SilverBow Resources Inc (SBOW) 2015 Q1 法說會逐字稿

Good morning. My name is Nicole and I'll be your conference operator today. At this time I would like to welcome everyone to the Swift Energy Company first-quarter 2015 earnings conference call.

(Operator Instructions)

Thank you. Mr. Atkinson, you may begin your call.

Good morning. I'm 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'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 our 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 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'm pleased report that we achieved quarterly production of 3.06 million barrels of oil equivalent, which was above our guided range of 2.92 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 redetermination 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're 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're able to incrementally improve our commercial results, while maintaining our original capital budget. We're going to focus more on each of these highlights at the end, and I will make a few comments on what we're 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.

With that I will turn the call over to Alton.

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, the 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: oil and gas sales were $67 million, before the $1 million in price risk gains and other income; and adjusted net loss of $36.5 million, or $0.83 per diluted share, which excludes the effects of our non-cash ceiling test right down.

As noted in the earnings release, we recorded a $502 million pretax ceiling test write-down in the first quarter due to changes in our reserves pricing, product mix, and development timing, resulting in a reported GAAP net loss for the first quarter of 2015 of $477.1 million, or $10.79 per diluted share.

Our controllable cost and metrics for the quarter include: general and administrative costs came in at $4.10 per BOE and included some one-time reduction in workforce charges; lease operating expenses came in at $6.21 per BOE; transportation and processing costs were $1.74 per BOE; DDNA was $19.81 per barrel; interest expense was $5.95 per BOE, and severance and ad valorem taxes were 7.6% of oil and gas sales.

Our effective income tax rate for the quarter was 14.3%, as we reduced the tax benefit attributable to our book loss with a valuation allowance against our deferred taxed asset in accordance with applicable GAAP accounting rules. Cash flow before working capital changes for the quarter came in at $9.3 million, while EBITDA was $26.3 million for the quarter. Quarterly CapEx, on an accrual basis, was below guidance at $28.4 million before a $3.7 million non-cash reduction related to our asset retirement obligations.

During the quarter we completed several steps to reduce our cost structure including a significant reduction to our corporate headcount, renegotiation of our corporate office lease, reducing both square footage and cost significantly, and proactively took other steps to reduce all other corporate G&A and field operating expenses. As mentioned, first-quarter G&A includes some one-time charges related to completing these steps, but, and more importantly, the initiative provides for prospective sustained lower overhead and operating costs.

As Terry noted, our borrowing base on our bank line of credit was reduced by 10% to $375 million as part of our scheduled semiannual redetermination in line with our expectations. We also worked with our bank group to amend several covenants, including a reduction of our interest coverage ratio from 2.75 to 1.5 times our trailing 12-month EBITDAX. Given the current pricing environment, we consider this to be very favorable outcome that ensures we have the liquidity to continue our operations as planned.

On slide 8, you'll see a breakdown of our debt maturity schedule, and as you can see, our nearest maturity is not until June of 2017. And as always, we've included additional financial and operational information and guidance in our press release.

With that I will turn it over to Bob.

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.

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 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 include 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 2014. We are currently producing just over 150 million cubic feet per 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 and 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 we're starting to be fully implemented. We're 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 one year without a lost-time accident. We love to talk about the strides we're making the streamlining our activities and driving operational efficiencies, but we can never lose sight of the fact that safety is the 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 and the fracture network, the hydraulic fracture geometry, as well as the stimulative rock volume. Given the lower commodity pricing environment, our repeated well performance that we've already achieved at Fasken, and our corresponding cost consciousness, the objectives of our flowback operations now are focused on adequate cleanup of the well bore, and cost efficiency, rather than trying to establish an initial production rate.

Because of the new objectives of our flowback operations, we have shortened the flowback 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 [cume] 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 designs. This was evident in our recent acquisition of approximately 24,000 acres at Oro Grande. We're 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 in Eagle Ford shale. We expect to focus our drilling activity in Fasken and our AWP fields for the remainder of 2015.

Quickly summarizing our southeast 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 seven sliding sleeve zone changes and 13 enhancement activities in the first quarter. We have an inventory of recompletion 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're 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 three 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 lease operating expenses were down 16% sequentially. We have negotiated lower prices for goods and services including chemicals, trucking, labor rates, salt water 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 per month compared to 2014 levels.

Over in Lake Washington, as an example, we've 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 look at the second quarter and full year 2015, as you can see on slide 9, we're 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 to 0.62 million barrels of crude oil production, and 0.35 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 to 11.6 million barrels of oil equivalent, and full-year planned capital expenditures of $110 million to $125 million. We've 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 can 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 flows 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.

Thanks, Bob. I will summarize today's call as follows: Our enhanced drilling and completion designs continue to improve the productivity of our wells at all our South Texas Eagle Ford properties. The last 17 wells we've drilled at Fasken are all tracking at or above their respective 12 Bcf EUR type 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're pleased with the redetermination amount which was consistent with our prior expectations.

Before I open the call up for questions and answers, I'd like to say a few things about the operating environment and how we're thinking about the future. 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're checking the boxes to make sure that we're on track to realize that future.

First of all, rock quality. We believe we've demonstrated, and 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've 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're doing so while focusing our effort on our profitability. We can check that box too.

Finally, having sufficient liquidity is a key to our success. We realize this and we're focused on it. Liquidity is a tougher thing to have enough of in this challenging market, but we think that we're 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'd like to begin our Q&A portion of the presentation.

(Operator Instructions)

[Will Derek], SunTrust

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

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

Okay, thanks. And then with that, what sort of sensitivity do think you'll see on your savings with oil prices?

Well, I think there is more room to go. And I think the longer we stay in this lower commodity price environment the more savings we'll be able to achieve. Correspondingly, if oil were to rebound materially, gas were to rebound materially, there would 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've made our adjustments, they are making their adjustments, and so these cost structures will stick around for a while.

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.

Okay. Thank you. Noel Parks, Ladenburg Thalmann.

Good morning. I was wondering at Fasken, your comments about not producing the wells as hard with an eye to just keeping costs down. How might the production curve differ as we look to model it out with new wells as a result?

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 flowback crew and equipment off more quickly. As soon as we believe that we've got enough cleanup and we've got our sand flowback, 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 flowback equipment on longer to get those IP rates, but at Fasken we no longer see the need to do that. As soon as those wells are cleaned up, we get the flowback system off, we put the well into production, and that saves us on our operating cost side.

In terms of the model, I think I mentioned to you in my comments that really we are returning about a Bcf in the first 67 days and were returning -- and 365 days almost 3.5 Bcf. You can do the math. That is the type curve you can expect from all of these wells that are all behaving very similarly now.

Yes. This is Terry. Another way to look at it is if you actually -- as Bob notes, the longer you test these wells and the longer you clean them up the more money it costs, and because we now have got quite a good history of knowing where we can stop spending money, we stop spending money. And it's very significant savings in the field. We're talking a couple hundred thousand dollars a pad. Something like that. So we're taking that.

Now we're not taking it in the sense of losing any important data. We went through that analysis. We're able to look at the pressure drops and the actual flowing pressures through the testing that we have and do the equivalent of what you would call a four-point analysis in conjunction with the rate transient analysis. And based on that we know we're on track.

Just so I understand -- so if you are 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?

I think in McMullen we're pretty close to being to a point where we can do the same rate transient pressure analysis four-point review, and of course we're 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're going to stop spending as much on testing and get the wells into the line and know that we're going to rely on this wealth of historical data to assess the productivity of the well.

If you go to a new area like Oro Grande or Uno Mas 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've already demonstrated the technology and use of it and have history, you're going to see us cutting our testing cost as well as every other cost we can cut.

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

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 rock 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 end-zoned, they certainly weren't able to target the brutal zone without that kind of technology. We're going to go in there with the right technology. We're going to go in there with the results that we've seen at Fasken and try to achieve them in Oro Grande. I'm particularly excited about that.

Great. That's all for me.

(Operator Instructions)

Adam Leight, RBC Capital Markets.

Good morning, everybody. Question probably for Alton, but Terry feel free to chime in. On your liquidity and balance sheet, thoughts on first the fall borrowing base redetermination, I guess that is just first part to the rest of the questions.

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 million had that automatic reduction from the Saka joint venture we did in the middle of 2014. And so we knew that the $417 million back November was not at the high-end of what we could have achieved. We felt comfortable with $375 million knowing what our look-forward is as far as liquidity is needed from the bank line. So I think we are pleased with that.

And the amendments we were able to achieve working with the banks.

This is Terry. To add a little bit more color to that and 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 than began the aggressive cost-cutting in LOE and G&A, and have pretty much achieved the initial efforts and that is 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. First quarter here we think we've delivered again to show that those assets are certainly high-quality and we have a team that can execute.

The next step, of course, was the borrowing base and we've now done that here for the spring. But in terms of line of sight for the next two to three years, and how you get through this commodity pricing environment, we are working on those plans. We'll be delivering those plans. I think they're very critical in terms of the Company growing its assets, maintaining the assets first, and then growing them. And I think as you would well note that with the current commodity pricing environment you really don't want to be using exclusively a borrowing base to get that growth.

So whether it's improved commodity prices, whether it's the marketplace providing capital in other ways, we are looking at every option and we will be moving now to 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 redetermination that I would wait until that time to show you how I've checked the box.

I appreciate that. So how do 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'll start with that.

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 is the way we delever the Company over the next two to three years. We clearly have the assets to do that. We've got the teams to do that.

We clearly can see the [mid-2017] notes and how they factor into it. That is 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 I wouldn't use a bank revolver through a two to three year period no matter what to try to do that.

We're going to look at combinations and we are looking at combinations. There's a significant amount of money in the market that is providing alternatives. Including joint ventures and transactions, drill co's, we've talked about that recently. We think we've got properties that fit that very well. We will also be complementing any strategy we deploy with drill co's or joint ventures.

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

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

Yes. As we spoke a few weeks ago, Adam, the key focus was on the borrowing base. We've checked that box. And absolutely. We are looking at all options and considering all of 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 get it lined out.

The good thing is we've got good assets. We've got options. And we are evaluating it so we take all the right steps.

Well, and just as a final comment on that, as you can well appreciate, 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 until the fall to use a fall borrowing base as the liquidity would provide line of sight. We think that is highly unlikely.

I guess we lost Adam or we answered his question?

William Adams, Advisors Research.

Good morning. Can you update us on any update on your hedging activities?

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're seeing that on the crude oil side. We don't currently have any hedges that we've put in place, but we see some upward movement and are evaluating that on a regular basis.

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

We're 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're looking at.

Okay. Thank you.

Owen Douglas, Baird.

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

Yes, Saka, I think it was 36%. There is, I think, a material difference in Fasken versus Oro Grande. Fasken actually had a fairly significant infrastructure already in place, already had crude producing assets there. 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 is 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've 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. We are looking for what I would say a strategic partner that is fully aligned with us, which is similar to what we did with Saka. And in that regard we're not looking to drill one well or two wells, we're looking for a full program in the Eagle Ford and we think the Oro Grande asset certainly fits that from a strategic view.

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

I think it similar to other things we said that when you are doing negotiating 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 is most important that we have a strategic partner that is 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.

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

It's related to any secured debt. So it would 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.

Got you. Understood. But that means that this 3x leverage covenant, that would apply to second lien debt or other junior liens as well?

That would be correct

Got you. And I think I had noted that it's going to be a 3x test for 2015 and lower thereafter. Can you give me a sense for the cadence of the step down and as well as the levels which the test would -- ?

Actually, more granular detail will be in the Q, so it's probably best to -- these things are a little bit complicated, but the Q that we'll file this afternoon will have a little more granular detail in there released to the public.

Okay. Great. Thanks.

Thank you.

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

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

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