SilverBow Resources, Inc.
Q1 2013 Earnings Call Transcript

Published: 3 May 2013

[Operator:]

Good morning, my name is Colleah and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Company First Quarter 2013 Earnings Conference 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) Thank you. I would now like to turn the call over to our host, Paul Vincent, Director of Finance and Investor Relations. You may begin your conference.

[Paul Vincent:]

Good morning. I am Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy's first quarter 2013 earnings conference call. On today's call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer, will review our financial results for the first 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 of 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 Swift:]

Thanks, Paul. And thank you to everyone for joining us on the call today. Swift Energy achieved higher than forecast production levels during the first quarter. Through a combination of better than forecast production rates in that Eagle Ford shale and stronger performance of our base production in Lake Washington, we achieved production of approximately 4% above the high end of our range of estimated results. Our primary goal this year is to improve the initial production and the EUR averages of our South Texas assets by approximately 10%, while reducing our average cost per well by 10%. We believe that our first-quarter results and expectations for the rest of the year see us on our way to reaching that goal. Beginning in the second half of 2012, we began to drill our laterals in the Eagle Ford shale directed at a narrower specifically targeted section of the lower Eagle Ford with more precision than we had previously drilled. This has allowed us to complete our wells in a more porous section of the shale with higher total organic content. A good example of the impact of this -- that this approach has had is a well we drilled and completed in the first quarter. The PCQ7H initially tested at a rate of 1,742 barrels of oil equivalent per day. This compares to the last well in this area we announced the PCQ6H, which tested at a rate of 1,011 barrels of oil equivalent in the fourth quarter. This is only one example and while no two wells are the same, we do believe the refined targeting of our horizontal laterals will continue to yield improved production and reserve profiles to varying degrees across all of our Eagle Ford acreage. We are improving our performance in South Texas at the same time as we are reducing our total capital expenditures, primarily through a lower rig count and reduced drilling activity. We are conscious of our cash flow levels and want to balance our activity in cash flows so that we clearly have an incredible opportunity to develop the high-value predictable crude oil and liquid rich play that we have in South Texas. This is why our second area of focus this year is to also accelerate activity in this project area through some type of partnership or joint venture opportunity. We are working towards a transaction with either a strategic or financial partner that will allow us to maintain at least a three rig program in our highest value acreage without increasing our leverage metrics and ultimately enabling us to grow our cash flows. There have been numerous transactions in the Eagle Ford shale announced this year, and we will still expect to have a transaction in place by the end of the third quarter. As we achieve this milestone, we will be able to increase activity levels shortly thereafter. While we do not believe that we have to enter into such a transaction, we believe that a deal would accelerate the present value of our assets, and at the same time provide a positive benchmark to the market for the per acre value of our acreage. We're also evaluating our portfolio for opportunities to monetize assets where we have low levels of activity or that don't fit into our longer-term strategic plans. In our release this morning, we announced the divestiture of our Brookeland field in East Texas. This wasn't a large transaction, but it is indicative of the direction we are headed toward streamlining our portfolio and focusing on the opportunities we believe have potential to be high-value, multi-year project areas. While South Texas is our primary area of activity today, we are developing three distinct opportunities in other operating areas that would afford crude oil and liquids rich growth should they be successful. We expect to achieve a key project milestone in each of these areas this year. I'm going to go into those areas in my discussion here. In Central Louisiana, we've just drilled our first horizontal well in the Wilcox formation in South Bearhead Creek. We are preparing to fracture stimulate approximately 3,400 feet of lateral during the second quarter and expect this well to confirm that this field can be developed horizontally with the new technologies. This is an area we control and we can accelerate activity here in the future. But as discussed earlier in the year, we do view this as an important part of our 2013 plan. We've also taken major strides toward spudding our first horizontal Niobrara test in La Plata County, Colorado, later this year. We spent a considerable amount of time working with the local community and the state and are in the process of securing permits to drill our first well. Permitting and spudding at least one well in this area are additional key targets for us this year. With approximately 50,000 net acres to Swift in this area, it will take us some time to evaluate our opportunity set fully, but we believe recent results from other industry participants in this area have demonstrated the potential that this has for horizontal drilling techniques in this liquid and crude oil area. Successful test in this area would also create opportunities to accelerate activity and growth in the future. In what is likely to be our longest lead time and highest risk, but also our highest potential reward growth project, we are developing and have made significant progress towards drilling a sub-salt well beneath the Lake Washington salt dome. We expect to present this opportunity to a small population of strategic industry participants over the course of the summer. Should our prospect be favorably received, we would expect to achieve our stated 2013 goal of having an operating partner in place for this important project before the end of the year. There is certainly a market for this type of deep exploration and we believe we have developed a world-class prospect that will be extremely meaningful for Swift Energy and exploration along the Gulf Coast. Considering the variety of projects we are working on, we are clearly balancing our efforts to allow for the most operational and financial flexibility possible given the external environment. With reduced capital spending levels this year, our challenges include maintaining economies of scale and operational momentum in South Texas, while developing significant future growth potential in new areas. These challenges have compelled us to focus our drilling dollars on our highest return projects, while continuing to look for ways to reduce our cost structure. At this point, we believe we are still on track to meet or exceed all of the milestones we've said and that I have discussed with you this morning. We have assembled a great team of operational and financial professionals to develop our diverse assets and unlock the value that we see in them. As we move through the year, we'll demonstrate our organization as poised for production and cash flow growth and we will be able to achieve that growth without meaningful additional leverage or dilution. And now, I'll ask Alton to present our first-quarter 2013 financial results.

[Alton Heckaman:]

Thank you, Terry, and good morning, everyone. In the first quarter of 2013 we exceeded our production guidance in both oil and natural gas liquids resulting in a sharp increase in net income compared to 1Q '12. Some highlights for the quarter, we had oil and gas sales of $146 million, and the income of $7.2 million or $0.16 per diluted share. Cash flow, before working capital changes for the quarter, was $1.67 per diluted share, and production came in at 2.8 million barrels. Natural gas prices were up 36% from 1Q '12. Crude oil prices were relatively flat and NGL prices, as you know, were off 34%. Combination of the improved natural gas pricing, along with changes in our production mix, resulted in an overall 7% increase in our net price realized per BOE. Oil revenue actually accounted for 73% of our total sales revenue for the quarter. As to our controllable cost and metrics for the quarter, G&A came in at $4.51 per BOE below guidance. DD&A was near the low range of guidance of $21.33 per barrel. Interest expense came in below guidance at $5.96 per BOE. Severance and ad valorem taxes were well below guidance at 6.7% of revenue due to better than expected benefits from state incentive programs approved and received during the quarter. And production costs for the quarter, which include transportation and processing, came in above guidance. A major contributor to the increased cost for the quarter was due to a well control incident in Lake Washington. Several other components of our operating costs in South Texas were also higher than forecast. But as you can see, these costs were already being reduced prospectively with respect to our forward 2013 guidance. As previously mentioned, the net result was income for the quarter of $7.2 million, or $0.16 per diluted share above the first-call mean estimate of $0.11. Our effective income tax rate for the quarter was 37.8%. Cash flow before working capital changes for the quarter came in at $73 million or $1.67 per diluted share while EBITDA was $90 million for the quarter. Quarterly CapEx on an accrual basis was $144 million on the lower end of guidance. With the updraft in prices during the quarter, we secured oil floors covering a good portion of the second quarter and natural gas floors covering portions of both the second and third quarters of 2013. We also recently layered in very attractive collars covering a meaningful percentage of our fourth-quarter nat gas production. As always, complete and timely details of Swift Energy's price-risk management activities can be found on the Company's website. We continue to maintain a strong balance sheet and the financial flexibility to execute our plans. Our banks recently reaffirmed our $450 million borrowing base and commitment amount and we recently closed on the $6 million sale of our Brookeland properties. As always, we've included additional financial and operational information in our press release, including guidance for the remainder of 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 to everybody. Today I'm going to discuss the first quarter 2013 activity and it's going to include the production volumes, the recent drilling results, activity in our core operating areas, and our plans for the second quarter and full-year of 2013. Beginning with production, Swift Energy's production during the first quarter of 2013 totaled 2.82 million barrels of oil equivalent, that's above our expected range of outcomes. First-quarter production was 2% greater than first-quarter 2012 production of 2.80 million barrels of oil equivalent and decreased 7% from the 3.11 million barrels of oil equivalent produced in the fourth quarter of 2012, as primarily due to lower sequential natural gas volumes. For the first-quarter drilling results, Swift Energy drilled 10 operated wells during the quarter. In South Texas, six operated horizontal wells were drilled to the Eagle Ford shale formations in South Texas. Five of these wells were drilled in La Salle County, and one was drilled in McMullen County. We drilled three wells into the Olmos formation in McMullen County. In Swift Energy's Southeast Louisiana core area one well was drilled in the Lake Washington field. We currently have four operated drilling rigs in our South Texas core area, drilling Eagle Ford shale wells and one operated rig active in Lake Washington. One non-operated rig is drilling in Austin Chalk well in Central Louisiana. In the Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields, production during the first quarter averaged approximately 4,956 net barrels of oil equivalent per day, down 24% when compared to the fourth quarter of 2012 average net production from the same area. Lake Washington averaged approximately 4,642 net barrels of oil equivalent per day, a decrease of 25% when compared to fourth-quarter 2012 average daily volumes. Lower production volumes during the quarter were primarily a result of unexpected increases in water production in four wells in the field beginning in the fourth quarter of 2012. This significantly reduced the performance of these wells. Average daily production in Lake Washington for the quarter was in line with our expectations after adjusting for these performance issues. Bay de Chene production of 314 net barrels of oil equivalent per day was up 6% when compared to fourth-quarter 2012 production levels as we've brought on one new well on to production during the quarter. 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, first-quarter production averaged 23,392 net barrels of oil equivalent per day, a 4% decrease in production when compared to fourth-quarter 2012 production in the same area, and a 5% increase over first quarter 2012. This sequential decrease is primarily due to natural declines in gas production volumes in our Fasken area in Webb County, Texas. We are drilling a two well down-spacing test in this area currently. But have not brought a new well online in the area since the first quarter of last year. Earlier this morning, we published specific information on the wells brought online during the first quarter in our quarterly press release. I'll refer you to that set of data. 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 improved drilling and completion efficiencies. The Central Louisiana and East Texas core area, which includes our Brookeland, Masters Creek, Burr Ferry and South Bearhead Creek fields contributed 2,770 barrels of oil equivalent per day of production in the first quarter of 2013, a decrease of 3% over fourth quarter 2012 production in the same area. Lower production levels in this area are due to the timing of the completion of a non-operated well in the Burr Ferry area during the first quarter. I'll now turn the call over to Bob Banks to review operational highlights of the third -- of the quarter.

[Bob Banks:]

Thanks, Bruce. At the Lake Washington field during the quarter we completed one well and performed 22 production optimization projects, which include returning shut-in wells to production, sliding sleeve shift changes, gas lift enhancements, and acid stimulations. We drilled one well at Lake Washington during the first quarter. At Lake Washington the BLD CM 21 was drilled to a measured depth of 6,441 feet and encountered 150 feet of true vertical pay. Recently completed, this well tested at an initial rate of 667 barrels of oil per day and 0.5 million cubic feet of natural gas with flowing tubing pressure of 580 PSI on the 2664 inch choke. Two of the wells in South Louisiana were completed during the first quarter. First in Lake Washington, the CM 428 drilled in the fourth quarter of 2012 to a measured depth of 3,445 feet encountering 47 feet of true vertical pay was completed and tested at an initial rate of 432 barrels of oil per day and 0.2 million cubic feet of natural gas per day with flowing tubing pressure of 360 PSI on a 2464 inch choke. 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 during the fourth quarter, but was completed during the first quarter. Now named the BDC UA139, this well initially tested at rates of 5.3 million cubic feet of natural gas per day and 17 barrels per day of condensate with flowing tubing pressure of 3120 PSI, on a 1664 inch choke. We have one bar drig in the field drilling a well in the southern part of salt dome. At this point, we don't expect to drill any additional wells at Lake Washington this year after this well is drilled. All in line with our plan, lower spending levels. We will, however, maintain a recompletion workover and maintenance programs in the field to mitigate natural declines for the remainder of the year. In our Central Louisiana East Texas area, the non-operated gas GASRS 29-10 Austin Chalk well was drilled and completed during the first quarter in the Burr Ferry field in Vernon Parish. This well produce hydrocarbons at an initial test rate of 1,042 barrels of oil per day, and 3.1 million cubic feet of natural gas per day, with flowing tubing pressure of 5,900 PSI on a 1664-inch choke. This well, however, after completion did experience a significant mechanical problem and has been shut-in pending further evaluation. At this point, it's not anticipated that this well will be brought into our production forecast for the rest of the year. Our partner is currently drilling what we now expect to be the last joint venture well that will be drilled in the area this year. We have been impressed with the results of many of the wells drilled by the joint venture to date, and like this area in that the wells are high rate with a large liquid component and the economics are very good. We have, however, observed a wider than expected variance in the repeatability of the results. In that regard, the joint venture partners, we will take the second half of the year to review our well design and completion methodologies to improve the overall operating performance of the area. At South Bearhead Creek in Beauregard Parish, the Company has drilled its first upper Wilcox test well. As Terry indicated, this is one of our key milestones for the year. The James O. Dolby H1 has a horizontal length of 3,387 feet in the upper Wilcox, and the completion system has been run. A 12-stage fracture stimulation will be conducted during the second quarter. Prior to drilling the lateral section, we drilled a vertical pilot holes through three key target intervals in the upper Wilcox and were able to collect good log and core data that has us encouraged and will help us to further appraise and develop the area. Moving to South Texas, seven Eagle Ford horizontal wells and two horizontal Olmos wells were completed during the first quarter. In this morning's press release, we included a table highlighting data from these completions. As we've spent some time discussing refined targeting of our laterals in the lower Eagle Ford shale, resulting in stronger well performance, I'll discuss now our progress today. In McMullen Eagle Ford oil area, the PCQ EF7H completion during the first quarter initially tested at rates substantially higher than our 2013 model forecast, which was shared with our Investor Day Conference in March, as well as higher than our PCQ EF6H well, which was completed in the fourth quarter of 2012. PCQ7H targeted the tighter drilling window within the lower Eagle Ford as defined by our 3-D attribute work. The entire lateral length was maintained within this target window and I believe it really represents our best attempt to date to use this new geotechnology to help improve our IPs and EURs across the play. In general, improvements continued in our McMullen Eagle Ford oil area with the exception of one well, which was drilled much earlier but was only recently completed. It did not have the benefit of the newer geotechnology approach. Out in La Salle Eagle Ford and oil condensate area, the batch 3H, a down spaced well, tested at higher rates than the 2013 model we shared during our March investor day, the two Aldermen Ranch wells were under the new IP projections for the area, but that was for a number of reasons. First, both wells were much shorter in lateral length due to the lease configuration. Second, the line pressures in this area had been about 200 PSI higher than our normal operating pressures. And thirdly, the IPs were early rates while still producing flowback water. If we look at our average 30 day rates, they are actually higher than the initial rates at approximately 830 barrels of oil equivalent per day. In our McMullen Olmos oil and condensate areas, the two recent wells did outperform the new model projections that were again shared at our Investor Day in March. With the use of our new 3-D attribute analysis and geosteering approach, that targets the best zones within the lower Eagle Ford and as infrastructure, compression, marketing and logistic needs are met, our operations will continue to take on more predictable characteristics that will yield improved performance metrics across our acreage position. We also continue to be encouraged by the down spacing work we've done and believe we are on track to increase our inventory of oil liquids rich drilling opportunities. And as Terry already mentioned, we're also continuing to work towards the formation of a partnership that will allow us to accelerate activity and grow production and cash flow without additional leverage. When I consider all I've just reviewed in addition to the drilling the Niobrara test this year and putting in place a timeline to drill a sub-salt expiration test, with a quality industry partner, we think we're in a great position to have a variety of projects that will all deliver crude oil or liquids rich production for some time to come. With that, thank you for your attention. And I'll turn it back to Terry to recap.

[Terry Swift:]

Thanks, Bob. Before we open the line for questions, I'll summarize Swift Energy's first-quarter results and review some of the highlights from today's call. First of all, strong Eagle Ford new well performance and Lake Washington base production supported first-quarter production of 2.82 million barrels of oil equivalent above our prior forecast. Nine new wells brought online during the first quarter in South Texas. We had further confirmation of our refined laterals in the Eagle Ford shale and contribution to improved well results. Our first horizontal Wilcox oil well was drilled and is waiting on completion. We anticipate accelerating high-value Eagle Ford activity after securing a transaction in that regard. We remain on schedule to drill a Niobrara horizontal well test in the second half of this year and we are designing and preparing to entertain reviews from potential partners, a sub-salt test in Lake Washington and expect to have such a partner to drill this well in place by year end. With that, we'd like to begin the question-and-answer portion of our presentation.

[Operator:]

(Operator Instructions) Your first question comes from the line of Noel Parks of Ladenburg Thalmann.

[Noel Parks:]

Can you hear me?

[Terry Swift:]

Yes.

[Noel Parks:]

Good. Just a couple of things looking at the Eagle Ford, you talked about how the variety of results this quarter reflects some special factor shorter laterals because of the leases and so forth, as you look ahead to the second quarter, this late of wells, do you think you are going to have more of the wells that are sort of, you know ideal lateral length and in the target zone or do you think you will still have some of these may be older style drilled wells?

[Bob Banks:]

Yes, let me try to answer that. I think generally we have completed now most all of the wells that were drilled earlier prior to utilizing the new attribute work and the geosteering. So I think pretty much everything we are doing now, all the wells that are at least coming through the planning phase and going into execution right now, we are being very specific with our teams, looking at that attribute work and making sure that the well plans are projected and that we come back and look to make sure that the wells stayed in the zone the way they were planned. So I would say this quarter most all the wells should be targeted into the end of the new zone. I don’t believe we have any wells with a shorter well lengths in the plan for second quarter, I think they are all more of the 5,000 to 5,700 foot lengths. These two wells were unique in nature, in that they were down more long about 4400 feet to 4500 feet. So I believe we don’t have any more shorter laterals for the second and third quarters based on my recollection.

[Terry Swift:]

Just one other comment on those two wells, clearly some of the results are indicative of the shorter lateral versus long lateral issues. We did have some issues in that area relative to getting them into the line and as Bob noted there were some pressure issues with infrastructure, but the 30 day test actually, Bob, you were actually better than these initial test.

[Bob Banks:]

Yes, the 30 day average was actually better than the initial test. One of the things that we're doing is we're releasing our flow back more quickly, so the IP rates that get published are usually probably about a seven day rate. If we are restricting the chokes, there is still a lot of produced water coming back, so I think we are going to look at how we report that IP and also probably we will start doing more with looking at 30 day averages and that sort of thing.

[Noel Parks:]

That’s interesting. I know one of the theories for a while had been that perhaps you could influence the EUR based on how you choke the well initially, is that still something you're experimenting with?

[Terry Swift:]

Well, we look at that I will tell you where we really look at that more seriously is in the -- in more of the oil window where we don’t have a lot of associated gas. In those cases, you will look and see the haze wells that we reported, while they were good numbers, I am going to point to you that those are on 1464 inch choke settings, so you will see us restricting our choke more on the oil areas in the future I believe.

[Noel Parks:]

Thanks. Appreciate that -- that detail. And I guess just the last over me then, at Burr Ferry you mentioned that it will take some time to look you in the partner your partner that would take some time to look at well design and completion techniques, do you have a sense that that is the next hurdle to get over in terms of just identifying how you know which wells are going to -- or how it is going to perform and hopefully get better repeatability?

[Terry Swift:]

Well, one of the key things and in fact I just talked to my counterpart in Anadarko over this area yesterday, I mean one of the keys really in this area is getting this well packer assembly into the well bore, we think that that really dictates whether they are going to be successful or not. So we have to look at the curves, the way we drilled the curves, we need to make sure that we use rotary steerables, we get a smoother well bore configuration, we do cleanout runs, condition that hole before we run that assembly, we think that’s all very key to making this more predictable and more repeatable. And so, we had these discussions as late as yesterday but we've been having lots of technical meetings with our partners on this, and that’s really the thing for us to work out, that the design and the completion methodology has to provide for that sequence of operations in a repeatable manner and that’s what we have to work through and ensure ourselves of.

[Noel Parks:]

And just refresh my memory, which well was this that you've drilled? Is this about the sixth or seventh you’ve drilled in the partnership?

[Terry Swift:]

We have drilled -- hold on just a second, we are adding them up here. We can get back, but certainly we've drilled seven or eight wells. Many of the wells we are very happy with the performance. And even our partner will state that this is very economic, they like the area, we all like the area, we just want to make sure that we can get a repeatability issue sorted out you know before we continue on. So we have to be sure that we have all these issues identified and optimized.

[Bob Banks:]

One comment there, to remind everyone, we have a very good lease terms in the area in terms of timing, there are no lease issues there that are pressing us in any way. In fact we are a mineral owner in the area. So we actually are the royalty in many of these leases.

[Terry Swift:]

And just one more follow-up, we've just calculated, we are drilling our 10th well now with the partner.

[Noel Parks:]

Thanks a lot. That’s all for me.

[Terry Swift:]

Thanks Noel.

[Operator:]

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

[Brad Heffern:]

Good morning, guys.

[Terry Swift:]

Good morning, Brad.

[Brad Heffern:]

Just a quick question on your guidance, if I look at the second quarter, you guys have projected sort of a sequential decline in both oil and NGL, I was just wondering if that was related to timing or if you could provide some more color on that?

[Terry Swift:]

Well, I'm going to let Bob follow-up on that, but I think it's essentially timing relative to the year and the fact that we mention we do have these Fasken wells where we're doing the down spacing, they should be coming along in the near-term, but it's a small change, and really I think we need to look to the whole year, we are focused in terms of the whole year on oil virtually everywhere else, so I think it's a timing issue particularly.

[Bob Banks:]

And then the Austin chalk well that we mentioned earlier, that had the mechanical problem down hold that we've shut in, that we don’t expect to get back on, has impacted our future production as well and that’s very liquid rich type of production oil and liquid rich.

[Terry Swift:]

Yes, and as we just noticed, obviously we lost that one key Austin chalk well into our mix going forward. We took that out of our production forecast. We have some key events to occur. We've our upper Wilcox test, which will be very oily well, you know we have to see how that’s going to come on. So we are looking at that. And as I think Terry and Bruce mentioned, Fasken, we've got some Fasken gas wells coming on the down space test and that we've got some end of the quarter compression projects that aren’t coming in until the end of second quarter.

[Brad Heffern:]

Okay, got it. And then just looking at your CapEx forecast as well, it seems like you are projecting half of some pretty substantial savings, I guess coming in the play in the second half of '12 or of '13 or you know maybe there is some truth projected savings from that, JV in there. Can you sort of go through whats contributing to CapEx going down then?

[Terry Swift:]

Well, first, while they are getting their papers and talking about the actual plan, I do want to emphasize that the guidance that we've been given does not have a transaction within it. So that’s all things we are doing to a creed or add value to the share, but in terms of the forward plan, Bob.

[Bob Banks:]

Yes, I mean it's really, it's just continuing to reduce activity level, in Lake Washington as I mentioned, it will be our last well, the well that we own now. You know so the capital expenditures for new drilling there, will subside, will continue on with our you know with all of our optimization projects and sliding sleeves and gas lift and all that. This will also be the last well that we drill in the Austin Chalk well -- in the Austin Chalk area as I mentioned, earlier. So that’s going to scale back. So you are going to see most of the activity really the remainder of the year focused in the South Texas, where we have better control of our CapEx and repeatability, and so that’s kind of how the program is laid out at this point.

[Terry Swift:]

Yes, I mean, our guidance is really the same as it was at the beginning of the year, designed to curtail capital spending in the second half of the year to proclaim in the fourth quarter and does not assume any sort of transaction obviously some sort of transaction that brings in a partner in a part of our Eagle Ford area, would allow us to increase spending by diverting capital to some of these other areas and so until we get something done and until we understand the structure of that, we are providing guidance assuming we don’t do anything.

[Brad Heffern:]

Okay, understood, thanks and last one for me, can you just talk a little bit about oil production in Lake Washington is currently?

[Bob Banks:]

Yes, that I think we are at about -- I think it's pretty close to that 4600 net barrels of oil equivalent per day. You know, we've got a relatively stable you know what the new well adds and the recompletion work that we've got, we've got ongoing and we will continue to do some re-completes and sliding lead changes and even some crude tubing completions to try to make sure that we can keep that production maintained.

[Brad Heffern:]

Things guys.

[Operator:]

Your next question comes from the line of Steve Berman of Canaccord Genuity.

[Steve Berman:]

Thanks, good morning. Just one clarification, it was the last two wells on the well list on the press release that had the higher 30 day average and published IP rates here, these two ARN wells.

[Bob Banks:]

Yes, those of the wells, that’s correct.

[Steve Berman:]

All right, Alton how much was drawn on the borrowing base at the end of the quarter? Or what’s the total available either way you want to answer.

[Alton Heckaman:]

About 100 million was drawn into the first quarter.

[Steve Berman:]

Okay and I mean are you actively shopping any other assets now in terms of maybe having data rooms open or anything like that? How active are you in looking to do some more divestitures?

[Terry Swift:]

Well, you know, we are always looking at our assets to try to see which ones are performing the best, and fitting into our strategic plans as we noted, and of course Brooklyn, though a small transaction, we had that one out, and that was in the data room and worked out rather well. We don’t have any other assets out there, in the data room, beyond some of the things that we've discussed in South Texas, trying to look at a transaction there. But we clearly continue to look at these assets, and wherever we see an asset that doesn’t fit into our longer-term strategies, we are going to look at ways that we can either get it to fit, or reallocate capital so that we are focusing on our better assets. So not to say you would never see another data room come up, or another Brooklyn type income forward, because they will, but we don’t have any open right now.

[Steve Berman:]

Okay, that’s it for me, thanks gentlemen.

[Terry Swift:]

Thanks Steve.

[Bob Banks:]

Thanks.

[Operator:]

Your next question is from the line of (inaudible) of John Rice.

[Unidentified analyst:]

Good morning.

[Terry Swift:]

Good morning.

[Unidentified analyst:]

It sounds like the Wilcox well to date has been going okay. Can you talk about the drilling I mean did you land that all in the B zone, and I know that the development mode target was about $11 million for a BUL, any estimate for this initial one?

[Terry Swift:]

Well, this first well, I think it's one thing developed, this well you have to remember, we drilled a pilot hole, we got logs, we got course, we are doing a lot of the valuation work, looking at a number of members of the upper Wilcox. In terms of the lateral, where we have the completion, that is all landed in the B zone. We did land that with a Rotary steerable, so that’s where we are going to concentrate our frac for stimulation treatment is in that B zone on this well. So yes, the 11 million that we're talking about, we think that’s still a decent number for development type drilling, but certainly not for the early, early evaluation well, just like we did down in the Eagle Ford, we drilled a number of wells down there with pilot holes where we got course involves and one thing that we will say and I think I mentioned it in my comments, in the Wilcox, the quarters looked very, very good to us. We were pleased that we gathered that data, and that’s actually given us a fair bit more confidence. In terms of the lateral section itself, it actually drilled quite quickly and in fact it drilled probably quicker than we would have expected it to. So -- but it's our first well. This is not a development type well. I think the numbers we talked about are still good for development drilling.

[Unidentified analyst:]

Okay, and on the completion side, and obviously it's a pretty deep subtenant thousand if I'm remembering correctly, are you guys going to use ceramics there and can you talk a little bit about the design on the fracs?

[Terry Swift:]

Yes, that's right, we are going to use a higher strength profit into this B zone because of the reasons you are talking about. We've run at a mechanical packer system in that will give us our diversion for the treatment but yes, we are going to use a higher strength profit, and we one of the things we were able to do in this field just like we did in the Olmos in South Texas, we've drilled a number of vertical Wilcox wells and in fact many Wilcox wells vertically, so we have that experience to go on as we design this completion.

[Unidentified analyst:]

Okay, and then on the LaSalle, excuse me LaSalle Wells, quarter-over-quarter, it looked like you had a pretty nice GOR drop on those IPs, are you guys simply moving a little bit more of dip or is there something going on there that I might have missed?

[Terry Swift:]

Well, I think you know when we had our Investor Day, we showed you a composite model and there are actually two different models that make up that composite model, there is a northern area, which is more oily and there is a southern area which is more like the condensate model. So yes, when you see these northern wells, you will see a higher -- higher oil content, lower GOR. So it just depends where on our lease position we are drilling those wells, as to the GOR whether it's North or South, and there's frankly probably one third model in there in between. So now that’s the variation you are seeing.

[Unidentified analyst:]

Okay, and I might print up this wrong, but the base looks like it's kind of northern most of those wells and then maybe the ARN is kind of that middle and by the time you get to the card in, you are kind of on your gassier of the third.

[Terry Swift:]

Yes, you're spot on. You can draw the map with us.

[Bob Banks:]

One other point to make is that Eagle Ford itself even though you got these fluid content differences is actually very stable in that area, thickness is pretty nice in there, you don’t see you know too much variation, it's actually one of the better areas to drill in.

[Unidentified analyst:]

Okay, perfect, well that’s all I had, thanks so much guys.

[Operator:]

Your next question is from the line of Biju Perincheril of Jefferies and Company.

[Biju Perincheril:]

Hi, good morning/

[Terry Swift:]

Good morning, Biju.

[Biju Perincheril:]

Couple of questions, in the Eagle Ford with this refined bottle targeting, can you talk about how many wells you have now completed there? I think you mentioned about seven wells at the Analyst Day and can you talk about you know maybe the 30 day or 60 day rates on those wells? How does that compare to the initial well?

[Terry Swift:]

Well, to be honest Biju, we don’t have a lot of that data compiled. We have not completed that many using this targeted methodology. I think you know the best example we can give you really is this PC 278, I think the Hayes Wells, we use that targeting methodology, we were very happy with that performance, but we have not compiled for release the 30-day averages yet. And I think it would be a little bit premature for me to start trying to compare the new targeting methodology against the older targeting methodology from a 30-day versus IP and all of that. That data will come, no doubt, but I think we are still a little early.

[Biju Perincheril:]

Okay, all right, and then looking at then the guidance for the back half of the year, are you -- can you talk about your projections for both the contribution from Austin chalk and Lake Washington for the remainder of the year baked into the guidance.

[Bob Banks:]

In terms of production…

[Biju Perincheril:]

Yes.

[Bob Banks:]

I don’t have the right numbers right here in front of me, we don’t guide quarter to quarter individual feels. We've tried to break it down to the actual commodity strains liquids versus gas in particular. I think it should be noted, though, we were proposing to move the capital South Texas in terms of an allocation where we are getting these excellent results. That is in the guidance. We've reaffirmed -- basically reaffirmed the guidance even though we have some differences, small differences in the Louisiana area, but that’s not where the growth was really expected this year. So we are really reaffirming the plan that we had out there on Investor Day. Lake Washington has some natural declines, we are clearly focused with the new wells we've drilled this quarter and the activity we have in their with the recompletions. We will continue to do those all year long and be actively seeking to mitigate natural declines out there and of course we spoke about the Burr Ferry area it's just appropriate positive, but not a lot of capital allocated there in the second half at all with the original plan, so we're pretty much on course with what we presented at Investor Day.

[Terry Swift:]

Yes, I think you can just kind of look at the activity and really the only activity that’s taking place there in Burr Ferry, is the last remaining Austin Chalk well, is currently being drilled. It won’t be completed until probably more towards the tail end of the second quarter, but there would be some risk production in the second half from that and then in Lake Washington, I believe there is one more well to be drilled there and other than that it's natural declines and of course Lake Washington we continue to do a lot of field optimization work and recompletions and things like that to try to mitigate those declines.

[Biju Perincheril:]

Got it. And then on the CapEx, can you remind me again, how much of this year's budget is South Texas? Percentage wise?

[Terry Swift:]

It is about 80%, probably 75% to 80%.

[Alton Heckaman:]

It was about 70%, to 70% to 80%.

[Biju Perincheril:]

Got it. And that doesn’t -- you are not assuming a JV in that current budget, right?

[Bob Banks:]

No we are not.

[Biju Perincheril:]

Current budget right.

[Biju Perincheril:]

Got it. Thank you.

[Terry Swift:]

Thank you, Biju.

[Operator:]

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

[Curtis Trimble:]

Thank you, just a quick year follow-up on Biju's, on Austin chalk the one that’s rolling now have they changed the drilling program there or with the expected deferral on the completion of that one as they investigate changes to the completion program?

[Terry Swift:]

No, this was a well we worked through both technical teams. We had already identified some of these issues before. So this well is supposed to be designed to get this well Packer in the whole to make some of the operational changes into their operations to give us a higher probability of success that that will occur. So there won’t be any delay to these operations.

[Curtis Trimble:]

Okay, good deal. Just looking at the Eagle Ford obviously the driver going forward, can you give me an idea is 9 to 10 completions ratable for the next few quarters? If not can you give me the number maybe that you are planning on carrying an inventory, either way to completion or pipeline hookups, etcetera as you work your way to the balance of the year in the context of that reduced CapEx in the second half of the year?

[Terry Swift:]

Well, there is a number, I think it's important to know, we've also got a lot of I would say infrastructure and optimization projects that are underway that really contribute to the production that we've got. For example Bob has mentioned we've got compression project that are underway over in the LaSalle County area. We've also got some infrastructure projects relative to saltwater disposal projects. We are working on to lower operating cost in those areas. So you know as we're putting the wells into the system, we are also seeking to optimize an early on and not wait but in terms of wells going forward for the rest of the year, Bob, you want to answer the question?

[Bob Banks:]

In terms of production I think one of the key projects of these several compression projects, that are ongoing, and a couple of areas.

[Curtis Trimble:]

Can you give me an idea of kind of analog results of the compression projects and how that’s augmented out of EURs expectations just kind of distil it down if you will the quantitative figure?

[Terry Swift:]

Okay. Let me go back to your earlier question, we think it's about it is probably seven to nine a quarter. At any given time we probably have two or three in inventory is kind of the way it looks now. In terms of compression, you know, we are basically putting in the compression to maintain our profiles. I think it's still a little early. We've just put some compression projects in we have three or four key compression projects going on in the second quarter. We are anxious to see how that performance looks from that compression. We do have some expectation from it. But I think it would be again a little early for me to try to quantify all that for you. In advance of getting this next slew of compression projects commissioned.

[Curtis Trimble:]

Understand, understand. Last question I had was looking at the Eagle Ford JV and the conversations you've had thus far, any mention of the Buda and the Buda potential along the lines of the partners and that's sweetening the pot?

[Alton Heckaman:]

Well, that’s a good observation, you know, in this area, you’ve got the Buda an even deeper, you've got the Pearsall. As it relates to the Pearsall in the area that we have, we do think it would be principally gas although it's not a near-term test near us, so there's not near the interest in that, but the Buda, definitely tends to be a more fractured zone that there are some folks that are interested in it, there may be some contribution that comes in from time to time from the Eagle Ford or vice versa in drilling, so that’s got to be worked out before anyone would go specifically for the Buda in our area, get such great results from the Eagle Ford, we wouldn’t be changing our program to do that. But we are watching that.

[Curtis Trimble:]

Good deal, I appreciate it.

[Alton Heckaman:]

Thanks Curtis.

[Operator:]

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

[Neal Dingmann:]

A question, just I think if I didn’t miss this, just on that first or I guess not even just the first, the cost related to the upper Wilcox test, I guess why I asked I just noticed like I guess it was on that James Dobie that didn’t you all have to side track that one and then I am wondering on a second one, if I am reading this right, on the LLE, that it looks like you had to side track that, so I just want to kind of cost you know when you are looking at these wells and if you in fact had to side track that of the ran the cost up a little bit.

[Terry Swift:]

Yes, in the upper Wilcox well, we did have a sidetracked in the first lateral, very early on in the sidetracked but again this was a well that had a pilot hole, and did have that sidetrack. When we went back and used rotary steerable as opposed to the mud motors, that really helped a lot. So yes that’s going to run up this evaluation a little bit. We think we have that figured out. And then in the -- in Lake Washington, as we go down the salt dome, it's not very uncommon that we don’t end up sidetracking from interval to interval, because we have a number of pay sands stacked up. The salt sediment interface is not -- it's not exact science and can’t be resolved within the resolution of the 3-D seismic. So it's not uncommon to see us historically sidetrack wells in Lake Washington.

[Bob Banks:]

Yes, you know drilling particular in the South Louisiana sidetracks are just really hard of South Louisiana, on the one hand, I might say I wish I didn’t have to sidetracked wells from time to time, but on the other hand some of the best wells I have ever drilled have been sidetracked, so it just kind of comes with the territory.

[Neal Dingmann:]

And Bob or Terry either one, what do those run, on the Wilcox the upper Wilcox wells?

[Bob Banks:]

Total costs.

[Neal Dingmann:]

Total cost.

[Bob Banks:]

Well, again, on development, we think about 11, is a good number, once we target is owned and land that lateral, we think probably about 11, this well was going to be -- is going to be more, I don’t have the total numbers, but it was planned to be more with all the pilot hole and logs and coring that we did and analysis that we've done. So this is our first valuation well just like some of those early Eagle Ford wells in South Texas, you saw post higher numbers for those too. I think it wasn’t uncommon to see us spending those evaluation wells over $10 million. We are now dealing these wells for $7 million. But it's money well spent to get the data you need to avoid spending more money in the future.

[Terry Swift:]

But it's important to know, in terms of project timing, and expectations, the way we've built our plan, we are still on time, we still have all the expectations that we laid out before in terms of results.

[Neal Dingmann:]

Understood, thanks for the clarity and then just one last one, just when you look at the Eagle Ford, I forget, it is most around Webb County now most of that acreage is held or what would you have to drill I forget and how many more when I look at it, I guess it is sort of second question there, how many identified locations there versus you know LaSalle that we're talking about?

[Terry Swift:]

Well, yes, the good news about Webb County, we have held all of that acreage position. And as I think we've talked in our Investor Day in the past, it's very, very high quality rock, we like that area very much from a rock perspective, it's all held by production, we are drilling two down spacing tests this year, to try to answer definitively how many locations, I think right now we have a total of you know location count of around 100 there, but depending on how the down spacing looks in this high quality rock will dictate how many more inventory locations we might have to bring in.

[Bob Banks:]

Yes, that well count is based on 160 acres basically.

[Neal Dingmann:]

Oh, that’s what I was going to ask. So you are still -- I mean there is obviously down spacing opportunities to Bob or Bruce?

[Bob Banks:]

Yes, we are already comfortable with 80s, and we are now getting ready to test down to 60s.

[Neal Dingmann:]

Got it, got it thanks. Thank you all.

[Operator:]

(Operator instructions) Your next question comes from the line of Warner Grantham of Intrepid Capital.

[Warner Grantham:]

Good morning.

[Bob Banks:]

Good morning.

[Terry Swift:]

Good morning.

[Warner Grantham:]

As leverage increases, is there a target level of 2013 or 2014 production you'd like to have hedged?

[Bob Banks:]

Well, that’s certainly part of our strategy is we see the curve improve, we are lowering in particularly on gas more hedging -- our strategy in the past has been purely forward, but we are looking at some caller type transactions now to try to capture some of this upside particularly where we've got strong gas production that we can match to it.

[Warner Grantham:]

But you don't have any explicit targets that you'd like to…

[Terry Swift:]

Well, Yes, particularly when it comes to the pure gas, where we get our over $4, we start getting some really good economics by the time you get to $4.50, the economic start to becoming compelling, and certainly with our historical gas streams, we do want to lock in some of that profitability, you know as a reminder last year, we were sitting you know some $2 handle gas, and this is a marketed improvement we recognize it and we are getting more and serious and aggressive in our hedging strategy/

[Bob Banks:]

And in terms of production, targets, we've generally tried to hedge between 20% and 50% of our production stream. Obviously on the gas side as Terry mentioned, you get some attractive numbers out there, in the strip you might consider a little bit higher percentage of your gas production if felt like that would warrant more predicting cash flow but also enable you to build some additional wells.

[Warner Grantham:]

Al right. And just for what it's worth, as both an equity holder and creditor, given leverage and then oil development ratio and your track record, we appreciate the increase in hedging activity this quarter.

[Bob Banks:]

Great, well we appreciate the comments and the observations.

[Warner Grantham:]

And then on the LOE, your last guidance was given I think towards late February so little more than halfway through the quarter, but there was still pretty big mitts on, if you sum together the new LOE expenses on the transportation processing. I'm just curious what drove that in the back half of the first quarter?

[Alton Heckaman:]

Yes, this is Alton. we had some out of period costs in there or one particular event was the CM 183 in Lake Washington, the crude boats that hit the wellhead, which was previously discussed, that caused the way from an accounting standpoint the cost related to that flow to LOE, so it was little over a $1 million that was charged in the first quarter net of insurance proceeds for that. And then the rest of the stuff was kind of touring up some things, which typically happens from quarter to quarter, on LOE you know there was some cost that came in their above the standard and with respect to severance tax, we had it going the other way some out of period credits. But I would tell you, that all that’s been reflected in the expectation for the second quarter and the guidance for second quarter and full year.

[Bob Banks:]

Yes, one additional comment is particularly in South Texas, saltwater disposal cost has been a problem for us and many operators, we do have a project underway to lower our saltwater disposal costs or more aggressive infrastructure system that disposes about locally as opposed to trucking it away, and that will give us some good relief to our cost structures to go forward.

[Terry Swift:]

And most of that in our guidance you will see it kick in, in the second half of the year because we get those projects online in the second quarter.

[Bob Banks:]

I think the other thing is probably nowhere it is, you will probably notice that we've broken out transportation processing separately before we incorporated that just in LOE, and the reason is, you can see, it's just become a more substantial portion of that, so we got that more definitive disclosure made sense.

[Warner Grantham:]

All right. I want to touch on the transportation processing. I think year-over-year it was up $0.50 per BOE from $1.64 to $2.14. In the press release, you may have touched on this earlier in the call, but the press release said it was primarily due to the one-time adjustment for a prior quarter.

[Bob Banks:]

Correct.

[Warner Grantham:]

Fiscal, the full-year guidance the range is $1.95 to $2.05.

[Bob Banks:]

Yes, we split it out a big portion of that obviously is variable as to revenue, so again, I think as Bruce articulated, we split it out, we are probably being a little conservative there until we kind of get more of a track record on what we see there. So that’s a very good observation. We will get tighter on that as we you know progressed into the future.

[Warner Grantham:]

Okay, and then, Terry, just as Chairman of the Board, given the current enterprise value, you're at 1.4, 1.5, relative to the value of the proved reserves you've already had, have there been any Board considerations of strategic alternatives for the company as a whole?

[Terry Swift:]

Well, we do have a very subsidy strategic plan in place to improve the shareholder value, and we've laid out numerous milestones, we began that on our Investor day and we were well on our course to achieving those milestones. I would say directly to your question, yes, the Board is very much aware of the need to improve shareholder value and we do have those discussions about exactly how we're going to do that.

[Warner Grantham:]

All right. When you talk about your current strategic plan, there's targeted spending in what are currently non-core areas? And with the current valuation, the market is not even giving you credit for the reserves you've already proved. So, I'm just trying to understand why you're spending on trying to find new reserves when you're not getting value for the reserves you currently have proved.

[Bruce Vincent:]

Well, I think we're trying to do both, this is Bruce, obviously the biggest area that we don’t think we are getting appropriate value for is in South Texas the Eagle Ford, particular, and one of the things that we have underway, is desire to accelerate some of that activity, will increase the present value of the asset, but it will also provide a benchmark for valuation that we think will be hard for the market to ignore. That is something we hope to have in place by the end of the third quarter, and that is very much what I would consider strategic alternative when you put it in that sense. But we really have to also be focused on some of these strategic growth areas, and because you always have to be looking into the future, we are not really spending a lot of capital in those areas, but they are all meaningful, Wilcox Wells is a meaningful well, that would open up a lot of opportunity, that to me would be easier for the market to value because in an existing field, where we have vertical wells and so we understand the structure and we understand the Rockwell well. The Niobrara could be a really great play, but again we are not spending too much money there about $10 million, but that evaluation of getting the well drilled in seeing how it test will be important to what we do in the future and we think it adds significant value and then the Lake Washington subsalt, we are really not spending any capital on that, that we are just trying to further that along. But we think finding a partner and laying out a timeline to get that well drilled next year, could be very, very meaningful in terms of valuation in the company.

[Warner Grantham:]

All right. I understand the story behind each of the different levers you're trying to pull, but just as full disclosure as a shareholder, we really think that the best exploration opportunity you have isn't in the ground it's in the Board room or some sort of strategic review for the company of all the existing assets, or management changes or something, just given that the long-term track record of the stock performance and then the current valuation relative to what you’ve already proved. But I appreciate taking the calls or taking the questions and thank you, very much.

[Terry Swift:]

Sure. Thank you.

[Bruce Vincent:]

Well, I want to say, that we appreciate the comments and the candor and of course any critique from shareholders, we are willing to have, so we appreciate your comments.

[Warner Grantham:]

Thanks. Terry, do you have any just with respect -- do you have any comments with respect to the long-term return of the share price?

[Terry Swift:]

Well, obviously I am not satisfied with where the evaluation is and so my comments are all directed by trying to improve shareholder value. And I am behind the plans that we put forward that they got very specific milestones and we need to achieve those milestones and improve the shareholder value. So those are my comments at this time

[Warner Grantham:]

All right. Thanks again.

[Terry Swift:]

Thank you, Warner. Operator And your last question comes from Bill Nasgovitz of Heartland Fund.

[Bill Nasgovitz:]

Good morning. That's Bill Nasgovitz. Appreciate all the information and just as a follow-up to the previous caller, my question had to do with valuation, as well. Why do you think this Company receives no credit for current proven reserves? What do you think are the factors that the institutional, strategic, retail investors is looking at, or worried about with Swift that causes the stock to sell where it is?

[Terry Swift:]

Well, I mean I wish I knew the exact answer to that question, I guess when I think about that myself, I think a lot of it and when I obviously talk to people and get feedback back, a lot of it comes of our concern over execution. If you look through 2011 and 2012, there were a number of quarters that we did not come in at our guidance. And so if you look at that just in the rear-view mirror, and you don’t look at why, you put that all in execution. The fact of the matter is, a number of those times we didn’t hit guidance, were really related to third-party issues, whether it was downstream marketing constraints, or pipeline, or rupture that shut in a significant field for some time, to hurricanes in 2011, hurricanes in 2012. There was also areas where we didn’t perform the way we should. So I don’t want to put it all on third-party stuff, but the fact is that all goods baked in its all of us, and in the end, we have to perform. It doesn’t really matter what third parties do, we have to put the numbers out there on the Board and I think what we are trying to do is layout and not just production guidance this year, but a number of other strategic milestones that we are doing, so that people can monitor our progress in more detail this year and see us making that progress and start developing a higher level of confidence in what we say is going to happen, happens. And so that’s kind of what we view the number one issue is, and I would certainly appreciate your thoughts on it, because what we are trying to do is lay out a plan that we can accomplish that the market can develop confidence in that ultimately improves our capital efficiency and improves the value of the firm.

[Bill Nasgovitz:]

Well for sure, that's a big part of it. I guess looking from afar here, when at least personally, when I see a company outspending its cash flow and levering up, especially in low interest rate environments, you know interest rates eventually have to go up, it's just worrisome and I think that has a big affect on your, on our valuation. It's my best guess.

[Terry Swift:]

We agree with that, if you look at the Swift Energy's history, we are not a big high leverage company. That’s not our modus operandi. We generally have historically spent within cash flow. As we move into Eagle Ford, and with the desire to earn the acreage that we felt was of value, that required us to significantly outspend the cash flow and that’s large part of what happened last year in trying to earn the acreage. We pretty much got the acreage earned or going to earn within our plans that we find of value in South Texas, and so that allows us to really pull back that capital spending. Now I would tell you, I had conversations with others, that think we can continue to outspend cash flow that we are not all that leverage compared to some other company but in our mind, we are pretty leveraged and that’s exactly why we put out this other strategic move of looking for someone to partner with us in the Eagle Ford in the oil section of the Eagle Ford, and depending on how it's structured would allow us to essentially accelerate the activity, increase net present value of the asset, bring in additional capital, and also put a benchmark value out there that clearly the markets aren’t reflecting in the stock price.

[Bill Nasgovitz:]

Okay. Thank you.

[Terry Swift:]

Sure. Thank you.

[Operator:]

There are no further questions. I am sorry. We do have another question and it comes from the line of Welles Fitzpatrick - Johnson Rice.

[Welles Fitzpatrick:]

Hey, guys, I know we are a little over so I'll make it really quick. Do I remember correctly, that you guys have previously said that you'd be willing to give up operatorship on that sub-salt Lake Washington prospect if that were one of the – if that were something that a potential partner was looking for?

[Terry Swift:]

I think the goal is to get that well drilled and to do it in such a way that it adds value to slip shareholders and operatorship in and of itself, is certainly something that we are going to be very concerned about, if we get a top tier player in there, that can operate this efficiently, then that would be something that I think would be attractive to the deal. If it's more of a financial backing that comes, and you are likely to have several parties here, not just one, so we have got to be careful about how we trade away operator ship, we are not starting the equation, we are trading it away, but I… [Abrupt end]