SilverBow Resources Inc (SBOW) 2014 Q3 法說會逐字稿

Good morning. My name is Holly, and I'll be your conference operator today. At this time, we'd like to welcome everyone to the Swift Energy Company third-quarter 2014 earnings conference call.

(Operator Instructions)

I would now like to turn today's conference over to Mr. Paul Vincent, Director of Finance and Investor Relations. Please go ahead, sir.

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy's third-quarter 2014 earnings conference call.

On today's call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer, will review our financial results for the third quarter. Then Bruce Vincent, President; and Bob Banks, Executive Vice President and Chief Operating Officer; will provide an operational update before we open up the line for questions. Also present on the call is Steve Tomberlin, Senior Vice President of Resource Development.

Before I turn the call over to Terry, 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.

We expect our presentation to take approximately 25 minutes to 30 minutes, and have allowed additional time for questions.

Thanks, Paul. And thank you to everyone joining in the call today. Our third quarter demonstrates that we're leveraging our technology and leadership position to drive improved performance, while balancing our spending with our cash flow to strengthen our balance sheet.

Despite the headwinds that our industry faces today with the downturn and the price of oil, we are confident that Swift is fundamentally strong and well-positioned. Importantly, we have a seasoned management team, who collectively possess the necessary expertise to successfully navigate the Company through this downturn.

At Swift Energy, we are assuming this downturn will likely last a while. And we are taking the action by immediately scaling back our capital spending plans in 2015 to reduce the cash flow impact resulting from the lower commodity prices. Given the commodity backdrop, we will focus our drilling activity in our higher rate of return and faster payout areas, which also have lower operational risk.

We will continue our efforts with regard to non-core asset dispositions and/or additional joint venture opportunities. These efforts will provide additional capital to fund our future cash flow deficits, and will allow us further to reduce debt and improve our liquidity, just as we did with the Saka joint venture this year.

Our attention is focused on controlling those factors under our control, and in this vain, we are taking action to reduce costs related to lease operating expenses and general and administrative expenses. We are confident we can achieve a lower cost structure.

Moving to third-quarter achievements, our results highlight our commitment to capitalizing on our technology and high-quality acreage to consistently improve well performance and commercial results. Evidence of our growing technical expertise and leadership in South Texas includes the following. Production growth of 5% year over year in our core South Texas area, despite selling a 36% interest of production at Fasken with our recently closed JV and lower activity.

South Texas gross volumes, which include all Fasken volumes, grew about 19% from the third quarter last year. This speaks to the strength of our operations and well performance as we continue to get more out of each well for lower costs. The Fasken firm capacity pipeline expansion is now fully operational and more than two months ahead of schedule. We expect to reach our maximum committed capacity levels by the end of the first quarter of 2015.

On the drilling front, our Fasken EF 29H set several records, including 17.1 average days on a well, compared to a previous record of 17.7 days, while also reducing the cost per foot by $27 a foot. Additionally, our Bracken JV 14H well was drilled in 31 days, compared to a previous number of 34 days, and also reducing costs per foot by about $11.

Our completion work has also improved during the quarter, as we continued to perform enhanced or engineered fracs on essentially all our new wells. This process allows us to selectively perforate and group our completion intervals in the most optimal fashion.

As outlined in our press release, we completed 10 new wells during the third quarter. In our Fasken area, three new wells averaged initial production levels of 20.9 million cubic feet per day. In our SMR area, three new wells averaged 1,340 barrels of oil equivalent per day, while two new PCQ wells averaged 1,150 barrels of oil equivalent per day.

In our Bracken JV area, two new wells averaged initial production of 3,200 barrels of oil equivalent per day. Based on the results of the first three quarters of 2014, we are raising slightly our estimated production volumes for the year, from a range of 33,400 to 33,700 barrels of oil per day to a new range of 32,600 to -- oh, from an old range, excuse me, of 32,600 to 33,200 barrels a day.

As we've consistently stated, we have built a balanced, diversified portfolio that will deliver value in a variety of commodity price environments. Our assets across Webb, La Salle and McMullen counties in South Texas provide a well-balanced mix of liquids and dry gas opportunities.

At the beginning of the year, we laid out our plans to strategically grow our Eagle Ford production, despite meaningfully reducing our spending levels. We are proud of the strides we've made in both our drilling times and completion methods to-date, which have positioned us to finish the year in a better position than when we started.

Our current expectations for 2015 include significant reductions to capital expenditures. We currently have preliminary guidance, and expect those capital expenditures to be in the range of $240 million to $260 million. At this level of CapEx, we still expect to deliver similar production levels in 2015, as compared to 2014, and see potential growth from our Fasken area of operations.

It is important to note that our primary goal during this lower commodity pricing cycle remains balance sheet stability and strength. Thus, we will remain flexible with our capital program as we continue to monitor the commodity price outlook and the macro environment. We have a great deal of optionality built into our 2015 budget, thanks to the majority of our acreage being held by production and the relationships we've cultivated amongst our supply chain vendors. Which provide us the flexibility to scale up or down quickly in response to the prevailing operating environment.

While our initial work plans for 2015 call for a decline in capital expenditures levels from 2014 levels, we have identified additional discretionary projects which can be funded, should cash flows be stronger with higher oil or gas prices. The majority of our CapEx next year will be deployed in the Eagle Ford, which yields attractive returns at a level of $80 a barrel and $3.50 an Mcf.

We are constantly evaluating the potential for further joint ventures, partnerships and asset disposition opportunities that will provide enhanced liquidity, financial flexibility and further expand value. We will continue to work on the sale of our Central Louisiana assets. At this point, any proceeds from an asset sale will be directed towards either short-term debt reduction and/or reducing a portion of our long-term debt.

Before I hand things off to Alton, I'd like to finish my comments by speaking a bit about Swift Energy and our legacy. Throughout our 35-year history, we've seen our fair share of turbulent times and cycles in the oil and gas market. This experience has taught us, among other things, that during difficult times, the most extraordinary opportunities may exist for those that are willing to work hard and stay true to their core values.

Swift Energy has a dedicated and experienced staff of oil and gas professionals, and I can assure you that no one will work harder through these difficult times than our team. With that, I'll turn it over to Alton to summarize our third-quarter 2014 financial results.

Okay. Thanks, Terry, and good morning.

Third-quarter 2014 production of 2.99 million Boe, which was well-above the high-end of our guidance, drove the quarterly results. Both natural gas and NGL volumes were above guidance levels, while oil volumes were slightly below. As previously disclosed, during the quarter, we closed our transaction with Saka Energy for a 36% interest in our Fasken properties, and received $175 million in total consideration, which includes the $50 million drilling carry enhancing our liquidity.

Our overall financial results for the third quarter of 2014 include oil and gas sales of $135 million, before adjustments, for our ongoing price risk management program, which this quarter includes a pretax $1.2 million non-cash gain-related to hedges we have in place that extend beyond 3Q 2014. Net income came in at $2.5 million or $0.06 per diluted share, and cash flow before working capital changes for the quarter was $75 million.

Our controllable costs were all below guidance for the quarter. Transportation and processing was $1.71 per Boe. Lease operating expenses came in at $7.83 per Boe. And general and administrative costs were $3.55 per Boe. LOE and G&A costs came in favorably, due to higher volumes and numerous cost-reduction efforts that are being realized.

Our other per-unit metrics were favorable to guidance as well. Oil and gas depletion was $21.73 per unit. Interest expense came in at $6.08 per Boe. And severance and ad valorum taxes were 7.6% of oil and gas revenues, which, again, was within guidance.

Our effective income tax rate for 3Q 2014 was 54.8%, higher than usual, due mainly to changes in our state tax estimates. As previously mentioned, the result was net income for the quarter of $2.5 million or $0.06 per diluted share, well-above first call mean estimate. Cash flow before working capital changes for the quarter came in at $75 million, EBITDA at $90 million, while our quarterly CapEx on a cash flow basis was just over $100 million.

I should also note that our regularly scheduled semi-annual borrowing base review was completed, and our borrowing base of $417.6 million was reaffirmed, effective October 17, 2014. This credit facility, as you know, matures in November of 2017.

Our expanded hedging program was utilized during 2014 to minimize price volatility risk. We strategically used a combination of commodity swaps and callers, and also locked in basis spreads, which protected against volatility we saw between prices at our field delivery points and major terminals. Complete and timely details of Swift Energy's price risk management activities can always be found on the Company's website.

As we've said on numerous occasions, but it warrants repeating, we continue to be very focused on strengthening our balance sheet and better aligning our capital spending with our expected cash inflows, which will also obviously enhance our liquidity. We are very committed to financial discipline first, and growth second. As always, we've included additional financial and operational information in our press release, including guidance for the fourth quarter.

And now I'll hand it over to Bruce Vincent.

Thanks, Alton. And good morning, everyone, and thanks for listening. Today I will discuss the third-quarter 2014 activity, including our production volumes, recent drilling results, activities in our core operating areas and our plans for the fourth quarter of 2014.

Beginning with production first. Swift Energy's production during the third quarter of 2014 totaled 2.99 million barrels of oil equivalent, or 32,542 barrels of oil equivalent per day. This is above the high-end of our guidance, and highlights the technical efficiencies we've been exploiting this year in South Texas.

The production mix during the third quarter was comprised of 29% crude oil, 16% NGLs and 55% natural gas. Production during the quarter was driven by 10 new wells we brought online, three in Webb County and seven in McMullen County. Offset, of course, by the sale of 36% interest of Fasken to Saka Energy, as well as some shut-ins while we were making completions.

For our third-quarter drilling results. Swift Energy drilled six operated wells during the quarter, all to the Eagle Ford shale in the Company's South Texas core area. Three of these wells were drilled in McMullen County and three wells were drilled in Webb County. We currently have two operated drilling rigs in our South Texas core area drilling Eagle Ford shale wells -- one in our Fasken area and 1 in the AWP area in McMullen County.

In the Southeast Louisiana core area, which includes the Lake Washington and beta Shane fields, production during the third quarter averaged approximately 3,819 net barrels of oil equivalent per day, down approximately 20% when compared to the third quarter of 2013 average net production from the same area. And down 6% from the second-quarter 2014 levels.

Lake Washington averaged approximately 3,662 net barrels of oil equivalent per day, a decrease of 7% when compared to second-quarter 2014 average daily volumes. We performed nine re-completions and four product optimization projects at Lake Washington during the quarter. We have identified numerous opportunities throughout the field for additional re-completions and workover projects for the fourth quarter and into 2015, which will mitigate the natural declines in this field.

In our South Texas core area, which includes our AWP, Sun TSH and Las Tiendas Olmos fields, and AWP, Artesia Wells and Fasken Eagle Ford fields. Third-quarter 2014 production of 26,821 net barrels of oil equivalent per day increased 5% when compared to the third-quarter 2013 production in the same area. It was down 16% when compared to second-quarter 2014 volumes. Recall that during the quarter, we closed the sale of 36% of our Fasken area, which affects these quarterly production comparisons.

In our Fasken area, net production volumes increased to 51 million cubic feet per day, up from 27 million cubic feet of gas per day during the third quarter of 2013. But down from 84 million cubic feet of gas per day in the second quarter. Our net volumes in Fasken have been reduced by 36% due to the closing of the joint venture in that area, but will continue to push gross production volumes higher in anticipation of bringing field production to approximately 160 million cubic feet per day by the end of the first quarter of early 2015.

In our AWP area, production grew 5% sequentially, and averaged 13,134 barrels of oil equivalent per day. We will continue to increase South Texas production levels with two rigs running in the area for the duration of this year.

Highlighted in our press release this morning are details of the 10 new operated wells we completed in our South Texas area during the quarter, and I'll refer you to that for the specifics. Three new areas from our Fasken area were completed during the quarter. We have now brought 10 consecutive wells online in this area that have exceeded 20 million cubic feet of gas per day in initial production rates. Further, we believe that we can continue to improve our drill and complete design, and expect to drill even higher-quality wells going forward, while seeing opportunities to further reduce capital costs.

In McMullen County, seven wells with an average IP of 1,818 barrels of oil equivalent per day were brought online. Most notable of these were the Bracken JV Eagle Ford 13H and 14H. These two wells were brought online at an average IP of over 3,200 barrels equivalent per day.

Terry has noted and Bob will discuss the Whitehurst wells completed last quarter. And now the Bracken JV wells represent the third and fourth area in South Texas that we've applied our current-generation drill and complete design, and have observed a meaningful uplift in initial and sustained performance.

We are now of the belief that our ability to drill precisely targeted laterals within the lower Eagle Ford, and our engineered completion design, is a transferable and competitive advantage and can be applied throughout the Eagle Ford trend, given certain geologic parameters. We look forward to testing our technical efforts to the upper Eagle Ford and the Olmos zone.

In the Central Louisiana core area -- which includes our Masters Creek, Burr Ferry and South Bearhead Creek fields -- contributed 1,799 barrels of oil equivalent per day of production in the third quarter of 2014. An increase of 3% from the second-quarter 2014 production in the same area, but down 33% from prior-year levels, primarily due to lower activity and natural declines.

I'll now turn the call over to Bob Banks, who will cover the highlights of the quarter.

Thanks, Bruce. As Terry mentioned, our commitment to deploying customized engineered completions in horizontal laterals, drilled in precise target zones of the Eagle Ford shale, is steadily increasing the value of the entirety of our South Texas acreage position. Our customized completions allow us to optimally perforate and group our frac intervals, resulting in more consistent treating pressures.

Coupled with placing higher concentrations of proppant in the laterals, we have, in many wells, doubled our cumulative produced volumes during the first 60 days to 90 days of production. Although we are drilling more technically precise wells, we are continuing to improve our days-on-well metrics in all areas.

In our Fasken area, we drilled our longest lateral so far, to a measured depth of 7,499 feet. We also set a new record of 17.1 days on a Fasken well, as measured from rig release-to-rig release. We have also applied the same enhanced technology to our new Bracken wells approximately 120 miles to the east of Fasken, adjacent to our Whitehurst lease.

For these two wells, we've set the bar high for our future Bracken wells, as we set new records for days-on-well, well costs, and cost-per-foot metrics in this area. In fact, on a program-wide cost per foot metric, our best wells' performance from 2013 is now our average performance for 2014, thus further evidencing our continuing improvement in the trend.

Let me take a few minutes now to talk about production operations. We get very focused on (technical difficulty) and completions in these shales because of cost, but we can't forget that these wells are going to produce for the next 20 years or more. And efficient production operations will make a difference in the ultimate recovery from these wells.

For example, it is well known that scale in (technical difficulty) and problems experienced in some areas of the Eagle Ford have negatively impacted production performance. To more effectively treat these problems, our production and completion engineers have worked together and have begun pumping granulated scale and paraffin inhibitors, with the proppant, into our frac jobs. We have found so far that wells treated in this manner are producing more fluid, and the initial decline rates are about 12% better than the untreated wells.

In the retrograde condensate area of Artesia Wells, our production engineers have deployed a high-pressure plunger-lift system that removes liquids from the wells at higher pressure, maintaining system pressures above the bubble point longer. And thus increasing our liquid hydrocarbon recovery from these wells.

In Fasken, we are utilizing tracer surveys to evaluate production trends and completion techniques. Recent tracer work carried out by our production and completion engineers has indicated that a relationship exists between those areas within the laterals that have better log response, and the contribution of those areas to the full production stream of the well.

While this work has not been fully evaluated, early indications are that the next step in customized completions will be customization of the frac design within each individual stage of the lateral. In the future, you can expect us to continue to improve the efficiency of our completions, including longer laterals, increased stage counts, higher sand loadings, and expanded customization of our fracs.

Additionally, we'll continue to focus on those things that reduce costs without impacting efficiency, such as improved methods and systems to initiate our toe fracs. Our use of toe sleeves resulted in almost $1 million in savings during the third quarter alone. Also, we've changed how we drill out our frac plugs, resulting in better performance and more consistent results, while cutting the time and cost in half.

Recently, the drop in oil price has been the center of a discussion in our industry. And despite the drop in price, the demand in the Eagle Ford shale, South Texas, for oil field services, such as drilling rigs, pressure pumping services, and proppant for frac jobs, has remained strong, keeping costs for these services high. While supply and demand for these services are currently out of balance, history has shown from previous cycles that commodity prices and the price for services have a way of balancing out.

As operators invariably cut back on development activity due to lower oil prices, demand for these services will decline, and the negative pressure we have seen the last few months on availability and price will come into balance. We believe the supply chain organization that we have developed and the relationships they've fostered with our vendors will continue to be one of our key operational and strategic advantages in any commodity price environment.

As Terry indicated, we have had great results to-date this year and are on track to produce more hydrocarbons than we previously expected. This not only validates the techniques and operational applications we've deployed over the past 12 months, it also sets the stage for 2015 and beyond. Our strong and continually improving operational capabilities are increasing the value of our high-quality acreage with every well we drill.

Equally important to our improving operating efficiencies and well performance are our ongoing business development efforts, which include potential asset sales, operating partnerships, additional joint ventures. Our first priority, however, remains balance sheet stability and strength, and any transaction that we would entertain must increase financial liquidity, reduce leverage and improve our operating metrics.

We've put a great deal of energy into our 2014 program to-date, and it's encouraging that we are exceeding the expectations we had for this point in the year. We are excited to take this operational momentum into 2015.

With that, I believe Terry has closing remarks.

Thanks, Bob. Before we open the line for questions, I'll summarize today's call.

Here are the more important events of the quarter. Driven by our South Texas development program, corporate production came in above our guidance for the quarter. Construction of the expanded takeaway capacity at Fasken was completed ahead of schedule, and we're confident we'll fill our 160 million cubic feet per day of firm committed capacity for natural gas transportation at Fasken by the end of the first-quarter 2015.

We are realizing fewer drilling days and lower costs per foot and completion costs in our areas in South Texas. Enhanced drilling and completion designs continue to improve the results we're observing at all of our South Texas Eagle Ford results.

Based on the results of the first three quarters of 2014, we expect to finish the year in a stronger position than when we started, despite the headwinds created by commodity prices. And as a result of this progress, we are slightly raising our estimated production volumes for the year to a range of 33,400 to 33,700 barrels a day from a prior range of 32,600 to 33,200 barrels a day.

With that, I would like to begin the question-and-answer portion of our presentation.

(Operator Instructions)

Your first question is going to come from the line of Michael Hall with Heikkinen Energy Advisors.

Thanks. Good morning, guys.

Good morning.

I wanted to just drive into the outlook around 2015 in a little more detail. Apologies if I missed any of this in the opening remarks; I was a little late getting on. Just some more color as to how you're thinking about capital allocation within the Eagle Ford in 2015, in the context of the early look on capital and production. I'm assuming it's very highly oriented towards the Fasken area in order to keep volumes up. Is that an accurate assumption? And how does cash flow and EBITDA growth look as you think about 2015?

Well, those are good questions, Michael. And clearly, with the commodity markets, we've got the main flexibility to keep what I would say a stronger balance sheet, better liquidity, as the goal, as opposed to production growth.

When we look specifically at our CapEx, I think we have given today preliminary guidance that we're going to significantly reduce our CapEx from last year. The range we're in a preliminary fashion guiding is 2.40% to 2.60% as a CapEx. The vast majority of that -- again, this is preliminary guidance, but the vast majority of that would be in South Texas in the Eagle Ford.

We also clearly are ongoing with what I'm calling our improvements in the wells. And by that, I mean better well results, lower costs drilling the wells, but also cutting costs in areas like LOE, G&A. Working hard, as Bob said, with the vendors who we have a lower commodity price deck next year. We're going to be pushing to reduce costs in other ways. Keeping that in mind, our current preliminary guidance is to have about the same production level next year as we have this year, and it would be slightly more gas-oriented. But in terms of allocating capital, I think it's real important to note that we've still got what I would say very good returns, both in terms of what I would call a present value-to-investment ratio. Rate of return is the other item, along with payout status, that we look at as really the three principal drivers to how we allocate capital.

When you look at those particular operating metrics or really, commercial metrics, you still see gas, particularly Fasken-type of gas. And now when you get over here into the Bracken area, where we've got these condensate wells, and exceptional results of the technology transfer. Again, the recent 2 wells (technical difficulty) IP average 3,200 barrels a day. We're seeing very good present-value investment ratios, very good rates of return, very good payout levels, using about an $80 deck for oil and $3.50 to $4 for gas. That's how we're allocating capital.

Clearly, we'll continue to keep the opportunity to do more projects, if oil bounces back. But we're not planning that way. We are going to keep our acreage position in good shape; that's one of the allocation concerns that a lot of companies have. But most of our acreage is already HBP'ed or requires very little drilling to just keep it going, or the drilling (technical difficulty) the areas we have exceptional economics.

Finally, just talking about allocation of capital and really driving to improve liquidity in the spending levels to be more matched or balanced with next year, looking at EBITDA, cash flow, everyone's got to do their own modeling. But I think our number, just kind of rough; this is preliminary -- the macro environment is certainly going to dictate a lot. But we're looking at maybe as much as $60 million to $70 million might be the outspend. But I say maybe only to the extent that we're doing everything in other ways to bring that down to zero or less, or pay down everything from bank line to even a portion of our long-term debt. How are we going to do that? Again, we're looking at cuts in LOE. We're looking at cuts in G&A. We're looking at lower well costs.

We're also looking at asset dispositions that are non-core, both in terms of Louisiana -- we've got an ongoing effort there that we've articulated as still in progress. And we also have some opportunity to do some non-strategic types of things with some of our smaller assets in Texas. We also are very pleased with our Saka venture, and should we be able to construct something similar to that next year, either with Saka or another party. We're on the course to be able to give ourselves that opportunity.

That's very helpful color. I appreciate it. And just to be clear, that roughly $60 million to $70 million outspend, that's on an $80 oil and 3.50 gas deck?

It's actually on an $80 oil deck and about a $4 deck. When I refer to $3.50, what I'm saying is, our economics are really exceptional at $3.50 in those areas still.

All right, that makes sense. Great. And then also wanted to get a little more color around -- sounded like some positive developments on producing the wells at Artesia. Just curious, maybe revisit that commentary and provide any additional color as to how that might help that part of the program going forward?

Well, yes, Michael, this is Bob. As I think I mentioned, we did install these high-pressure plunger-lift systems, and we've seen some pretty good performance out of the wells after we've done this. In fact, if you look at our [Betz] lease area and ARN area, where we really tried these plunger lifts, we're outperforming our forecasted production by anywhere from 40% to 60%, from where we were forecasting back in April to what we're forecasting now. So we're going to see how that continues to perform. But, yes, we're very encouraged about the way we're managing those reservoirs in that retrograde area. We think we can do a lot better than what we did very initially in the early wells.

Great. I appreciate the color, guys.

And your next question will come from the line of Neal Dingmann with SunTrust.

Good morning, guys. Just a quick question. Obviously, the Fasken area continues to have tremendous wells. Terry, I guess for you or Bruce. How do you guys look at -- you hear a lot about, in many of these plays, about managing the choke program. Just wondering when you look at choke sizes there versus how you view that, versus expected depletion rates, and how you all view that.

To answer that in a precise way, you'd have to get our production engineers in a room and you would have a little bit of a debate. But I think the guys are pretty-well fixed in the gas area that this is not a real concern of ours. The ultimate recovery of these wells is really more based on how we're fracking them, and also the quality of the rock. You clearly can pull a well too fast and adversely affect your near-well bore draw-downs, and even potentially unpack or crush sand, and we don't want to do that. But you can manage the actual pressures that you're seeing at the surface to determine what kind of draw-down you're getting, and avoid that.

We have no concern right now that the chokes that we're using, choke sizes, are adversely affecting it. In fact, we think it's pretty important to balance this choke size; we're getting the water off the formation early. Basically I wouldn't sit here and tell you that I could pinch the wells back and get more recovery in Fasken, or open the wells up and get more recovery in Fasken. I think our guys are doing a good job.

Just a little more color to that, Neal. We're always managing the pressure and the production, so we're not doing anything with the reservoir that the reservoir won't allow. In fact, what we're seeing in Fasken is a flatting of these decline profiles. So I think the practices that we're deploying on our choke management and our reservoir management are working very well there.

That makes sense. One last one for -- Terry, for you or Alton. When you think about allocation next year, I know you mentioned cutting overall CapEx. But just on allocation, you haven't fully have a 2015 plan, I realize that. But how you think about Fasken and the surrounding areas versus just the other total part of the plays?

Well, we're looking at a balanced program in terms of keeping a rig active over in the McMullen County area, and drilling both oil and some of these very high-impact condensate gas wells. We're keeping a rig over in the Fasken area. We're working with our partner Saka on that, just basically have a strong partner. And to the extent that gas prices allow us, we may actually do more next year with a partner.

The allocation of capital is really not to overproduce or go too aggressive in Fasken. Because I think strategically, we do believe the LNG market's going to be a great -- Fasken, and properties like it, is going to be a great backyard to be in, relative to LNG. We're not trying to peak that out and just have it gone in four or five years. We also have the upper Eagle Ford and we have the Olmos in that area. And there, maybe a little more sensitive to the gas price, in terms of the Olmos. We are clearly well-positioned to do bolt-on acreage acquisitions in the general area. We know where the best rock is. We're working on that. I think there's some nice running room for us at some very modest capital levels.

In terms of the non-Fasken areas in South Texas, the activity will be obviously at AWP and McMullen County, but we also plan a couple of wells in Artesia Wells. We have not drilled one with this more recent design -- both drilling and completion design that we're utilizing. And now that we have a better handle on how to operate and produce those wells, we want to go back in and drill a couple of wells in Artesia Wells next year.

Thanks, guys. That's very helpful.

Thanks, Neal.

And your next question will come from the line of Leo Mariani with RBC.

Hi, guys. Can you talk a little bit more specifically about what type of well costs you're currently seeing in your different areas, whether it's Fasken or the McMullen area?

Leo, it's Bob. Let me take you through a little bit. Like I said, the guys have continued, in our drilling group across the program, to drive our cost-per-foot metrics way down. As I mentioned in my statement, our best 2013 well is now our average 2014 well. In terms of Fasken, we're routinely under $3 million a well, even for those longer laterals, and that would include drill and pre-complete-type costs. As you get over into the SMR, PCQ areas. Again, PCQ, we're in that $3 million, little over $3 million range. We had 1 well this year in SMR, we actually drilled spud to TD in 10 days, about $2.4 million. So hopefully, that gives you a range of some of the numbers.

All right, and if you throw those completion costs in, what would your drilling complete costs be in those areas?

Well, the completion costs are -- it's a combination. We're drilling longer, so we're increasing the stage count. We're increasing the sand loadings. But you can probably put an average of -- well, back in 2011, I think, our average completion cost was about a little over $5 million. But now, those are averaging about $4 million, and that's with the increased lateral length. That's within the increased sand loadings. Even in 2013, our sand loadings were about 802 pounds per foot of completed lateral. Now, we're up well-over 1,300, approaching 1,400 pounds of sand per completed lateral. So we're driving costs down, while at the same time putting more stages in, going from an average -- last Q3 2013 of 15 stages. We're now averaging about 23 stages. So very different dynamics in terms of driving costs down and increasing lateral length in sand loadings.

Leo, if you actually look at the first six months of this year, the average drill and complete cost was $7.1 million.

The one thing I do with -- this is Terry. The one thing I do want to point to is, prior to the oil price basically collapse we've seen, we did see the pressure coming in, particularly on the completion services. And some of that pressure has not fully abated yet. But we know that our service providers, while some of them are trying to get a little bit higher price right now, they're keenly aware that, that's not sustainable. So looking into the 2015 year program, we actually think prices will be about the same as what we've experienced in 2014, or lower. But near-term we have seen some price pressure.

All right, that's helpful. You guys, obviously, referred a couple times to potential new JVs or partnerships. Could you help us understand that a little better? Would that be taking an existing Swift asset and bringing a partner in on it? Or would that be potentially the acquisition of some new dry-gas acreage, like you spoke of, and then bringing a partner in on that?

I'd say yes and yes. What we've tried to do in the Eagle Ford, and thus far I believe we've been very successful, is make sure that anything we do is strategic and helpful in the long-term. The Saka relationship was much more than a disposition or a transaction. It was a strategic partnership that we developed in Fasken. It is underway; it is working well. Of course, we'd like to do another one like that. But I think if you're concerned, and I would be too, that we might pick too good of a property and not get a good result; I think you look at the Saka transaction, you look at the Fasken transaction, that's the kind of thing we would do.

We don't have any specific asset targeted that we're ready to talk to folks about publicly. We do have relationships where we know what folks want. And we also have acreage that we're on the hunt for, that's bolt-on, that we think fits strategically into either a combination development program, or maybe an appraisal program.

In terms of Central Louisiana or our Louisiana assets, there again, we would seek to do something in the way of a disposition there. We have been working the clay tex; it's taken way too long, but it's still in play. That might also have a strategic element to it, as well. Those are the kinds of things we want to do. But in Louisiana, we clearly would transact more in a disposition mode, since it's not a core area.

To follow up on what you said there about Louisiana, is there any drop-dead date or anything like that, that you guys have set on a disposition there, where if you get past it, you keep it, or anything?

You know, I think a drop-dead date would be nice, in some ways. Maybe I already had it and passed it. We have a live effort going and we want to see it to its fruition. Whether that means we get a deal done or whether we then begin to seek to do other things with the property. Should we not have a transaction by end of the year, we clearly need to go into the property and begin to do some low-capital types of things, some maintenance-type things to improve the value of it, sustain the value of it. And at the same time we need to begin to look at selling in pieces or portions rather than a full transaction.

So I wouldn't call it a drop-dead date in the sense of not doing anything after that date. But I would say that tactically, if we go beyond the end of the year without a completion of a full transaction there, you'll see us work it in pieces and do some work in the fields.

I think you have to understand that in terms of working this transaction, we're working with another party and have some time lines and milestones set up on that. And as long as you're making progress and you see an ultimate completion of a transaction, you're going to continue working on it. A drop-dead date could come when all of a sudden you stop moving forward. It doesn't have to be some artificial date out there. I think if you're making progress and you think you can get the transaction done, you ought to keep working on it. And that's where we are right now.

All right. Thanks for all the color, guys.

And your next question will come from the line of Bertrand Donnes with Johnson Rice.

Good morning. Great quarter, guys.

Thanks.

Could you talk about which area will be next to see those enhanced completion techniques? I think you mentioned the upper Eagle Ford and the Olmos. And if you're considering increasing those enhancements further on the properties you've already tested?

I think we are going to enhance the methods. I think one of the things I mentioned on the call was the relationship of the inner stage completions to the total production from the wells. So we're just getting more precise with our completions, and we're applying that both to Fasken and over in that AWP area.

The area we have not deployed this technology in to-date is Artesia Wells. We have very high hopes for what we can do utilizing this same technology over into our oily Artesia Wells area. So that will be the next area we apply what our learnings have been so far. But you'll continue to see us tweaking and getting better in Fasken and AWP and in all of our properties.

Perfect, thanks. Could you put some color on the LOE bump that it looks like fourth quarter has guided to? It's a slight move up. But is that just conservatism, or is there something we need to look for going into 2015?

I don't think there's anything specific there. I think we are seeing some LOE reduction, some of those savings come through. We'd like to continue that, but you'd rather guide it up.

Right, okay. And then just one last one. How are you looking at hedging in 2015, with the high results in Fasken? Are you looking to lock in more gas volumes? Or are you just going to play the commodity back up and down?

Well, there's clearly several different views on hedging. And first, I'll speak to oil. At this point, the oil market doesn't really afford you much of an opportunity to hedge out unless you want to be able to take the lower price. So I wouldn't expect to see us do much hedging on oil right now. We don't believe it's the time to sell or do hedges when the market's so low.

On the gas side, you come into winter -- you typically get some opportunities as you come into winter. We did some material hedging last year starting around this time and through the winter. Gas, I think, you're more likely to see us put some hedges on. Clearly, another way of hedging gas is to do a joint venture transaction. I do try to point out to folks that this year, the Saka transaction was, in fact, a hedge. Because not only did we sell gas effectively in the ground forward, but we also accelerated the development program through the carry that we got with them. They will do their hedging just as a point separate than us. But do look for us to hedge, should we see some opportunities in the natural gas market.

Okay. Well, thanks, guys.

Thanks.

And your next question will come from the line of Noel Parks of Ladenburg Thalmann.

Good morning.

Good morning, Noel.

As you're talking about the success you had with the redesigned fracs, thinking back to some of the earliest wells you drilled, would there be anything attractive about the economics of trying to do re-completions or anything similar out there?

Noel, it's Bob. We have thought about that. We've even played around a little bit with some re-fracking in the early days. I think the way we're looking at that right now is, that's future activity, compared to what we have now to do. But I think you'll see the entire industry work on that down the road. And that's how we're thinking about it, too.

Okay.

I think it's a case of first things first. You really want to go to the virgin rock at this point in time with this latest design that we have and continue to develop that out. And then you can come back to these older wells. And I'm fairly confident that we will, and the industry will.

Okay, great. And I was thinking, as you've put in larger fracs and longer laterals and so forth, I know in the past you talked about shifting to a policy of, I think, logging the lateral -- I guess most wells or, if not all of them. Are there any of the steps that you added to improve your steering to improve recoveries? Are any of those steps at the point where you can pull back and don't need to do as exhaustive a regimen on every well going forward, or are you still on the curve of basically doing bigger --

Let me attempt to -- this is Terry. Let me attempt to answer that. It's not as simple as just a longer lateral. It's not as simple as more frac stages, or more sand. You clearly need to be in good rock, overall. You need a really good Eagle Ford section. We've got those kind of properties. But even with a good rock, long lateral, lots of stages, lots of sand, you have to steer yourself in-zone. We've been getting much better at that. I'm very proud of how the geophysics and geology is working together with the engineering and the drilling to steer in-zone. And then within that zone and along the lateral, these engineered fracs -- and to answer your question directly, there is still a lot to learn and a lot to gain. I don't think we're at the limits, by any means.

But certainly, are you doing some big step changes? I think you're not going to see as much in the way of big step changes unless you see someone coming to an area and transferring the technology, like going into Artesia Wells, where we haven't been there doing that. Also, getting the cost down; I think there's more opportunity there to get the cost down. But at the end of the day, it's not just about getting the cost down. It's about getting better wells. And we're certainly seeing that, and proud of our results.

Noel, just to add to that, we still see a lot of variability in the lateral sections, and these logs have helped us immensely, group our fracture stimulations into rock of like-frac gradient. And we think that is a big driver of getting a better stimulated rock volume of rock.

In the future, we even see, as I mentioned, getting into the individual stage itself and pumping one stage differently from a second stage, differently from a third stage. So I think there's still a learning curve we're on, using the success we've built upon with these customized frac designs and customized completions.

It's a great question you ask. And as we talk through it, I think I will add that there's one other area that I think there's a lot of learning going to come. And that is in the way of frac height. A lot of folks don't talk too much about how effectively they stimulated the entire Eagle Ford up into the section. Where you have a thinner Eagle Ford section, maybe it doesn't matter as much, except to the extent that you might have actually stimulated rock beyond the Eagle Ford. And that's an opportunity to be more effective in your frac.

But in a lot of these areas, the Eagle Ford can get very thick, and there is this upper Eagle Ford. And I think the industry right now has also come to grips with how effective have these historical fracs been in the way of frac height. That's a big learning factor that I think is going to come in the future.

Thanks a lot. Just the sort of things I was interested in.

And your next question is going to come from the line of James Spicer with Wells Fargo.

Hi, good morning. In your prepared remarks, you talked a lot about maintaining balance sheet strength during this period of volatility. I was wondering if you could just elaborate a little bit on what metrics you use to evaluate balance sheet strength, and what targeted levels you have?

Well, I think we can go back to some of the specifics we've been talking about today. First of all, it is very important to us that we have good capital allocation. And in that regard, we do look at present value to investment. We look at payout. We look at rate of return. Those are the three most important metrics to us right now. We are allocating most of our capital, the most significant amount to the Eagle Ford. We clearly have what we believe is excellent rock in the McMullen area and over in the Fasken area. So we're allocating capital to where we think the best resource is.

In terms of the actual numbers, the preliminary guidance we're giving for next year is to significantly reduce our capital that we spend in 2014, to a level of about $240 million to $260 million as a capital budget. With that, we believe we can deliver a production base or a production level that's essentially equivalent in volume to 2014, but would be slightly more gassy. But again, the areas we're working in, that gas has got exceptional economics, using the parameters that I just mentioned.

Additionally, to the extent that we look at EBITDA and debt metrics, we currently in this commodity market, using about $80 on oil and $4 on gas, we see a potential outspend of about $60 million to $70 million. We will work in other ways to close that gap. We have cost initiatives underway in our LOE, in our G&A. And within the budget I've mentioned, there are discretionary items that we might further cut.

We also have dispositions from strategic disposition opportunities that we're looking at in South Texas that might be similar to a [socka] type transaction to a disposition of a non-core area like the Central Louisiana area. And should we have proceeds above and beyond that gap, we are committed to bringing the bank line, or even a portion of long-term, debt down.

Thanks. I appreciate that. What about metrics in terms of debt-to-EBITDA, liquidity under the revolver, those sorts of things? How do you think about that?

Absolutely we're focused on that. We realize we're kind of at the high-end of our leverage appetite. So we keep a keen eye on coverage for debt-to-EBITDA, net debt-to-equity. From a bank covenant standpoint, we aren't even close to breeching that. So again, we've got a keen eye on the fact that our debt-to-EBITDA is at the high-end of our appetite, and we think you would agree with that.

James, I don't think you want a hard and fast rule there, but obviously, we look at cash flow coverage to debt, whether it's debt-to-EBITDA or interest coverage. We understand what the market looks at. We understand what the rating agencies look at. We understand how that can vary, depending on the price outlook you look at and forecast into our production guidance.

We believe we are in the high-end of where we want to be. We want to get that down. We did that this year with the Saka transaction. That was an important point. If you recall, the very beginning of the year, we said we would do something with regard to bringing debt down, not just funding the gap. I think the same plan's in place for 2015. We want to be sure we fund any gap, if we have it, depending on what prices turn out to be. Obviously, with the commodity environment the way it is, we started by pulling CapEx down. But continue to work on, obviously, the clay tex disposition. We also are working on some other things. And to the extent that we do a transaction that brings in proceeds over and above the amount needed to fund any capital spending gap, we intend to reduce debt. Obviously, initially you'll pay down short-term debt, but the plan would be try to actually retire some of our long-term debt, as well.

Okay, great. I appreciate that. And then, some of the scenarios and outlook that you've laid out, it sounds like you've been focused on $80 oil and $3.50 or $4 gas. Just wondering if we kind of stress-test things going down a little bit at $70 oil or $75 oil, how that changes the picture in terms of capital spend, capital allocation. Or how you think about those sorts of cases.

That's a good question. Clearly, we're not going to just start a budget and not pay attention to the macro environment. To the extent that we see a sustained low period, and to the extent it's below $80, we can take further steps. We clearly have to go in with some momentum into next year. And, particularly on the gas side, we're not affected unless gas also goes down. But our gas projects are strong. Our condensate projects are strong.

One thing that I'm a little concerned of is that this sell-off that's occurred in the equity markets has been -- energy equity has been very indiscriminate between oil and gas. And you've basically seen all the oil and gas equities go down, whether they had a strong gas position or not. So while we are affected by $70 oil, most certainly, we're not as affected as you might consider, because again, 27%, 30% oil there. On the other hand, gas is a more positive -- or, I think there's more upside in gas at the moment. So that part of the capital spending we would not pull back. Some of the oil, we might defer. But also, costs are going to be coming down. And so if we get in that environment, we're going to be pushing very hard to bring the costs down.

As I said, we do have a fairly aggressive effort to either have strategic transactions that go on that principally would deal with gas. I think they are more likely to be gas-oriented transactions, and we do have the disposition in Louisiana.

We are not going to just -- I said we had preliminary guidance in 2015. The reason I'm using preliminary is, no one knows right now where this oil market's going to go. And so we will adapt as we see that macro environment.

Okay, great. I appreciate it, guys. Thank you.

Thanks, James.

And your next question will come from the line of Adam Leight with RBC Capital Markets.

Good morning, everybody.

Good morning.

A clarification. Can you give me a sense of where you think your overall decline rate is at this point?

We may need to come back on that one. In terms of overall decline rate, it varies by property. If you go over to Louisiana, I think we've got that where we have mitigated the declines in Lake Washington, and I think we basically saw a 7% decline quarter to quarter. But we've got a lot of projects out there that we think we can continue to either have a decline of that nature or less, as we come in. Our clay tex area actually, quarter to quarter, had a slight increase; I think it was about 3%.

But overall, that area tends to decline 25% 30%, depending upon whether there's activity. You bring activity back in there, and you can really mitigate that decline. In our Fasken area, underneath -- I would have to get some of the reservoir experts in here. These wells hold up very well in their early three- to six-month period. Even though you test them at 20 million or higher a day, it's not unusual for us to really see these wells coming in and staying above 10 million to 14 million a day across a three- to six-month period.

But that's managing the decline. Clearly, if you wanted to just produce it at full bore, you would have a much higher decline. So we're managing that decline in Fasken. But as shale wells go, you can typically easily see on early oil wells; you can see 75%, 90% declines in the first year. But then they flatten and the mix is such that I would be reaching to tell you what the overall decline is. We would have to do it by area.

I get that. I'm just trying to get a better sense of the capital intensivity of your existing asset base, and given the preliminary discussion of spending and production expectations, what that really means on a corporate level.

I think one way to look at it -- it's a reasonable question that's hard to answer in the new shale world. Because it does depend on the activity level and how many of your new wells are contributing to your current production.

I think it's reasonable to say that bringing our budget down to the 2.40% to 2.60% range, we see our production being about the same. And in that 2.40% to 2.60%, you'd see similar proportions to some capitalized G&A, some lease oil, and some other things that aren't well-specific; like we did this year, in proportions.

So just to clarify again, similar production levels -- is that off a third- fourth-quarter type of baseline?

That's based off of the average 2014 daily production rates. So, if you take our guidance of what we expect 2014 average daily production rate, we would expect that same average daily production rate in 2015.

Okay.

And if you want to look at it on a cumulative basis, we forecast annual production to be 12.2 million to 12.3 million barrels of oil equivalent. So we would expect the same level in 2015.

Thanks, Bruce. Okay, one last question. Do you have a sense of the magnitude of the operating cost reductions you're targeting and think are achievable, and how long it would take to realize some of that?

Well, I think what we're targeting is achievable. As you look at the development of our Eagle Ford assets in particular, we are getting more efficient at producing the oil. We're getting more efficient at producing condensate. And gas just -- you know, my whole career, I've found that gas is the place where you can get the best LOE economics. So like a typical gas well; $4 wellhead price. And if you're developing that gas in terms of a DD&A or finding cost-type of number at sub-$1 or maybe $0.80 even, the operating costs on a gas well might literally only be $0.30 to $0.40. When you compare that to the percentage of an oil price, they're exceptional. Our overall target on a BOE basis is to reduce it about 5% to 10% next year.

Okay. That's what I was getting at, 5% to 10%. That's LOE, transportation, G&A, or that's just LOE?

Transportation, you're not going to reduce that significantly, because that's fairly locked in. On a unit basis, the more production volume you have, it comes down on a unit basis.

But I think LOE and G&A, it's fair to say that's our target, Adam.

Okay. That's just what I was looking for. And how long do you think it takes to start to see the results of whatever initiatives you're undertaking?

I think we've already started those initiatives, and we think we'll be able to get there for the full year of 2015.

Yes, we're seeing results right now. On our LOE, we're making great progress there.

That's great.

Yes, what we're doing here is a lot more than a sharp pencil. We're taking the actions, we're drilling the right kind of wells. Again, we're giving preliminary guidance for 2015 for the very reason that everyone's asking. And that preliminary guidance, it's going to be very dependent on the macro environment. But this is an opportunity to cut costs and to get your cost structures down. We're not going to miss that opportunity.

I appreciate that. Thanks, guys.

Thanks, Adam.

And your next question will come from the line of Andrew Coleman with Raymond James.

Good morning. Thank you for taking my call. Looking at the CapEx budget, you mentioned a couple of different times--

Andrew, we're having trouble hearing you.

Can you hear me now? Is that better?

Yes, much better.

Sorry about that. Well, good morning. Thinking about the CapEx budget, can you give us a sense on phasing in that budget? I assume it's probably more front-end loaded. If it is the case, could you give me an idea on the flexibility you have across your service providers to lay down rigs or opt out of contracts?

Andrew, it's Bob. It's a little bit front-end loaded, but not much. It's pretty spread out through the year. In terms of flexibility with our drilling contractors, we do have flexibility built into our contracts. And in terms of term, we're in the middle of those negotiations right now, so I don't want to say too much. But we've historically done a pretty good job of building that flexibility in on the drilling side.

On the frac services side, we do not have a commitment for frac services, but we basically work off of schedules that we work with our two primary frac providers. But we are not under a take-or-pay type arrangement with our service company that way.

Okay, all right. Good deal. So it's going to be just a quick drop then from about the $100 million a quarter run rate to -- what, about $60 million a quarter?

And secondarily, just looking at -- oil just started to dip down. Can you give me a sense of exiting third quarter, what the cushion was on the ceiling test?

There was plenty of room there.

Yes, we don't report that separately.

Okay, all right. Fair enough. Thank you.

Thanks, Andrew.

And currently, there are no further questions.

Okay. Well, if there's no further questions, we want to thank you for joining us on the call, and look forward to having a good year and reporting back to you. Thank you.

Thanks for listening in.

Once again, we'd like to thank you for your participation on today's Swift Energy conference call. You may now disconnect.