SilverBow Resources Inc (SBOW) 2014 Q2 法說會逐字稿

Good morning. My name is Nan, and I will be your conference Operator today. At this time I would like to welcome everyone to the Swift Energy Company Second Quarter 2014 earnings Conference Call.

(Operator Instructions)

Thank you. I would now like to turn the call over to Mr. Paul Vincent, Director of Finance and Investor Relations. Please go ahead, sir.

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy's Second Quarter 2014 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 before we open up the line for questions. Also present on the call is Steve Tomberlin, Senior Vice President of Resource development.

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 25-30 minutes and have allowed additional time for questions.

Thanks, Paul and thank you to everyone for joining the call today.

There are several examples of our growing technical expertise and leadership in South Texas during the Second Quarter. Corporate production growth of 24% over Second Quarter 2013, and 17% production growth sequentially was driven primarily by growth in our Fasken and AWP areas in South Texas. This growth was delivered with capital expenditures 28% below 2013 Second Quarter levels.

We believe this type of performance demonstrates that our operational capabilities can deliver meaningful higher levels of productivity per dollar than even just one year ago.

We announced and have successfully closed a joint venture transaction with PT Saka Indonesia in our Fasken area in Webb County. The $175 million consideration Saka paid for a 36% interest in our 8300 acre position implies an approximate $500 million valuation for the entirety of the acreage. We believe our ability to demonstrate continual performance improvements, while reducing the cost curve in our operations was critical in Saka's evaluation of this transaction.

Based on our ability to continually increase our well performance, we announced an agreement with Howard Energy to expand our committed natural gas firm transportation capacity in Webb County from 75 million cubic feet per day to 160 million cubic feet per day. We expect this capacity to be available early next year, and anticipate achieving this level of gross production in the Fasken area shortly thereafter.

On the drilling front, during the quarter, we have reduced average days on a Fasken well by 1 to 21 days and reduced our cost per foot by $5. We've also achieved new drilling records in our SMR and PCQ areas in McMullen County. Our completion work also improved during the quarter, as we are now performing enhanced or engineered fracs on effectively all of our new wells. This process allows us to selectively perforate and group our intervals in the most optimal fashion.

The results of our enhanced drilling and completion approach are hard to argue with. In our Fasken area, three new wells averaged initial production levels of over 21 million cubic feet per day. In our PCQ area, four new wells averaged just under 1400-barrels of oil equivalent per day. South of our PCQ area, in the Whitehurst area, two new wells averaged initial production slightly over 3000-barrels of oil equivalent per day.

We've really got our operations moving in a very nice pace and are enjoying the success that comes with the cohesive team-based approach to our oil field operations. We expect that there's more room for improvement in our results in all our areas due to improved application of available technology.

We've maintained for the most part of this year our primary focus was and is to strengthen our balance sheet and improve our liquidity. We believe the joint venture with Saka has accomplished this. We've also reduced our South Texas rig count by one for the second half of the year, and expect our capital spending and cash flows to be roughly in line with one another in the Fourth Quarter of this year.

Our secondary goal for the year was to demonstrate the viability of our technical approach to developing the Eagle Ford Shale. We believe that both our First and Second Quarter results demonstrate that we have the capacity to deliver production growth through the drill bit within our existing acreage for years to come. We've demonstrated that our approach in South Texas, which has been applied across our acreage position in three distinct areas, provides a platform for growth as we invest in and acquire new acreage in the trend.

Many Operators have been successful in adding additional drilling inventory in 2014 through Eagle Ford transactions, and we believe we will be able to do the same based on our knowledge in the trend. Our focus on the Eagle Ford Shale gives us a competitive advantage, particularly when it comes to evaluating dry gas and condensate rich opportunities. Due to the scalability and the transferability of our drilling and completion designs.

For all of the reasons stated above, and the performance results that are at hand, we also believe we can grow our production. Based on our performance during the first six months of 2014, we are confident that our full year production volumes will be above our previous expectation of 11.5 million to 11.8 million barrels. Our current estimate of 2014 production is now 11.9 million to 12.1 million barrels of oil equivalent.

The Second Quarter was another very strong quarter, operationally. We continue to drill better wells at lower cost. We know that our folks have the passion and commitment and skills to deliver outstanding results.

And now, I'll ask Alton to summarize our Second Quarter 2014 financial results.

Thanks, Terry, and good morning, everyone.

Second Quarter 2014 production of 3.45 million BOE was well above the high end of our guidance. Both oil and natural gas volumes were above guidance levels, while NGL volumes were near the mid range. Our overall financial results for the Second Quarter of 2014 include oil and gas sales of $158 million before adjustments for our ongoing price risk management program, which this quarter includes a pre-tax $1.2 million non-cash loss related to hedges we have in place that extend beyond 2Q 2014.

Net income came in at $8 million or $0.18 per diluted share. Cash flow before working capital changes for the quarter was $90 million.

Our controllable costs were overall very favorable for the quarter. G&A which includes approximately $1 million in transaction related costs associated with the Fasken joint venture, came in at $3.60 per BOE, slightly above guidance. While all other per unit metrics were favorable to guidance, as oil and gas depletion was $20.93 per unit, interest expense came in at $5.41 per BOE, severance and ad valorem taxes were 6% of our oil and gas revenues, transportation and processing was $1.74 per BOE, and lease operating expenses came in at $6.36 per BOE.

LOE costs came in favorably due to higher volumes and numerous cost reduction efforts, but also benefited this quarter from adjustments for actual costs coming in below our previous original accrual estimates. On a normalized basis, our LOE per BOE for 2Q 2014 would have been about $0.90 to $1 per unit higher based on the 2Q 2014 production levels. Please see the Company's guidance in our Press Release for expected forward per unit LOE.

As previously mentioned, the result was net income for the quarter of $8 million or $0.18 per diluted share, well above First Call mean estimate. Cash flow before working capital changes for the quarter came in at $90 million, while EBITDA was $105.9 million. Quarterly CapEx on an accrual basis was $110.2 million.

We continue with our expanded hedging program to minimize the price volatility risk. We're strategically using a combination of commodity swaps and collars, and also have locked in basis spreads which protect against volatility we see between prices at our field delivery points and major terminals. As always, complete and timely details of Swift Energy's price risk management activities can be found on the companies website.

As Terry mentioned in his intro, in 2014, we continued to be laser focused on strengthening our balance sheet and better aligning our capital spending with our expected cash inflows, which will also obviously enhance our liquidity. With the recent closing of our Fasken joint venture, along with improving operating cash flow, we're clearly achieving these objectives, and we're committed to financial discipline first and growth second.

As always, we've included additional financial and operational information in our Press Release, including guidance for the Third Quarter and full year of 2014.

And with that, I'll turn it over to Bruce Vincent.

Thank, Alton. Good morning, everyone. Thanks for listening.

Today, I will discuss the Second Quarter 2014 activity, including our production volumes and our recent drilling results, activity in our four operating areas as well as our plans for the third quarter this year.

Beginning with production, Swift Energy's production during the Second Quarter of 2014 totaled 3.45 million-barrels of oil equivalent, or at a rate of 37,902 barrels of oil equivalent per day. This is above the high end of our guidance and highlights the technical efficiencies we've been exploiting this year in South Texas. Second Quarter production was 24% higher than our Second Quarter 2013 production of 3.26 million-barrels of oil equivalent, and increased 17% sequentially.

The production mix during the Second Quarter was comprised of 26% crude oil, 13% NGLs, and 62% natural gas. Production growth during the quarter was driven primarily by increased production volumes in our Fasken area due to the prolific nature of our newest wells drilled in the area, and the ability to access interruptible transportation out of the Fasken area.

For our Second Quarter drilling results, Swift Energy drilled 11 operated wells during the quarter and all through the Eagle Ford Shale in the companies South Texas core area. Seven of those wells were drilled in McMullen County, and four wells were drilled in Webb County, and the Webb County is the Fasken field. We currently have two operated drilling rigs in our South Texas core area, drilling Eagle Ford Shale wells. One in our Fasken area and one in the AWP area in McMullen County.

In the Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields, production during the Second Quarter averaged approximately 4036 net barrels of oil equivalent per day, down approximately 20% when compared to the Second Quarter of 2013 average net production from the same area, and down 8% from the First Quarter 2014 levels. Lake Washington averaged approximately 3940 net barrels of oil equivalent per day, a decrease of 7% when compared to First Quarter 2013 average daily volumes.

Recompletion and work-over activity began at Lake Washington in the Second Quarter and is expected to reduce natural declines during the second half of 2014. We have identified numerous opportunities throughout the field and expect to conduct approximately 20 of these low cost, high return projects this year.

In our South Texas core area, which includes our AWP, Sun TSH and Las Tiendas, Olmos fields and AWP Artesia wells and Fasken Eagle Ford fields, Second Quarter 2014 production of 32,040 net barrels of oil equivalent per day, increased 23% when compared to the First Quarter 2014 production in the same area, and up 37% when compared to Second Quarter 2013 volumes.

In our Fasken area, production volumes increased 93% to 84 million cubic feet of gas per day, up from 43 million cubic feet of gas per day during the First Quarter of 2014. Our net volumes in Fasken have been reduced by 36% due to the closing of our joint venture in that area, but we continue to push gross production volumes higher in anticipation of bringing field production to approximately 160 million cubic feet per day early in 2015.

In our AWP area, production grew 6% sequentially, and averaged 12,513 barrels of oil equivalent per day. We will continue to increase South Texas production levels, with two rigs running in the area for the duration of the year.

Highlighted in our Press Release this morning are details of the nine new operated wells we completed in our South Texas area during the quarter, and I'll refer you to that detail as opposed to recite it here.

Three new wells from our Fasken area were completed during the quarter. We have now brought seven consecutive wells online in that area that have exceeded 20 million cubic feet of gas per day in initial production. Further, we believe we can continue to improve our drill and complete design, and expect to drill even higher quality wells going forward while seeing opportunities to further reduce capital costs.

In McMullen County, six wells with an average IP of 1946 barrels of oil equivalent per day were brought online. Most notable of those were the Whitehurst JV Eagle Ford 3h and 4h. These two wells were brought online with an average IP over 3000-barrels of oil equivalent per day, with strong flowing pressures and almost 50% liquids.

As Terry noted and Bob will discuss further, the Whitehurst area represents the third area in South Texas we have applied our current generation drill and complete design, and observed a meaningful uplift in initial and sustained performance. We are now in the belief that our ability to drill precisely targeted laterals within the lower Eagle Ford, and our engineered completion design, is a transferable and a competitive advantage that can be applied throughout the Eagle Ford trend, given certain geologic parameters.

The Central Louisiana corridor, which includes our Masters Creek, Burr Ferry, and South Berry Creek fields, contributed 1731-barrels of oil equivalent per day of production in the Second Quarter of 2014. That's a decrease of 16% from the First Quarter of 2014 in the same area, primarily due to low activity levels and natural declines.

Now I'll turn it over to Bob Banks who will cover the results of the quarter in more detail.

Thanks, Bruce.

Our work to date in 2014 has confirmed our belief that the combination of longer laterals that are steered in a tighter zone of the highest quality rock, along with customized completions that optimally group and perforate our frac intervals with greater volumes of proppant and fluids are very important factors in delivering improving well performance. While any of these factors can be achieved on their own, we are consistently achieving all of these in every well while continuing to drive our costs and well delivery times down.

This means that first, we are able to add significantly more producing wells within the calendar year and year-on-year, and second, that we are able to drill more wells in the calendar year and year-on-year for the same amount of capital. Although we are drilling more technically precise wells, we are continuing to improve our days on well metric in all areas. In Fasken, we are now averaging 21 days on the well, and we measure that from rig release to rig release. In SMR and PCQ areas, we set new records of days on well to 15 days and 16 days, respectively, compared to our previous records of 21 and 18 days, respectively.

If we look at our Fasken field in Webb County, it's easy to see how we have demonstrated improvement during the past year. We have grown our gross Eagle Ford gas production from 28.3 million cubic feet per day in the second quarter of 2013 to 103.8 million cubic feet per day of Second Quarter 2014, and that represents a 367% increase.

We've also increased our average lateral lengths and sand volumes by 40% and 80% respectively. We have reduced both our average drilling costs and drilling times by 40%. On the completion side, we reduced our cost per stage by 20%, and the performance results of these new designs have yielded 30 day and 90 day cumulative production increases of 100% and 85%, respectively.

We've also applied some of the same enhanced technology in the new Whitehurst wells 130 miles to the East of Fasken at our AWP field in McMullen County. For these two wells, we increased our lateral lengths by 12%, reduced our drilling days and costs by 15% and 8%, respectively, increased our stage count and proppant per foot of completed lateral by 27% and 50%, respectively, and continued with our customized completions approach. This resulted in an IP increase of about 30%.

While we've enjoyed remarkable stability in drilling and completion vendor services and pricing for the past two or three years, we know that at some point in time the enormous appetite of our industry will periodically drive costs higher and vendor availability lower. Swift is very proud of the Supply Chain organization that we have developed, and believe that this team and their capability will continue to be one of our key operational and competitive advantages for the future.

As Terry indicated, we've had great results to date this year, and are on track to produce considerably more oil and gas than we previous believed. This not only validates the technology and techniques we have deployed over the past 12 months, it also sets the stage for sustained growth in 2015 and beyond.

While we are making great strides with our efficiencies and performance, one of our key core values is that of continuous improvement. Looking ahead, we anticipate increasing our stage counts and sand loadings by another 10% to 20%. Also, we are obtaining more consistent results with our drilling out of our plugs and are beginning to cut that time and cost in half. Additionally we're working on an improved design efficiency and effectiveness of our toe fracs.

Our strong and continually improving operational capabilities are increasing the value of our high quality acreage with every well we drill. We also believe they are important tools in executing our strategy for acreage acquisition in South Texas.

With our joint venture with Saka Energy now closed and our near term leverage liquidity and funding goals met, we can turn our attention to adding to our inventory of high quality Eagle Ford drilling locations. Our Business Development efforts are focused on adding acreage where our drilling and completion approach can rapidly improve upon historical improvement -- historical performance. We are actively sourcing opportunities to lease outright, farm in, and partner via joint venture, various acreage positions that we believe have not been fully evaluated using leading technology.

As a result of the flexibility afforded by the Fasken joint venture, we've determined that while we are continuing significant work with potential buyers of our Central Louisiana assets, if no sale were to occur, we are prepared to invest a limited amount of capital in 2015 in low risk projects in order to maintain and enhance the value of these oil assets. We've put a great deal of energy into our 2014 program to date and it's encouraging that we are exceeding the expectation we've had for this point in the year.

With that, I believe Terry has the closing remarks.

Thanks, Bob.

Before we open the line for questions, I'll summarize today's call.

Driven by our South Texas development program, corporate production grew 24% over Second Quarter 2013, and 17% sequentially. Our joint venture in Fasken helps us achieve our leverage and liquidity objectives, while also providing a valuation for that acreage above what many expected. We remain confident we will have 160 million cubic feet per day of firm, committed capacity for natural gas transportation at Fasken early in 2015. We are realizing fewer drilling days, and lower cost per foot drilling and completion costs in all our areas in South Texas.

Enhanced drilling and completion designs continue to improve the results we're observing in all of our South Texas Eagle Ford results.

With that, we would like to begin the question and answer portion of our presentation.

Thank you.

(Operator Instructions)

Your first question comes from the line of Brad Heffern with RBC Capital.

Hi, good morning, guys.

Good morning, Brad.

Just looking at the new guidance for 2015, I know it's early, but do you have any preliminary indications on what the mix of commodities is going to be on that?

We're just giving more or less our strategic line of sight for 2015. It is very early.

Clearly without giving you a mix number, which we aren't prepared to do at this time, we haven't formalized our final budget for 2015, that's a Board review that we'll have a little later in the year, and we'll bring out the details later in the year. But, I think it's safe to say that the mix on gas will increase somewhat because of Fasken. But at this time we aren't prepared to give any precise numbers.

Okay, understood.

And then, looking at the new 2014 guidance, there was a slight shift to more gas taking some out of oil. Is that a reallocation of drilling to sort of gassier areas where you've seen better results?

Well maybe a little bit, but not so much. It really has more to do with our performance at Fasken.

Just, for everyone's benefit, the production for the Third Quarter obviously or the production guidance for the Third and Fourth Quarter is below what the Second Quarter was, and that's driven first and for most by the sale of the 36% to Saka that was effective July 15. So, that's the first thing.

Secondly, we were able to access a lot of interruptible capacity in the Second Quarter, and we will obviously try to access as much as we can, but we've been told by our midstream provider that they anticipate having less interruptible available than with our other producers that have firm transportation capacity in their line have already indicated to them they expect higher levels of production into their firm capacity. So, we don't expect as much available.

And then thirdly, we had talked before about drilling a [four pack] well in Fasken. That's currently being fracked and we've had to shut in some of these big producers while that's being fracked. Now, that's good news because we're bringing new wells on production, but the biggest reason for the increase in gas mix has more to do I think with the productiveness of the Fasken wells than a reallocation of capital.

Okay understood.

And then just shifting over to the Whitehurst area, I was wondering if you have any indications as to what the EURs are in that area with these new completion designs? And maybe a little color on how the returns compete with Fasken and how many locations you'll have there?

Well let me take that first while Bob is collecting his thoughts on the EURs at Whitehurst and how that compares to some of the Fasken metrics, I think.

First of all, we've been drilling down in the Whitehurst area and have significant core data, long data, seismic data, and we've always liked that area. We're coming back into the area with the technology improvements that we've seen across the play. There is a significant amount, and you can see by the test of condensate that's associated with this gas, it's a very rich gas.

We're not prepared at this time to model in all of the upside that we now are beginning to see at Fasken on the designs, though we clearly believe we're going to get some of that. So, I think that it's fair to say that in our existing outlook of reserves and the things that we're doing, there's really not much uplift in EUR contemplated until we have some more proof of concept over there, but the results thus far are extremely encouraging to us.

Bob?

Yes, I would just add to that on the pay out question, with what we're seeing from these two new wells, we feel very comfortable that pay outs are going to be under 18 months on these wells, and we're doing everything we can to replicate this kind of performance on a number of additional locations.

We do have a fair bit of running room here right along this trend. Another 30 or so we see very similar to this area, and as Terry said, our EUR model that we've endorsed for purposes of reserves is a lot less than what we're seeing from these results, and it's probably a little more too immature to throw a new number at you, but we have our working models, and we're going to be testing those with our outside auditors here fairly shortly.

Okay, thank you, guys.

Thanks, Brad.

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

Thanks. Nice work on the operational progress this quarter guys.

Thanks, Michael.

You bet.

I guess just a couple questions on my end. Looking out at the 2014 guidance you put out. On that Third Quarter number, do you by chance have how much you're incorporating in that for interruptible volumes? I know you talked about already get the message from the midstream provider there could be less available, but is there any assumed in that number?

There is within the range. Our firm capacity at Fasken is 75 million a day, and so we've kind of run some sensitivities at 75 million and 85 million and even up to 100 million, and based on both the conversations with our midstream provider, as well as what we see having to shut in because of the fracking that's ongoing, that's how we arrived at that range, so there is some -- probably the low end has little interruptible but the higher end of the guidance has some interruptible capacity in it.

And I mean, I'll be frank with you. We're going to try to get as much interruptible capacity as we can, but because it's an unknown and because it's not guaranteed space, and we do know from our midstream provider they expect increased levels under their firm contracts, we want to be conservative in terms of how we guide our ability to get into that.

Okay that's helpful, thanks. Makes sense. And then, the Fourth Quarter kind of implied CapEx shows a pretty material decline from Third Quarter and the first half on a run rate basis. Can you just walk through some of the high level outline on how you reduced that spend rate so materially in the Fourth Quarter?

Yes, this is Terry. Let me kind of lay out three premises. First of all, that was a goal. So, we have been guiding that direction all along this year, it's purpose to do that. That's the first important point.

Second of all, the Saka transaction really has two components to it. One is all the drilling over there is now 36% born by Saka, plus additional drilling that we do post transaction, there is a carried interest that's there that's to our credit, so you see both the Saka taking their share of their capital requirements there, but you also see them paying a portion of our capital requirements.

And then finally, and I think this is a material point, is we're getting more productive wells in all our areas, which means we have to expend less capital to get that production, but also we're driving our cost down in all of our areas, we're having fewer drilling days to get these wells down. We're seeing more efficient levels of expenditure on the completion.

So those three items, one is we purpose to drive it that way; two, the Saka transaction changes the mix of capital requirement, gives us a promote in that area that we're recovering a portion of the consideration as we drill there; and finally, the wells are much more productive per dollar spent.

I'd also point out that we did drop the third rig in South Texas that occurred early in the third quarter, but we're still completing those wells in the third quarter that were drilled by the extra rig, so that's a slightly reduced level of activity because of that as well.

Okay, that's helpful.

Can you remind me, just a follow-up to that, what average per well costs you're running in say Fasken and in McMullen? Sorry if I missed that.

Yes, are you talking about completed or drilling side and all-in?

Yes, full D&C, yes.

All-in at Fasken, we have driven our costs really down to depending on how much proppant we're pumping. You know, like I said, we're driving our cost per completed foot of lateral down, but we are increasing our proppant, we're increasing our stages, there's some offsetting effect. But generally, we're about $7.5 million right now to date in Fasken.

We think we can drive that lower. Over in the AWP area up in the PCQ, SMR areas, we're at about right now today at about $6.5 million to $7 million, and down in this condensate area that we announced today, those are right now running about $8 million.

Okay that's helpful, thanks.

Then, can you just remind me what the post JV borrowing base looks like and how much is drawn on that?

Yes, we're currently at about $180 million to $190 million, Michael. We see that staying flat -- (multiple speakers) -- yes, of the draw.

The borrowing base is reduced by what?

Oh, I'm sorry, I thought he was talking about outstanding.

Well, what was the borrowing base reduced by? I think it was -- (multiple speakers)

I think we're at about $417 million versus the $450 million. (multiple speakers)

Yes, correct.

Okay. Then I guess I have got to ask, on the Central Louisiana sale, what if that just doesn't get done? I guess what your update on the process they already have? Is there anything in particular holding it up, and then at what point do you just move on?

Yes, this is Terry. I'll give a little bit of color to that.

We've always seen these properties as having some good quality to them. They are oil, they're liquid-type properties.

We clearly need to be in these properties doing maintenance workover type work, some of that was done in the -- really began in the First, but also Second Quarter, we actually saw some of that. We are encouraged by the results we saw. We also have been looking in South Bearhead Creek to actually permit a couple of the lower cost wells and begin a drilling effort next year of a minor nature to go in and get the liquids production up.

It's a great property in our view. We do think that, going forward, we need to look at some alternatives, both in terms of doing some minimal work in the field and drilling a few wells to bring production up, but also look at selling it in pieces should we not sell it as a whole.

We really do like the production, so we'll get back with you in the future on the details. But it's not going to be a big part of 2015 capital, not going to be a part of 2015 production growth to speak of. Our focus is South Texas where we are bidding these big wells in Fasken and now seeing some big results across all of our acreage as we transfer the technology there.

Great that's helpful. Again, congrats on the progress in South Texas. Thanks, guys.

Thanks, Michael.

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

Good morning.

Hi, good morning.

I was thinking about Fasken. I think for the most recent set of wells, if I remember right it was early 2012 when you last had some significant drilling activity there. With the well improvement, what do you see happening to the production curves? Are you attributing -- I should say, do you expect now to mainly just bring a lot of the production forward or actually the whole curve do you expect has shifted up now?

Oh, yes, the whole curve, Noel. This is Bob.

The whole curve is shifting up. We kind of divide our efforts at Fasken into about three generations, and if you just look at how the wells perform how the curves, decline curves are performing from the first to the second to the third generation, I can tell you it's quite a dramatic shift upwards in total to where now, really, these wells -- we're taking out a couple of BCF in the first six months on these curves.

We've had this field reviewed by independent auditors to check our decline curves, do the history matching with the well performance, and basically, two independent reserve engineering firms, as well as ourselves, are all converging pretty closely on much improved decline curves for these Fasken wells.

This is Terry.

I'd like to put it in kind of the simplest terms I can. While there's a lot of technology improvement in terms of how we steer the wells and the type of completion fluids, the amount of sand and the pump rates, I don't want to take away from that. That's critical to the success here. But I think it easiest to think of this as though, instead of going back and looking at a historical result per well, you really need to go back and look it at historical result per foot of reservoir contacted.

We're actually contacting and stimulating significantly more reservoir than we were before. In the early days, these were 3,500 to 4,000-foot laterals. We're now drilling not quite twice that amount. We're drilling 7,000 foot laterals, so you're almost double the lateral length. But also in the early days we're putting 3 million to 4 million pounds of sand to stimulate that reservoir, and today we're up to 8 million, 9 million, 10 million pounds of sand to stimulate it, and we're doing all of that more effectively.

So, if in the old days you drilled one pud, and you drilled one 50-acre drainage and then you say -- well I can drill two of those you'd expect twice the production, twice the reserves. Here in Fasken, you're basically developing more acreage with more lateral.

Great. That's real helpful.

And I think you may have touched on it a little bit earlier, but do you have sense of where the EURs are headed in Fasken then?

Well, I'll take that one, because I shoulder it. We currently are saying about 10 BCF a well, and we're absolutely confident that that's the right place to be right now.

We need to see some longer term production performance from these wells. We need to see how they produce in a longer time period against the line pressures that we have and the new techniques.

I think there is an opportunity, certainly we see it in probables and possibles now, to increase that, but we're not ready to do that. So, 10 is our number right now, though we see more upside than downside right now.

So the 10 is -- again what you're comfortable with right now, but it sounds like it could conceivably sound conservative for the years down the road?

Well, we're trying to be that way. Mother nature throws you curve balls both directions, sometimes she gives you great opportunities but you have to be careful not to bite them off too fast.

Right. And Bob had mentioned in his comments that the plan was to increase the stage count and the sand loading by 10% to 20%, and there's also a mention of doing more with the toe frac, and where is the frontier, do you think, in terms of the number of stages and the amount of proppant, just in your part of the Eagle Ford? And, have people gone considerably further than what you've done in terms of those quantities?

Well I mean -- I think some people have probably been out a little ahead of us, but we're -- well, I'd say we're kind of in the upper end of pushing this technology and calibrating to our well performance. You ask a good question about -- where's the frontier going? We haven't found it yet. We're continuing to make improvements almost on a well by well basis.

One thing we've learned is that these are not cookie cutter approaches. We take a very specific and engineered approach to each one of our wells and we calibrate that against the well performance. We try to optimize on things that add value, and we try to economize on things that don't add value.

So I'm just trying to give you a glimpse of our next stage of some of the things we're going to keep pushing, because we believe you've got to find the technical limits in your fields, and that's really what we're pushing towards. As early as we can find those technical limits, both on productivity and cost structure, that's what we're about.

Great. That's all for me.

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

Good morning, guys. Say, just a question more on realizations.

Obviously, I think it was a month or two ago in May when you guys signed the FT in the Fasken area, so I guess, when [Elton] or you guys model this, how do you think about, sort of -- I guess, two questions around that. One, you haven't had any take away issues now in some time. Do you feel pretty confident that that will continue to be the case now that I think you've got a couple different options there? It seems to be better.

And then number two, on this take away that you have, I'm just wondering about realizations. How you think about taking it to the different areas and sort of factoring in that, with the -- given the FT that you're signing up?

Well I'll take the first part of that question, and then I'll hand it over to Bruce to handle maybe the interruptible side, because he is right on top of that. But you know, we worked hard with our pipeline company out there, and they had many different ways to provide this service to us, and we looked at different options, different outlooks. Whether we took everything south, took some of it north, and they have a full system out there that services gas beyond our gas, and we're in a position now with our firm capacity to do more than just the 160 in the future.

We haven't committed to do that. They haven't committed to do that, but they're building a much bigger system in the area because they see the potential as well. I'm very confident that Howard Energy, in particular, is going to be able to get this service in place by early 2015, and then our firm take away will be very strong.

Bruce, do you want to talk about the interruptible?

Yes, let me comment a couple things. Let's stick with Fasken for the time being.

I was going to make the same comment Terry did, that when we get to 160 firm transportation capacity, we think we'll have well capacity above that, so interruptible is still going to be important to us. As you saw in the Second Quarter, we were able to access quite a bit of interruptible capacity, so the system itself has that capacity, although much of that is contracted out to other producers who may be undersupplying their firm transportation.

Our midstream provider has told us, which I indicated earlier, that some of their producers that have firm capacity have indicated an increasing level of production into the Third and Fourth Quarter to use their firm transportation, which means less interruptible will be available. That same midstream provider though in conjunction with the work he's doing for us, is also adding some additional capacity to their larger system. And we need to get a better sense for that, probably after we get the 160 firm built in, what additional interruptible capacity might be available to us.

In addition to that, there is another provider of -- midstream provider in the area of our Fasken field that we believe we can access a certain amount of interruptible capacity. It is a little more expensive than that with our provider that has the firm transportation. But if we can get a substantial amount of additional gas and interruptible, we think that will make sense, and we'll see what we can access in the Third and Fourth Quarter as we move forward.

I think your question was also a little broader in terms of the other areas, so let me give you a quick synopsis of that.

AWP, we're in good shape there with capacity. We don't see any capacity constraints in the short run based upon our drilling plans, and in Artesia Wells in La Salle county, the same thing is true. Is we don't see any capacity strains unless we, either one, we would have to increase the level of capital spending on the gas side to have issues with regard to that.

So we think we're in pretty good shape in the near term. Obviously, constrained currently at Fasken but that's a good thing.

We already got all of the plans in place, we expect that additional capacity to be available early next year, whether they can come earlier or not, we don't know. Obviously, everybody tries to get something done sooner than you hope, but then we think there will be some interruptible capacity available to us in the Third and Fourth Quarter before that additional firm is in place.

And Bruce just to -- that answered that great. Bruce, and just one follow-up to that just on the differentials around that. Because you have so much of this firm transport, is it fair to say that I guess more than others you're a little more confident on differentials and such because more of that's locked in? Or just wondering how to -- I guess a modeling question. Going forward, how to think about differentials?

Yes, that's a fair comment.

I think that, certainly, the firm transportation, the interruptible has a little bit different cost to it, and as I mentioned in Fasken, if we are able to, if our principal midstream provider, who we have the firm transportation with, the cost of interruptible is X. If they're maxed out and we are able to go to another provider, their cost is X plus. So, it's going to be a little more expensive, which could cause a little bit higher differential, but I don't think it would be a significant on a per Mcfe basis because you'd have higher volumes with that.

We've tried to factor that in, in terms of our guidance. We think we're relatively on with that.

Got it. Great color, solid quarter, guys.

Thanks, Neal.

Your next question comes from the line of [Robbie Kamath with Citigroup].

Hi guys, great quarter. Couple of questions.

One, on the 2015 production guidance, the early guidance that you provided, what would the associated CapEx -- would that be just a broad range?

Well, again, we're trying to be careful to explain that this is more line of sight and strategic look forward into 2015. We have not completed our 2015 budgeting process. We've got to do that in the Fall.

We'll give all that granularity, but we are committed to spending within cash flow -- of the anticipated cash flow and so, based on that kind of guidance, if you want to use the word guidance and looking forward, I think you'd see similar spending levels going forward, as we grow production.

Similar to 2014?

Yes.

Okay got it.

And then secondly in the Eagle Ford, you know you talked about looking to increase your drilling inventory via leasing. Just curious what kind of cost per acre you might be willing to pay or what kind of recent transactions you've seen in terms of acreage cost.

You know, I love that question, and the only unfortunate thing is it's a very difficult question to answer.

This play started off as a gas play. It started off in the dry gas window and acreage prices gradually got very high and then it moved to an oil play, so you've got a myriad of historical prices that ranged from a couple of thousand dollars an acre back at the beginning, to tens of thousands of dollars an acre as it became a robust oil play.

The play has changed materially. There's a lot of wells that have been drilled that give us a lot of data points. There's cores throughout the play.

I think we've got access to one of the most detailed and robust core sets in the whole play or any shale play, and the answer to your question really revolves around the quality of the acreage today, as opposed to just being one trend or in a window. And so, I'm going to say that, as you would expect, the highest quality acreage is going to command the higher price, the lower quality acreage won't, but in the minds of the mineral owners, often they don't know.

And so we're going have to go in here through this, what I'm calling a second round that's going on, and we're going to be willing to pay the right price for the highest quality acreage, which might be you're looking I'd say $500 an acre in the dry gas window. Maybe a little less, and more in the oil window.

You get over the [Carns] trough outside of our backyard, different game. But that's probably as granular as I can give you. Obviously, I want to pay the lower price, but I'm willing to pay a good price for the high quality acreage, which is now very differentiated.

And is the focus going to be on McMullen and Webb, or are you looking to kind of go into other counties?

Well, clearly, we've got a big footprint in Webb, we're producing significant gas. We expect next year to fill that firm capacity up to 160 million a day and get some interruptible above that, so if I get some Webb County acreage similar to Fasken, yes, Webb is on the radar screen. But our backyard as we see it is Webb, La Salle, McMullen. That's our backyard, that's what we know.

Got it, and then quickly moving to Southeast Louisiana and Lake Washington, are you planning on drilling any new drills in 2015? And then lastly, any sort of update on your deep sub-salt prospect in terms of finding a JV partner? Thank you.

Yes, I'll answer that kind of in reverse fashion. The sub-salt is a high risk, high reward project. It really fits a different type of player than Swift Energy Company. We're certainly open to folks that are interested in that, and we certainly do have a position that's HBP'd, so there's not any pressing requirement on us to move on that, and, given our South Texas focus, don't expect us to press it. If someone's interested and wants to go at that sooner rather than later, we will entertain those discussions.

That really kind of goes to the broader sense of we're not doing high risk exploration in Lake Washington, there's a lot of running room in the deeper sands, but that's not part of our strategy certainly near term. We want to be looking at the low hanging fruit. We're going to be looking at recompletions, we're going to be looking at enhancements, and we're doing that this year. Second Quarter, we're -- I mean Third and Fourth Quarter, we're continuing that program.

I think you will see us go back in there next year and drill some of the smaller capital types, lower risk types items. You will see us be fairly consistent in going after the lower risk, more certain types of thing (inaudible). It's a great field, 300 million-barrels produced to date or more. There's still a lot of creaming to do in the more low risk, lower productivity types of things.

Got it, and then last one on the Central Louisiana asset sale, do you have a timeline where you'll say -- okay, I'm going to walk away? Or should I kind of read into your comments that maybe we should see parts of the package being sold?

Well, yes. In terms of the group that we're working with, we do have a timeline, and we've got some milestones, and as long as we're working along that timeline and they're working along the same timeline and meeting those milestones, we'll continue to work this to hopefully a successful conclusion. If at some point in time they are not getting there at the time frame we need to do it, we'll end the discussions.

Yes, and I would add to that. As with any property, anywhere in the portfolio, we're looking at making sure that we maintain or optimize the value. We want to monetize any value that's either non-producing or that can be better suited in the hands of another, and so should we continue forward with Claytex into next year, don't be surprised if we sell pieces of it, or we do some structured things there to reduce the risk of how we might be monetizing it.

Great, thanks guys, good quarter.

Thanks, Robbie.

Your next question comes from the line of Chris Stephens with KeyBanc.

Hi, good morning, guys.

Hi, Chris.

I just wanted to get a little bit more color in your 2015 program? With the flattish CapEx, that would imply 2 to 3 rig program, again, next year in the Eagle Ford. Do you have a ballpark of the split between Fasken and McMullen? And would you go back into La Salle and drill some wells over there to see if you can get the uplift in the returns from your new completion design?

Let me touch on it, and then Bob can talk a little bit about various strategies. Again, it's premature on our part right now to give you any granular plan for 2015, although we have several different plans we're working through right now and we clearly want to optimize our results next year. We clearly want to drill the most productive wells in the most, best areas. We will be focusing the vast majority of our capital in South Texas and the Eagle Ford.

That said, you should expect and you will see us to focus even within the Eagle Ford on where we have the most certainty, where we have the best productive outcome. So, yes, you'll see us continue to drill in Fasken. Yes, you'll see us continue to drill in our oily areas, and, yes, you'll see us with a focus on our balance sheet to ensure that we spend within our cash flow. Call it flattish if you will, but that really is not the issue in terms of production uplift, because we see production growth next year with our ability to spend within cash flow.

We're not giving a 2015 budget right now. We've still got to go through that process with the Board. We will give you that detail as we get further into that process.

Bob, do you want to comment on just the relative metrics and some of the areas you think are going to fit into the 2015 budget?

Well, we can start with Fasken, of course. We have the joint venture there, we have kind of an agreed development pace to try to keep that production level around our firm capacity or maybe even better. So, you'll continue to see a rig down in Fasken next year trying to maintain that production at 160 and maybe even increasing it from there as per our pre agreed development plan with Saka Energy.

With regard to the other areas, you're going to see us back in the PCQ and in that condensate area where we're getting some good results that we just announced to you today. The Whitehurst, we'll be drilling some more there, we'll be drilling some more PCQ wells.

We are looking at La Salle, we are looking in the oily part of La Salle, and the way we've been watching the production there and managing that production, and we're liking what we're seeing in a good portion of that acreage, so we are studying how we could apply this enhanced technology back into that Artesia Wells area of La Salle, but that could also come into play a little bit next year.

Okay, and did you guys book any -- or incorporate any interruptible supply into your 2015 guidance? And if not, I guess would that imply there's possibly some upside if the system gets built out a little bit bigger than what was expected?

I would tell you, with our 2015 guidance there's no implied interruptible. It would be reaching the 160 million a day and maintaining that.

And I want to stress that, while you can refer to it as guidance of a sort, it is very preliminary, and there are folks that are also trying to predict what we're going to do next year. We just feel we're in a better position to give some line of sight on that, and so we've done that, but nonetheless it's preliminary as it sits right now.

Thanks.

Thank you.

Your next question comes from the line of Welles Fitzpatrick with Johnson and Rice.

Good morning.

Good morning.

With the success you guys are having in the JV and Fasken, and Central Louisiana moving a little bit to the back burner, you guys have talked in the past about how you like teaming up with Saka because you could expand that JV into newer areas. Do you foresee any of that happening in, say, the next 12 months?

Well, I think that's a good question. We've always maintained that anything we wanted to do in South Texas in terms of any kind of transaction would be strategic. And, we believe with great purpose and great confidence that the transaction with Saka was not just a disposition of some property, it was a very strategic alliance of their goals, their objectives and ours. It was a focus on dry gas in their part.

It is a significant step on their part to accelerate development of a field, and they have some long term objectives that are theirs alone but they are very aligned with us. And whether you look at the natural gas markets as they relate to Texas Gulf Coast LNG or other things that could come in the future that may not be there in 2015, but certainly look nice and robust in the future they are looking for more supply.

We are certainly in Fasken their partner of choice and we do want to do more things with them. That said, there are other folks also looking longer term, and because of our competitive advantage and our knowledge of the play, we talked with other folks also. We're going to be very strategic in how we grow in South Texas.

That's great. That's all I had. Thanks so much.

Thanks, Welles.

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

Thanks for taking my questions, and sorry I got on the call a little bit late here, but just wondered if you could recap if you had mentioned it earlier, just on kind of the you guys are heading toward a $375 million to $400 million CapEx plan. Looks like you'd be a little over $300 there for the first three quarters, should we imply a little bit of slowdown in the fourth quarter given the pull back in that gas price?

Well, yes, a couple things. We had three rigs running in South Texas, we dropped that third rig at the beginning of the Third Quarter. We're still obviously completing some of the wells that that rig drilled, so there's your slowdown very specifically. And then secondly, we sold the 36% of Fasken to Saka, and so they are now picking up that 36% of their capital for Fasken drilling. In addition to that, there's 18% of those capital costs are part of the carry, so that's a reduction in our CapEx.

Those are probably the big picture items in terms of why that's lower in the Fourth Quarter.

Okay sounds good. And then kind of debt to trailing EBITDA looks like around 3 times on an annualized basis, right now, I guess targets still to get into the low twos?

Yes, obviously trying to enhance the liquidity and all our ratios, so that would be a reasonable target.

Okay, great. Thank you very much.

Thank you, Andrew.

This concludes the Q & A portion of today's call. I would now like to turn the call back over to Mr. Swift for any closing remarks.

Well again, we would like to thank you for joining our Conference Call today, and I want to reiterate and say once again that both the Second Quarter and the First Quarter this year were both strong operational quarters, and we continue to drill better wells at lower costs, and we look forward to our next report with you.

Thank you again.

Ladies and Gentlemen this does conclude today's Conference Call. We thank you for your participation and ask that you please disconnect your lines.