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Swift Energy Co. (NYSE:SFY)

Q3 2010 Earnings Call

November 04, 2010 10:00 am ET

Executives

Paul Vincent - IR

Terry Swift - Chairman & CEO

Alton Heckaman - EVP & CFO

Bruce Vincent - President

Bob Banks - EVP & COO

Analysts

Jason Wangler - Wunderlich Securities

Leo Mariani - RBC

Michael Hall - Wells Fargo

Derrick Whitfield - Canaccord

Brian Kuzma - Weiss Multi-Strategy

Operator

Good morning, my name is Dorothy 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 call over to Mr. Paul Vincent, Director of Financial and Investor Relations. Sir, you may begin.

Paul Vincent

Good morning. I am Paul Vincent, Director of Finance and Investor Relations. I’d like to welcome everyone to Swift Energy’s third quarter 2010 earnings conference call. On today’s call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, EVP and CFO will review the financial results for the third quarter and then Bruce Vincent, President; and Bob Banks, EVP and COO, will provide an operational update. Terry Swift will then summarize before we open it up to questions. Also present on the call are Jim Mitchell SVP Commercial Transactions & 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 for everyone to listening for joining our conference call today. Before we discuss third quarter operational and financial results I believe its necessary to take a pit stop and review how strongly Swift Energy has positioned despite the current economic and operating environment. Our resource base currently includes (inaudible) production, low risk oil development opportunities and deeper mature exploitation and exploration inventory in South Louisiana. In south Texas approximately 79,000 perspective acres in the Eagle Ford shale and approximately 41,000 perspective acres in the almost tight gas ms plus over 100,000 net acres prospected for Austin Chalk in Central Louisiana and East Texas. We have two joint venture in place with leading oil and gas companies to accelerate the development of our resource base in addition to production infrastructure, gathering, processing and transportation capacity to bring hydrocarbons to the market. We also contractual secured three high power drillings rigs for our 2011 south Texas operations. Financially our balance sheet is in excellent shape, we extended our $300 million borrowing base through 2015 and expect the borrowing base to increase as our production and reserve base grows. Our current exposure to a large growing liquid rich resource base coupled with a financial strength liquidity to develop it place Swift Energy in a unique position to develop multi-year high return production and reserve growth. As most industry participants and observers know demand for critical oil field services have got strong over the past six months.

This rapid increase in demand has impacted both the availability and performance of providers and vendors especially high pressure pumping services for fracture simulation. In many cases previously agreed upon frac schedules have been delayed or canceled. While this represents additional challenges to meeting forecast and performance targets, Swift Energy remains committed to improved performance and efficient execution of its operating plans.

These scheduling delays have resulted in a significant backlog and industry wells awaiting fracture stimulation. As of the end of the third quarter, we had 12 horizontal wells waiting on fracture stimulation, with our current drilling activity we expect to have 9 to 12 horizontal wells waiting on fracture stimulation services by the end of the year.

This number of backlog completions is well above our original expectations and has reduced our full year production and lowers our year end exit rate target. Starting in the fourth quarter, Swift Energy began using dedicated fracture stimulation equipment and services under our completion services agreement. This increased control of our completion activity in South Texas combined with a recent completion performance improvements gives us confidence that our adjusted performance targets will be met.

However, as a result of the uncertainty and high pressure pumping service scheduling and performance for much of 2010, we are lowering our forecast during corporate daily production rate to 26,000 to 28,000 net barrels of oil equivalent per day. This new range is a 15% to 24% increase from our third quarter average daily production rate of 22,500 barrels of oil equivalent per day. The impact of this unexpected scheduling device is approximately 525,000 barrels of oil equivalent of production which will be delayed past the end of this year.

As a result our full year 2010 production is expected to be 8.3 to 8.5 million barrels of oil equivalent. This equates to a 2 to 9% sequential increase in four quarter production over third quarter 2010. Our focus on liquid rich opportunities will result in our production mix remaining approximately 60% liquid at year end 2010. Based on year-to-date drilling and appraisal program, we expect our year end 2010 reserve to increase by 15 to 20% over last years year end level.

During the third quarter prior to the arrival of the dedicated equipment crew we completed an average of one horizontal fracture stimulation job per month. Our completion performance improved in October as we took control of the dedicated fracture stimulation crew and equipment. With this dedicated crew and equipment in place for the entire month of October we were able to complete four horizontal fracture stimulation jobs and commence a fifth job. Additionally we commenced a sixth job with a non dedicated crew and equipment during October. Overall October stimulation service performance was excellent and we believe that our dedicated crew and equipment will accomplish three or more horizontal fracture stimulation jobs a month during the fourth quarter.

Bob and Bruce will detail all of our operational activities and results in a few minutes. We will first review some of the highlights of the quarter which include the Swift operated Discher 1-H, the PCQ #4H and Quintanilla Me-You 1-H Eagle Ford wells that were brought online during the quarter. The Discher 1-H was completed with 14 fracture stimulation stages and tested at a rate of 448 barrels of oil a day and 1.6 million cubic feet of gas per day. The PCQ #4H with a 13 stage fracture stimulation tested at a rate of 528 barrels of oil per day and 1.9 million cubic feet of gas per day.

The Quintanilla Me-You 1-H had a 12 stage fracture stimulation performed and tested at a rate of 494 barrels of oil a day and 1.3 million cubic feet of gas per day. This well came online during the fourth quarter. The Bracken JV 3-H a non-operated well drilled earlier in the year was completed by our joint venture partner during the quarter with a 10 stage fracture stimulation.

These wells initial production rate was 5.8 million cubic feet per day with flow in casing pressure of 5753 psi on a 16/64 choke. This test continues to de-risk our acreage in McMullen County and provide additional evidence that our technical work is sound. In South East Louisiana and Lake Washington, we completed three wells during the quarter and continued our Lake Washington production maintenance program. We expect to spread a deep exploitation target in the fourth quarter at Lake Washington.

Finally, in our Central Louisiana, East Texas area, the first well targeting the Austin Chalk in our joint venture area in the South Burr Ferry Field was drilled. Initial production rates of this well were 13 million cubic feet of gas per day and 1000 barrels of oil per day. Those are gross numbers Swift has a 50% working interest in this well and the same joint venture area a second well is currently drilling. In the Brooklyn field in east Texas we are drilling a Swift operated Austin Chalk well and we are participating in a non operated well targeting the same formation and expect both to be online by the year end 2010.

The current operating environment is placed exceptional demand on our service providers, our partners and our vendors to provide critical services to our industry and we recognize that it will take time for them to adapt to current and projected activity level. High industry levels of activity particularly across the Eagle Ford Shale further confirm the value and upside we recognize in our own Eagle Ford shale acreage. Swift Energy has always planned for the long term and we are now in an excellent position to provide long term operational and financial growth. And now I will Alton to present third quarter 2010 financial results

Alton Heckaman

Thank you Terry and good morning everyone. Again having balance in our portfolio has served Swift well during the third quarter 2010 as oil prices have stabilized while natural gas prices remain sluggish. Swift Energy’s financial results in the third quarter reflect this. Oil and gas sales excluding hedging effect were $106 million and 8% increase from 3Q ’09. Our income from continuing operations was $9.4 million or $0.24 per diluted share up from 3Q ’09 but down from the previous quarter. Cash flow before working capital changes came in for the quarter at $1.62 per diluted share beating current first call estimate and 3Q 10 production was up 2% from second quarter levels yet on the low side of our guidance at 2.07 million barrels of oil equivalent

As to our price realizations, crude oil prices were 12% higher than third quarter 2009 levels or natural gas prices for 2010 were 36% higher leading to an overall 16% higher price per Boe in 3Q '10. Swift's average realized price in 3Q '10 therefore increased to $51.06 per Boe due primarily to crude oil prices increasing to an average of approximately $76 per barrel compared to $68 per barrel a year ago.

Allowing Swift to increase its quarterly oil and gas revenues 8% over the third quarter of 2009. As always we again continue to focus on our controllable cost and metrics, G&A came in slightly above guidance at $4.21 per barrel, DID&A came in at 19.69 per Boe within our guidance, production cost came in slightly above our guidance at $10.12 per barrel, interest expense of 399 per barrel from a high side of guidance and product and ad valorem taxes came in at 10.2% of oil and gas revenues. Result was income from continuing operations for the quarter of $9.4 million, again $0.24 both basic and diluted.

Our effective income tax rate for the quarter was within guidance as 37.5%. Cash flow before working capital changes for 3Q '10 came in at $62 million or $1.62 per diluted share. While EBITDA was $65 million for the quarter and CapEx on a cash flow basis was $99 million. Now let me spend just a moment to again highlights with solid financial position.

As of the end of the third quarter 2010, we had no outstanding balance under our line of credit and as Terry mentioned we also renewed and extended our $500 million line of credit facility with nine major banks to October 2015 and initially set our borrowing base then increased $300 million. As also indicated in our press release, we recently purchased an initial (inaudible) covering 520,000 MMBtu of January 2011 natural gas production. Please see our website for complete and current details hedging information.

And as always we included additional financial and operational information in our release including guidance for the fourth quarter. As Terry said, Swift is well positioned financially to execute our strategy and we have the strength and flexibility to handle the continuing price volatility that seems to become the norm in our industry. And with that I will turn it over to Bruce Vincent for an overview of our operations.

Bruce Vincent

Thanks, Alton and good morning everyone and thanks for being on the call. Today, I’ll review third quarter 2010 activity including production volumes, recent drilling results, activity in our core operating areas and our plans for the fourth quarter of 2010.

Bob Banks will then discuss significant operational activity of the quarter and its effect on the remainder of the year and moving into next year. Begin with production, Swift Energy’s production in the third quarter of 2010 totaled 2.07 million barrels of oil equivalent, our 12.43 billion cubic feet equivalent, an increase of 2% from the 2.03 million barrels of oil equivalent, our 12.17 billion cubic feet equivalent produced in the second quarter of 2010.

Third quarter production, when compared to third quarter of 2009 production, 22 million barrels of oil equivalent, our 13.32 billion cubic feet equivalent actually decreased 7%. Year-over-year decline as a result of primarily from our reduced spending and activity levels were up in 2009 continuing fracture enhancement and completion delays in South Texas and natural declines.

For the fourth quarter of 2010 we expect production increase 2 to 10% over third quarter 2010 production. As our dedicated fracture stimulation equipment and crew build momentum and improved efficiencies and completion activity works alright. While our third quarter drilling results Swift Energy drilled 17 operated development wells one of which was plugged and abandoned in Lake Washington and also participated in two non operated development wells.

The company also drilled one operated exploration well and participated in one non operated exploration well. Three operated horizontal development wells were drilled to the Eagle Ford shale, five operated horizontal development wells were drilled to the Olmos sand, one of which will be completed as a water source well after encountering mechanical difficulties. Two non operated horizontal developed wells were drilled by our joint venture partner to the Eagle Ford shale and five operated vertical development were drilled Olmos sand. All these wells were drilled in McMullen County in South Texas.

One operated horizontal exploration well was drilled to the Eagle Ford Shale in LaSalle County. The company has three rigs capable of drilling horizontal wells in the Eagle Ford and Olmos currently active in South Texas with the principal focus being on the Eagle Ford Shale. A non operated rig is currently targeted in the Eagle Ford Shale in our joint venture area in McMullen County and operated by our partner.

In the Lake Washington field and Plaquemines Parish, Louisiana, fourth well was drilled, and three were completed and one was plugged in abandoned during the third quarter. Six, sliding sleeve shift changes were performed early quarter resulting in an average production increase of 277 gross barrels of oil equivalent per day per operation. Drilling activities are expected to resume and like Washington [later in] the fourth quarter. Now briefly review our activity in each of our core operating arrangements quarter and then let Bob detail some of the highlights of their activity.

In the Southeast Louisiana core area which included Lake Washington, Bay de Chene field, production during the third quarter averaged approximately 10,152 net barrels of oil equivalent per day or about 61 million cubic feet equivalent per day in this area. A 2% decrease for the comparative of our second quarter 2010 average, net production from the same area.

Lake Washington average approximately 8,058 net barrels of oil equivalent per day are about 48 billion cubic feet of equivalent per day. A decrease of 2% when in compare to see of 2010 volumes. Primarily due to the lower levels of drill completion of maintenance activity and natural declines. Bay de Chene sequential production decreased 5% of 2,093 net barrels of oil equivalent per day is about 13 million cubic feet equivalent per day.

The sequential decline is due to known drilling activity and limited operational activity as well as natural declines. At fourth quarter 2010 operating plans in this quarter keep bringing a barge rig in the Lake Washington field, the drilling expectation test in December.

In our South Texas core area which includes our AWP, Sun TSH, Briscoe Ranch and Las Tiendas fields. Third quarter 2010 production averaged 8648 net barrels of oil equivalent per day or about 52 billion cubic feet of oil per day. A 7% increase in production when compared to second quarter 2010 production from the same area. This also represents a 25% increase over third quarter 2009 production in this area.

Production in this area increased as a result of increased activity and proved drilling efficiencies and production optimization. Production in this area is extremely sensitive to the performance and timing of third party service providers and vendors. For most of 2010, we have been disappointing with the ability of these third parties to perform along two schedules and timelines.

We do believe the dedicated frac system stimulation accrued equipment that arrived in early October will reduce the scheduling and performance issues we experienced throughout the first three quarters of 2010. Bob will discuss a specific impact on these issues on a full year production as well as daily rates.

Swift Energy currently has pre-operated rig drilling horizontally differed objectives in the La Salle and Webb Counties. One non-operated rig is also drilling in joint venture area in McMullen County. The Central Louisiana and East Texas core area which includes our Brookeland, Masters Creek, South Bearhead Creek and South Burr Ferry Fields contributed 1987 barrels of oil equivalent per day or about 12 million cubic feet equivalent per day. Production in third quarter 2010 that was an 8% increase in production from the second quarter of 2010.

One operated rig and one non operated rig are drilling wells to the Austin Chalk formation in East Texas and our Brooklyn field. We have a 100% working interest in the operated well and 40% interest in the non operated well. One non operated rig is also drilling well in the Austin Chalk formation in our South Burr Ferry field Swift Energy has 50% working interest in this well.

In our South Louisiana core area which is compromised Horseshoe Bayou/Bayou Sale fields, Jeanerette field, Cote Blanche Island and Bayou Penchant. Production averaged approximately 1575 barrels of oil equivalent per day or about 9 million cubic feet equivalent per day during the third quarter. Minimal operational activity is expected in this area for the remainder of 2010. Now I’ll turn it over to Bob who is going to review some operational highlights during the quarter.

Bob Banks

Thanks, first of our Lake Washington field we drilled four wells during the third quarter completing three and one. The CM #413 was drilled to a measured depth of 2922 feet nd encountered 48 feet of true vertical net pay. This well has averaged approximately 270 gross barrels of oil per day over the past 30 days. The State Lease 17266 #25 was drilled to a measured depth of 5,037 feet and encountered 246 feet of true vertical net pay. This well has averaged approximately 100 gross barrels of oil per day over the past thirty days. The CM #414 was drilled to a measured depth of 1,622 feet and encountered 90 feet of true vertical pay. This well was recently completed and will be tested following a facility upgrade. Also during the quarter at Lake Washington field, six sliding sleeve changes were performed during the quarter. The average product increased from these operations was 277 barrels of oil per day.

Additionally we will spot a deeper exploitation well later in the fourth quarter and we'll continue tour production maintenance and optimization program for the remainder of the year like Washington. Moving to our Central Louisiana East Texas core area, a non-operated exploration well targeting the Austin Chalk was drilled and completed in the South Burr Ferry Field by our joint venture partner.

Initial production test rates of this well was 13 million cubic feet of gas per day and 1,000 barrels of oil per day gross production. Swift Energy has a 50% working interest in this well which will be produced to sell upon completion of a salt water disposal well. A second well in this are has been drilled and will be completed during the fourth quarter. WE do expect to be active in the Austin Chalk in 2011.

Moving to South Texas and our AWP four horizontal wells, The AFP 3-H, the SBR 1-H, the AFP 4-H and the Whitehurst 1-H were all drilled to the Olmos formation in McMullen County during the third quarter. The SBR 1-H and Whitehurst 1-H had not yet been fracture stimulated, The AFP 3-H was recently fracture stimulated and will begin flowing back shortly. We also concluded drilling operations on the (inaudible) 1-H well, another horizontal Olmos well during the early fourth quarter.

During the third quarter we also drilled four vertical wells targeting oil in the Olmos formation in the Northern Portion of AWP and McMullen County. At the end of the quarter, three of these wells were completed does not have been brought online. The initial production rate of the most recently completed well, the SMR 7 was 318 barrels of oil per day and 0.8 million cubic feet of gas per day, the flowing [cubing] pressure of 1900 psi on a 1264 inch choke.

We concluded this drilling program after a sixth well was drilled during the fourth quarter. Now moving and updating our Eagle Ford activity during the quarter and McMullen County we drilled three 100% operated horizontal wells. We completed three of these wells during the quarter and brought on two of the wells during the quarter and one early in October.

The Discher 1-H and the PCQ #4H both drilled during the second quarter when brought online during the third quarter. A 14 stage fracture stimulation was performed on additional 1-H. This well’s initial production rate was 448 barrels of oil per day, 1.6 million cubic feet of gas per day.

The flowing casing pressure of 3275 psi on a 12/64 inch choke. The PCQ #4H was completed with a 13 stage fracture stimulation and this well’s initial production rate was 528 barrels of oil per day and 1.9 million cubic feet of gas per day with flowing casing pressure of 4903 psi on a 14/64 inch choke. The Quintanilla Me-You 1-H was drilled in the third quarter and was brought online early in October.

This will add a 12 stage fracture stimulation performed the initial production rate at this well was 494 barrels of oil per day and 1.3 cubic feet of gas per day, the flowing casing pressure of 2100 psi on a 18/64 inch choke. And the Carden 1-H an exploration well, was drilled to test the Eagle Ford shale formation on Swift Energy acreage in LaSalle County during the third quarter. A 14-stage completion was performed on this well, which is in the process of flowing back and being brought on line.

In our joint venture area in McMullen County, our joint venture completed the Bracken JV 3-H during the quarter. This well was drilled earlier in the year and was completed during the quarter with 10 stage fracture stimulation, these wells initial production rate was 5.8 million cubic feet of gas per day with flowing casing pressure of 5,753 psi on a 16/64 inch choke. Another well, the Bracken JV 2-H is currently being fracture stimulated and will be online in the fourth quarter.

Two additional wells the Whitehurst JV 1-H and Bracken JV 6-H have been drilled but not yet completed in this area as well. Now as Terry mentioned earlier we lowered our full year production guidance range primarily due to continuing schedule and performance delays of our completion related service providers. While we now control our own frac spreading crew too much work has been delayed for us to catch us volume wise before year end.

In July our planning contemplated that we can continue and have online 19 of our Eagle Ford and almost horizontal wells for the second half of 2010. We had also believed that we could have five JV wells frac and 24 vertical almost refract completed during the second half. Three different fracture stimulation providers involved have not been able to perform to the agreed schedule. During the month of July to September which is the period prior to our receiving our dedicated equipment and crew we only achieved three of seven fracture stimulations that we have firm scheduled dates for. This loss of program production has resulted in a reduction of 525,000 barrels of oil equivalent to our expected second half 2010 production. Perhaps a better way to evaluate how our horizontal fracture stimulation efficiency is progressing, we should review performance before and after our dedicated frac crew arrived. In the second quarter of 2010 and before we have build a significant inventory of wells, we averaged a one frac job per month pace of activity.

In the third quarter, we again only averaged in one frac job for month pace of activity even though we had two per month scheduled and committed. During this period we experienced severe equipment problems and delays, a service company stretched their spreads timelines and maintenance schedules too thin. In October after the [water] platform our dedicated frac spreading crew, we work at a four frac job per month pace which represents a four fold increase over the previous two quarters.

This performance pace is also carrying forward into early November result as we have just finished off of the AFP 4-H within five days. As such we are still expecting a strong ramp up in fourth quarter production but we have also widen our anticipating year end daily production rate range as a result of lower confidence levels of project scheduling with third party completion services are concerned. Let me be very clear however our vendors and contractors do an outstanding job when they are actually working on our the half. Until we sell, they have simply been too inconsistent and delivering their services for us to have high components in all timetables and work schedules.

If service or liabilities were to improve or put more simply, schedules are maintained at this point, we do still believe that we can exit the year above the midpoint of our revised 26,000 to 28,000 barrels of oil per day forecast. And I believe that the performance we are now seeing since the beginning of October is a very positive sign.

Terry mentioned earlier that strong operational and financial position this company is in. as we continue to execute on our operational plan, stabilize our completion operations and drilling more of a development type mode in South Texas, I believe we will surpass even his expectations. The more of our remote field locations to our home office in Houston, hundreds of people have worked tirelessly to get our section advantageous position.

And I can’t wait to see the results continue to gain momentum. 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’ll summarize Swift Energy’s third quarter results and review some of the highlights from today’s call. We have three new Eagle Ford wells on production. As of today, we have five 100%, three 50% joint venture Eagle Ford and three almost horizontal wells that are being frac waiting on facilities to flow back or waiting on completion operations.

Our long-term dedicated fracture stimulation accrued a lot and completed four stimulation jobs and began to fill in the month of October. This crew will complete at least three wells per month during the fourth quarter. Completion schedule bottlenecks will affect our full year production guidance.

We maintain our reserve guidance of growth at 15% to 20% over year end 2009 levels. We also expect to see our daily production increased steadily and finish the year at 26000 to 28000 barrels of oil equivalent per day, a 15 to 24% higher rate than our third quarter daily average production rate. We have encouraging results from our first Austin Chalk joint venture well in Louisiana, a second well is currently drilling in this area and we are drilling a Swift Energy operated well to the Austin Chalk and our Brooklyn field in East Texas. We have secured long term gathering and transportation agreement for natural gas production in Webb County Texas and we’ve also extended our $500 million credit facility with a $300 million borrowing base through 2015. 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 Jason Wangler with Wunderlich Securities.

Jason Wangler - Wunderlich Securities

Good morning guys, just a quick question now you have that frac crew on the ground, is four probably a good number that’s the max they could do per month and like you said Terry three is a good average per month.

Bob Banks

This is Bob, I think that the performance we are seeing and we think we can do three if everything is going reasonably well I will already at a four per month pace and things looks pretty smooth at this point. And there is even opportunity down the road probably not within the next month or two to get even above that pace. So we’ve just seen a material turnaround since we’ve got the dedicated crew equipment we are able to work with our provider on maintenance, scheduling services and the way we time that maintenance into our operation, its all just smoothing out for us.

Terry Swift

I hate to complicate the view of the answer, but I think I will here. I am again sure lot of people working behind the scenes and a lot of effort put on the part of our folks and our service providers and one of the things that we need to be clear about is, we have been doing the slick water fracs principally and there is whole programs there. Now we have recently done some hybrid fracs and for those that auction there you were about to slick water fracs typically take longer to do and as you move to the hybrid fracs, you do get some performance advantage in terms of [Todd], we are working with that, because we don’t think that’s the right answer for every area and every situation but we certainly do think the hybrid fracs are going to be part of our ongoing program, particularly up in the oil rich area.

Jason Wangler - Wunderlich Securities

Just maybe one more on the frac because since you have that backlog, is there any thoughts maybe still jumping on to the schedule for some of the service providers and just hoping that maybe even get a incremental frac put in there or you just kind of stick with your crew and let them did that backlog work out over the next couple of quarters?

Bob Banks

We are very actively engaged with a number of service providers, in fact we have a non-dedicated crew right now frac in one well that was the backlog. We are working on a couple of more dates, we have not built those indoor planning because dates have in those been the most reliable the past two quarters but clearly we are engaged with all the service providers on future dates and that really is part of our plan in the first part of next year and maybe even a little bit more in fourth quarter to get some more fracs done.

Operator

Your next question comes from the line of Leo Mariani from RBC.

Leo Mariani - RBC

You guys had a pretty good well there on and off the chart, carries this Q with the well (inaudible)?

Terry Swift

Its over in the Austin Chalk area, I think we basically need to know that first well was an exploratory well and the good news is it really has tested much better than we thought the difficulty in drilling in the well was we ran into some really hot pressures and that well did have some mechanical problems although we were able to go ahead and get a really good test run or so.

The initial cost on that well Bob.

Bob Banks

It was about $10 million with the trouble time. The good news is we worked in collaborative way with the operator on the second well designed and that second well is coming significantly under that first well in about the $5.5 million range. So, we have a good working relationship with the operator and I think we are making some adjustments in real time and they are showing up now on the second well.

Leo Mariani - RBC

You think that probably $5.5 million number is pretty good going forward and you guys have estimated you are on that 2000 Chalk well?

Terry Swift

I think that’s a reasonable number because we again have the pressure, we have the mid-cap drilling but we made it a much less complicated well more construction design. So I think both partners are on board that’s the way to go forward in the future.

Leo Mariani - RBC

Okay and how many estimate we think the EUR was on that first drill?

Terry Swift

Not yet. We have only done an initial test on it. We are waiting to hook it up and get some more production history before I think we’d be comfortable talking about you are.

Leo Mariani - RBC

Alright, again jumping over to the Eagle Ford I guess you got some gathering line in Webb County over there. Can you talk about your infrastructure in other key areas you still have wells that are producing at the expected rate. Are you able to flow your wells full look like some of the slow slider you guys had in some of those wells looked a little smaller than some of your peers.

Terry Swift

I think starting down in Webb County we are in the process now to get that infrastructure hocked up. We think that will be to where we can be floating open our wells and frac our next two wells in December. So we’ve tackled that and handle that infrastructure issue. Up in the north Sun TSH we still have some facility issues we are working through. We expect those to be debottled next year within the next quarter or so and then over the AWP area we are pretty much open up, I think one thing that you saw on our test rates is we really working on restricted chokes here now as opposed.

So we are really as interested in getting the higher IP numbers, we are really looking at some models where we are trying to hold those wells back bring them in more slowing and see if that doesn’t confirm our suspicion that we will get better EURS within a short period of time out of the well managing the well that way as opposed to opening it up and pulling it a little harder. So I think that’s what you are really seeing.

Leo Mariani - RBC

Just moving to Lake Washington you guys have a deep exploitation well you talked about getting ready to start later this quarter here. Just curious size of that target, I guess you could describe to the thing for exploitation in the process, exploratory, you can give us sort of more color on that?

Terry Swift

That is what I would call a partial part is up debt from known production, very-very good sand quality so we think this well has potential to be a very good oil producer. In terms of size I think we would probably say the range is 150,000 barrels to maybe 1.5 million barrels for that particular location.

Operator

Your next question comes from the line of Michael Hall with Wells Fargo.

Michael Hall - Wells Fargo

First in the Eagle Ford, few questions. If I recall the cost parameters around the dedicated crew, somewhere related to your utilization level of crew, if you are doing about four per month, its called three per month, four per month. What's the expected cost looking like for while now?

Terry Swift

The contract as you properly know, that it is really a exclusive dedicated crew. So, obviously if we don’t get any wells frac amount then we are paying money, I'm not getting anything done. But if we are up around two fracs amount, we think that we are still under the current spot market process fracs out there. Current spot market frac jobs clearly depend on whether you are doing a slick water, a hybrid, whether you are doing nine stages of 14, the amount of sand you are putting in and all of operators have different mixtures there but our stop market job can easily be $3 million to $4 million if you are trying to do a really big job, we heard some exceptional numbers above that, but really two jobs a month will put us under the spot market in terms of average type of frac out there. We think we can get up to four and we think we will be seriously beating what you have been seeing in terms of that average spot market job materially beating it.

Michael Hall - Wells Fargo

Would you care to put a number around what’s the total cost would be it for four months?

Terry Swift

At four at months, bob you want to answer that.

Bob Banks

Yes, I think depending on the number of other issues frac recipe design I have been saying all along that as long as we are not really stepping out there testing new positions as long as we are really getting more into development mode, there is no reason why we can’t be drilling this for $6 million to $7 million. I think we are sticking with that. We are still sticking with that.

Michael Hall - Wells Fargo

And I guess also just curious as it relates to the reporting of results in Eagle Ford. The gas stream that you are reporting with those wells is that a white gas stream or there be some sort of MGL up lift associated with that post processing. How should I think about that?

Terry Swift

We early segregated out of gas but that’s a [wet] gas stream with the high Btu, it has some nice liquids with it.

Michael Hall - Wells Fargo

And what’s kind of average btu looking like on the wells at this point?

Bob Banks

1250 to 1300 btu on the gas.

Michael Hall - Wells Fargo

And then thinking about the exit rate guidance of 26 to 28 what I guess the key variable on high and low end. What are the…isn’t really just timing of Eagle Ford wells is there any other one off item to think.

Bob Banks

The biggest issue probably is the timing. We run a couple of different paces out through the end of the year to come with our numbers. The other variable is these Austin Chalk that’s two now how those come on and clean and producing the sales. One we got a good test on, we had to shut in waiting hook so that’s getting ready to come back on here eminently and then second well we have not tested yet but we like what we saw so those two factors are the biggest variables.

Michael Hall - Wells Fargo

And thinking about that Austin Chalk program, I mean if you had continued success here in the fourth quarter you said you would expect to have some activity in 2011. maybe how many wells could you think about drilling and then what sort of additional facilities might be needed.

Bob Banks

Yeah, actually as you look forward to next year. We got to a little bit careful we haven’t come out with all the 2011 budget strategies. We will be doing that as we go across year end and certainly into our analyst meeting next year. But I can tell you this right now we are very excited about the Austin Chalk we really have four areas that we are working in the Austin Chalk. We’ve got our bread and butter area over in the Brooklyn area, there is some nice things to do there. So you definitely see us drilling a well or two over there next year, working with a partner over there that has some working interest in our some of our units. We have our Master Creek area, we are pretty excited about some of the things we can do to revitalize, reintegrate some of that production over there.

Again both of those areas are bread butter, there is no facility issues to speak of whatever production you get, you are ready to put in, whatever gas you have got, you are ready to process. Burr Ferry is close to facilities, if you remember we had our production in that area while back but one of the things that time has done for us the new technologies are helping us stay in zone better, get much better completions in terms of, in the old days you had to worry a lot about the mud cap and they right see the manufactures today, I think we are doing a better job stay in the in zone, but we are drilling exploratory and appraisal wells first.

We have got one very large AMI with the joint venture partner, we do intend next year to come back in there and have some offsets, where its appropriate as Bob noted we got some early production results that look good, with those higher bluff in the next year you will see these growth some developmental wells that would offset that basically continuing the appraisal program on a very large acreage position and we do have additional acreage all along trend that we will probably put some more exploratory was in the next year.

Michael Hall - Wells Fargo

Just one more if I may, third quarter accelerate, what was that?

Bob Banks

The average production for the third quarter was about 22,500 barrels across the entirety of the third quarter. How about the exit right now?

Terry Swift

I think it was much higher than that.

Michael Hall - Wells Fargo

Thanks with the lot of these wells, just come in order in October.

Terry Swift

Phase 22, [probably] to 23.

Bob Banks

I think it was higher than the average.

[Multiple Speakers]

I don’t think it was significantly higher than the average.

Terry Swift

We have some flush days where we got up to 24 but the way we are trying to manage this business is to give you numbers that are useable and in that regard Bob want to refresh on how we actually come up with these test rates that we are reporting.

Bob Banks

Well, I mean we have a standard on our test rates that or certain type of wells, gas and safe wells. We are picking the IP day number five and then before some of the MROs wells that we get more (inaudible) and may be some of the more dry gas wells are picking day number 10. So we are trying to be very consistent on the day we are picking IP. So that helps us with our model internally and calibrating our production history back to our prequel model. So that’s what we are picking on the numbers and on day six or day seven may be higher but we just chosen to pick that consistent date of return.

Operator

Your next question comes from the line of Derrick Whitfield from Canaccord.

Derrick Whitfield - Canaccord

On the Eagle Ford, the latest wells change of view on the (inaudible) of the gas compensate 21 days at AWP?

Bob Banks

I think the latest was a pretty consistent. However, I would say there is still some tinkering to do where you had a line that might have been a great area couple of miles wide now that grey area I think may be a mile wide. I think we found more oil, I don’t think there is any doubt we were oilier than we expected in terms of our Northern AWP program. But also there is an area in the northern JV area that we are just getting into and that’s going to be a pretty critical well. We think northern of our JV area has got some really nice liquid based on this program so that’s a long answer but we did learn something, we are fine tuning that line and we think it’s goes well for the northern portion of the JV acreage.

Derrick Whitfield - Canaccord

And then moving to the Austin Chalk, could you comment on how the geology compares across each of the key product areas.

Terry Swift

Well if you look at Austin Chalk of course it goes all the way along the Texas Gulf Coast it’s a big massive trend and when you get into the Master Creek area we drilled some very deep, high pressure wells on units that had 2000 acre spacing units so that was the kind of spacing back in the 90s when those have been drilled.

As you move across that play it does change somewhat in the Master Creek area there was a lot of water associated with the initial production but you definitely had oil wells that would come in excess to 2000 3000 barrels of oil a day and some of the accumulates on those wells were over 2 million barrels equivalent. as you move west to the Burr Ferry area you generally would get a little bit shallower you would begin to have less water and by the time you got to Brooklyn you were even shallower in terms of the play fair way that was being developed and you typically had no water drop by the time you got to Brooklyn. I had nice oil component probably 50-50 oil gas over there.

We now really do believe and other offers have shown that the play has extended deeper South of Brooklyn, there has been a nice opening up to deploy and as you match that extension of the Brooklyn area south forward over to the Masters Creek area, you see a lot of opportunity for the play to continue, so that’s what we are exploring.

Derrick Whitfield - Canaccord

Maybe a little more color on the first day while if you could, or this well have exactly landed in zone say across 80% a better than horizontal and you think its representative of what you could expect in this part of the trend and look at that forward?

Bob Banks

On the first well we steered this well independently and I can say that well was very well kept in the zone, there were some mechanical difficulties with that well but from the actually compromised even the test rates we reported. The second well also, we just here that independently and it looks like that well is strictly in the zone. So, a very good job on keeping the well bore [putting] zone on these first two wells.

Derrick Whitfield - Canaccord

And maybe jumping over the base Jane, any updates on your deeper test targets there?

Bob Banks

We clearly have two wells over that area we saucered and blowed and ready to drill one is what we call at the team time, it principally a gas, its principally HBP, so we are kind of slowing down on that because of the gas market, but we want to drill that and about where we have and every one call it south [shaft] that just don’t kind of do at North and East of (inaudible) but in the general (inaudible) area. That South [Shasta] where we intend to drill next year probably take about a 50% position in operate that well, it should have a very nice liquids component associated with it most of the work we have done based on, we did have discovery of [shaft] on North of derivatives given us a lot of encouragement that we could have a little exploration target there next year.

Operator

(Operator Instructions) your next question comes from the line of Brian Kuzma from Weiss Multi-Strategy.

Brian Kuzma - Weiss Multi-Strategy

I was just wondering with these more liquid or rich wells. Do you have sense as to what kind of EUR expectations?

Bob Banks

The morals we have been talking about publicly like it dug and other places, its still kind of in a range of about 250,000 to 375,000 barrels EUR on those real liquid rich wells.

Brian Kuzma - Weiss Multi-Strategy

What percentage of your (inaudible) acres have to say gets into a category?

Bob Banks

Well, I wouldn’t put it on a percentage basis because I just can’t calculate that fast. We have what we call our norms on AWP area that really there is probably about 12,000 acres of their firm or SMR over our Discher area, over to (inaudible) area those two wells we have talked about or at PCQ area, that probably that 12,000 or more acres there. We also have a block of acreage that’s very oiling that in the trend that HBP that’s probably about 4000 to 5000 acres and then we also have the northern part of our JV area where we think that’s going to be very, very oily probably put in the gas common segment but still oily and that portion is probably 4000 to 5000 acres.

Terry Swift

And then our two new wells which is another 14000 acres over there we believe is in the oil compensate window.

Brian Kuzma - Weiss Multi-Strategy

And then your lookout in 11 what kind of level are you guys comfortable as far for the cash flow. Should I think about that in that terms or should I think about in terms of cap metrics that you guys traditionally look at.

Bob Banks

I think the best way to answer that is we are absolutely committed to protect the balance sheet and in that regard all of our look will be at cash flow obviously we got to try to figure out what gas prices are going to do in all process because that’s the material thing. We do expect some really nice production gains next year as we do our modeling which we are doing right now working with the board it’s clearly the gas logy is probably the most uncertainty and I would say that’s very clear that we intend to spend cash flow to the extend that we can accelerate the oil pieces and liquids pieces then we got a line of credit $300 million. So we could go into that somewhat but we also have options in terms of maybe selling some non strategic properties we will putting that all together for you as we go across the year and early into 2011 but we will protect the balance sheet.

Brian Kuzma - Weiss Multi-Strategy

And a minimum that you think you will do to keep that one frac?

Bob Banks

Yes.

Brian Kuzma - Weiss Multi-Strategy

Working in basically drilled up 40 wells.

Terry Swift

I think we have numerous scenarios and plans but we clearly have a plan where we protect the acreage as well without stressing the balance sheet anyway.

Brian Kuzma - Weiss Multi-Strategy

And then one last one from me. On the wells you guys have drilled are realized going forward, they are going to be lower but what’s been the average cost to drill and then the average cost to complete?

Terry Swift

As bob mentioned, we have done a lot of exploratory work this year, a lot of appraisal work. We put our water facilities around these worlds so that we are ready to do the fracs. We have some infrastructure we put in. So this year is average number of (inaudible) wells in terms of development. I would say this year what we have looked at some $7 million to $8.5 million types of wells.

We had wells that [record], we have done microcosmic out there just a whole lot of science to given this a leg up on this. But going forward as Bob said, you give them to the oilier areas, we opt to be able to drill these now on a development mode in the $6 million to $7 million range.

Operator

There are no further questions at this time. Are there any closing remarks?

Terry Swift

We would like to thank you for joining us today on our conference call. Thank you very much. Thanks.

Operator

This concludes today’s conference call. You may now disconnect.

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