, thanks guys.

[Terry Swift:]

Thank you.

[Operator:]

That concludes today’s question-and-answer session. We have no additional questions presented. I’d turn the call over to you for closing remarks.

[Terry Swift:]

Okay, we thank you everyone again for joining us today. We look forward to presentation next quarter. Thank you.

[Bruce Vincent:]

Thank you.

[Operator:]

Ladies and gentlemen that does conclude today’s conference call. You may now disconnect.