SilverBow Resources Inc (SBOW) 2014 Q1 法說會逐字稿

Good morning, my name is Nan 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 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)

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

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy's 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 first quarter; then Bruce Vincent, President, and Bob Banks, Vice President and Chief Operating Officer, will provide an operational update before we open up the line 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 involves 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 can differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Thanks, Paul, and thank you to everyone for joining the call today. The first quarter was a strong quarter, operationally. We continue to drill better wells at lower costs. 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 seen 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 the 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'll 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, nine 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 a 31% in reduction in job times and brought our drilling days down to 17 days at Fasken and PCQ, and as low as 14.8 days in our SMR area, setting a new Company record for days on a horizontal well.

We also continue the use cost-efficient tow prep methods to eliminate coil tubing intervention. This tow prep method is saving 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 16H 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.

In Lake Washington, we made significant progress in the first quarter to improve our results and stabilize the production profile. We performed 35 production optimization projects during the quarter and just recently commenced our planned 2014 re-completion 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 [sam] prospects, along with high risk, high reward sub-salt exploratory well tests.

Lastly, we continue to make progress on a joint strategic venture, or potential venture, with our Fasken acreage, as well as a possible cell of some of 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'll conclude my opening remarks with the following strategic remarks. I've highlighted the 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've made with horizontal drilling and multi-stage fracture stimulation and optimization have led to lower costs 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 to 11.8 million barrels of oil equivalent of production. And now I'll ask Alton to summarize our first quarter 2014 financial results.

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 were $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 2014. 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 2013 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 those cost metrics were either below or at the low end of our 1Q 2014 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 restrictive stock grants invested in 1Q 2014, 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 levels 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 $76.3 million. EBITDA was $93.2 million, and our quarterly CapEx on an accrual basis was just over $99 million.

I'm 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 of 2017.

We continue to expand our hedging program to minimize the price volatility risk. We're strategically using a combination of swaps and collars, and have recently added some basis spread coverage, which protects 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 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. We'll obviously enhance our liquidity. Our priority continues to be financial discipline first and growth second.

As always, we've included additional financial and operational information in our press release, including guidance for the second quarter of 2014. And with that I'll turn it over to Bruce Vincent.

Thanks, Alton, and good morning, everyone. Thanks for listening in. Today, I will discuss 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 totalled 2.94 million barrels of oil equivalent, or 32,716 BOE per day. This is above the high end of 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 into service during the second quarter.

First quarter production was slightly above our first quarter of 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 on line base of these multi-well pads. This is much more efficient than drilling one well at a time, but does result in periodic lumpiness in our short-term production volumes. Additionally, production will be impacted from [shedding] uncertain, what can sometimes can be large producing wells, as we frac new wells that are nearby, as well as our ability to access additional interruptible transportation capacity at our Fasken field, over and above our contracted firm capacity.

For our first quarter drilling results, Swift Energy drilled 11 operated wells during the quarter, all to the Eagle Ford shale in 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 the southeast Louisiana core area, which includes the Lake Washington and the 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 2013 average net production from the same area, and down 9% from the fourth quarter of 2013 levels. Lake Washington averaged approximately 4,250 of net barrels of oil per day, a decrease of 11% when compared to fourth quarter 2013 average daily volumes.

We 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 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 Olmos fields, and AWP Artesia wells and Fasken Eagle Ford fields, first quarter of 2014 production of 26,106 net barrels of oil equivalent per day decreased 1% when compared to fourth quarter 2013 production in the same area, and up 12% when compared to the first quarter of 2013 volumes.

As we highlighted in our press are release this morning, we completed eight new operating wells in our South Texas area during the quarter. We brought on line three new wells from our Fasken area during the quarter, all of which have had a cumulative production of greater than 900 million cubic feet of gas during the first 60 days of production, or averaging approximately 15 million cubic feet per day, per well.

We also brought on line five new wells from our oily McMullen County acreage, with an average IP of 1,140 barrels per day. We're 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 on line in this area during the quarter in our quarterly press release. I'll 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 2013 production in the same area, primarily due to low activity levels and natural declines. I'm going to turn the call over to Bob Banks now, who will cover the results of the quarter.

Thank you, Bruce. Our objectives in the first quarter and for 2014 revolve around the principle of enhancing our liquidity while building a platform to sustain meaningful production and 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've heard today.

As we've previously discussed with you, we are now targeting a very specific zone of the lower Eagle Ford in all of our South Texas wells. In targeting this zone, we have become very proficient in keeping our entire lateral length in this zone by utilizing advanced geo-steering techniques. We are finding that there's a high degree of correlation between completed lateral in the sweet spot zone and great well performance.

This approach does require greater drilling and geo-steering precision, yet, we're 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 well location in less than 15 days. All of these are new records for each area, and indicate the technical drilling limits are lower than we previously believed.

The speed that we are drilling these wells at is resulting in drill pre-complete and logging costs below $3 million per well. These improvements are very meaningful to our capital efficiency metrics, as we're hitting benchmarks that seemed unreachable not too long ago.

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

Additionally, we run geo-frac logs in advance of completing our wells to ensure we configure the completion, so as to 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've seen the single largest improvement in recent versus prior results is in our Fasken area. When these techniques are applied to, arguably, the highly quality rock in the Eagle Ford shale, the impact is tremendous. Over 60 days, the three Fasken wells we delivered in the first quarter produced in excess of 900 million cubic feet of gas each, with flowing pressures materially higher than wells completed with earlier frac designs.

In a $4.50 gas price environment, these wells will pay out in approximately 9 months, and may yield an excess of 4 billion cubic feet of gas in each well in the first 12 months of production. I believe that these are the types of metrics that most operators are looking for in their shale investment.

We'll have another set of Fasken wells on line during the quarter and have similar expectations for the performance of those wells. We will also be drilling several more wells there this year, including an upper Eagle Ford test that has the potential to significantly increase our opportunity [set] in that area.

All 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 of available transportation capacity at Fasken. It is not unreasonable to assume that we will need to more than double our current committed level of takeaway capacity to align with our next phase of development.

Moving to our Louisiana assets, we have had a very active quarter in Lake Washington on the production optimization front. We performed 35 optimization projects during the quarter and prepared for our approximate 20 well re-completion program which has commenced recently.

We are also continuing extensive sub-surface work around the entire salt 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 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'll hand the call back over to Terry now to wrap it up.

Thanks, Bob. Before we open the line for questions, I'll summarize today's call. Our core South Texas development program continues to perform at exceptional levels. We continue to deploy technological advancements to our assets in South Texas, drilling longer laterals and performing hydraulic fractures stimulations which improve the performance and the results of our Eagle Ford program.

We continue to defy our internal technical drilling limits, recently setting new Company records in drilling days and completion costs. As Bob mentioned, we are now achieving drilling costs 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'd like to begin the question and answer portion of our presentation.

Thank you.

(Operator Instructions)

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

Good morning, guys. Say, just a couple of things here. First, guys, Bruce for you or Terry, just your thoughts on the potential transactions -- on the timing. This has been going on for a little while now. Is there a certain period later this year you would just make a decision?

I guess it sounds like your negotiations with a few folks there. Is it just a matter of price or is there more things involved? And if so, is there a certain point you would just decide -- on a timing wise -- decide to go at it on your own? Or make that call as far as the sale?

The answer to that is yes. And I'm glad you bring that forward. We really have been very consistent in our messaging on the transactions. We are in negotiations on the -- a strategic joint venture opportunity in Fasken. We are also in negotiations as concerns our Claytex asset.

We said that, I think earlier in the quarter -- the 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, you want to add more, please?

Yes. First off, they're interdependent. One is not dependent on the other. And our focus is to try to be sure to get one of these transactions done. We think one of them alleviates and improves our -- alleviates leverage, improves our liquidity, allows us to spend a little bit more money to further grow, but also at the same point in time end up with less debt at the end of the year. So that's our overall objective.

And we're focusing on both of them. And I'm going to tell you, as we said, they're both in the state of negotiations. And they are both moving forward in the state of negotiations. And so as long as a transaction is moving forward, based on a timeline the two of you agree on, you are going to continue to work on it.

We'd all love to do things yesterday. Generally things take longer than you'd like them to take. They're not operating on the same timeline. Like I said, they're both separate transactions and we're pursuing them both.

And they won't necessarily happen at the same time. And so clearly, there comes a point in time in a negotiation that if something is not moving forward, that you do come to closure on it and make a decision to do something else with that. We're not at that point. I think the best color I can give you on that, is that both transactions are moving forward, negotiating with parties and they're moving in a timeline that is consistent with what we've talked about with the people we're negotiating with.

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

Which I think to be clear on that, if we don't do a transaction certainly by mid-year it would require that we really curtail the current rate of capital spending. But that is consistent with what we've said. That's why we've got it a $300 million to $350 million. We think that's consistent with what our anticipated cash flow would be. And if we don't get anything done, that's what we would pull back to.

We have a reasonably high confidence level that we're going to get one of these transactions done and be able continue at a spending rate that we currently have. In 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 too and have that lower at the end of the year than it was at the beginning of the year.

Okay. And then -- Great color, guys. Just one follow up, if I could. On the new -- I was looking at the CapEx, obviously going from $99 million to the $120 million to $130 million for second quarter and then on a go-forward basis.

Can you give me an idea -- I'm trying to figure out just how many well locations -- or how many wells you are anticipating this year? Primarily in the different areas in South Texas between the Fasken and the AWP, the SMR and the Artesia? If you could give us - give me a little more color as far as how you see that just from an activity standpoint playing out the remainder of the year?

Let me start with that. First of all, we are again experiencing reductions in costs due to the efficiencies. And as we noted a little earlier, there is also some lumpiness in drilling three pads at a time and then bringing production on through some very well-planned shut-ends of offset wells and the likes.

As we looked at first quarter, we did have some benefit from lower costs, but we also had some lumpiness from things that moved from first quarter into second. That's really what you're seeing in those different numbers. Bob can give you more color on some of the forward program.

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

Yes. This is probably a good time to also mention that we're very, very pleased with the Fasken wells. Not only the initial completions, but also the cumulative gas volumes we're getting over the first 60, 90 days from these wells. That they are really exceptional wells.

The pressure that we see after 60, 90 days on this well is still very, very strong. If you look at what pressure you have after you produced a BCF from this well, it's materially higher than the pressure you'd have from some of the earlier older designs at the same point of cumulative production.

That said, when you're having this kind of performance, you've got to get the take away capacity to match things. We are in discussions and negotiations on that right now. We got to match that up to the forward drilling program. Let us assure you that we're working on getting additional take away capacity there also.

Great details. Thanks, guys.

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

Hi, guys. I was hoping you could talk a little bit more to some of these production trends that I'm 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 2Q. Can you give us a sense of what's driving that?

Well, in terms of the actual overall production, we do want to focus on the fact that we're focusing our capital on the high margin gas that we've got.

In terms of some of the take away issues and other areas -- processing issues, I'll let Bob speak to that more specifically. We do have a little bit of what we think is a bump. I think the declines you're seeing right now are not representative of what we expect the rest of the year, given the program we're drilling. That said, we're certainly increasing the gas and the oil should be a good bit more robust for the rest of the year. Bob?

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 in -- more oil, less volume of NGLs. As an example, when we were drilling in the LaSalle County where there's a higher NGL mix.

As I also said, we're drilling about one-third of our wells out in Fasken. That's dry gas. There's no NGLs associated with that area, but those are very superior economics. And so it really has to do with the mix of properties we're drilling.

Okay. I guess, obviously, you talked about shifting capital towards more oilier properties here. Just looking at you guidance for 2Q, you guys are expecting -- it looks like oil production to be down about 11% sequentially, from what I can see.

Trying to get a sense -- is this more of a second half 2014, when you expect oil to start to increase in the second half? Is that how we should think about it here?

I think it's fair to say that in the second half we do have more focus on oil than you're seeing in the first half. Again, Leo, what it relates to is the take away capacity. We're filling it up at Fasken in the first half of the year and positioning ourselves to be able to bring more gas to the market via additional take away capacity.

But we're going to slow down some of the Fasken drilling in the second half of the year, making sure we have that take away capacity and we'll be focusing more on oil. That's kind of the short answer to it.

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

All right. So just in terms of Fasken, when do you guys think you're going to sort of hit that point where you're kind of out-stripping the firm take away there? You guys mentioned that there was some uncertainty 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?

Yes. Let me give you the numbers again. We've got about 75 million a day of firm take away capacity there. We have been able to use what I would call interruptible of another 20 million or so that we've actually been able to do. That's something we can't count on. It's great when we get it. But when we're doing our forecasting we have to be careful about counting on that.

We do believe we could get more of that interruptible across the summer and into the fall. We're working on that. And we're working with our current pipeline providers in the area. Principally where we have the firm take away. And I do believe that we can get additional meaningful material firm take away, maybe as much as twice that much, by early next year.

That's just my opinion laying out there for you. But in the interim you're working your interruptible along the way.

Okay. I guess -- can you guys maybe speak to the upper Eagle Ford. I think you guys said you're going to target that in Fasken. What's the thickness of the zone in Fasken? And maybe just a little more color on what you guys are expecting to see there?

I think Bob -- Bob may want to add a little more color. But Bob mentioned in his remarks that we were planning an upper Eagle Ford test this year in Fasken. The next set of wells that we're going to be drilling is actually a four pack and three will be in the lower Eagle Ford, but one of those is going to be the upper Eagle Ford. We'd like to get a test on that upper Eagle Ford this year so we have an appreciation for the complete potential that we have there at Fasken.

Yes, Leo, just on your earlier question, it is a -- it is a pretty thick interval there. It's about 150 feet. The porosity not quite as good as the lower Eagle Ford, but it is very brittle. It is very frackable. And so this will be quite an interesting test for us.

Yes. One other point there, one of our earlier -- 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 it's got gas, we've got cores in the area, additionally, that show it has somewhat lower porosity, as Bob's mentioned, but it is thicker than the lower Eagle Ford.

And you're 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 it might have less total gas in place it might be a little bit more --

Better recovery.

More accessible in terms of fracking and recovery. So we're going to find out.

Thanks a lot for all the color, guys.

Thanks.

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

Good morning.

Good morning.

Good morning.

Getting that 75 -- it sounds like it might be around mid-year, maybe in the back half that you hit that 75 million, quote unquote -- I know you have the interruptible -- quote unquote, capacity. When you talk about getting something -- getting something in place by early next year would that -- would that include any sort of significant build out by -- by yourselves or a midstream company or is that really just kind of locking up the interruptible capacity that already exists?

Yes. Let me -- let me clarify once more. We have 75 million cubic feet a day of firm capacity right now. We have interruptible, that from time to time we think has been -- we've demonstrated it can be as much as 20 million a day. We think over the course of the summer we can have more interruptible.

But we're not baking that into all of our plans because we just need to see how it matures. So the system itself -- could it get to 100 million a day? Could there be off takes to other systems? Yes. We're working through those negotiations now.

My prejudice, my competitiveness, if I went through all the pieces -- there's more than one way out of that area. Dependent on which direction you go -- the timing can be longer. So we're 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.

Yes, to give you a little more color, when we went in there, it had maybe a million or two of capacity. It was kind of a long way from anywhere. So we had to contract with a midstream player who would lay pipe in there. 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 maybe a little bit more on occasion.

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. That's one of the reasons it would take a little bit longer. That's why we're saying early next year.

You would to go and get right of ways, lay the line and et cetera. And we're in negotiations regarding that as speak. That's really -- we wouldn't want to add any further color than that.

I don't want to over complicate it. While this -- we clearly have a great asset. We want to match the take away 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're talking about laterals that go to the main pipeline. Don't confuse it with other areas where it might be very difficult to get out. This is not that case.

I've got one maybe further point of color. As far as Swift infrastructure facilities at the Fasken lease, we are pretty much ready to go for the type of capacity commitment we're talking about. So there's no significant build out from our perspective.

Okay. Perfect. And then one other. Obviously, it's a good problem to have, but with the continued success in Fasken and then the potential for the upper Eagle Ford -- and I know you guys mentioned a couple other zones. Has your, I guess hurdle rate would be the term -- shifted at all for what you would need to enter into a JV with a partner there? Has that moved up with the success you guys have had?

I would say that we've always had high expectations. We might be faulted for that. I think Fasken is playing out very strongly to what we thought we could do. We always risk properties before we go into these types of developments and hopefully as you move forward you can take some of the risk off.

I think we have de-risked some original plans in Fasken as a result of the rates and the drilling success we've had there. That's the long answer to yes, I see it as more valuable property than I did 6 months ago. No question about it. But we always saw it as much more of a valuable property than I think most of the market participants did. We're validating that. We're not going to transact with anybody that doesn't share our views.

Okay. That's perfect. Thank you so much.

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

Good morning.

Good morning.

Good morning.

A couple things. I -- in addition talking about the -- the drilling, I hadn't really noticed until this quarter that you haven't done much for a few quarters in the Olmos formation in South Texas. Is that just because of the politics coming out of that? And as gas has gotten a little bit stronger, do you see yourself doing anymore Olmos activity later in the year?

Well -- this is Bob. Let me take a crack at that. Yes, obviously we're trying to drill our highest return projects with our capital budget. Trying to manage our liquidities -- we've all talked about today. So we're taking our best projects first.

As far as the Olmos 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 that we keep talking about, we see lots of opportunity there for horizontal Olmos drilling, as well. I think it's just a matter of us taking our highest return projects first.

But there is a lot of value in the Olmos. We're not forgetting about it. It will get drilled as we can allocate capital to it.

And if we see gas prices persist in sort of the current range, or in line with the next 12 months (inaudible) and so forth, would -- could you have an even larger pads that you would drill, including the Olmos? And would you get any efficiency improvements from those do you think?

Well, we -- pretty much right now, we're working on three well pads, sometimes four well pads. We're kind of alternating between that. We have outfitted all of our rigs with walking systems. And so it really 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 maybe to as much as a six well pad. But we're not there yet.

Thanks. That's all I had.

Thank, Noel.

Thanks.

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

Hey, Michael.

Michael, your line is open.

Operator, you might go --

Can you hear me? Hello?

Yes, we can hear you.

A lot of mine have been answered. I guess, a couple questions that I had remaining. One 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 (inaudible)?

Michael, that's upper Eagle Ford.

Okay. Great. That makes more sense.

And then as it are relates to the joint venture in Fasken, how is the upper Eagle Ford going to play into your thinking and negotiations there? Is the thought process that it would be included in the JV? Is it up for negotiation whether or not the upper Eagle Ford would be included? What's the thought process -- how's that being evaluated?

Yes. I think, again, with don't want to prejudice any negotiations or discussions that were happening. I think it needs to suffice to say that we're looking for a strategic joint venture, where we have good 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 what we're trying to do. We definitely want alignment with any potential partner we have there.

Okay. So I guess then along those lines, you kind of alluded to it earlier, but I just wanted to circle back around onto it. In terms of timing on both these transactions in Claytex and in Fasken -- or broader Eagle Ford -- if we haven't heard anything by mid-year or you haven't secured anything by mid-year, should we assume then you move on and the path towards the transaction just action just kind of stops? How should we think about that?

Michael there's --

Go ahead.

Some of this I said earlier --

I got dropped a little. I apologize.

No, it's a good question you're asking. I mean, I think the best way 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 Claytex assets, we've indicated we would sell either some or all of those assets. And those negotiations are progressing.

We believe that at least one of those sets of negotiations will progress to a positive outcome. And we'll keep you and the market apprised of that. We believe that we should have an update by mid-year.

I think if we make decision -- and our intent is to do at least one, but we'd like to do them both. If we get to the point that one of them, say, stops I think we would likely communicate that in some way at some appropriate time, so that we would take that concern as to whether it's 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're not going to leave it fallow. And that's the best way I can phrase that.

I wouldn't look at June 30 and you haven't heard anything and just assume nothing is happening. I would expect opportunities to update to the market on the -- to the extent that we can. I mean, when you're in negotiations you've got some sensitivity to that.

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 we're talking with and bring those to a successful conclusion.

That's helpful color. In terms of just helping me think about modelling potential impacts of these transactions, particularly in the JV -- would production likely be associated with it? Is it too early to say? You know, i.e., should I think about some lost production as a result of the incoming proceeds or not?

Yes. Well, clearly we're working, whether it's Fasken or the rig deployment in north AWP on oil. We're working very diligently to get really good capital efficiencies on all the drilling that we're doing. We're working hard in Lake Washington to really get the production profile there stabilized and even grow it through the 3D enhancements we're doing. We're doing the things I think will give very, very clear line of sight into 2015.

2015 is really what this discussion is all about. We've given 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 we are aligned with our shareholders -- creating value. I think this discussion is really about 2015.

And so when we say we'll give you an update by mid-year, certainly we do expect and hope to have a very meaningful transaction done that would give great clarification on the transaction side, but just as importantly to be able to give you a 2015 line of sight without giving guidance for 2015. It's clearly too early to do that. We can give much better line sight for 2015 about mid-year.

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. I would expect more marginal types of changes. Of course, that doesn't assume exactly what you do with that capital in the case if you get both of those transactions done -- it's different than one.

Patience is important, but not withstanding the patience, I think we've given good production guidance, good metrics for this year, good capital guidance for this year. I think it's going to be a great year for the Company.

Okay. That's helpful color. Thank you. And then -- I guess last one (inaudible). PCQ, how much inventory do you have left? Those wells have been performing very well. I'm just trying to think about how much more of that we have.

The PCQ lease itself -- the main PCQ, as far as types of models that is in that trend along our acreage position, even coming over into our held by production position. We have kind of in that trend area right there -- we have about 100 -- about 100 locations.

That would include getting over to Y Bar, Hayes --

That would get into the Hayes. That would get into the NBR. Along that model area.

All right. That's helpful. Thanks, guys.

Thanks, Michael.

Your next question come from the line of Steven Carpell with Credit Suisse.

Good morning, guys.

Hey, Steven.

First off, what's the balance today on the revolver?

I don't know what it is today. And there's inter-month changes to it. (inaudible) $300 million, I believe. That would be about right.

$300 million.

And $300 million was consistent with the March 31 number, as well?

Yes.

I guess I just want to understand -- I know this has been alluded to -- just understanding the CapEx budget. So the CapEx budget I guess was a little lower in Q1. And you've exceeded on production side. 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?

Well, there was actually some of both. The first quarter production did come in below our guidance. That's a combination of our ability to spend less.

Above our production. Production was higher.

No, the capital spending. (inaudible) I'm sorry, capital spending came in below our guidance. That was as a result of spending less on our AFEs. And spent less capital than we thought we would. But also the result of deferment in the second quarter, which is why the ramp up in the second quarter.

I guess I'm trying to understand too -- is the 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 Q1 production anyway?

I think the production has much more to do with timing of these things as opposed to thinking of a quarter -- as we indicated earlier in the first quarter -- the wells we were drilling really didn't come until early March. And in the second quarter they're more likely to come on in the middle of the second quarter.

It has more to do that with and along with the lumpiness of the three packs that we're doing, as well as the requirement you set in certain big wells. Particularly in Fasken. When you shut in some of those wells -- pretty big wells and you're shutting them in to frac others, but when you get them all back on production we have a lot of capacity.

Lastly, just to hammer out on the CapEx. You maintain the guidance. How do we think about how much of your guidance is committed at this point? If you look at the -- obviously the run rate doesn't tell you much, in terms of -- I guess I'm saying your ability to the throttle back.

We have the ability to pull back with our spending levels. Other words, our spending levels right now, if you maintained those for the rest of year you would be far above $300 million to $350 million. We've guided $300 million to $350 million and we do have the ability to pull that back.

We're maintaining a spending level in the first and the second quarter though on a pace that we hope to be able to maintain throughout to the year because we have a confidence level that we're going to get at least one of these transactions done.

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

I guess what I'm trying to get at -- the last questioner was talking about maybe mid-year or past mid-year you potentially could give an update on the status in terms of where you are on asset sales. By that time you would have spent a pretty significant portion of that $300 million to $350 million. Or probably succinctly -- is it too late to pull back, or you will still be able to pull back at that point?

No, no. I'll reinforce this. We've designed our plan to deliver the production guidance that we've given you and the capital guidance we've given you without a transaction. Now, we've also designed our plan without baking in a lot of the cost savings that we're seeing on drilling these wells. We designed our plan without baking in the better gas market that we're seeing right now.

So we're very confident in the guidance we've given you. But we are still very focused on getting the right transactions done for the Company.

Perfect. Thank you, gentleman.

One more point of clarification, the balance at the end of April on our bank line was $318 million. So you get some intra-month swings there.

Your next question come from the line of Keaton Tyndall with Raymond James.

Hi, guys. Good morning.

Good morning.

Good morning.

Claytex package was split into multiple parts. Can you give a sense of what that might look like -- mineral interests and everything else? Would you guys keep an override or maybe consider a JV versus sale at some point?

We are -- we hope to sell all of central Louisiana as a whole. But they do consist of, I guess, what I would break into three district pieces -- South Bearhead Creek, which is a Wilcox play, which has both proved producing properties as well as upper and lower Wilcox development, The Burr Ferry field, which is principally is Austin Chalk development. It both has some proved producing developments, as well as some development opportunities to it.

And then there's the mineral interest. The mineral interest both has proved production on it in the Burr Ferry field as well as a substantial amount of additional acreage that's undeveloped.

We anticipate trying to sell that as a package. Clearly, if you don't sell it as a package all those parts have value on their own. That would give us an ability to do that. I think beyond that, what we've not done is provide any specific valuation metrics related to either the whole or parts of those packages. Obviously, we're in negotiations with people regarding those assets, we don't want to do that.

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

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

Let me just say -- this is Bob. If you go back through the history, we have plenty of these every quarter at Lake Washington. We have many, many well bores there. Many opportunities to do optimization projects.

To build a little on what Terry said, 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 operations to get more efficiency or lifting our liquids out of these well bores. Sometimes we're doing swabbing operations on our wells. We're doing hot oiling on our wells and on our lines. We're doing chemical treatment projects.

There's always, every quarter, a slew of these things we do to manage all of those assets, all of that -- all of those reservoirs that we're involved with at Lake Washington.

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

Right. And that generally involves getting more serious equipment -- a rig out into the field whereas, a lot of the other things we just discussed don't require that kind of equipment commitment.

Okay. Great. That's helpful. Thank you.

Thank you.

Thank you.

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

Good morning, guys. Thanks for the update.

Yes.

So it's great that CapEx -- is the trend is your friend, it's coming down. When do you expect -- I've listened to your guidance and all that. Which quarter are we going to see CapEx less than our cash flow?

I think in terms of the current plan without a transaction, you'd see that in the third and fourth quarter. And --

The third quarter?

That's kind of how we've guided things.

That's terrific. These shareholders need some relief here. The stock is off another 10% today. And again, this has been talked about.

Investors want independent oil and gas companies to live within their cash flows. And we're getting crucified for all these years for out-spending our cash flows. I look forward to the third quarter. I can't wait.

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

Appreciate that. That's good. That's good to hear. So just theoretically assuming we sale Lake something in Louisiana for just say $200 million -- how much of that do you expect will be used to pay down debt? What percent?

Any transaction we do, initially all of it will 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. We worked through those numbers. We would not make any material changes, in my judgement to the plan, except to ensure we gave better line of sight for 2015. And how we will particularly develop the Fasken assets and the oil and the AWP area where we're getting exceptional results.

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 of capital for the rest of the year. It wouldn't deliver a whole lot of new production for the rest of the year. In fact, all of that sets 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 apply those proceeds going forward. I expect the majority of them would be go to pay down debt.

Okay. That would be great too. Thank you.

Thank you.

Thanks.

Ladies and gentlemen, that --

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

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