SilverBow Resources Inc (SBOW) 2015 Q2 法說會逐字稿

Good morning. My name is Jake and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Company's second-quarter 2015 earnings conference call. (Operator Instructions)

Thank you. Mr. Doug Atkinson, Manager of Investor Relations, you may begin.

Thank you, Jake. Good morning. I'm Doug Atkinson, Manager of Investor Relations. Welcome to Swift Energy's second-quarter 2015 earnings conference call. Joining today's call is Terry Swift, President and CEO; Alton Heckaman, Executive Vice President and Chief Financial Officer; Bob Banks, Executive Vice President and Chief Operating Officer; as well as Steve Tomberlin, Senior Vice President of Resource Development and Engineering.

We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions. To complement our prepared remarks we have prepared a slide presentation which is available on our website within the investor relations section.

Before I turn the call over to Terry I'd like to call your attention to our forward-looking statements on slide 2. 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.

Thanks, Doug, and thank you to everyone for joining the call today. I'm going to quickly cover the highlights of the quarter before turning over the presentation to Alton Heckaman, our CFO, who will talk about the second-quarter financial results. After that, our Chief Operating Officer, Bob Banks, will speak to our operations, and then I will make a few concluding comments and remarks before we open it up to Q&A.

Starting with slide 3 of the presentation, despite the challenges that our industry is obviously facing, I'm pleased to report operationally that we achieved quarterly production of 2.88 million barrels of oil equivalent, which was above our guided range of 2.75 million to 2.8 million barrels. We revised our full-year 2015 production guidance to a range of 11.5 million to 11.6 million barrels of oil equivalent and revised our capital budget to $110 million to $120 million.

We successfully secured an additional 30 million cubic feet per day of takeaway capacity out of our Fasken field in Webb County, bringing our total takeaway up to 190 million cubic feet per day. On the cost side, we are now drilling and completing our wells in Fasken for approximately $6 million per well. We have done this and continued to improve the technology that we have been using. We will speak more of that today.

We believe we can bring these costs down further in the coming months. Our cost-reduction initiatives are still on track as lease operating expenses declined sequentially 8%, general and administrative cost declined sequentially 18%. We set new technical limits in Fasken in the quarter, drilling our longest lateral to date, and achieving our best to date drilling cost per foot, all of which Bob will discuss in more detail.

We have now completed 21 consecutive wells at Fasken that are expected to meet or beat our 12 Bcf per well type curve. These new Fasken wells are producing between 3 billion and 3.5 billion cubic feet of cumulative gas production in their first year of production. This is an amazing accomplishment compared to our original designs, which were, of course, shorter laterals and less sand, which pulled roughly 1.5 billion cubic feet of gas production out of the ground in their first year of production.

We're going to focus more, during this call, on each of these highlights and outline our plans for the third quarter of 2015. At the end of our prepared remarks, I will make a few comments on recent events and we will open the call up for Q&A. With that, I will turn the call over to Alton.

Thanks, Terry, and good morning. I will summarize our financial results for the quarter. For those following along with the presentation, summary tables of our second-quarter financial and operating highlights can be seen starting on slide 4 in our presentation deck.

As Terry mentioned, our second-quarter 2015 production was 2.88 million Boe, slightly above expectations. We were above guidance as to both oil and nat gas, while NGL production was within our guidance range.

Our overall financial results for the second quarter of 2015 include, oil and gas sales were at $68.3 million, before the $2.1 million loss in price risk management and other income. Our adjusted net loss was $32.9 million, or $0.74 per diluted share, which excludes the effects of our non-cash ceiling test write-down.

As we noted in the earnings release, we recorded a $261 million pre-tax ceiling test write-down in the second quarter of 2015, due to the continued lower commodity prices, resulting in a reported GAAP net loss for 2Q 2015 of $292.9 million, or $6.58 per diluted share.

Our controllable cost and metrics for the quarter include: general and administrative costs, which came in at $3.58 per Boe; lease operating expenses of $5.97 per Boe for the quarter; transportation and processing costs were $1.77 per Boe; DD&A was $14.64 per barrel; interest expense was $6.52 per Boe; and severance and ad valorem taxes were 6.5% of our oil and gas sales.

Our effective income tax rate for the quarter was essentially zero, as we talked before about the valuation allowance against our deferred tax assets effectively offsets any tax benefit attributable to our book loss, in accordance with the applicable GAAP accounting rules. Cash flow before working capital changes for the quarter came in at $14.9 million, while EBITDA was $29.2 million for the quarter. Quarterly CapEx, on an accrual basis, was below our guidance and came in at $33.2 million for the quarter.

As Terry mentioned, earlier this year we completed several steps to reduce our cost structure, including a significant reduction to our corporate headcount, renegotiation of our corporate office lease, which reduced both the square footage and the cost significantly, and we took proactive steps to reduce our other corporate G&A and field operating expenses. As you can see, these cost-cutting initiatives have taken hold and will provide for sustained lower overhead and operating costs going forward.

Let me refer you to slide 7, where you will see a breakdown of our debt maturity schedule. It also indicates as of June 30, we had roughly $100 million in availability on the revolver.

Now, I would like to make a few comments about our financial strategy with respect to navigating through this lower commodity price environment. As indicated on slide 8 of our presentation, Swift strives to manage our business with the following financial tenets in mind. We invest with a focus on attractive economic returns; proactively manage any refinancing risk; we opportunistically hedge to minimize price volatility and protect our future cash flows; and last but clearly not least, maintain our liquidity.

We remain very committed to capitalizing the Company in a manner that optimizes investment in prudent development opportunities, while preserving our ability to repay our debt and enhance our metrics and ratios. We are taking what we feel are the necessary steps to achieve this objective.

Finally, on slide 9, we've included production and capital expenditure guidance for the third quarter and full year 2015. With that, I will turn it over to Bob.

Thanks, Alton. Today, I will discuss second-quarter activity, including our production volumes, our recent drilling results and our plans for the rest of 2015.

For corporate-wide production, Swift Energy's production during the second quarter of 2015 totaled 2.88 million barrels of oil equivalent, which is above our expected range of outcomes. Production was comprised of 65% natural gas, 22% crude oil and 13% NGLs. Second-quarter 2015 production decreased 6%, compared to first-quarter 2015 production of 3.06 million barrels of oil equivalent.

In our South Texas core area, second-quarter 2015 production of 26,842 net barrels of oil equivalent per day decreased 6% compared to first-quarter 2015 levels. Gross volumes out of Fasken in the second quarter, which include production sold to Saka as part of the joint venture, did increase to 142 million cubic feet per day, compared to 133 million cubic feet per day in the first quarter of 2015. We are currently producing close to 160 million gross cubic feet per day in Fasken and expect to start producing into our newly secured incremental 30 million cubic feet per day during the month of August.

We drilled six operated wells during the quarter, all in Webb County in our core Eagle Ford Fasken Shale area, and all six wells were drilled and pre-completed under budget.

We completed four Fasken wells in the quarter, and as we discussed last quarter, we believe that Fasken is a proven area and we are now more focused on efficiently managing production and operations than on providing initial production volumes to demonstrate the strength of the Fasken field.

Based on the rate and pressure data from the 31H, 32H, 33H and 34H wells, we have now completed 21 consecutive wells at Fasken that are expected to meet or beat our 12 Bcf EUR model. These wells typically deliver their first Bcf gas in under 70 days and cume approximately 3.5 Bcf in the first year of production.

At Fasken we drilled our longest lateral to date of 7,823 feet, which compares to the second longest lateral drilled in the first quarter at 7,745 feet. We also lowered our best-to-date drilling cost to $122 per foot. Additionally, we've upside our sand loadings in two recent wells, going from an average of 1,400 pounds of sand per foot of lateral, to roughly 2,000 pounds of sand per foot of lateral.

Our cost-reduction program continues to deliver additional reductions on sequential wells, as components of the program become fully implemented. For example, we are very proud to announce that the most recent well at Fasken was drilled, logged and cased for $2 million, which is a 37% reduction from the 2014 average. We are now drilling and completing Fasken wells for approximately $6 million per well.

We believe our operational results clearly demonstrate our expertise in the Eagle Ford, providing us with a multiple year high graded drilling inventory at current commodity pricing and corresponding cost structures. We have demonstrated that our approach in South Texas, which has been applied across our acreage positions in four distinct areas now, does provide a platform for growth as we expand our interest in the South Texas Eagle Ford.

As you know, we acquired Oro Grande in late 2014, we also secured a small position in Live Oak County around that same time, which we refer to as our Uno Mas acreage. We have successfully added small bolt-on acreage to our original Uno Mas position in the last few months. We do have a slide in the appendix of our quarterly earnings presentation with more detailed information on Oro Grande and Uno Mas.

We are pursuing a strategic partner for several of our properties, including Oro Grande and Uno Mas, as we believe much of our undeveloped acreage in our portfolio is commercially economic in today's environment. As such, we plan to utilize joint ventures and farm-out type arrangements to accelerate our development. We now have a deeper and more predictable inventory of commercial locations in the Eagle Ford, and we look forward to applying our enhanced techniques to our undeveloped acreage in the near future.

Quickly summarizing our southeast and central Louisiana areas, in southeast Louisiana, Lake Washington averaged approximately 3,052 net barrels of oil equivalent per day, a decrease of 5% when compared to first-quarter 2015 average daily volumes. We performed eight sliding sleeve zone changes and three gas lift redesigns in Lake Washington in the second quarter. We do have an inventory of re-completion opportunities and expect to conduct a number of these low-cost, high-return projects in 2015.

Our central Louisiana properties, which includes Masters Creek, Burr Ferry and South Bearhead Creek fields, contributed 1,603 barrels of oil equivalent per day of production in the second quarter of 2015, a decrease of 9.5% from first-quarter 2015 production in the same area.

Now, I would like to take a minute and talk about some of the things we are doing to reduce our capital and operating costs. We continue to expect to see cost reductions for drilling and completions at the high end of our previously stated goal of 15% to 30% for the full year 2015. We are aggressively pursuing further vendor concessions, and in some cases, have started bundling our services in order to accrue deeper discounts. For example we bundled our fracs, e-lines and frac plugs and saved nearly $300,000 per well in the quarter.

Our lease operating expenses declined 18% year over year and 8% sequentially. Our lease operating costs in Fasken and AWP were down 6% and 3% sequentially. The primary drivers behind our LOE reduction program include lower labor, repairs and maintenance and compression costs. We expect our LOE cost-reduction initiative to save us approximately $10 million to $12 million in 2015 compared to 2014 levels.

Now, for a look at the third quarter and full year 2015, as you can see on slide 9, we are targeting third-quarter production levels of 2.77 million to 2.82 million barrels of oil equivalent, including 11.23 Bcf to 11.43 Bcf of natural gas production, 0.55 to 0.56 million barrels of crude oil production, and 0.34 million to 0.35 million barrels of natural gas liquids production.

This level of production is based on $35 million to $40 million in capital expenditures for the quarter. For the full year, we have revised our production guidance range to 11.5 million to 11.6 million barrels of oil equivalent, and our full-year planned capital expenditures range to $110 million to $120 million.

A portion of the capital expenditure program for the rest of the calendar year is discretionary and can be further deferred if necessary. As we noted, the majority of our capital this year will be deployed to Fasken and our AWP properties, which yield attractive returns at current pricing and corresponding cost structures. With that, I will now turn the call back over to Terry for his closing remarks.

Thank you, Bob. I will summarize today's call as follows. Our enhanced drilling and completion designs continue to improve the productivity of our wells in all our South Texas Eagle Ford properties. The last 21 wells we have drilled at Fasken are expected to meet or beat their respective 12 Bcf EUR type curves.

We continue to drill longer laterals and pump more sand while realizing fewer drilling days and lower per-foot drilling and completion costs. We continue to make substantial progress in aligning our cost structure with the current environment. Cost-reduction initiatives to date are on track and in many cases exceeding our expectations.

We secured an additional 30 million cubic feet a day of firm capacity and takeaway out of Fasken, which will be operational by the end of August. We have an inventory of several hundred high-graded Eagle Ford locations that are economic, even in today's challenging commodity price environment. As a result of improved well productivity and operational efficiencies and successful cost-cutting efforts, we are able to tighten our full-year production guidance and full-year capital expenditure budget.

Before I open the call up for Q&A, I'd like to say a few things about some of the recent events here at Swift Energy Company. As you all know, on June 23, we announced we had launched a $640 million first-lien term loan. Based on unfavorable conditions in both the global and the domestic debt markets, we are reassessing the various first-lien options that we have. The first-lien loan was one of the various options that we considered to secure the amount of liquidity we needed to execute our business plan through the next two to three years.

We have retained Lazard to advise the Company's management and Board of Directors with respect to realigning our balance sheet, including our senior notes, which trade at significant levels below face value, addressing certain maturities and enhancing our liquidity profile. The Company's liquidity, as we have said before, is something that we have been focused on for quite a while. And we remain focused in this area, that is obviously a very difficult area as relates to the commodity pricing environment.

To sum it up, we believe the assets we have developed here at Swift Energy Company have meaningful value, much of which can be realized even in today's challenging environment. We believe we have the right people in place to execute on these assets. We believe we have set new technical limits with each well we have drilled. In fact, per the IHS data, Swift Energy has drilled 16 of the top 20 gas wells ever drilled in the Eagle Ford.

Finally, we believe we are making significant progress in adjusting our cost structure and spending to maximize our current liquidity, and we're taking the necessary steps on behalf of all stakeholders to ensure that we have the resources and liquidity we need to execute our business plan going forward. With that, we would like to begin the question-and-answer portion of our presentation.

(Operator Instructions) Neal Dingmann, SunTrust.

Good morning, guys.

Good morning.

This is Will for Neal. Question on I guess asset sales in light of the announcements on the bank financing: would you all consider selling anything today?

First a comment, just again on the commodity market. Because of the volatility of the market, you well know that it freezes or makes it difficult for buyers and sellers to come together. That said, we definitely have some assets that we think are non-core. Our South Texas assets is where we're growing. So I think as you look at the overall business plan, you would see us continue to be interested in focusing on South Texas and to the extent there are divestiture opportunities in the non-core assets, we would certainly would entertain them.

All right; thanks, Terry. Then going back to Oro Grande, you all talked about that a little bit, what are thoughts to drill the well? Are you all still planning on drilling a well there later this year, hopefully?

Yes. I think clearly, the summer double dip in commodity prices is making us reassess things, whether it be our liquidity and how we work through that or our drilling plans. I think Oro Grande really will push into next year. We are, as Bob noted, we are doing some other things that we think are very proactive in expanding the reserve base and bringing, I think, more proven reserves forward, particularly in the gas and Fasken area. But as to Oro Grande, I think we will slow that down and get into that early next year as Uno Mas fits into that category as well.

Okay. Thank you.

Thank you.

Welles Fitzpatrick, Johnson Rice.

Good morning. Congrats on the continued success, especially in Fasken.

Thank you.

Staying with Fasken and dovetailing on your last comments, can you talk a little about what the third party reserve engineers might give you in the fall on Fasken? Obviously, they are great wells, but they are a little bit newer.

Well, that is, obviously, a great question because we think we are doing better than we certainly started out. I think it is very important to keep in mind, particularly in Fasken, this is, if not the best, it's one of the best rocks in the whole Eagle Ford. It is gas, which makes it a little easier to understand than oil.

That said, you really are able to look at the pressure data in Fasken and make reserve assessments that are based on pressure and rate, as well as compare that back to the core data, which tells us what the gas in place actually is. We think we are ratcheting down from several different reservoir engineering perspectives and understanding our rock better with every day we produce and watch the pressures.

We do RTA analysis and that is pointing to some higher reserve opportunities. We are drilling longer laterals and, I think at the end of the day, it really is the reserves that you recover per foot and, therefore, as you are able to drill longer laterals you, obviously, get a better EUR.

And then, finally, we are increasing our sand count, sand concentrations there and we do believe that also enhances the actual recovery of the drainage area of each well. Long story short, we are very confident in the 12, we think we are going north of that. We do work with Gruy and they keep up with the field on a pretty regular basis, it is not just an end of the year type of thing. Without finishing Gruy's work for them, I think I would say it is definitely headed the direction we expect and that would be higher than the 12 Bcf per well.

That is great. Then I just had one more. If I am reading the new presentation right, I think 1,600 gross AWP acres moved from condensate to gas. Any explanation on that?

Yes. I will hit on that and then Bob can go a little farther. But I think one of the nice things that we have is we have got a large seismic 3-D database and we have been able to tie that database all across AWP to the Northwest, or excuse me, the Northeast, up in the Live Oak County area all the way down into the La Salle area and compare not only the 3-D to the cores that are out there, but all the logs and different wells that have been drilled.

I think as we look at AWP, we are absolutely convinced, very similar to Fasken, early days, the laterals were too short, early days, the sand concentrations were too small, a lot of early wells were out of zone and, just as importantly, that area there was this slick water or highway fracs that were used that today we just don't believe they're getting the same kind of results. So, we've gone into the AWP; I will let Bob talk about the recent wells and what we're doing today there with the technology.

Yes. Just to go back to your first question. We have a fault that runs the there and we're reinterpreted that a little bit and that shifts around some of where we draw our condensate gas line. So we just reclassified around that.

But the real fact is that in that area you have different degrees of liquids from north to south so it is not an exact point of disembarkation. We will have one layer of wells that will have a certain yield to it in terms of liquids, as you move further south that yield starts to decrease. So it's really geared around how we interpret what should be called gas and what should be called condensate.

We continue to drill in that top row where we do get the better liquids yields. And the wells we are drilling now, these are going to be much longer laterals. We have never drilled a 7,000 foot lateral there, we are drilling two 7,000 foot laterals in AWP and we are applying a lot more of our enhanced technology in these wells that we have become accustomed to out in Fasken. That hopefully answers your question on that interpretation.

Yes. That is perfect. Thanks so much.

Thank you.

Neal Dingmann, SunTrust. Your line is open.

I think they were previously in the queue. They must have been in there twice, so then we can go to the next caller.

Michael Hall, Heikkinen Energy Advisors.

Thanks. Good morning.

Good morning.

Curious if you have any commentary you could provide around what sort of indications have been given on the borrowing base re-determination this fall and any conversations you have had thus far?

The conversations I have had are pretty much along the same lines as, I think, everybody sees in the marketplace. Commodity prices are down. It is very hard to ascertain how banks will move forward. It is a very volatile environment, but that said, last February was also very volatile and we came through that borrowing base re-determination with $375 million as the borrowing base.

We've made a lot of progress since then in terms of lowering our costs, both in terms of capital costs going forward, LOE going forward. We are continuing to do that and we have drilled some really great wells, improving the reserves within the fields, particularly Fasken and the AWP area. So while we are not able to necessarily say the world is great and there's going not be any trouble or challenges or changes, we will be working with our banks to go into the borrowing base to try to maximize the amount of borrowings that we can have there.

Michael, this is Alton. Obviously, we stay in constant communication with our banks and we are taking steps to have less reliance on that being the funding source, as you can see and as we have indicated in our release, and as you'll see in our Q.

Okay. What was the amount outstanding on the revolver at the end of the quarter?

At the end of June it was to $275 million and, actually, I just checked yesterday: it was like $280 million.

Okay. That's helpful, thanks. Then you indicated and alluded to, I think, in the release but also in your remarks that some other options are being evaluated after the process around the lien. Can you give any additional indications as to what sort of options are being evaluated there? What are the other potential (multiple speakers)?

This is Terry. It's a good question. I think in terms of the various options, we still have the options that we had in the spring. You have got your first lien, your second lien, your one and a half liens, you've got ways to go about working with the capital structure.

I don't want to get ahead of myself though. We did announce that we've retained Lazard and, in that regard, they are providing financial expertise to both management and the Board as relates to all the stakeholders, which would involve the entire capital structure. We need to let that work get done and we won't be commenting on that publicly, as that is being done, but rather when there's things that are such that we should disclose them, we will do it at that time.

I do think we have got great assets and I think there is the possibility that we might do some limited dispositions that might change the picture somewhat, but anything you see us do, we will be focused on trying to maintain our strategy and continue to develop the assets. And, again, I think it is very important to realize that we are drilling some of, if not the best, gas wells in the state of Texas. So we're going to try to keep doing that however we fix the liquidity issues.

Okay. It makes sense. Is there a timeline that you have engaged Lazard with that you hope to have some sort of plan in place or is that still in flux as well?

Well, I would not say it is in flux, I would say there is a plan, but it's not a plan that we're going to necessarily put out to the public. We need to let Lazard do their work and if you're looking for timing, I think everybody would say in this environment sooner is better than later. I cannot give you really any more color on that, but I can assure you we are not sitting here waiting to find out what people may say and bring to us, we're actually working it proactively and we have engaged Lazard to help us with that.

Okay. That is helpful color. I appreciate it. On the Oro Grande, we talked about the potential for joint venture there. This kind of pause, if you will, in terms of the initial testing of the acreage, is that also pausing negotiations around the joint venture process or how should we contemplate that?

Actually, I think Oro Grande looks better today than it did six months ago. We have 3-D across the entire area and we have been using this time to optimize that. We have actually been in discussions with various parties on, not only the JVing and working with us in that area, but also looking at the overall gas picture in the gas window of the Eagle Ford. The Eagle Ford has a tremendous advantage over other gas up north in that it can get to the Gulf Coast petrochemical complex, the LNG, Mexico. A $0.75 to a $1.25 advantage in the gas market.

We are finding those people that believe that and want to be a part of that opportunity. Again, rather than negotiate out in the open, we are working that as well. I do not want to go in there and just drill one well. I think that is the wrong way to go about it. So we are working with the program approach and, again, that is something we want to prosecute early next year.

Okay. That is helpful. On the other properties, I guess in the non-core arena, as well as in the Eagle Ford, maybe less of the focus within the capital program, are you guys non-consenting much at this point within the program?

I am sorry, I didn't quite --

Are you non-consenting much of your activity?

If you're talking about Louisiana, that's, for the very most part, all held by production.

Yes. I was more referencing actually the non-op JV you had in the Eagle Ford.

The non-op JV? No, that we are actually the operator of that position.

Okay. (multiple speakers)

Just to clarify it, we had a large joint venture with Petrohawk. Petrohawk had a successor, BHP. BHP is not drilling in the gas window. Not to speak for them, but they had extremely large holdings, well beyond their joint venture with us, and they have been either farming out those holdings, non-consenting wells, or letting acreage expire. I think that is fairly public information.

Yes. That is what I was trying to get at. Okay, that is helpful.

The last one on my end, in terms of keeping that 190 million a day full, what sort of capital commitment would there be on that for 2016? How many wells would you say you have to drill to keep that full?

I want to answer that. They're all jumping to answer that. Fasken is a crown jewel asset. Just to keep the 190 full, we estimate that at present it would probably be eight to nine wells and that, all in, that might be net to the Swift position maybe $35 million for the whole year. It is just a jewel.

I'm going to say this though, we have great expectations for the upper Eagle Ford and we also do believe these lower Eagle Ford wells are going to do better than 12 Bcf. So should we be correct about reserves that are better than 12 and the upper Eagle Ford be as good as we think it is, then I think 190 is kind of a low bar. We are working with plans right now to ascertain how we drive that up and certainly would look again to strategic partners like Saka and those that believe in the gas market in South Texas.

Okay. How thick is your Fasken upper Eagle Ford and lower Eagle Ford section?

The upper Eagle Ford is about 210 feet. It is pretty thick and the lower Eagle Ford is about 160.

Great, I'll let some others on. Thank you for the time. I appreciate it, guys.

Thank you, Michael.

Noel Parks, Ladenburg Thalmann.

Good morning.

Good morning.

With the positive changes you've made in pricing at Fasken, can you just update us as far as where the inflection point is for -- with the new cost structure? What $0.50 range really gets you the most bang for the buck on your economics? Is it from $2.50 to $3.00, or $2.75 to $3.25? What are the inflection points for economics there?

I think there's really two things to try to point out. I think in our slide deck that's labeled the corporate presentation --

Yes, that's the corporate presentation that's on the website.

The corporate presentation, I believe it's slide 13, actually has what we think is a single well model for Fasken. That actually uses a $3.00 price deck and the returns are exceptional at $3.00.

We clearly, in the Fasken area, because of Mexico and proximity really to the pipeline infrastructure, I think the basis differential to ship channel really is in the minus $0.10 to minus $0.05 range; and the outlook forward is for that to improve significantly into the $0.16 and $0.17. So we think from a basis differential standpoint it's going to really have an advantage. That will help the economics in the Fasken area.

And then I think on page 15 of our corporate slide presentation, we do compare that to some other basins. KeyBanc actually did that work for us.

Okay. Great. As you model going forward into 2016 and beyond, what are your working assumptions for how much of the service cost improvement you have seen is sustainable? If we assume you are going to get close to a trough in cost this year, what do you model the first year inflation being in costs?

I think what we're modeling into next year is what we have already achieved. However, at Fasken we do have additional room to lower those costs. The rig that we have under contract there right now was a year contract. When we executed that contract, we were in a higher day rate environment. What we are actually looking at now is to go more to an even higher efficiency rig at a day rate that is probably another $7,000 or $8,000 lower than what we currently have.

So we will sustain in our Fasken program further reductions in two ways. First, the lower day rate on the drilling rig and, second, we think we can shave two more days off of drilling time with a little bit higher efficiency rig. But we have not totally modeled all of that into 2016, so I think what we have sustained now, I feel very good about for 2016 and in the Fasken area taking some additional savings on those wells by going to those high-performance rigs at a lower day rate.

Great. Actually, what is the baseline? So what's the current day rate for that rig under contract?

That is a commercial contract. I don't want to give you an exact, but it is in the -- I will guide you into the mid-20s.

Okay. Fine. That is all for me. Thanks.

Thanks.

Adam Leitman (sic), RBC Markets.

Good morning, everybody.

Good morning, Adam. We are having trouble hearing you, Adam.

Sorry. Most of my questions were answered, but just to follow up, I know you are sensitive about the nature of what you are going to do in the capital markets. Can we assume that you are expecting to get something done prior to the fall re-determination?

I think it is appropriate to assume in conjunction with the fall re-determination, we are being proactive to bring all of our options forward and working with folks. We are not waiting on people and to come to us and say here is what they think is right. My goodness, in this environment, there are so many ideas, I think you just have to focus on a couple of very meaningful things.

I really do not want to set a date certain because deals work around dates as opposed to specifically to a date. But, yes, we are focused on making sure that the fall re-determination season, we have a solution.

Regarding asset level deals, JVs or even sales, is there anything you have got material that is probably ready to get done, but is awaiting a capital market solution?

I think it is fair to say that, I hit on this a few minutes ago, we have non-core properties, principally in Louisiana. We have our core area where we know we can grow, that's in South Texas; that is where we are getting the great efficiencies. So to the extent that buyers and sellers can come together in a market like this, we would entertain dispositions over in Louisiana.

That said, oil just took another mid-summer dive. I am personally thinking we are at right at the cusp of seeing the domestic production begin to turn down. We know the value of the assets, we are not just going to transact because oil made a dive and we think it will be back up in the $60s by the end of the year.

Nor are we waiting on any capital transaction, Adam. I think that was the root of your question.

I guess the essence is, particularly if a JV in a gas area that has good economics, but your partner might be making sure you have sufficient liquidity post whatever you get done, if there's something ready to go or if we're just waiting to hear?

I think it is fair to say we know our assets really well. We know how to transact around our assets. In that respect, we can do things reasonably quickly.

Okay. I will leave it at that. Thanks, guys.

Thanks, Adam.

(Operator Instructions) Joshua Gale, GMP Securities.

Good morning. A lot of the questions on liquidity have focused on the fall re-determination, but wanted to ask even before that, coupon payment due on one of your bonds on September 1. What is the likelihood you make that payment?

It is scheduled and the likelihood is very -- probably close to 100%. (Laughter)

I think it -- normal operating plan is to make the payment.

Yes.

Okay. In conjunction with the fall re-determination, I know in the latest amendment there was a minimum liquidity condition that was instituted in there. In order to make the interest payments, your availability has to be at least I think it is $56 million, effectively cutting what is available at the times you make the interest payment, so --

Sure. We have a payment on September 1, December 1, January 1. The September 1 payment, there will be no issue with respect to that liquidity covenant.

Okay. Is it fair to say that if you do have an asset sale, JV or some other transaction that brings in cash that perhaps that minimum, or reduces the balance of debt in the cap structure, that perhaps that minimum liquidity condition would be reduced or eliminated?

Well, to the extent that you have some contemplated disposition, you obviously have to look at the value of the disposition versus the collateral and the borrowing base, and since there is no such transaction to discuss, I just have to say, hypothetically, we would not sell a property unless it was advantageous to us in that regard.

Right. I think the answer to your question is yes, it would reduce that being an exposure item because we would be selling something that would be accretive and any reduction to the borrowing base would be significantly less than the proceeds we receive.

Great. All right. Thank you.

Thank you.

At this time I would like to turn the call back over to Terry Swift.

Okay. On behalf of Swift Energy Company, we would like to thank you for joining us on the call. We look forward to reporting back to you on our next operating and earnings call report. Thank you.

This concludes today's conference call. You may now disconnect.