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Swift Energy Company (NYSE:SFY)

Q3 2011 Earnings Call

November 3, 2011 10:00 a.m. ET

Executives

Paul Vincent – Director, Finance & IR

Terry Swift – Chairman & CEO

Alton Heckaman – EVP & CFO

Bruce Vincent – President & Secretary

Bob Banks – EVP & COO

Analysts

Neal Dingmann – Suntrust Robinson Humphrey

Jeb Bachmann – Howard Weil

Ray Deacon – BMC

Gray Peckham – Susquehanna International

Adam Light – RBC Capital Market

Marcus Talbert – Canaccord Genuity

Noel Parks – Ladenburg Thalmann

Operator

Good morning. My name is Dona and I’ll 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).

Thank you, Mr. Paul Vincent. You may begin you conference sir.

Paul Vincent

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, 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.

Terry Swift

Thanks, Paul. And thanks to everyone on the call for taking time to join us today. Since the beginning of 2009 we witnessed oil and gas activity accelerate rapidly on 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 continue to scale its operations during the third quarter with ten wells drilled and ten 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 the 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’ve matured three 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 three. 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 an early 2012 in this field and we’ll 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 two years.

In Central Louisiana and East Texas, we’re 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 reevaluating 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’d like to review some of the highlights of this quarter.

The completion of nine operative rigs and one 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, two high-rate oil wells, the SMR 4H and the SMR 5H have been completed in McMullen County. These wells were drilled from the 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 1398 barrels of oil per day, 2.7 million cubic feet of gas per day and a 192 barrels of natural gas liquids per day with flow and casing pressure of 3125 psi on a 16/64-inch choke.

The SMR 5H well had an initial production rate of 1188 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 flow and casing pressure of 3600 psi on a 14/64-inch 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 two wells were drilled during the quarter Burr Ferry area and one well is currently drilling in our Masters Creek field. We are very early in the process of data collection and still testing development concepts but we’ve been encouraged by what we’re seeing today. Drilling activity should increase in this area in 2012.

We’re having a very strong year despite challenges we face this year primarily with the timing and owned mine days of third party controlled projects. We’ve made great strides in controlling larger portion 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 balanced 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.

Now, I’ll ask Alton to present third quarter 2011 finical results.

Alton Heckaman

Thanks Terry, and good morning. Third quarter was a good quarter Swift Energy with considerable production and revenue growth compared to the prior year. Our production increased 23% than 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 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 to metrics compared to guidance are as follows.

Production cost 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 in 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 column mean estimate. Our effective income tax rate for the quarter was 37.9% just slightly above guidance. Cash flow before working capital changes for 3Q ’11 came in at $19 million or $2.11 per diluted share, while EBITDA was $91 million for the quarter. Our quarterly CapEx on a cash flow basis was $124 million.

Our hedging activities were minimal during the quarter and we did not have any hedges outstanding at the end of the quarter. Please see our website for complete and current detail of oil and gas hedging information.

As we previously announced we’ve closed on the sale of certain non-strategic 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 have $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 floating to execute our strategic plans during the remainder of 2011 and gives us financial momentum needed going into 2012.

As always we’ve included additional financial and operational information in our press release including revised guidance for the fourth quarter and full year 2011.

With that I’ll turn over to Bruce Vincent for an over view of our operations.

Bruce Vincent

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 details 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 the third quarter of 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 shutting 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 that I just mentioned negatively impacted production by approximately 120,000 barrels of oil equivalent in the third quarter and were 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 million and 10.5 million barrels of oil equivalent for the full year of 2011.

This equates to a growth of 24% to 26% over 2010 production. The unplanned loss of the drilling rig in South Texas and the uncertain online date of our operated well in Burr Ferry suffered a mechanical setback, led 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 well.

For our third quarter drilling results, Swift Energy drilled 11 operated wells and participated in one non-operated well during the quarter. In South Texas 10 operated horizontal development wells were drilled to the Eagle Ford shale formation in South Texas. Six wells were drilled in McMullen County, three wells were drilled in Webb County and one well was drilled in LaSalle County.

In Swift Energy Central Louisiana/East Texas core area one operated well and one non-operated well were drilled in Burr Ferry fields. Four rigs drilling horizontal wells in the Eagle Ford and/or 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. One operated drilling rig is active in Central Louisiana/East Texas core area in our Masters Creek field.

I will briefly review our activity in each of our four operating areas for this quarter and then Bob will detail the highlights.

In the South East Louisiana core area which includes the Lake Washington and Bay De Chene fields production during the third quarter averaged approximately 8511 net barrels of oil equivalent per day or approximately 51 million cubic feet equivalent per day in this area. That’s down 6% when compared to the second quarter of 2011 average net production for the same area.

Lake Washington averaged approximately 7756 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 of 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 Artesia wells and Fasken Eagle Ford fields, third quarter of 2011 production averaged 15,745 net barrels of oil equivalent per day or about 94 million cubic feet of growth 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 of 2010.

The sequential increase is primarily from the nine new operated wells and one 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 in curtailments experienced throughout the third quarter. Bob will spend time discussing our Olmos and Eagle Ford programs in greater detail.

In central Louisiana, East Texas core area which includes our Brooklyn, Masters Creek, Burr Ferry and South Ferry Creek deals contributed to 2555 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 in 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 the Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island and Bayou Penchant, production averaged approximately 1268 barrels of oil equivalent per day (inaudible) about 8 million cubic feet equivalent per day during the third quarter.

These assets were sold as part of a package of non-core, non-strategic 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.

Bob Banks

Thanks Bruce and good morning. At the Lake Washington Field, we completed six wells and formed ten 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 product optimization projects which include sliding sleeve changes, gas lift enhancements and returning shut-in wells to production averaged an initial production response of a 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 one non-operated well and we drilled one 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 two wells drilled in the area. This well was an appraisal well and was drilled near the southern extend 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 further 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 20-1concluded drilling operations during the third quarter and has been completed. A mechanical problem occurred during the initial cleanup of the well that required a work over rig to resolve. A work over rig is currently on this well and work is under way to remedy the issue. This well bore remained in zone for the entirety of the 4254 foot lateral and encountered high natural fracture density in the formation along the strong tubing pressure. 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 in the South Bearhead 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 but 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 rate 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’ve also long term water handling agreements in 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 official lift and analyzing also ways to reduce our water management and waste water costs in the field amongst many other things.

Results of the nine operated third quarter wells and the one non-operated well completed in South Texas can be found in the cable at our press release issued this morning. I’d like to spend my time with you this morning discussing our first two well completions in the fourth quarter as they’re 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 northern most portion of our acreage in the McMullen County. They were drilled by a walking rig half off of the do well drilling pad. This approach obviously says Tom introduces drilling cost and how we’ll exploit the acreage as we move more into the in-field development phase.

The proximity of these wells to each other also allowed for us to fracture stimulate both wells without moving our frac equipment to a new site. This also reduces cost and saves us time. The drilling complete project design is also ideal for application in MicroSeismic technology which was utilized during the first of the two fracture stimulations on these wells.

MicroSeismic events data indicate a good fracture treatment of the lower Eagle 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 1398 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 3125 psi on a 16/64 inch choke.

The SMR 5H well had an initial production rate of 1188 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 casing pressures of 3600 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 29th. Intermittent production curtailments during the fourth quarter are expected in this area as work necessary to ensure the integrity of the 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 level since 2007.

South Texas is clearly where we are growing fastest and we have five 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 levels 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 will turn it back to Terry to recap.

Terry Swift

Thanks Bob. Before we open the line for questions, I will 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. Nine operated wells and one non-operated well were completed in the South Texas area during the quarter.

In the fourth quarter our first two Eagle Ford wells drilled from the multiwall pad were completed and are performing at exceptional rates. We are preparing to kick off a multi well drilling program in our South East Louisiana Lake Washington field. Two 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.

Question-and-Answer Session

Operator

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

Neal Dingmann – Suntrust Robinson Humphrey

Good morning fellows. Let's say a couple of things here. First, surrounding the Eagle Ford takeaway issues it sounds like most of us have been remedied, will you continue to look forward different alternatives as far as – not just because the problems just given the rampant production that you are all are going to having in the region.

Bob Banks

Yeah, Neal, the answer to that is yes. Out in the Fasken area we are looking for a backup there because of the failure that we had. Also Artesia wells looking at a couple of different options, I think we will get that area that’s our LaSalle County acreage, I think we will have different options available there by the end of the year and then in the AWP area I think we’ve got a lot 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.

Neal Dingmann – Suntrust Robinson Humphrey

Okay. And then turning to the SMR, the EF 4H and the 5H, obviously results look good quite good, besides the pad drilling you mentioned was that something in addition that you’ve done on a completion technique that you had in some prior wells and should we assume results around this area going forward?

Bob Banks

As far as the stimulation treatment it was pretty similar to what we had been pumping. It is a hybrid stimulation design. We actually tried a few things out in the well. Some of the asset and some of the different 100 mesh sands and actually brought our completions cost down about half a million dollars 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.

Neal Dingmann – Suntrust Robinson Humphrey

Okay. Just last two questions, either for maybe Bruce or Alton. It was just, you never wanted to hedge too much, in one of your comment 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 could comment around both of those too.

Alton Heckaman

Let me take 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 implemented that primarily through the use of floor, and occasionally we used participating callers. In the short run we don’t see that changing certainly even if you wanted to go later swaps. The forward curve isn’t particularly attractive for certainly floors or even some slopes in some areas. But we always review our price risk management strategy and are open to modify (inaudible) to do 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 the storms, having a greater diversification in South Texas might lend itself to that kind of thing. But we’ve 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 in 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, likely within cash flow but recognize today you’ve got some tremendous opportunity out there as well as obligations under leasehold and the like as well as obligations with drilling rigs and fracing 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 and 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 that doesn’t get out of line.

Neal Dingmann – Suntrust Robinson Humphrey

Perfect. Thank you all for the time.

Operator

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

Jeb Bachmann – Howard Weil

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

Bruce Vincent

Well we have – this is Bruce, if I understand your question both in the third quarter – let we talk about third and then 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, and moved from Enterprise to Southcross. That gives us much more capacity giving us a better rate, giving us a real great long term opportunity there. We’ve got up to 90 million a day of capacity there. But as with any construction project, the line took a while to get laden, 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, as 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 being able to flow any gas in the systems, 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 couldn’t process – we were able to produce and transport it but not process it. Same thing happened Southcross actually started and not all the processing was ready, so we were able to produce gas but not process it all.

So, that really affected third quarter in terms volumes, it also affected third quarter in terms of NGLE yields when you look at the numbers that refer to what our original guidance was. And then obviously, the big one we had was down in 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’s the reason we are now coming out looking to reduce full year numbers because we now know the impact of that and that’s fixed and back on production and we’re pleased with it. It certainly could have been better but it could’ve been worse.

In terms of our fourth quarter guidance, you know, there is some uncertainty around – primarily down in the Fasken area in terms of that pipeline situation. They are going to be doing some pigging that will lower our production rates both with the smart pig and then some others in terms of some chemical treatments of the pipeline. And what we are uncertain is exactly how that’s going to be scheduled and what impact that will be on our production. We believe that we accounted for that in terms of our guidance but there is some uncertainty, and I think that’s the principal place in the fourth quarter where there is some risk of production volumes.

It goes up in AWP, the Southcross line is working, the process is all there and so we don’t really expect to have any significant issues there.

The third, Artesia wells where we’re starting pick up drilling activity and we don’t yet have our transportation and process 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’re asking?

Jeb Bachmann – Howard Weil

Yeah. Thanks Bruce. I mean I guess what I was trying to get at is, moving to 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 now, and you should be able to have an internally better expectation or estimate on production for the quarter, not being surprised by some of these curtailments that come up with (inaudible).

Bruce Vincent

Yeah, I think that’s 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 Artesia wells area, and all of it really won't be in place probably until mid next year, but that’s a pretty –won’t be ramping up that area, it's not going to be a big impact in the first half.

Bob Banks

Yeah. That will tie to our drilling and completion schedule.

Jeb Bachmann – Howard Weil

Okay, so I guess it’s safe to assume you provide at least first half 2012 guidance that you will be making some downtime expectations through possible curtailments.

Terry Swift

Yeah, I don’t know that we really envision significant curtailments at this point in time, because we’ve got the contractual agreements both at AWP and Fasken. We expect to have contractual agreements at Artesia wells in place also, it's just infrastructure won't be there. But as Bob noted we will just tie out the timing of our development to the availability of the infrastructure. So, you are not going to go drill 10 wells and not have the ability to outtake it.

Jeb Bachmann – Howard Weil

All right. Okay guys, thanks for the call.

Operator

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

Ray Deacon – BMC

Yeah, hey. I was just wondering whether the well cost number that you put out recently $8.5 million and to $9.5 million that’s still accurate, and any kind of comment given that maybe without a year’s production on some of these Eagle Ford wells what the cumulative production might look like over the first year.

Bob Banks

Yeah, I will help to take a stab at that. As far as the well cost go, yeah, I think our numbers – that number that we are talking about especially with some of our recent initiatives in driving our cost down and sourcing some of our own materials we still believe that the $8.5 million and $9.5 million number is good. And I think we kind of proved that on these two SMR wells. We did make some design changes that lowered our cost and it did not impact our performance the way we see it.

In terms of the – we don’t have that at our finger tip, the cumulative production through the first year out of our Eagle Ford drill, what we have already drilled I guess that’s your question?

Ray Deacon – BMC

Right, right.

Bob Banks

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

Ray Deacon – BMC

Okay, great, thank you.

Operator

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

Gray Peckham – Susquehanna International

Hey guys, good morning. 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 on when you are going to drill those wells?

Bob Banks

Yeah, I think our goal is to pick up the barge rig in the fourth quarter, most likely scenario seems to be December at this point and we have a continuous drilling program identified, only the prospect work has been done, all 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.

Gray Peckham – Susquehanna International

Okay, thank you.

Operator

Our next question comes from the line of Adam Light with RBC Capital Market.

Adam Light – RBC Capital Market

Hey good morning gentlemen. Just wanted to clarify, regarding oil production, a couple of different things, one 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?

Alton Heckaman

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

Adam Light – RBC Capital Market

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

Terry Swift

Yeah, Adam, the bulk of that change really occurred in the first quarter of this year when we went down there and drilled the dry gas area at Fasken, as we discussed before that’s tremendous Eagle Ford rock and 10 BCF well is very economic and that’s 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’s about where we are today and we believe that we can do that. When we have done, not just one year but three year planning we believe that we can design our activity in a way that keeps that liquid ratio to gas ratio about 50:50.

Adam Light – RBC Capital Market

And another one I hope this isn’t a transposition tube with the capital spending range for fourth quarter is also pretty wide, what does that depend on?

Terry Swift

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

Bruce Vincent

Barge rig and then the other the rig that’s under repair and the timing of that makes a difference. Like that particular rig that was damaged earlier is the one that’s drilling those SMR wells, and that’s one of the reasons that our exit rate in fourth quarter production has impacted because those 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.

Adam Light – RBC Capital Market

And then lastly on the completion side, what are you doing differently in terms of lateral leg stages, etc. in Fasken versus some of the more liquids prone areas and is there a significant difference in cost through drilling and completion?

Bob Banks

Yeah, I will try to answer all that. In the Fasken area we are drilling lateral links depending upon the least configuration. Most of the wells we are drilling there now are now in the 5000 to 6000 foot range that we can't get all 6000 footer, sometimes we can get a little more than 6000 foot, other times we are down closer to 5000 foot. So, in terms of well cost it is a little shallower. The drilling seems to go pretty well and easy. You don’t have a lot of variation and in other words you don’t have the sligo reef margin to content with. It's all very easy geology. So our well costs, we tend not to have as much non-productive time or inefficiencies drilling those wells in the Fasken area.

In terms of our other areas we are trying to get to the 6000 foot where we can. Not all the wells that you see announced in the press release were 6000 footers. I would say probably of what we released about 40% of those were 6000 foot wells tied to our 6000 foot models. Many other ones are closer to what we would have is a 5000 foot model, because of lease configuration and lease boundaries and things like that.

Adam Light – RBC Capital Market

And so no significant cost -- cost differences insignificant?

Bob Banks

Yeah, not too much different. I mean we are pretty much horned in. What we are focused on really is bringing our cost down by tweaking our recipes that we are pumping, cutting out things, we don’t think we need or adding to it, looking at our pump rates to make sure we are 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 are in the middle of including sourcing our own proppants and trying to drive our cost down sourcing our own logistics driving that part of it down and that’s really what we are focused on.

We are still sticking pretty much with our high hybrid design. We think that’s working well for us, and on the 6000 foot laterals we are pumping 17 stages, about 350 feet apart. So that’s really what we are trying to get to where the acreage boundaries allow us to do that.

Adam Light – RBC Capital Market

Okay, great, thank you very much.

Operator

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

Marcus Talbert – Canaccord Genuity

Good morning gentlemen. I think Bob just answered my previous question on the percentage of completed wells in the press release that were drilled to the longer laterals. I have something here, if you could just provide a little bit color on the Whitehurst, it looks like you got a very strong oil rate out of that from your almost – campaigning the AWP, is there something that was driving that stronger oil rate there or something that was unexpected?

Bob Banks

Yeah, well, I think it might have been a little bit of an uplift in the area. It did sense 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 be with some of the uplifting that went on in that area.

Marcus Talbert – Canaccord Genuity

Okay, great, thanks. 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 led to the result that we got?

Bob Banks

We have got a couple of working theories about what caused the lower fracturation in that well bore down to the south. One would be, we are 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 depths aren’t the same, it’s a little flatter area and there is less faulting in that area. So that could have also contributed to the less fracturation. So, those are the things the guys are working on now to try to understand down in that southern extend, what's controlling the fracturation down there.

Marcus Talbert – Canaccord Genuity

Okay, great, thanks. And I guess just looking at that southern extend 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 (inaudible).

Bob Banks

Yeah, further south, further south. Yeah, it’s kind of right down at the end of the line down there.

Marcus Talbert – Canaccord Genuity

So it’s the very most southern well that you drilled to-date there in the Burr Ferry?

Bob Banks

Yeah, that’s right.

Marcus Talbert – Canaccord Genuity

Oh, yeah, that’s correct.

Marcus Talbert – Canaccord Genuity

Great, thanks guys. I appreciate all the color.

Operator

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

Noel Parks – Ladenburg Thalmann

Good morning. I have been on and off throughout the call. So probably you touched on this already. But in the Eagle Ford I saw that in the 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?

Bob Banks

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 to create any near well bore damage. So you will see us open these things up pretty slowly so that we did a good pressure distribution throughout the fracture network in the reservoir and then we contact as much of the reservoir and proppant 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 differentials that might cause some crushing or something of that nature. So, yeah, our choke management program is integral to the way we flow back these wells and long term manage the reservoirs here.

Noel Parks – Ladenburg Thalmann

I’m just wondering do you have enough wells where you can kind of contrast, say in offsetting wells, reopen the choke that – at this rate versus we let another one run harder and how that’s affected the production curve?

Bob Banks

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

Noel Parks – Ladenburg Thalmann

Got it, and one other thing, you talked earlier about looking into doing horizontals to the Wilcox and in South Bearhead Creek and Beauregard, just to get a sense, the cost of those what sort of oil price threshold do you need in order for something like that to work?

Bob Banks

We are not to the point in doing that, we are really in the field study phase looking at designs, looking at options, there is obviously upper Wilcox and lower Wilcox and middle Wilcox and there is 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.

Noel Parks – Ladenburg Thalmann

What’s your current out there, if you go back and look at the production history of the vertical well just in the South Bearhead Creek you will find the oil is pretty oily, so – I mean it’s an oil-gas mixture, but there’s pretty good liquid component to that production.

Bob Banks

And that does enjoy the gulf coast uplift on pricing differential. So we think it’s a very economic area obviously.

Noel Parks – Ladenburg Thalmann

Great, that’s all from me.

Operator

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

Ray Deacon – BMC

I was wondering if you could just give a little bit more detail on the wells you have got planned that Lake Washington wants the rig get there, and what are your goals in terms of maintaining production or potentially growing it?

Bob Banks

Well, yeah, in Lake Washington obviously the team has done an absolutely marvelous job, flattening out that production by doing nothing more than recompletions and production optimizations, sliding sleeve changes, things like that. So we have a team that’s kind of 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’s really our goal for next year is to be sure that not only is it flat, but to try to get it to gross on next year.

Bruce Vincent

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

Bob Banks

Yeah, both what we announced earlier in the Jelly Bowl and the Hershey well, Jelly Bowl down in the South East side, Hershey on the West side, we do have identified follow-up opportunities to both of those wells.

Ray Deacon – BMC

All right. And then just one quick follow-up. I guess in terms of the Fasken volumes that were curtailed and the MGLs that were – that you weren’t able to process, I guess is there kind of a ballpark number you think that you lost in the third quarter due to those?

Bob Banks

Yeah, I mean on – I’ll give you some rough numbers here out of the bigger numbers that we reported. In the MGL area, up in AWP in Southcross, that for the third quarter was about 55,000 barrels in the third quarter. In terms of meritage, the Fasken area in the third quarter, that was more like around 30,000 barrels equivalent. But in the fourth quarter the meritage outing in Fasken area, and looking at fourth quarter going forward that’s as much as 220,000 barrels out of our production component. So that kind of some of the break out of the bigger numbers that we reported.

Ray Deacon – BMC

All right. Thanks Bob.

Operator

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

Terry Swift

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.

Operator

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

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