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Swift Energy Company (NYSE:TRK)

Q2 2014 Earnings Conference Call

July 31, 2014 10:00 AM ET

Executives

Paul Vincent - Director of Finance and Investor Relations

Terry Swift - Chairman and CEO

Alton Heckaman - EVP and CFO

Bruce Vincent - President

Bob Banks - EVP and COO

Steve Tomberlin - SVP of Resource Development

Analysts

Brad Heffron - RBC Capital

Michael Hall - Heikkinen Energy Advisors

Noel Parks - Ladenburg Thalmann

Neal Dingmann - Suntrust Robinson Humphrey

Ravi Kamath - Seaport Capital

Chris Stephens - Keybanc Capital Markets

Andrew Coleman - Raymond James

Operator

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’s Second Quarter 2014 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions).

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.

Paul Vincent

Good morning. I am 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 to 30 minutes and have allowed additional time for questions.

Terry Swift

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 area in South Texas. This growth was delivered with capital expenditures 28% below 2013 second quarter level.

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 the joint venture transaction with PT Saka, Indonesia in our Fasken area in Webb County. The $175 million consideration Saka paid for 36% interest in our 8,300 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 one 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 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. At the 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 1,400 barrels of oil equivalent per day. South of our PCQ area, in the Whitehurst area, two new wells averaged initial production slightly over 3,000 barrels of oil equivalent per day. We’ve really got our operations moving at a very nice pace and are enjoying the success that comes with the cohesive team based approach to our oilfield operations.

We expect that there’s more room for improvement in our results in all of our areas due to improved application of the available technology. We’ve maintained for the most part of this year that 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 develop in 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 exiting 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 that 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’ll be able to do the same based on our knowledge in the trend.

Our focus on the Eagle Ford shale gives us the 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 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 so summarize our second quarter 2014 financial results.

Alton Heckaman

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 ’14. 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 a $1 million in transaction related cost 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 a $1.74 per Boe and lease operating expenses came in at $6.36 per Boe. LOE cost came in favorably due to higher volumes and numerous cost reduction efforts but also benefited this quarter from adjustments where actual cost coming in below our previous original accrual estimates.

On a normalized basis, our LOE per Boe for 2Q ‘14 would have been about $0.90 to $1 per unit higher, based on the 2Q ‘14 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 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 Company’s Web site.

As Terry mentioned in his intro, in 2014, we continue 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.

Bruce Vincent

Thanks, Alton and good morning everyone. Thanks for listening. Today, I will discuss the second quarter 2014 activity including our production volumes, our recent drilling results, activity in our core operating areas as well as our plans for the third quarter of this year.

Beginning with production, Swift Energy’s production during the second quarter 2014, totaled 3.45 million barrels of oil equivalent or at the 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 also the Eagle Ford shale in the Company’s South Texas core area. Seven of those wells were drilled in McMullen County and four wells were drilled in the 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 a Lake Washington and Bay de Chene fields, production during the second quarter averaged approximately 4,036 net barrels of oil equivalent per day, down approximately 20% when compared to the second quarter 2013 average net production from the same area and down 8% from the first quarter of 2014 levels. Lake Washington averaged approximately 3,940 net barrels of oil equivalent per day, a decrease of 7% when compared to first quarter 2013 average daily volumes. Recompletion of 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 field 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 will refer you to that detail as opposed to reside 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 and 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 see an opportunities to further reduce capital cost.

In McMullen County, six wells with an average IP of 1,946 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 3,000 barrels of oil equivalent per day, 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 of 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 core area which includes our Masters Creek, Burr Ferry and South Bearhead Creek fields contributed 1,731 barrels of oil equivalent per day at production in the second quarter 2014, at the decrease of 16% from the first quarter of 2014 in the same area, primarily due to low activity levels and natural declines. I will now turn it over to Bob Banks, who will cover the results for the quarter in more detail.

Bob Banks

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 cost 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 at second quarter of 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 cost 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 have also applied some of the same enhanced technology in the new Whitehurst well. It’s 130 miles to the east of Fasken and our AWP field in McMullen County. For these two wells, we increased our lateral lengths by 12%, reduced our drilling days and cost by 15% and 8% respectively, increased our stage count and profit 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 to three years, we know that at some point in time the enormous appetite of our industry will periodically drive cost 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 previously believed.

This not only validates the technology and techniques we’ve 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 for the drilling out of our plugs and are beginning to cut that time and cost in half. Additionally, we are working on an improved design efficiency and effectiveness 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 Energi 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 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 put a great deal of energy into our 2014 program to-date and it’s encouraging that we are exceeding the expectation that we’ve had for this point in the year. With that I believe, Terry has the closing remarks.

Terry Swift

Thanks, Bob. Before we open the line for questions, I will 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 cost in all of our areas in South Texas. Enhanced drilling and completion designs continue to improve the results we are 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.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). Your first question comes from the line of Brad Heffron with RBC Capital.

Brad Heffron - RBC Capital

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?

Terry Swift

We are just giving more or less our strategic line of sight for 2015. It is very early, clearly without giving you a mixed number which we are not prepared to do at this time. We haven’t formalized our final budget for 2015 that the Board review that we will have a little later in the year. We will 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 are not prepared to give any precise numbers.

Brad Heffron - RBC Capital

Okay, I understand. And then looking at the new 2014 guidance, there was a slight shift to more gas, taking some out of oil, is that reallocation of drilling to sort of gassier areas where you are seeing better results?

Terry Swift

Well, maybe a little bit but not so much, it really has more to do with our performance at Fasken. I mean 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 foremost 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 of the second quarter and we will obviously try to access as much as we can but we have been told by midstream provider that they anticipate having less interruptible available and with our other producers that have firm transportation capacity in the 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 have talked before about drilling a four pack well in Fasken that’s currently being fracked and we have had to shut in some of these big producers while that’s being fracked. Now that’s good news because we are 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.

Brad Heffron - RBC Capital

Okay, understand. 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 will have there?

Terry Swift

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 have been drilling down in the Whitehurst area and have significant core data, log data, seismic data and we have always liked that area. We are coming back into the area with the technology improvement that we have seen across the play. There is a significant amount and you can see it by the test of condensate that’s associated with this gas. It’s a very, very rich gas. We are 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 are going to get some of that.

So, I think it’s fair to say that in our existing outlook of reserves and the things that we are doing, there is 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?

Bob Banks

Yes, I would just add to that on the payout question with what we are seeing from these two new wells, we feel very comfortable that payouts are going to be under 18 months on these wells. And we are 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 have endorsed for purposes of reserves, is a lot less than what we are seeing from these results. And it’s probably a little 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.

Operator

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

Michael Hall - Heikkinen Energy Advisors

I mean just a couple of questions on my end, just looking out at the 2014 guidance we put. On that third quarter number, do you guys can tell how much you are incorporating in that for interruptible volumes? And I know you talked about you are already getting the message from the Midstream providers there would be less available. But is there any assumed in that number or how much of it.

Terry Swift

There is within the range. Our firm capacity at Fasken is 75 million a day. And so we’ve kind of run some sensitivities, 75 and 85 and even up to a 100, and based on the both 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’d 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 that 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.

Michael Hall - Heikkinen Energy Advisors

And then on the fourth quarter kind of implied the CapEx shows a pretty material decline from third quarter and the first half on a run rate basis. Can you just kind of walk through some of the high level outline of how you reduce that spend rate so materially in the fourth quarter?

Terry Swift

Yes, this is Terry. Let me kind of lay out three premises; first of all, that was a goal. So we’ve been guiding that direction all along this year get’s focused through 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% borne by Saka plus additional drilling that we do post transaction there is a carried interest that’s of there, of it’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 are getting more productive wells in all our areas, which means we have to expend less capital to get that production but also we are driving our cost down in all of our areas. We’re having a fewer drilling days to get these well down, we’re seeing more efficient levels of expenditure on the completion. So, those three items won as we purpose to drive at that way to 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 spend.

Bruce Vincent

I’ll also point out that we did drop the third rig in South Texas, it 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.

Michael Hall - Heikkinen Energy Advisors

Can you remind me what, just kind of a follow up to that, what average per well costs are running in, say Fasken and in McMullen? Sorry if I missed that if you already provided it.

Bruce Vincent

Yes, are you talking about completed or drilling side at all?

Michael Hall - Heikkinen Energy Advisors

Full BMC, that you’re running at.

Bruce Vincent

All-in at Fasken, we’ve driven our costs really down to depending on how much profit we’re pumping. Like I said, we are driving our costs per completed foot of lateral down but we are increasing our profit, we are increasing our stages, there is 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 7mm, and down in this condensate area that we announced today those are right now running about 8 million.

Michael Hall - Heikkinen Energy Advisors

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

Terry Swift

Yes, we’re currently at about 180 million to 190 million, Michael. And we see that sort of staying flat. The borrowing base has reduced by what…

Alton Heckaman

Oh, I’m sorry, I thought it was from outstanding.

Terry Swift

But what was the borrowing base reduced by, I think it was 30.

Alton Heckaman

I think we’re about 417 versus the 450, correct.

Michael Hall - Heikkinen Energy Advisors

And then I guess to ask on the Central Louisiana sale. I mean what if that just doesn’t get done or kind of what sort of update on the process there do you have, is there anything in particular open up and then at what point you just move on?

Terry Swift

Yes, this is Terry. I will give a little bit of color to that. We’ve always seen these properties as having some good quality to them, they’re oil they’re liquid tight properties. We clearly need to be in these properties doing maintenance work over-type work, some of that was done in the really began on 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, drilling a few wells, 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 will get back with your 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’re bidding these big wells in Fasken and now seeing some big results across all of our acreage as we transfer the technology there.

Michael Hall - Heikkinen Energy Advisors

Great, that’s helpful. Again, congrats on the progress in South Texas, thanks guys.

Operator

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

Noel Parks - Ladenburg Thalmann

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 billing activity there. Was the well improvement done, what do you see happening to the production curves, is it -- are you attributing, or I should say, do you expect now to mainly just bring a lot of the production forward or actually the whole curve gets shifted up now with the region assets?

Bob Banks

The whole curve, Noel, let me, 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, declined curves are performing from the first or the second or 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 declining curves for these Fasken wells.

Terry Swift

This is Terry. I would like to put it in kind of the simplest term I can. While there is a lot of technology improvement in terms of how steer the wells and the type of completion fluids the amount of sand, the pump grades, they’ll want to take away from that. That’s a critical of the success here. But I think it’s 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 a 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 are almost double the lateral length but also in the early days we are putting 3 million to 4 million pounds of sand to stimulate that reservoir, today we’re up to 8 million, 9 million, 10 million pounds of sand to stimulate it, and we’re doing all that more effectively. So if in the old days you had one pud and you drill 150 acre pud, 50 acre drainage and then you say, well I can drill two of those, you’d expect twice production twice the reserves. Here in Fasken, you are basically developing a more acreage with more lateral.

Noel Parks - Ladenburg Thalmann

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

Terry Swift

Well I think I will 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 longer time period against the line pressures that we have and the techniques. So I think there is an opportunity certainly we see it in probables and possibles now to increase that but we are not ready to do that. So our number right now though we see more upsides and downside right now.

Noel Parks - Ladenburg Thalmann

So again what you’re comfortable with right now, but it sounds like it is conceivably sound conservative of the years down the road.

Terry Swift

Well, we’re trying to be that way. I mean Mother Nature throws you curve balls both directions, sometime she gives you great opportunities but you got to be careful not buy them off too fast.

Noel Parks - Ladenburg Thalmann

And Bob has mentioned in his comments that the plan was to increase the stage-count in the sand loading by 10% to 20% and it is also I mentioned of doing more with the total frac. And where is the frontier do you think in terms of the number of stages and the amount of profit? Just in your part of the Eagle Ford you have people gone considerably further than what you’ve done in terms of those qualities?

Bob Banks

Well, I mean I think some people have probably been out a little ahead of us but we have to say we’re kind of in the upper end of pushing this technology and calibrating into our well performance, but you asked a good question about where is 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 they don’t add value.

So I’m just trying to give a glimpse of our next stage of some of the things we’re going to keep pushing, because we believe you 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.

Noel Parks - Ladenburg Thalmann

Great, that’s all from me.

Operator

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

Neal Dingmann - Suntrust Robinson Humphrey

Good morning guys. So just a question more on realizations, obviously I think it was month or two but I think in May when you guys signed the FT in the Fasken area. So I guess when ultimately you guys model this, how do you think about sort of I guess two questions around that; one, you haven’t had any takeaway issues now in sometime. Do you feel pretty confident that that will continue to be the case now that I think you got a couple different options it seems to be better? And then number two; on this takeaway that you have, I’m just wondering about realizations, how you think about taking it to the different areas and sort of factoring that with the given the FT that you’re singing up?

Terry Swift

Well, I’ll take the first part of that question and then I’ll handle off to Bruce to handle maybe the interruptible side because he is right on top of that. But we’ve 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 get beyond our guess. 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 basically 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 takeaway will be very strong.

Bruce you want to talk about the interruptible?

Bruce Vincent

Yes, I was going to -- let me comment couple of things. Let’s stick with Fasken for the time being. I was going to like thank on a Terry did when we get the 160 firm transportation capacity we think we’ll have well capacity above that, so interruptible is still going to 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 maybe under supplying their firm transportation.

Our midstream provider has told us, which I indicated earlier, that they are -- some of their producers that have firm capacity have indicated that increasing level of production into the third and fourth quarter to use their firm transportation, which means less interruptible available. That same Midstream provider though, in conjunction with the work he is 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, one additional interrupt capacity might be available to us.

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

I think your questions was also a little broader in terms of the other area, so let me give you a quick synopsis of that. The 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 and La Salle County, the same thing is true, we don’t see any capacity strengths unless we either; one, we’d have to increase the level of capital spending on the gas side that 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. And we’ve already got all the plans in place. We expect that additional capacity to be available early next year, whether it 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 quarter and fourth quarter before that additional firm is in place.

Neal Dingmann - Suntrust Robinson Humphrey

You’ve got good answer to that great Bruce and just one follow up to that just on the differentials around that. I guess because you have so much of this firm transport, is it fair to say that I guess more than others, you are a little more confident on differentials and such because more of that’s locked in or just kind of wondering how the kind of I guess the modeling question I mean going forward how to think about the differentials?

Bruce Vincent

That’s a fair comment. I think that certainly the firm transportation, the interruptible has a little bit different cost to it. And then as I mentioned in Fasken, if we are able to -- if our principal midstream provider we have the firm transportation with, the cost of interruptible is X. If they are 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 higher volumes with that. We’ve tried to factor that in, in terms of our guidance. We think we’re relatively on with that.

Operator

Your next question comes from the line of Ravi Kamath with Sea Group.

Ravi Kamath - Seaport Capital

A couple of questions one on the 2015 production guidance, the early guidance that you provided, what would be associated CapEx or that would be just a broad range?

Bruce Vincent

Well, again, we’re trying to be careful to explain that this is more line of sight and strategic look-forward into ’15. 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, 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.

Ravi Kamath - Seaport Capital

So similar to the 2014?

Bruce Vincent

Yes.

Ravi Kamath - Seaport Capital

And then secondly in the Eagle Ford, 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?

Bruce Vincent

I love that question and the only unfortunate thing is it’s a very difficult question to answer. This place started-off as a gas play. It started-off in the dry gas window and acreage prices gradually got very, and then it moved to an oil play. So you’ve got a myriad of historical prices that range from a couple of thousand dollars an acre back at the beginning to tens of thousands of dollars in acre as it became robust oil play. The play has changed materially there is 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 steps in the whole play or any shale play.

And the answer to your questions really revolves around the quality of the acreage today as opposed to just being on trend or in a window. And so I am 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 mineral owners, often they don’t know. And so we we’re going to have to go in here through this, what I will call it a second round that’s going on, and we are going to be willing to pay the right price for the highest quality acreage which might be you are looking I’d say $500 an acre in the dry gas window, maybe a little less and more in the oil window.

And you get over the Cons 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 with high quality acreage, which is now very differentiated.

Ravi Kamath - Seaport Capital

And is the focus going to be on McMullen and Webb or I’m looking kind of go into other counties?

Bruce Vincent

Well clearly we’ve got a big footprint and there 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 performed at the rate of our stream. But our backyard we see it is Webb, plus all McMullen, that’s our backyard, that’s what we know.

Ravi Kamath - Seaport Capital

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 Subsalt’s prospect in terms of finding the JV partner? Thank you.

Bruce Vincent

I’ll answer that kind of in a reverse fashion. The Subsalt is a high risk, high reward project it really fits a different type of player than Swift Energy Company. We are certainly open to folks that are interested in that and we certainly do have a position that’s HPP. So there is 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 is interested and wants to go with that sooner rather than later with, we’ll entertain those discussions.

That really kind of goes to the broader sense that we’re not doing high risk exploration in like Washington there is 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 recompletions, we’re going to be looking enhancements, and we’re doing that this year, second quarter, 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 of items. You will see us be fairly consistent in going after the lower risk more certain types of things and those portions. It’s a great field, 300 million barrels produced to-date or more, there is still a lot of creaming to do I the more low risk, lower productivity types of things.

Ravi Kamath - Seaport Capital

Got it. And then last one, one the Central Louisiana asset sale, do you have a timeline where you’ll see it again with an walk away or should I kind of read into your comments that maybe we should see parts of the package being sold?

Bruce Vincent

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 pointing in time they’re not getting there, the timeframe we need to do it, we will end the discussions.

Terry Swift

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 not producing or this can be better suited in the hands of another. And so should we continue forward with Claytex in the next year, don’t be surprised if we saw pieces of it or we do some structural things there to reduce the risk of how we might be monetizing it.

Operator

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

Chris Stephens - Keybanc Capital Markets

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

Terry Swift

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, the Eagle Ford.

Okay, 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 will see us continue to drill in our all the areas and yes you will 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 still got to go through that process with the Board, we will give you that details as we get further into that process. Bob, you want to comment on just the relative metrics in some of the areas you think of are going to fit into the ‘15 budget.

Bob Banks

Yes, 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 I mean you will continue to see a rate 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 with Saka Energi.

With regard to the other areas, you are going to see us back in the PCQ in that condensate area where we are getting some good results that we just announced to you today, the Whitehurst, we will be drilling some more there, we will be drilling some more PCQ wells. We are looking at La Salle, we are looking in that oily part of La Salle and the way we’ve been watching the production there and managing that production and we are liking what we’re seeing in a good portion of that acreage. So we are studying and 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.

Chris Stephens - Keybanc Capital Markets

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

Alton Heckaman

Yes, I would tell you with our 2015 guidance there is no implied interruptible, it would be reaching a 160 million a day in maintaining that.

Terry Swift

And I want to stress that while you can refer to it as guidance of a sort, it is very preliminary and it’s only meant, there are folks that are also trying to predict what we are going to do next year. We just feel that we are 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.

Operator

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

Welles Fitzpatrick - Johnson Rice

With the success you guys are having in the JV in Fasken and Central Louisiana maybe moving a little bit to the back. 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?

Terry Swift

Well I think that’s a good question, we’ve always maintained that anything we wanted to 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 line of a field and they have some long term objectives that are there’s alone but they are very aligned with those.

And whether you look at the natural gas markets as it relate to Texas Gulf Coast LNG or other things that could come in the future that may not be there in ’15 but certainly look nice and robust in the future, they are looking for more supply. We are at certainly in Fasken their partner of choice and we do want to do more things with them.

That said there are other folks that are also looking longer term and because of our competitive advantage and our knowledge of the play, we talk with other folks also. We’re going to be very strategic in how we grow in South Texas.

Operator

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

Andrew Coleman - Raymond James

Just wondered if you guys could just recap if you had mentioned it earlier just on kind of you guys are heading toward 375 million to 400 million CapEx plan. It looks like it’d be a little over 300 there for the first three quarters. Should we imply a little bit of slowdown there in the fourth quarter given the pull back in that gas price.

Terry Swift

Well a couple of things. We did, 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 at that rig drilled. So there is a 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 is 18% of those capital costs are part of a carry, so that’s a reduction in our CapEx. So I think those are probably the big picture items in terms of why that’s lower in the fourth quarter.

Andrew Coleman - Raymond James

And the kind of debt-to-EBITDA, was like around three times on an annualized basis right now I guess target still to get into the low 2s?

Terry Swift

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

Operator

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 remark.

Terry Swift

Well, again we’d like to thank you for joining our conference call today and I want to reiterate and state once again that both the second quarter and the first quarter of 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.

Operator

Ladies and gentlemen, this does conclude today’s conference all. We thank you for your participation and ask that you please disconnect your lines.

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Source: Swift Energy's (SFY) CEO Terry Swift on Q2 2014 Results - Earnings Call Transcript
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