SilverBow Resources, Inc.
Q1 2015 Earnings Call Transcript

Published: 7 May 2015

[Operator:]

Good morning. My name is Nicole and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Company’s First Quarter 2015 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Mr. Atkins, you may begin your call.

[Doug Atkinson:]

Good morning. I am Doug Atkinson, Manager of Investor Relations. Welcome to Swift Energy’s first quarter 2015 earnings conference call. Joining today’s call is Terry Swift, President and CEO; Alton Heckaman, Executive Vice President and Chief Financial Officer; and Bob Banks, Executive Vice President and Chief Operating Officer. 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 would 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 our cautionary statements contained in our press releases and our actual results could differ materially.

[Terry Swift:]

Thanks, Doug and thank you to everyone for joining the call today. I am going to quickly cover the highlights of the quarter before turning the presentation over to Alton Heckaman, our CFO, who will talk about the first quarter financial results. After that, our Chief Operating Officer, Bob Banks, will speak to our operations and then I will make a few concluding remarks before I open up to Q&A. Starting with Slide 3, despite the very low commodity price environment, I am pleased to report that we achieved quarterly production of 3.06 million barrels of oil equivalent, which was above our guided range of 2.92 million to 2.97 million barrels. Eagle Ford production increased 19% year-over-year primarily driven by higher production from our Fasken area. Our team continued to set new technical limits in Fasken during the quarter, drilling our longest lateral to-date, achieving our lowest lateral cost per foot and setting a new days on well record, all of which Bob will discuss in more detail. Due to the reduction in prices, our borrowing base was modified from $417.6 million to $375 million. We are pleased with the re-determination amount, which was reasonably consistent with our expectations. Our cost reduction initiatives put in place in late 2014 are on track to meet our 2015 expectations. We are seeing cost concessions in some cases greater than we originally budgeted. Lease operating expenses decreased 16% sequentially. Finally, based on well performance and better than expected cost savings, we are able to incrementally improve our commercial results, while maintaining our original capital budget. We are going to focus more on each of these highlights at the end and I will make a few comments on what we are doing to position ourselves in order to emerge from this challenging environment and try to become a much stronger company and certainly much more profitable. And with that, I will turn the call over to Alton.

[Alton Heckaman:]

Okay. Thanks, Terry and good morning. I will summarize our financial results for the quarter and for those who are following along with the presentation summary tables of our first quarter financial and operating highlights can be seen starting on Slide 4. As Terry mentioned, our first quarter 2015 production was 3.06 million BOE as we exceeded our forecasted gas and crude oil production, while our NGL production was right in the middle of guidance. The overall financial results for the first quarter 2015 include

[Bob Banks:]

Thanks Alton. Today, I will discuss first quarter activity, including our production volumes, our recent drilling results and our plans for the rest of 2015. The corporate wide production, Swift Energy’s production during the first quarter of 2015 totaled 3.06 million barrels of oil equivalent, above our expected range of outcomes. Production was comprised of 64% natural gas, 22% crude oil and 14% NGLs. First quarter 2015 production increased 4% compared to first quarter 2014 production of 2.94 million barrels of oil equivalent and was up 2% compared to the fourth quarter 2014 levels. In our South Texas core area, first quarter 2015 production of 28,872 net barrels of oil equivalent per day increased 11% compared to first quarter 2014 levels and 6% compared to fourth quarter of 2014. Gross volumes out of Fasken in the first quarter, which included production sold to Saka as part of the joint venture increased to 133 million cubic feet per day compared to 110 million cubic feet per day in the fourth quarter of 2014. We are currently producing just over 150 million cubic feet a day gross at Fasken. As a reminder, we have firm takeaway of 160 million cubic feet per day out of Fasken and are actively looking to expand that to 190 million cubic feet per day in the near future. We drilled five operated wells during the quarter, all to the Eagle Ford Shale in company South Texas core area. Four of those wells were drilled in Webb County and one well was drilled in McMullen County. In Fasken, we drilled our longest lateral to-date of 7,745 feet, which compares to the second longest lateral drilled in the fourth quarter of 7,614 feet. We also set a new record for lateral cost per foot of $337 and achieved a new best of 16.5 days on well site compared to our previous record of 18.5 days. Our average drilling cost for 2015 currently stands at $2.6 million per well, down from $3.2 million in 2014. While the 2015 average shows a substantial reduction from 2014, our cost reduction program has delivered additional reductions on sequential wells as components of the program are starting to be fully implemented. We are very proud to announce that the most recent well at Fasken was drilled for $2.2 million, which is a 31% reduction from 2014 average. I would also like to mention that our team has now gone 1 year without a lost time accident. We love to talk about the strides we are making in streamlining our activities and driving operational efficiencies, but we can never lose sight of the fact that safety is our most important objective here at Swift. As we discussed in our press release this morning, we have developed an analytical model using data from our previous Fasken wells using advanced rate transient analysis. This analytical model allows us to have a better understanding of the flow regimes in the fracture network, the hydraulic fracture geometry, as well as the stimulated rock volume. Given the lower commodity pricing environment of repeated well performance that we have already achieved at Fasken and our corresponding cost consciousness, the objectives of our flow back operations now are focused on adequate cleanup of the wellbore and cost efficiency rather than trying to establish an initial production rate. Because of the new objectives of our flow back operations, we have shortened the flow back duration and as a result future Fasken wells will not be brought to the previous test rates. Instead, our new approach will evaluate well performance against our analytical model developed from the performance of the previous 14 wells drilled at Fasken. Based on the rate and pressure data from the 24H, 25H and 26H, our most recent wells completed in the quarter, we have now drilled and completed 17 consecutive wells at Fasken that will meet or beat our 12 Bcf EUR model. And these wells typically deliver their first BCF of gas in about 67 days and claim almost 3.5 BCF in the first year of production. We believe our operational results clearly demonstrate our expertise in the Eagle Ford providing us with multiple year drilling inventory at current commodity pricing and corresponding cost structures. We have demonstrated that our approach in South Texas, which has now been applied across our acreage position in four distinct areas provides a platform for growth as we expand our interest in the South Texas Eagle Ford. Our focus and knowledge of the trend gives us a competitive advantage, particularly when it comes to evaluating new Eagle Ford opportunities due to the scalability and transferability of our drilling and completion design. This was evident in our recent acquisition of approximately 24,000 acres at Oro Grande. We are actively pursuing a strategic partner, who will help us develop our Oro Grande property. We believe this acreage is Fasken-like as it has all the geological parameters that we look for when evaluating projects, including thickness, porosity, TOC and a number of other attributes we look for. 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 Oro Grande. We currently have one operated rig drilling in South Texas core area and Eagle Ford shale. We expect to focus our drilling activity in Fasken and our AWP fields for the remainder of 2015. Quickly summarizing our South East and Central Louisiana areas, in Southeast Louisiana, Lake Washington averaged approximately 3,199 net barrels of oil equivalent per day, a decrease of 11% when compared to fourth quarter 2014 average daily volumes. We performed 7 sliding sleeve zone changes and 13 enhancement activities in the first quarter. We have an inventory of re-completion opportunities and expect to conduct a number of these low-cost high return projects in 2015. In our Central Louisiana properties, which include Masters Creek, Burr Ferry and South Bearhead Creek fields, they contributed 1,791 barrels of oil equivalent per day of production in the first quarter of 2015 and that’s an increase of 13% from fourth quarter 2014 from the same area. Now, I would like to talk a minute about some of the things we are doing to reduce our operating costs. Our operations are focused on streamlining our drilling processes, rationalizing and consolidating our inventory, leveraging our relationships with service providers and vendors, as well as adding high-quality acreage at competitive prices. We have aggressively sought to reduce our drilling and completion costs for 2015. And as Terry mentioned, we have seen some cost concessions take hold quicker than anticipated. We now expect to see cost reductions at the high end of our previously stated goal of 15% to 30%. We continue to aggressively scrutinize our costs. Our cost-cutting initiative is really based on a 3-tier approach. First, change what can be changed. Next, optimize what can’t be changed. And lastly, reduce the cost of goods and services through aggressive bidding and negotiations. You will note that our operating – lease operating expenses were down 16% sequentially. We have negotiated lower prices for goods and services, including chemicals, trucking, labor rates, saltwater disposal costs, and some of the examples of the cost reductions on our lease operating expenses include both labor and repairs and maintenance costs, each by over $200,000 a month from 2014 levels. Additionally, compression costs are down over $150,000 a month compared to 2014 levels. Over in Lake Washington, as an example, we have optimized the use and placement of our boats and barges, which has reduced LOE by over $100,000 per month. Additionally, we have converted our high cost South end facility at Lake Washington into an intermittent operation, which saves us about $100,000 per month. And now for a look at the second quarter and full year 2015, as you can see on Slide 9, we are targeting second quarter production levels of 2.75 to 2.80 MMBoe, including 10.8 to 10.9 BCF of natural gas production, 0.6 million to 0.62 million barrels of crude oil production, and 0.35 million to 0.37 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 maintained our production guidance range of 11.4 million to 11.6 million barrels of oil equivalent and full year plan capital expenditures of $110 million to $125 million. We have included additional operational information in our press release, including operating and capital expenditure guidance for the second quarter and full year of 2015. Our capital budget calls for approximately 10 to 12 wells in our Fasken area and 3 to 4 wells in our Bracken acreage. A portion of the capital expenditure program is in the back half and is discretionary and could be further deferred if necessary. But with our reduced capital budget, on the other side, we have identified additional discretionary projects that can be funded should cash flow strengthen with higher oil and natural gas prices. As we noted, the majority of our capital this year will be deployed to Fasken and our AWP Eagle Ford properties, which yield attractive returns at current prices and corresponding cost structures. With that, I will now turn it back to Terry for closing remarks.

[Terry Swift:]

Thanks Bob. And 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 17 wells we have drilled at Fasken are all tracking at or above their respective 12 BCF EUR tight curves. We continue to drill longer laterals while realizing fewer drilling days and lower per foot drilling and completion costs. As a result of improved well productivity, operational efficiencies and successful cost-cutting efforts, we are able to incrementally improve our results, while maintaining our original capital budget. And finally, our borrowing base was modified from $417.6 million to $375 million. Additionally, our interest coverage ratio was amended from 2.75 to 1.5. We are pleased with the re-determination amount, which was consistent with our prior expectations. Before I open the call up for question-and-answer, I would like to say a few things about the operating environment and how we are thinking about the future. It’s very interesting – it’s a very interesting time for the industry as many operators are still attempting to adjust to the lower commodity price environment and the associated lower levels of profitability. Referring to slide 11 in our presentation, I think it’s important that we note that Swift Energy Company does have a bright future and we are making every effort to see that we are checking the boxes to make sure that we are on track to realize that in future. First of all, rock quality, we believe we have demonstrated in many times over through our results that we have great rock. Second, operatorship, our results clearly demonstrate that we can successfully execute and produce industry leading results. Third, inventory, the recent additions to our Eagle Ford portfolio gives us nearly 230 locations that are economic at current prices. Fourth, cost structure, we have taken significant steps to align our cost structure with the current environment. Cost reduction initiatives to-date are on track and in some cases exceeding our expectations. Fifth, and very importantly, we know we have great assets. We also know we have great people. It seems like our teams now set new technical limits in each well they drill, from the 17 consecutive wells at Fasken to the most recent Bracken wells, our folks are responsible for safely drilling some of the most prolific wells in the trend and we are doing so while focusing our effort on our profitability. We can check that box, too. Finally, having sufficient liquidity as a key to our success, we have realized this and we are focused on it. Liquidity is a tougher thing to have enough of in this challenging market. But we think that we are doing the right things to adjust our cost structure and spending to optimize the liquidity that we have. And we are also carefully monitoring how additional capital alternatives might be deployed to the benefit of our shareholders. And with that, we would like to begin our Q&A portion of the presentation.

[Operator:]

[Operator Instructions] Your first question comes from the line of Will Derrick from SunTrust. Your line is open.

[Will Derrick:]

Good morning guys. First on service cost, talking about – obviously you guys are making some really good progress there. Aside from efficiencies on the operations side, what are the core drivers of these costs really in the last couple of months and going forward...?

[Terry Swift:]

The core drivers on the cost side, I mean we have negotiated new pricing structure with basically all of our service lines on the drilling side from submitting operations to mod to basically all of the service directional drilling. On the completion side, a big negotiation, we have been having are with the fracture stimulation groups on pumping costs, on sand, on the logistics to support the sand. And on the operating side, we have really driven lower our labor and our chemical costs as well as some of our saltwater disposal costs.

[Will Derrick:]

Okay. Thanks. And then, with that what sort of sensitivity do you all think you will see on your savings with oil prices?

[Bob Banks:]

Well, I think there is more room to go. And I think the longer we stay in kind of this lower commodity price environment, the more savings we will be able to achieve. Correspondingly, if oil were to rebound materially, gas were to rebound materially, there will be some upward pressure. But right now, I think the service side of the industry is settling into a lower commodity cost structure environment. Everybody is making their adjustments. We have made our adjustments, they are making their adjustments and so these cost structures will stick around for a while.

[Terry Swift:]

This is Terry. Just another point there. While we had a 16% sequential quarter-to-quarter reduction, it will be very hard to maintain any kind of trend like that. What that says is we got a very good head start on our overall goals. And certainly by the end of the year, we expect some more there. But just be aware that while we think a good bit of that is certainly sustainable for this year, as Bob notes with improving oil and gas prices, you might not be able to sustain or keep all of that.

[Will Derrick:]

Okay, thank you.

[Terry Swift:]

Thank you.

[Operator:]

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

[Noel Parks:]

Good morning.

[Terry Swift:]

Good morning.

[Noel Parks:]

I was wondering at Fasken, your comments about not producing the wells as hard within a Tier 1, just keeping costs down, how might the production curve differ as we sort of look to the model it out with new wells as a result?

[Bob Banks:]

Well, the production curves don’t differ from our 12 BCF model. The only thing – it’s not a question of not pulling them harder, it’s a question of getting the flow back crew and equipment off more quickly. As soon as we believe that we have got enough cleanup and we have got our sand flow back, we just get off now. We had 14 wells that were very identical, very repeatable, so we have become very comfortable at Fasken. We may in other areas choose to leave that flow back equipment on longer to get those IP rates, but at Fasken we no longer see the need to do that. So as soon as those wells are cleaned up, we get the flow back system off, we put the well into production and that saves us on our operating costs side. In terms of the model, I think I mentioned to you in my comments that really, we are returning about 1 BCF in the first 67 days and we are returning in 365 days, almost 3.5 BCF. So you can do the math, that’s the type curve you can expect from all of these wells that are all behaving very similarly now.

[Terry Swift:]

Yes. This is Terry. Another way to look at it is you actually – as Bob notes, the longer you test these wells and the longer you clean them up, the more money it cost. And because we now got quite a good history and knowing where we can stop spending money, we stop spending money. And it’s very significant savings in the field we are talking a couple of hundred thousand dollars a pad, something like that. So we are taking that. Now we are not taking that in the sense of losing any important data. We went through that analysis. We are able to look at the pressure drops and the actual flowing pressures through the testing that we have and do the equivalent of I guess what you call a four point analysis in conjunction with the rate transient analysis. And based on that we know we are on track.

[Noel Parks:]

Just trying to understand, so if you were drilling in the Eagle Ford and almost say at AWP, would you implement similar practices going forward or is there enough variability in that part of McMullen that you would be doing it more like you used to?

[Bob Banks:]

I think in McMullen, we are pretty close to being to a point where we can do the same rate transient pressure analysis, four point review. And of course, we are also logging these wellbores, don’t forget that. So we can see exactly what kind of rock we went through compared to the other wells, also. So I think wherever we are doing all of those things, we are going to stop spending as much on testing and get the wells under the line and know that we are going to rely on this wealth of historical data to assess the productivity of the well. You go to a new area like Oro Grande or Uno Mass [ph] or to the extent that we do something more on the technical edge, maybe a lot more sand or some change. You might find us go back and test a little bit more aggressively. But I think in our core areas, where we have already demonstrated the technology and use of it and have history, you are going to see us cutting our testing cost as well as every other cost we can cut.

[Noel Parks:]

Great. And actually about Oro Grande, just with the couple of months since you acquired it, do you have any better sense of either your expectations there or just as you have gotten your hands dirty with a little bit more just what we can look forward to?

[Terry Swift:]

Well, I think with every well we drill in Fasken and every well we drilled over in South AWP, I think, we just get more and more confident about the technology and the application of it. Oro Grande is going to be no different. We know the raw quality. Certainly, in portions of the play, we can see where others went in very early and tried to complete wells even without 3D seismic. So, they weren’t in zone, they certainly weren’t able to target the brittle zone without that kind of technology. We are going to go in there with the right technology. We are going to go in there with the results that we have seen at Fasken and try to achieve them in Oro Grande. I am particularly excited about that.

[Noel Parks:]

Great. That’s all for me.

[Terry Swift:]

Thanks, Noel. Thanks.

[Operator:]

[Operator Instructions] Your next question comes from the line of Adam Leight from RBC Capital Markets. Your line is open.

[Adam Leight:]

Hey, good morning everybody.

[Terry Swift:]

Good morning, Adam.

[Adam Leight:]

This is probably for Alton, but Terry, feel free to chime in. On your liquidity and balance sheet, thoughts on first the fall borrowing base re-determination, I guess that’s the [indiscernible] with the rest of the questions?

[Alton Heckaman:]

Yes. As we indicated, Adam, the reduction we had of about 10% was in line with our expectations. As you know, the borrowing base at 417 had that automatic reduction from the Saka joint venture we did in the middle of 2014. And so when you hit the 417 back in November, was not at the high end of what we could have achieved. So, we feel comfortable with the 375. No one with our look forward is as far as liquidity is needed from the bank lines. So, I think we are pleased with that. And the amendments, we were able to achieve working with the banks.

[Terry Swift:]

Yes, this is Terry. To add a little bit more color to that and kind of look forward to the rest of the year, we clearly took the initial steps that I think everyone would expect us to take relative to liquidity. We significantly reduced our capital budget for this year. We then began the aggressive cost-cutting and LOE and G&A and have pretty much achieved the initial efforts and that’s ongoing. And then we needed to make sure that we were continuing to develop and get the kind of test that we need from these assets or high-quality assets in Fasken, South AWP and other areas that we have. So, first quarter here, we think we have delivered again to show that those assets are certainly high quality and that we have a team that can execute. The next step, of course, was the borrowing base and we have now done that here for the spring. But in terms of line of sight for the next 2 to 3 years and how you get through this commodity pricing environment, we are working on those plans. We will be delivering those plans. I think they are very critical in terms of the company growing its assets, maintaining the assets first and growing them. And I think as you would well note that with the current commodity price environment, you really don’t want to be using exclusively a borrowing base to kind of get that growth. So, whether it’s improved commodity prices, whether it’s the marketplace providing capital and other ways, we are looking at every option and we will be moving out of that last box and getting it checked to ensure that we have the liquidity to get through this environment. And said a different way, I don’t think that the fall borrowing base re-determination that I would wait till that time to show you how I have checked the box.

[Adam Leight:]

I appreciate that. So, how do you feel about having a revolver, at least for the time being, versus replacing it with something else? And then as you look at the balance sheet, thoughts on dealing with the nearer term bond maturities as opposed to the entire debt structure? I will start with that.

[Terry Swift:]

Yes. I think just looking at it strategically the way for Swift Energy Company to maintain its assets and create value is to increase its EBITDA. And in so increasing the EBITDA, I think that’s the way that we de-lever the company over the next 2 to 3 years. We clearly have the assets to do that. We have got the teams to do that. We clearly can see the mid ‘17 notes and how they factor into it and that’s part of our planning and part of our review. We certainly don’t want to ignore that. Our bondholders are very important to us and are part of the solution as we go forward. But that said, we think the assets are strong enough to deliver the EBITDA in the current strip price environment. And I think, what you want to see us do is develop a plan that shows us doing that. And in that context, you are – I wouldn’t use a bank revolver through a 2 year to 3 year period no matter what, to try to do that. So we are going to look at combinations and we are looking at combinations. There is a significant amount of money in the market that is providing alternatives, including joint ventures and transactions, drillcos. We have talked about that recently and we think we have got properties that fit that very well. So we will also be complementing any strategy we deploy with drillcos or joint ventures.

[Bob Banks:]

And finally, I would like to add, that’s not new to Swift Energy Company, we have had joint ventures in the past with very significant operators, very significant financial sources and most recently Saka out of in Indonesia last year.

[Adam Leight:]

So – and we spoke a few weeks ago, I thought that the cadence of action was kind of what reserves get the borrowing base redetermination and then announced whatever plan there was going to be on balance sheet and liquidity, so can we expect something in the near future that addresses that?

[Bob Banks:]

Yes. As we spoke a few weeks ago, Adam the key focus was on the borrowing base. We have checked that box and absolutely we are looking at all options, considering all the alternatives and as I think we probably said a couple of weeks ago, it’s not one particular action, but probably going to be a sequence of events that we will absolutely share with the public once we sort of get it lined out. So the good thing is we have got good assets, we have got options and we are evaluating it, so we take all the right steps.

[Terry Swift:]

And just as a final comment on that, as you can well appreciate that there are many different combinations that could get to similar places. And in order to affect the optimum outcome for the company, we are going to look at all of those and to the extent that you actually find one that you think is best, you need to negotiate that to the benefit of the company. And we would not want to be talking about those negotiations in the public view. Nonetheless – and negotiations, you don’t want to talk about timing around them either publicly. But I think it’s fair to say that we will check that box sooner rather than later. And that we will not be waiting to the fall to use a fall borrowing base as the liquidity would provide line of sight. We think that’s highly unlikely. I guess we lost Adam or we answered his question?

[Alton Heckaman:]

Thanks, Adam.

[Operator:]

Your next question comes from the line of William Adams from Advisory Research. Your line is open.

[William Adams:]

Hey, good morning. Can you update us on your – any update on your hedging activities?

[Alton Heckaman:]

Yes. We continue to monitor that very actively and look at some opportunities to lock in some of these prices. Clearly, the time to do that is in strength and we are seeing that on the crude oil side. So we don’t currently have any hedges that we put in place. But we see some upward movement and are evaluating that on a regular basis.

[William Adams:]

Okay. And given where your bonds are trading would you all consider buying those back and just not necessarily retiring them, but just hold them as an investment?

[Alton Heckaman:]

We are looking at all options related to our balance sheet and our liquidity and that would be one of the options that would be out there that we are looking at.

[William Adams:]

Okay. Thank you.

[Operator:]

Your next question comes from the line of Owen Douglas from Baird. Your line is open.

[Owen Douglas:]

Good morning and thanks for taking my questions. I wanted to start off asking about the Oro Grande, you guys mentioned you were going to be developing that and seeking a partner, are you thinking of proportionate and similar terms to what you did involving Fasken in that Saka structure, I think you guys sold about a third of that interest, right?

[Terry Swift:]

Yes. And Saka I think it was 36%. And there is I think a material difference in Fasken versus Oro Grande, yes. Fasken actually had a fairly significant infrastructure already in place, already had approved producing assets there. And in that regard, Oro Grande is more of a Greenfield opportunity. But that also means it’s got a lot of upside, and to that extent we have a much more significant development that can be done there. Fasken was, I think about 8,000 acres, whereas the Oro Grande area is 24,000 acres. Will all 24,000 be like Fasken, we don’t know. That’s the thing we do in this business as we go out and determine what the best portions are. It’s also probably a better 3D environment than Fasken. Fasken, we actually got started in the early days before we had 3D there. Fasken being a little bit shallower and of course, now we have got our cost structures way, way down. Oro Grande, it will take us four or five wells to get in there and get the cost structures down. So we are looking for what I would say a strategic partner that’s fully aligned with us, which is similar to what we did with Saka. And in that regard, we are not looking to drill one well or two wells. We are looking for a full program in the Eagle Ford and we think the Oro Grande asset certainly fits that from a strategic view.

[Owen Douglas:]

Okay. And with Saka, I believe that you guys received a certain amount of cash upfront, how do you guys think about that versus a drilling carry with regards to Oro Grande?

[Terry Swift:]

I think it’s similar to other things we said, when you are doing negotiations, you don’t want to do them in the public sector and there are different structures that could be brought to bear, all of which could make sense to Swift Energy Company. Our most important objective is a strategic development of the Eagle Ford. 80% to 90% of all of our capital is going there, so Oro Grande will play a very strategic role in our future. It’s most important that we have a strategic partner that has aligned with us, not just in Oro Grande but other things we might do in the gas window might give that partner an edge in doing a deal with us.

[Owen Douglas:]

Okay, understood. And shifting gears for a second, in the press release you guys noted that the ABL revolving credit facility, some of those covenants are revised and now there is a maximum secured leverage test, quickly, is that test just on the sort of first lien test or is that going to be anything that has a lien on the collateral?

[Alton Heckaman:]

It’s related to any secured debt, so it will be the total. And again, our current plan doesn’t show any of those covenants being an issue for at a minimum the rest of 2015, so.

[Owen Douglas:]

Got it. Understood. But that means that there is three times leverage covenant that would apply to second lien debt or other junior liens as well?

[Alton Heckaman:]

That would be correct.

[Owen Douglas:]

Got it. And I think you noted that there is going to be a three times test for 2015 and lower thereafter, can you give me a sense for the cadence of that step down and as well as the levels we should test with?

[Alton Heckaman:]

Actually, more granular detail will be in the Q, so it’s probably best to read – these things are a little bit complicated, but the Q that we will file this afternoon will have a little more granular detail in their release to the public, so...

[Owen Douglas:]

Great. Thanks.

[Alton Heckaman:]

Thank you.

[Operator:]

There are no further questions at this time. I will turn the call back over to the presenters.

[Terry Swift:]

Okay. We would like to thank you for joining Swift Energy Company during our first quarter conference call. Thank you.

[Operator:]

This concludes today’s call. You may now disconnect.