Swift Energy's CEO Discusses Q1 2014 Results - Earnings Call Transcript

May. 1.14 | About: Swift Energy (SFY)

Swift Energy Co. (NYSE:SFY)

Q1 2014 Earnings Conference Call

May 1, 2014 10:00 AM ET

Executives

Paul Vincent – Director, Finance and Investor Relations

Terry Swift – Chairman and Chief Executive Officer

Alton Heckaman – EVP and Chief Financial Officer

Bruce Vincent – President

Bob Banks – EVP and Chief Operating Officer

Steve Tomberlin – SVP, Resource Development and Engineering

Jim Mitchell – SVP, Commercial Transactions and Land

Analysts

Neal Dingmann – SunTrust

Leo Mariani – RBC

Welles Fitzpatrick – Johnson Rice

Noel Parks – Ladenburg Thalmann

Michael Hall – Heikkinen Energy

Steven Karpel – Credit Suisse

Keathen Kendall – Raymond James

Bill Nasgovitz – Heartland Fund

Operator

Good morning. My name is Nayan and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Company First Quarter 2014 and Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions).

Thank you. I would now like to turn the conference call over to Paul Vincent, Director of Finance and Investor Relations. Please go ahead, sir.

Paul Vincent

Good morning. I am Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy’s First Quarter 2014 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 before we open the line up for questions.

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 the call today. The first quarter was a very strong quarter operationally. We continue to drill better wells at lower cost. Our South Texas operations are running very smoothly and we believe that this performance is reflective of the continuous improvement effort put forth by our oil and gas professionals. At the same time we see an improving natural gas pricing environment creating more opportunities for us to grow.

We believe that our folks have the passion, commitment and skills to deliver outstanding results. Personally, when you consider our people and the quality of our assets, we believe the equity is undervalued in market. Our commitment to create value for our shareholders has never been stronger and we have taken numerous steps to ensure that our alignment with them is evident.

Before handing the call off to Alton, I will note several first quarter 2014 highlights. Our core South Texas development program continues to perform at exceptional levels. We drilled 11 new Eagle Ford wells in the quarter, 9 of which were drilled virtually trouble-free and at a lower cost per foot.

Our team has worked tirelessly at uncovering ways to efficiently and safely cut our drilling and completion cost. As an example in South Texas we improved our frac plug drill out method resulting in 31% reduction in job times and brought our drilling days down to 17 days in Fasken and PCQ and as well as 14.8 days in our SMR area, setting a new company record for days on a horizontal well.

We also continued the use of cost efficient toe prep methods to eliminate coil tubing intervention. This toe prep method is savings us about $120,000 per well on average. We continue to deploy technological advancements to our assets in South Texas, drilling longer laterals and performing more custom hydraulic frac stimulations which improve the performance and results of our Eagle Ford program.

Specifically, we incorporated the enhanced frac designs and utilized geo frac logging to optimize our completions. Consequently, we observed our highest IP of 23.3 million cubic feet per day with our Fasken BD Eagle Ford 16 H well and saw an average IP of 22.1 mcf per day for the three completed Fasken wells during the quarter.

We also tested three Eagle Ford wells in our McMullen County PCQ acreage at an average IP of 1,212 barrels of oil equivalent per day over 90% liquids. These results coupled with strong operational performance led to first quarter production being approximately 5% above the high end of guidance.

And Lake Washington, we made significant progress in the first quarter to improve our results and stabilize production profile. We performed 35 production optimization projects during the quarter and just recently commenced our planned 2014 recompletion program.

Also, at Lake Washington we will be reprocessing 3D seismic to help us better exploit existing reserves and develop comprehensive field development plans. This 3D work should also help us to progress towards the drilling of deeper LI and CC sand prospects along with high risk high reward Subsalt exploratory well test.

Lastly, we continue to make progress on a joint strategic venture or potential venture with our Fasken acreage as well as a possible sale of some or all of our central Louisiana assets. As we’ve noted before the proceeds from either of these transactions will allow us to increase our level of drilling and completion activity in our core south Texas acreage as well as improve our liquidity.

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

As we have noted in previous calls, we are committed to improving our balance sheet. Our 2014 capital budget of $300 million to $350 million will be flexible and adjusted based on the timing of transactions and marketplace fundamentals. We expect this capital to deliver 11.3 million to 11.8 million barrels of oil equivalent of production.

And now I will ask Alton to summarize our first quarter 2014 financial results.

Alton Heckaman

Okay. Thanks Terry and good morning. First quarter 2014 production of 2.94 million BOE was well above the high end of our guidance as Terry mentioned. Both oil and natural gas volumes were above guidance levels while NGL volumes were near the mid range. As we projected our net gas production ratio has increased in tandem with our focus on our high quality gas prospects.

Our overall financial results for the first quarter of 2014 include oil and gas sales of 149 million before the quarter end mark-to-market of our hedging program, which included a pre-tax 3.4 million non-cash loss related to hedges we have in place that extend beyond 1Q ’14.

Net income came in at 5.4 million or $0.12 per diluted share and cash flow before working capital changes for the quarter was 73.6 million. Our realized price per BOE increased 7% from 4Q ’13 sequentially driven by a 26% increase in the average natural gas price received along with improvements in oil which was up 6% and NGL prices which was up 7%.

As to our controllable cost for the quarter, G&A came in at $3.65 per BOE, oil and gas depletion was $20.95 per unit. Interest expense was $6.27 per BOE. Severance and ad valorem taxes were 6.2% of oil and gas revenues; LOE was $8.58 per unit and transportation was $1.80 per BOE.

All of these costs metrics were either below or at the low end of our 1Q ’14 guidance. Our effective income tax rate was 53.6%, which is obviously above normal due to the tax effect of a shortfall in the first quarter between the tax deduction received with respect to prior restricted stock grants vested in 1Q ’14 versus the actual book expense recorded over the life of those grants.

We anticipate our full year effective tax rate will be back in line with historical level in the 40% range. As previously mentioned, the result was net income for the quarter of 5.4 million or $0.12 per diluted share above the first-call mean estimate. Cash flow before working capital changes for the quarter came in at $73.6 million; EBITDA was $93.2 million and our quarterly CapEx on an accrual basis was just over $99 million.

I am also pleased to report our borrowing base commitment amount of $450 million was reaffirmed yesterday in conjunction with our semi-annual bank group review. As a reminder, that facility matures November 2017.

We continue to expand our hedging program to minimize the price volatility risk, we are strategically using our combination of swaps and collars and have recently added some basis spread coverage which protect against volatility that we see between the prices of our field delivery points in the major terminals.

As always, complete and timely detail of Swift Energy’s price risk management activities can be found on the company’s website. And as we previously mentioned our focus in 2014 is on strengthening our balance sheet and better aligning our capital spending with our expected cash inflows, will obviously enhance our liquidity.

Our priorities continues to be financial discipline first and growth second. As always, we have included additional financial and operational information in our press release, including guidance for the second quarter of 2014.

And with that, I will turn it over to Bruce Vincent.

Bruce Vincent

Thanks, Alton and good morning everyone and thank all of you for listening in. Today, I will discuss the first quarter 2014 activity. That will include the production volumes, recent drilling results, activity in our core operating areas and our plans for the second quarter of 2014. Beginning with production, Swift Energy’s production during the first quarter of 2014 totaled 2.94 million barrels of oil equivalent, are 32,716 BOE per day, this is above the high end our guidance and provides positive momentum for the second quarter operation performance as well as 2014 production levels.

To date in the second quarter, our average daily production has exceeded 34,000 barrels per day and we will be bringing several new wells including three high rate wells in Webb County in the service during the second quarter.

First quarter production was slightly above our first quarter 2013 production of 2.82 million barrels of oil equivalent and was comprised of 32% crude oil, 16% NGLs and 52% natural gas.

First quarter production decreased from the 3.09 million barrels of oil equivalent produced in the fourth quarter of 2013 due to the timing of new production coming on line during the quarter as most of our new well activity didn’t occur until the beginning of March.

As more of our new production comes from multi-well pads in the future, our quarterly production volumes will be affected to a greater degree by the online dates of these multi-well pads. This is much more efficient than drilling one well at a time but does result in period lumpiness in our short term production volume.

Additionally, production will be impacted from shutting uncertain with sometimes be large producing wells as we frac new wells at nearby as well as our ability to access additional (inaudible) transportation capacity at our Fasken field, over and above our contracted firm capacity.

While our first quarter drilling results Swift Energy drilled 11 operated wells during the quarter, all to the Eagle Ford shale and the company’s South Texas core area. Six of these wells were drilled in McMullen County and five wells were drilled in Webb County. We currently have three operated drilling rigs in our South Texas core area, all drilling Eagle Ford shale wells.

In South East Louisiana area, which includes the Lake Washington and Bay de Chene fields, production during the first quarter averaged approximately 4,449 net barrels of oil equivalent per day, down approximately 10% when compared to first quarter of 2013 average net production from the same area and down 9% from the fourth quarter 2013 levels.

Lake Washington averaged approximately 4,250 net barrels of oil equivalent per day, a decrease of 11% when compared to fourth quarter 2013 average daily volumes. We have recently commenced and expect to accelerate re-completion and workover activity at Lake Washington during 2014. We have identified numerous opportunities and expect to conduct at least 20 of these low cost, high return projects this year which will help us mitigate the natural declines.

In our Bay de Chene field, production of 199 net barrels of oil equivalent per day was up 39% when compared to fourth quarter of 2013 production levels due to a well being put back on production as part of our regular field optimization work.

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, first quarter 2014 production of 26,106 net barrels of oil equivalent per day decreased 1% when compared to fourth quarter of 2013 production in the same area and up 12% when compared to the first quarter of 2013 volumes.

As we highlighted in our press release this morning, we completed eight new operated wells in our South Texas area during the quarter. We brought online three new wells from our Fasken area during the quarter all of which have had accumulative production of greater than 900 billion cubic feet of gas during the first six 60 days of production or average in approximately 15 million cubic feet per day per well.

We also brought online five new wells from our oily McMullen County acreage with an average IPe of 1140 barrels per day. We are in the process of completing two Eagle Ford wells in our PCQ area and in Northern McMullen County and three Eagle Ford wells in Fasken.

Earlier this morning, we published specific performance data on all the wells brought online in this area during the quarter in our quarterly press release. And I will refer you to that data with more details on our results. The Central Louisiana core area, which includes our Masters Creek, Burr Ferry and South Bearhead Creek fields contributed 2,067 barrels of oil equivalent per day of production in the first quarter of 2014, a decrease of 8% from the fourth quarter of 2013 production in the same area, primarily due to low activity levels and natural declines.

I am going to turn the call over to Bob Banks now who will cover the results of the quarter.

Bob Banks

Thank you, Bruce. Our objectives in the first quarter and for 2014 revolve around the principal of enhancing our liquidity while building a platform to sustain meaningful production in cash flow growth in the coming years.

While we are attacking these objectives at the corporate level with potential asset sales and joint venture activity, we are also continually improving our operational efficiencies as you have heard today.

As we have previously discussed with you, we are now targeting a very specific zone of the lower Eagle Ford in all of our South Texas wells and targeting this zone we have become very professional in keeping our entire lateral length in this zone by utilizing advanced geosteering techniques.

We are finding that there is a high degree of correlation between completed lateral in the sweet spot zone and great well performance. This approach does require greater drilling and geosteering precision yet we are continually improving our performance on both time and cost metrics.

In both the Fasken and PCQ areas, wells have now been drilled, logged and pre-completed in 17 days as measured from rig release to rig release.

Recently, in our SMR area we were on and off the well location in less than 15 days. Although, these are new records for each area can indicate the tactical drilling limits are lower than we previously believed. The speed that we are drilling these wells at is resulting in drilled pre-complete logging cost below $3 million per well. These improvements are very meaningful to our capital efficiency metrics as we are hitting benchmarks that seemed unreachable not too long ago.

On the completion side, we employed an enhanced frac design on all our first quarter completions, this enhanced frac design includes tidder state spacing while increasing the amount of profit per stage.

Additionally, we run geo-frac logs in advance and completing our wells to ensure we configure the completion so as optimize our stimulated rock volumes. This completion design is now consistently delivering better initial results and as importantly higher sustained flowing pressures which equate to higher deliverability and performance where we have seen the single largest improvement in recent versus prior results is in our Fasken area. When these techniques are applied to arguably the highest quality rock in Eagle Ford shale the impact is tremendous.

Over 60 days for three Fasken wells we delivered in the first quarter, we produced in excess of 900 million cubic feet of gas each with flowing pressures materially higher than wells completed with earlier frac designs.

At a $4.50 gas price environment, these wells will payout in approximately nine months and may yield in excess of 4 billion cubic feet of gas each well in the first 12 months of production. I believe that these are the types of metrics that most operators are looking for initial investments.

We have another set of Fasken wells online during the quarter and had similar expectations for the performance of those wells. We’ll also be drilling several more wells there this year, including an upper Eagle Ford test which has the potential to significantly increase our opportunity set in that area. As I told we are just now beginning to recognize the incredible growth potential of this asset.

With these results, we are currently working towards meaningful increases on available transportation capacity at Fasken. It is not unreasonable to assume that we will need more than double our correct committed level of takeaway capacity to align with our next phase of development.

Moving to our Louisiana assets, we’ve had a very active quarter like Washington on the production optimization front. We performed 35 optimization projects during the quarter and prepared for our approximate 20 well recompletion program which has commenced recently.

We are also continuing extensive sub surface work around the entire south dome by using new seismic processing techniques to tie existing and new 3D data to our well logs and production history we are developing a number of quality drilling opportunities. This is important work and it is a necessity ahead of any new drilling activity we may conduct later this year or early in 2015.

I am very pleased with our start in 2014 and excited about what lies ahead in the remaining quarters. Thank you for your attention this morning and I will hand the call back over to Terry now to ramp it up.

Terry Swift

Thanks Bob, before we open the line for questions I will summarize today’s call. Our core South Texas development program continues to perform an exceptional level. We continue to deploy technological advancements to our assets in South Texas, drilling longer laterals and performing hydraulic fracture stimulations which improve the performance on the results of our Eagle Ford Program.

We continue to defy our internal technical drilling limit recently setting new company records in drilling days and completing costs. As Bob mentioned, we are now achieving drilling cost below $3 million per well, a testament to the hard work and dedication of our asset teams. Our Fasken area continues to identify itself as a premier Eagle Ford asset. We will be testing the upper Eagle Ford in this area later this summer.

Moving forward, we expect to have a much more stable production profile as we expect to experience shallower declines in Lake Washington and more predictable results in South Texas. With that we would like to begin the Question-and-Answer portion of our presentation.

Question-and-Answer Session

Operator

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

Neal Dingmann – SunTrust

Good morning, guys. Just a couple of things here, first, guys, Bruce for you or Terry just your thoughts on the potential transactions on the timing it has been going on for a little while, is there a certain period later this year you would just make a decision, I guess it sounds like your negotiations with the few folks there, is it just a matter of price or is there more things involved and if so is there a certain point where you just decide on a timing-wise decide to go at it on your own or make that call as far as the sale.

Terry Swift

Well, the answer to that is yes and I am glad you bring that forward. We really have been very consistent in our messaging on the transactions; we are in negotiations on the strategic joint venture opportunity in Fasken, we are also in negotiations as our concerns are Claytex asset. We have said that I think earlier in the quarter or first quarter and that by mid-year we expected to be able to bring some closure to these potential transactions and give you an update on that. Bruce, do you want to add a little bit more to that please?

Bruce Vincent

Yes I think, first off they are inter-dependent. I mean one is not dependent upon the other and our focus is to try to be sure to at least get one of these transactions done, we think the one, one of the alleviates our leverage, improves our liquidity allows us to spend a little bit more money to further growth but also at the same point in time end up with less [stat] [ph] at the end of the year and so that's our overall objective. And we are focusing on both of them and I would tell you that as we said they are both in the state of negotiations and they are both moving forward in the state of negotiations and so as long as the transaction is moving forward based on the time-line that the two of you agree on, you are going to continue to work on it. While we’d all love to do things yesterday, generally things take longer than you would like them to take, they are not operating on the same timeline, like I said they are both separate transactions and we are pursuing them both and they won’t necessarily happen at the same time. And so clearly there comes a point in time in the negotiation if something is not moving forward that you do come to closure on it, make a decision to do something else with that. we are not at that point, I think the best color I can give you on that is that both transactions are moving forward, negotiating with the parties and they are moving in a timeline that is consistent with what we have talked about with the people we are negotiating with.

Terry Swift

Yes, and one final comment to that, just to emphasize the guidance we have given is without any specific transaction being concluded.

Bruce Vincent

Yes, which, I think to be clear on that if we don’t do a transaction certainly by mid-year would require that we really curtail the current rate of capital spending but that is consistent with what we have said. That's why we guided to 300 to 350 and we think that's consistent with what our anticipated cash flow would be and if we don’t get anything done that's a where we will pull back to. We have reasonably high confidence level that we can get one of these transactions done and be able to continue at the spending rate that we currently have and which case when we get that done we can provide more updated guidance on what we would do both with the proceeds by paying down debt, how much capital we might increase our capital spending by but also where we would end up at the end of the year because we don’t want to just take all the proceeds and spend them, we really want to reduce our debt outstanding to and have that lower at the end of the year than it was at the beginning of the year.

Neal Dingmann - SunTrust

Great color guys, and then just one follow up if I could on the new - I was looking here at the CapEx obviously going from 99 to 120 to 130 for second quarter and then on a go-forward basis, can you give me an idea, I am trying to figure out just how many well locations or how many wells are you anticipating this year but primarily in the different areas in the South Texas between the Fasken and the AWP, SMR and Artesia if you could give me a little more colors as far as how you see that just from an activity standpoint playing out the reminder of the year.

Terry Swift

Yes, let me start with that, first of all, we are again experiencing reductions in cost due to the efficiencies and as we noted little earlier there is also some lumpiness in drilling three pads at a time and then brining the production on, there is some very well planned shut-ins of offset wells and the like. So as we looked at first quarter, we did have some benefit from lower cost but we also had some lumpiness of some things that move from first quarter into second, so that's really what you are saying in those different numbers, Bob can give you more color on some of the forward program.

Bob Banks

Yes, as far as the split between areas in South Texas, I would say roughly two-thirds up in our North AWP area at about one-third down at Fasken and I would say, it’d be safe to say well count anywhere from 38 to 45, depending on timing.

Terry Swift

This is probably a good point to also mention that we are very-very pleased with the Fasken wells not only the initial completions but the accumulative gas volumes we are getting over the first 60-90 days from these wells and they are really exceptional wells. The pressure that we see after 60-90 days on those wells is still very-very strong. So if you look at what pressure you have after you produce a BCF from this well it’s materially higher than the pressure you would have from some of the earlier older designs at the same point of accumulative production.

That said so when you are having those kind of performance, you have got to get the takeaway capacity to match things, we are in discussions and negotiations on that right now. We have got to match that up to the forward drilling program. So let us assure you that we are working on getting additional takeaway capacity there also.

Neal Dingmann - SunTrust

Great details. Thanks guys.

Operator

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

Leo Mariani – RBC

Hey guys, I was hoping you could talk a little bit more to some of these projection trends that I am just noticing here. I mean looking at the NGL production in the first quarter, it looks like it was down about 22% sequentially from the prior quarter and your guidance is kind of saying, it's down another 10% here in Q2. Can you just give us a sense of what's driving that?

Terry Swift

Well in terms of the actual overall production, we do want to focus on the fact that we are focusing our capital in high margin gas that we have got, in terms of some of the takeaway issues in another areas, processing issues, I’ll let Bob speak to that more specifically. We do have a little bit of what we think as a bump, I think the declines that you are seeing right now are not representative of what we expect the rest of the year given the program we are drilling. That said we are certainly increasing the gas and the oil should be, good bit more robust for the rest of the year.

Bob Banks

Yeah, just some color to that, I mean obviously as I mentioned earlier to Neal about two thirds of our program this year is up in Northern AWP that tends to be more the oil rich area less and - more oil less volume of NGLs and as an example when we were drilling out in La Salle County where there is a higher NGL mix and as I also said we were drilling about a third of our wells out in Fasken that's dry gas, there is no NGLs associated with that area but those are very-very superior economics and so it really has to do with the mix of properties we are drilling.

Leo Mariani - RBC

Okay and I guess obviously you talked about shifting capital towards some oiler properties here. I mean just looking at your guidance for Q2 you guys are expecting it looks like oil production would be down about 11% sequentially from what I can see. So just trying to get a sense, is this more of a second half 2014, when you expect oil to start should increase in the second half is that how we should think about it here?

Terry Swift

I think it’s fair to say that in the second half, we do have more focus on oil than you are seeing in the first half. Again if – what it relates to is the takeaway capacity, we are filling it up in Fasken in the first half of the year and positioning ourselves to be able to bring more gas to the market via additional takeaway capacity. But we are going to slow down some of the Fasken drilling second half of the year making sure we have that takeaway capacity and we will be focusing more on oil. So that’s kind of the short answer to it.

Bruce Vincent

Yes I think under the current guidance of 300 and 350, clearly we are going to shut that Fasken rig down in second half but even under assuming you do a transaction and you are able to expand your capital spin and you are still not going to expand the drilling in Fasken until we have the additional capacity for the transportation of gas out of there.

Leo Mariani - RBC

Alright. So in terms of Fasken, when do you guys think you are going to sort of hit that point where you are kind of outstripping the firm takeaway there and you guys mentioned that there was some uncertainties around the interruptible capacity you might get at Fasken, can you give us a little bit more color there in terms of how that may transpire in the second half?

Bob Banks

Yes, let me give you the numbers again. We have got about 75 million a day, a firm take away capacity there. We have been able to use what I would call interruptible of another 20 million or so that we have actually been able to do that's something we can't count on. It's great when we get it but when we are doing our forecast and must be careful about counting on that. We do believe we could get more of that interruptible across the summer and into the fall. We are working on that. And we are working with our current pipeline providers in the areas, principally where we have the firm takeaway and I do believe that we can get additional, meaningful material firm takeaway maybe as much as twice that much by early next year. That's just my opinion line out there for you but in the interim, you are working you are interruptible along the way.

Leo Mariani - RBC

Okay. I guess can you guys maybe speak to the upper Eagle Ford, I think you guys said you are going to target that in Fasken, what's the thickness of the zone there in Fasken and maybe just little bit more color on what you guys are thinking you are going to see there.

Terry Swift

Yes, I think Bob and Bob might want to add more color but Bob mentioned in his remarks that we were planning in upper Eagle Ford chest this year in Fasken. The next set of wells we’re going to be drilling is obviously a four pack and three will be in those lower Eagle Ford but one of those is going to be in the upper Eagle Ford. We’d like to get a test on that upper Eagle Ford this year so we have our appreciation towards the complete potential that we have there at Fasken.

Bob Banks

On your earlier question it is a, it is a pretty thick interval there. It’s about 150 feet, the proximity is not quite as good as the lower Eagle Ford but it is very brittle. So it’s very fracable and so this would be quite an interesting test for us.

Bruce Vincent

Yes, one other point there. One of our early wells, I think going back to 2012 or somewhere back in there we actually did have a portion of that lateral in the upper Eagle Ford so we do know that this has got gas, we’ve got cores in the area. Additionally that show it has some lower porosities Bob has mentioned but it is thicker than the lower Eagle Ford. And we are going to hear us talking more and more about this. The brittleness of the rock we actually think the upper Eagle Ford could be more brittle than the lower which means that even though we might have less total gas inflation it might be little bit more – more accessible in terms of fracking and recovery, so are going to find out.

Leo Mariani - RBC

Thanks a lot for all the color guys.

Terry Swift

Thanks.

Operator

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

Welles Fitzpatrick – Johnson Rice

Good morning.

Terry Swift

Good morning.

Bruce Vincent

Good morning.

Welles Fitzpatrick – Johnson Rice

Getting that 75 million, it sounds like it might be around mid-year; maybe in the back half hit that 75 million “interruptible” capacity. When you talk about getting something in place by early next year would that include any sort of significant build-out by yourselves or mid-stream company or is it really just kind of walking up to interruptible capacity that already exists?

Bruce Vincent

Yes, let me clarify once more, we have 75 million cubic feet today, a firm capacities right now. We have interruptible that from time to time we think has been, we demonstrated it could be as much as 20 million today we think over the course of the summer we can have more interruptible but we are not backing that into all of our plans because we just need to see how it matures. So the system itself couldn’t get to a 100 million a day could there be some uptake to other system, yes. We are working through those negotiations now. So I might prejudice my competitiveness if I went through all the pieces there is only one way out of that area and dependent upon which direction you go, the timing can be longer. So, we are basically saying that early next year, we think we could have as much as twice the firm capacity that’s kind of a reasonable metric to be looking at right now.

Terry Swift

To give you a little more color when we went in there, it had maybe a million or two the capacity, it’s kind of a long way for many of our and so we had a contract with the midstream player who would lay pipe in there and we contracted for $40 million a day of firm capacity which we got up to. We’ve been able to negotiate this increase from 40 to 75 without having to lay new pipe. They were able to come in and add compression to the system that was in place and get us to that and actually a little bit more on occasion. But in order to get additional capacity, dependent upon who you end up working with, you will need to lay new pipe which I think was part of your question and that’s one the reason it would take a little bit longer as far we are seeing early next year, you’d have to go on it ride away, laid on et cetera but and negotiations regarding that as we speak and that’s really wouldn’t want to add any further color than that.

Bob Banks

I don’t know why it over complicated what obvious we clearly have a great asset, we want to match the takeaway to what this asset can do. This is not a big infrastructure problem. There are big, major pipelines in the general area that we can, we really have to talk about laterals they go to the main pipeline so don’t confuse this with other areas where it might be very difficult to get out, this is not that case.

Bruce Vincent

I have got maybe one further point and colors, as far as swift infrastructure facilities at the Fasken lease we’re pretty much ready to go for the type of capacity commitment we are talking about. So there is no significant build out from our perspective.

Welles Fitzpatrick – Johnson Rice

Okay, perfect and then one other obviously it’s could problem to have but with the continued success in Fasken and then the potential for the upper Eagle Ford and you guys have mentioned the couple other zones, how’s yours I guess hurtle rate would be the term shifted at all for what you would need to enter into a JV with partners there has that moved up with the success you guys have had.

Bob Banks

Well, I would say that we always had high expectations and we might be faulted for that but I think Fasken is playing out very strongly than what we thought we could do. We always risk properties before go into these types of development and hopefully as you move forward you take some of the risk off. I think have due risk, some of the original plans in Fasken as a result of the rates and the drilling success we have had there. So that's the long answer to it, yes I see it as a more valuable property than I did six months ago. No question about it. But we always saw it as a much more valuable property than I think most of the market participants did. So we are validating that. We are not to going to transact with anybody that doesn’t share our views.

Welles Fitzpatrick – Johnson Rice

Okay that's perfect. Thank you so much.

Operator

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

Noel Parks - Ladenburg Thalmann

Good morning.

Terry Swift

Good morning.

Bruce Vincent

Good morning.

Noel Parks - Ladenburg Thalmann

Couple of things, in addition talking about the joint program that you had, I haven’t really noticed until this quarter that, you haven’t done much for a few quarters than the Olomos formation in south Texas, is that just because of the product mix coming out of that and as gas start little bit stronger, do you see it up getting any more Olomos activity later in the year.

Bob Banks

This is Bob, let me take a crack of that. Yes obviously, we are trying to drill our highest return projects with our capital budget, trying to manage our liquidity as we have all talked about today. So we are taking our best projects first. As far as the Olomos goes, yes it does start to compete better as these higher gas prices come into play. And even in that regard, in the Fasken area, although we keep talking about we see lots of opportunity therefore horizontal almost drilling as well. So, I think it’s just a matter of us taking our highest return projects first but there is a lot of value in the Olomos, we are not forgetting about it. It will get drilled as we can allocate capital to it.

Noel Parks - Ladenburg Thalmann

And if we see gas prices persistent in terms of the current range (inaudible) with the next 12 months trip and so forth, could have even larger pads that you would drill and putting in Olomos and would you get any precision (inaudible) think?

Bruce Vincent

Pretty much right now, we are working on three well pads, sometimes four well pads. So we are kind of alternating between that. We have outfitted all of our rooms and so it real becomes an operational efficiency analysis is to, between the walking system, walking the rig what capability the rig has to walk versus how big the pad is, right now today we think our optimal zone is probably in that three to four range but that doesn’t mean that we can’t expand out may to as much as a six well pad but we are not there yet.

Noel Parks - Ladenburg Thalmann

Thanks. That's all I had.

Terry Swift

Thanks, Noel.

Operator

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

Terry Swift

Hey, Michael.

Operator

Michael, your line is open.

Michael Hall - Heikkinen Energy

Can you hear me?

Terry Swift

Yes, we can hear you.

Michael Hall - Heikkinen Energy

Okay, a lot of my has been answered. I guess, couple of questions I had remaining. Just to clarify on the upper Eagle Ford, is that 150 feet of upper Eagle Ford thickness or is that the total Eagle Ford package in Webb?

Bruce Vincent

Michael, that's upper Eagle Ford.

Michael Hall - Heikkinen Energy

Okay, great. Make a more sense and then as it relates to the joint venture in Fasken, how is the upper Eagle Ford is now playing into your thinking and negotiations there, is that top process that would included in the JV is it up for negotiations whether or not the upper Eagle Ford would be included or just what’s that process, how that being evaluated?

Terry Swift

Again, we don’t want to prejudice any negotiations or discussions that were happening. I think it need to, suffice to say that we are looking for a strategic joint venture where we have good or alignment with whoever that joint venture partner would be. I think some of the historical deals you might have seen in the past, really wouldn’t necessarily fit with what we are trying to do. We definitely want alignment with any potential partners we have there.

Michael Hall - Heikkinen Energy

Okay, so I guess then along the other line, cannot eluded to it earlier but just wanted to circle back around, in terms of timing on both these transactions and claytech and in Fasken or broader Eagle Ford, actually haven’t heard anything by maybe year, you haven’t secured anything by midyear, should we assume then you move on and the past thoughts the transaction is kind of just stops or I guess how should we think about that?

Terry Swift

Michael, (inaudible) it’s a little earlier.

Michael Hall - Heikkinen Energy

I guess drop a little, my apologies.

Terry Swift

No I mean, it’s a good question you are asking. I mean the best way that we can put it is, is we are in negotiations on both of these assets with other parties. In the case of Fasken, it would be in the form of a joint venture in the case of the claytech assets we have indicated we would sale either some or all of those assets and those negotiations are progressing. We believe that at least one of assets negations will progress to a positive outcome and will keep new in the market a price to that. We believe that we should have an update by midyear and I think if we make a decision and are intent is to do at least one but we’d like to do them both, okay.

But if we get to the point that one of them say start, I think we would likely communicate that in some way or some appropriate time so that we would take that concerned as to whether is going forward or not because if we didn’t pursue negotiations with either one of these assets we would want to incorporate a development plan of our own regarding that asset, we are not going to just leave it follow. And that’s the best way I can phrase it. I would look at June 30; even if you haven’t heard anything just assume nothing is happening. I would expect opportunities to update the market on to the extent that we can, I mean when you are in negotiations you got some sensitivity there, we don’t think it’s appropriate to negotiate in the public domain. We think it’s important to try to work with the people who are talking with and bring those to a successful conclusion.

Michael Hall - Heikkinen Energy

That’s helpful color. And then in terms of just helping me, think about modeling potential impact of these transactions particularly in JV, would production likely be associated with it, is it too early to say i.e. should I think about some last production as a result of the incoming proceeds or no?

Bruce Vincent

Clearly, we are we are working in whether it’s Fasken or the redeployment in North AWP on oil, we are working very diligently to get really good capital efficiencies on the drilling that we are doing. We are working hard and like Washington to really get the production profile, they are stabilized and even grow it through the 3D enhancements that we are doing. So we are doing the things that I think will give very, very clear line aside into ’15.

2015 is really what this discussion is all about. We’ve give you guidance that I think is very reasonable for this year and very reasonable for what our balance sheet looks like right now. We’ve given you the steps that we’re taking to ensure that we are aligned with our shareholders creating value. I think this discussion is really about ’15 and so when we say we’ll give you can update by midyear, certainly we do expect and hope to have a very meaningful transaction done that will give more clarification on the transaction side but just as importantly to be able to give you 2015 line of sight without giving guidance for ’15. It’s clearly too early to do that but we can give much better line of sight for ’15 about midyear and as to the guidance we’ve given for 2014 both capital and production because we are moving to about the middle of the year. I wouldn’t expect big changes in any of that guidance, so I would expect more marginal types of changes and of course but don’t assume that I exactly what you do with that capital in the case of you get both of those transactions done and it’s difference in one. So patience is important but not withstanding the patience I think we have given good production guidance, good metrics for this year, good capital guidance for this year, I think this is going to be a great year for the company.

Michael Hall - Heikkinen Energy

Okay, that’s helpful color, thank you. And then I guess last one from, (inaudible) on PCQ how much inventory do you have left with those wells have been performing very well, I’m just trying to think how much more that we have.

Bob Banks

Well, PCQ lease itself is the main PCQ as far as types of models, is in that trend along our acreage position, even coming over end are held by production positions, we have kind of in that trend area right there we have about a hundred, about a hundred locations.

Terry Swift

Yes, that would include probably getting over to the (inaudible) Haze.

Bob Banks

That would get into the Haze, that would get into the NBR along that model area.

Michael Hall - Heikkinen Energy

Alright. That's helpful. Thanks guys.

Terry Swift

Thanks, Michael.

Operator

Your next question comes from the line of Steven Karpel with Credit Suisse.

Steven Karpel - Credit Suisse

Good morning, guys.

Terry Swift

Hi, Steven.

Steven Karpel - Credit Suisse

First up, what’s the balance today on the revolver?

Terry Swift

I don’t know what it is today. There is, every month changes to.

Bruce Vincent

Around 300, I believe, this month end, that will be about right.

Terry Swift

300 million.

Steven Karpel - Credit Suisse

The 300 was consistent with the March 31 number as well.

Unidentified Participant

Yes.

Steven Karpel - Credit Suisse

And I guess I just wanted to understand, I know this has been alluded to, is understanding the CapEx budget. So the CapEx budget I guess was a little lower in Q1 and you’ve exceed on the production side. So what conclusions do we draw as we look to the second quarter to what that means for your production and what does that mean in terms of productivity that you’ve been getting on, on your CapEx versus deferred spending?

Alton Heckaman

There was actually some of both. Yes, first quarter production did come in below our guidance and that's a combination of our ability to spend less.

Bruce Vincent

Production was higher.

Alton Heckaman

No, the capital spend, okay, I am sorry, capital spending came in below our guidance and that was a result of spending less on our AFEs. So we spent less capital than we thought we would but also the result of some deferment in the second quarter which is why the ramp up in the second quarter.

Steven Karpel - Credit Suisse

I guess I am trying to understand too is that production growth and what that impact was, as a result because – or should we not think much about the lower CapEx because it wouldn’t have impacted Q1production anyway?

Terry Swift

I think the production has much more to do with the timing of these things as opposed to thinking of a quarter. As we indicated really in the first quarter, the wells we were drilling didn’t really come on till early March. In the second quarter, they are more likely to come on kind of in the middle of the second quarter and it has more to do with that, along with the lumpiness related to these three packs that we’re doing as well as the requirement that you shut in certain big wells, particularly in Fasken. When you shut in, some of those wells are pretty good wells and you shut them to frac others, but then when you get them all back on production, you’ve got a lot of capacity.

Steven Karpel - Credit Suisse

And then lastly just kind of hammering out on the CapEx, you’ve maintained the guidance, how do we think about how much of your guidance is committed at this point because if you look at obviously the run rate doesn’t tell you, tell you much in terms of what’s the guidance, I guess I am trying to think your ability to throttle back.

Terry Swift

We have the ability to pull back with our spending levels and with our spending levels right now if you may have noticed through the rest of the year, you would be far above 300 to 350. And we have got at 300 to 350 and we do have the ability to pull that back. We are maintaining the spending level in the first and the second quarter though on the pace that we hope to be able to maintain throughout the year because we have a confidence level that we're going to get at least one of this transactions done.

Bruce Vincent

Yes and you do need to remember that for example if the AFE well is 8 million or 7.5 million, you come in under that AFE which is we did a good bit of that in the first quarter that you are setting new technical limits but you don't integrate that into your plan immediately. You don't assume that every well going forward is not going to be breaks the curve. So we do contemplate that we can continue this pace but until we have done it over a longer period, we're leaving our AFEs where they are.

Steven Karpel - Credit Suisse

I guess what I am trying to get at it, the last question, I was talking about maybe mid-year or past mid-year you potentially given update in the status of where you want, in terms of the asset sales. By that time you would have spent a pretty significant portion of that 300 to 350, probably, distinctly is it too late to pull back or you are still will be able to pull back upon at that point.

Bruce Vincent

No, our reinforces. We have designed our plan to deliver the production guidance that we have given you and the capital logs we have given you without a transaction. Now we have also designed our plan without baking in a lot of the cost savings that we are seeing on drilling these well. We designed our plans without baking in, the better gas market that we're seeing right now. So we're very confident and in the guidance we have given you but we're still very focused on getting the right transactions done for the company.

Steven Karpel - Credit Suisse

Perfect, thank you gentlemen.

Terry Swift

And one more important clarification. The balance at the end of April when our bank line was 318 million. So you get some into a month swings there.

Operator

Your next question comes from the line of Keathen Kendall with Raymond James.

Keathen Kendall - Raymond James

Hey guys, good morning. , Claytex package was split into multiple parts. Can you give us a sense of what that might look like, minimal interest and everything else? Would you guys keep an override or maybe consider a JV versus sale at some point?

Alton Heckaman

We are, we hope to sale all of essentially Louisiana asset as a whole but they do consist of I guess what I would like into three distinct pieces. South Bearhead Creek which is a Wilcox play which has both producing properties as well as upper and lower Wilcox development, then Burkferry field which is principally Austin Chalk development. It both has some crude producing development as well as some development opportunities to it. And then there is the mineral interest, the mineral interest will have some crude production on it which is in the Burkferry field as well as substantial amount of additional acreage that it is undeveloped. We anticipate, trying to sell that as a package. But clearly if you don't sale that as a package all of those parts have value on their own and that would give us the ability to do that. I think beyond that what we have not done is provide any specific valuation metrics related to either the whole or parts of those packages and obviously we are in negotiations with people regarding those assets we don't want to do that.

Keathen Kendall - Raymond James

Okay, that's fair, that's helpful and I apologize if I've missed it but could you guys give a little bit more color on the 35 production optimization projects done like Washington and how many more are on the plan for the rest of the year?

Terry Swift

Well, while Bob is sorting you know the typical optimization program is going to be cutting paraffin out there, lopping lines, optimization the compression. There is a lot of gas lift that goes on in the field across the field from three different platforms, giving the water oil cuts from one area to the other, being able to dispose off more water because as the field continues to produce, you can find well that is 5% to 10% oil but you've got to be able to have a little water so you are constantly trying to optimize both water lift movement and disposal. Those are the general types of projects when we referred to enhancements.

Bob Banks

Yes and let me just say, this is Bob. I mean, if you go back through the history we have plenty of these every quarter at Lake Washington. We have many, many wellbores there, many opportunities to do optimization projects to build a little on what Terry said you know these are typically sliding sleeve type operations when we move from one zone to the next. Sometimes there are gas lift projects where we change our gas lifting operation to get more efficiency on lifting our liquids out of these wellbores. Sometimes we're doing slobbing operation on our wells. We are doing hot oiling on our wells in order to align. We're doing chemical treatment projects. So there is just always every quarter (inaudible) these things we do to manage all of those assets, all of that -- to all of those reservoirs that were involved with, at Lake Washington.

Terry Swift

It’s a bigger set of projects in both the higher level of capital spending and the ones that have a greater impact on mitigating production declines really is the recompletion effort. We’ve identified 20 that are in our budget and that just started. And that’s probably the important set of projects that need to get implemented in order to mitigate the declines in Lake Washington.

Bob Banks

Right and that generally involves getting more serious equipment or rig out to the field whereas lot of the other things we just discussed don't require that kind of equipment commitment.

Operator

Your next question comes from the line of Bill Nasgovitz with Heartland Fund.

Bill Nasgovitz - Heartland Fund

Good morning guys. Thanks for the update. So it’s great that (inaudible) the trend is your friend is coming down and when you expect work I know, I have listened to your guidance and all but which quarter are we going to the see CapEx less than our cash flow.

Bob Banks

I think in terms of the current plan without the transaction you will see that in the third and fourth quarter.

Bill Nasgovitz - Heartland Fund

In the third quarter?

Bob Banks

And that's kind of how we guided things.

Bill Nasgovitz - Heartland Fund

Well that's terrific because the shareholders really need some relief here. In the stack often another 10 percent today and again I but this is been talked about it through the investors want independent oil and gas companies to live within their cash flows and were getting crucified for all these year outspending our cash flows. So I look to forward to the third quarter. I can’t wait.

Terry Swift

I can’t wait either and thank you for your comments and we are aligning ourselves on the cash flow and we are paying close attention to the balance sheet. I appreciate that.

Bill Nasgovitz - Heartland Fund

That's good to hear. So just theoretically assuming we sale, like something in Louisiana for just a $20 million much of that do you expect will be used to pay down debt, what percent?

Bruce Vincent

Any transaction we do initially all of it of course go against the line of credit and pay down debt. I think the question is how much of that capital might you deploy additionally in the year and we work through those numbers, we would not make any material changes in my judgment to the plan except to ensure that we get better line for ’15 and how we will particularly develop the Fasken assets and the oil in the AWP area where we are getting exceptional result. So I think the real difference is whether you keep one additional rig running or whether you don’t and that particular capital wouldn’t be a whole lot capital for the rest of the year, it wouldn’t deliver a whole lot of new production for the rest of the year and in fact it all that set itself up for next year, the more important thing would be whatever you sold the amount of production you took out of the second half of the year so to speak or wherever that transaction might be and how you plot those proceeds going forward I expect the majority of them would go by around that.

Bill Nasgovitz - Heartland Fund

Okay, that’ll be great too. Thank you.

Bruce Vincent

Thank you.

Bob Banks

Thank you.

Terry Swift

Okay, we thank you so much for joining us on the call today and look forward to reporting back in the next quarter.

Operator

Ladies and gentlemen, thank you for joining the Swift Energy first quarter 2014 earnings conference call. You may now disconnect.

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