SilverBow Resources Inc (SBOW) 2013 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Swift Energy Company's second-quarter 2013 earnings 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 call over to Mr. Paul Vincent, Director of Finance and Investor Relations. Mr. Vincent, please go ahead.

Good morning. I'm 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 second 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've also posted an updated corporate presentation to our website this morning.

Thanks, Paul. And thank you to everyone joining the call today. Swift Energy Company took significant strides towards achieving our 2013 operational goals during the second quarter. Our primary goal this year has been to improve the initial average production 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 steps 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 rate in the same area. Improved performance, lower cost and a demonstrated production response from higher activity levels have led us to commit to maintaining at least two drilling rigs in this area through the end of 2013. We expect this additional activity to add approximately $50 million to 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 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 of the performance of these assets, we've determined that the 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, which is expected within the next 6 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 our remaining primary operational goals for 2013. In the second quarter, we drilled and completed a horizontal well, testing the 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 us 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 6 to 12 months.

In southwest Colorado, we plan to spud 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 remain 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 operations 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, and we'll continue to target performance enhancements, cost savings and value enhancements wherever we can identify such opportunities.

Now I will turn it over to Alton to present our second-quarter 2013 financial results.

Okay, thanks, Terry, and good morning. I will quickly recap our results for the second quarter. Our production came in at 2.78 million barrels, 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, but crude oil revenue still accounted for two-thirds of our revenue for the quarter.

As to our controllable cost of metrics, G&A costs 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 below guidance at 7.5% of revenue. And production costs for the quarter, which include workovers, were at the high end of guidance, while transportation and processing came in well below guidance. As mentioned, the net result was income for the quarter of $6.7 million, $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 buyer from the previously discussed sale of our Brookeland 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 of our net 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 our $450-million borrowing base in May, providing us with ample liquidity for inter-period 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 will turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton, and good morning, and thanks to all of you for listening in. Today I will discuss second-quarter 2013 activity, including our production volumes, our recent drilling results, our activity 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 than 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 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 drilled 14 operated wells during the quarter. In South Texas, all operated horizontal development wells were drilled to the Eagle Ford shale formation in South Texas. Six of these wells were drilled in LaSalle 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. In the Company's South Bearhead Creek field, one well was drilled during the quarter. We currently have three operated drilling rigs in 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 first-quarter 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 expectations. We expect to perform minimal levels of recompletion and workover activity, with no new drilling activity in Lake Washington for the remainder of this year. Bay de Chene's production of 290 net barrels of oil equivalent per day was down 8% when compared to the 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 rates 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 has 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 in 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 won't 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. The lower production levels in this area are primarily due to the mechanical failure of the non-operated GASRS 29-1-10 well, which was drilled earlier this year, along with the sale of the Brookeland field, which occurred during the quarter.

I will now turn the call over to Bob Banks to review operational highlights for the third quarter.

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 divesting our Central Louisiana assets. We believe these are high-impact, high-quality assets that, during the near term, will not compete for capital with our South Texas Eagle Ford program. There is strong market demand for these types of oily 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 divestiture process, and expect to finalize the sale of these assets in the next 6 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 stoutly with accelerated levels of activity. An example of this potential is our July production in South Texas, which is tracking approximately 10% out of our second-quarter average. I will recap our South Texas activity and strategy further after a brief review of our Louisiana assets.

During the quarter, we did drill 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 fully assess the potential to either reenter or redrill the well at a later date.

Also in Louisiana, our first horizontal test of the Wilcox formation in our South Bearhead Creek Field, the James Dolby 1-H well, was drilled during the quarter. We successfully proved that this field can be effectively exploited with horizontal drilling and completion technology. The well flowed continuously for 10 days at a rate of 200 barrels of oil per day, despite 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 that 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 put on 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 LLE #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 on to South Texas. Due to faster drilling times, lower well costs 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 La Salle 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 have begun using the two-year reserve recovery metric for each of our areas to ensure that our early time production data is performing to or exceeding our modeled total EURs for each of our development areas.

When these performance improvements are coupled with well costs that are routinely at least 10% lower than wells drilled in the same areas last year, we came to several conclusions. The first being that we are convinced that focusing on our lowest-risk, longest-life, proven-liquids-rich reserves and production assets will be the most accretive growth activity for our stakeholders. And that monetizing our less predictable Central Louisiana assets will allow us to finance gaps between cash flow 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 over 500 high-quality Eagle Ford drilling locations, with expected initial performance, reserve recovery and costs 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 continues to be interest in these assets. In that regard, we have recently successfully downspaced 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 its first shale play. And are prepared to accelerate the growth of our Eagle Ford assets 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've 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 it is these assets that will form the foundation for our performance and growth over the next several years.

Thank you for your attention this morning. And I'll turn the call back to Terry.

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 and lower cost, we have increased our activity level in South Texas to afford for higher levels of growth in that area.

We've committed to a strategic shift in our operations through the divestiture we've initiated of our Central Louisiana assets, 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 spud a horizontal well to test the Niobrara formation in 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 Instructions)

Will Fitzpatrick with Johnson Rice.

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

Yes. Real quickly, the guidance we have out today is adjusted for everything we've learned as of this date. Obviously, I think that 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.

Okay. Great. And then just one more modeling one. The $36 million of 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?

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

Okay, perfect. And then one last one. Can you give us a reminder, the 88,000, I think it is 80,000 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?

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

Some of us actually even north of the AMI with Anadarko, not part of that AMI.

Okay, perfect. Thanks so much.

Noel Parks with Ladenburg Thalmann.

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

Noel, this is Bruce. I'd probably break that up into two pieces. One, let's talk about their prospective buyers and the process we went through. We retained JPMorgan and we really identified prospective candidates in two camps -- the strategic buyer, mainly the Asian buyer that we've seen back, particularly, in 2010, '11 and '12. And then more of the financial institution buyer, which is institutions polling 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 on 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 are not paying the kind of premiums that they were back in those days. Those that had basically paid a premium for strategic reasons to technology transfer, things like that, really had already done that. So they were looking at things a little bit differently. But 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. You would have to get a significant premium to the valuation to justify parting even a portion of those assets. Because that, in our view, is our lowest risk area for substantial growth for Swift over the next several years.

So we made, really, more of a strategic decision based on where we wanted to direct our capital. And then, as a consequence of that, we wanted to fill a funding gap. So we really made a decision to liquidate one of the areas that we've been involved in a long time, that still has a lot of opportunity. But when we look at our capital allocation, we're not going to be able to devote much capital to the Central OES area. So it made a lot more sense to put it out for disposition where it would be worth more to someone else who will devote 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 manufacturing. And so our decision ultimately came more from strategic thinking about it, where we're best served to accomplish growth, particularly on a low-risk, risk-adjusted basis, than it did about trade in a joint venture which is, in fact, selling a portion of the asset to somebody else.

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

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

The dedicated frac crews are not as necessary, if necessary at all, compared to the early time horizon. There is a lot more horsepower available out there. Certainly we do pay a lot of attention to which crews we get, and in particular the efficiencies of those crews, the ATSC issues. But at present I don't think that's necessary to run a program of, say, two to five rigs. We just don't have that necessity anymore.

I think it is fair to say, though, while the plan for the remainder of this year is to have two rigs active down there, our current preliminary plans for 2014 have a more aggressive level of activity than two rigs.

Okay. And then just the last one for me, just to maybe put some numbers to this. Compared to what you were thinking back in, say, March time frame about getting a partner in the Eagle Ford, can you give us a sense of maybe the relatively stronger returns you now foresee from efficiencies and progress and completions, compared to maybe best case of what you were looking to get out of Central Louisiana?

Yes, this is Bob. Let me take a crack at that. As Bruce, I think, said, on 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. So, when we take a risk-adjusted basis, obviously improving these IPs, improving our two-year EURs, lowering our drilling costs, in some cases substantially, even prior to getting into the pad and manufacturing drilling, it really starts to stand out that the liquids-rich areas of the Eagle Ford are highly valued. I think in 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 mineral interest, those are very strong economics. But we have continued to have some repeatability issues in those assets.

Yes, this is Terry. To pivot off of what Bob has said, it is hard to be all things to all people. And clearly one of the things a smaller company like Swift Energy Company has to do is focus. And the shale play requires a tremendous amount of focus. And we've been honing our skills, the service company alliances that we've had, whether they've been formal or informal, have 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 is a great opportunity there. But we just cannot be all things to all folks.

Thanks, that's it for me.

David Deckelbaum with KeyBanc.

Good morning, everyone. Thank you for taking my call. My first is, the decision now to look to divest of Central Louisiana, you had 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 is realistic that you would be able to get anything more than value for production? 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?

This is Terry. First note, the assets that we are 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 mineral interest, it is a whole different type of evaluation that goes on because we own those in fee, or almost own them in perpetuity, the way they are constructed. And there you have basically to the center of the earth, and you don't have 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 up into its constituent parts. And obviously our desire would be to have one bidder 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, proved producing opportunities, PUDs that are sitting there ready to drill, and mineral acreage that can be held in almost perpetuity, and leased and released and royalties taken from it. So I think it is premature for us to say -- here's what we think the market's going to bring to us. There are some folks that are going to make some estimates. People are already making estimates based on metrics that are out there on per barrel or per acre type metrics. Those may be meaningful to use. But I think we're 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.

Okay. You made some mentioned earlier about all the work that's been done in Webb County and the downspacing. And believe that, that's some of the best rock in Eagle Ford. But obviously it is a gassy area. Considering that you are trying to grow on the liquid side, do you think there's an opportunity to just divest of the Webb County acreage to accelerate the liquids portion of the portfolio?

That's probably one of the best questions I've heard. Because I actually struggle with that. Our strategy has 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 is such a high-value, high-quality Eagle Ford rock that even in this environment it gives reasonably good economics, even at $3.50, $4 gas. Not near as good as the liquids 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 an outright sale of it in today's market with today's gas prices, probably not likely.

There's 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.

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 that 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 we went to a third party just to get another sense test, and compare this rock to other types of shale plays. 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, whether our numbers are right or theirs. But we are still upwards at the 800 BCF range in that area in terms of gross reserves over in that area. Bob? And that's not a proven number in today's gas price environment. That's just the potential number there. Bob?

Yes, just to add on that a little bit. At 60-acre spacing, so far we are liking what we are seeing from these downspaced wells. If we can drill 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 improve dramatically with small moves in gas price is quite amazing. At about $4.50 gas, as an example, we are in the 80% rate of return range for this Fasken type of asset. As Terry said, at $4 we can make money. But at $4.50, the rates of return really start ramping up. Anything north of there it gets 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 with the types of returns that we can generate out of an asset like that.

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

Some of that is in there, but we will also note that our liquids has grown an equivalent amount. So, I think that's really in the corporate presentation, which I think you might have access to. Slide 10. You can see that, that first quarter, you can see the splits between gas and liquids. And you can see that we've increased our liquids 10%, as well.

Thank you, gentlemen. Have a good one.

Neal Dingmann with SunTrust.

First question, probably for Terry more. Just, Terry, a strategy question. Or maybe for you or Bruce. When you see going forward, when you look at -- just looking at free cash flow, are you trying to balance now, depending on what happens with the Central Louisiana assets, is that going to impact just by how much you've continued to accelerate your south Texas? I'm trying to get an idea, as we look at a year-end exit rate or beginning next year, of how to look at what you guys -- or even Alton -- are modeling as far as cash flow versus CapEx?

Yes, this is Terry. Obviously, when we say 12 to 6 months in terms of an asset sale, 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 a strategy that ought to bring significant capital in to 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 reserve production growth in the 8% to 10% range next year with preliminary numbers. We are not fixed on these numbers for the reasons I stated. But preliminary numbers that would have a capital budget similar to this year. That's 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 underway that we are going to make sure that we are comfortable with our spending next year to accelerate the Eagle Ford.

I think the 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 on the line of credit. But we think we can have a level of capital spending next year that accomplishes 8% to 10% growth but is fairly neutral given the asset disposition.

And even the funding gap this year only gets us up below 50% the current borrowing base. And obviously with success, the borrowing base goes up. So we're toward the top of our leverage appetite, but we've got the liquidity to cover this and get more toward a cash flow neutral position going forward with success.

I think Alton is hitting 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, 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 a percent of the liquidity used, and in terms of a liquidity availability being stronger.

Great responses there, guys. And then moving over to South Texas. Looking, number one, maybe for Bob, just averaging how much -- it seems like some of your well costs maybe have come down a little bit. And then, secondly, as we look at LaSalle, Webb and McMullen, where do you sit as far as just holding acreage there? I think, if I recall, you all are in pretty good position

Yes, we are 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 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 are in reasonable shape there. 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 showed you some of the PCQ results that we are getting there. We are also going to concentrate in that Betts area, out in Artesia Wells. You can see the kind of rates we are getting there.

In terms of well costs, we have brought those down now. We are anywhere from about $6 million to $7.5 million in these liquids-rich areas. So the guys are doing a phenomenal job in bringing our costs down in drilling and completions. It's some of that performance improvement on all sides of this that has us very encouraged about focusing into those liquids-rich areas.

By the way, for everyone listening, we've refreshed our corporate presentation. It is currently out on our website, that you can pull down. And slide 11 is a really compelling slide that shows how we worked those well costs down in South Texas.

Very good, thank you all.

(Operator Instructions)

Adam Light with RBC.

Just on Central Louisiana, first of all, have you got an updated remedial reserve estimate?

We mentioned earlier that we don't have a refreshed net present value or proven 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 that goes through all the reserve opportunities that are there in the various types of categories, and producing metrics versus probable reserve metrics. So that's going to be forthcoming pretty quick. But we don't have anything to show you right now.

Okay. I got the 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?

We will look that up and Alton is going to give you a number here in a minute.

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

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

One of the things I was trying to get at is what you might see in a borrowing base change with a sale, would it be a dollar for dollar?

Believe me, we've looked at that, Adam, among a number of things. For example, in the second quarter the assets we are talking about represented about 8% of our revenue. As Terry mentioned, if you just try to quantify that, you will clearly undervalue these assets.

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

I think, generally speaking, we need to note that, again, it makes itself up of a lot of different components. So proved producing -- yes, there is some undeveloped opportunities that are proven. Yes, there are some. But it has got a tremendous amount of mineral acreage that really shouldn't be evaluated in the same context of working interest. Fee he acreage that's in perpetuity, as well as a lot of potential reserves and probable reserves. So we need to go to the market and find some folks that focus on those types of things and give them an opportunity to bid on it.

And specific, ADam, to your question about the borrowing base, again, one of the things that we clearly look at in something like this, we think that will be more than offset by the success we're having in South Texas.

I got that. Okay. And I didn't hear if you said when you might be opening up a data room?

As we indicated, we expect to have this done in 6 to 12 months, giving ourselves some room there. Obviously, as Terry also said, sooner is better than later. We are in discussions with several intermediaries. We've not selected one as of yet. We expect that to happen in the fairly near future. Then we will go through that process of doing all the work to get a data room together. And we would hope to have that by certainly early fall.

Okay, that's great, thanks. Just going back to Fasken for a second. You said 80% returns at $4.50. Give us a sense of where these breakeven or 10% type of return breakeven might be with gas prices?

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

Okay. That's great. And then on --.

We are not going to drill at $2.40. It won't compete for capital.(laughter)

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

With regard to Fasken or --?

No, subsalt, sorry.

Subsalt. What we've indicated is -- these processes take time. And while we are getting good feedback, and as we noted in the call, we believe that we passed those first tests of peer review and such. Realistically it is going to take until the end of the year to get an actual joint venture, both agreement and papered and then a plan to go forward as to the timing of the well and such.

I would add that our approach has been to only really go to top tier companies that we believe are very well apprised of what kind of targets and what kind of risk and rewards, what kind of operations are involved. So, they, of necessity, will have a big role in how we put this together. As we've begun our discussions with such companies, we are giving them some latitude to also shape the kind of project they are going to be in.

It is not designed to send this out to 50 or 100 people. We are really going to talk to probably in single digits in terms of the number of people we talk to. But very high-quality names, and doing it in a very methodical way. You want the right partner, not just a partner.

Okay. That's great for me. Thanks.

Andrew Coleman with Raymond James.

Thanks a lot, folks, and good morning. I had a question. Could you just run through again the ranking exercise that got you guys to decide on Central Louisiana versus South Louisiana or pieces thereof, for targeting for divestiture? And would you consider down the road, if you needed more capital next year, to look at those assets too?

I think the ranking process really starts with Texas performing so well. We are just very pleased with Artesia and North AWP, our liquids areas, our condensate areas. As we noted, we are very pleased with Fasken, albeit it is not the right time to go into full development there. So, when we look at the growth profile of the Company, the risk profile of the Company, we really decided that we needed to make sure that the capital got allocated to the best assets. So what that meant is, 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 to hit the ranking was the Central Louisiana assets. In one respect, it is because there's a lot of upside potential there. And a lot to do in the way of development and 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 just not prepared to be doing that compared to our other assets.

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 of recompletions 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 is going to be done the same way. Where does the best capital go. And Lake Washington has certainly been a great asset 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.

Okay. And a couple other ones there on the Central Louisiana assets. Does your partner there in the JV have any [rofers]? Or the fact that you have a JV there, providing any complication to divesting those assets?

Andrew, this is Bob. Actually, some of the leases are beginning to expire that we granted to that partner. So it is a mixed bag. Some is already back with Swift 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 mixed as to making this a clear transaction going forward.

I will add to that. Not to avoid using their name, but we've always had good relationships with Anadarko. They've operated these wells and we 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 one that collects the royalty on a substantial amount of this production. And so, as we are looking at the plan of development, we want a more substantive plan of development going forward, should we remain royalty owner there. Or we sell it to someone who will get that subsidy plan of development.

Okay. And can you give us a little bit of flavor on just the interest that you all have seen so far? Maybe break it down into perhaps a mix of unsolicited interest versus just what you've gotten since you put out the press release here in the last couple hours? Or, have you been surprised by some of the interest that you've seen so far?

Andrew, this is Bruce. We have not engaged an intermediary at this point in time and put anything out. So, obviously, for the market to even be aware that we're planning to sell these assets, they've only had a couple of hours notice. We've not had any inquiries to this date. But in conversations with a number of the intermediaries, going through that selection process, they believe that there will be a very strong interest for these properties. There's not just a proved producing component, but there's a lot of upside to it. And they're very oily properties. So, our belief is that there will be a very good interest for these. Again, whether it's a single buyer or multiple buyers, don't know at this point in time. But we feel pretty confident we'll go through a pretty good sales process and have good competition.

Okay. And then the last question is, given that Masters Creek, you do own the actual minerals on that, is that the only area in your Company where you own mineral rights outright? That's it.

Yes, I would say Louisiana really is the only place where we have any significant outright fee mineral 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 of the field.

And that's in addition to the Burr Ferry mineral acreage. Not to get those confused. Both are significant.

Okay. And to confirm, then, you are looking to sell that mineral acreage. You guys wouldn't keep an override or a small piece of it just for optionality down the road?

It all comes down to the value that comes out of the transaction. We made a strategic decision to focus in South Texas. And so any residual interest that we might 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 North Louisiana going forward strategically.

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

(Operator Instructions)

Tom Morgan, Global Hunter Securities.

Just had a quick question about the Eagle Ford, wIth the efficiency improvements that you have seen there, and the plans to increase the activity there in the second half of the year. I'm just wondering how many wells you are looking at completing the second half of this year versus what you planned on drilling, that might be pushed back into 2014.

With the two rigs, we're probably in the range of another 10 to 12 wells. In terms of completions, probably in the 5 to 8 range within this year, with the remainder early next year.

Most of that late in the year.

Yes, towards the late end of the year.

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

No, based on our current accounting practice, that would not be necessary. Not significant enough.

Okay, thanks.

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

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

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