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Swift Energy Company (NYSE:SFY)

Q4 2012 Earnings Call

February 21, 2013 10:00 am ET

Executives

Paul Vincent – Director of Finance and Investor Relations

Terry Swift – Chairman and Chief Executive Officer

Alton Heckaman – Executive Vice President and Chief Financial Officer

Bruce Vincent – President

Bob Banks – Executive Vice President and Chief Operating Officer

Analysts

Neal Dingmann – Suntrust Robinson Humphrey

Leo Mariani – RBC

Noel Parks – Ladenburg Thalmann

Michael Hall – Robert W. Baird & Co.

Curtis R. Trimble – Global Hunter Securities LLC

Leo Mariani – RBC

Gordon Douthat – Wells Fargo Securities, LLC

Operator

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 speaker’s remarks, there will be a question-and-answer session. (Operator Instructions)

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

Paul Vincent

Good morning. I’m Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy’s fourth quarter 2012 earnings conference call. On today’s call, Terry Swift, Chairman and CEO will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer will review our financial results for the fourth quarter. Then Bruce Vincent, President, and Bob Banks, Executive Vice President and Chief Operating Officer will provide an operational update. 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.

Terry E. Swift

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 continue to climb reaching 55% of total core 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 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 to $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 sub-salt test which 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 to our oil and condensate rich areas in South Texas. With over 100 horizontal wells drilled and completed in South Texas, we believe we have delineated our highest value acreage to a point where we can now 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 material proven liquid reserve growth. We grew our south Texas liquid reserves by 121% last year with an overall companywide finding cost of $16.42 to per barrel of oil equivalent. Over 94% of our 2013 net reserve ads were liquid based reserves.

More of our production is now coming from the prior year's activity in South Texas then from new wells. And some of our highest return opportunities lie and 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.

50 and 68 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 opportunities 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 derisk liquid rich acreage, we expect to be able to accelerate activity levels and bring meaningful net present value forward.

In addition to our South Texas opportunities, we are committed to deepening our liquids drilling focus and we’ll evaluate three new strategic growth areas. All perspective for high margin crude oil projects over the next 12 months to 24 months. In order of relative to timing we've already spud our first horizontal Wilcox oil test in South Bearhead Creek field in Beauregard Parish, Louisiana. Due to the historical activity in this field and recent success of nearby operators, we are considering this to be exploration. But rather than just the next logical step in applying leading technologies to our existing oil rich opportunity set. A horizontal – a successful horizontal test of this acreage sets up immediate follow-up drilling. We believe that this opportunity exposes us to 20 million to 30 million barrels of gross oil equivalent of un-booked upside oil potential.

In Southwest Colorado we have approximately 53,000 net acres perspective for horizontal oil drilling in the Niobrara formation. Projects in this part of the country require longer lead times, but we anticipate spuding test 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 multistage completion technology. We believe that this opportunity exposes us to 100 million barrels to 200 million barrels of gross oil equivalent of un-booked upside potential.

Finally, we’ve already taken the initial steps necessary to drill sub-salt 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 test. Personally I want to see this deep sub-salt test conducted with a highly quality recognized industry partner. We plan to do everything necessary to mitigate the risk of this project on a pre-drilled basis, but within reason. We will drill this sub-salt 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 future seismic evaluation and the final determination of how deep we’ll 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’s 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 assets. We believe that this opportunity exposes us to 200 million to 350 million barrels of gross oil equivalent of unbooked upside potential. All the projects I just highlighted are all underway and represent opportunities for the organization to demonstrate the value we see every day in our portfolio to the investment community.

We will discuss all of these opportunities in greater detail at our Annual Investor Day on March 14. 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 levels 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 an exciting point at its history as we are presented with more opportunities than we can pursue at a timely fashion. Near-term our focus is on growing high margin production in South Texas and overtime we will be selective in our activity pursuing only the highest return projects for those unlock strategic value.

Our commitment to pursuing our strategic growth opportunities we’ll involve exploring strategic high quality partnerships early in successful developments or divesting projects we don't believe will fit our portfolio over the long term. While our production in 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 Swift Energy Company.

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

Alton Heckaman

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 2011 and 3Q 2012. The result was solid improvement in revenue and earnings from the prior quarter were down from fourth quarter 2011 as prices softened during 2012 particularly in the gas liquids market.

Our overall results for 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 NGOs were up 41%. Improvement in the oil share of our product mix limited or overall realized price decrease to 12% per BOE in 4Q ‘12 versus 4Q ‘11. As approximately 72% of 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 cost came in at $9.70 per BOE above guidance primarily due to higher leased labor maintenance in chemical trading cost. G&A came in at $3.46 below our 4Q guidance. DD&A was above guidance slightly at $21.08 per BOE because our reserve base has shifted to higher value oil and rich 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 from 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 for 4Q12 came in at $91 million or $2.13 per diluted share, while $7 million $109 million for the quarter.

Quarterly CapEx on an accrual basis was $147 million as our capital activities mainly as to the facilities cost reduced at a slow pace than projected. We recent purchased crude oil floors that will cover 140,000 barrels of first quarter 2013 crude oil production and an average NYMEX strike price of $95.85 per barrel and as always complete details of Swift Energy’s price risk management activities could be found on the Company's website.

Let me wrap up the financial discussion by reminding you of our fourth quarter financing activity. In early October, we issued an additional $150 million of senior notes of add on to our 22 debentures and used to proceeds to pay down the balance on our credit facilities. These notes were priced to the yield of just under 7%. We also extended our credit facility through November 2017, improved our pricing grid and increased our borrowing basic commitment amount to $450 million. The combination of these activities ensures the Company is maintaining liquidity necessary to continue to execute our strategic plans. As always we’ve 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.

Bruce Vincent

Thanks, Alton, and good morning everyone and 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 the full-year 2013.

Beginning first with production, though Swift Energy’s 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 of 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 quarter of 2012.

Well, our fourth quarter drilling results, Swift Energy drilled 15 operated wells during the quarter. In South Texas, 12 operator horizontal development wells were drilled in the Eagle Ford Shale formation in the 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, 2 wells were drilled in the Lake Washington field and 1 well was drilled in the Bay de Chene field. In the Company’s Central Louisiana and East Texas core area, 1 non-operated well targeting the Austin Chalk was drilled in the Burr Ferry field.

We currently have 3 operated drilling rigs in our South Texas core area, drilling the 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 the 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 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 2012 average daily volumes.

Third and fourth quarter production volumes in this area were impacted by Hurricane Isaac. Oil 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 the current spending in this area relative to 2012 levels because of our desire to better match our cash flow with capital spending and now keeping drilling rig active for only a portion of the entire year. This activity is expected to maintain a shallow production decline profile and 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 Olomos 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 was offset slightly by slowing activity in the region. Earlier this morning, we published specific information on wells brought online 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 technics 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 field, contributed 2,842 net barrels of oil equivalent per day of production in the fourth quarter of 2012, an increase of 11% over third quarter 2012 production in the same area. Higher production levels in this area due to non-operated wells in the Burr Ferry during the fourth quarter.

And now I will turn the call over to Bob Banks, to review operational highlights for the third quarter.

Bob Banks

Thanks Bruce. And so Lake Washington field during the quarter we were completed five wells and performed 20 production optimization projects, which include sliding sleeve shift changes, gas lift enhancements, and asset 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 measure 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 of true vertical pay. Over in Bay de Chene, the UB 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 sub-salt 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 earlier remarks we’ve recently observed four key wells at Lake Washington, experience significant water cuts impacting our base production forecast for the field in 2013. This type of occurrence at Lake Washington a field that has produced since 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 the clients as they mature.

In our Central Louisiana East Texas area, the non-operated GASRS 15-1 well was drilled to a lateral length of 7,524 feet in the Austin Chalk in the South Burr Ferry field during the quarter. This well was brought online during the first quarter and produced at initial rates of 903 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 were also given a nice NGL yield from this well of about 175 barrels per million cubic feet of gas.

The results to date from this joint venture have been strong with results improving over the time. One additional Austin Chalk well, the GASRS 29-1-10 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 3 wells during 2013 in the area.

In our South Bearhead Creek field in Beauregard Parish, we recently spot our first horizontal well to test the oily Wilcox formation. As Terry mentioned, we view this activity as lower risk exploitation and a natural fit for the proven horizontal drilling and completion techniques we’ve applied repeatedly at South Texas. Should we achieve favorable results for their first well, we will move forward with additional activity this year. Due to the higher margin oily nature of production from the well cost from 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 completion. Initial results from 60 acre downspacing test in LaSalle County and 50 acre downspacing test in McMullen County have been very encouraging. These results seem to firm the concept of tighter well spacing that our previous assumption of 80 acres in these crude oil and liquids rich project areas.

Aside from a two wells 50 acre down spacing testing in our Fasken Ranch area 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 test 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 flat in the trajectory of our production growth, but we believe well selection drilling and completion performance and lower overall service cost will yield higher margin production than in prior years. As Terry indicated average well 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 our results, versus our forecast to 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 lifts.

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 perspective 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 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 sub-salt 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 perspective 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 already conducted 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 price backdrop, 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 will turn it back to Terry to recap.

Terry Swift

Thanks, Bob. Before we open the line for questions, I will 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; 17 new wells brought online during the fourth 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 and additional 7% to 12% reserve growth is expected and projected in 2013.

2013 capital spending levels 30% to 40% lower than 2012, continued downspacing test which may increase our liquids rich South Texas drilling inventory 30% or more. And as we’ve highlighted today, we have plans for initial test 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 100 million to 200 million gross barrels of oil equivalent of potential and the sub-salt in Lake Washington which has 200 million to 350 million gross barrels of oil equivalent potential.

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

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Neal Dingmann with Suntrust.

Neal Dingmann – Suntrust Robinson Humphrey

Morning gentlemen.

Terry Swift

Hey, Neal.

Neal Dingmann – Suntrust Robinson Humphrey

Just for the 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 in lot of the Eagle Ford and you do have a fair amount of liquidity right now, Bruce may be either for you or Terry just kind of one in sort of a strategy question, why cut so much given sort of the type of IRRs you're getting from that Eagle Ford play?

Bruce Vincent

Well, the couple of reasons Neal, 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 unfortunate of our Eagle Ford development and in form of a joint venture that will allows 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 pay down debt so that we could then increase capital spending in some of the other areas of the company. So we're going to look at that as the prudent thing to do at the outside of the year as we get something accomplished and we can accelerate activity once that's done.

Terry Swift

This is Terry, I will reinforce what Bruce said, our primarily drive over the long term is strategic growth in both reserves and production, we clearly have focused on liquids. But we are keenly aware of the need to manage our cash flow, keep our balance sheet in good shape. So you will see as this year not only moving on these strategic growth projects and as Bruce said with success in the way of partners or joint venture activity put ourselves in a position too accelerate, bring some of that net present value for which we’ll also see us be very conservative in terms of how we are going to forecast things going forward. Make sure we protect the balance sheet because we know that 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.

Operator

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

Leo Mariani – 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 there is four wells maybe off-line and you talked about with the water encroachment issues. I mean additionally can you just talk about your production guidance for 2013 and what do you assuming Lake Washington to do in that guidance. You are assuming kind of continued declines or stabilization in the production?

Terry Swift

Well, I'll take, first short 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 to get higher water cut. And 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 amount of water, I'm not prepared – they're getting the numbers to say that the wells are actually shutting, they may be cycling the wells, to get some more out of them. But they are 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 or rig out there right now, we're doing some completion work. So Lake Washington still has a lot of wells producing and lot of new production that comes on every year that replaces the declines in various ways, but we did have four wells, I think it was somewhere around 1,200, 1,500 barrels a day in the composite, we backed out of the production forecast. Bob?

Bob Banks

Leo, a little detail, we have about a 100 wells producing out there. The four wells, where four of our bigger wells over in that Newport area where we were getting pretty big production from, but at these newer levels and I will say that the production really stabilized the past couple of months. It’s turned a lot flatter, we are 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 may be even some growth at this level with our activity.

Operator

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

Noel Parks – Ladenburg Thalmann

Good morning.

Terry Swift

Hi, Noel.

Noel Parks – Ladenburg Thalmann

Just a few things, just want to get a bit of an update on how the Eagle Ford inventory progressed this year as you didn’t reserve bookings. Just understood and whether you had any improvements as far as wells performing better than their type curves and may be what the tightest spacing is that you booked wells on this year. And then finally, could you give us some sense of may be what the 2P numbers look like in the Eagle Ford?

Terry Swift

The 2P numbers, yeah, yeah.

Bob Banks

Let me take a start of this, I think the most that we’ve – that 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 our most of our liquids rich area 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 taking any of that into account; we have not booked much of our Fasken reserves. But the work we see to date in most of our acreage is we are seeing some improving EURs overtime, some of that is the result of the use of our 3-D seismic and the way we are getting our wells in zone a little bit better, and using some of our attribute analysis to steer those wells. So we’re pretty positive that we are going in the right direction here.

Bruce Vincent

The other thing I would add to that, we did comment on earlier that was we’ve done this down spacing work in terms of nicely drilling the 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. Now you may note that that’s going to be dry gas production, which is not something we necessarily choose to do, but we think it’s very important to understand down spacing potential in Fasken. And so we wanted 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 inventory. So none of that 30% increase is, that’s really focused on (inaudible) wells McMullen County area.

Noel Parks – Ladenburg Thalmann

Okay. And the 2P number?

Terry Swift

We don't publish that 2P number NOEL.

Noel Parks – Ladenburg Thalmann

Okay.

Terry Swift

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 14 and while we may not give specific 2P number something like that I think you'll be able to deduce what that could be from the Analyst Day.

Noel Parks – Ladenburg Thalmann

Great. And then just one last thing, sorry if I missed this before. It looks like the inventory of wells that you’ve bought online in fourth quarter, you had generally stronger rate a few more wells above 1000 barrels I think on the oil side even IP, is that just improved efficiency or as you are saying better targeting or changes in your frac procedures or so forth?

Terry Swift

No, I think as I kind of 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 what we have call the brittle law 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 are steering those wells in the most brittle rock, but we think is this the sweetest part of the lower Eagle Ford and we are noticing much better performance coming out of those wells.

Noel Parks – Ladenburg Thalmann

Great. Thanks a lot.

Operator

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

Michael Hall – Robert W. Baird & Co.

Thanks. Good morning. I just wanted to – I guess circle back a little bit on the joint venture comments in the Eagle Ford. 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?

Terry Swift

Yeah. 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 learn more about the models, we’ve got a much higher confidence level and where the good EURs are and moved away from poor EUR types of activity. We’ve also as Bob noted really focused on the frac activity, we’ve optimized the fracture designs both in terms of some fluid changes that we made as well as sand and [proppant] types, and then as Bob noted the steering.

So we got an operation that we do believe can move faster, accelerate some of the area particularly in La Salle County, we are considering may be 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 and to the bright partners, and it all depends on your deal structure, but basically get ourselves in a position where you would be selling a little bit of production, that’s not really a material piece of it, but you would be accelerating in bringing so much value forward but overall that absolutely would be accretive or we’ll just not do it.

Bob Banks

Yeah I think you have Bruce. You have 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 some differently. We do want to structure a transaction over our partner and Swift are aligning their interest. And we have lot of ways to do that and include a component of the existing proved 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 NPV up forward.

Bruce Vincent

Yeah, just one other comment there, we absolutely are committed to be the operator and taken all the lessons learned and all the advantages that we’ve developed forward within these such potential transaction.

Michael Hall – Robert W. Baird & Co.

Okay, that’s helpful. I guess just may be thinking about seeing from another angle, I mean with the Eagle Ford being so core to the successes to Swift over the last couple of years, I mean why not consider another piece of portfolio from monetization to then redeploy into and accelerate the Eagle Ford. Just kind of curious on the thought process there.

Terry Swift

Well, we are doing with the things that you would expect us to do what we are disposing of, we’re divesting up 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 and it is just not core to us any more. 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 within the Niobrara or as we are 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 are 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, big chunk of what we've got in the Eagle Ford. So...

Bob Banks

Okay, I would just add to couple of comments on that. I think if you – the Eagle Ford area is probably the area where asset base is the best proved up highly valuable out there in the marketplace as well. So there's a lot of people would be interested in that. One of the things if you will note in our strategic growth area we are moving forward fairly aggressively trying to develop the value to a higher level of confidence in these other areas both in Niobrara, if you look at Central Louisiana area, the Wilcox, and if you look at Lake Washington move forward with a plan to get that sub-salt well drill, we're talking about that for some time and we are convinced that we got a very high-quality prospect and want to get a drilled and want to move forward with it. You didn't have those plans to move forward and develop other value in those other area you actually might consider disposing them as well.

Michael Hall – Robert W. Baird & Co.

Okay, that's helpful. Appreciate the color guys.

Operator

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

Unidentified Analyst

Hi guys, thanks for taking the question. Few questions actually, on the timing of the JV how far long in this process are you – is this something we can expect in the next couple of quarters.

Terry Swift

Yeah, I think we would hope to certainly have some by the third quarter.

Unidentified Analyst

Okay. And with regards to your Lake Washington sub-salt 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?

Terry Swift

Yeah, that’s a great question and this is one of my favorite topics. So this is Terry, I will answer that. Interesting enough, Lake Washington back in I believe 1989 was one of the first areas that was looked at by some of the main brand players in developing sub-salt targets. And Lake Washington did have a test of the sub-salt that began in 1989, I think they got log in 1990, but it was pre-3D, they did not had the 3D out there and it was before the big Mars discovery and the big results that were found in the sub-salt.

So we do have and 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, now 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-3D and shortly after this well 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 the Analyst Meeting will give you a lot more detail. We are looking at what I would call recognize players this is a very important test for Swift Energy and its shareholders, so we are going to have the highest quality of players that will be looking at this as we proceeding with our plans.

Unidentified Analyst

Would you expect that some of the valuable potential pay zones would be shallower than what is being discovered over it's a Lineham Creek?

Terry Swift

Yeah, okay, there are two comments. I think what you reference is a good bit to the rest of us, and a good bit really kind of offshore, it's not really an offshore, but it's over (inaudible). That area tends to be more gassy and yes the things over there are deeper. But that said, we're very confident then we've got an old prospect, because of our location will show some data at our Analyst Meeting that will help people get very confident in that. Will then that all piping studies as well as have some shows down dip that all, but finally I would like to also mentioned that the Amoco well that was drilled off structure and down dip from us was still in sands at 22,000 feet.

Unidentified Analyst

Okay. 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 are seems to be a lot of very high impact potential that you can bring forward in the next couple of years. The stock price is down again today is that a 52-week low and 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?

Terry Swift

That’s a really good question and we get that certainly at times like this. I have to say, I’m really disappointed with where the stock price is right now. I do think we’re considerably undervalued or 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’re talking about one, two year types of growth activities, we are doing things now, and we are taking every effort now to accelerate some of the things that we are talking to you about, because we’re just not going to sit around and wait on, I guess the market to try to adjust, that we’re going to be very proactive trying to make sure that the markets seize the value.

That said, I do think the stock as a buying opportunity and there has been times in the past where the company did use some of its liquidity to buyback 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 get in the stock up, is to bring those projects forward and let you see the results, then to try to collect shares. That’s my personal view.

Unidentified Analyst

Okay I appreciate it. Good luck.

Terry Swift

Thanks Dan.

Alton Heckaman

Thank you.

Operator

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

Curtis R. Trimble – Global Hunter Securities LLC

Good morning everyone. I was hoping may be you guys could [WHET] those appetites for the upcoming Analyst Day, give us a little bit of profile on the Niobrara wells, expected cost, EURs things like that?

Terry Swift

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 they did produced from the Niobrara after frac and those wells tend to make all 30,000 barrels 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 frac to 15 frac stages. We do believe that we could get somewhere around 250,000 barrels to 350,000 barrels per well, and I think the drilling costs...

Bob Banks

Yeah, I think the long-term, we have modeled in about 6 million drilling costs to complete model stage frac. We think the costs are going to be less than that, these are shallower debts, EURs in the 250 MMBoe to 400 MMBoe range.

Terry Swift

And initially obviously costs are little higher this will drill pilot holes and core samples and the like. We think it's – really good opportunity for a sustained oil play in the good areas.

Unidentified Company Representative

Yeah, just a little bit more color for those of you don't know, this is really a north western portion up dip out of the San Juan basin what's called the hog back mono Kline area, so you do also have some natural fracturing in that area, you are up out of the gas window, as I mentioned there is a field in there, that believe it's the red mesa field that has already produced oil from these horizons. So even though it still perspective and still exploratory in nature there is a lot of good strong control points that show us that it’s oil.

Curtis R. Trimble – Global Hunter Securities LLC

Okay. You had there in pretty pristine country, any regulatory issues, anything of that nature to be concerned about?

Bruce Vincent

Well, yeah coming clearly we’ll have to deal with the local community and we’re in the process of doing that. Colorado State Oil and Gas Conservation Committee, is the regulatory authority for oil and gas activities across the state. But you will have to deal with the local community in particularly 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 second one is probably what you can do with the water disposal and then truck traffic, things like that. Those are all issues that have taken place in a number of shale developments across the country. I think you will recognize those have to be dealt with. But they can’t be, the industry could deal with those things. We just need to work with the community as a good neighbor. But both not just developing the resources, but bringing in lot of economic uplift to the county as well.

Curtis R. Trimble – Global Hunter Securities LLC

Good, I appreciate it. How about an idea of one room over on the Wilcox play at South Bearhead Creek have any perspective locations you think you might have there that define that 20 million barrel to 30 million barrel potential?

Terry Swift

Yeah, I think we have both an upper and the lower Wilcox. And right now we have multiple zones in multi-upper and the lower. We have about three units in the upper and some more units in the lower. So a lots really going to be depended 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 have the opportunity to go much higher if we target the individual units within these upper or lowers.

Curtis R. Trimble – Global Hunter Securities LLC

So when about the verticals...

Terry Swift

The vertical produce this year, this is in a field were we've already drilled and produced, the vertical producers in this field are yielding anywhere from about 100 MMboe to 400 MMboe EUR. So we feel very good that putting our lateral technology into this filed which is very similar to the almost field only this is oily and within control that will get multiples on those vertical producers.

Curtis R. Trimble – Global Hunter Securities LLC

With the vertical interval between the upper and lower have any separate those?

Terry Swift

Maybe 1,500 feet.

Curtis R. Trimble – Global Hunter Securities LLC

Okay.

Terry Swift

1000 feet to 1500 feet.

Curtis R. Trimble – Global Hunter Securities LLC

I appreciated.

Terry Swift

Thanks.

Alton Heckaman

Thank you.

Operator

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

Leo Mariani – RBC

I guys, just curious is to whether or not there was a significant active drilling activity in and around La Plata County right now other operators involved in this area?

Terry Swift

There's not a significant drilling activity taking place, but historically (inaudible) numbers correctly there been over 50,000 wells drilled at La Plata County and they go always maybe 10% have been frac before, so there is the activity – the vast majority of the wells drilled in La Plata though have been coal bed methane. What will be new to La Plat is a 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 to getting up there and educating people as to what will take place and working with local county Board of Commissioners, both in terms of [road use], and water and all the various things that people widely are concerned about?

Terry Swift

Yeah I might add though that again north-western uplifted area of the San Juan Basin what we call hog back mono Kline area. 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 too 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 room 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 Indians I believe, they have also drilled a horizontal multi-stage well out there.

Leo Mariani – RBC

Thanks guys.

Bruce Vincent

Okay.

Operator

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

Gordon Douthat – Wells Fargo Securities, LLC

Good morning guys.

Terry Swift

Good morning.

Gordon Douthat – Wells Fargo Securities, LLC

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

Bob Banks

Yeah our 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’ll very update up 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 activities, I feel pretty good to about double digits on production in 2014. On the reserve side, I think we feel good about where we're at this year and where will be next year as well.

Gordon Douthat – Wells Fargo Securities, LLC

Okay, thank you.

Operator

Your next question comes from the line of (inaudible) Lee Munder Capital Group.

Unidentified Analyst

I just kind of back to the JV issue, there seems to be a massive disconnect between what sell side now models say in your outlook, if I try to dissect that, the thing that kind of keep someone back when you talk to various people as a management credibility issue. And 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 is not going to help your creditability, and why not considered as a strategic alternatives for the whole company and your stocks down 13% today on production outlook that was significantly less and what the street expect and I know you did producing more CapEx this year, but it still you say one thing one quarter and then something else happen to 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?

Terry Swift

Well, I’ll address it first and then Bruce may have some follow-up comments. First of all we're committed to the growth of Swift Energy Company and we do believe we got significant assets we've spent some time here today talking to that extent and at our Analyst Meeting we are going to lay out whole lot more information into the extent that there is any creditability issues than 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 the 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 recognize for its value. So your comments about value are absolutely legitimate and I certainly hope you be at the analyst meeting because get deeper into of the assets and ask whatever questions you want to the management.

Bruce Vincent

Well I do think as to the strategic joint venture in the Eagle Ford would validate the value of the Eagle Ford compared to what the market’s value in it. Secondly, I don’t think the appropriate time to look at strategic alternatives, is when your added significant low point in terms of valuation.

Terry Swift

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

Bruce Vincent

I menace as we’ve noted we are definitely looking at ways to accelerate our activity and bring forward the net present value. And when you talk about whether it’s Lake Washington or a deep sub-salt player, that’s going to be a name brand player. I don’t think there is going to be any doubts about the credibility or the capabilities of the (inaudible) we’ll be talking with for that project. But 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 are doing by the types of joint ventures that we’re contemplate putting together.

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

Terry Swift

We are definitely looking at ways to accelerate our activity and bring forward the net present value and when you talk about whether its Washington on a deep sub-salt player, that’s going to be a name brand player. I don’t think there is going to be any doubt about creditability or the capabilities of the kinds of players we will talking with for that project. That same thing is true in the Eagle Ford. So I do believe that we will bring forward a lot more confidence in what we are doing by the types of that we are contemplating putting together.

Unidentified Analyst

Okay, thank you.

Terry Swift

Thank you.

Operator

At this time there are no further questions.

Terry Swift

Okay, well we thank you so much for joining us today.

Operator

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

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