SilverBow Resources Inc (SBOW) 2011 Q3 法說會逐字稿

Good morning. My name is Dawn, and I will be your conference operator today.

At this time, I would like to welcome everyone to the Swift Energy Company third quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions)

Mr. Paul Vincent, you may begin your conference, sir.

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy's third quarter 2011 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. Terry Swift will then summarize before we open up the line for questions. Also present on the call is Jim Mitchell, Senior Vice President of Commercial Transactions and Land.

Before I turn it 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.

Thanks, Paul, and thanks to everyone on the call for taking time to join us today. Since the beginning of 2009, we have witnessed oil and gas activity accelerate rapidly in South Texas. The rig count in South Texas has exploded from under 10 rigs operating in January of '09, to over 180 as of the end of September 2011. This is due to many factors, not least of which are the commercial qualities and operational accessibility of the Eagle Ford Shale. While we are highly focused on our Eagle Ford Shale, and [almost tight] gas sands positions, we are also witnessing the operational pressures that can be associated with this type of growth. In order to compete for limited services and supplies, we believe organizations must take a disciplined approach to supply chain and project management.

This approach includes taking steps, as we have, to secure drilling rigs, completion services, source water, raw materials, manpower; and capacity to gather, transport, and process hydrocarbons. Clearly, scale is important in this type of environment, and Swift Energy Company continued to scale its operations during the third quarter, with 10 wells drilled and 10 wells completed during the quarter. We also saw our dedicated capacity grow with the construction and commissioning of 90 million cubic feet a day of dedicated natural gas transportation and processing take away in McMullen County.

With a larger portion of our activity under contractual commitment than in the past, we must also have a strong balance sheet in order to protect against downturns. We do this by maintaining low leverage and high liquidity, selling non-core assets, holding capital spending within a reasonable range of cash flows, maintaining our liquidity, and using the capital markets to match our long and longer-term assets with longer-term financial instruments. Along with the balance sheet, our operational and financial strategy provides that we seek diversity among our assets.

Over time, we have matured 3 distinct core operating areas in Texas and Louisiana. With the dedication of capital to any of these areas, we can grow production and reserves in all 3. While South Texas is where our operational focus is today, we maintain a multi-year inventory of oil projects in the Lake Washington field, which benefits from strong Gulf Coast pricing realizations, generating high margin returns and free cash flow. We intend to resume drilling operations later this year or in early 2012 in this field, and will keep a rig active for most of the year.

We also boast a deep exploration inventory that we are maturing in the Southeast Louisiana area, which we expect to test within the next 2 years. In Central Louisiana and East Texas, we are utilizing new technology to transform a mature asset base to a growth area. Our large partnership area with Anadarko in the Burr Ferry area of Vernon Parish provides ample running room for a multi-year drilling program targeting the Austin Chalk. We're also re-evaluating the Austin Chalk and our Masters Creek Field to further assess further development opportunities there. Finally, in this area, we are now assessing the Wilcox formation in the South Bear Head Creek Field in Beauregard Parish for the potential to drill horizontal wells.

Bruce and Bob will detail all of our operational activity in a few minutes, but first, I would like to review some of the highlights of this quarter. The completion of 9 operated rigs and 1 non-operated well in South Texas -- with these completions and subsequent performance of these wells are critical to our momentum in 2012. So far, in the fourth quarter, 2 high-rate oil wells, the SMR 4H and the SMR 5H, have been completed in McMullen County. These wells were drilled from a multi-well pad, which allowed for cost and time savings during the drill and complete operations. The SMR 4H well had an initial production rate of 1,398 barrels of oil per day, 2.7 million cubic feet of gas per day, and 192 barrels of natural gas liquids per day, with flowing casing pleasure of 3,125 PSI on a 16/64 choke. The SMR 5H well had an initial production rate of 1.188 barrels of oil per day, 0.4 million cubic feet of natural gas per day, and 57 barrels of natural gas liquids per day, with flowing casing pressure of 3,600 PSI on a 14/64 choke.

In Lake Washington, our production optimization program continues to yield good results. We're preparing to begin a multi-well drilling program there before the end of this year. In our Central Louisiana/East Texas area, 2 wells were drilled during the quarter in the Burr Ferry area, and 1 well is currently drilling in our Masters Creek Field. We are very early in the process of data collection, and still testing development concept, but we have been encouraged by what we have seen to date. Drilling activity should increase in this area in 2012.

We're having a very strong year, despite challenges we faced this year, primarily with the timing and online dates of third-party controlled projects. We have made great strides in controlling larger portions of our supply chain, and entering into strategic service agreements that allow us to control our destiny to a greater degree in the future. Our production reserves and cash flows are all growing nicely. More importantly, these metrics are poised to grow to higher levels next year. We have balance, diversity, and a defined project inventory across our assets like never before in the company's history, and we have the managerial, operational, and financial talent in-house to deliver growth for many years to come.

And now I'll ask Alton to present the third quarter financial results.

Thanks, Terry, and good morning.

Third quarter was a good quarter for Swift Energy, with considerable production and revenue growth compared to the prior year. Our production increased 23% from the third quarter 2010 numbers; and oil prices remained solid during the quarter, as reflected in Swift's financial results. Oil and gas sales were $143 million, a 35% increase from 3Q '10. Income from continuing operations was $17 million, or $0.39 per diluted share, up from $0.24 in 3Q '10. Cash flow before working capital changes came in for the quarter at $2.11 per diluted share; and 3Q '11 production was up 23% from the prior year at 2.54 million barrels of oil equivalent, though slightly below our quarterly guidance for reasons discussed in our press release.

Crude oil prices were 38% higher than third quarter 2010 levels, while natural gas prices actually decreased by 5%; combined for an overall 10% increase in our realized price per BOE in 3Q '11. Our controllable cost of metrics compared to guidance as follows -- production costs came in at $10.31 per BOE, within guidance. G&A came in at $4.48, slightly above guidance. DD&A was within guidance at $21.40. Interest expense came in at $3.32 per barrel, and production and ad valorem taxes were within guidance at 9.5% of revenue. The net result was income from continuing operations for the quarter of $17 million, $0.39 diluted, above the First Call mean estimate. Our effective income tax rate for the quarter was 37.9%, just slightly above guidance. Cash flow before working capital changes for 3 Q '11 came in at $90 million, or $2.11 per diluted share, while EBITDA was $91million for the quarter.

Our quarterly CapEx on a cash flow basis was $124 million. Our hedging activities were minimal during the quarter. We did not have any hedges outstanding at the end of the quarter. Please see our website for complete and current detail oil and gas hedging information. As we previously announced, we closed on the sale of certain nonstrategic assets in October, for $48.8 million of net cash proceeds, after interim adjustments. The buyer also assumed approximately $28 million of asset retirement obligations, or ARO, related to these properties.

As of the end of the third quarter 2011, we had no outstanding balance on our line of credit, and had $16 million in the bank. With receipt of the disposition proceeds in October, we have a strong liquidity position, putting Swift in a solid financial footing to execute our strategic plans during the remainder of 2011, and gives us financial momentum needed to get going into 20 12. As always, we have included additional financial and operational information in our press release, including revised guidance for the fourth quarter and full year 2011.

And with that, I'll turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton, and good morning, everyone, and thanks for listening in.

Today I will discuss third quarter 2011 activity, including our production volumes, our recent drilling results, activity in our core operating areas, and our plans for the remainder of 2011. Bob Banks will then provide greater detail on operational highlights of the quarter. So, beginning with production. Swift Energy's production during the third quarter of 2011 totaled 2.54 million barrels of oil equivalent, or 15.25 billion cubic feet equivalent, an increase of 23% over third quarter 2010 production of 2.07 million barrels of oil equivalent., and a decrease of slightly less than 5% from the 2.64 million barrels of oil equivalent, or 15.84 billion cubic feet equivalent, that was produced in the second quarter of 2011, and also slightly below our previously stated guidance range.

Third quarter production was limited by shut-in production across South Louisiana due to Tropical Storm Lee; delays in the commissioning of a third-party natural gas pipeline and processing plant in McMullen County; Texas, periodic transportation and processing curtailments under existing interruptible natural gas transportation agreements, also in McMullen County; and the failure in late September of a third-party operated gathering line handling natural gas production in Webb County, Texas. Additionally, late in the third quarter, a contracted drilling rig went out of service to undergo significant repairs. The loss of drilling activity caused by this rig being out of service will affect fourth-quarter production volumes and our year-end exit rate. These events I just mentioned negatively impacted production by approximately 120,000 barrels of oil equivalent in the third quarter, and are estimated to negatively impact full year 2011 production by approximately 530,000 barrels of oil equivalent.

As Terry mentioned, industry activity has advanced at unprecedented levels in South Texas. We believe that many of these unexpected and temporary events that periodically affect our production are symptoms of this industry's growth and expansion and success. We have adjusted our full-year production guidance accordingly, and now expect to produce between 10.3 and 10.5 million barrels of oil equivalent for the full year 2011. This equates to a growth of 24% to 26% over 2010 production. The unplanned loss of a drilling rig in South Texas and the uncertain online date of our operated well in Burr Ferry, which suffered a mechanical setback, lead us to lower our anticipated year-end exit rate to a range of 31,000 to 33,000 barrels of oil equivalent per day. This is lower than our previously guided range of 34,000 to 36,000 barrels of oil equivalent, and represents a 17% to 24% increase over our 2010 production exit rate level.

For our third quarter drilling results, Swift Energy drilled 11 operated wells and participated in 1 non-operated well during the quarter. In South Texas, 10 operated horizontal development wells were drilled in the Eagle Ford Shale Formation in South Texas. 6 wells were drilled in McMullen County, 3 wells were drilled in Webb County, and 1 well was drilled in LaSalle County. In Swift Energy's Central Louisiana/East Texas core area, 1 operated well and 1 non-operated well were drilled in Burr Ferry Field. 4 rigs drilling horizontal wells in Eagle Ford and [our] Olmos are active in South Texas. A fifth contracted rig in South Texas is undergoing repair work, and should resume drilling before the end of the year. 1 operated drilling rig is active in Central Louisiana and East Texas core area in our Masters Creek Field.

I will briefly review our activity in each of our 4 operating areas for this quarter, and then Bob will detail the highlights. In the Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene Fields, production during the third quarter averaged approximately 8,511 net barrels of oil equivalent per day, or approximately 51 million cubic feet equivalent per day, in this area. That is down 6% when compared to the second quarter of 2011 average net production for the same area. Lake Washington averaged approximately 7,756 net barrels of oil equivalent per day, or approximately 46.5 million cubic feet equivalent per day, a decrease of 1% when compared to the second quarter 2011 average daily volumes. Bay de Chene sequential production decreased 36% to 755 net barrels of oil equivalent per day, or about 5 million cubic feet equivalent per day. This sequential decline is due to no new drilling activity and natural declines.

In our South Texas core area, which includes our AWP, Sun TSH, Las Tiendas, and Briscoe Ranch Olmos Fields, and AWP artesian wells and Fasken Eagle Ford Fields, third quarter 2011 production averaged 15,745 net barrels of oil equivalent per day, or about 94 million cubic feet equivalent per day, a 4% increase in production when compared to second quarter 2011 production in this same area, and an 82% increase over third quarter 2010. This sequential increase is primarily from the 9 new operated wells and 1 non-operated new well brought online during the quarter, in addition to our ongoing production optimization efforts. Please see our press release, issued this morning, for specific information on each of these wells. It is important to note that this area did grow during the quarter in spite of weather, timing, and third-party related delays and curtailments experienced throughout the third quarter. Bob will spend time discussing our Olmos and Eagle Ford programs in greater detail.

The Central Louisiana/East Texas core area, which includes our Brookeland, Masters Creek, Burr Ferry, and South Ferry Creek Fields, contributed 2,555 barrels of oil equivalent per day, or about 11 million cubic feet equivalent per day of production in the third quarter 2011. Swift Energy is currently drilling an operated well in the Masters Creek Field, and will release this rig after it concludes drilling operations. We expect our joint venture partner to resume drilling in the Burr Ferry Field during the first quarter of 2012. In our South Louisiana core area, which is comprised of Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island, and Bayou Penchant, production averaged approximately 1,268 barrels of oil equivalent per day, or about 8 million cubic feet equivalent per day during the third quarter. These assets were sold as part of a package of non-core, nonstrategic assets during the quarter for $53.5 million. The net cash proceeds from this transaction will fund a portion of our 2011 capital expenditures.

I'll now turn the call over to Bob Banks to review operational highlights of the third quarter.

Thanks, Bruce, and good morning.

At the Lake Washington Field, we re-completed 6 wells and performed 10 production optimization projects during the quarter. The re-completions we did perform averaged an initial production response of approximately 563 gross barrels of oil equivalent per day. Our production optimization projects, which include sliding sleeve changes, gas lip enhancements, and returning shut-in wells to production, averaged an initial production response of 167 gross barrels of oil equivalent per day. This core area continues to receive strong Gulf Coast crude oil price realizations, and we intend to further exploit this pricing dynamic by returning a barge drilling rig to the Lake Washington Field to drill shallow and intermediate depth objectives around the salt dome.

Our ongoing production optimization projects will compliment this drilling program. In our Central Louisiana/East Texas area, we participated in 1 non-operated, well, and we drilled 1 Swift Energy-operated well during the third quarter. Both wells were drilled in the Burr Ferry area. The non-operated well, the GASRS 16-1, was completed in the Austin Chalk and had an initial production rate of 207 barrels of oil per day, and 1.3 million cubic feet of gas per day. This production rate is significantly lower than the first 2 wells drilled in the area. This well was an appraisal well, and was drilled near the southern extent of the Company's joint operating area, where it did encounter fewer natural fractures while drilling than what we see in the wells drilled further to the north. This well will be an extremely important well for us in furthering understanding the geology in the area, and will assist us in designing the most effective development plan for this Burr Ferry area.

The Swift Energy-operated GASRS 20-1 concluded drilling operations during the third quarter and has been completed. A mechanical problem occurred during the initial clean-up of the well that required a work-over rig to resolve. A work-over rig is currently on this well, and work is underway to remedy the issue. This well bore remained in zone for the entirety of the 4,254 foot lateral, and encountered high natural fracture density in the formation along with strong tubing pressure. The GASRS 20-1 well was drilled further north than the non-operated GASRS 16-1, and we believe it will be a highly productive well once we have resolved the mechanical issue.

We are also evaluating the Wilcox and the South Bear Head Creek Field in Beauregard Parish, Louisiana, to assess the potential for horizontal drilling in that area as well. In our South Texas area, as Terry commented, we were definitely impacted operationally by the third-party interruptions and timing delays associated with the rapid growth of industry activity throughout the area during the quarter. Many of the issues we encounter in South Texas are short-lived, and while specific events like pipeline failures are difficult to predict, it is probably safe to assume these types of events will continue to occur periodically until industry growth rates slow and oil field service and midstream providers add capacity.

We are addressing the challenges of operating in South Texas through our focused approach to supply chain management and vendor service alliances. We have secured committed drilling rigs, oil country tubular goods, and fracture stimulation services. We have also long-term water handling agreements and firm natural gas processing and transportation contracts. We are now sourcing raw materials further into the supply chain, including proppants, to help secure high-quality materials at lower cost. Our engineering training and retention programs are enabling us to do more production analysis and optimization work, even as we accelerate our activity levels. This important work includes optimizing when we move our oil- and condensate-producing wells in South Texas to artificial lift; and analyzing also ways to reduce our water management and waste water costs in the field, amongst many other things.

The results for the 9 operated third quarter wells and the 1 non-operated well completed in South Texas can be found in the table in our press release issued this morning. I would like to spend my time with you this morning discussing our first 2 well completions in the fourth quarter, as they are indicative of the direction our operations are going to be taking in the future. The SMR 4H and the SMR 5H were both completed in October, and are in the northernmost portion of our acreage in McMullen County. They were drilled by a walking rig off of a dual-well drilling pad. This approach obviously saves time and reduces drilling costs, and it's how we'll exploit the acreage as we move more into the infield development phase. The proximity of these wells to each other also allows for us to fracture stimulate both wells without moving our frac equipment to a new site. This also reduces costs and saves us time.

The drilling complete project design is also ideal for application of micro-seismic technology, which was utilized during the first of the 2 fracture stimulations on these wells. Micro-seismic events did indicate a good fracture treatment of the lower Engle Ford along the entire lateral length. We also collected valuable data, which will help us in the future as we consider further down-spacing and reservoir drainage optimization. All of this work, combined with the high quality of the Eagle Ford Shale, resulted in strong initial well performance. The SMR 4H well had an initial production rate of 1,398 barrels of oil per day, 2.7 million cubic feet of gas per day, and 392 barrels of natural gas liquids per day, with flowing casing pressure of 3,125 PSI on a 16/64 inch choke. The SMR 5H well had an initial production rate of 1,188 barrels of oil per day, 0.4 million cubic feet of gas per day, and 57 barrels of natural gas liquids per day, with flowing cases pressures of 3,600 PSI on a 14/64 inch choke.

This type of operation is representative of the next phase of our development program as we continue to exploit our highest value acreage. In determining our 2012 project management schedule, we are evaluating areas where pad drilling and micro-seismic will be most effective in helping us to optimize the development of our Eagle Ford position across South Texas.

Finally, we recently resumed production and sales of natural gas from the Eagle Ford Shale in the Fasken Field in Webb County, Texas. This production had been shut-in as a result of a third-party pipeline failure, which we announced on September 29. Intermittent production curtailments during the fourth quarter are expected in this area as work necessary to ensure the integrity of this system is performed by the pipeline operator.

Although there have been short-lived events that have impacted our production this year, we are still on track for our highest annual corporate production levels since 2007. South Texas is clearly where we are growing fastest, and with 5 rigs running and a fully utilized completion crew operating in South Texas as we exit the year, it is very reasonable to expect we'll deliver the highest annual production level in the company's history in 2012. I'm extremely proud of the people I work with, and I know that the best is yet to come as we meet these new milestones and continue to grow Swift Energy Company.

Thanks for your attention this morning, and I'll turn it back to Terry to recap.

Thanks, Bob.

Before we open the line for questions, I'll summarize Swift Energy's third quarter results and review some of the highlights from today's call. Third quarter production growth of 23% over third quarter 2010 production have us poised to deliver 24% to 26% full-year production growth. We now have 90 million cubic feet a day of dedicated natural gas processing and transportation capacity available to us in McMullen County, South Texas. 9 operated wells and 1 non-operated well were completed in the South Texas area during the quarter. In the fourth quarter, our first 2 Eagle Ford wells drilled from a multi-well pad were completed and are performing at exceptional rates. We are preparing to kick off a multi-well drilling program in our Southeast Louisiana Lake Washington Field. 2 wells were drilled in the Austin Chalk, and another well is currently drilling in our Central Louisiana/East Texas area. Daily production rates will ramp up steadily throughout the fourth quarter, and we will exit 2011 producing between 31,000 and 33,000 barrels of oil equivalent per day.

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

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

Say, a couple of things here. First, just again, surrounding the Eagle Ford takeaway issues, it sounds like most of these have been remedied. Will you continue to look for different alternatives, not just because of the problems, but just given the ramp in production that you all are going to be having in the region?

Yes, Neal. The answer to that is yes. Out in the Fasken area we're looking for a back-up there because of the failure that we had. We're also, artesian wells, looking at a couple of different options. I think we'll get that area, that's our LaSalle County acreage. I think we'll have different options available there by the end of the year, and then in the AWP area, I think we have a locality of that taken care of with the new Southcross agreement, but we do have redundant meters to allow us to go into other systems. So we do believe that we are getting some of the bottlenecks remedied with some back-up plans as well, in all of our areas.

Okay, and then turning to the SMR, the EF 4H and the 5H, obviously results look quite good. Besides the pad drilling you mentioned, was that something addition that you have done on a completion technique that you had not done on some prior wells, and should we assume results around this area going forward?

As far as the stimulation treatment, it was pretty similar to what we had been pumping. It is a hybrid simulation design. We actually cut a few things out in the well, some of the acid and some of the different 100-mesh sands, and actually brought our completions cost down about $0,5 million on each of those wells, with no negative impact. So basically the completion design is the same. We have just improved our cost profile on these completions.

Okay, and then just last kind of cue card question either for maybe Bruce or Alton. It was just, you have never been one to hedge too much. Just wanted you to comment, the prices have come back on hedges, and then lastly just I think Terry mentioned the likely record production next year. Would that entail still drilling within cash flow, if you comment around both of those 2.

Let me think the hedging comment first. We have had a fairly consistent strategy regarding price-risk management, generally protecting the downside without giving away the upside. We have implemented that primarily through the use of floors. Occasionally we use participating collars. In the short run, we don't see that changing, certainly even if you wanted to go to later swaps, the forward curve isn't particularly attractive for certain floors or [unit] swaps in some areas, but we always review our price-risk management strategy, and are open to modifying it if we see an opportunity to it. One of the reasons we tended to stay away from swaps when we had the predominant portion of our production in the water areas around Louisiana that were subject to disruption from storms. Having a greater diversification in South Texas might lend itself to that kind of thing, but we have not made any particular change. We just recognize that it's important to review your strategy.

With regard to next year's budget, we're still in the process of finalizing our budget for next year. We have historically announced that in February, and we intend to do that again next February. As you know, we're a conservatively run company, like to live within cash flow, but recognize today you have got some tremendous opportunity out there, as well as obligations under leaseholds and the like, as well as obligations with drilling rigs and fracking services and the like. Our balance sheet is in really good shape. We think one of the important things to mitigating risk today, particularly with the limited hedging opportunities, is having a strong balance sheet, both in terms of leverage as well as liquidity. Expect us to continue to be focused on that. We are certainly willing to outspend cash flow to some level, but we'll always want to keep it within the framework of our balance sheet so that doesn't get out of line.

Perfect. Thank you all for the time.

Thanks, Neal.

Your next question comes from the line of Jeb Bachman with Howard Weil.

Just had a couple of quick questions going back to production. Just wondering if you guys could disclose the amount of volumes that are exposed to those temporary curtailments that happen every now and then, because of the increased activity?

This is Bruce. If I understand your question, let me talk about third and let me talk about fourth quarter. In the third quarter, in the AWP area, where the largest portion of production is, we changed agreements with the processor transporter. We moved from Enterprise to Southcross. That gives us much more capacity, it gives us a better rate, it gives us a really great long-term opportunity there. We have got up to 90 million a day of capacity there, but as with any construction project, the line took a while to get laid and didn't actually get done and fully operational until closer to the 1st of October. Our deal with Enterprise actually expired like in June. So there was a period of several months in the summer that we didn't have firm agreements, so we were interruptible. Enterprise was bringing on other capacity from other operators who had signed contracts and firm capacity. They would push us out, and push other operators too. We weren't alone in that. Sometimes we got pushed out in terms of other being able to flow any gas in the system. Sometimes we could flow gas but we got pushed out of the processing.

So you'll see that in our volumes and also our NGL yields for the third quarter because we were able to produce and transport it, but not process it. Same thing happened when Southcross actually started up, and not all of the processing was ready. So we were able to produce gas but not process it all. So that really affected third quarter in terms of volumes. It also affected third quarter in terms of NGL yields, when you look at the numbers compared to what our original guidance was. And then obviously the big one we had was down in the Fasken Field where they had the pipeline failure down there in a 16-inch line. When we first announced that, as you know, we were unable to guide full year, because until we knew that pipeline was back on, we didn't know the full impact. So that is the reason we are now coming out with the reduced full year numbers, because we now know the impact, because that is fixed and back on production, and we are pleased with that. It certainly could have been better, but it could have been worse.

In terms of our fourth quarter guidance, there is some uncertainty around, primarily, down in the Fasken area in terms of that pipeline situation and they are going to be doing some pigging that will lower our production rates, both with a smart pig and then some others in terms of some chemical treatments of the pipeline, and we're uncertain as to exactly how that is going to be scheduled and what impact that will be on our production. We believe that we have accounted for that in terms of our guidance, but there is some uncertainty, and I think that is the principle place in the fourth quarter where there is some risk to production volumes, because up in AWP, the Southcross line is working, the processing is all there, and so we do not really expect to have any significant issues there. The third [air course], artesian wells, where we are starting to pick up our drilling activity, and we don't yet have our transportation and processing agreements long-term in place, but we are working on that and expect to get that done this quarter. Does that take care of what you are asking?

Yes, thanks, Bruce. I guess what I was trying to get into is as we move into 2012, I know you guys haven't provided guidance yet, but it sounds like the interruptible portion of your transportation and processing is largely behind you now, and that you should be able to have it entirely better, at that expectation or estimate, on production for the quarter, not be surprised by some of these curtailments that come up without you guys knowing.

Yes, I think that is largely true. Certainly In the AWP area and the Fasken area, I think it could be probably mid next year until you get all the capacity. They are building infrastructure into that artesian wells area, and all of it really won't be in place probably until mid-next year, but we'll be ramping up that area. It's not going to be a big impact in the first half.

That will tie to our drilling and completion schedule.

Okay. So it is safe to assume you guys, when you provide at least first half 2012 guidance, that you will bake in some downtime, the expectation for the possible curtailments?

Yes. don't know that we really envision significant curtailments at this point in time, because we have the contraction agreements, both at AWP and Fasken. We expect to have contractual agreements at artesian wells in place also, it is just infrastructure won't be there, but as Bob noted, we'll just tie timing of our development to the availability of the infrastructure. So you're not going to go drill 10 wells and not have the ability to outtake it.

All right. Okay guys, thanks for the color.

Our next question comes from the line of Ray Deacon with BMC.

I was just wondering whether the well cost number that you put out recently, $8.5 million, $9.5 million, is that still accurate? And any kind of comment, given that you may got a year's worth of production on some of these Eagle Ford wells, what the cumulative production might look like over the first year?

I will take a stab at that. As far as the well cost goes, yes, I think that number that we're talking about, especially with some of our recent initiatives in driving our costs down and sourcing some of our own materials. We still believe that $8.5million, $9.5 million number is good, and I think we kind of proved that on these 2 SMR wells. We did make some design changes that lowered our cost, and it did not impact our performance, the way we see it. We don't have that at our fingertip, the cumulative production for the first year out of our Eagle Ford drill, what we have already drilled, I guess that is your question?

Right, right.

.I don't think we have that at our fingertips, but I'm sure we can get that.

Okay, great. Thank you.

Our next question comes from the line of Gray Peckham from Susquehanna International.

Could you just give us a little bit of additional color on how your 2012 program at Lake Washington is going to scope out in terms of maybe the timing of when you're going to drill those wells?

Yes. I think our goal is to pick up a barge rig in the fourth quarter. Most likely scenarios seems to be December at this point, and we have a continuous drilling program identified. All of the prospect work has been done, all of the geology, the drilling programs are being worked on now. So we would expect to pick up that barge rig in December and drill fairly continuously well in and through next year.

Okay, thank you.

Our next question comes from the line of Adam White with RBC Capital Markets.

Just wanted to clarify, regarding oil production, a couple of different things. 1 is a fairly wide range of variance for the fourth quarter guidance, and I wasn't quite clear on how much of that is related to infrastructure, how much is pending well results.

Adam, this is Alton. That is a transposition, as opposed to 0.49, it should be 0.94 on the low end.

I didn't have time to do the math, okay. That answers that, and then just in general, oil production as a percentage is been declining, is that a trend that is going to continue with what you're planning for 2012, in both the Eagle Ford and Lake Washington, or are we going to see a shift?

Yes, Adam. The bulk of that change really occurred in the first quarter of this year when we went down there and drilled that dry gas area in Fasken, as we have discussed before. That is tremendous Eagle Ford Rock, and 10 BCF wells, very economic, and that is why we really want to earn that acreage, but our objective is to try to keep the oil liquids and gas ratio about 50/50, and that is about where we are today, and we believe that we can do that. When we have done some both, not just 1 year but 3 year planning, we believe that we can design our activity in a way that keeps that liquid ratio to gas ratio about 50/50.

And another 1. I hope this is isn't a transposition too, but the capital spending range for fourth quarter is also pretty wide What does that depend on?

I think it probably is a function of the timing of getting the barge rig.

The barge rig, and then that is the other, the rig that is under repair, the timing of that makes a difference. That particular rig that was damaged earlier is the1 that is drilling those SMR wells, Adam. That is 1 of the reasons that our exit rate and fourth quarter production is impacted, because a couple of those wells would have been drilled by now, that we pushed off, waiting for that rig to be repaired. That obviously affects CapEx as well.

And lastly, on the completion side, what are you doing differently in terms of the lateral link stages, et cetera, in Fasken versus some of the more liquids-prone areas, and is there a significant difference in cost for drilling and completion?

Yes, I'll try to answer all that. In the Fasken area, we are drilling lateral links, depending upon the lease configuration. Most of the wells we're drilling there now are in the 5,000 foot to 6,000 foot range. We can't get all 6,000 footers. Sometimes we can get a little more than 6,000 foot, other times we're down closer to 5,000 foot. So, and in terms of well costs, it is a little shallower. The drilling seems to go pretty well and easy. You don't have a lot of variation. In other words, you don't have the Sligo Reef margin to contend with, it's all very easy geology's. So our well costs, we tend not to have as much nonproductive time, or inefficiencies, drilling those wells in the Fasken area. In terms of our other areas, we're trying to get to the 6,000 foot where we can. Not all of the wells that you see announced in the Press Release were 6,000 footers. I would say, probably of what we released, about 40% of those were 6,000 foot wells tied to our 6.000 foot models. Many other ones are closer to what we would have as a 5.000 foot model, because of lease configuration and lease boundaries and things like that.

And so no significant cost differences, insignificant?

Yes, not too much difference. I mean, we have pretty much honed in. What we are focused on, really, is bringing our costs down by tweaking our recipes that we're pumping, cutting out things we don't think we need, or are adding to it, looking at our pump rates to make sure we're getting our frac heights and keeping those in zone as opposed to letting them grow out of zone. It's those types of optimization things that we're in the middle of, including sourcing our own profits and trying to drive our costs down, sourcing our own logistics. Driving that part of it down, and that is really what we are focused on. We're still sticking pretty much with our hybrid design. We think that is working well for us, and on the 6,000 foot lateral's, we're pumping 17 stages, so about 350 feet apart. So that is really what we're trying to get to, where the acreage boundaries allow us to do that.

Okay. Thank you very much.

(Operator Instructions) Our next question comes from the line of Marcus Talbert with Canaccord.

I think Bob just answered my previous question on the percentage of completed wells in the press release that were drilled to the longer lateral's. I was hoping maybe you could just provide a little bit of color on the Whitehurst well. It looks like you got a very strong oil rig out of that from your Olmos campaign in the AWP. Is there something that was driving that stronger oil right there, or something that was unexpected?

Yes. Well, I think that it might have been a little bit of an uplift in the area. It just tends to be a little bit more oily. Whitehurst is moving west in our Olmos area. We expected it to be pretty liquids rich. It was probably a little more liquids rich than we had anticipated, so that was a nice surprise, and it probably just has to do with some of the uplifting that went on in that area.

Okay, great, thanks. And I guess looking at the most recent Austin Chalk wells, is there anything that you can point to, I guess, outside of the fewer natural fractures that you encountered on the 16-1 well that lead to the result that we got?

Well, we have a couple of working theories about what caused the lower fracturization in that well bore down to the south. 1 would be we're getting much further away from the Sligo Shelf Margin where you have more tectonic activity. The other theory would be that it's flattened out a little bit down there. The dips aren't the same. It's a little flatter area, and there's less faulting in that area. So that could have also contributed to the less fracturization. So those are the things the guys are working on now to try to understand down in that southern extent, what is controlling the fracturization down there.

Okay, great, thanks, and I guess just looking at that southern extent on the map that you have here. Was the 16-1 offset to the 18-1 well, or was that further south and east, even further south of the 5-1?

Yes, further south, further south. Yes, it is kind of right down at the end of the line down there.

So it is the very most southern well that you have drilled to date there in the Burr Ferry?

Yes, that's right.

That's correct.

Great, thanks, guys. I appreciate all the color.

Our next question comes from the line of Noel Parks with Ladenburg Thalmann.

I have been on and off throughout the call, so I apologize if you touched on this already, but in the Eagle Ford, I saw that in Press Release you put out your choke information on the different wells. Do you have a sense of how the different chokes are affecting EURs at this point?

Well, I mean, I think we have talked about this in the past. We do believe in being very careful with how we open up these wells so as to not create any near well bore damage. So you will see us open these things up pretty slowly so that we get a good pressure distribution throughout the fracture network in the reservoir, and that we contact as much of the reservoir and profen as we can. You probably won't see us too often report much over a 20-inch choke on an initial rate, because we are being a little more conservative to try to protect the near bore integrity around the well bore so that we don't cause any sudden pressure differential that might cause some crushing or something of that nature. So, yes, our choke management program is integral to the way we flow back these wells and long-term manage the reservoirs here.

I am just wondering do you have enough wells where you can kind of contract, say, in offsetting wells we open the choke at this rate versus we let another 1 run harder, and how that has affected the production curve?

We're studying that. We don't really have enough data to be able to draw much in the way of conclusions. We're still very early in the hyperbolic, in the decline of these wells. I think where you really start to get more deviation is you turn that hyperbolic in about year two, and then you start measuring points along the axis of the decline. In a lot of these wells, we're just not far enough along in the profile of the well to know that.

Got it, and 1 other thing. You talked earlier about looking into doing horizontals through the Wilcox and South Bear Head Creek and Beauregard, just to give me a sense, the cost of those, what sort of oil price threshold do you need in order for something like that to work?

Yes, we're not to the point of doing that. I mean we're really in the field study phase looking at designs, looking at options. There's obviously Upper Wilcox and Lower Wilcox and Middle Wilcox, and there's a lot of different geology out there that has to be worked through. So I would say that's a little premature for us to start throwing numbers around to you.

What you kind of say is if you go back and look at the production history of the vertical well just in the South Bear Creek, you find the well is pretty oily. So it's an oil/gas mixture, but there's pretty good liquid component to that production.

And that does enjoy the Gulf Coast uplift on pricing differentials. So we think it's a very economic area, obviously.

Great. That's all for me.

Our next question comes from a follow-up with Ray Deacon with BMC.

I was wondering if you could give a little bit more detail on the wells you have planned at Lake Washington once the rig gets there, and what are your goals in terms of maintaining production, or essentially growing it?

Well, yes. In Lake Washington, obviously the team has done an absolutely marvelous job flattening out that production by doing nothing more than re-completions and production optimizations, sliding sleeve changes, things like that. So we have a team that is kind of is working like a tuned-up automobile right now in that area on that kind of work. In terms of growing production, we definitely need to get back to drilling. We think that drilling next year what we have in mind can actually increase production a little bit. So that is really our goal for next year is to be sure that not only is it flat but to try to get it to grow some next year.

Yes. I think I would add to that, Bob, that we did drill in the Jelly Bowl area. We announced those results. Had some very good rates over there. We also stepped over on the west side. So we have been doing some preliminary drilling in advance of this program, gone back and calibrated that in, and actually have some nice development follow-up opportunities to those successes.

Yes. Both what we announced earlier, the Jelly Bowl and the Hershey well. Jelly Bowl down in the southeast side, Hershey on the west side. We do have identified follow-up opportunities to both of those wells.

Great, and just want a quick follow-up, I guess. In terms of the Fasken volumes that were curtailed and the NGLs that you weren't able to process, I guess, is there kind of a ballpark number that you think that you lost in the third quarter due to those?

Yes, I'll give you some rough numbers here out of the bigger numbers that we reported. In the NGL area up in AWP and Southcross, for the third quarter was about 55,000 barrels in the third quarter. In terms of Maritage, the Fasken area in the third quarter, that was more like around 30,000 barrels equivalent, but in the fourth quarter, the Maritage outing in Fasken area, in looking at 4th quarter going forward, that is as much as 220,000 barrels out of our production component. So that kind of is some of the break-out of the bigger numbers that we reported.

And there are no further questions at this time. I would now like to turn the call over to our presenters for any closing remarks.

This is Terry Swift and the team here at Swift Energy Company, we would like to thank everyone for joining us on the conference call. We look forward to closing the year out during this fourth quarter and getting back with you. Thank you.

This concludes our Swift Energy Company third quarter earnings conference call. You may now disconnect.