Swift Energy's CEO Discusses Q4 2013 Results - Earnings Call Transcript

Feb.27.14 | About: Swift Energy (SFY)

Swift Energy Company (NYSE:SFY)

Q4 2013 Earnings Conference Call

February 27, 2014 10:00 ET

Executives

Paul Vincent - Director, Finance and Investor Relations

Terry Swift - Chairman and Chief Executive Officer

Alton Heckaman - Executive Vice President and Chief Financial Officer

Bruce Vincent - President

Bob Banks - Executive Vice President and Chief Operating Officer

Steve Tomberlin - Senior Vice President, Resource Development and Engineering

Jim Mitchell - Senior Vice President, Commercial Transactions and Land

Analysts

Neal Dingmann - SunTrust

Welles Fitzpatrick - Johnson

Noel Parks - Ladenburg Thalmann

Brad Heffern - RBC Capital Markets

Michael Hall - Heikkinen Energy

Brian Foote - Clarkson

Ravi Kamath - Sea Port Group

Operator

Good morning. My name is Brigit and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Company Fourth Quarter 2013 and Full Year 2013 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions)

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

Paul Vincent

Good morning. I am Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy’s fourth quarter 2013 earnings conference call. On today’s call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer will review our financial results for the fourth quarter. Then Bruce Vincent, President; and Bob Banks, Executive Vice President and Chief Operating Officer, will provide an operational update before we open the line up for questions. Also present on the call is Steve Tomberlin, Senior Vice President of Resource Development and Engineering; and Jim Mitchell, Senior Vice President, Commercial Transactions and Land.

Before I turn the call over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates, and projections about us, our industry and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports, to which we refer you along with cautionary statements contained in our press releases and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

To complement our prepared remarks, we have prepared a slide presentation, which is available both on our website and through the streaming webcast of this call.

Terry Swift

Thanks, Paul and thank you everyone for joining the call today. I will begin our presentation by noting some 2013 results. We developed a 10-10-10 plan for improved well performance from our Eagle Ford activity. This plan sought to increase IPs and EURs by 10% or more and reduced drilling and completion costs by 10% or more. We are proud of our progress on this and Bob will present these details later on our presentation.

During 2013, we strategically high-graded our natural gas and crude oil assets from the Eagle Ford and South Texas to our Lake Washington field in South Louisiana. We also announced our plans to divest of our Central Louisiana. We also announced our plans to divest of our central Louisiana properties. In South Texas we deployed technology advancements drilling longer laterals and performing hydraulic fracture stimulations, which significantly improved the performance and results in our Eagle Ford program. As an example, late in 2013 we flow tested the Fasken BDC 9H and 10H wells at rates of 17 million and 23 million cubic feet per day respectively. During the fourth quarter we also tested eight Eagle Ford wells in our Northern AWP acreage at an average IP of 1240 barrels of oil equivalent per day, 80% liquids.

During 2013, we continued the development of the Eagle Ford in our Artesia wells area. While we did lower costs and increased IPs in this area, the liquid yields underperformed our expectations. It appears that the liquids or the fluids, varies considerably across this acreage position. To the south we have found a fluid that starts out very rich with liquids but changes its character over time yielding reduced liquids. Portions of our acreage in the North continue to have good liquid yields.

In Lake Washington we made significant progress to improve our results and stabilize the production profile. We plan to reprocess the 3D seismic to help us better exploit existing reserves and develop comprehensive field depletion plans. Prospectively we plan to significantly increase our recompletion program in 2014. The 3D work should also help us progress towards the drilling of a high risk, high reward Subsalt exploratory well. We have two projects underway that will reduce our leverage and increase our liquidity upon completion.

We are currently in negotiations regarding the previously announced asset disposition of some or all of our Central Louisiana assets. And we are also in negotiations regarding a joint venture partner or potential partner in South Texas focused on our Fasken area. While we hope to accomplish both of these, the completion of either will lower our leverage and improve our liquidity and give us additional financial flexibility.

Finally, as previously mentioned we will discuss our 2013 year end reserves results. During 2013 we grew reserves approximately 14%. Bruce will provide an update on our year end reserves and a reconciliation to compare them to the previous year.

I will conclude my opening remarks with the following strategic remarks. I highlighted these fourth quarter events as they tie to our strategy of maintaining a balanced hydrocarbon mix with a diverse portfolio of opportunities. We are disappointed with the downward revisions, but we are extremely pleased with the more stable natural gas opportunities that we have added. These opportunities are best exploited with our focus on technological and operational experience. The exceptional improvements we have made with horizontal drilling and multi-stage fracture stimulation and optimization have led to lower cost and better performing wells. These accomplishments have been augmented by the use of 3D seismic attribute analysis and precision well placement.

As we have noted in previous calls, we are committed to improving our balance sheet and capital efficiency metrics. Our 2014 capital budget of $300 million to $350 million will be flexible and adjusted based on the timing of transactions and the marketplace fundamentals. We expect to improve our production profile and produce 11.3 million to 11.8 million barrels of oil equivalent in 2014. The early 2014 production will be a bit lumpy given that we should have up to six new Fasken gas wells to place into production. The 2014 capital program can be supported by the sale of all or a portion of our Central Louisiana assets or by a strategic partnership to develop gas in our Fasken area. Both of these potential transactions had progressed to the point where we are in negotiation with perspective buyers and potential partners.

And now I will ask Alton to summarize our fourth quarter 2013 financial results.

Alton Heckaman

Thank you, Terry and good morning everyone. Fourth quarter 2013 production of 3.09 million BOE was at the high end of our guidance. Oil was at the low end of guidance while natural gas and NGLs were slightly above guidance. Oil and liquids production comprised 53% of our 4Q ’13 production, virtually unchanged from 4Q ’12. Our overall financial results for the fourth quarter 2013 include oil and gas sales of $146 million, income of $5.8 million or $0.13 per diluted share excluding the effects of a non-cash ceiling test write-down.

Cash flow before working capital changes for the quarter was $77.8 million. And as noted in the earnings release, we recorded a $74 million pre-tax, $47.7 million after-tax non-cash ceiling test write-down in the fourth quarter due to changes in our reserves, product mix, pricing and timing. Our realized price per BOE decreased 7% from 4Q ‘12 driven by an 8% decline in the average crude oil price that we received somewhat offset by improvement in natural gas, which was up 9% and NGL prices which was up 8%. Oil revenue accounted for 66% of our total sales revenue for the quarter.

As to our controllable cost of metrics for the quarter, G&A came in at $3.47 per BOE below guidance. DD&A was also below guidance at $21.19 per barrel. Interest expense was within guidance at $5.85 per BOE. Severance and ad valorem taxes were on the low end of guidance at 7% of revenue and production costs for the quarter, including workovers were slightly below guidance, while transportation and processing costs were within guidance. As previously mentioned, the net result excluding the non-cash ceiling test write-down was net income for the quarter of $5.8 million, $0.13 per diluted share significantly above the first-call mean estimate.

Cash flow before working capital changes for the quarter of $77.8 million and EBITDA of $95 million in tandem with our quarterly CapEx on an accrual basis of $107 million. Given the more predictable nature of our South Texas shale production, we have significantly expanded our hedging program to reduce our risk to commodity price volatility. We recently put in place meaningful natural gas swaps and collars covering a good portion of our production for 2014 with a few swaps even stretching into the first quarter of 2015. We also have executed some oil swaps and collars through mid 2014.

As always, complete and timely details of Swift Energy’s price risk management activities can be found on the company’s website. As Terry mentioned, our focus in 2014 is on strengthening our balance sheet and better aligning our capital spending with our expected cash inflows, which will obviously enhance our liquidity. As noted in our earnings release, we have reduced our capital spending targets for 2014 to levels more in line with our internally generated cash flow and expected disposition JV proceeds.

Our priorities are financial discipline first and gross second. Further, we continue to take steps to reduce our per unit cost and expenses through a number of initiatives. As always, we have included additional financial and operational information in our press release, including initial guidance for the first quarter and full year 2014.

And with that, I will turn it over to Bruce Vincent for an overview of our fourth quarter activity.

Bruce Vincent

Thanks, Alton and good morning everyone and thank all of you for listening in. Today, I will discuss the fourth quarter 2013 activity, including our production volumes, our recent drilling results, activity in our core operating areas and our plans for the first quarter of 2014. Beginning with production, Swift Energy’s production during the fourth quarter of 2013 totaled 3.09 million barrels of oil equivalent near the top of our expected range of outcomes.

Fourth quarter production was slightly lower than fourth quarter 2012 production of 3.1 million barrels of oil equivalent and was comprised of 33% crude oil, 20% NGLs and 40% – 47% natural gas. Fourth quarter production increased from the 3.06 million barrels of oil equivalent produced in the third quarter of 2013 due to initial well performance improving as a result of more effective drilling and completion techniques. For the fourth quarter drilling results, Swift Energy drilled 10 operated wells during the quarter all to the Eagle Ford shale in the company’s South Texas core area. Seven of those wells were drilled in McMullen County and three wells were drilled in Webb County. We currently three operated drilling rigs in our South Texas core area drilling the Eagle Ford shale wells.

In the Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields, production during the fourth quarter averaged approximately 4,904 net barrels of oil equivalent per day, up approximately 3% when compared to third quarter of 2013 average net production from the same area and down 25% from the fourth quarter 2012 levels.

Lake Washington averaged approximately 4,761 net barrels of oil equivalent per day, a decrease of 4% when compared to third quarter 2013 average daily volumes. We expect to accelerate re-completion and workover activity at Lake Washington during 2014. We have identified numerous opportunities and expect to conduct at least 20 of these low cost high return projects this year. We have also determined after contacting numerous significant participants in the subsalt drilling arena that we need to reprocess and further analyze existing data in the Lake Washington field before moving forward with this project. We believe that we can develop much better imaging of the potential horizons and then optimize the placement of the initial test well. And based on these results or the results of the further analysis, we will determine the next steps for this project.

In our Bay de Chene field, production of 143 net barrels of oil equivalent per day was down 21% when compared to third quarter of 2013 production levels due to natural decline and low levels of operational activity.

In our South Texas core area, which includes our AWP, Sun TSH and Las Tiendas Olomos fields and AWP Artesia wells and Fasken Eagle Ford fields, fourth quarter 2013 production of 26,335 net barrels of oil equivalent per day increased 3% when compared to third quarter of 2013 production in this same area and 8% when compared to fourth quarter 2012 volumes. We expect to average between 2 to 3 drilling rigs in this area during 2014.

Earlier this morning, we published specific performance data on our wells brought online in this area during the quarter in our quarterly press release. And I will refer you to that data for more details on our results. The Central Louisiana core area, which includes our Masters Creek, Burr Ferry and South Bearhead Creek fields contributed 2,258 barrels of oil equivalent per day of production in the fourth quarter of 2013, a decrease of 16% from third quarter 2013 production in the same area, primarily due to low activity levels and natural declines.

I will now turn the call over to Bob Banks to highlight the results of our 10-10-10 plan and an overview of our assets. And then I will return to go over the reserve reconciliation and wrap up the call.

Bob Banks

Good morning, everyone. First, an update on our South Texas 10-10-10 plan, that we have talked to you about at our Analyst Day presentation last March. As a reminder, we challenged ourselves to increase our IPs and EURs by 10%, while reducing our drilling and completion costs by 10%.

Moving to our slide deck, on Slide 6, you can see that we increased our IP significantly in each of our Eagle Ford areas that we drilled last year. AWP oil IPs were up 33%; Artesia oil and condensate IPs were up 34%; and Fasken IPs were up 62%. On Slide 7, you can see that we had mixed results with both our AWP oil EURs up 7% and Fasken gas EURs up 85%. In Artesia, however, we did see a reduction in our oil and condensate EURs due to a retrograde condensate behavior that was observed as reservoir pressure was drawn down. I will talk about this further in a few moments.

Moving to Slide 8. We are highlighting part of the reason why we believe that we are achieving better IP and EUR results. We are using our 3D seismic to extract attributes that indicate higher porosity TOC in brittleness. We then tie these attributes to pilot holes in each of our areas that allows us to tighten up on the landing and wellbore placement into a zone of best rock. As you can see from the slide in our early wells, prior to using this methodology, we drove wells that were generally in a 150-foot target zone. We are generally calling these trajectories poor to fair steering against the new standard, which is post 3D criteria, which is a tighter 60-foot target zone. The blue wellbore trajectory in between the dashed yellow line, which represents the new target zone, is what we are now accomplishing on a regular basis. While there are multiple variables and well performance, including lateral length, stage and clusters phasing, profit, quantity and type, we can definitely see an improvement in the wells where we are able to steer the entire lateral length within this narrower sweet spot interval.

Moving to the cost side on Slide 9, we are showing our drilling cost reductions over time in each of our areas. You can see from the graphs that in all areas we are now at or under $3 million for drilling, which includes the time from moving in and rigging up through 3D, including the time spent running and cementing in production liner. We are also showing you our target cost as indicated by the yellow bar, which we consider to be our current technical limits and what we strive for in each wells.

Similarly on Slide 10, we are showing you the same information for each area in terms of drilling days. Overall, we reduced our drilling cost 17% from 2012 to 2013. Staying with cost on Slide 11, we are showing you how we have moved over the past two to three years from a standard completion and stimulation design to an improved then enhanced design. First, we have reduced our per stage full completion costs from $339,000 per stage to $235,000 per stage currently.

Overall, we reduced our completions costs about 11.5% from 2012 to 2013 when we calculated on a per foot of completed lateral length. At the same time, we have increased our stage count from 14 stages and 4.3 million pounds of profit to 19 stages and 7.6 million pounds of profit currently. Additionally, as noted in the slide, we are now logging the laterals to help design our cluster configurations and fetch away that we can optimize our stimulated rock volumes. I’d like to now talk a little bit about our Fasken property and the great work that our team is doing down there.

On Slide 12, you can see the first and foremost, we are dealing with some of the very best rock properties in the Eagle Ford trend. So, that is a great benefit to us. We are illustrating three of these properties that highlight our porosity, TOC and thickness. We believe that each well in this field is capable of IPs at 12 million to 20 million cubic feet per day and EURs of 10 to 15 Bcf.

On Slide 13, we are showing you our most recent well, the Fasken BDC 10H, which IPed at 23.1 million cubic feet a day, a flowing casing pressure of 3,784 psi on a 34/64-inch choke. This well was a 7,000 foot lateral with 21 stages and 8.7 million pounds of profit.

Slide 14 shows our next to the last well, the Fasken AB 9H, which IPed at 17.5 million cubic feet per day and a flowing casing pressure of 3,102 psi on a 34/64-inch choke. This well was a 6,400 foot lateral with 20 stages and 8.5 million pounds of profit. We believe that both of these wells will be representative of what we are able to do going forward.

Next, I would like to review the Artesia Wells area to better describe what we have been experiencing there. As you will see on Slide 15, after 1.5 years from initial startup most wells in Artesia are put on compression. Due to the additional pressure drop down-hole associated with compression installation, condensate has begun to fallout thus reducing condensate production at the surface. This phenomena does not affect the early production of the wells, thus has a reduced effect on project payout and IRR. 50% of the Artesia inventory, the northern area is still in our 5-year drilling plan as it provides favorable economic returns due to higher liquid yields overall. For all future wells in this area, restricted choke management procedure will be instituted and compression will be delayed until the well completely loads up in order to increase liquid recoveries. Four of our newest wells are testing this concept and initial results are very encouraging.

Moving to Louisiana at our Lake Washington Field Slide 16 illustrates how our base decline has been decreasing year-on-year. Due to the watering out of some higher oil rate wells in 2011 and 2012 base decline was approximately 40%. In 2013 the number of higher rate oil wells in the producing well inventory has reduced significantly with low individual well producing over 300 barrels of oil per day. Under these more stable based field conditions it is much easier to arrest decline with numerous recompletion and optimization opportunities in the field plus only a 10% decline in 2013.

Moving to Slide 17, Lake Washington sand deposition around the dome is complex and inner-bedded making well to well sand correlations difficult. To enhance our correlation efficiency the dome has been remapped using easily recognizable maximum flooding surfaces as a foundation. To further enhance our understanding of the deposited sand bodies, seismic inversion has been utilized. As a result of coupling at the maximum flooding surface and seismic inversion techniques, we have reevaluated the prospect potential around the dome with very encouraging initial results. That is demonstrated on Slide 18, which shows remapped prospects of significant oil potential. You can see that we have multiple identified opportunities on all four flanks of the south dome using the techniques I described earlier.

In addition to flank prospectivity Slide 19 shows the Lake Washington cap rock. Lake Washington began as a field in the 1930s with the drilling in shallows 1300 feet in cap rock. Despite the shallow depth several of these wells came between 200 million barrels of oil equivalents. Two cap rock field studies completed after the second phase development in the late 1970s completed that the reservoir had not been adequately drained and remaining recoverable reserves are there. We have been reviewing these two studies over the past two months and are in agreement that the remaining recoverable reserves are likely. We will bring our review to conclusion in 2014 in anticipation of additional drilling in 2015 and beyond.

Thanks for your time this morning. I will turn the call back over to Bruce.

Bruce Vincent - President

Thanks Bob. This is Bruce again. Before I start on the reserve reconciliation I want to go back and correct something that I said earlier when I was talking about the Southeast Louisiana core area. Lake Washington production averaged 4,761 net barrels of oil equivalent per day and that actually increased 4% when compared to the third quarter of 2013 at that time I have said decreased, so I want to get that straight.

Referring to Slide 20, we are showing you the reconciliation of our year end 2013 reserves versus the year end 2012 reserves. Year end reserves in 2013 increased 14.6% from 191.25 million barrels of oil equivalent to 219.227 million barrels of oil equivalent with the primary adjustments coming from the Fasken and Artesia wells area. I know there is a lot of detail on this slide and rather than get into all that detail quickly on the top of the slide, I’ll let you look at that. I really want to highlight the significant changes that we had in the reserves portfolio.

In particular if you look at the lower left you will note the upward adjustments to reserves with particular notes on the additional reserves in Fasken both from the additional drilling activity that we conducted as well as well performance of the existing wells. We are also able to additional reserves in the northern portion of AWP and in Louisiana. In terms of the downward adjustments, the largest component was the adjustment in Artesia wells, which Bob discussed earlier. A significant portion of this was reclassified to the probable category. Additionally, we released some acreage in the South AWP area that we expect to be dry natural gas as we didn’t feel it was economic in today’s market. I also want to note that there is an appendix in the slide deck and we are including a set of slides that further describe each of our acreage positions and the remaining drilling locations and well economics as we thought this would be helpful to everyone.

But before we open it up to lot of questions, I want to summarize our call today. Our initial priority is to conclude two transactions, one asset sale and one joint venture. Our capital program is designed to expand upon the conclusion of one or both of these transactions. We have delivered and are continuing to deliver exceptional increases in the performance of our South Texas wells. Most recently, in our Fasken area with two new wells measured initial productions rates of 17.5 million to 23.1 million cubic feet of gas per day. And moving forward, we expect to have a much more stable production profile bolstered by shallower declines in Lake Washington and more predictable results in South Texas.

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

Question-and-Answer Session

Operator

(Operator Instructions) And your first question comes from the line of Neal Dingmann with SunTrust.

Neal Dingmann - SunTrust

Give me a sense you obviously continue to have some great results on the McMullen and these (indiscernible) results that you have detailed. Just your thoughts, Bob, for you or Bruce, I was wondering now on sort of lateral length as far as spacing down there and just sort of prop at the whole bid, are you still stepping out on these or do you kind of refine the designs?

Terry Swift

Yes. I think we are honing in on the design pretty well up in Northern McMullen County of course, we try to configure it to the least boundary. We do try to drill as longer lateral as possible there. Little bit hard up in that area to get out the 7,000 feet. So, you will see a lot of those wells kind of around 5,500, 6,000 feet, maybe 6,500 feet. In terms of the stage spacing, we have definitely moved down on our stage spacing. And as I noted, we have increased our proppant quite significantly. So our stage spacing now is kind more in that 250 foot range with eight clusters per stage. I think – but the other thing to note that we are doing and I didn’t really talk much about that is that in the lateral length we are logging to try to get good reading on the whole lateral wellbore of the frac gradients, so that we can space our staging and engineer our clusters to optimize our placement of the fracture stimulation in the best rock that’s going to stimulate very effectively. So as we do that stage spacing, we are actually engineering it based upon the log in fairly real time, so that we ensure that we get a good fracture stimulation away.

Neal Dingmann - SunTrust

Okay. And then one other question, Bob, just on looking at the again at South Texas assets, trying to get a sense of just activity for the remainder of the year, two things here just on sort of where these assets are located, what percentage sort of where you think the most activity will be for the remainder of the year and then around whether the right down was around the Artesian wells, trying to get an idea of kind percentage that is of that total South Texas?

Terry Swift

In terms of the activity we are not currently drilling anything in Artesia right now and don’t plan to drill anything there for 2014. Most of our drilling, in fact all of our drilling in South Texas will be geared in the first half of the year in the Fasken area. And then for the remainder for the full year really up in our SMRPCQ Northern AWP area where we are getting great oil results. So, it’s going to be a combination of pretty heavy drilling in the oily area combined with some effective drilling in these high rate gas wells in Fasken.

Neal Dingmann - SunTrust

Okay. And then last if I could just on Lake Washington, Bruce, I know it still seems like you have got a number of opportunities there. Bruce and just in the, I guess the production guidance that’s out there, are you assuming much growth there that many of these things take place or are you assuming that it stays rather flat for now?

Bruce Vincent

We are assuming it stays flat. We are not assuming any growth at Lake Washington.

Neal Dingmann - SunTrust

Okay, thank you all.

Bruce Vincent

Thanks Neal.

Operator

And your next question comes from the line of Welles Fitzpatrick with Johnson.

Welles Fitzpatrick - Johnson

Good morning.

Bruce Vincent

Good morning.

Welles Fitzpatrick - Johnson

I know it might be a little bit early, but any idea where you guys think that the EURs and (GURs) are going to in the Artesia area?

Bruce Vincent

Bob you want...

Bob Banks

Yes, I think if you look at the appendix and even in one of my EUR slides, I think I want to get it out here, you look at that Eagle Ford oil in Artesia, we have that EUR at about 615 to 730 MBoe and in that condensate area and we show you the line of the oil window versus the condensate window is about 636 to 730 MBoe.

Welles Fitzpatrick - Johnson

Okay. Thanks and perfect. I apologize and a little trouble with my computer. And on that Southwestern acreage how much of it is (NYSE:HPP) and if there is a portion that isn’t, do you think you guys are going to let that go?

Bob Banks

I think most of that we were going through that the past couple of days, most of that is held by production. We have earned most of that acreage. So if there is drilling obligation, it’s not very much. But I don’t want to definitively say there is nothing remaining there.

Welles Fitzpatrick - Johnson

Okay, great. And at the risk of asking others that’s on the appendix, the 50 to 60 Fasken wells, is that net or gross?

Bruce Vincent

It’s going to be gross.

Bob Banks

Those are gross wells. Yes. Gross location count but we have 100% of that position.

Welles Fitzpatrick - Johnson

Okay, perfect. Thanks so much.

Operator

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

Noel Parks - Ladenburg Thalmann

Good morning.

Bob Banks

Good morning.

Bruce Vincent

Hi Noel.

Noel Parks - Ladenburg Thalmann

I actually also – I am having a little trouble downloading the slides, so same thing I am sorry if this is included in them, but could you talk little bit about the Fasken economics that you are seeing now with these last wells being as strong as they are, I was wondering if they were improved over maybe the last graphs you put out in like your past Analyst Day and so forth?

Bruce Vincent

Before we answer that just for everyone’s benefit if you are having trouble with the slides, you can go to the Swift Energy website and download it directly from our website, if your trouble with the webcast slides.

Terry Swift

Okay, before Bob – Bob is going to get into the detail of the Fasken, but I won’t kind to give the big picture. We clearly have some of the best rock in the whole Eagle Ford trend right there in the Fasken area it is dry gas. We have had numerous experts working with us that are basically well know in the industry. And I think there is pretty good conformance that this is excellent quality rock. When we look at the wells that have been drilled, we started out with 4,000 foot laterals and lesser sand quantities, lesser stages. Again, a lot of data early on began to develop that gas prices went down as you know and then subsequently the industry is drilling longer laterals with more stages, more sand, better targeting. And we have gone out and done this in Fasken. So it’s really reserves per lateral rank number of stages or stimulated rock. And presently, we are seeing these exceptional results were actually better than we had modeled. But we have gone after almost 7,000 foot per lateral and significantly increased the sand and the number of stages. So you got to keep that in mind and we have driven the cost down. So overall you could be looking at 10 to 15 Bcf a well in a generic sense right now and you could be looking at $7 million to $8 million including facilities we are driving that down, so those kind of development costs are exceptional. Bob?

Bob Banks

Yes, just pick up on that a little bit. You can see one other things, we included in the slide deck on Slide 22 was our Fasken position. The answer to your question is the economics are really outstanding in this area and outstanding for number of reasons; First, our drilling guys have done a phenomenal job and completion guys through driving our cost down. The last well that we drilled and three completed with production line are in place was about $2.65 million. So the capital cost is way, way down. They have got the steering really in a sweet spot there. I think the completion design that we have is really good. The economics are well over 100% in this area at $4.50 gas. The B-10 well, really we believe holds at about 20 million a day for about 90 days, so if it’s 20 million a day for 90 days. You already have taken out 1.8 Bcf in the first three months. At those types of economics combined with what our production guys have done on the LOE side, we have really driven our LOE cost per Mcf way, way down in that area is very efficient to produce this gas. So our operating cost from a commercial structure standpoint delivers outstanding returns. And I will tell you at $4.50 I would drill these all day long. The economics and payouts are well under a year payouts, we get tax credits in this area. So it’s a very, very competitive with just about any Shale Play in North America.

Noel Parks - Ladenburg Thalmann

Okay. Assuming that maybe we are having a temporary uptick in gas prices because of the cold winter, at lower gas prices $4 or $3.50 what do the returns look like they will stay?

Bob Banks

Yes. I think down to $4 gas, you are still over 100% rate of return at $4 if that helps kind of narrow the band for you.

Bruce Vincent

And really look at on our website you can see what we have locked in the way of collars and swaps for natural gas. We have locked in a meaningful percentage for 2014 in the high $4 range even locked in some swaps $6 going out. So take a look at that because again the fact that we are doing this drilling as Bob articulated these things payout in the first two years. So you can sort of lock into your economics and that is even more meaningful.

Terry Swift

Yes. I will note we have also get on the slide in the appendix. We put the F&D cost in terms of dollars per barrel. So we will have to adjust that slide on the economics of the Fasken area all of the other areas so much liquids that we made that error. So I apologize that, we will update that slide.

Noel Parks - Ladenburg Thalmann

Sure. And just what I think on Fasken, what sort of type curve were you using for booking wells previously this last set and are your external engineers going to – gave you some upside to that going forward with the new bookings, do you think?

Bruce Vincent

Yes. We have had this property looked at by a number of outside engineering firms. So we feel pretty confident and basically we just came through reserve audit. The property still that very, very well through our reserve auditors. And most of them our giving us upside and kind of do it in the terms of 1P, 2P, 3P approach. So there is remaining upside but I think we capture kind of the 1P to 3P range in that Slide 22 which is kind of the 10 Bcf to 15 Bcf per well.

Terry Swift

Yes, I think in the initial planning activity we are more at 10 Bcf.

Bruce Vincent

Yes. We’re going to…

Bob Banks

And as you are aware, whenever you actually book, you book on backward price deck that is an important factor because that’s just the rules you use 12 months rolling gas prices backwards. And clearly for the development program, we also have upside in the pricing and the economics that we are showing you here are on the $4.50 not on the backward price deck.

Noel Parks - Ladenburg Thalmann

Got it, thanks. That’s it for me.

Bruce Vincent

Thank you.

Operator

And your next question comes from the line of Brad Heffern with RBC Capital Markets.

Brad Heffern - RBC Capital Markets

Good morning guys. Continuing on the Fasken theme and I was wondering if you could talk a little bit about the thinking behind potentially JV in that. Is that, you think that the faster drilling would give you better economics and having more locations, any color on that?

Bruce Vincent

Yes and yes, yes, we can answer that. Yes, I think faster drilling definitely brings a lot of PV forward. When we look at the 1 and 2P out there and we also look at the fact that you have a lower Eagle Ford and an upper Eagle Ford that we – the upper Eagle ford were really very early in understanding it with wells that can make 10 million to 20 million a day. It doesn’t take a lot of wells to develop an awful lot of productivity that can be very stable. But if you increase that and bring that PV forward, it can be extremely meaningful to Swift Energy Company. There are some very strategic players now that are looking for gas principally for LNG markets as you are aware. So some of them want to go slow, but some of them just want to come in and start taking position and start making money. This is the kind of asset that can do that. We do have a strategy to have a balanced hydrocarbon portfolio. So we do not intend to just load up completely on gas going forward. We want to have that balance. We want to have that diversity. And we clearly do have a desire here to have a strategic partner, where we could potentially do more things in the future beyond this type of transaction.

Brad Heffern – RBC Capital Markets

Okay, thanks. That makes sense. And talking about the CapEx budget, I wonder if you could talk about, if you did an asset sales on how much flexibility there is on that, if you make up a number of safety sells, essentially using it for $125 million, are we guys see you try to come back and spend that money this year or is it going to be something less than that or is the CapEx budget relatively fixed? Thanks.

Bruce Vincent

This is Bruce. The capital budget does have flexibility in it. We have already got identified projects that we can take it up if we feel like we have the capital. That’s not to say that we would necessarily sell our ramp up CapEx to the equivalent of the added influx of capital from an asset sale or joint venture. Clearly, if you did an asset sale and joint venture both we would not ramp up capital that high and we would in fact pay down debt. So we would end the year with a much better balance sheet and better liquidity, but we would have ramped up capital spending. So we definitely have the flexibility there. We definitely have identified projects. I think we have got the access to the equipment that we would need. So we are sent to ramp it up once we have some confidence that we are going to get those – one of those transactions closed.

Brad Heffern – RBC Capital Markets

Okay, great. And just one more for me if I could, do you guys have a well count that you are expecting did online in the Eagle Ford next year and if you could break that down by McMullen versus Fasken, that will be great?

Terry Swift

Well, they are looking for right now, but I don’t think we do not put that on our slides. Bob, do you want to take up?

Bob Banks

Well to some extent, it’s dependent upon what capital spending actually ends up at, so…

Terry Swift

Yes. We will give some more clarity on that later.

Bruce Vincent

Yes. Just again in general and it does tie to that capital and the timing of the transactions, but it will be about two-thirds of the capital going to McMullen the oily area and about one-third going to Fasken. And that’s kind of in general ballpark around 30 wells is what we would like to achieve.

Terry Swift

Yes. And that’s talking drilling cap, although I do want to at least put a little bit of focus back on Lake Washington. We are doing some very important re-completion activity in Lake Washington and we are again going back to this flexible thing offsetting to drill Fasken wells all day long I will do recompletions in Lake Washington all day long and we are setting ourselves up to be able to do more rather less. We have got significant amount of capital within Lake Washington. I am going to say $15 million to 20 million going to recompletions out there.

Brad Heffern – RBC Capital Markets

Great, thanks guys.

Terry Swift

Thank you.

Bruce Vincent

Thanks Brad.

Operator

And your next question comes from the line of Michael Hall of Heikkinen Energy.

Michael Hall - Heikkinen Energy

Thanks. Good morning.

Terry Swift

Hey Mike.

Michael Hall - Heikkinen Energy

A decent amount of mine has been covered. I wanted to I guess understand a little better the steps you are taking to try and resolve the retrograde issues in LaSalle, just if you could maybe review that a little in terms of how that might potentially help the situation going forward with the 50% of the acreage you currently think is maybe on economics, can these move compression timing techniques in one hand help the situation going forward and kind of when might you have a read on that?

Terry Swift

Okay, this is Terry. I am going to take a shot at that and then let Bob finish up because he and the operating team have deep into this issue. What we found is the Western part of our acreage is different than the Southern part is different than the Northern part. And these differences are material in everything from the nature of the fluid, the IPs we get in those areas, the NGLs that we get out of the gas and it – this is varying a lot across the area. So we are kind of in that little fairway where mother nature has created these what I would call a distillation column. And we drilled enough wells, we know where the right place to be in the distillation column is and we know where there is the wrong place.

Now, what does the wrong place mean, it means that low gas prices at low NGL prices it doesn’t make sense to us and certainly the shorter length laterals that we started to program didn’t make sense to it. So I think with an uplift in pricing of both NGLs and natural gas and with longer laterals more efficient or more capital efficiency on the fracs you might find the Southern acreage becoming attractive again because (indiscernible) a fair amount of early liquids. Start of these – these wells start out at well over 100 barrels per million of condensate production and then they also have considerable NGLs in the gas stream, that’s where the economics really are there. But over on the West side we just didn’t get the initial rates that we are looking for. We didn’t get the amount of liquids we are looking for, so I am less optimistic on the West side as you kind of almost leave the county basically leave La Salle County.

And I am more optimistic in the South that we can combine both technology and prices being more attractive to bring that acreage back into a commercial status. The Northern part of the acreage we feel very good about. We actually have kind of a good opportunity in terms of how we produce these well. We are finding just the difference between a 600 psi flowing tubing pressure and the 400 pound tubing pressure can be a big difference in the amount of condensate we get out of the well. So as Bob noted earlier we are trying to optimize that and flash the gas on the surface instead of down in the lateral. Bob do you want to add to that?

Bob Banks

Yes, just a couple of additions to that. And first of all just to make sure we are clear the phase north of that oil condensate line that area is very economic. We have some of that falling out behavior, but the economics are very good at $4.50 and $90 and is worthy of investment right now today. The area in the condensate window south of that line on the chart is not really uneconomic, at $4.50 and $90 oil is just not as robust economics as we would like to see. And with the inventory that we currently have, we are going to divert our capital where we are getting the better economic returns. But even in the condensate area it’s not uneconomic from a PD#10 standpoint without any uplift from the managed chokes and the – trying to delay the compression. So we are still getting about 60,000 barrels of oil recovery and its flat at about 150 barrels to 200 barrels per day in these wells. So I mean I think as we experiment with managing these chokes, managing the reservoir drawdown, delay that compression and when we do put compression in really don’t pull the reservoir pressure down, I think we have a got a lot of room to go up from here.

Terry Swift

I will just give one final comment to that. We have asset teams that work with these properties and are deeply involved in both the drilling as well as the appraisal and operations of property. And the asset teams looked at this and they made their determinations. And we just felt it is better to have some opportunities to come back to this and try to give better capital efficiency. And so we have taken the steps to not put it in this year’s drilling activity and to – as you see have the revisions that we have.

Michael Hall - Heikkinen Energy

Okay, that’s helpful color. I appreciate it. We’re seeing hurdle that lot of this variation and throughout the Eagle Ford just last few weeks. I’m just curious, as you look at the activity in McMullen County, you have some acreage that can crosses over there. Condensate window into the gas window and that transition on seems to maybe be where some of those variability is emerging most materially, are you seeing any of the sorts of observations in McMullen any commentary on that?

Bruce Vincent

Yes. I mean the answer your question, no we’re not seeing in the same type of behavior at all over in McMullen. In fact the last condensate where we drill was really a fantastic well. We just on see any kind of retrograde behavior at all in McMullen.

Bob Banks

There is variation, though, the North to South particularly in terms of hydrocarbon makeup or is in the North is very oily and all the way to the south its very dry gas and you get the condensate window between. And there is some areas is that or not is quite is other meaning they have got some faulting that you have to be more conscious when your designing your lateral lengths and so.

Bruce Vincent

Saying that our Southern McMullen where we do have a lot of probable and potential gas. We did release down there because which relative economic compare to all the other things we have and so that’s area that I think the technology and better gas prices, you could have some material opportunities in the future. So not you have to remember lot of McMullen particularly in the South is gas not oil.

Terry Swift

And just last point on that Michael we have excellent 3D coverage over AWP that’s we are showing all the inversion work where we’ve got all of our mapping done really in the position way. So, we clearly know what we’re doing in that area we don’t have to be encumbered by any kind of faults or fracs I mean I think we have a very good image of what we’re doing down there.

Michael Hall - Heikkinen Energy

Okay, that’s helpful. I guess last one my and I just in terms of the potential JV at Fasken, is there any bias towards upfront cash versus carrier. Is that still up in the air for discussions?

Alton Heckaman

Yes, I mean yes, there is a bias, the bias is to strategically again have a good hydrocarbon mix in the overall portfolio to make sure the extinct we do a joint venture that we get proper value for that which of course would have cash component that’s we would hope could be meaningful because another strategic objective just improve the balance sheet and have be more flexible with better liquidity.

Michael Hall - Heikkinen Energy

Okay, that’s helpful. Thanks guys.

Bruce Vincent

Thanks.

Operator

And your next question comes from the line of Brian Foote with Clarkson.

Brian Foote - Clarkson

Good morning. You have done through also lot of what I was going to ask. However, I wanted to get a little bit more clarity on the shape of the drilling program across the year. You talked about 2 to 3 rigs working under the current situation which shifting in the back half of the year to more liquids prone areas. How does that work and what is the gating factor between running two rigs versus three any given point. And what the sale I know you answered this partially before but would the sale earlier in the year of the Central Louisiana assets may be imply the bias towards 3 or more rigs.

Bob Banks

Yes. I think just a quick stab at that, yes, the disposition early in the year would bias as more towards the 3 or 4 or 3 rig drilling program throughout the full year. That’s kind what we would like to achieve, but as Terry and Bruce noted we got some lower capital guidance out there. That if you as we don’t get those transactions away depending on the timing of all that maybe two rigs.

Alton Heckaman

Well I will add to that basically we designed budget that have flexibility. We have done that so that we have our first priority to be fiscally responsible than provide some fiscal discipline there and to improve our liquidity, improve our balance sheet. That’s our first priority. Clearly by having multiple things going on in terms of achieving that of both the joint venture strategy as well as the Central Louisiana asset sale, we are confident given our current situation and currently anticipate having these transactions done such that we can accomplish our goals this year.

Brian Foote - Clarkson

And within the complexion of the 30 rigs, the 30 wells that you say that you will drill, how much of that is McMullen liquids within the 30?

Bruce Vincent

Well, we said, yes, I think we said that under a 30 program, it would be about two-thirds McMullen liquids, one-third Fasken gas.

Terry Swift

And I want to emphasize, we are clearly aware that gas has kind of been a little stepchild through, certainly through the past couple of years. We are encouraged by the better gas prices we see today. We are not just moving to gas for gas sake, we are definitely having a gas component here, because we find ourselves with – at an exceptional gas asset that has rates of return, payouts and economic metrics that compare favorably or even better than a lot of the oil projects that are out there available today.

Brian Foote - Clarkson

Yes, they sound like great results. Thanks again.

Bruce Vincent

Thank you.

Operator

And your next question comes from the line of Ravi Kamath with Sea Port Group.

Ravi Kamath - Sea Port Group

Hey, guys. Just had I am also having difficulty with the presentation, so I apologize if this is already in there, but I wanted to get some details with regards to Artesia Wells, what was the year end 2013 proved reserves, a developed and a commodity mix? And how much of your acreage is in Artesia Wells and how much are relative to what your total acreage is in the Eagle Ford? And also if you can maybe talk about what the year end PV10 was in Artesia Wells? Thank you.

Bruce Vincent

We don’t slow. We don’t have that information in front of us here, Ravi. And then actually we don’t disclose that to that level.

Terry Swift

Yes, there is some level of…

Ravi Kamath - Sea Port Group

Yes.

Bruce Vincent

I mean, in the 10-K which we think it file tomorrow, you will be able to see a lot of the information you are asking for.

Ravi Kamath - Sea Port Group

Okay. And then what about production maybe Q4 production from our Artesia Wells as a percentage you have hit total Eagle Ford?

Terry Swift

We will have to look that up and then get back to you on that, but…

Ravi Kamath - Sea Port Group

Okay. And then on the Central Louisiana asset sale, I was just wondering if the bids that you have received are adequate and now you are just kind of negotiating the final sort of the details, maybe any color on that would – which will be helpful?

Terry Swift

Yes, I appreciate that request for detail, but obviously we are in the middle of negotiations and just not in a position to comment further.

Ravi Kamath - Sea Port Group

Okay. Alright, great, thank you guys.

Terry Swift

Okay, thank you.

Operator

And there are no further questions at this time.

Terry Swift

Okay. Well, again we thank you for joining us and look forward to next quarter’s call.

Operator

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

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Swift Energy Co. (SFY): Q4 EPS of $0.13 Revenue of $146M (-7.5% Y/Y) misses by $3.55M.