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Swift Energy Company (NYSE:SFY)

Q3 2012 Earnings Call

November 1, 2012 10:00 AM ET

Executives

Paul Vincent – Director, Finance and IR

Terry Swift – Chairman and CEO

Alton Heckaman – EVP and CFO

Bruce Vincent – President

Bob Banks – EVP and COO

Analysts

Neal Dingmann – SunTrust

Biju Perincheril – Jefferies

Kyle Rhodes – RBC

Noel Parks – Ladenburg Thalmann

Porter Pursley – Raymond James

Michael Hall – Robert W Baird

Operator

Good morning and my name is Sabrina and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy 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. I would now like to turn the conference over to Paul Vincent, Director of Finance and Investor Relations. Please go ahead sir.

Paul Vincent

Good morning. I’m Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy’s third quarter 2012 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 Steve Tomberlin, Senior Vice President of Resource Development & Engineering and Jim Mitchell, Senior Vice President, Commercial Transactions and Land.

Before I turn the call over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates and projections about us, our industry and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports to which we refer you along with cautionary statements contained in our press releases and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Terry Swift

Thanks, Paul and thank you to everyone joining the call today. Although, we’re on track to enter 2013 with our expected levels of operational momentum and production mix, we did encounter several challenges and opportunities during the third quarter, which have let us to recalibrate and adjust some of our objectives.

As previously disclosed, Hurricane Isaac caused us to shut-in approximately 175,000 barrels of oil equivalent of primarily oil production during the third quarter and we’ll defer approximately another 50,000 barrels of production from the fourth quarter. We’re proud to have the production teams safely prepared for and recovered from the Hurricane.

In South Texas the initial test rates for our first four well pad met our expectations. But lower than expected associated gas required instillation of artificial lift much sooner than previously anticipated. These lower than expected gas to oil ratios required us to conduct operations which required significant production down time as the proxy cemetery of these wells to one another required all of them to be shut-in to conduct tubing and gas lift installation operations. We also had some temporary facility issues with this four well pad operation.

These operational complexities with our first four well pad zipper frac design in Northern McMullen County have let us to reduce our production forecast. Bob will discuss this particular situation, which we believe is isolated to this particular set of wells a bit later on in our presentation.

Recently in the fourth quarter, we completed the McClarity 1-H and 2-H well in this same area. These wells have demonstrated significantly higher gas to oil ratios and experienced stabilized flow test rates above 700,000 barrels of oil per day and 1 million cubic feet of gas per day. This type of result is in line with our expectations for this area and further suggests a unique event with our four well pads SMR in that area.

As we developed the Eagle Ford and try new techniques to become more efficient, we do continue to find variations in fluid characteristics, rock properties and operating conditions that present both challenges and opportunities, as we go through our Eagle Ford development.

These challenges together with the effects of Hurricane Isaac have let us to adjust our full year 2012 guidance to the 11.6 million to 11.7 million barrels of oil equaling range. Prospectively, we are now even more confident that we will have meaningful 60 acre downspacing opportunities within our Eagle Ford inventory.

Bob will provide more details on our Eagle Ford downspacing test that we’ve conducted are in the process of reviewing in LaSalle County. Our drilling program has also delivered slightly higher concentrations of crude oil and natural gas liquids than forecast, resulting in lower volumes of production, but volumes which yield higher overall value.

Finally, we’re executing more production optimization projects on our South Texas horizontal well inventory than originally planned, which is important relative to long-term performance of these wells that does requires to shut-in wells. We’re working on to conduct this work, which does also impact in the short-term production.

In spite of these events our 2012 program will result in production growth of approximately a 11% and reserve growth towards the higher end of our expected 15% to 20% target or the fourth quarter daily production rate should be greater than 33,000 barrels of oil equivalent per day and fourth quarter production will consistent between 55% to 60% crude oil and natural gas liquids, further demonstrating the value of our proven asset base.

We’ve also committed to the lower capital expenditure levels, approximately 25% to 30% in 2013 from our 2012 levels, while still being positioned to meet our strategic long-term production growth targets which are in the range of 7% to 12%. With the commitment to lower spending levels at growing current inventory, several new strategic growth areas we have developed at an uncertain commodity price environment, we have multiple scenarios that we’re looking at for our 2013 work plans and capital budgeting which we’re working through.

Our current base expectations for 2013 include keeping three rigs fully utilized in South Texas throughout the year. We intend to offer a one barge rig for a portion of the year in Lake Washington and participate in three to four wells in our Burr Ferry joint venture area targeting the Austin Chalk.

We also expect to dedicate a portion of our budget through strategic growth in exploration which will better to find our future growth opportunities. As of now, we expect to drill at least one horizontal Wilcox well in Louisiana early in 2012 in our South Bearhead Creek field. Later in 2013, we intend to drill a well in Southwest Colorado targeting the Niobrara formation.

Over the past several years, we put together over 50,000 net acres as a position in this area that’s perspective in the Niobrara while there are risk associated with these oil opportunities we enjoy a very low cost of entry in both of these areas and control the acreage we intend to test.

We’re also evaluating a third opportunity that if successful if we also have meaningful growth potential for the company. As our asset base evolves and becomes more predictable we will look to mitigate risk through our cash flows, we’re more active natural gas hedging as prices allow. We will look forward to use long dated swaps color transactions and floors to cover portions of our base production. This will naturally and partially reduce our sensitivity to near term price volatility and enable us to commit to longer-term drilling schedules.

During the quarter, we accomplished several meaningful operational milestones which includes, we drilled 11 well in South Texas and now have drilled over a 100 horizontal wells in total in South Texas. Drilling times continue to improve driving cost lower. Three new wells, we drilled in Lake Washington during the quarter and we conducted to recompletion at our Jelly Bowl prospect with excellent results.

And we expect to drill a new offset well in this area next year. In the Burr Ferry field in Vernon Parish, Louisiana our partner tested two wells during the quarter, one well tested above the 1,000 barrels of oil and 3 million cubic feet of gas and the other well tested above 800 barrels of oil and 5 million cubic feet of gas.

In South Texas, our completion efficiency continue to improve. Costs are decreasing as a greater number of our completions are conducted a multi-well operation. We’ve completed a $150 million bond offering priced at yield, effective yield below 7%.

This successful transaction coupled with our recent borrowing base increase, significantly improves our liquidity. At the beginning of fourth quarter, we successfully completed and tested a three well 60 acre downspacing tests in the LaSalle County, while further downspacing test will be required to validate this work. We’re excited about the potential to increase our inventory in this high value area.

When I contemplate the opportunity set, our company of our size has with there is many options to explore it as we have. I’m extremely excited. We also enjoy a solid operational foundation and financial position and command us to expand our operating areas in 2013. Finally before turning the call over to Alton, I feel it’s important to acknowledge that we here at Swift Energy appreciate the damage and disruptions that storms like Hurricane Sandy can cause on daily activities. And we do hope for a quick recovery for those affected by this particularly powerful storm.

And now I’ll ask Alton to present our third quarter 2012 financial results.

Alton Heckaman

Thanks Terry and good morning everybody. This quarter continue to be a challenge for Swift Energy as Hurricane Isaac played the Golf Coast a visit. The natural gas prices did increase from recent lows and oil prices continue to be relatively strong. Even with the effects of the storm, our production increased 13% from the third quarter of 2011 and declined only slightly from the second quarter of 2012 resulting in oil and gas sales of $128 million, income from continuing operations of $3.1 million or $0.07 per diluted share, cash flow before working capital changes for the quarter of $1.66 per diluted share and 2.9 barrels of oil equivalent of 3Q12 production.

Fuel prices were 3% lower than a year earlier and natural gas prices decreased by a third resulting in an overall 21% decrease in our realized price per BOE in 3Q12 versus 3Q11. With our current mix, approximately 83% of our revenues came from crude oil and liquid sales during the quarter. Our controllable cost and metrics compared favorably to guidance even with Hurricane affected production volumes.

Production cost came in at $9.26 per Boe lower than guidance, G&A came in at $4.16 in the middle of guidance, DD&A was well below guidance at $20.52 due to higher reserve volumes and improved cost efficiencies, interest expense came in at $4.79 per barrel slightly above guidance and production in Avalon, Texas were slightly below guidance at 8.3% of revenue due primarily to the Hurricane affected production mix.

As previously mentioned, the net result was income for the quarter of $3.1 million or $0.07 per diluted share, well above the first call mean estimate. Our effective income tax rate for the quarter was 43.7%. Cash flow before working capital changes for 3Q12 came in at $71 million or $1.66 per diluted share, our EBITDA was $79 million for the quarter. CapEx on a cash flow basis was $201 million.

Let me wrap up my discussion by highlighting two recent financial events. As Terry mentioned in early October, we issued an additional 150 million of senior notes as an add-on to our 2022 debentures and use the proceeds to pay down the balance on our credit facility. These notes were priced to the yield of a little less than 7%. We’re also pleased to report that we recently in conjunction with our semi-annual borrowing based review extended our credit facility through November 1, 2017 and increased our borrowing base and commit that amount to $450 million.

The first natural gas and NGL prices in the near term still pose a significant challenge to our sector, with our expanded liquidity, our inventory of liquid rich projects and over 80% of revenues coming from oil and liquid production. We feel we are very well positioned to continue to execute our strategic plans. As always, we’ve included additional financial and operational information in our press release including guidance for the fourth quarter of 2012.

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

Bruce Vincent

Thanks, Alton and good morning everyone and thanks for listening. Today, I’m going to discuss the third quarter 2012 activity, including our production volumes, our recent drilling results, activity in our core operating areas and our plans for the fourth quarter of 2012 and let’s turn over to Bob to provide a little more color with regard in these areas.

Beginning with production, Swift Energy’s production during the third quarter of 2012 totaled 2.87 million barrels of oil equivalent within our previously issued expected range when adjusted for the 175,000 barrels of oil equivalent impact from Hurricane Isaac. Approximately 50,000 barrels of oil equivalent of production are also expected to be deferred from the fourth quarter as a result of that storm. Third quarter production was 13% greater within the third quarter 2011 production of 2.54 million barrels of oil equivalent and decreased 2% from the 2.92 million barrels of oil equivalent produced in the third quarter of 2012.

For the third quarter, drilling results Swift Energy drilled 14 operated wells during the quarter and participated in two non-operated wells. In South Texas, 11 operated of horizontal development wells were drilled in the Eagle Ford Shale formation in South Texas, seven of these wells were drilled in the McMullen County and four were drilled in LaSalle County.

In Swift Energy’s Southeast Louisiana core area, three wells were drilled in the Lake Washington field. In the company’s Central Louisiana East Texas core area, two non-operated wells targeting the Austin Chalk were drilled in the Burr Ferry area.

We currently have three operated drilling rigs in our South Texas core area, all of them drilling in the Eagle Ford shale wells and we also have one operated barge rig drilling in our Southeast Louisiana area and one non-operated drilling rigs active in our Central Louisiana/East Texas area.

In the South Texas core area, which includes our AWP, Sun TSH and Las Tiendas Olmos field and AWP, Artesia wells and Fasken Eagle Ford fields, third quarter 2012 production averaged 23,620 net barrels of oil equivalent per day, a 1% increase in production when compared to the second quarter 2012 production in the same area and a 52% increase over third quarter 2011 production in the same area.

As drilling activity slows from our decision to reduce rig activity in this area that better match the capital spending of cash flows, we also expect sequential production growth were flat when this fewer new wells are added each quarter over time.

As evidence by our higher intensity drilling activity, we are moving closer to having a braced all of our high value acreage to the drill bit and we’ll be closer to a full scale manufacturing mode by the end of 2013 program. In our Southeast Louisiana core area which includes the Lake Washington and Bay de Chene field production during the third quarter averaged approximately 5,040 net barrels of oil equivalent per day, down 20% when compared to the second quarter 2012 average net production for the same area.

Lake Washington specifically averaged approximately 4,750 net barrels of oil equivalent per day, a decrease of 20% when compared to the second quarter 2012 average daily volumes. Production volumes would have grown approximately 10% over the second quarter 2012 levels and Hurricane Isaac not shut in the 1,750 barrels of oil equivalent during that quarter.

Bay de Chene sequential production decreased 20% to 290 net barrels of oil equivalent per day. This sequential decline is due to no new drilling activity and natural declines as well as the downtime associated with Hurricane Isaac.

The Central Louisiana, East Texas core area, which includes our Brookeland, Masters Creek, Burr Ferry and South Bearhead Creek fields contributed 2,558 barrels of net barrels oil equivalent per day of production in the third quarter of 2012, an increase of 6% over the second quarter of 2012. Higher production levels in this area are due to the non-operated wells have been brought on line with Burr Ferry field during the third quarter.

I’m now going to turn the call over to Bob Banks to review operational highlights of quarter.

Bob Banks

Thanks, Bruce. At the Lake Washington field during the quarter, we completed 4 wells and performed 14 production optimization projects, which include sliding sleeve shift changes, gas lift enhancements, chock changes and returning shut-in wells to production. These types of operations are the backbone of our current base production management program in the field. One recompletion in particular on the LL&E number 5 will also referred to as the Jelly Bowl prospect, tested at rates above 1500 barrels of oil per day.

This type of result highlights the opportunities that still exists in Lake Washington in addition to the new drilling activity. We did drill three wells during the third quarter at Lake Washington and we will maintain a one rig program throughout the end of the year and on into next year in this area. We completed one well at Lake Washington during the third quarter, the CM 423, which was drilled to a measured depth of 9,016 feet, encountered 202 feet of true vertical pay and tested 912 barrels of oil per day and 0.3 million cubic feet of gas per day on a 22/64” choke.

Over in the Central Louisiana, East Texas area in the Burr Ferry field, the non-operated GASRS 34-1 well was completed in the Austin Chalk during the quarter. Initial production rates of this well were 840 barrels of oil per day and 5.1 million cubic feet of gas per day with flowing tubing pressure of 2,520 psi on a 30/64-inch choke.

A second non-operated well, the Forestar 18-1 was also completed. Initial production test rates of this well were 1,056 barrels of oil per day and 3 million cubic feet of gas per day with flowing tubing pressure of 4,000 psi on a 30/64-inch choke. We remain encouraged about the strong well results from this area and continue to believe the Austin Chalk project area has the potential to be a meaningful growth area for us. One non-operated well is currently being drilled in the Burr Ferry area and we expect to participate in at least 3 more wells in this area next year.

Moving on to South Texas, 12 Eagle Ford horizontal wells were completed during the third quarter. In the morning’s press release, we included a table highlighting test data from these completions. Swift Energy continues to adjust our completion and production techniques to optimize production. In addition, we continue to benefit from more efficient drilling and completion times as we moved fast appraisal mode into development mode in some areas.

As Terry mentioned earlier, we did experienced some unexpected delays during the completion of a four well pad project in the SMR area in the North McMullen County. The first delay was related to the simultaneous fracing operations themselves where faulting in the area caused inference between these closed proximity wells resulting in sticking some tools down hole.

The second and more significant delay was related to the unexpectedly low GORs of the Eagle Ford wells compared to offset SMR Eagle Ford locations, as well as the greater more than AWP area of McMullen County. Most wells in these areas have GORs of 1,000 to 2,000 to 1 these wells had GORs of about 600 to 1 that’s requiring us to move much more quickly than planned to our tubing installation and gas lift operations.

Due to the closed proximity of the wells on this four well pad, we were require to shut-in all wells on the pad from most of October to conduct these operations, plus delaying production from this key area. While the lower GORs of these wells were below original forecast, we did achieve expected initial oil production rates and still expect these wells to perform well once where our oil and gas lift and have to been installed.

As a result of the lessons learned, we have modified our pad fracing operations to insure that we do not cause this type of pressure interference, in our pad wells in the future, especially in areas with non-pulving. A good example of the changes we made can be found in the next two wells in this area that we’ve recently completed. The McClarity 1-H and 2-H were recently completed and are currently flowing back at an average stabilized rate of 708 barrels of oil per day and 1.3 million cubic feet of gas per day.

The GORs of these wells are much more in line with our model expectations throughout more than AWP area. As we’ve pointed out, we have reduced our South Texas drilling activity to three rigs down from the six, primarily to better to align our spending levels with cash flows. This reduced pace of drilling has allowed our asset team to spend more time evaluating existing wells and developing production optimization programs based on historical production data.

One of the results of this evaluation work has been to increase the amount of tubing installations we are conducting on the in-service wells, while we have to shut-in a well for several base to perform this activity, it better manages the reservoir and results in flatter production and pressure declines for the long-term. This operation is really important for all of our lower GOR wells.

While we’ve elected to maintain a slower pace of drilling in South Texas, we have also taken steps to increase our inventory through downspacing. In Artesia wells, we’ve recently completed that the base 1-H, 2-H and 3-H all on a 60 acre spacing design. These wells all tested at rates above 1,000 barrels of oil equivalent per day and was greater than 55% liquids.

I believe our acreage in LaSalle County may prove to be our highest value acreage. We’re seeing our lowest drilling costs in this area while drilling liquids rich wells with good pressure support and higher GORs, while we need to continue to test our downspacing assumptions, we are thrilled with that yearly results here.

Terry indicated earlier a commitment to expanding our operational horizon through strategic growth in exploration. This is a critical component to our future and we worked very hard to put in place a strategic growth framework, which will support intelligent risk taking and afford a steady diet of growth opportunity for Swift Energy. In 2013 alone, we will test at least two opportunities in different areas where the company control significant acreage and has a low entry costs. We’re also evaluating a third opportunity with meaningful running room but this play hasn’t yet been sufficiently de-risk.

Early in the year, we will drill a horizontal Wilcox test in our South Bearhead Creek field in Beauregard Parish, Louisiana. We have already drilled a number of strong vertical wells in this area giving us confident in our ability to utilize our horizontal drilling and multi stage frank technology in this prime position of the trend.

Additionally, we have observed high quality offset operators significantly improving their results through the use of horizontal drilling technology. In a second play area, our land organization has done an incredible job of putting together a large acreage position in the Four Corners areas of Colorado that is perspective for Niobrara development. Their work as well as the subsequent technical evaluations we’ve conducted have put us in a position to drill at least one test well in this area next year.

All of these growth opportunities exists in regions with extensive histories of oil and gas production and represents the types of opportunities we will continue to develop through our strategic growth framework. It’s safe to say that although we expect to have less South Texas drilling activity next year, we will be busier than we have ever been. We are in a growth mode at Swift Energy and continue to build an asset base, an opportunity set unlike any that company has ever seen.

With that, I thank you for your attention this morning and I’m going to turn it back to Terry to recap.

Terry Swift

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. Despite Hurricane Isaac and isolated delays with the four well completion pad in South Texas, we anticipate fourth quarter daily production above 33,000 barrels of oil equivalent per day. We also expect reserve growth to be at the high end of our 15% to 20% growth target.

Continued strong drilling results in Louisiana and improving drilling and completion costs in South Texas. Fourth quarter production would be close to 60% crude oil and natural gas, liquid production up from 45% in the first quarter of 2012. We’ve recently completed a successful 60 acre downspacing test with three wells in LaSalle County. We expect to test three new play areas with the drill bit in 2013.

With that we’d like to begin the question-and-answer portion of our presentation.

Question-and-Answer Session

Operator

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

Neal Dingmann – SunTrust

Good morning guys.

Terry Swift

Good morning.

Alton Heckaman

Good morning.

Neal Dingmann – SunTrust

Say just a question obviously the success you’ve had in LaSalle it looks like or just recently had in the downspacing. I was wondering if you could give me an idea, is that just going to be you think now that that downspacing that will be throughout LaSalle and then just is that going to – you’ll try the same thing over McMullen and some of the other counties in the Eagle Ford and you know wonder if you have that success where you just immediately start to go to the downspacing or do you still have to hold some other acreage first?

Terry Swift

Oh, that’s a good question, Neal let me take a crack at that. Yeah in LaSalle County, we feel very good about the 60 acre spacing. We’ll probably even test further downspacing after we get a little more production history from these three wells on the 60s. Over in McMullen County, we are actually doing a downspacing test, now we’re just completing the drilling of them and we’ll be fracking them and bringing those on to production.

So we’re continuing the down test over in McMullen County. And so the answer is we’re going to continue to do downspacing test in all of our areas. And we would like to get to the answer sooner rather than later because obviously it’s more effective development if you can walk away the ultimatum optimized downspacing going to be coming back later and drilling in between wells that have already been producing. So that’s our objective.

Neal Dingmann – SunTrust

Got it. And then just wondering maybe just last one, I’ll turn it over. Just for Alton or maybe for Terry on overall strategies on hedges. Your thoughts – again I know you’ve got a – had a little bit on that that it looks like a bit rolling up at the end of the year. Your thoughts today obviously, you’re sitting pretty well financially, so just your thoughts as far as potentially as in adding hedges as we go into next year?

Terry Swift

Yeah, I think well as we mentioned in the conference call script that we’re starting to have discussions and look at the potentially longer swaps and those items as opposed to just utilizing the floors and participating collars. So we see it as the – an ability to sort of lock in prices and be able to take particular areas and accelerate those projects, once you kind of get – you locked in the pricing. So, something we’re looking at and you’re right we basically had a small amount of protection in the form of floors in the fourth quarter. We don’t have anything right now into 2013, but we have those discussions on an ongoing basis.

Bruce Vincent

So and I think – Neal, it’s Bruce. We will and if we saw market out there, right now you look at the forward curve; it’s really not conducive on the gas side yet to fix something on the play.

Neal Dingmann – SunTrust

And Bruce, if I could just seek one last one. Just your partner on Burr Ferry, what – I know you’ve kind of talked around this just your thoughts as you go into next year on how it will stay as active in that – in that block?

Bruce Vincent

We expect them to – we had again that we thought we would drill three to four wells, we expect them to stay active in that. We not together settle down a plan yet, but we think three to four is probably a pretty good; it can be 5 but somewhere in that neighborhood.

Terry Swift

Yeah Neal, I think we have some regular partner meeting that’s going on here this week and again bring a little more clarity to budget work program issues for next year.

Neal Dingmann – SunTrust

Very good. Thank you.

Operator

Your next question comes from the line of Biju Perincheril with Jefferies.

Biju Perincheril – Jefferies

Just first I guess in South Texas you talked about in the press release rock properties you refer to in your comments about province or guidance, production guidance, I am just wondering if you can elaborate a bit more on that mix, if you see any impact your – your assumption just because is that?

Terry Swift

No I think yeah the reference to the rock properties obviously is we are moving around drilling wells in this area GOR is our changing around fairly rapidly and that more than AWP area as an example we are probably going to some submodels of our general model they are just based on wells that continue to be drilled in close proximity changing slightly some of our GOR in terms of the rock properties that was mentioned really that’s a positive thing in my mind.

And that really comes from the 3D seismic that we saw over the area we have a very – very strong geotechnology group here at Swift that is used as 3D seismic to extract a number of different attributes some of which are pretty proprietary that have been developed, but really now help us to take that lower Eagle Ford sweet spot zone where we would drill our horizontal, lateral and geosteering in a wider 40 to 50 foot interval, these guys now have been able to break down that lower Eagle Ford in the even some sweet spots where were we may have more brittleness and they want to target even a 10 to 20 foot zone to make sure we stay within the most griddle of the rock and so that’s the type of rock property analysis that we are doing based upon the 3D and the geotechnology.

Biju Perincheril – Jefferies

So, have you drilled any of – any wells, knew an improve targeting, or if not when will that be tested?

Terry Swift

Yeah we are actually these three wells that we – well two of the wells that we talked about the McLarty wells we targeted that barrels zone we also have another PCQ well on flow back right now, it’s looking very strong and we targeted that lower zone. So it’s early to talk too much about that, but we are testing that.

Biju Perincheril – Jefferies

It’s okay. And then Lake Washington, the Jelly Bowl well – so I think that well was initially completed early last year. So how do we recomplete that I guess in less than two years? Is that – was that expected and does new reservoir that you recompleting and how does that compared to the initial reservoir?

Terry Swift

Yeah, I think the lower zone that we completed with just one of the intervals that we logged in that wellbore. We still have behind pipe zones. We only completed it using the single selective method as opposed to a dual selective. So what we like to do is really started the bottom and work our way up when we do a completion methodology like that in these deeper parts of the reservoir.

So it’s not unexpected that we’re going to take the lower interval first that was also a strong producer, but it’s depleted to the point and then we’ve had some water encroachment that we’re just now coming back up the hole. So that’s a pretty typical operation at Lake Washington and we’ll always try to start at that lowest sand interval.

Biju Perincheril – Jefferies

Okay. So in this new facility just think about is having some similar type of life field?

Terry Swift

Yeah, I think probably similar. I don’t have the maps here in front of me, but probably pretty similar.

Biju Perincheril – Jefferies

Okay. And then one last question, the Austin Chalk wells few completions, when they tending to sale from the third quarter, if keep use roughly what – when they were tending the sales?

Terry Swift

I’m sorry I think I missed that question.

Alton Heckaman

Related relationship to the other wells that we’ve drilled.

Terry Swift

Oh, yeah, yeah okay. The – there were two wells drilled. The GASRS 34-1 was kind of in generally that same area where we drilled our earlier GASRS wells, but the Forestar 18-1 well was quite a step-out that actually went into our AMI 2 area, to the East. So that was a very positive development. We’re really like seeing the fractures that we’re developed over in that eastern position. And so that now builds us a lot of confidence to drill back towards that AMI 1 area in those GASRS wells.

Alton Heckaman

Yeah, you may recall this year that we had (inaudible) though then added a second AMI, which adjoins AMI 1, AMI 2 border each other but AMI 2 is acreage to the east. And so what that forced our well does it actually extend the play further to the east. So that’s quite very encouraging with that kind of results.

Biju Perincheril – Jefferies

Yeah, and then you have the mineral rights in AMI 2, area 2?

Alton Heckaman

Mineral rights.

Biju Perincheril – Jefferies

Oh, no.

Alton Heckaman

Mineral rights of that – just as other things to point out, AMI 1 is a 50/50 working interest joint venture where we do have a lot of mineral rights in some of the acreage. AMI 2 is a 55 Anadarko, 45 Swift and then we really don’t have the mineral rights in the AMI 2.

Biju Perincheril – Jefferies

Got it. And then I was wondering, if you could say when these walls were tending to sales?

Alton Heckaman

Post production...

Terry Swift

Right around...

Bruce Vincent

Yeah in the mid-September, it’s something like that, mid-September late September.

Biju Perincheril – Jefferies

Okay. Got it, that’s all I have. Thank you.

Terry Swift

Thank you.

Operator

Your next question comes from the line of Kyle Rhodes with RBC.

Kyle Rhodes – RBC

Hi, guys.

Terry Swift

Hey.

Kyle Rhodes – RBC

I was wondering what’s your current Eagle Ford well costs are running and kind of what you are budgeting for 2013.

Bob Banks

Yeah, I mean that’s a good question. Over in LaSalle County, we’re actually beating our well cost quite a bit. I think what we put out at Analyst Day was probably around $7.5 million completed and hooked up. One well we drilled, this quarter, we drilled from spud to TD in 12.5 days as an example. So we’re regularly drilling these wells much faster. The completion operations where we’ve gone from last quarter doing about 227 stages in the quarter to about 260 stages this quarter.

We’re routinely getting seven stages a day. Probably our best day this quarter was nine stages. So I would say you’re down in the LaSalle County area in the low – in the mid to high sixes now. Over in the AWP area, we’re pretty much tracking. Those costs that we’ve presented at our Analyst Day and put out there publically. So we’re kind of wide on those. And then up in the SMR area, we’re probably beating our well costs there a little bit. So we’re fine tuning our cost estimates by area for the next year’s budget. But overall we’ve seen a pretty good trend that we are happy within two to three areas.

Alton Heckaman

Yeah, let me add to that. The well costs that Bob is referring to, do not include some of the other cost that you are kind of front load these campaigns with such as your land costs, your facilities, you gathering your water handling. So just remember do front load a lot of this activity with those kinds of costs and he is just referring to the well costs.

Kyle Rhodes – RBC

Okay, great. And then you guys still acquiring acreage in Colorado are you kind of happy with your position?

Terry Swift

We’re still acquiring acreage.

Bruce Vincent

Yeah, I think it’s a yes and yes we’re happy with the position and we’re still acquiring acreage.

Kyle Rhodes – RBC

Fair enough. And then one last one for me. Does you are kind of 7% to 12% production growth tentative guidance that include any production from Wilcox Niobrara area?

Bruce Vincent

We don’t really have anything in there from Niobrara. We do have some expectation in there a small piece from the Wilcox.

Kyle Rhodes – RBC

Okay, and anything in this area?

Bruce Vincent

I’m sorry.

Kyle Rhodes – RBC

And anything from your kind of unidentified area.

Bruce Vincent

No nothing from the unidentified.

Kyle Rhodes – RBC

No, okay, thanks. That’s it for me guys. I appreciate it.

Bruce Vincent

Thank you.

Terry Swift

Thank you.

Operator

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

Noel Parks – Ladenburg Thalmann

Good morning.

Terry Swift

Hi, Noel.

Bruce Vincent

Good morning.

Noel Parks – Ladenburg Thalmann

Sorry if have the drop-off, but did you the particular area that you going after in Niobrara and you know considering the areas at the play colors discuss how you kick that particular like in other words?

Bruce Vincent

Why that area...

Terry Swift

Well, I think it’s surpass to say that Niobrara is a very, very significant play in the Rocky Mountains in general and its present in many basins and these Intermountain basins in particular. We’re looking at it in more than one place, but we are talking about now in terms of the 50,000 acres where we are interested in acquiring more acreages is the four corners area kind of the northwestern portion as you get near the (inaudible) and coming up that of the San Juan basin.

And there we do see some really nice vertical oil completions in the Niobrara. Traditionally, there’s small little wells but with this technology we think we can go in and do multi-stage completions and make some nice oil growth out of it. But we still got it tested, it’s still early it’s going to be de-risk. But we’d like Niobrara section that it’s a section as a whole is like 1,500 feet that there are two members within it that are smaller than that in the 150, 300 foot range that we probably will be testing both members of what’s referred to as like Smoky Hills section.

Noel Parks – Ladenburg Thalmann

Okay, great. And if I remember, you have had some acreage in that that area for at least just a few years if I remember right or I thought you were going for deep gas there at one point, maybe the (inaudible) just something like that. Is this the same area or it’s just near where you had – previously had acreage?

Terry Swift

Well there maybe a little bit of confusion, the San Juan basin is a massive gas play and whether you’re looking at Niobrara or you’re looking at which, as you get deeper into the basin the Niobrara can be gassy. What we’re up on – what we think is to condensate to oil window was what we’re playing, but the San Juan basin that there had been some horizontal multi-stage fracs done deeper in the basin and they have been successful for gas.

We’re not targeting gas. Our acreage isn’t there. It’s more on what we think is the oil prospectivity. There are other formations – formations in that area that have other potential that’s not involved gas. We’ve taken multi-year leases, a lot of these are long-term five year with five year ticker kinds of leases. So we weren’t jumping in there trying to do something real fast and quick we’ve made this a long-term type of play. We’re going to test it appropriately. We may test more than just the Niobrara. We’re focused on the liquids though, and it’s not deep. We’re typically going to be looking at somewhere between 5,000 to 8,000 feet something in that range.

Bruce Vincent

To answer the first part of your question, yes, this is the same acreage that we’ve been showing in our probably filings up in that area for a number of years. We’ve been methodically acquiring this acreage and getting a big enough footprint before we want to talk about it, it just more than anything to protect our flanks so...

Noel Parks – Ladenburg Thalmann

Great, that was just what I was wondering, that’s it from me, thanks a lot.

Operator

Your next question comes from the line of Porter Pursley with Raymond James.

Porter Pursley – Raymond James

Hey good morning guys. Just quick question in regards to the Eagle Ford well that you completed in South Texas in the Table 1 release, can you identify, which wells you characterizes oil versus condensate in both LaSalle and McMullen?

Terry Swift

Yeah. I’m pulling that out now, I think – I think one of the other things, I want to point out to out here, you’ll see we’re really in these test experimenting with some of the restricted choke settings a bit, we are going to some calibration to our baseline models there, but we just start at the top of that table.

Porter Pursley – Raymond James

Yeah.

Terry Swift

I would say the first five wells, those are in the condensate window and then as you get down to the Hayes to the SMR those are all would be in the real window of McMullen County.

Porter Pursley – Raymond James

Okay. Great, that’s all I have, thanks guys.

Bruce Vincent

Thank you.

Terry Swift

Thank you Porter.

Operator

(Operator Instructions). Your next question comes from the line of Michael Hall with Robert W Baird.

Michael Hall – Robert W Baird

Hey, can you hear me all right?

Terry Swift

We can Michael.

Bob Banks

Hey, Michael.

Michael Hall – Robert W Baird

Fair enough. Yeah, I guess just a couple quick one from my end, if you could, you get a decent ramp down needed in terms of trajectory spend, fourth quarter versus third quarter maybe can you just add some additional color around how you execute on that and just give us a bit more comfortable there?

Bob Banks

Yeah, okay. So let’s just take it by area kind of at a high level, I mean we can talk more detail if you would like that in South Texas we’ve reduced from six rigs to three rigs.

Michael Hall – Robert W Baird

Got it.

Alton Heckaman

In the Central Louisiana East Texas area, in the chart, we reduce from two rigs to one rig, down in Lake Washington, we’ve reduced one of our workover rigs, and so that’s kind of the ramp down and how we’re going from Q3, well we actually have a lot of efficiencies in drilling and completion times that we’ve pulled some capital into that quarter, but the ramp down if you go through all of this, we’re ramping it down probably another $70 million or so to what our fourth quarter numbers are going to look like.

Michael Hall – Robert W Baird

Great, that’s very helpful. So, I guess the only other outstanding one in mine and is the, just I know well do you have any idea in terms of how that where will be design and in terms of lot of length frac stages and that’s sort of saying and that’s still in the works.

Bob Banks

Well, it’s being find to we have some pretty good ideas about what kind of lateral links we want to get how many stages we want to put in there. We may not the first step we may not push it up to end of these 6,000-foot laterals but we will give it good go and get a good laterals linked out there and get the model stage fracing and kind of similar to what we do down in the almost in the Eagle Ford. We do have quite a bit experience in the vertical wells here fracing vertical wells. So we kind of have a good idea how we want that to be ultimately designed.

Terry Swift

Yeah I would like to add that, this field that where we want to fly this – this is really got at least five well cock zones in the vertically you have been a very commercial in their own right. And yet across the fuel those fine zone do change a little bit we do thing we are in the sweet spot of the overall well cocks trend. So if you look at typical vertical well and typical zone in there is not unusual make quarter, million barrels are one of those zones. So we are pretty excited about how we can optimize use in this technology in that area?

Bob Banks

Yeah, I just build on Terry said it’s lot of large of acreage position really, but we do have a multiple pay horizons stacked up each would require probably horizontal wells into those different zones. So it does present us with the fair have been a running room if we can you get this technology working for us.

Michael Hall – Robert W Baird

Great, (inaudible) how checks out, I appreciate you all of guys. Thanks.

Terry Swift

Thank you.

Operator

(Operator Instructions) At this time, there are no further questions.

Terry Swift

Okay. Well we would like to thank you for join us our conference call and look forward to our next quarter. Thank you.

Operator

This does conclude today’s conference call. You may disconnect.

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