SilverBow Resources, Inc.
Q3 2014 Earnings Call Transcript

Published: 6 Nov 2014

[Operator:]

Good morning. My name is Holly and I will be your conference operator today. At this time, we'd like to welcome everyone to the Swift Energy Company's Third Quarter 2014 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, you will have an opportunity to ask questions. (Operator Instructions). I would now like to turn today's conference over to Mr. Paul Vincent, Director of Finance and Investor Relations. Please go ahead sir.

[Paul Vincent:]

Good morning. I am 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 to 30 minutes and have allowed additional time for questions.

[Terry Swift:]

Thanks Paul and thank you to everyone joining in the call today. Our third quarter demonstrates that we are 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 in 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 vein, 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 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 of 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 by about $11. Our completion work is also improved during the quarter, as we continue 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 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 33.4 to 33.7 Mboe/d from an old range of 32.6 to 33.2 Mboe/d. As we have consistently stated, we have built a balanced diversified portfolio, that will deliver value in a variety of commodity price environment. Our assets across Webb, LaSalle 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 have 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 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 in 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 have 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 expenditure 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 continue to work on the sale of our Central Louisiana assets. At this point, any proceed 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 have 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 the core values. Swift Energy has a dedicated and experienced staff of oil and gas professional, and I can assure you that no one will work harder through these difficult times than our team. With that, I will turn it over to Alton to summarize our third quarter 2014 financial results.

[Alton Heckaman:]

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 Energi for 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 pre-tax $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 valorem 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 of 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 collars, and also locked-in basis spreads, which protected against volatility we saw between prices at our field delivery points in major terminals. Complete and timely details of Swift Energy's price risk management activities can always be found on the company's web site. As we 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 have included additional financial and operational information in our press release, including guidance for the fourth quarter. And now I will hand it over to Bruce Vincent.

[Bruce Vincent:]

Thanks Alton and good morning everyone and thanks for listening. Today, I will discuss the third quarter 2014 activities, 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 a 32,542 barrels of oil equivalent per day. This is above the high end of our guidance, and highlights the technical efficiencies we have 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 Energi, 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 through the Eagle Ford shale in the company's South Texas area. Three of these wells were drilled in the 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 one in the AWP area in McMullen county. In the Southeast Louisiana core area, which includes the Lake Washington and Bay De Chene 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 of 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 recompletions and four product optimization projects at Lake Washington during the quarter. We have identified numerous opportunities throughout the field for additional recompletions 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 [indiscernible], all those 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 first quarter of 2013 production in the same area, was down 16% when compared to the 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 in anticipation of bringing the 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 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 we will refer you to that for the specifics. Three new wells 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 drilling complete design, and expect to drill even higher quality wells going forward, while seeing opportunities to further reduce capital costs. In McMullen country, 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 in 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 have applied our current generation drill and complete design, and have observed a meaningful uplift in initial and sustained performance. We are now to believe 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 well. 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 2014, an increase of 3% from the second quarter of 2014 production in the same area, but down 33% from prior year levels, primarily due to low activity and natural declines. I will now turn the call over to Bob Banks who will cover the highlights of the quarter.

[Bob Banks:]

Thanks Bruce. As Terry mentioned, our commitment to deploy customized engineering completions in horizontal laterals drilled in precise target zones for the Eagle Ford 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 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 measure 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 east of Fasken, adjacent to our Whitehurst lease. For these two wells, we set the bar high for our future bracken wells, as we set new records for days on well, well cost, and cost per foot metrics in this area. In fact, on a program-wide cost per foot metrics, our best wells performance from 2013 is now our average performance with 2014, thus further evidencing our continuing improvement in the trends. Let me take a few minutes to talk about production operations. We get very focused on drilling and completions in these shales because of costs, 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 paraffin 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 in 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 pressure 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 will 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 have 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 discussion in our industry, and despite the drop in price, the demand in Eagle Ford shale, South Texas for our oilfield services, such as drilling rigs, pressure pumping services and [indiscernible] 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 for 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 in the last few months on availability and price will come into balance. We believe the supply chain organization that we have developed in relationships they foster with our vendors, and continue to be one of our key operational and strategic advantages in any commodity price environment. As Terry indicated, we've 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 have 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 in any transaction that we would entertain must increase financial liquidity, reduce leverage and improve our operating metrics. We have put a great deal of energy into our 2014 program to-date, and its 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.

[Terry Swift:]

Thanks Bob. Before we open the line for questions, I will summarize today's call, and 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 are confident we will 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 cost per foot and completion costs in our areas in South Texas. Enhanced drilling and completion designs continue to improve the results we are observing in all of our South Texas Eagle Ford results. Based on the result 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 volume for the year to 33.4 to 33.7 Mboe/d from the prior range of 32.6 to 33.2 Mboe/d. With that, I'd like to begin the question-and-answer portion of our presentation.

[Operator:]

(Operator Instructions). And your first question is going to come from the line of Michael Hall with Heikkinen Energy Advisors.

[Michael Hall:]

Thanks. Good morning guys.

[Terry Swift:]

Good morning.

[Michael Hall:]

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

[Terry Swift:]

Those are good questions Michael, and clearly with the commodity markets, we got the main flexibility to keep, what I would say, our 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 are going to significantly reduce our CapEx from last year. The range we are -- in a preliminary fashion guiding is 240 to 260 of the CapEx. The vast majority of that, again, we are -- this 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 am calling our improvements in the wells, and by that I mean better well results, lower costs drilling the wells, but also cutting cost in areas like LOE, G&A, working hard, as Bob said, with the vendor; should we have a lower commodity price deck next year, we are 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 its real important to note, that we have still got, what I would say very-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. And 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 have got these condensate wells and exceptional results of the technology transfer, again the recent two wells, IP average 3,200 barrels a day, we are seeing very good present valued investment ratios, very good rates of returns, very good payout levels. Using about an $80 for oil and $3.50 to $4 for gas. That's how we are allocating capital. We are clearly -- we will continue to keep the opportunity to do more projects if oil bounces back, but we are 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 HPPed or requires very little drilling to just keep it going, or the drilling in different areas we are at, we have the exceptional economics. Finally, just talking about allocation of capital and really driving to improve liquidity and spending levels to be more matched or balanced with next year. Looking at EBITDA, cash flow, everyone has got to do their own modeling. But I think our number just kind of rough, this is preliminary. The macro environments certainly are going to dictate a lot, but we are looking at maybe as much 60 million to 70 million, might be the outspend. But I'd say, maybe only to an extent that we are 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 we are going to do that? Again, we are looking at cuts in LOE, we are looking at cuts in G&A, we are looking at lower well costs, we are also looking at asset dispositions that are non-core, both in terms of Louisiana. We have got an ongoing effort there that we have articulated, it's 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 are on the course to be able to give ourselves that opportunity.

[Michael Hall:]

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

[Alton Heckaman:]

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

[Michael Hall:]

Okay, that makes sense, great. Okay, and I guess maybe just also wanted to get a little more color around -- kind of 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?

[Bob Banks:]

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

[Michael Hall:]

Okay. I appreciate the color guys.

[Operator:]

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

[Neal Dingmann:]

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

[Terry Swift:]

Well to answer that in a precise way, you'd have to get our production engineers in a room, and you could confer a little bit of a debate. But I think the guys are pretty well fixed into gas areas that this is not a real concern of ours. The ultimate recovery of these wells is really more based on how we are fracking them, and also the quality of the rock. You clearly can pull a well too fast and adversely affect your near well bore drawdowns, 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 drawdown you're getting and avoid that. We have no concern right now that the chokes that we are using, choke sizes are adversely affecting. In fact, we think it's pretty important to balance this choke size. We are getting the water off the formation early, and 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.

[Bob Banks:]

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

[Neal Dingmann:]

That makes sense. And then just one last one; for Alton -- Terry, for you or Alton. Just when you think about allocation next year, I know you mentioned cutting overall CapEx. But just on allocation, I don't know if you haven't fully have a 2015 plan, I realize that, but how you think about maybe Fasken in the surrounding areas, versus just the other total part of the plays?

[Terry Swift:]

Well we are looking at a balanced program in terms of keeping rig active over in the Mullen county area and drilling both oil and some of these very high impact of condensate gas wells. We are keeping the rig over in the Fasken area, we are 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 the partner. The allocation of capital is really not to overly -- over produce or go too aggressive in Fasken, because I think strategically, we do believe the LNG market is going to be a great Fasken and properties like it, it's going to be a great backyard to be in, relative to LNG. So we are not trying to peak that out, and just have it gone in four-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 are working on that. I think there is some nice running room for us at some very modest capital levels.

[Alton Heckaman:]

In terms of the non-Fasken areas in South Texas, the activity will be obviously at AWP and McMullen County, but we also planned a couple of wells and Artesia wells. We have not drilled one with this more recent design, both drilling and completion design that we are 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.

[Neal Dingmann:]

Thanks guys. That's very helpful.

[Terry Swift:]

Thanks Neal.

[Operator:]

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

[Leo Mariani:]

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

[Bob Banks:]

Leo its Bob. Let me kind of 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 are routinely $3 million a well, even for those longer laterals, and that would drill and pre-complete type costs. As you get over into the SMR-PCQ areas, again, PCQ, we are kind of in that three -- a little over three range. We had one well this year in SMR. We actually drilled -- spud the TZ [ph] in 10 days, about $2.4 million. So hopefully, that kind of gives you a range of some of the numbers.

[Leo Mariani:]

All right. I guess if you threw at us completion costs in, what would your drilling complete costs be in those areas?

[Bob Banks:]

Well, the completion costs are -- it’s a combination. We are drilling longer, so we are increasing the stage count. We are increasing the sand loading. 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 are up well over 1,300; approaching 1,400 foot of sand performance per -- pounds of sand per completed lateral. So we are driving costs down, while at the same time, putting more stages in. Going from an average less Q3 2013, 15 stages; we are now averaging about 23 stages. So very different dynamics in terms of driving costs down and increasing lateral length and sand loadings.

[Bruce Vincent:]

If you actually look at the first six months of this year, and the average drilling complete costs was $7.1 million.

[Terry Swift:]

This is Terry, the one thing I do want to point to is, prior to the oil price basically collapsing, 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 are keenly aware that that's not sustainable. So looking into the 15 year program, we actually think prices would be about the same as what we have experienced in 2014 or lower. But near term, we have seen some price pressure.

[Leo Mariani:]

All right, that's helpful. I guess, you guys obviously referred a couple times to potential new JVs or partnerships. Could you help us just maybe understand that a little better, would that be kind of taking and existing Swift assets and bringing in a partner on, or would that be potentially be the acquisition of some new dry gas acreage, like you spoke of and then bringing a partner in on that?

[Terry Swift:]

I'd say yes and yes. What we have tried to do in the Eagle Ford, and thus far, I believe we have 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 too good of a property and that gives a good result. I think you look at the Saka transaction, you look at the Fasken transaction, that's where we would -- that's the kind of thing we would do. We don't have any specific asset targeted that we are ready to talk to folks about publicly. We do have relationships where we know what folks want, and we also have acreage that we are on the hunt for this 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 CLATEX, it has taken way too long, but its still in play. That might also have a strategic element to it as well. Those are the kind of things we want to do, but in Louisiana, we clearly would transact more in a disposition mode, since its not a core area.

[Leo Mariani:]

All right. I guess just a follow-up on what you said there about Louisiana, is there any kind of like drop-dead date or anything like that that you guys have set on a disposition there, where if you get past it, its just [indiscernible] or anything?

[Terry Swift:]

You know, I think a drop dead date would be nice, and in some ways, maybe we already had it in the past. We have a live effort going and we want to see it to its fruition, whether that means we get our deals done, or whether we then sell -- begin to seek to do other things with the property. We clearly need to go. Should we not have a transaction by the end of the year, we clearly need to go into the property and begin to do some low capital types of things, the 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 will see us work it in pieces and do some work in the fields.

[Alton Heckaman:]

I think you have to understand that in terms of working this transaction or working with another party and have some timelines and milestones set up on that. As long as you're making progress and you see an ultimate completion of a transaction, you're going to continue to 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. 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.

[Leo Mariani:]

All right. Thanks for all the color guys.

[Operator:]

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

[Bertrand Donnes:]

Good morning. Great quarter guys.

[Terry Swift:]

Thanks.

[Bertrand Donnes:]

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

[Bob Banks:]

Yeah I think we are going to enhance the methods. I think one of the things I mentioned on the call was, the relationship of inner stage completions to the total production from the well. So we are just getting more precise with our completions, and we are 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, and 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 applied, what our learnings have been so far, but you will continue to see us tweaking and getting better in Fasken and AWP and all of our properties.

[Bertrand Donnes:]

Perfect, thanks. And maybe could you put some color on the LOE bump that it looks like fourth quarter was guided to? Just a slight move-up, but is that just conservatism, or do you think -- is there something we need to look for, kind of going into 2015?

[Terry Swift:]

I don't think there is 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.

[Bertrand Donnes:]

Right. Okay. And then just one last one, how are you looking at hedging in 2015, maybe with the high results in Fasken, are you looking to lock-in more gas volumes, or are you just going to kind of play the commodity back up and down?

[Terry Swift:]

Well there is clearly several different views on hedging, and first I will 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 is so low. On the gas side, you are coming into winter, and 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 go 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.

[Bertrand Donnes:]

Okay. Well thanks guys.

[Terry Swift:]

Thanks.

[Operator:]

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

[Noel Parks:]

Good morning.

[Terry Swift:]

Good morning Noel.

[Noel Parks:]

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

[Bob Banks:]

Noel, its Bob. I mean, we have though about that. We have even played around a little bit with some refracking in the early days. I think the way we are looking at that right now, is that's kind of future activity, compared to what we have now to do. But I think you will see the entire industry work on that kind of down the road, and that's kind of how we are thinking about it too.

[Bruce Vincent:]

In case of first things first, you know, you really want to go into 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 am fairly confident that we will and the industry will.

[Noel Parks:]

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

[Terry Swift:]

Let me attempt that -- this is Terry, let me attempt to answer that. Its not as simple as just a longer lateral. Its 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 have 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, that we have been getting much-much better at that. I am very proud of how the geophysics and geology is working together within engineering or 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 have the limits by any means. But certainly, are you doing some big, 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 costs down, I think there is more opportunity there to get the costs down. But at the end of the day, its not just about getting the costs down, its about getting better wells, and we are certainly seeing that and proud of our results. And Noel, just adding 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 are even seeing, 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 is still a learning curve we are on, using the success we have built upon and with these customized frac designs and customized completions.

[Bob Banks:]

It’s a great question, and as we talk through it, I think I will add that there is one other area that I think there is 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 center 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 is going to come in the future.

[Noel Parks:]

Thanks a lot. That was [ph] everything I was interested in.

[Operator:]

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

[James Spicer:]

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?

[Terry Swift:]

Well I think we can kind of go back to some of the specifics we have 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 -- most significant amount to the Eagle Ford. We clearly have, what we believe is excellent rock in the McMullen area and over the Fasken area. So we are allocating capital where we think the best resource is. In terms of the actual numbers, the preliminary guidance we are giving for next year, is to significantly reduce our capital that we spent 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 are 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 maybe $70 million. We will work in other ways to close that gap. We have cost initiatives underway and our LOE and our G&A and within the budget I have mentioned, there are discretionary items that we might further cut. We also have dispositions from -- strategic opportunities that we are looking at in South Texas that might be similar to a Saka 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 the long term debt down.

[James Spicer:]

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

[Alton Heckaman:]

I mean, absolutely we are focused on that. We realize we are kind of at the high end of our leverage appetite, and 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 breaching that. So again, we 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.

[Bruce Vincent:]

James, I don't think you want a hard and fast rule there, but obviously we look at cash flow cover t debt, whether its 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 upon 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 at 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 is in place for 2015. Obviously, we want to be sure we fund any gap if we have, depending on what prices turn out to be. Obviously with the current commodity environment the way it is, we started by pulling CapEx down. But continue to work on, obviously the CLATEX disposition, but 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 will pay down short term debt, but the plan would be try to actually retire some of our long term debt as well.

[James Spicer:]

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

[Terry Swift:]

That's a good question. I mean clearly, we are not going to just start a budget and not pay attention to the macro environment. To the extent that we really see a sustained low period and to the extent that'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 are not affected, unless gas also goes down. But our gas projects are strong. Our condensate projects are strong. One thing that I am a little concerned of, is the sell off that has occurred in the equity market, has been -- energy equity has been very indiscriminate between oil and gas, and you have 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 are not as affected as you might consider; because again 27%, 30% oil there; and on the other hand gas is a more positive or I think there is more upside in gas at the moment. So that part of the capital spending we will 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 are going to be pushing very-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 on 2015. The reason I am using preliminary is, no one knows right now where this oil market is going to go. And so we will adapt, as we see that macro environment.

[James Spicer:]

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

[Terry Swift:]

Thanks James.

[Operator:]

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

[Adam Leight:]

Good morning everybody.

[Terry Swift:]

Good morning.

[Adam Leight:]

Clarification; can you give me a sense of where you think your overall decline rate is at this point?

[Terry Swift:]

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, we have got that, where we have mitigated the declines unlike [indiscernible]. I think we basically saw a 7% decline quarter-to-quarter, but we have 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 CLATEX area actually quarter-to-quarter has a slight increase, I think its about 3%. But overall, that area tends to decline 25%, 30%, dependent upon whether there's activity. You bring activity back in there, and you can really mitigate that decline. In our Fasken area, underneath I'd 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, its 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 at a full bore, you'd have a much higher decline. So we are managing that decline in Fasken. But as share of wells, 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'd be reaching to tell you what the overall decline is. But we'd have to do it by area.

[Adam Leight:]

I get that. I am 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?

[Terry Swift:]

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 its reasonably to say that bringing our budget down to the $240 million to $260 million range, we see our production being about the same. And in that $240 million to $260 million, you know, you'd see similar proportions to some capitalized G&A, some leaseholds, some other things that aren't well specific like we did this year, in proportions.

[Adam Leight:]

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

[Bruce Vincent:]

That's based off of the average 2014 daily production rate. 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. 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.

[Adam Leight:]

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

[Terry Swift:]

Well I think what we are targeting is achievable, and as you look at the development of our Eagle Ford assets in particular, we are getting more efficient, producing new oil. We are getting more efficient at producing condensate. And gas, just -- in my whole career, I 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 the DD&A or finding cost type of number, sub $1 or maybe $0.80 even, the operating cost on a gas well might literally only be $0.30 to $0.40, and you compare that to the percentage of an oil price, they are exceptional. Our overall target on a BOE basis is to reduce at about 5% to 10% next year.

[Adam Leight:]

Okay. That was -- 5% to 10%, that's LOE, transportation, or G&A, or that's just LOE, or is it?

[Bruce Vincent:]

Transportation here not going to reduce that significantly, because they are kind of locked in. On a unit basis, the more production volume you have, it comes down on a unit basis.

[Bob Banks:]

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

[Adam Leight:]

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?

[Bruce Vincent:]

I think we have already started those initiatives, and we think we will be able to get there for the full year in 2015.

[Alton Heckaman:]

Yeah we are seeing results right now on our outlook. We are making great progress there.

[Terry Swift:]

What we are doing here, is a lot more than a sharp pencil. We are taking the actions, we are drilling the right kind of wells. Again, we are giving preliminary guidance for 2015 for the very reason that everyone's asking, and in that preliminary guidance, its 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 are not going to miss that opportunity.

[Adam Leight:]

I appreciate that. Thanks guys.

[Bruce Vincent:]

Thanks Adam.

[Operator:]

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

[Andrew Coleman:]

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

[Bruce Vincent:]

Andrew, we are having trouble hearing you.

[Andrew Coleman:]

Can you hear me now, is that better?

[Bruce Vincent:]

Yeah, much better.

[Andrew Coleman:]

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

[Bob Banks:]

Andrew, its Bob. It’s a little bit front end-loaded, but not as much. Its 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 are in the middle of those negotiations right now, so I don't want to say too much, but we have 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 of arrangement with our service company that way.

[Andrew Coleman:]

Okay. All right. Good deal. And so give me just a quick drop then for -- about the $100 million a quarter run rate to I guess about $60 million a quarter. Then I guess secondarily, looking -- oil has just started to dip down. Can you give me a sense of kind of exiting the third quarter, what the cushion was on the ceiling test?

[Bruce Vincent:]

There was plenty of room there.

[Bob Banks:]

Yeah, we don't record that separately.

[Andrew Coleman:]

Great. All right. Fair enough. Thank you.

[Operator:]

And currently, there are no further questions.

[Terry Swift:]

Okay. Well if there is 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.

[Bruce Vincent:]

Thanks for listening in.

[Operator:]

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