SilverBow Resources Inc (SBOW) 2013 Q4 法說會逐字稿

Good morning. My name is Bridget, 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)

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

Good morning. I'm 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 updates before we open the line up for questions. Also present on the call is Steven 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 questioning. 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.

Thanks, Paul. Thank you to everyone for joining the call today. I'll 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 reduce drilling and completion costs by 10% or more. We're proud of our progress on this, and Bob will present these details later in our presentation.

During 2013, we strategically high-graded our natural gas and crude oil assets from the Eagle Ford in South Texas to our Lake Washington Field in South 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 1,240 barrels of oil equivalent per day, 80% liquids.

During 2013, we continued the development of the Eagle Ford and our Artesia Wells area. While we did lower cost and increase IPs in this area, the liquid yields underperformed our expectations. It appears that the liquids, or the fluids, vary 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 planned to reprocess the 3D seismic to help us better exploit existing reserves and develop comprehensive fuel 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're currently in negotiations regarding the previously announced asset disposition of some, or all, of our Central Louisiana assets. And we're 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'll 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're extremely pleased with the more stable natural gas opportunities that we've added.

These opportunities are best exploited with our focus on technological and operational experience. The exceptional improvements we've 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 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 in 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 have progressed to the point where we are in negotiation with prospective buyers and potential partners. Now, I'll ask Alton to summarize our fourth-quarter 2013 financial results.

Thank you, Terry. 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 2013 production, virtually unchanged from 4Q 2012.

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 2012, 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 above the first column 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've 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 grow, second.

Further, we continue to take steps to reduce our per unit costs and expenses to a number of initiatives. As always, we've included additional financial and operational information in our press release, including initial guidance for the first quarter and full-year 2014. With that, I'll turn it over to Bruce Vincent for an overview of our fourth quarter activity.

Thanks, Alton. Good morning, everyone. 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's energy 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 through 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 have three operated drilling rigs in our South Texas core area drilling 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 and 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 recompletion 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've 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. Based on these results, 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 2013 production levels, due to natural declines and low levels of operational activity.

In our South Texas core area, which includes our AWP/Sun TSH and Las Tiendas Olmos fields and 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 2013 production in this same area, and 8% when compared to fourth quarter 2012 volumes.

We expect to average between two to three 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 fourth quarter 2013 production in the same area, primarily due to low activity levels and natural declines.

I'll 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'll return to go over the reserve reconciliation and wrap up the call.

Good morning, everyone.

First, an update on our South Texas 10-10-10 plan that we 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 IPs 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 44%, 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 EURs, up 85%. In Artesia, however, we did see a reduction in our oil and condensate EURs due to a retrograde condensates 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're highlighting part of the reason why we believe that we're achieving better IP and EUR results. We're using our 3D seismic to extract attributes that indicate higher porosity, TOC, and 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 in well performance, including lateral length, stage and clusters phasing, profit, quantity and type, we can definitely see an improvement in the wells where we were 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 the TD, including the time spent running and cementing in production liner. We are also showing you our target costs, as indicated by the yellow bar, which we consider to be our current technical limits and what we strive for in each well.

Similarly on slide 10, we are showing you the same information for each area in terms of drilling days. Overall, we reduced our drilling costs 17% from 2012 to 2013. Staying with costs 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 and 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 cost about 11.5% from 2012 to 2013, when 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 proppant to 19 stages and 7.6 million pounds of proppant currently. Additionally, as included in this slide, we are now logging the laterals to help design our cluster configurations in such a way that we can optimize our stimulated rock volumes.

I'd like to now talk a little about our Fasken property and the great work that our team is doing down there. On slide 12, you can see that 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 IP'd at 23.1 million cubic feet a day at flow -- with flowing casing pressure of 3,784 psi on a 34/64-inch choke. This well is a 7,000 foot lateral with 21 stages and 8.7 million pounds of proppant.

Slide 14 shows our next to the last well, the Fasken AB 9H, with IP'd 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 is a 6,400-foot lateral with 20 stages and 8.5 million pounds of proppant. 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. If you will see on slide 15, after 1.5 years from initial start-up, most wells in Artesia are put on compression. Due to the additional pressure drop downhole associated with compression installation, condensate has begun to fall out, 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 five-year drilling plan as it provides favorable economic returns due to higher liquid yields overall. For all future wells in this area, a 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 no individual well producing over 300 barrels of oil per day. Under these more stable base field conditions, it is much easier to arrest decline with numerous recompletion and optimization opportunities in the field, thus, 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 the maximum flooding surface and seismic inversion techniques, we have re-evaluated 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 from all four flanks of the salt 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 drilling as shallow as 1,300 feet in cap rock. Despite the shallow depth, several of these wells came between [200] and 1 million barrels of oil equivalent. Two cap rock field studies completed after the second phase development of the late 1970s concluded 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 remaining recoverable reserves are likely. We will bring our review to conclusion in 2014, in anticipation with additional drilling in 2015 and beyond. Thanks for your time this morning. I'll now turn the call back over to Bruce.

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 a third quarter 2013, at the time, I had said decrease. 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 areas. I know there's a lot of detail on this slide, and rather than get into all that detail, particularly 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 the reserves, with particular note 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 were also able to add 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 this slide deck, and we're 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.

Now before we open up the line of questions, I want to summarize our call today. Our initial priority is to conclude two transactions. One, asset sale and, one, joint ventures. Our capital program was designed to expand upon the conclusion of one, or both of these transactions. We 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 measuring 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 would like to begin the question-and-answer portion of our presentation.

(Operator Instructions)

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

Say, can you give me a sense, obviously you continue to have some great results on the McMullen and these (inaudible) that you have detailed. Just your thoughts, Bob, either for you or Bruce, I was wondering now on sort of lateral link, 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?

I think we're 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 long a lateral as possible there. A little bit hard up in that area to get out to 7,000 feet, so you'll see a lot of those wells around 5,500 feet, 6,000 feet, maybe 6,500 feet.

In terms of the stage spacing, we have definitely moved down on our stage spacing. As I noted, we've increased our proppant quite significantly. So, our stage spacing now is more in that 250-foot range with eight clusters per stage.

I think -- but the other thing to note that we're doing and I didn't really talk much about that, is that in the lateral length, we are logging to try to get a 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're actually engineering it based upon the log in fairly real time so that we ensure that we get a good fracture stimulation rate.

Okay, and then one other question, Bob. Just on -- looking at the, again, it's South Texas assets, trying to get a sense of just activity for main [reader] two things here, just on where these assets are located.

What percent is -- where you thinking the most activity will be for the remainder of the year? Then around the where the write-down was around the Artesian Wells? Trying to get an idea of percentage that is of that total South Texas?

In terms of activity, we're 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 SMR/PCQ Northern AWP area where we're 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.

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

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

Okay. Thank you all.

Thanks, Neal.

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

Good morning.

Good morning.

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

Yes, I think if you look at the Appendix and even in one of my EUR slides, I think, let me get out here. You look at that Eagle Ford oil in Artesia, we have that EUR at about 615 to 730 MMBoe. And in that condensate area, we show you the line of the oil window versus the condensate window, it's about 636 to 730 MMBoe.

Okay, thanks. It's perfect. I apologize. I'm having a little trouble with my computer. On that southwestern acreage, how much of it is HBP'd and if there is a portion that isn't, do you think you guys are going to let that go?

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

Okay. Great. And at the risk of asking another that's in the Appendix, the 50 to 60 Fasken wells, is that net or gross?

That's going to be gross.

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

Okay, perfect. Thanks so much.

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

Good morning.

Good morning, Noel.

I actually also am having a little trouble downloading the slides, so, the same thing. I'm sorry if this is included in them, but could you talk a little bit about the Fasken economics that you're 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 in your past Analyst Days, and so forth.

Before we answer that, just for everyone's benefit, if you're have trouble with the slides, you can go to Swift Energy website and download them directly from our website, if your trouble is with the webcast slides.

Okay. Before Bob -- Bob's going to get into the detail of the Fasken, but I want 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've had numerous experts working with us that are basically well-known in the industry, and I think there's pretty good conformance that this is excellent quality rock.

When you look at the wells that have been drilled, we started out with 4,000-foot laterals and lesser sand qualities, lesser stages. I got a lot of data early on and began to develop that. Gas prices went down, as you know, and then subsequently, the industry's drilling longer laterals with more stages, more sand, better targeting, and we've gone out and done this in Fasken.

So it's really reserves per lateral length, number of stages, or stimulated rock. Presently, we are seeing these exceptional results. They're actually better than we had modeled, but we've gone up to almost 7,000 foot per lateral and significantly increased the sand and number of stages.

So you've got to keep that in mind and we've 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're driving that down. So those kind of development costs are exceptional. Bob?

Yes, I'll just pick up on that a little bit. You can see one of the 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 a number of reasons.

First, our drilling guys have done a phenomenal job. I think our completion guys too, driving our cost down. The last well that we drilled and pre-completed with production liner in place was about $2.65 million. So the capital cost is way, way down; they've 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 B10 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 that first three months.

At those types of economics, combined with what our production guys have done on the LOE side, we've really driven our LOE costs per Mcf way, way down in that area. It's very efficient to produce this gas.

So our operating cost, from a commercial structure standpoint, delivers outstanding returns, and I will tell you that 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.

Okay. Assuming that maybe we're 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 there say?

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

Morning. And Noel, look at our website. You can see what we've locked in the way of collars and swaps for our natural gas. We've locked in a meaningful percentage for 2014 in the high $4 range, even locked in some swaps at $6 going out. So take a look at that, because again, the fact that we're doing this drilling as Bob articulated, these things pay out in the first year. So, if you can lock in your economics, then that is even more meaningful.

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

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

Yes, we've had this property looked at by a number of outside engineering firms, so we feel pretty confident. Basically, we just came through a reserve audit.

The property stood up very, very well to our reserve auditors and most of them are giving us upside and kind of do it in the terms of a 1P, 2P, 3P approach. So there is remaining upside but I think we capture kind of the 1P to 3P range in that slide, on slide 22,which is a, kind of a 10 to 15 Bcf per well.

Yes, I think in the initial planning activity, we're more at 10 Bcf, and trying to (multiple speakers) --

And as you're well aware, whenever you actually book, you book on a backwards price deck. That's an important factor because that's just the rules. You use 12-month rolling gas prices backwards to -- and clearly for the development program, we also have upside in the pricing. And the economics that we're showing you here are on the $4.50, not on the backward prospect.

Got it. Thanks. That's it for me.

Thank you.

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

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

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 1P 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're -- the upper Eagle Ford will really very early in understanding there. 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 the Swift Energy Company.

There are some very strategic players now that are looking for gas, principally for LNG markets, as you're 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 the single transaction.

Okay. Thanks. That makes sense. Talking about the CapEx budget, I wonder if you could talk about, if you get an asset sale done, how much flexibility there is in that? If you make up a number, say if you sell Central Louisiana for $125 million, are we going to 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.

The capital budget does have flexibility in it. We've already got identified projects that we can take it up, if we feel we have the capital. That's not to say that we would necessarily sell or 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 or joint venture, both, we would not ramp up capital debt 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've the access to the equipment that we would need. So we're set to ramp it up once we have some confidence that we're going to get those -- one of those transactions closed.

Okay. Great and just one more for me, if I could. Do you guys have a well count that you're expecting to get online in the Eagle Ford next year? And if you could break that down by McMullen and -- versus Fasken, that would be great.

Well, they're looking for it right now, but I don't think -- we did not put that on our slides. Bob, do you want to take a --

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

Yes, we'll give some more clarity on that later.

Yes, just -- I'll give you a 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 one-third going to Fasken. And that's kind of in general ballpark, around 30 wells is what we would like to achieve.

Yes, and that's talking drilling capital. I do want to at least put a little bit of a focus back on Lake Washington. We are doing some very important recompletion activity in Lake Washington, and we are, again, going back to the flexible thing. Bob said he'd drill Fasken wells all day long.

I'll do recompletions in Lake Washington all day long. We're setting ourselves up to be able to do more rather than less. We've got significant amount of capital within Lake Washington. I'm going to say $15 million to $20 million going to recompletions out there.

Great. Thanks, guys.

Thank you.

Thanks, Brad.

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

Thanks. Good morning.

Good morning.

A decent amount of mine has been covered. I wanted to understand a little better the steps you're taking to try and resolve the retrograde issues in LaSalle. 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, it currently take as many on economic. Can that -- these new compression timing techniques and whatnot help the situation going forward and kind of when might you have a read on that?

Okay, this is Terry. I'm going to take a shot at that and then let Bob finish up. Because he and the operating team were -- have been 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. It's -- there's varying a lot across the area. So we're kind of in that fairway where mother nature has created what I would call a distillation call.

We've drilled enough wells where we know we're the right place to be in the distillation column, and we know where there's the wrong place. What does the wrong place mean? It means that low gas prices at low NGL prices; just doesn't make sense to us. And certainly, the shorter length lateral that we started the program didn't make sense to us.

So I think with an uplift in pricing, 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 it [took out] a fair amount of early liquids.

These wells start out at well over 100 barrels per million of condensate production, and when 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 were looking for. We didn't get the amount of liquids we were looking for. So I'm less optimistic on the west side, as you kind of almost leave the county basically, leave LaSalle County. And I'm 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 a good opportunity in terms of how we produce these wells. We're finding that just the difference between a 600 psi flowing tubing pressure and a 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're trying to optimize that and flash the gas on the surface instead of down in the lateral. Bob, you want to add to that?

Yes, just a couple of additions to that. First of all, just to make sure we are clear, the phase north of that oil condensate line, that oil is very economic. We have some of that falling out behavioral, 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. It's just not as robust economics as we would like to see. And with the inventory that we currently have, we're going to divert our capital where we're getting better economic returns. But even in the condensate area, it's not uneconomic from a PV-10 standpoint without any uplift from the managed chokes and the -- trying to delay the compression.

So, we're still getting about 60,000 barrels of oil recovery and it's flat at about 150 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've got a lot of room to go up from here.

I'll just give one final comment to that. We have asset teams that work these properties and are deeply involved in both the drilling as well as the appraisal and operations of the property. The asset teams looked at this and they made their determinations. We just felt it is better to have some opportunity to come back to this and try to get better capital efficiency. So we've taken the steps to not put it in this year's drilling activity and to, as you see, have the revisions that we have.

Okay. That's helpful color. I appreciate it. We've seen or heard about a lot of the variations throughout the Eagle Ford for the last few weeks. I'm just curious. As you look at the activity you've got in McMullen County, you've got some acreage that crosses over that condensate window into the gas window and that transition there, it seems it should maybe where some of those variabilties is emerging most materially. Are you seeing any of these sorts of observations in McMullen? Any commentary on that?

To answer your question, no. We're not seeing the same type of behavior at all over in McMullen. In fact, the last condensate well we drilled was really a fantastic well. We just don't see any retrograde behavior at all in McMullen.

There is variation, though, towards the south, particularly in terms of hydrocarbon makeup, whereas in the north, the -- it's very oily and all the way to the south, it's very dry gas and you've got the condensate window in between. There are some areas that are not as quiet as others, meaning they've got some faulting that you have to be more conscious of when you're designing your lateral lengths and stuff.

And saying that our Southern McMullen is, where we do have a lot of probable and potential gas, we did release a lease down there because of mixed relative economics compared to all of the other things we have. And so, that's an area that we're -- I think with technology and better gas prices, you could have some material opportunities in the future. And so not, you have to remember, a lot of McMullen, particularly in the south is gas, not oil.

And just last point on that, Michael. We have excellent 3D coverage over AWP. That's the area where I was showing you how the inversion work, where we've got all of our mapping done, really, in a precision 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 think we have a very good image of what we're doing down there.

Okay. That's helpful. I guess last one on my end, just in terms of the potential JV at Fasken, is there any bias towards upfront cash versus a carry, or is that all still up in the air for discussions?

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 that to the extent we do a joint venture, that we get proper value for that, which, of course, would have a cash component that we would hope would be meaningful. Because another strategic objective is to improve the balance sheet and be more flexible with better liquidity.

Okay, that's helpful. Thank you, guys.

Thanks, Michael.

Your next question comes from the line of Brian Foote with Clarksons.

Good morning. You've gone through an awful 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 two to three rigs working under the current situation, but shifting to -- in the back half of the year to more liquids-prone areas. How does that work? And what does the gating factor between running two rigs versus three at any given point? And would the sale, and I know you answered this partially before, but would the sale earlier in the year of the Central Louisiana assets maybe imply the bias towards three or more rigs?

Yes. I think -- I'll just take a quick stab at that. The disposition early in the year would bias us more towards a three, a full three-rig drilling program throughout the full year. That's kind of what we would like to achieve. But as Terry and Bruce noted, we've got some lower capital guidance out there. But if we don't get those transactions away, and depending on the timing of all of that, maybe two rigs.

Well, I will add to that. Basically, we've designed a budget that has flexibility. We've done that so that we have our first priority to be fiscally responsible and provide some fiscal discipline there and to improve our liquidity and improve volatility.

That's our first priority. Clearly, by having multiple things going on in terms of achieving that, both a joint venture strategy as well as the Central Louisiana assets, we're confident given our current situation and currently anticipate having these transactions done such that we can accomplish our goals this year.

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

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

And I want to emphasize we're clearly aware that gas has been a little stepchild through, certainly, through the past couple of years. We're encouraged by the better gas prices we see today.

We're not just moving to gas for gas sake. We are definitely having a gas component here because we find ourselves with 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.

They sound like great results. Thanks again.

Thank you.

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

Hi, guys. Just had -- I'm 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 were the year-end 2013 proved reserves, developed and a commodity mix? And how much of your acreage is in Artesia Wells? And how much are relative to what's your total acreage is in the Eagle Ford?

And also if you can maybe talk about what your year-end PV-10 was in Artesia Wells? Thank you.

We don't have that information in front of us here, Ravi, and actually, don't disclose that to that level.

There is some level in the (multiple speakers) --

I mean, in the 10-K, which we should -- gets out tomorrow. You'll be able to see a lot of information you're asking for.

Okay, and then what about production, maybe Q4 production for Artesia Wells, either percentage of your total Eagle Ford?

We'll have to look that up and get back to you on that, but --

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're just kind of negotiating the final, sort of the details? Maybe any color on that would be helpful.

Yes, appreciate that request for detail. But obviously, we're in the middle of negotiations and just not in a position to comment further.

Okay. All right, great. Thank you, guys.

Okay. Thank you.

There are no further questions at this time.

Okay, well, again, we thank you for joining us on our conference call and we look forward to our future presentations with you. Thank you.

Thank you. This does conclude today's conference call. You may now disconnect your lines.