SilverBow Resources Inc (SBOW) 2014 Q4 法說會逐字稿

Good morning. My name is Beth, and I will be your conference operator. At this time, I would like to welcome everyone to the Swift Energy Company fourth-quarter 2014 earnings conference call.

(Operator Instructions)

Doug Atkinson, you may begin your conference.

Thank you, Beth. Good morning, I'm Doug Atkinson, Manager of Investor Relations. Welcome to Swift Energy's fourth-quarter 2014 earnings conference call. Joining today's call is Terry Swift, our 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 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 cautionary statements contained in our press releases, and our actual results could differ materially.

Thank you, and good morning. Thanks, Doug. We are very pleased to be here with the call. 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 will then make a few comments on the E&P environment and what we're doing to position ourselves to successfully navigate through what are certainly turbulent times. After that, our Chief Operating Officer Bob Banks will speak to our operations and then I will make a few closing remarks before we turn it over to our question-and-answer period.

If you will start with slide 3, I would like to note that despite the very difficult environment that we are currently operating in, I am pleased to be able to report that we achieved quarterly production of 3 million barrels of oil equivalent, which was above our guided range of 2.81 million 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 operator 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 reserve bookings by about 20%. Our process of selectively perforating and grouping our completion intervals in the most optimal fashion continues to yield better performance and greater EURs.

Our two most recent Bracken wells in our AWP gas acreage averaged over 5,000 barrels of oil equivalent day of initial production. These wells represent the highest initial rates from wells drilled and completed in the Company's Eagle Ford history and recent history.

We acquired an additional 12,500 acres of high-quality contiguous Eagle Ford gas acreage at an area we're calling Oro Grande in La Salle County. The lease also contains a one-year option to lease an additional 11,850 acres in McMullen County. We look forward to transferring our enhanced drilling and completion design to the Oro Grande area in the near future and believe the property complements our existing asset base extremely well.

We reported proved reserves of 194 million barrels of oil equivalent, 59% natural gas, and 34% proved developed. Reserves declined 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 reserves would have increased 3%.

Finally, we initiated disciplined CapEx and cost-reduction initiatives throughout the Company which I will touch on later. We're going to focus more on each of the highlights that I've mentioned and also give focus as to what we're doing strategically to position the Company during the operating environment that we are currently enduring.

Before I turn the call over to Alton, let me also add that much of what we have achieved in 2014 is a result of strong properties that we own in the Eagle Ford. We will 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 are 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 a way as to seek the best outcomes for all of our stakeholders. Alton?

Thanks, Terry, and good morning, everyone. I will summarize some of our financial results for the fourth quarter 2014. For those following along with our presentation, summary tables of our fourth-quarter and full-year financial and operating highlights can be seen on slides 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 4Q 2014 guidance.

As to our overall financial results for the fourth quarter of 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 pretax, $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 costs and metrics for the quarter, general and administrative costs came in at $2.02 per Boe, which was well below guidance due to a lower 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 within guidance at 7.7% of our revenues. Our effective income tax rate for the 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. As always, complete and timely details of Swift Energy's price risk management activities can be found on the Company's website.

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 headcount 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 have also reduced our capital spending targets for 2015 to levels more in line with our internally generated cash flow. Our priorities continue to be financial discipline first and growth second.

On slide 7, you'll see a breakdown of our debt material schedule. As you can see, our nearest 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.

With that, I will turn it back over to Terry.

Thank you, Alton. 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 will notice we have refined the lower end of our projected CapEx spend from $100 million, up to $110 million.

Second, we have carried out a workforce reduction that is aligned with our proposed spending. Our headcount is down 25% since early 2014, which equates to about $15 million to $20 million in annual savings. We have also began an aggressive LOE reduction initiative, in which Bob will speak later on the details of that. Third, we have aggressively sought to reduce our drilling and completion costs and expect to realize price concessions from our vendors anywhere from 15% to 30% in 2015.

Fourth, much our drilling focus in 2015 will be at Fasken and AWP, which still provide attractive rates of return at current prices and reduce our development costs by taking advantage of existing infrastructure and operating personnel. These initiatives will put us in an excellent position to weather the current market downturn and to efficiently accelerate and take advantage of market opportunities when commodity prices recover.

Finally, it's important to understand, our management team and the Board our proactively focused on behalf of all the Company's constituents. Furthermore, we just recently added two new Board members and are 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 specialized banking, financial market, transactional, and operational experience.

We believe we have 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 am now going to turn it over to Bob Banks, our Executive Vice President and Chief Operating Officer to go over the operational highlights of the quarter.

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's estimated proved reserves were 194 million barrels of oil equivalent with a PV-10 value of $1.9 billion.

Reserves declined 12% in 2014, primarily due to the joint venture with Saka at 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 is 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 a year of 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 is still early, many of these wells are tracking above their 12 Bcf type curve.

For 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 of 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, when factoring in the production attributable to the joint venture interest at Fasken with Saka Energi, 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 this same area and 3% when compared to fourth-quarter 2013 volumes. Gross volumes out of Fasken in the fourth quarter, which included production sold to Saka 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, all to the Eagle Ford shale in the Company's 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 to date of 7,614 feet, which is over 100-foot longer than our previous record.

Compared to 2013, our 2014 average Fasken lateral length increased almost 1,300 feet, or 22%, and our frac stages increased by four or about 26%. Additionally, we are now drilling all of our Fasken wells in a new tighter 30-foot target window as compared to our previous 40-foot target window.

Earlier this morning, we published specific performance data on all wells 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 our drilling activity in Fasken and our AWP fields in 2015.

We were also successful in leasing an additional 12,000 acres in the 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 County.

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 leaseholds.

Quickly summarizing our southeast and central Louisiana areas, in southeast Louisiana, Lake Washington averaged approximately 3,584 net barrels of oil equivalent per day, a decrease of 2% when compared to third-quarter 2014 average daily volumes. 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.

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 and 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 of 2014. That is a decrease of 12% from third-quarter 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 and 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 the combination of longer laterals that are steered in a tighter zone of the highest quality rock, along with a customized completion that optimally perforates and groups our frac intervals with greater volumes of profit, are very important factors in delivering the improved well performance that we are seeing.

At 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 Bracken wells 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. Then also in our AWP area, our last seven PCQ enhanced technology oil wells have outproduced earlier wells by 29% in the first 180 days of production.

We believe our 2014 operational results clearly demonstrate our expertise in the Eagle Ford, providing us with a 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.

We believe the 24,000 acres in Oro Grande that we added have all the geological attributes that we look for when acquiring acreage, including thickness, porosity, and total organic content. It's in 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 in Oro Grande.

Now I'd like to talk a minute about some the things we're doing to reduce our operating costs. 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 at competitive prices.

We have aggressively sought to reduce our drilling and completions cost for 2015 and we expect to see cost reductions of 15% to 30%. Given the dynamics of our industry, if 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 costs and are constantly finding unique and creative ways to lower our cost structures. For example, we implemented a new and more efficient and cost-effective ported system in our first frac stage at the toe of the well, which led to savings of roughly $650,000 in the fourth quarter. We also implemented a new engineered procedure for drilling out our frac plugs that has cut our drill out time in half. This time has resulted in a savings of $320,000 during the fourth quarter.

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 planned 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 and condensate properties. A portion of the capital expenditure program is discretionary and can be further deferred if necessary.

Even with our reduced capital budget for 2015, 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 next year will be deployed to 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.

Thanks, Bob. Before we open the line for questions, I will summarize today's call. First, enhanced drilling and completion designs continue to improve the results we're observing in all of our south Texas Eagle Ford properties. This is most recently demonstrated by our two new wells in our AWP Bracken area measuring initial production of 5,345 and 5,222 barrels of oil equivalent, roughly 30% to 31% liquids there.

We increased our Fasken per well reserve bookings by 20% to 12 Bcf per well. We now have 160 million cubic per day of firm, committed capacity for natural gas transportation at 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 days and lower per foot drilling and 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 work force and administrative cost reduction that has reduced headcount by 25% compared to a year-ago level; aggressively sought to reduce our well cost and believe we'll realize cost reductions of 15% to 30% throughout the year; and we have 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 operations. 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 would like to turn the call over to the question-and-answer portion. Thank you.

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

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

Let me talk about it this way -- this is Bob. On the drilling side, we are seeing, across the various product lines, looking at every various part of cementing and mud logging and all of the services, we are looking at the 15% to 30% across the different product ranges right now, today. We feel that we are securing that type of cost reduction here now. As I said, if things languish a bit, we will see further cost reductions throughout the year.

On the fracking side, I would say that we are down right now about 20% from where we were in the third quarter of 2014. As you will recall, because of proppant availability and whatnot, in the fourth quarter, frac 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 will see further competitiveness on that completion and frac side.

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

This is Terry. I will 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 you go from Fasken all the way over to South AWP, and you stay principally above the Edwards fault line, and on the north side of the Edwards reef, you find some really good rock in places, either through the seismic and/or through the core data sets that we have.

We have focused our acreage acquisition on areas where the best rock is. 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 oil technologies that help 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 border of La Salle and McMullen. The acreage on the La Salle side, which we point out in our press release, is principally [up thrown] of the Edwards fault line, and some of the more prospective and what I would call first-stage appraisal-type acreage. Then the option acreage, we have got roughly a year to figure out what the appraisal in the north side is doing versus that. We are very pleased with that.

We currently are working on an appraisal and development plan, and we should be able to give you more granular detail on that about the second quarter. We would like to actually appraise the property in the second half of 2015, but that is going to be dependent on the outcome of the different development programs we're looking at, and possible JV participation in some of those programs.

So, a little early to talk about exactly how we're going to drill it. It is absolutely where we want it to be. The hydrocarbon pore volume, or the thickness, porosity, and gas saturation in this area is well established by core data, and it is very, very Fasken-like. I would also say that when you look at the gas in place via core data, our logs also, it is very Fasken-like. So, we are very happy with it.

We did get the position at what I would call today's environment. We all remember the high, heady cost of acreage in the past, and in this case, we're much more in tune 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 pay for it.

But I would say that in Oro Grande, we work directly with the mineral owner, and we are recognized as having the expertise to deliver the kind of wells that they want seen on their property. And so, we are starting out with a very good relationship there.

Okay. Thanks, Terry. Thanks, guys.

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

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?

I guess you are referring to Oro Grande -- the acreage acquisition?

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?

Yes. Again, for competitive reasons, we don't want to really talk directly about what we have gotten the acreage for. I think it is best said that our competitive advantage is, in fact, the wells we have drilled in Fasken, and now the wells we've drilled in south AWP, and that certain mineral owners in the play want those kind of wells drilled on their property, which gives us a different kind of advantage going in and seeking to acquire the acreage.

We are 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 the knowledge to make these comparisons, and transfer the technology.

In terms of our balance sheet and our ability to do these things, it is still a small portion of our budget. The acquisition that you're looking at now is fully closed and done, with the exception of an option about a year out. It really has no impact right now on the liquidity going forward. It has got a lot of opportunity for the Company in terms of joint venture partners that might come in to it, or what folks refer to as drillco. We are going to work through those plans and give you more detail later.

As to bolt-ons in the play, I think we will manage our liquidity and our balance sheet very appropriately. We are 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 through either joint ventures or drillco's.

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

No, that was last year. We closed that out last year, and finished it up late in the year.

Okay. That was actually -- okay. Understood.

Just in terms of JVs that you are speaking about here, could you give us a little bit more color on what type of structures you might be considering?

I will do a repeat. Last year about this time, we talked to you about JV-ing in Webb County, and we went out and found Saka. They are a very strategic partner. And we said, before that was done, that we only wanted to do JVs that were strategic and accretive, and would bring an immediate value to a transaction. I don't think Oro Grande is going to be any different than that.

We don't want to just do a typical, small thing -- a little promote and 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 programs and projects that are in play, as well as the Mexican market that is still growing. We are finding a lot of interest in Texas gas. Texas gas can easily get [to] these markets. It is not a roadblock, like we see in other areas with high differentials to get to the market.

We are seeing a lot of folks that are interested in these kinds of opportunities, and we are the operator of choice to do this right now. We are drilling the best Fasken gas well, now south AWP Eagle Ford wells in the trend.

Okay. That is helpful. Are you considering a JV that's of 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?

Leo, it is a little early. Again, we are putting the development plans together. It's over 12,000 acres -- almost 24,000 acres of both leased acreage and option acreage. It is a big chore to put a full-fledged development plan all the way to the markets; we are doing that, and how you appraise it.

But that said, it is easily 80 locations; it could be 150 locations, just depending on the pace of development and how you appraise it. To the extent that we do something this year, I would think it would be with a strategic gas partner not too different than a Saka. To the extent that this property would trade like Fasken, well, clearly Fasken already had gas production at the time, so it is different in that regard.

Okay. That is helpful. Could you just clarify current well costs? You guys talked about some of the reductions. So, what are the well costs today at Fasken and the AWP gas area?

Bob, you want to take that?

In Fasken, we are down around the mid-$6 million, $6.5 million. Over at AWP, we are in the $7.5 million to $8 million range.

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 $15 million to $20 million lower in 2015? How should we think about that?

I think you should think about it as a cash savings going forward. As to the different components, we're not actually giving specific guidance at this point. Most of those savings -- the $15 million to $20 million -- are from the administrative and G&A reductions we have done. That is a tough thing to do. Most of that was personnel 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. When you look at that, and try to allocate it to LOE versus expense G&A, versus maybe some of the capitalized areas, you are going to have to give us some time to let you see how that comes out granular.

For one point, some of the cost reductions were actually greater than the $15 million to $20 million, in that they were non-cash items, although they will show up on the income statement. Some of those, actually, we had in the fourth quarter of last year and, therefore, it shows a lower G&A going forward as the expense G&A that you will actually see. We're giving you full-year guidance; and on a cash basis, we fully expect $15 million to $20 million less in general and administrative costs.

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

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

Good morning, everybody.

Good morning.

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 re-determination, and whether you are going to get some covenant relief off the ratio test?

That is a good question for this environment. Realistically, what I would like to say is we are very aware of the low commodity-price environment, and some of the challenges it creates for all of the folks in the space. To the extent that we look at our borrowing base and our bank line, although we don't expect any near-term issues there, we continue to carefully monitor it.

I do believe we will go through this borrowing base review, and successfully continue the operations and the budget that we have. I don't have any doubts that the banks themselves do have pressure today to reduce borrowing bases, but we have the assets that, 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, 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 has seen before. That just suggests to us that there is a tremendous amount of capital ready to come in to the sector.

We have not made any decisions. I don't want to move too fast. The old saying -- you don't want to be the first, nor the last. And certainly we have lots of levers to pull, so we are going to take our time to do what is in the best interest of all of our constituents.

Adam, as I'm sure you know, our covenant, especially the coverage ratio, is a 12-month rolling computation. So, you have some time there. But we will clearly -- and we have been signaled by the bank that they have been talking with folks about seeing that coming, an early warning sign, and probably getting some covenant relief.

And more color to that, I don't know that we will need it, but we certainly see that the banks are providing that for certain companies at this time.

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 transaction, is there anything else you're thinking about that might be towards the front burner? (multiple speakers)

The two most obvious things that are in our control, we have 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 are going to achieve in LOE and CapEx, relative to well costs. Those are the things that are somewhat in our control -- we're pushing, we're aggressive there.

Things that are not in our control -- right now I do see some opportunity out there. Not only are we -- I think one of the accolades I heard recently was at NAPE here a while back, here in Houston, there were more new investors roaming the aisles of NAPE that were from out of state than we have ever seen looking for opportunities that ranged everything from drillco's to joint ventures. We certainly have the opportunity set here for folks that are interested in the Eagle Ford.

So, I think you will see us do some of those things this year, from joint ventures. They may not be extremely large, but they will all be accretive to the extent -- and strategic -- to the extent we do them.

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 over the next couple of quarters, and will you be (multiple speakers) --?

Yes, there have been. Alton, you want to speak a little more -- ?

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

Okay. Thanks. That is it for me.

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

Good morning.

Good morning.

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 would probably want to get some of your own enhanced completions in there before going down that JV road?

Those are great questions. We have an updated corporate presentation out there. I would like to point to slide 6. It gives you a little bit more granular detail on our Oro Grande area. Again, it is almost -- about 24,000 acres in total, La Salle and the McMullen County.

You are right on course in terms of it being Fasken-like. The first and foremost, we have got the core data. We see the gas in place, according to the core data, could be very, very similar -- in some cases, actually greater than Fasken. You are absolutely right that the earliest drilling was done in 2009 and 2010. And some of the early techniques -- while they got out there and got the cores, and did get some really good initial tests, they weren't using the techniques that are available today, and it was 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 is available to us. There's a lot of folks that need equity gas for the LNG markets now, or need to be queuing it 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 1 Bcf a day. So, we think we are going to be the operator of choice to bring some of these things to.

I would like to also mention 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 have done at Fasken.

It is a little early to say whether or not we would have a joint venture or whether we would do a drillco, or go out there and just drill a couple of wells to get it early staged like Fasken. We're working through those development plans.

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 on other things. And we have a good relationship there; this is not part of the original Saka deal.

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 takeaway from that area, but is there any -- can you remind me -- do you have enough processing capacity to deal with that higher liquid cut?

Yes. South AWP -- we have been there for a long time. When we actually started getting even more condensate in the Eagle Ford wells, we developed a relationship with Southcross, and they are currently the marketplace. And they have got lots of options. I think currently, we are going out of the south, but there is different ways to maneuver.

If you look at a pipeline map of south Texas, you will find that AWP is really at the crossroads of lots of different pipelines. There is some 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.

That is perfect. Thanks so much.

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

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?

It is comparable to AWP on the upthrown side of the Edwards fault system, Steve. It ranges from about [12,500] -- in the general area.

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

Bob, do you want to take that?

Yes. No, we are not currently ramped to the 160 million. Something we have not talked about is that in the first quarter, we did bring three new Fasken wells online. We're finishing up another four pads. Before too long, we will be ramped to that 160 million. We are in discussions with some pipeline providers to try to get us more capacity to go above our 160 million, and those discussions are in progress now, but we feel very good about getting additional capacity above our 160 million firm.

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

We will have to -- Bob is looking that up -- we will have to get back with you. But I would say essentially that all the drilling is going to be in the Eagle Ford -- all of the drilling completion. And to the extent that it is in Texas, it's in the Eagle Ford, and it's generally in development projects, although there might be some drilling, as we've discussed, over in the Oro Grande that is currently not classified as development or proven in our books.

We have -- in addition to the four wells we're finishing up now at Fasken, we have probably another eight we will drill in this current environment. And then we will have probably two to four more wells to drill over in the AWP area in that Bracken area.

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

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

We have one rig running now. We have a couple of different scenarios that we are still working through. We could have that rig drill through third quarter, or we could actually pick up another rig. We have been able to negotiate some flexibility on these rigs, so we don't have any long-term commitments. There are rigs available, so that buys us a little more flexibility, whether we want to run two rigs for a portion of the year, or just only run one rig through most of the year. We are still evaluating that.

I would like to add to that. There is a new dynamic in -- the commodity prices came down hard. They came down fast. There was a lag in the drop of drilling cost, although drilling costs are now starting to look much more favorable, and much more in line with the commodity environment. There was a bigger lag in completion costs.

One of the strategies that we have been looking at, as well as other operators, is how can you take advantage of these low drilling costs. 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 wells in this environment. We are pushing to drill joint-venture-type wells in the second half of the year, although we don't have those plans baked in yet.

Okay, and just one final question: What is the commodity mix expected to be like in 2015?

We gave first-quarter commodity mix guidance, and I don't think it will be significantly different; maybe a little gassier going out into the outquarters. Again, we're finalizing all that now, which is why we did some high-level guidance this time.

I think first quarter is probably the best proxy to use at this point in time.

All right. Thanks a lot, guys.

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

Hi, guys. Thanks for taking my question here. I just wanted 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?

I will start, and then I will let Bob wrap it up, and fill in any holes that I leave.

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, take-away processing is there. So, a lot of the issues are already dealt with.

We do have leasehold. We have got oil in the north. We have got condensate and gas near the center portion, and then dry gas at the most southern area.

These most recent two wells -- we are very excited about. It is still 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, 30%-something liquids, and quite candidly, it was a little more liquids than we were anticipating, although we clearly have the capacity, and we've been able to get them on production.

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 get back up nicer. But these wells have excellent rates of return.

We clearly have shown that we can drill them with the new techniques and testing. On the other side of the coin, testing I think at over 25 million a day natural gas, and just a great economic result. So, we're going to step in and do more of those in that condensate/gas window that really goes through the middle of the AWP area.

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 CLATEX assets? Are those going to be held on to, or are you guys going to be investing a lot more money on re-completions there, or is that going to be run-off?

Just a tad bit more color on the AWP area: We do have, like, three PCQ wells that are oil wells that are awaiting 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 in the CLATEX or central Louisiana area; and come November, OPEC did its thing, and the world changed. Basically, all transactions, including the things we were doing of that nature, just froze.

So, I really don't think you will see us, or, quite frankly, I don't think you will see other people looking at oil transactions until there is some stabilization, either in the pricing environment or in the pricing -- the cost of developing environment, which takes me specifically to the Wilcox and the Austin Chalk of the CLATEX properties. Those are excellent properties, in our view, especially in an environment where you have lower costs.

So, I think the other side of this -- if you come out of it at let's just say $65, $70 oil, which most people 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 Bearhead Creek or the Austin Chalk. So, our job today is just to maintain those properties. They are basically held by production, in terms of the substance of the Wilcox and South Bearhead Creek.

Also, in terms of the Burr Ferry or Austin Chalk area, we not only have a significant acreage position with a lot of development that can be done at lower costs, given this new environment we find ourselves in, but we also have a lot of fee mineral acreage there. That gives us an advantage when oil prices get back up to $65, $70. But I don't think we want to be out there drilling at the $50, $55 level, nor do I think others would. Even to the extent I can get back out there and try to drill, I am going to do it with the new cost environment.

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-hour. Is it possible for me to get better 30-day numbers for those wells?

Yes. Let me just say that, in Fasken, we are probably going to be going to 30-day averages now. We have enough calibration at our IPs. So, I don't think you will be seeing us reporting the IPs for that property in the same way. We will probably go more to a 30-day. In fact, these last three that we just brought online in the first quarter, we're taking that approach, that we will calibrate everybody to more of a 30-day.

Over at Bracken, those are 24-hour tests. Until we understand this Bracken area, and the condensate and liquids -- the GPMs a little bit better -- you will probably see us, for the next two or three wells, still reporting that 24-hour test rate until we are 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 announced the IP rates, I mentioned that in the first 70 days, we have already taken out 1 Bcf equivalent. That begins to tell you -- give you the numbers where you can start formulating what your 30-day average or 60-day average might look like.

Okay. Great. Actually 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 guys setting up as your hurdle, given the emphasis on preserving the balance sheet liquidity?

We are only going to drill the absolute best projects that we have in this environment. And by best, I mean the best rock that we have. We're going to drill where we know we are going to get the cost savings. We're going to know where we can get the payouts in two years or less, and get rates of return in excess of 30% in this environment, is the hurdles we're looking at.

This business has always been -- I love the oil business, to be candid. It always is about drilling and bringing in production that is profitable. And we have been through a bunch of these cycles before; every one of these cycles is a little bit different. This particular one doesn't have the backdrop of a true physical imbalance in supply and demand that we've seen in the past ones, so I think we're going to get through it.

Some of the economics that we're now recalibrating to should be much better when you get through this pricing environment. But if it stays for 18 months, two years, we're hunkering down to be ready to get through that, too.

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

You are pointing to a very good fact. The entire bond space of the energy sector has changed pretty dramatically, and we are no exception to that. There are probably some really good returns in there, given the environment and what you actually think the future is going to be. We don't actually make our drilling decisions based on how the bonds are trading, but we are keenly aware of them, and I think that is a different kind of opportunity that sits out there.

Okay. I will hop back in the queue. Thanks.

(Operator Instructions) There are no further questions. We will turn the call back to our presenters for closing remarks.

This is Terry Swift. Once again, we would like to thank you for joining Swift Energy Company during our fourth-quarter 2014 earnings conference call and operating results. We look forward to the first quarter and getting back with you at that time. Thank you.

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