SilverBow Resources, Inc.
Q4 2014 Earnings Call Transcript

Published: 26 Feb 2015

[Operator:]

Good morning. My name is Beth and I will be your conference operator. At this time, we'd like to welcome everyone to the Swift Energy Company's Fourth Quarter 2014 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, you will have an opportunity to ask questions. [Operator Instructions] Doug Atkinson, you may begin your conference.

[Doug Atkinson:]

Thank you, Beth. Good morning. I am Doug Atkinson, Manager of Investor Relations. Welcome to Swift Energy's fourth quarter 2014 earnings conference call. Joining today’s call is Terry Swift, CEO; Alton Heckaman, Executive Vice President and Chief Financial Officer; Bob Banks, Executive Vice President and Chief Operating Officer as well as Steve Tomberlin, our 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 complete our prepared remarks, we have prepared a slide presentation which is available on our Web site within the Investor Relations section. Before I turn the call over to Terry, I’d like to call you 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.

[Terry Swift:]

Thank you and good morning. Thanks Doug and we’re very pleased to be here with call and I am going to quickly cover the highlights of the quarter before we turn the presentation over to Alton our CFO who will talk about quarterly and full year financials, I’ll then make a few comments on the EMP environment and what we’re doing to position ourselves to successfully navigate through what our certainly turbulent times. After that our Chief Operating Officer, Bob Banks will speak to our operations and then I’ll make a few closing remarks before we turn it up over to our question-and-answer period. If you start with Slide 3, I would like to note that despite the very difficult environment that we’re currently operating in I am pleased to be able to report that we achieved quarterly production of 3 million barrels of oil equivalents which was above our guided range of 2.81 to 2.91 million barrels. Full year production in the Eagle Ford where we spent roughly 85% of our capital in 2014 actually increased 32% despite the sale of production to our joint venture partner Saka. If you exclude the impact of our joint venture the Eagle Ford production as an operation would have increased 46% for the year. We drilled 36 wells in the Eagle Ford in 2014 and 14 of the last Fasken wells or better said 14 consecutive wells in Fasken have averaged over 20 million cubic feet per day of initial production. Based on the performance at Fasken throughout the year, we are able to increase the Fasken per well reserved booking by about 20%. Our process of selectively perforating and grouping our completion air holes in the most optimal fashion continuous yield better performance and greater EUR Our two most recent Bracken wells and our AWP gas acreage averaged over 5,000 barrels of equivalents per day of initial production. These wells represent the highest initial rates for wells drilled and completed in the Company’s Eagle Ford history and in recent history. We acquired an additional 12,500 acres of high quality contiguous Eagle Ford gas acreage at an area we’re called Oro Grande in La Salle County. The lease also contains a one year option to lease an additional 11,850 acres in the McMullen County. We look forward to transferring on enhanced drilling and completion design to the Oro Grande area in the near future and believe property complements our exists asset base extremely well. We reported proved reserves of 194 million barrels of oil equivalent, 59% natural gas and 34% proved developed reserves decline 12% in 2014 primarily due to the joint venture with Saka in our Fasken area, excluding the impact of the sale of reserves to our Fasken joint venture partner year end reserve would have increased 3%. Finally we initiated disciplined CapEx and cost reduction initiatives throughout the Company which I’ll touch on later. We are going to focus more on each of highlight that I have mentioned also give some focus as to what we’re doing strategically to position the Company during the operating environment that we’re currently enduring. Before I turn the call over to Alton, let me also add that much of what we’ve achieved in 2014 is result of strong properties that we own in the Eagle Ford, we’ll detail some of our more important 2015 plans for the Eagle Ford as we continue the presentation. That said I want to be very clear that we’re very aware of the commodity environment and the various opportunities as well as threats of continued low oil and gas prices. We will manage and operate in such way as to seek the best outcomes for all of our stakeholders. Alton?

[Alton Heckaman:]

Okay, thanks Terry and good morning everyone. I’ll summarize some of our financial results for the fourth quarter 2014 and for those following along with our presentation summary tables of fourth quarter and full year of financial and operating highlights can be seen on Slide 4, 5 and 6. As Terry mentioned our fourth quarter 2014 production was 3 million BOE which was above our 4Q guidance in fact all three components oil, natural gas liquids and natural gas were above the 4Q14 guidance. As to overall our financial results for the fourth quarter 2014, oil and gas sales were 106 million prior to the 4.1 million of gains related to our ongoing price risk management program. We posted an adjusted net loss of $0.25 per diluted share which excludes the effects of our non-cash ceiling test write-down. As noted in the release, we recorded a non-cash 445 million pre-tax, 287 million after tax, ceiling test write-down in the fourth quarter due to changes in our reserves pricing, product mix and development timing as more fully described in the press release. As to our controllable cost and metrics for the quarter, general and administrative cost came in at $2.02 per BOE which was well below guidance due to a lowered deferred compensation accrual in the fourth quarter. Lease operating costs were below guidance at $7.53 per BOE, transportation and processing costs were $1.58 per BOE, DD&A was slightly above guidance at $22.17 per barrel, interest expense was below guidance at $5.97 per BOE and severance and ad valorem taxes were with guidance at 7.7% of our revenues. Our effective income tax rate for quarter was 35.5%. Cash flow before working capital changes for the quarter came in at 44.6 million while EBITDA was 68 million for the quarter. Quarterly CapEx on an accrual basis was $70 million. We currently have natural gas hedges covering a small amount of our estimated first quarter 2015 production and as always complete and timely details of Swift Energy's price risk management activities can be found on the Company's web site. As we previously mentioned, our focus in 2015 is to reduce cost and align our capital spending with our expected cash flows. We have significantly reduced our corporate head counts since the first of the year, renegotiated our corporate office lease and are proactively taking other steps to reduce other corporate G&A and field operating expenses. We’ve also reduced our capital spending targets for 2015 to levels move in line with our internally generated cash flow. Our priorities continue to be financial discipline first and growth second. On slide 7, you will see a breakdown of our debt maturities schedule. As you can see our debt maturity is not until June of 2017. As of December 31, we had roughly 220 million in availability on our revolver. We’ve included additional financial and operational information in our press release including guidance for production and capital expenditures for the first quarter and full year 2015. And with that, I’ll turn it back over to Terry.

[Terry Swift:]

Thank you, Alton. And as you can see on Slide 8, we have pursued a number of initiatives to address the current market environment. First, we revised our capital budget to the range of 110 million to 125 million. This is roughly 70% below our 2014 capital spend and at these levels we’re targeting production to be down between 6% to 8%. You’ll notice that we have refined the lower end of our projected CapEx spend from 100 million up to 110 million. Second, we’ve cleared out a work force reduction that is aligned with our propose spending. Our headcount is down 25% since early 2014 which equates to about $15 million to $20 million in annual savings. We’ve also began on aggressive LOE reduction initiative in which Bob will speak later on in details of that. Third, we’ve aggressively start to reduce our drilling and completion cost and expect to realize price concessions from our vendors anywhere from 15% to 30% in 2015. And fourth much of our drilling focus in 2015 will be at Fasken and AWP, which still provide attractive rates of return in current prices and reduce our development cost by taking advantage of existing infrastructure and operating personnel. These initiatives will put us in an excellent position to whether the current market downturn and to efficiently accelerate and take advantage market opportunities when commodity prices recover. Finally is important to understand our management team and the Board are proactively focused on behalf of all the company constitutes. Furthermore, we just recently added two new Board members and I am pleased to welcome Ron Saxton and Bill Bruckmann to the team. Ron and Bill strengthen our existing Board by bringing with them a significant amount of specialize banking financial market transactional and operational experience. We believe we’ve moved quickly and decisively in response to the severity of the downturn. That being said, we will also take additional steps if commodity prices continue to languish. I’m now going to turn it over to Bob Banks, our Executive Vice President and Chief Operating Officer to go over the operational highlight for the quarter.

[Bob Banks:]

Thanks, Terry. Today I will discuss the fourth quarter and 2014 activity including our year-end 2014 proved reserves, production volumes, our recent drilling results and our plans for 2015. At year-end Swift estimated proved reserves were 194 million barrels of oil equivalent with a PV-10 value of $1.9 billion, reserved decline 125 in 2014 primarily due to the joint venture with Saka and Fasken. Excluding that joint venture reserves would have increased 3% year-over-year. Our year-end 2014 PV-10 is down roughly 20% due to lower realized oil prices, the sale of a portion of the Fasken properties, changes in the product mix and a revision of our forward development plan, a reserve reconciliation table on Slide 9 of the quarterly presentation. Our total proved reserves were roughly 60% gas and 40% liquids with over 80% of our proved reserves located in South Texas. As Terry mentioned earlier, we increased Fasken per well reserve bookings by 20% in 2014 with roughly year production in the books from our enhanced wells at Fasken many are averaging roughly 3 Bcf of cumulative production in just their first year. While it's still early, many of these wells are tracking above their 12 Bcf type curve. The corporate wide production Swift Energy’s production during the fourth quarter of 2014 totaled 3 million barrels of oil equivalent above our expected range of outcomes. Production was comprised to 59% natural gas, 27% crude oil and 14% NGLs. Fourth quarter production was slightly lower than fourth quarter 2013 production of 3.09 million barrels of oil equivalent, however, and factoring end of production attributable to the joint venture into Fasken with Swift Energy production would have increased 14% year-over-year. Fourth quarter production was flat with third quarter 2014 levels. In our South Texas core area, fourth quarter 2014 production of 27,247 net barrels of oil equivalent per day increased 2% when compared to third quarter 2014 production in the same area and 3% when compared to fourth quarter 2013 volumes. Gross volumes in Fasken in the fourth quarter which included production saw the softer as part of the joint venture increased to 110 million cubic feet a day compared to 32 million cubic feet a day a year ago. We drilled eight operated wells during the quarter and to the Eagle Ford Shale in the company South Texas core area. Four of those wells were drilled in McMullen County and four were drilled in Webb County. In Fasken, we drilled our longest lateral today of 7,614 feet which is over a 100 foot longer than our previous record, compared to 2013 our 2014 average Fasken lateral length increased at most 1300 feet or 22% and our frac stages increased by 4 or 26%. Additionally we’re now drilling all our Fasken wells in a new tighter 30 foot target windows compared to our previous 40 foot target window. Earlier this morning, we published specific performance data on all well brought online in the Eagle Ford during the quarter in our quarterly press release and I refer you to that data for more details on our results. We currently have one operated rig in South Texas in the core area of the Eagle Ford shale. We expect to focus for drilling activity in Fasken and our AWP Fields in 2015. We were also successful in leasing an additional 12,000 acres in La Salle County. This transaction which I will talk more about later contains a one year option to lease an additional contiguous 11,850 acres located just across the county line in McMullen. Most of our acreage in South Texas is held by production in areas that are not held we have been mostly successful in extending our lease holds. Quickly summarizing our Southeast and Central Louisiana areas in Southeast Louisiana Lake Washington average approximately 3,584 net barrels of oil equivalents per day, a decrease of 2% when compared to third quarter 2014 average daily volume, we performed three recompletions and 37 enhancement activities in the fourth 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 Bay De Chene field production of 116 net barrels of oil equivalent per day was down 26% when compared to third quarter 2014 production levels due to natural declines on low levels of operational activity. Our Central Louisiana properties which includes Masters Creek, Burr Ferry and South Bearhead Creek fields, contributed 1,592 barrels of oil equivalent per day of production in the fourth quarter 2014, that’s a decrease of 12% from the third quarter of 2014 production in the same area, again primarily due to low activity levels and natural declines. Now I would like to talk a minute about some of the things that we’re doing on the drilling and completion side, along with improving our balance sheet liquidity another primary goal of ours in 2014 was to demonstrate the viability of our technical approach to developing the Eagle Ford shale. Our results in 2014 demonstrate that it combination of longer laterals that are steered in a tighter zone of the highest quality raw along where a customized completion that optimally perforates and group our frac intervals with greater volumes of proppant are very important factors in delivering the improved well performance that we’re seeing. And Fasken our last 13 gas wells have delivered normalized cumulative production of 1 Bcf in the first 60 to 90 days. In the AWP area our last two liquids rich frac internals recorded average initial production rates of 5,280 barrels of oil equivalent per day and each had delivered normalized cumulative production of 1 Bcf equivalent in the first 70 days and then also in our AWP area our last 7 PCQ enhanced technology oil wells have outperformed earlier wells by 29% in the first 180 days of production. We believe our 2014 operation results clearly demonstrate our expertise in the Eagle Ford providing us with the multiple year drilling inventories at current commodity pricing and corresponding cost structures. We've 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 newly Eagle Ford opportunities due to the scalability and transferability of our drilling and completion design. We believe the 24,000 acres in Oro Grande that we added to have all of the geological attributes that we look forward when acquiring acreage including thickness, porosity and total organic content and it’s an area that was underinvested in using the older technology at the very beginning of the play. 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 at Oro Grande. Now I’d like to talk a minute about some of the things we’re doing to reduce our operating cost, we believe the current commodity price backdrop provides an opportunity for us to become even more efficient in our operations through focused initiatives such as streamlining our drilling processes, rationalizing and consolidating our inventory, leveraging our relationships with service providers and vendors as well as adding high quality acreage competitive prices. We have aggressively sought to reduce our drilling and completion costs for 2015 and we expect to see cost reductions of 15% to 30%. Given the dynamics of our industry we’ve commodity prices continue to languish for an extended period of time and the level of activity within the industry continues to soften, we will most likely see even further cost reductions which will further enhance our returns. We continually and aggressively scrutinize our cost and are constantly finding unique and creative ways to lower our cost structures. For example, we implemented a new and more patient and cost effective recorded system in our first frac stage at the toe of the well which led the savings of roughly $650,000 in the fourth quarter. We also implemented a new engineered procedure for drilling on our frac plugs that is kind of drill out time and half. This time has resulted in savings of $320,000 during the fourth quarter. And now looking to first quarter and full 2015, we’re targeting first quarter production levels of 2.92 million to 2.97 million barrels of oil equivalent including 11.1 Bcf to 11.2 Bcf of natural gas production; 0.65 million to 0.67 million barrels of crude oil production and 0.42 million to 0.44 million barrels of natural gas liquids production. This level of production is based on 30 million to 35 million in capital expenditures for the first quarter. For the full year we are targeting annual production levels of 11.4 million to 11.6 million barrels of oil equivalent based on plan full year capital expenditures of $110 million to $125 million with a focus on drilling activity in the dry gas Fasken area, as well as in the AWP gas in common state properties. A portion of the capital expenditure program is discretionary and can be further deferred if necessary, even with our reduce capital budget for 2015, we have identified additional discretionary projects that can be funded through cash flow strengthen with our oil and natural gas prices. As we noted the majority of our capital next year, we’ll be deployed the Fasken and our AWP properties which yield attractive returns at current prices and corresponding cost structures. With that I’ll turn the call back to Terry for his closing remarks.

[Terry Swift:]

Thanks, Bob and before we open the line for questions, I’ll summarize today’s call. First, enhance drilling and completion designs continue to improve the results we’re observing in all of our South Texas Eagle Ford properties. This has most recently demonstrated our two new wells and our AWP Bracken area measuring a initial production of 5,345 and 5,222 barrels of oil equivalent, roughly 30% to 31% liquid there. We increased our Fasken per well reserve bookings by 20% to 12 Bcf of the well. We now have 160 million cubic feet per day firm committed capacity for natural gas transportation of Fasken and to the extent we reach our maximum capacity there could be additional capacity in the area that all depends on our drilling pace. We continue to realize fewer drilling phase and lower per foot drilling completion cost in all our areas in South Texas. In response to the rapid drop in commodity prices, we have taken several proactive steps to reduce our drilling activity well cost, G&A and LOE including the following; reducing our rig count to one and our capital budget to a range of 110 million to 125 million for 2015, carried out a workforce and administrative cost reduction that’s reduce headcount by 25% compared to a year ago level. Aggressively saw to reduce our well cost and believe will realize cost reduction of 15% to 30% throughout the year and we’ve implemented an LOE reduction program in which cost savings are already being realized. We are taking each of these steps very seriously and will be looking for other ways to optimize every aspect of our operation. We believe these steps will not only make us a more efficient operator, but will position us for future success when commodity prices recover. With that, we’d like to turn the call over to question-and-answer portion. Thank you.

[Operator:]

(Operator Instructions) Your first question comes from the line of Neal Dingmann, SunTrust. Your line is open.

[Unidentified Analyst:]

Good morning, guys. This is Will for Neal. First, looking at well costs, how do you all expect cost to trend -- you talked about it a little bit -- how do you all expect cost to trend down this year, just after conversations with your vendors?

[Bob Banks:]

Well, let me talk about at this way, this is Bob, on the drilling side, we’re seeing across the various product lines, I mean looking at every various part of mining and mud logging and all the services. We’re looking at the 15% to 30% across the differ product ranges right now today. We feel that we’re securing that that type of cost reduction here now, as I’ve said I think a thing was languish a bit, we’ll see further cost reductions throughout the year. On the fracking side, I would say that we’re down right now about 20% from where we were in the third quarter of 2014. As you all recall because of the proppant availability and what not in the fourth quarter frack and completion costs rose, so we’re probably down about 30% from fourth quarter about 20% from where we were in the third quarter. And again in that area as prices continue to languish if they do throughout the year, I think we’ll see further competitiveness on that completion in frac side.

[Unidentified Analyst:]

Thanks. Also looking at the acreage acquisition at Oro Grande and McMullen call, can you all give some more details around the terms of those and whether there is any drilling requirements and just any details in general?

[Terry Swift:]

This is Terry. I’ll give you a little bit of color or granular detail on that Oro Grande is in fact in the trend of some of the best Eagle Ford rock that we know of if we build from Fasken all the way over to the South AWP and you stay principally above the Edwards fault line and on the north side of Edwards reef. You’ll find some really good rock in places either through the seismic and/or though the core dataset we have and we have focused our acreage acquisition on areas where the best rock is, and in addition to that Bob noted, that in this area there have been some early tests not only cores but some early wells using the old technologies and that helped us calibrate so that we understand what can be done today versus what was done five years ago. That said Oro Grande really sits right on the broader of La Salle and McMullen. The acreage on the La Salle side which we point in our press release is principally up thrown of the Edwards fault line and some of the more prospects even what I would call firs stage appraisal type acreage and then the option acreage. We’ve got roughly a year to kind of figure out what the appraisal in the north side going versus that, so we’re very pleased with that. We currently are working all in appraisal and development plan and we should be able to give you more granular detail on that about the second quarter. We liked to actually appraise the property in the second half of 2015 but that’s going to be depending on the outcome of the different development programs we’re looking and possible JV participation in some of those programs. So little early to talk about exactly how we’re going to drill it is absolutely where we wanted to be. The hydrocarbon pore volume or the thickness porosity of gas saturation in this area is well established by core data and it is very-very Fasken like and I would also say that when you look at the gas and place via core data or logs also is very Fasken like, so we’re very happy with it and we did get a position at what I would call in today’s environment we all remember the high heady costs of acreage in the past and I think in this case we’re much more in tuned with the environment. We’re going to keep some of that information tight for a while because we’re still looking at other areas in terms of what you’ve paid for it, but I would say hit that in Oro Grande we worked directly with the mineral owner and we recognized as having the expertise to deliver the kind of wells that they won’t see on their property and so we’re started now with a very good relationship there.

[Operator:]

Your next question comes from the line of Leo Mariani, RBC. Your line is open.

[Leo Mariani:]

Could you guys speak a little bit to how you think about managing the acquisition here and potential future acquisitions, which sounds like you are still in the market for at this point, with just the financial leverage on the balance sheet here in 2015?

[Terry Swift:]

I guess you’re referring to Oro Grande the acreage acquisition?

[Leo Mariani:]

Yes. This and it sounds like you are certainly alluding to the potential for other acreage deals this year. Could you just talk about how you balance spending money on acquisitions versus the current state of the financial leverage?

[Terry Swift:]

Yes, again, for competitive reasons we don’t want to really talk directly about what we’ve got in the acreage for. I think its best said that the our competitive advantage is, is in fact the wells we’ve drilled in Fasken and now the wells we’ve drilled in South AWP and the third mineral owners in the play want those kind of wells drilled on their properties which give us a different kind of advantage going in and seeking to acquire the acreage and we’re only interested in acquiring acreage that can be Fasken like that can be South AWP like and therefore we’re only targeting areas where you have the core data and knowledge to make these comparisons and transfer the technology. In terms of our balance sheet and our ability to do this time it’s still a small portion of our -- acquisition that you're looking at now is fully closed and done with the exception of an option about a year out. So it really has no impact right now on the liquidity going forward, it's got a lot of opportunity for the company in terms of joint venture partners that might come into or what refer to a drill -- we’re going to work through those plans and give you more detail later. As to bolt-on and the play, I think we’ll manage our liquidity and our balance sheet very appropriately, we’re not going to be adding acreage that we don’t think will be drillable and Fasken like in 2015 we’re only going for the highest quality acreage that will actually enhance the value of the company to -- I mean the joint ventures or drill cost.

[Leo Mariani:]

Okay. Just to clarify was that acquisition actually in the budget in terms of your capital here? You spoke about $30 million or $35 million in the first year?

[Terry Swift:]

No, that was last year; we close that out last year and finish this up late in the year.

[Leo Mariani:]

Okay. That was actually okay. Understood. Just in terms of JVs that you are speaking about, could you give us a little bit more color on what type of structures you might the considering?

[Terry Swift:]

Well, I’ll kind of do repeat, last year about this time we talk to you about JV in Webb County and we went out and found Saka, they are very strategic partner and we said before that was done that we only wanted to do JVs that were strategic and increase and we bring immediate value to our transaction. I don’t think that’s going to be any different from that, we don’t want to just do difficult small thing little promoting we’re done, what we’re looking for is a strategic player who wants Eagle Ford gas, Texas has got some of the best gas position in the whole country between the LNG program and projects that are in place as well as the Mexican market that still growing. So we are finding a lot of interest in Texas gas, Texas gas can easily get these markets is not road block like we see in other areas with high differentials to get to the market. So, we’re seeing a lot of folks that are interested in these kinds of opportunities and we’re the operator of choice to do this right now. We’re drilling the best Fasken gas well, now South AWP Eagle Ford wells in the trend.

[Leo Mariani:]

Okay. That is helpful. Are you considering a JV that is to the magnitude of what you did at Fasken? Can you just give us a little bit of color in terms of what you're pursuing?

[Terry Swift:]

Leo, I think it's a little early; again we’re putting the development plans together. I mean over 12,000 acres to almost 24,000 acres of both leased acreage and option acreage is a big chore to put a full-fledged development plan all the way to the markets we’re doing that and how you appraise it. But that said, it is easily 80 locations it could be a 150 locations just depending on the pace of development and how you appraise it. So the extent that we do something this year, I would think it would be with a strategic gas partner not to different than Saka. To the extent that this property trade likes Fasken and well clearly Fasken already had gas production of time, so just different in that regard.

[Leo Mariani:]

Okay. That is helpful. Could you just you clarify current well costs? You guys talked about [some of the] reduction. What are the well costs today at Fasken in AWP gas area?

[Bob Banks:]

Yes, in Fasken we’re down around the mid 6.5 million and -- or we’re at AWP we’re kind of in the $7.5 million to $8 million range.

[Leo Mariani:]

Okay. That is helpful. With respect to the cost savings, you guys talked about $15 million to $20 million of savings. I just want to make sure I understood that. Is that going to be a year-over-year savings in 2015 versus 2014 and does that come from both LOE and G&A? So if we add up LOE and G&A in 2014, should we expect it $15 million and $20 million lower in 2015? How should we think about that?

[Alton Heckaman:]

Yes, I think you should think about it as a cash savings going forward as of the different components, we’re not actually giving specific guidance at this point. Most of those savings of $15 million to $20 million are from the administrative and G&A reduction we’ve done, that’s a tough time to do most of that with personal related as well as contractor related and different things all the way from office rent to pencils we buy, we have just been aggressively reducing our cost and when you look at that and try to allocated to LOE, versus expense G&A, versus maybe some of the capitalize areas you're going to have to give us some time to let you see how that comes out granular. So when point some of the cost reductions were actually greater than the 15 million to 20 million and they were non-cash items, although they will show up on the balance sheet -- on the income statement some of those actually we have in the fourth quarter of this year, I mean of last year and therefore it kind of shows a lower G&A going forward of the expense G&A that you’ll actually see. So, we’re giving you full year guidance and on a cash basis, we fully expect 15 million to 20 million lessen general administrative cost.

[Operator:]

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

[Adam Leight:]

Good morning. On your liquidity, can you give us a sense what you know so far and what your borrowing base might look like after the spring redetermination and whether you are going get some covenant relief off the ratio test?

[Terry Swift:]

That’s a good question for this and fireman and I think realistically what I would like to say is we’re very aware of the low commodity price environment some of the challenges create for all of the folks in the basin and to the extent that we look at our borrowing base and bank line although we don’t expect any near term issues thee. We continue to careful and monitor it. I do believe we’ll go through borrowing base and successfully continue the operations in the budget that we have. I don’t have any doubts that the banks themselves do have pressure today to reduce borrowing basis but we have the assets that I think even with the reductions that might be appropriate with us I don’t have any concerns that we won’t get through that period of time. There are a lot of I guess what I would say new players in the space, we’re getting phone calls, we’re hearing from the investment banks about lots of different financing options that are out there by folks some of which I don’t think anybody seen before, and that just suggest us that there is a tremendous amount of capital ready to come into the sector. We’ve not made any decisions. I don’t want to move too fast. You know the old saying; you won’t be the first not the last, and certainly we’ve got lots of levers to pull. We’re going to take our time to do what’s in the best interest of all constituent.

[Alton Heckaman:]

And ahead of us I am sure you know our covenants specially the coverage ratio is a 12-month rolling computation, so you’ve got some time there, but we’re clearly we’ve been signaled by the banks that they’ve been talking with folks about seeing that coming and we want excited and probably get some covenant relief.

[Terry Swift:]

Well and more color to that, I don’t know that we’ll need it, but we certainly see that the banks are providing that for certain companies.

[Adam Leight:]

Okay. Thanks. You alluded to the other ways you might be able to enhance your liquidity. If a joint venture is probably a little too early, and you're not quite ready for capital markets transactions, is there anything you're thinking about that might be towards the front burner?

[Terry Swift:]

Well the two most obvious things that are in our control we’ve already done or we’re in the process of doing, one is we did reduce the capital budget we’re only doing that to the extent that we still maintain good production from the high quality properties. So we’re watching that. We also have taken these big reductions in G&A and we’re moving down the same path in terms of big reductions we believe we’re going to achieve and now while we and CapEx relative to well cost, so those are things that are somewhat in our control we’re pushing we’re aggressive there. Things that are not in our control, well right now I do see some opportunity out there, there not only are -- I think one of the accolades I heard recently was that make here awhile here Houston, there were more new investors roaming the Isles of nape that were from out of state than we’ve ever seen looking for opportunities that range everything from drill close to joint ventures and we certainly have the opportunity set here for folks that are interested in the Eagle Ford, so I think you’ll see us do some of those things this year from joint ventures. They may not be extremely large but they’ll be accretive to the extent and strategic to the extent that we’re doing.

[Adam Leight:]

Great. The last one for me, in terms of achieving those cost savings, particularly on the G&A side, do you think there will be any upfront costs associated with that or are you just going to be able to start to recognize the decreases of the next couple of quarters and will you be (multiple speakers)?

[Terry Swift:]

Yes, there have been out and you want to speak.

[Alton Heckaman:]

Yes, there will be some costs in the first quarter. Adam good point from a standpoint of reduction and force and some severance type of cost there, but then we’ll clearly have those savings that will kick in after that.

[Operator:]

Your next question comes from the line of Welles Fitzpatrick, Johnson Rice. Your line is open.

[Welles Fitzpatrick:]

I apologize, there are some calls going on, so I'm sorry if you said this, but the new acreage at Oro Grande, how do you guys -- is that a potential to roll into the Saka JV or potentially a new JV or do the under spent wells from the prior operator mean that you guys probably will want to get some of your own enhanced completions in there before going down that JV road?

[Terry Swift:]

Those are great questions, we have updated corporate presentation out there, I’d like to point to slide six gives you little bit more granular detail on our oil ground area. Again it's a almost about 24,000 acres in total of La Salle and McMullen County. You're right on course in terms of it being Fasken like the first and foremost, we’ve got the core data, we see the gas in place according to the core data can be very, very similar in some cases actually greater than Fasken. You're absolutely right that the earliest drilling was done in ’09 and ’10 and some of the early technique while they got out there and got the course and did just some really good initiative test that we’re using the techniques that are available today and with a much higher cost environment back then than it is today. So, should we go out and test it ourselves before we joint venture that just all depends on the nature of the type of transaction that’s available to us. There is a lot of folks that need equity gas for the LNG markets now or need to be up so it will be available, we think with the addition of Oro Grande across our entire Eagle Ford gas portfolio that we could actually develop and operate as much as Bcf a day. So, we think we’re going to be the operator of choice to bring some of these things to and have like also mentioned once again that we worked with the mineral owner on this transaction and we actually have a very good relationship with them, they wanted us to come over there and drill some wells with the new technologies like we’ve done at Fasken. So it's a little early to say whether or not we would have a joint venture or whether we do a drillco or go out there and just a drill a couple of wells to get early stage like Fasken, we’re working through those development. But it is important that you know this was not included in the Saka joint venture in terms of an AMI, although, we certainly would like to work more with Saka and other things and we have a good relationship there. This is not part of the original Saka deal.

[Welles Fitzpatrick:]

Okay. Perfect. It sounds like there are not any take-away issues from the new acreage. Then on the Bracken wells, obviously, you guys have done a great job getting the gas take-away from that area, but is there any -- can you remind me, do you have enough processing capacity to deal with that higher liquid cut?

[Terry Swift:]

Yes, Southcross we’ve been there for a long time when we actually started getting even more comments in Eagle Ford wells we developed a relationship with Southcross they are currently the marketplace made a lots of options, look I think currently we’re going out of the south, but there is different ways to maneuver, if you look at our pipeline that our South Texas you’ll find that really kind of at the crossroads, lots of different pipeline. So there is from discussions about maybe taking that out north in the future but right now there is plenty of processing capacity or can be capacity added via Southcross.

[Operator:]

Your next question comes from the line of Chris Stevens, KeyBanc. Your line is open.

[Chris Stevens:]

Hey, guys. Thanks for taking my call here. What is the depth of the Eagle Ford on your newly acquired acreage and how does that compare to your existing AWP acreage out there? Is there any difference in well costs that you are expecting?

[Terry Swift:]

It's comparable to AWP on the upfront side of the Eagle Ford or the [Edward] fall system Steve it ranges from that a [12/5] in the general area.

[Chris Stevens:]

Okay. Out at Fasken right now, are you fully utilized on your existing take-away capacity and what is the outlook for getting some interruptible this year?

[Bob Banks:]

No, we’re not currently ramped to the 160 something we have not talked about in the first quarter. We did bring three new Fasken wells online, we’re finishing up another four pad. So before too low we will be ramped to that 160, we are in discussions with some pipeline providers to try to get us more capacity to go above our 160 and those discussions are in progress now, but we feel very good about getting additional capacity above our 160.

[Chris Stevens:]

Okay. In terms of your CapEx budget for 2015, do you have an approximate breakdown of how much you'll be spending in Eagle Ford versus other areas and also how many wells you expect to drill and complete this year?

[Terry Swift:]

We’ll have to Bob -- we’ll have to get back with you, but I would say essentially that all the drilling is going to be in the Eagle Ford, all the drilling completion and to the extent that it's in Texas, it's in Eagle Ford and it's generally in development projects there might be some drilling as we discussed on Oro Grande that is currently not classified at development or approving in or book.

[Bob Banks:]

Yes, I mean we have in addition to the four wells we’re finishing up now in Fasken we have probably another eight well drilled in this current environment and the we’ll have probably two to four wells to drill over in the AWP area and that Bakken area.

[Terry Swift:]

Yes, I think I’d also like add that the way we constructed our budget and of course the way we look at the commodity pricing environment, we’re ready to drill much more than certainly in the second half of the year, but our first order of business is the balance sheet and liquidity and I can sure that we’re financially conservative as long as these commodity prices are low.

[Chris Stevens:]

Okay. So is the plan at this point is to drop the rig around mid-year and just complete all the wells in the first half of the year?

[Terry Swift:]

Yes, I mean we have one rig running now. We have a couple of different scenarios that we’re still working through we could have that rig drilled through or we could actually pick up another rig. We’ve been able to negotiate some flexibility on these rigs so we don’ have any long-term commitments. There are rigs available so that buys a little more flexibility whether we want to run two rings for a portion of the year or just only want to run one rig through most of the year and we’re still evaluating that.

[Bob Banks:]

I’d like to add to that, there is a new dynamic and the commodity prices came down or they came down fast -- there was a lag in the drop of drilling cost although drilling cost are now starting to look much more favorable and much more in line with the commodity environment. There was a bigger lag in completion cost so one of the strategies that we’ve been looking at as well as other operators is, okay how can take advantage of these low drilling cost and we’re certainly to any extent that we look at any joint venture activity and complement our drilling program, we want to get out here and drill well in this environment. So we’re pushing to drill joint venture type wells in the second half of the year although we don’t have those plans baked in yet.

[Chris Stevens:]

Okay and just one final question, what’s the commodity mix expected to be like in 2015?

[Terry Swift:]

Well we gave first quarter mix guidance and I don’t think it will be significantly different maybe a little gas here going out into the out quarters, again we’re finalizing all that now which is why we did some high level guidance this time.

[Alton Heckaman:]

Yes, I think first quarter probably the best proxy you use at this point in time.

[Operator:]

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

[Owen Douglas:]

Hi guys. Thanks for taking my question here. I want to drill in a little bit, if you could, on your AWP drilling program. Can you speak a little bit about whether you are going for the oil window, the condensate window, the gas window? Any additional color there would be appreciated?

[Terry Swift:]

Yes, I’ll start and then I’ll let Bob wrap it up fill in any whole with I leave, but AWP has been a core property for the company for over 20 years. It’s a great place to operate, infrastructure is there, pipeline is there, takeaway processing is there, so a lot of issues are already dealt with and we do have lease hold, we’ve got oil in the north, we’ve got condensate and gas and near the center portion and then dry gas at the most southern area. These most recent two wells we’re very excited about, it’s too early so we’re being a little cautious about how we figure out the full development program there, but these are over 5,000 barrel a day equivalent tests, 37% liquids and quite candidly assume more liquid than we were anticipating although we clearly have the capacity and we’ve been able get them on production, but I do think that the economics of these wells are actually much better than the economics of a general oil well in the Eagle Ford trend at these current oil prices. We would actually prefer to defer certain of the oil properties until we see the oil prices getting back up nicely, but these wells have excellent rates of return. We’ve clearly have shown that we can drill with the new techniques and testing on the other side of the coin testing. I think it’s over 25 million a day natural gas and this is a great economic result, so we’re going to step in and do more of those in that condensate/gas window that really kind of goes through the middle of AWP area.

[Owen Douglas:]

Great. Thanks. That is some good color. If I could, also, just thinking about your entire drilling program now, as you guys are moving a lot more to the gas wells at the moment and thinking about that, what does that suggest for those [clay tex] assets? Are those going to be held onto or are you guys going to be investing a lot more money on recompletions there or is that run off?

[Terry Swift:]

Well just a have there is more color on the AWP area, we do have I think like three PCQ wells that are awaited, that are oil wells and awaited frac. So there is going to be some oil activity coming forward, but getting to the specifics of your question, we were in the process of conducting a transaction or working with potential buyers and the site tax for Central Louisiana area and come November OPEC did its thing and the oil change and basically all transactions including the things we were doing that make sure just kind of flow. So I really don’t think you’ll see us or quite frankly I don’t see think you’ll see other people looking at oil transaction until there is some sort of stabilization either in the pricing environment or in the pricing the cost development environment which takes them specifically to the Wilcox in the Austin Chalk of the Playtex properties. Those are excellent properties in our view especially in environment we have lower cost, so I think the other side of this if you come out of it and looks to see $65, $70 oil which mostly are thinking we’re going to get to in a couple of years it will bode well for the development of the Wilcox play there in South Berry a creek or the Austin Chalk. So while our job today is just to maintain those properties they are basically have mark reduction in terms of the substance of the Wilcox in South Berry Creek. And also in terms of the Burr Ferry or Austin Chalk area, we not only have a significant acreage position with lot of developments that can be done at lower cost given this new environment we find ourselves in but we also have a lot of fee mineral acreage there, so that gives us an advantage when oil prices get back up to $65, $70. But I don’t think we want to be after drilling the 50-55 loan order I think others would and even to the extent get back after and provide a drill, I want to do with the new cost environment.

[Owen Douglas:]

Great. That is good to know. Finally, looking at your presentation, I presume that those rates which were listed in the presentation were IP 24 hours. Is it possible for me to get better 30-day numbers for those wells?

[Terry Swift:]

Yes, let me just say that in Fasken, we’re probably going to be go into 30-day average as now, we have enough calibration at our IPs. So, I don’t think you’ll be seeing us reporting the IPs for that property in the same way, we’ll probably gross profit more to a 30-day. In fact these last three that we just brought online in the first quarter we’re kind of taking that approach will calibrate everybody to more of a 30-day. At Bracken, those are 24 hour test, until we understand this Bracken area and comments say liquids, the GPM is a little bit better you’ll probably see us for the next two or three wells still reporting that 24 hour test rate until we calibrated well enough. But as I mentioned on the call, if you want to calibrate right now those first two Bracken wells that we tested where we announce the IP rates, I mentioned that in the first 70 days we’ve already taken out one Bcf equivalent. So that begins to tell you where give you the numbers where you can kind of start formulating what Investor Relations 30-day average or 60-day average might look like.

[Owen Douglas:]

Okay. Great. One more question, if I could. As you guys think about the current commodity price environment, roughly $50 a barrel, $3 an Mcf, what exactly are you setting up as your hurdle, given the emphasis on preserving the balance sheet liquidity?

[Alton Heckaman:]

Well, we only got drill the absolute best projects we have in this environment by best I mean the best rock that we have, we’re going to drill where we know we’re going to get the cost savings we know so we can get the payouts and two years or less and get ready to return I think in excess of 30% as we’re in this environment kind of the hurdles we’re looking at. This business has always been, I love the old business be candid it always is about drilling and bringing in production that’s profitable and we’ve been through a bunch of these cycles before, everyone of these cycles is little bit different just particular one doesn’t have the backdrop of the true physical imbalance and supply demand that we’ve seen in the past one. So I think we’re going to get through it, I think some of the economics that we’re now recalibrating to should be much better when you get through this pricing environment, but if you stays for 18 months, two years we’re hunkering down to be ready to get through that too.

[Owen Douglas:]

Okay. Because it is interesting to note that if your drilling for property is 30% well head returns, you also have your 7 1/8% bonds, which are the first maturities yielding in excess of that hurdle. Just curious how are you guys are viewing your hurdle rates and whether it is just about well opportunities or also balance sheet ones, too?

[Terry Swift:]

Well, you’re pointing to a very good fact, the entire bonds space of the energy sector has changed pretty dramatically and we’re not exception of that and there are probably some really good returns in there given the environment and what you actually think the future going to be. We don’t actually make our drilling decisions based on how the bonds are trading but we’re keenly aware of them and I think that’s a different kind of opportunity that sits out there.

[Operator:]

[Operator Instructions] There are no further questions. We’ll turn the call back to our presenters for closing remarks.

[Terry Swift:]

Okay this is Terry Swift and once again we’d like thank you for joining Swift Energy Company during our fourth quarter 2014 earnings conference call and operating results and we look forward to the first quarter and getting back with you at that time. Thank you.

[Operator:]

This concludes today’s conference call. You may now disconnect. Thank you.