SilverBow Resources Inc (SBOW) 2012 Q4 法說會逐字稿

Good afternoon, and welcome to the Swift Energy Company fourth quarter and full-year 2012 earnings call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question and answer session.

(Operator Instructions)

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

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy's fourth quarter 2012 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. Terry Swift will then summarize before we open up the line for questions. Also present on the call is Steve Tomberlin, Senior Vice President of Resource Development and Engineering, and Jim Mitchell, Senior Vice President, Commercial Transactions and Land.

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

We expect our presentation to take approximately 25 to 30 minutes, and have allowed additional time for questions.

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

Swift Energy continued to focus on its crude oil and liquids-rich project portfolio during 2012. The success of this focus is evident in our strong reserves growth in these categories and shifting production mix. Our crude oil and natural gas liquids production for the fourth quarter continued to climb, reaching 55% of total corporate production, up 22% from the beginning of the year. Crude oil and liquids production also generated 83% of our fourth quarter revenues.

Further reflecting our focus on crude oil and liquids-rich activity is our year-end 2012 reserves report. Total reserves increased 20% from year-end 2011 and are now comprised of 48% of oil and natural gas liquids. This is a marked shift upwards from a 36% liquids cut at year-end 2011. We still believe that the commodity price environment favors our strategic inclination to drill higher-value, lower-volume projects, and aside from conducting a two-well 50-acre down spacing test of our Fasken Ranch acreage this year, we don't anticipate drilling any dry natural gas wells in 2013.

This year's capital budget has been materially reduced to $440 million from $480 million, significantly down from approximately $725 million last year. Given low natural gas prices and our desire to have a more cash-neutral spending plan, we have reduced our 2013 capital program even further from our initial expectations. We have also further reduced our production growth estimates, and will continue to focus on our value over our volumes.

Recent water encroachment of several wells at Lake Washington have also led us to be more conservative about our near-term growth forecast plans. With that said, Lake Washington is indeed a gift that keeps on giving. In this regard, we have also begun planning a significant Lake Washington deep Subsalt test which will we'll comment on later in today's call.

This year we intend to focus drilling activity on liquids-rich projects by directing the bulk of our drilling dollars through our oil and condensate-rich areas in South Texas. With over 100 horizontal wells drilled completed in South Texas, we believe we have delineated our highest-value acreage to a point where we can make efficiency gains in our production maintenance and optimization operations that will rival efficiency gains realized through drilling and completions the past several years.

Last year's capital spending program delivered a material proven liquids reserve growth. We grew our South Texas liquid reserves by 121% last year with an overall Company wide finding cost of $16.42 per barrel oil equivalent. Over 94% of our 2013 net reserve ads were liquid-based reserves. More of our production is coming from the prior year's activity in South Texas than from the new wells, and some of our highest return opportunities lie in being able to maximize the performance from our facilities, secondary lift, and compression projects. Having longer-term production data to fully understand the characteristics of our diverse acreage make it possible to improve performance in these areas markedly.

Fifty and 60-acre down spacing test concepts in both McMullen and LaSalle counties continue to perform well and affirm the potential for increased amounts of oil-drilling locations in these areas. As a result of our success in South Texas, we have created a crude oil and liquids-rich opportunity set that has an enhanced value, if developed at a faster pace than our current levels of activity and our internally cash-generated cash flow will support. To address this, we are currently exploring opportunities to create a joint venture partnership covering portions of our highest-value acreage in the Eagle Ford shale. Once we have a partner to participate on our significantly de-risked liquid-rich acreage, we expect to be able to accelerate activity levels and bring meaningful net present value forward.

In addition our South Texas opportunities, we are committed to deepening our liquids drilling focus and will evaluate three new strategic growth areas, all prospective for high margin, crude-oil projects over the next 12 to 24 months. In order of relative timing, we have already spud our first horizontal Wilcox oil test in the South Bearhead Creek Field in Beauregard Parish, Louisiana.

Due to the historical activity in this field and recent success of nearby operators, we aren't considering this to be exploration, but rather the next logical step in applying leading technologies to our existing oil-rich opportunity set. A successful horizontal test of this acreage sets up immediate followup drilling. We believe that this opportunity exposes us to 20 million to 30 million barrels of gross oil equivalent of un-booked up-side oil potential.

In Southwest Colorado, we have approximately 53,000 net acres prospective for horizontal oil drilling in the Niobrara formation. Projects in this part of the country require longer lead times, but we anticipate spudding a test well by the end of 2013. Successful testing of this acreage would be extremely encouraging, but appraisal of our acreage will likely take some time as this is an area that is just now being tested with horizontal drilling and multi-stage completion technology. We believe that this opportunity exposes us to a 100 million to 200 million barrels of gross oil equivalent of un-booked up-side potential.

Finally, we have already taken the initial steps necessary to drill a Subsalt deep exploration oil test at Lake Washington. While early in the process, this project has the greatest potential positive impact, and will be among our most exciting exploration tests. Personally, I want to see this deep Subsalt test conducted with the high-quality recognized industry partner. We plan to do everything necessary to mitigate the risk of this project on a pre-drill basis, but within reason. We will drill this Subsalt test. Our timelines today contemplate having the first exploration well drilled within 24 months from today. This timeline could be accelerated, but it is dependent on the future seismic evaluation and the final determination of how deep we will take the test, all of which will be decided in collaboration with any future partners.

The data we've collected to indicate that a discovery beneath Lake Washington is likely, shows us that it is likely to be crude oil. And it's my further belief that a successful exploratory test may well discover a new Lake Washington beneath our existing asset. We believe that this opportunity exposes us to 200 million to 350 million barrels of gross oil equivalent of un-booked up-side potential.

All the projects I just highlighted are all underway and represent opportunities for the organization to demonstrate the value we see everyday in our portfolio to the investment community. We will discuss all of these opportunities in greater detail at our annual investor day on March 14th. We also expect to increase our reserves this year by 7% to 12%. We expect the percentage of our total reserves that are crude oil and liquids to be approximately 50% and our production mix to be between 50% and 55% crude oil and natural gas liquids.

Before I ask Alton, Bob, and Bruce to discuss further details of our fourth quarter and 2012 activity, I'll recap several strategic items for consideration as they relate to 2013. As I indicated earlier, we will reduce our spending level significantly in 2013 between 30% and 40% from 2012 levels. Approximately 10% to 15% of our anticipated CapEx of $440 million to $480 million will be dedicated to facilities, gathering systems and other infrastructure.

We have also committed 5% to 10% of this year's budget to our strategic growth initiatives in Louisiana and Colorado, which will add minimal production this year, but open up multi-year opportunity sets in 2014 and beyond. Given our pullback in capital spending, lower activity levels dedicated to high-value, but lower volume projects, and longer-term investments, we are projecting modest production growth and expect no deterioration to cash flows.

Swift Energy is at an exciting point in its history as we are presented with more opportunities than we can pursue in a timely fashion. Near-term, our focus is on growing high-margin production in South Texas and over time we'll be selective in our activity, pursuing only the highest-return projects for those that unlock strategic value. Our commitment to pursuing our strategic growth opportunities will involve exploring strategic high-quality partnerships early in the successful developments or divesting projects we don't believe will fit our portfolio over the long term. While our production and cash flows may not grow significantly this year, what is happening beneath the surface can set up 2014 to be an extremely high-growth year. It can be a game changer for the Swift Energy Company.

And now I'll ask Alton to present our fourth quarter 2012 financial results.

Thank you, Terry, and good morning, everyone.

As Terry discussed in the fourth quarter, we experienced strong production growth in oil and natural gas liquids versus both 4Q '11 and 3Q '12. The result was solid improvement in revenue and earnings from the prior quarter. Though down from fourth quarter 2011, as prices softened during 2012, particularly in the gas liquids market. Our overall results from the fourth quarter are -- oil and gas sales of $158 million, income from continuing operations of $11.2 million, or $0.26 per diluted share, cash flow before working capital changes for the quarter of $2.13 per diluted share, and 3.1 million barrels of oil equivalent of production.

Crude oil prices were 8% lower than a year earlier. Natural gas prices were down 10%, and NGLs were off 41%. Improvement in the oil share of our product mix limited our overall realized price decrease to 12% per BOE in 4Q '12 versus 4Q '11, as approximately 72% of our revenues came from crude oil sales during the quarter compared to 68% in the prior year.

Our controllable cost and metrics were mixed, as well. Production costs came in at $9.70 per BOE, above guidance primarily due to higher leased labor, maintenance, and chemical treating costs. G&A came in at $3.46 below our 4Q guidance. DD&A was above guidance slightly at $21.08 per BOE, as our reserve base has shifted to higher-value oil and gas reserves.

Interest expense came in at $5.39 per barrel, within guidance, and production and ad valorem taxes were below guidance at 8.2% of revenue. As previously mentioned, the net result of this was income for the quarter of $11.2 million or $0.26 per diluted share. Our effective income tax rate for the quarter was 44%.

Cash flow before working capital changes before Q12 came in at $91 million or $2.13 per diluted share. While EBITDA was $104 million for the quarter. Quarterly CapEx on an accrual basis was $147 million, as our capital activities, mainly as to facilities cost, reduced at a slower pace than projected. We recently purchased crude oil floors that will cover 140,000 barrels the first quarter of 2013 crude oil production, and an average NYMEX [drive] price of $95.85 per barrel. And as always, complete details of Swift Energy's price risk management activities can be found on the Company's website.

Let me wrap up the financial discussion by reminding you of our fourth quarter financing activities. In early October, we issued an additional $150 million of senior notes as an add-on to our 2022 debentures and used the proceeds to pay down the balance on our credit facilities. These notes were priced at a yield of just under 7%. We also extended our credit facility through November 2017, improved our pricing grid and increased our borrowing base and commitment amount to $450 million.

The combination of these activities ensures the Company is maintaining the liquidity necessary to continue to execute our strategic plans. As always, we have included additional financial and operational information in our press release, including the initial guidance for first quarter and full-year 2013.

And with that I'll turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton, and good morning, everyone. Thanks for listening in.

This morning I'm going to discuss fourth quarter 2012 activity, including our production volumes, our recent drilling results, activity in our core operating areas, and our plans for the first quarter and full-year of 2013.

Beginning first with production, though. Swift Energies production during the fourth quarter of 2012 totaled 3.11 million barrels of oil equivalent within our expected range of outcomes. Fourth quarter production was 15% greater than fourth quarter 2011 production of 2.7 million barrels of oil equivalent and increased 8% from the 2.87 million barrels of oil equivalent produced in the third quarter of 2012.

For our fourth quarter drilling results, Swift Energy drilled 15 operated wells during the quarter. In South Texas, 12 operated horizontal development wells were drilled in the Eagle Ford shale formation in South Texas. Seven of those wells were drilled in McMullen County, and five were drilled in LaSalle County. In Swift Energy's southeast Louisiana core area, two wells were drilled in the Lake Washington field, and one well was drilled in the Bay de Chene field. In the Company's central Louisiana and East Texas core area, one non-operated well targeting the Austin chalk was drilled in the Burr Ferry field.

We currently have three operated drilling rigs in our South Texas core area drilling Eagle Ford shale wells and one operated rig active in Lake Washington. We are also drilling a horizontal well in the South Bearhead Creek field in Beauregard Parish, Louisiana. In southeast Louisiana core area, which includes the Lake Washington and the Bay de Chene fields, production during the fourth quarter averaged approximately 6,510 net barrels of oil equivalent per day, up 29% when compared to the third quarter 2012 average net production from the same area. Lake Washington averaged approximately 6,214 net barrels of oil equivalent per day, an increase of 31% when compared to third quarter of 2012 average daily volumes. Third and first quarter production volumes in this area were impacted by Hurricane Isaac.

Four wells in Lake Washington have recently encountered water due to natural declines. This has resulted in steeper than expected base production declines. We've opted to curve spending in this area relative to 2012 levels because of our desire to better match our cash flow with capital spending, and now plan on keeping the drilling rig active for only a portion of the entire year. This activity is expected to maintain a shallow production decline profile in Lake Washington as we prepare to drill a deep exploration test in the field.

Bay de Chene's production of 295 net barrels of oil equivalent per day was unchanged when compared to the third quarter of 2012 production levels. 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 2012 production averaged 24,362 net barrels of oil equivalent per day, a 3% increase in production when compared to the third quarter of 2012 production in the same area, and a 28% increase over the fourth quarter of 2011. This sequential increase is primarily from newly completed wells and production optimization projects that came online during the quarter and offset slightly slowing activity in the region.

Earlier this morning we published specific information on wells brought on line during the quarter in our quarterly press release. Well performance continues to build a solid base of production and continued employment of multi-well drilling pads, zipper and serial frac techniques and well optimizations, are yielding improving drilling and completion efficiency.

The Central Louisiana/East Texas core area, which includes our Brookeland, Masters Creek, Burr Ferry and South Bearhead Creek fields, contributed 2,842 net barrels of oil equivalent per day of production in the fourth quarter of 2012, an increase of 11% over the third quarter 2012 production in the same area. Higher production levels in this area are due to non-operated wells in the Burr Ferry during the first quarter.

And I'm now going to turn the call over to Bob Banks to review operational highlights for the third quarter.

Thanks, Bruce.

At the Lake Washington field during the quarter, we completed five wells and performed 20 production optimization projects. Which include sliding sleeve shift changes, gas lift enhancements and acid stimulations. We drilled two wells at Lake Washington and one well at Bay de Chene during the fourth quarter. At Lake Washington, the CM-424 was drilled to a measured depth of 8,095 feet and encountered 14 feet of true vertical pay. The CM-428 was drilled to a measured depth of 3,445 feet and encountered 47 feet true vertical pay. Over in Bay de Chene, the UV-157 was drilled to a measured depth of 11,233 feet and encountered 81 feet of true vertical pay. We have a completion rig active in the area now, and all three of these wells will be completed during the first quarter.

Overall we're going to spend less in this area during 2013 than we did in 2012. We do, however, see tremendous upside in this area, particularly beneath the salt dome at Lake Washington. As Terry mentioned, we intend to drill a Subsalt test at Lake Washington before the end of 2014. It is possible that we'll achieve milestones during 2013 that will allow us to accelerate the project meaningfully. We will deliver a more detailed analysis of both our technical and operational approach to this prospect next month at our investor day.

As indicated in our press release and in Terry and Bruce's remarks we have recently observed 4 key wells at Lake Washington experience significant water cuts impacting our base production forecasts for the field in 2013. This type of occurrence at Lake Washington, a field that has produced since the 1930s, isn't unusual, but it's difficult to plan for. It is, however, unusual to have this happen in multiple wells at the same time. Fewer wells are now accounting for larger percentages of field-wide production and have larger impacts on declines as they mature.

In our Central Louisiana/East Texas area, the non-operated gas RS 15-1 well was drilled to a lateral length of 7,524 feet in the Austin Chalk and the South Burr Ferry field during the quarter. This well was brought online during the first quarter and produced at initial rates of 923 barrels of oil per day and 10 million cubic feet of gas per day with flowing tubing pressure of 6,000 PSI on a 24-64-inch choke. We will also get a nice NGL yield from this well of about 175 barrels per million cubic feet of gas.

Results to-date from this joint venture have been strong with results improving over the time. One additional well, the gas RS 291-10 has been drilled this year to a lateral length of 6,112 feet and should be completed and testing this quarter. After a brief pause in activity we expect that our partner will resume drilling operations and drill up to a total of three wells during 2013 in the area.

In our South Bearhead Creek field in Beauregard Parish, we recently spud our first horizontal well to test the oily Wilcox formation. As Terry mentioned, we view activity as lower risk exploitation and a natural fit for the proven horizontal drilling and completion techniques we've applied repeatedly in South Texas. Should we achieve favorable results with our first well, we will move forward with additional activity this year. Due to the high margin oily nature of production from the Wilcox in this field we believe we can develop our inventory here in a fairly self-funding manner.

Moving to our South Texas area, 17 Eagle Ford horizontal wells were completed during the fourth quarter. This morning's press release we included a table highlighting data from these completions. Initial results from 60 acre down spacing tests in LaSalle County and 50 acre down spacing tests in McMullen County have been very encouraging. These results seem to affirm the concept of tighter wells spacing than our previous assumption of 80 acres in these crude oil and liquids rich project areas.

Aside from a two-well 50-acre down spacing test in the our Fasken Ranch are in Webb County this year, all of our activity will be focused in these oil and liquids rich areas. Should performance continue to confirm 60 acre down spacing, we should be able to increase our potential Eagle Ford drilling locations by 30% or more.

As other operators have publicly commented, we also anticipate conducting further down spacing tests to ultimately optimize the development of each of our Eagle Ford acreage positions. We will have lower activity levels in South Texas this year, which will flatten the trajectory of our production growth, but we believe well selection, drilling and completion performance, and lower overall service costs will yield higher-margin production than in prior years.

As Terry indicated, average costs are down from a year ago and completion costs are heading lower, as well. Record year-end reserve levels, as well as a significant increase in oil and NGL reserves have delivered lower F&D costs, and we expect that trend to continue. We also see a great opportunity to enhance returns and improve the quality of your results versus our forecast through optimization of our base production profile in South Texas. With a greater portion of our production coming from prior years' new wells, we can benefit greatly by reducing base production declines through compression and artificial lift.

Although we are reducing activity this year, our preference would be to further accelerate development of our liquids rich acreage in order to enhance our overall project economics. In that regard we are in the process of working with potential partners on a prospective joint venture on a portion of our high-quality Eagle Ford acreage. We believe this would allow us to increase activity levels and that any transaction we enter into would have an immediate accretive effect for the Company.

Finally we've made a budgetary commitment to our strategic growth initiatives of 5% to 10% this year. This capital will be directed to drilling wells in Louisiana and Colorado, as well as targeted acreage acquisition in our key growth plays. I've already highlighted our Wilcox and Subsalt opportunities and have a few comments on our Niobrara opportunity in Colorado.

We've put together a high-quality, cost-effective and meaningful acreage position prospective for shallow oily Niobrara production primarily in La Plata County, Colorado. As we prepare to drill our first well there later this year, we've conducted a detailed analysis of the basin, its production history and the current activity in the area. This, we believe, will enable us to move forward quickly as we achieve successful results.

Despite an uncertain commodity back price drop, we are committed to delivering the value we see in our portfolio through prudent exploitation and development projects, strategic growth initiatives, joint venture partnerships where appropriate, and through the divestiture of assets that no longer fit strategically. Our activity this year, particularly in South Texas and in our strategic growth areas should again allow for double-digit production and reserves growth in 2014.

With that thanks for your attention this morning, and I'll turn it back to Terry to recap.

Thanks, Bob.

Before we open the line for questions, I'll summarize Swift Energy's fourth quarter results and review some of the highlights from today's call. Fourth quarter production growth of approximately 15% over fourth quarter 2011 production. Seventeen new wells brought online during the first quarter in South Texas. A 20% increase in 2012 reserves with approximately 48% made up of crude oil and natural gas liquids. Year-end daily production is in excess of 50% crude oil and natural gas liquids. An additional 7% to 12% reserve growth is expected and projected in 2013. 2013 capital spending levels, 30% to 40% lower than 2012. Continued down spacing tests, which may increase our liquids-rich South Texas drilling inventory 30% or more.

And as we've highlighted today we have plans for initial tests and plans for projects to move forward in three large impact strategic growth areas, which include the Wilcox and Louisiana, which has 20 million to 30 million gross barrels of potential for the Company; the Niobrara in Colorado, which has a 100 million to 200 million gross barrels of oil equivalent potential, and the Subsalt in Lake Washington which has 200 million to 350 million gross barrels of oil equivalent of potential.

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 from SunTrust.

Good morning, gentleman.

Hey, Neal.

First just a sort of strategy question. I understand -- it makes a lot of sense as far as the cut in CapEx, but I guess the other side of that is, given the outstanding returns you have on a lot of the Eagle Ford -- and you do have a fair amount of liquidity right now. What -- Bruce, maybe either for you or Terry -- from a of strategy question, why cut so much, given the type of IRRs you're getting from that Eagle Ford play?

Well if you -- a couple reasons, Dale. Thanks for the question.

If you look at our capital spending actually through the year, that cut really comes in the second half, not so much in the first and second quarter. One of the things that Terry mentioned, though, is we really are looking to bring in a partner in a portion of our Eagle Ford development in the form of a joint venture that would allow us to monetize some of those assets and bring cash in, and also provide possibly a carry for future drilling. That would actually allow us to accelerate development in the Eagle Ford and also give us capital to pay down debts so that we could then increase capital spending in some of the other areas of the Company. So, we really look at that as a prudent thing to do at the outset of the year. As we get something accomplished, then we can accelerate activity once that's done.

Yes. This is Terry. I want to reinforce what Bruce has said.

You know, our primary drive over the long term is strategic growth in both the reserves and production. We clearly have focused on liquids. But we're keenly aware of the need to manage our cash flow, keep our balance sheet in good shape.

So you will see us this year not only moving on these strategic growth projects, and as Bruce says, with success in the way of partners or joint venture activity, put ourselves in a position to accelerate, bring some of that net present value forward. But you'll also see us be very conservative in terms of how we're going to forecast things going forward. Make sure we protect the balance sheet. We know this has been a difficult time, particularly with gas prices and NGL prices. So we want to move through the year with our main focus on delivering the value but keeping the cash flow in good shape.

Your next question is from the line of Leo Mariani with RBC.

Hey, guys.

Just in terms of Lake Washington, can you give us a sense of how many wells are on production today? I'm assuming those four wells may be off-line, that you talked about, with the water encroachment issues.

And then additionally, can you talk about your production guidance for 2013? And what are you assuming Lake Washington to do in that guidance? Are you assuming continued declines or stabilization in the production?

Well I'll take a first shot at that, and I think Bob is going to follow up more operationally.

In Lake Washington, as Bob mentioned, we do have wells from time to time that get higher water cut. You have to balance that water cut against the facilities that are out there and the amount of water handling that you can do. We did have four wells that basically did have significant amounts of water. I'm not prepared -- they're getting the numbers -- to say that the wells are actually shut in. They may be cycling the wells, still getting some oil out of them, but they're not the big producers that they once were several years ago. But the timing of that water cut was just unfortunate.

We do have other behind pipe opportunities, re-completion program, a rig out there right now. We're doing some completion work. So Lake Washington still has a lot of wells producing, a lot of new production that comes on every year that replaces the declines in various ways, but we did have four wells that I think some were around 1,200, 1,500 barrels a day in the composite we backed out of the production forecast.

Bob?

Yes, Leo. A little detail.

We have about a hundred wells producing out there. The four wells were four of our bigger wells, over in that Newport area where we're getting pretty big production from. But at these newer levels -- and I will say that the production has really stabilized the past couple of months. It's turned a lot flatter. We're feeling a lot better about what started happening right there at the end of the year with those four wells.

At these newer forecast levels, our projections for 2013 really is that we can keep Lake Washington production flat to maybe even some growth at this level with our activity.

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

Good morning.

Hey, Noel.

Good morning.

Just a few things.

Wanted to get a bit of an update on how the Eagle Ford inventory progressed this year, as you did reserve bookings. Just interested in whether you had any improvements as far as wells performing better than their type curves? And maybe what the tightest spacing is that you booked wells on this year? And then, finally, could you give us some sense of what the 2P numbers look like in the Eagle Ford?

The 2P?

Let me take a start at this.

I think the most that we've done any bookings on in the Eagle Ford is at 80-acre spacing. Looking at our EUR performance over time, I can tell you that in most of our liquids-rich areas we see an improvement of these EURs. In our LaSalle County position, we see probably three models versus two models that we had before. But we're getting better condensate yields from those models.

So overall, if you look at the way we've booked our spacing right now, if we can get down to 60 acres or even progress it further, at 60 acres we probably have in all of our Eagle Ford another 30% of drilling locations. We have not taken any of that into account. We have not booked much of our Fasken reserve. But the work we see to date in most of our acreage is we are seeing some improving EURs over time. Some of that is the result of our 3-D seismic and the way we are getting are wells in zone a little bit better and using our attribute analysis to steer those wells. We're pretty positive that we're going in the right direction here.

Because the other thing I would add to that -- we did comment on earlier, though, is that we've done this down-spacing work in terms of actually drilling wells in LaSalle County Artesia wells and McMullen County. But Terry noted and Bob noted that we are going to drill two wells down in the Fasken area. You may note that's going to be dry-gas production, which is not something we necessarily choose to do but we think it we think it's very important to understand the down-spacing potential in Fasken.

So we want to drill a couple of wells and test that; and if we do find that to be able to be down space that would also add to the inventories. So none of that 30% increase -- it's really focused on Artesia wells, McMullen County area.

Okay. And the 2P number?

We don't publish that 2P number, Noel.

Okay. I guess --

Let us get back with really the group at our analyst meeting. We're going to give a lot of color on that. I believe that's the 14th. While we may not give a specific 2P number or something like that, I think you'll be able to deduce what that could be from the Analyst Day.

Great. And just one last thing -- sorry if I missed this before -- it looks like the inventory of wells that you brought online in fourth quarter, you had generally stronger rates of a few more wells above a thousands barrels, I think, on the oil side, even IPs. Has that improved efficiency? Or as you're saying, better targeting, or changes in your frac procedures, or so forth?

No. I think, as I mentioned earlier, we have done a lot of processing of our 3-D seismic data, and we've done some attribute work that's allowed us to land those wells better and steer those wells better into the tightest of what we would call the brittle rock of the lower Eagle Ford. Without some of the techniques we've developed, we couldn't keep those well bores within the most brittle rock. And so now we're keeping those wells using that attribute analysis from the 3-D seismic. We're steering those wells in the most brittle rock, what we think is the sweetest part of the lower Eagle Ford, and we're noticing much better performance coming out of those wells.

Great. Thanks a lot.

Your next question is from the line of Michael Hall with Baird.

Thanks, good morning.

Hello, Michael.

Just wanted to circle back on the joint venture comments and the Eagle Ford. I guess, number one -- is the thought process that would include some production sold with that? And then any additional color around how much of the position you might be considering?

Yes. I think that's a fair question.

We clearly have spent a lot of time and a lot of money last year delineating some of the best areas that we have, the highest value areas. We've moved away from gas, as we've noted, and as we've adjusted or learned more about the models, we've got a much higher confidence level in where the good EURs are. And moved away from poor EUR types of activity.

We've also, Bob noted, really focused on the frac activity. We've optimized the fracture designs, both in terms of some fluid changes that we've made, as well as sand and proppant types. And then, as Bob noted, the steering. So we've got an operation that we do believe can move faster, accelerate some of the area, particularly in LaSalle County.

We are considering maybe as much as 10% of our acreage, but that's a little bit of a moving target, so it's not a big strategic position. But we could put that out to the right partners, and it all depends on your deal structure. But basically, get ourselves in a position where you would be selling little bit of production. That's not really a material piece of it. But you would be accelerating and bringing so much value forward that overall, it absolutely would be accretive, or we're just not going to do it.

Yes. I think you have -- it's Bruce -- to be a little careful about building a rigid structure for the deal at this point in time, because you may find different people want to do something differently. But we want to structure a transaction, though, where our partner and Swift are aligned in their interest. One of the ways you do that is include a component of the existing crude reserves. But as Terry said, it's really largely the future drilling, because the purpose of it is not just to bring some capital into the Company, but to accelerate the activity and move MPV up forward, so --

Yes. Just one other comment there.

We absolutely are committed to being the operator and taking all of the lessons learned and all of the advantages that we have developed forward with any such potential transaction.

Okay. That's helpful.

Maybe thinking about things from another angle -- with the Eagle Ford being so core to the successes at Swift over the last couple of years, why not consider another piece of the portfolio for monetization to then redeploy into and accelerate the Eagle Ford? Just kind of curious on the thought process there.

Well, we are doing the things that you would expect us to do. We're disposing of -- we are divesting of some non-core assets this year, in particular our Brookeland area -- again, not a lot of production, not a lot of reserves, but high operating cost area. But someone else can get in there and do more with it. It's just not core to us anymore. We are doing those kinds of things.

In these other areas, I would not take off the table that, whether it's new oil play that we're working with in the Niobrara, or as we're moving forward in some of these other areas, that we would not monetize or do things there. We clearly recognize the advantage of having activity that brings net present value forward and that is accretive.

So I think your comment is appropriate, that we need to look at different areas. But right now this is an area -- we're very active, we can increase our activity very quickly because of the core operation that we have there. But we're not looking at a big chunk of what we've got in the Eagle Ford.

Yes. I would just add a couple of comments on that.

I think if you -- the Eagle Ford area is probably the area of our asset base that's the best proved up, highly valuable out there in the marketplace as well. So a lot of people would be interested in that. One of the things, if you'll note, in our strategic growth area, we are moving toward fairly aggressively trying to develop the value to a higher level of confidence in these other areas -- both the Niobrara, if you look at the Central Louisiana area, the Wilcox, and if you look at Lake Washington. Move forward with a plan to get that subsalt well drilled. We've talk about that for some time.

We are convinced we've got a very high quality of prospects and want to get it drilled and move forward with it. If you didn't have those plans to move forward and develop other value in those areas you might absolutely might consider disposing of them as well.

Okay. That's helpful. I appreciate the color, guys.

Your next question comes from the line of [Dan Ketkis] with Global Credit.

Hello, guys. Thanks for taking the question. A few questions, actually.

On the timing of this JV -- how far along in this process are you? Is this something we can expect in the next couple of quarters?

Yes. I think we would hope to certainly have something done by the third quarter.

Okay. With regards to your Lake Washington subsalt prospect, can you give us a little more color on how deep you think some of these target zones can be? And then have you either approached partners already, or have you been approached by some of the guys that are doing similar things?

Yes. That's a great question. This is one of my favorite topics. This is Terry. I'll answer that.

Interestingly enough, Lake Washington, back in, I believe, 1989, was one of the first areas that was looked at by some of the name-brand players in developing subsalt targets. And Lake Washington did have a test of the subsalt that began in '89. I think they got a log in 1990. But it was pre-3-D. They did not have the 3-D out there. And it was before the big Mars discovery and the big results that were found in the subsalt.

So we have an actually an Amoco well that was drilled down dip from what we now know to be the present-day structure. That Amoco well gives us great confidence that, one, you can get through the salt here, because they did; two, that there are sands below the salt, because they found them; and three, they cored and gave us a lot of high-quality information on those sands. We actually have some shows in some of those sands. But again, this was pre-3-D.

Shortly after this was drilled, Mars was discovered and most of the players moved offshore from the Lake Washington area. We also have good porosity and perm in the sands that were found. Now that well, I believe, got down to about 22,000 feet.

Our prospect comes up dip from that, but all I can say at this point is that at the analyst meeting we'll give you a lot more detail. We are looking at what I would call recognized players. This is a very important test for Swift Energy and its shareholders. So we're going to have the highest quality of players that will be looking at this with us as we proceed with our plans.

Would you expect that some of the valuable potential pay zones would be shallower than what is being discovered over at, say, Lineham Creek?

There's two comments. I think what you're referencing is a good bit to the west of us.

Right.

And a good bit -- really kind of offshore. It's not really offshore, but it's over in Cameron Parish, I think. That area tends to be more gassy; and yes, the things over there are deeper. But that said, we're very confident that we have an oil prospect because of our location. We'll show some data at our analyst meeting that I hope people get very confident in that. We've done oil typing studies as well as have some shows down dip that were oil.

But finally, I would like to mention that the Amoco well that was drilled off structure and down dip from us, was still in sands at 22,000 feet.

And then the last question I have is, it looks like you guys are fairly optimistic on the prospects of the Company. And I agree, there seems to be a lot of high impact potential that you can bring forward in the next couple of years. The stock price is down again today. It's at a 52-week low. And your market cap at this point is only $550 million.

So given that your EBITDA has grown sequentially and your balance sheet is in better shape than most of your high-yield peers, would you consider buying back stock or something like that to have the market recognize the value in your stock that you think you have?

You know that's a really good question. We get that certainly at times like this.

I have to say I'm very disappointed at where the stock price is right now. I do think we're considerably undervalued even to the extent that you look at our cash flow multiples now and our growth prospects now. So our job is to get that valuation recognized in the marketplace. And even though we are talking about 1, 2 year type of growth activities, we are doing things now; and we are taking every effort now to accelerate some of the things we are talking to you about. Because we're not just going sit around and wait on the market to try to adjust it. We're going to be very proactive trying to make sure the market sees the value.

Now that said, I do think the stock is a buying opportunity, and there have been times in the past where the Company did use some of its liquidity to buy back stock. But just as a general policy and as a general view on our part, when you've got so many capital projects where you can invest money, and you can bring value forward, I think the better approach to getting the stock up is to bring those projects forward and let you see the results, than to try to collect shares. That's my personal view.

Okay. I appreciate it. Good luck.

Thanks, Dan.

Your next question comes from the line of Curtis Trimble with Global Hunter.

Good morning, everyone.

I was hoping you guys could whet those appetites for the upcoming Analyst Day. Give us a little bit of the profile on the Niobrara wells -- expected costs, the EURs, things like that.

Okay. Bob is going to pull that out of his satchel over there, but I'll give you a little flavor for it right now.

These are shallower wells, so they should not be as expensive as plays you're familiar with. And we do have some vertical wells in La Plata County that did produce from the Niobrara after frac. And those wells tended to make 30,000 to 40,000 barrels per completion. We're going to drill much -- higher technology, probably about 3,000 to 4,000 foot laterals initially, somewhere in the 10 to 15 frac stages. We do believe that we could get somewhere around 250,000, 350,000 barrels per well, and I think the drilling cost --

I think for the long term, we have modeled in about $6 million drilling costs to do a complete multi-stage frac. We think the costs are going to be less than that. These are shallower depths. EURs in the 250 to 400 [MBOU] range.

And initially the cost will be a little higher, because we'll drill pilot holes and core samples and the like. But we think it has really good opportunity for a sustained oil play in a good area.

Yes. Just a little more color for those who don't know -- this is really in the northwestern portion -- up dip out of the San Juan basin in what's called the Hogback monocline areas. So you do also have some natural fracturing in that area. You're up out of the gas window. As I mentioned, there's a field in there, I believe it's the Red Mesa field, that has already produced oil from these horizons. So even though it's still prospective and still exploratory in nature, there's a lot of good strong control points that show us that it's oil.

Good deal. You are out there in a pretty pristine country. Any regulatory issues, anything of that nature to be concerned about?

Yes. Coming -- clearly, we'll have to deal with the local community, and we're in the process of doing that. The Colorado -- the state oil and gas conservation committee is the regulatory authority for all gas activities acc ross the state. But you will have to deal with the local community, in particular the La Plata County Board of Commissioners, in terms of various things. Probably the biggest issue there is water, access to water, because Colorado is a fairly dry area; and then the second one is what are you going to do with the water disposal and truck traffic -- things like that.

Those are all issues that have taken place in a number of shale developments across the country. I think we recognize that those have to be dealt with. But they can be. The industry can deal with those things. We just need to work with the community as a good neighbor, not just developing the resources, but bringing a lot of economic uplift to the county as well.

Good deal. I appreciate it.

How about an idea of run room over on the Wilcox play at South Bearhead Creek? How many prospective locations do you think you might have there that define that 20 million to 30 million barrel potential?

Yes. I think we have both an upper and a lower Wilcox, and right now we have multiple zones in both the upper and the lower. We have about three units in the upper, and several units in the lower. So a lot is really going to be dependent on which zones we target first, but we're saying about 23 million to 30 million barrels. I think that includes about 20 in the upper and 15 in the lower. But that has the opportunity to go much higher if we target the individual units within these upper and lowers.

Sure. What about the vertical?

The vertical producers here -- this is in a field where we've already drilled and produced. The vertical producers in this field are yielding anywhere from about a 100 to 400 Mboe EURs. So we feel very good that putting our lateral technology into this field, which is very similar to the Olmos field, only that this is oily; and we're within control, that we'll get multiples on those vertical producers.

What's the vertical interval between the upper and lower? How many feet separate those?

Oh, yes. Maybe 1,500 feet. Yes. 1,000 to 1,500.

Good deal. I appreciate it.

Thanks.

Your next question is from the line of Leo Mariani with RBC.

Hey, guys. Just curious as to whether or not there's a significant active drilling activity in and around La Plata County right now. Are there other operators involved in this area?

There's not a significant drilling activity taking place. But historically, if I remember the numbers correctly, there have been over 50,000 wells drilled in La Plata County. I think of those, maybe 10% have been fracked before. They're used to the activity.

The vast majority of the wells drilled in La Plata, though, have been coal bed methane. What will be new to La Plata is that fact that it will be the first horizontal multi-stage frac shale development. And that's going to bring concern to the citizens, and that's just a matter of us getting up there and educating people as to what will take place. And working with the local county Board of Commissioners, both in terms of road use and water and all the various things that people rightly are concerned about.

Yes. I might add, though, that again, we're on the northwestern up-lifted area of the San Juan basin, what we call the Hogback monocline. But as you go around the San Juan basin, you do find other activity. In particular, Williams drilled a horizontal well down in the basin before gas prices got so low. They were able to successfully apply this technology in a gas well. And then there's been other players, I believe, Encana and some others, that have come up along the rim and started poking around looking for oil using this technology.

In our immediate area, I do believe Red Willow, which is a known player out there, associated with the Ute Indians, I believe. They have also drilled a horizontal multi-stage well out there.

Your next question is from line of Gordon Douthat with Wells Fargo.

Good morning, guys.

I had a quick question on -- Bob, I think you mentioned, in 2014, plans for a return to double-digit production and reserve growth. And I was just wondering -- if I heard that correctly -- does that assume an Eagle Ford JV? Or what might be different between the 2014 program and the 2013 program? I understand it's a little early, but I just wanted to get your thoughts there.

The main thoughts -- certainly an Eagle Ford JV would allow us to accelerate back and get that growth engine going again in the Eagle Ford. But also, we're very upbeat about the Wilcox. We think this initial well that we're drilling now is going to lead to multiple -- more wells to be drilled. Those should be very good high-margin, high-return wells. So it's really based on just those two pieces of activity that I feel pretty good about double digits on production in 2014. On the reserve side, I think we feel good about where we are this year and where we'll be next year as well.

Okay. Thank you.

Your next question comes from the line of [Shay Robinson] with Lee Munder Capital.

Yes. You know, just back to the JV issue -- there seems to be a massive disconnect between what sell-side [nav] models say and your outlook. And if I try to dissect that, the thing that keeps coming back when you talk to various people is the management credibility issue. If I think about the JV, how does the JV bridge that management credibility issue? Because the value of the assets are there, by doing a JV, it's not going to help your credibility. Why not consider strategic alternatives for the whole company?

Your stock is down 13% today on a production outlook that was significantly less than what the Street expected. I know you did -- predicting lower CapEx this year. But still -- you say one thing one quarter, and something else happens the next quarter. Whether it's bad luck, or management execution, I'm not sure. But I guess -- would you just address that point, please?

I'll address it first, and Bruce may have some followup comments.

First of all, we're committed to the growth of Swift Energy Company. We do believe we have significant assets. We spent some time here today talking to that extent; and at our analyst meeting we're going to lay out a whole lot of more information. And to the extent that there's any credibility issues, then certainly people do need to be able to look at the data, they need to be able to look at the assets, and they need to be able to talk to us directly. And the analyst meeting, which is just a couple of days off, is a great opportunity to do that.

We have a strong team of professionals here. We really do not have any belief whatsoever that we can't execute. We can execute. If I talked to last year's activity and some of the bumps that were there, including a hurricane, it will sound like excuses. We do have to look forward; that's what this business is about. We do have to get the share price up and recognized for its value. So your comments about value are absolutely legitimate, and I certainly hope you'll be at the analyst meeting to dig deeper into the assets and ask whatever questions you want of Management.

But I do think a strategic joint venture in the Eagle Ford would validate the value of the Eagle Ford compared to what the market's valuing at. Secondly, I don't think the appropriate time to look at strategic alternatives is when you're at a significant low point in terms of valuation.

I guess I would disagree. If your net asset value is significantly higher than what the public market is willing to pay, the private market would recognize that value.

Well, as we've noted we definitely are looking at ways to accelerate our activity and bring forward the net present value. When you talk about it, whether it's Lake Washington and a deep subsalt player -- that is going to be name-brand player. I don't think there is going to be any doubts about the credibility or the capabilities of the kinds of players we'll be talking with for that project. The same thing is true in the Eagle Ford. So I do believe that we'll bring forward a lot more confidence in what we're doing by the types of joint ventures we're contemplating putting together.

Okay. Thank you.

Thank you.

At this time there are no further questions.

Is that it? Okay. Well, we thank you so much for joining us today.

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