SilverBow Resources Inc (SBOW) 2009 Q3 法說會逐字稿

Good morning. 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, will there be a question-and-answer session. (Operator Instructions) Thank you. I would now like to turn the conference over to Mr. Paul Vincent, please go ahead, sir.

Good morning. I'm Paul Vincent, Manager of Investor Relations. I would like to welcome everyone to Swift Energy third quarter 2009 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 for questions. Also present on the call are Mike Kitterman, SVP Operations.

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, 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 results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Thanks, Paul, and thank you again for joining today's conference call. Swift Energy was very active during the third quarter of 2009 on numerous fronts. We brought new crude oil and low pressure production facilities at Bay de Chene online earlier and at higher initial volumes than anticipated. Our recompletion and work-over program at Lake Washington continued and performed above expectations. These two factors led to quarterly production being above our previously announced guidance during the quarter. Our horizontal drilling programming in the Olmos formation of AWP field in South Texas resumed in the third quarter. We begun a vertical drilling program targeting oil formations in the northern portions of AWP as well as a fracture stimulation program designed to improve the performance of the existing productive well bores. Southeast Louisiana we resumed drilling operations in our Lake Washington field focusing on shallow oil horizons. Financially, we experienced better than forecasted price realizations, primarily on crude oil sales at Lake Washington and a lower than expected tax rate during the quarter. Alton will discuss the items in a few moments.

Finally, as of yesterday, we have entered in to a joint venture agreement in South Texas to exploit a develop Eagle Ford shale. This particular transaction is very strategic for us. We have taken a portion of our Eagle Ford shale position in the AWP area and teamed up with Petrohawk, a well respected shale resource player, to develop jointly 26,000 acres. We will provide the important details of this arrangement later in the call.

2009 has not been an easy year in toil and gas business. We at Swift Energy Company have put this company in a position to enter 2010 with excellent momentum towards production and reserve growth. We built a large inventory of projects in our core areas. These protects include oil and natural gas opportunities in and order salt domes and south Louisiana, horizontal drilling opportunities in both shale and tight gas end formations in south Texas, as well as Austin chalk opportunities in central Louisiana and east Texas.

During the quarter continued to witness oil field service cost moderate relative to hydrocarbon pricing. The exploration and production sector has begun to slowly rebuild activity levels as the outlook for natural gas and crude oil prices have begun to improve. Although the industry rig count has stabilized and even increased from second quarter levels, we do not believe that the current rig count can sustain existing natural gas production levels. Although we are budgeting conservatively in regard to natural gas prices, we expect to continue our capital spending levels in 2010 above our 2009 budget level as the economic and operating environment continue to firm up.

In August we conducted a secondary equity offering of our common stock, received net proceeds of approximately $109 million. This strengthened our balance sheet as we used these proceeds to pay down borrowings on our credit facility which was recently reaffirmed at $300 million. Alton will give the details and the impact of this offering on our business as well as ongoing cost reduction efforts at both the corporate and field level.

While the capital markets have been active and the economic outlook has begun to improve, we remain aware that prices are tenuous and protected a portion of our first and second quarter natural gas pricing through our price management -- price risk management program. We are prepared to predict additional volumes in to 2010 as the opportunity arises. We are prepared operating and pricing environment deteriorates, to be able to show the discipline of slowing down our operation and protect our business should that happen. Bob and Bruce will give detail on operating activity in a few moments but first I would like to review some of the highlights in the quarter and commend everyone involved with the organization for their capital discipline and for performing value adding work that meets or exceeds our expectations.

Operational highlights for the quarter include the resumption of crude oil sales at our Bay de Chene field in south Louisiana. These facilities were brought online earlier than expected and performed well. The initial flush oil production averaged over 2500 gross barrels of oil per day after the start up of these facilities. Field wide crude oil production over the last seven days averaged about 1100 gross barrels of oil per day since up the upgraded production facilities were brought online. No wells have been drilled in 2009 in this area nor any wells planned to be drilled for the remainder of the year, but we will start up again in 2010 in Bay de Chene. Our production optimization and recompletion program in Lake Washington field continued to deliver excellent results.

While these types of projects may not be as exciting as the higher risk ones, they have certainly delivered valuable cash flows during a very uncertain period. We also began drilling shallow and intermediate wells targeting oil reservoirs at Lake Washington during the quarter. Initial results have been positive and this program will continue. In south Texas we resumed our horizon drilling program in the Olmos formation at AWP during the quarter. We continue to be encouraged by what we are finding in these wells and will continue to modify our operational designs and optimize our results. Bob will discuss these technical details of the two wells drilled during the quarter.

First horizon well drilled in the Olmos formation late last year was the R Bracken 33H. It continues to perform well with estimated ultimate recoveries actually trending upwards. As we drill these wells, our expertise and knowledge of the play continues to improve. We still expect these types of wells to average a resource potential per well of 3 to 5 DCF equivalent. During the third quarter we advanced preparations to drill horizontally in the Eagle Ford shale for the fourth quarter and both in our newly announced joint venture as well as the undeveloped acreage outside of the venture, we plan to drill additional wells. The exceptional value this play brings cannot be ignored. We analyzed the locations and the results of wells that have been drilled by others in the industry and we believe our acreage remains highly perspective, particularly in the AWP area and certain other areas of south Texas where we have sizable acreage positions. We will be developing this play beginning with wells drilling in the fourth quarter of this year and in to 2010.

The most turbulent portion of this particular economic downturn appears to be behind us. However, we appreciate how quickly the environment can change. We have managed our business prudently and will be cautious as we increase activity levels in the fourth quarter of 2009 and in to 2010. With that, I'll ask Alton to present the third quarter 2009 financial results.

Thanks, Terry, and good morning. The oil and gas sector continued to experience a low, although somewhat improving commodity price environment during the third quarter of 2009. Swift Energy's financial results for the third quarter reflect this. Revenues were $96.3 million, a 55% decrease from Q3 2008 but up 16% sequentially. Our income from continuing operations was $7.6 million or $0.21 per diluted share, down from Q3 2008 levels yet beating current first call mean estimate of $0.01. Cash flow before working capital changes came in for the quarter at $1.65 per diluted share and Q3 2009 production decreased 4% to 2.2 million barrels of oil equivalent.

As you know, both crude oil and natural gas prices are substantially lower than third quarter 2008 levels, though recently on the upswing. Swift's average realized price 3Q 2009 declined to $44.14 per Boe due primarily to crude oil prices declining to an average of approximately $68 per barrel for the quarter compared of approximately $123 per barrel a year ago. Along with natural gas prices declining to an average of approximately $3 per mcf compared to approximately $10 per mcf in 2008. Resulting in a decrease in quarterly oil and gas revenues of 54% when compared to 3Q 2008. Sequentially, the increased pricing in crude more than offset the slight decline in natural gas pricing resulting in our quarterly oil and gas revenues increasing 18% when compared to the second quarter of 2009.

I would like to point out regarding crude oil prices received during 3Q 2009 that the relatively strength of certain sweet crude differentials during the quarter offset other price factors more positively than in prior quarters. Please see our guidance for more detailed information on fourth quarter and full year estimated pricing differentials. As always, we continue to focus on our controllable per unit cost and metrics.

Production came in above guidance which helped to reduce our per unit cost in the following areas. G&A came in at $3.98 per Boe, which is within our guidance. DD&A came in at $18.48 per barrel at the low end of guidance. Production cost came in well below our guidance at $8.34 per barrel as cost in several categories were reduced. Interest expense came in at $3.31 per barrel below our guidance due to lower borrowings on our line of credit and production taxes came in within guidance as a percentage of revenue. Result was income from continuing operations for the quarter of $7.6 million which is $0.21 both basic and diluted.

Our 3Q 2009 tax provision, as Terry mentioned, includes accumulative year to date adjustment in accordance with the applicable accounting rules which drastically reduced this quarter's effective tax rate. Please see the guidance in our earnings release for detailed information on the fourth quarter and full year estimated affected tax rates. Cash flow before working capital changes for 3Q 2009 came in at $58 million or $1.65 per diluted share while EBITDA was $57 million for the quarter. Quarterly CapEx on a cash flow basis was $29 million.

Let me spend a moment now to highlight Swift's solid financial position and discuss a few of our cost containment initiatives. In August we completed a successful public offering of 6.21 million shares of our common stock at $18.50 per share, the largest such equity offing in the companies 30 year history. The net proceeds were approximately $109 million which was used to pay down our line of credit. Further, as announced yesterday, we closed a joint venture arrangement with respect to a portion of our Eagle Ford acreage in south Texas which resulted in the receipt of $26 million, also applied to our line of credit. At close of business yesterday, our outstanding balance under our line of credit was $41.6 million down from the $80.8 million at the end of 3Q 2009.

With respect to our line of credit facility with 10 member bank group that currently runs through October 2011, our borrowing base and commitment amount will reaffirm $300 million on November 1, 2009. We are very pleased with the steps we have taken to strengthen our balance sheet. As previously mentioned, we are also emphatic about controlling our cost across the enterprise. We continue looking closely at our capital expenditures, operating expenses and administrative costs. We have identified several cost saving opportunities in each of our core areas. We also are working very closely with all vendors for additional cost savings for goods and contract services. We will maintain a conservative financial discipline and have a 2009 CapEx budget that enables us to live within cash flow while building momentum in to 2010.

With respect to Swift's hedging activity, we purchased floors covering a meaningful percentage of our domestic natural gas production for the first and second quarter of 2010 at an average NIMEX strike price of $4.73 per MMbtu. Please see our website for complete and current detailed hedging information. As always, we included financial, and operational information in our press release including guidance for the fourth quarter and full year 2009. As Terry mentioned, Swift is well positioned financially to take advantage of any opportunities that always seem to present themselves during times of uncertainty and adversity as we have all experienced. We've been through these cycles before and ready for the challenge. With that, I will turn it over to Bruce Vincent for an overview of our operation.

Thanks, Alton. Good morning, everybody. We appreciate you listening in. Today I will discuss third quarter 2009 activity, including our production volumes, our recent drilling results, activity in our core operating areas, and our plans for the fourth quarter 2009. Bob Banks will then provide greater detail on a couple of our activities we want to highlight for you today.

Beginning with production. Swift Energy's production during the third quarter of 2009 totaled 2.22 million barrels of oil equivalent, or 13.32 billion cubic feet equivalent. This was approximately 120,000 barrels of oil equivalent above our third quarter 2009 production guidance primarily as a result of oil production at our Bay de Chene field starting up in late August, better than expected performance of our recompletion in the work-over program in Lake Washington, and partially as a result of minimal Gulf Coast storm activity. The lack of storm activity in the Gulf not only eliminated any down time from shut-in production, but also did not interfere with our facility construction activity at Bay de Chene. Third quarter production decreased 4% from the 2.32 million barrels of oil equivalent or 13.91 billion cubic feet equivalent produced in the same quarter 2008 as a result of reduced activity, shut-in production at Bay de Chene for July and most of August and natural declines. Sequential production decreased 2% when comparing third quarter 2009 production to production in the second quarter of 2009.

Now for our drilling results. Swift Energy drilled three wells during the quarter. Two horizontal wells and one shallow vertical oil well were drilled in the Olmos formation at the AWP field in McMullen County, Texas during the third quarter. We continue drilling in the Olmos in the four quarter and began drilling shallow and intermediate oil targets in Lake Washington as well. I will briefly review our activity in each of our core operating areas for this quarter and let Bob actually fill you in on more detail of the recent activity.

In the southeast Louisiana core area, which includes Lake Washington and Bay de Chene fields, production during the third quarter of 2009 averaged approximately 13,448 net barrels of oil equivalent per day or proximately 81 million cubic feet equivalent per day in this area, an increase of 2% when compared to our second quarter 2009 average net production from the same area. Lake Washington averaged approximately 10,112 net barrels of oil equivalent per day or about 61 million cubic feet per day, a slight increase when compared to the second quarter 2009 volumes. Bay de Chene sequential production increase of 8% to 3,336 net barrels of oil equivalent per day or about 20 million cubic feet equivalent per day. It is primarily due to the restoration of oil production which has been shut in as a result of damage caused by Hurricane Gustav .

Initial crude oil production averaged approximately 2,590 gross barrels of oil per day, that along with natural gas production of 20.4 million cubic feet a day over the first seven days after the start up of these facilities. This was higher than expected but we did expect flush production. Field wide, crude oil production over the last seven days averaged proximately 1,100 gross barrels of oil per day and 17.1 million cubic feet per day of natural gas. No new drilling activity has occurred at Bay de Chene this year.

In our south Texas core area, which includes our AWP, Sun TSH, Briscoe Ranch and (inaudible) Fields third quarter 2009 production averaged 6,982 net barrels of oil equivalent per day or about 42 million cubic feet equivalent per day, a 6% decrease in production when compared to second quarter 2009 production in the same area. This decrease is primarily a result of significantly reduced drilling activity in the area.

In the AWP field located in McMullen County, the R Bracken 34H and 35H horizon well were completed in the Olmos formation during the third quarter. The R Bracken 36H is currently being drilled, that rig drilling this well will remain in the field during the fourth quarter to drill one more well this year. I'm going to let Bob discuss this program in more detail in just a few minutes.

Also at AWP, though, we are drilling oil targets in the northern portion of the field. One well was drilled during the third quarter and two have been drilled to date in the fourth quarter. The rig is currently drilling a well and will remain active through the end of the year. In addition to our drilling activity at AWP we began an extensive refract program in the field. Bob will also discuss these programs in more detail.

Finally, we announced yesterday a joint venture at [Greenwood] Petrohawk to develop an approximate 26,000 acre portion of our Eagle Ford shale acreage in McMullen County, Texas in and around the AWP field. At least one well will be drilled to test Eagle Ford shale horizon in this 26,000 acre prospect during 2009. We currently expect our rig to remain active in the area during 2010.

The company will retain a 50% interest in the approximate 26,000 acre prospect area which covers leasehold interest beneath the Olmos formation and inclusive of the Eagle Ford shale formation extending to the base of Pearsall formation. Swift Energy received approximately $26 million in cash consideration upon closing of this agreement. Petrohawk will also fund approximately $13 million of capital expenditures on Swift's behalf within the first 12 months of the joint venture. Presently, Swift Energy expects to utilize this entire $13 million amount to cover drilling and completion cost of horizon wells targeting Eagle Ford shale in the joint venture area. If the full amount is not utilized during the first 12 months of this agreement, the difference will be paid to Swift as a cash consideration.

Petrohawk will serve as an operator during the drilling and completion phase of the join development and swift will operate the wells drilled once they have entered the production phase subject, of course, to the terms of the agreement. The company is planning to spud horizon well to test the Eagle Ford shale on its undeveloped acreage position outside of the joint venture. As with all of our operations, we will provide results from drilling activity in this joint venture during our regularly scheduled quarterly conference calls or in the event that any results are material in nature.

The central Louisiana and east Texas area, which includes our Brooklyn, Masters Creek and South Bearhead Creek fields, contributed 2,244 barrels of oil equivalent per day or 13.5 million cubic feet per day production in the third quarter 2009. There was no significant operational activity in this area during the third quarter. In our south Louisiana core area which is comprised of Horseshoe Bayou, Bayou Sale, [Generete], Cote Blanche Island and Bayou Penchant, production averaged approximately 1,553 barrels of oil equivalent per day or about 9.3 million cubic feet per day. During the third quarter a decrease of 13% when compared to second quarter production in this area primarily as a result of reduced activity levels and natural declines. Let me turn the call over to Bob Banks, our Chief Operating Officer, to review some of the more notable activity during

Thanks, Bruce. At our Lake Washington field the TM400 and TM403 both finished drilling early in the fourth quarter. CM400 was drilled to a measured depth of 6,023 feet and encountered 31 feet of true vertical net pay. The CM403 was drilled to a measured depth of 5,365 feet and encountered an estimated 52 feet of true vertical net pay. Both wells are now being connected to production facilities and this one rig program will remain active during the fourth quarter and in to 2010.

Also, our production optimization program involving gas lift enhancements and sliding sleeve shifts which began during the first quarter of 2009 continued during the third quarter. Well work was completed on four wells and five recompletions were performed during the third quarter. All five of these recompletions tested well above our expectations. In our Bay de Chene field, the company is maturing in inventory of oil and gas prospects and expects to resume drilling operations in the field early in 2010.

In south Texas, at the AWP field, the R Bracken 33H well, now online for over 10 months, continues to perform above expectations and the estimated ultimate recovery is now anticipated to be at the high end of our original 3 billion to 5 billion cubic feet estimate. The initial production rate for the R Bracken 34H was 5.7 million cubic feet per day and flowing pressure of 2,175 PSI on a 3664 choke. The production declined in this well and has already turned hyperbolic and has stabilized at the current production rate of approximately 1.8 million cubic feet per day. The initial production rate of the R Bracken 35H well was 4.6 million cubic feet equivalent per day with flowing tubing pressure of 4,200 PSI on 1464-inch choke.

Mechanical difficulties developed very early within five days of the startup of this flow back and the well was plugged off by sand in the well bore. We subsequently went in and cleaned out the well bore and we are slowly bringing that well back on at a rate of 2.3 million cubic feet per day with flowing tubing pressure of 1900 PSI.

The R Bracken 36H is currently being drilled. In this well, a vertical pilot hole was drilled, cored and logged. These cores and logs will be utilized to further our understanding of the depositional environment in the southwest AWP area and to enhance our ability to relate Petrohawk prompts to logs and better able to predict reserve recoveries in future development wells. The completion design of the R Bracken 36H will be modified to reduce the risk of mechanical issues similar to those encountered in the R Bracken 35H. Since we began this initiative with the R Bracken 33H, we have been able to reduce our drilling complete cost in to the $5 million to $6 million range. One additional horizon Olmos well will be drilled after the R Bracken 36H and then the rig will be released to allow time for a technical evaluation of the 2009 horizon Olmos drilling program and before beginning our 2010 program early next year. In this next well, we do intend to eliminate the intermediate casing string which will reduce our well costs by $0.5 million to $1 million. If we are able to apply these cost savings to future wells, it will enhance the overall economics of this program.

Moving to the northern portion of the field, the northern Gonzalez #2 well was drilled to a depth of 9,510 feet during the quarter and it logged 25 feet of net pay. This well initially tested at a rate of just over 100 barrels of oil equivalent per day and is now producing the sales at approximately 60 barrels of oil per day. Two other wells, the Quintanilla #2 and 3, began drilling in the third quarter and recently concluded drilling operations, Quintanilla #2 tested above 200 barrels of oil per day, casing pressure of 360 PSI. This well is currently shut in awaiting connection to production facilities. The Quintanilla #3 will be [fraced] after it is connected to the production facilities.

Finally, we have identified a opportunity to increase production rates in some of our existing productive wells at AWP. To date we have identified over 150 wells which are candidates for an additional fracture stimulation. 11 of these identified wells have been fracture stimulated since the beginning of September and the results have encouraged us to continue on with this program. While no one operation will be meaningful when compared to our overall production profiles, initial production rates in these initial 11 wells are approximately 600 mcf per day which is significantly higher than the average results from the previous fracture stimulation carried out in the these vertical wells in the field. We believe these operations will help support our base production profile in the field over the next several years. The company plans to perform approximately two additional fracture stimulation operations per week for the remainder of 2009 and in to 2010.

In total, we still expect our current activity levels to support a daily production rate of between 24,000 to 26,000 net barrels of oil equivalent by the end of 2009. Thanks for your attention this morning and I will turn it back to Terry to recap.

Thanks, Bob. Before we open the line for questions, I want to summarize Swift Energy's third quarter results. To review some of the high lights from today, our Bay de Chene crude oil facility start up and our production enhancement and recompletion program performed better than expected contributing to better than guide operational performance. We currently have one rig drilling well in Lake Washington, one rig drilling horizontally in the Olmos AWP and one rig drilling vertical oil targets in AWP.

We recently entered in to a joint venture agreement to accelerate the development of a portion of our AWP acreage believed to be perspective for the Eagle Ford shale. We plan to spud a shale well within this joint venture during the fourth quarter. We will also begin testing the Eagle Ford shale on our acreage outside of this joint venture area this year. A secondary equity stock offering and closing of our south Texas joint venture have allowed us to significantly improve our balance sheet and reduce our borrowings on our credit facility. With a stronger balance sheet we are better positioned to execute our strategic plan. Finally, commodity price strength and operational success will increase the momentum as we exit 2009 and expect our 2010 capital budget to increase over 2009 levels. At this time, we would like to begin the question and answer portion of our presentation.

(Operator Instructions) Your first question comes from the line of Leo Mariani with RBC.

Good morning, guys. Just curious here as to the decision to go out in joint venture 26,000 acres you talked about having a bigger position that gets roughly 90,000 acres perspective, just curious as to how you got the decision to get out there and do a portion of this versus doing a bigger piece?

That's a good question. Clearly we do have a very significant acreage position in south Texas, both the Olmos sand perspectively as well as the Eagle Ford shale. The Eagle Ford shale, as you well know, is quite a homogeneous type of resource play. Even then, there are sweet spots in this play through the drilling programs going on now and will go on in to the next year folks are going to find nice places to drill out there and some areas that maybe aren't as good as others. We decided it was strategically important for us to accelerate our drilling in this play and to go in to the play with a partner that we thought would bring exceptional technical expertise to us that had already been a well respected shale player. As to why we ended up with just 26,000 acres, we do want to keep a bunch of it for ourselves. We felt strategically this was the right type of deal and worked well with our partner. We got acreage in and around it that's 100%. We got acreage in parts of the play that's 100% . We are looking forward to working with Petrohawk on this 26,000 aches and teaming up with their technical expertise and expanding beyond this play area where we done

Okay. Are there any other sort of significant terms for JV like maximum or minimum wells that get drilled in a year and I guess this 100% sort of 50-50 JV where either of you has the right to propose a well?

We each have the right to propose a well. There is no minimum or maximum. We do have one obligation well that has to be drilled. We are in the planning mode to begin that well here within the next 30 to 60 days. So -- but each party has a right to propose wells. We spent a lot of time working through the agreement terms on both sides and we think we ended up with a very good agreement.

Okay. Any estimate in terms of [AFB] for that first well out that, what it might cost you?

We going to hold back on some of that information until we actually get the first well spuded. I think it should be clear that the first several wells in here, we are going to conduct some more science, get some core data that's not present in the area because we want to optimize the results out here and Petrohawk has worked closely with us on the science side. We are in complete agreement that the first couple of wells probably be little more expensive than the most subsequently come forward.

Clearly we are going to drill a pilot hole and take cores, run a full sweet of logs to understand the geology better. I think if you look at what Petrohawk is doing in the hawk field, the reason they are interested in our acreage is they believe, and we believe too, that same trend runs right underneath AWP. Over on the other side if you look at the Pioneer well, we are smack in the middle between Pioneer well and what Petrohawk has been doing. We would fully expect looking at Petrohawk's experience and our experience at driving the cost down in the Olmos horizontal drilling that you will drive the costs down as you start doing repetitive drilling.

Okay. Jumping over to the Olmos program, it looks like you guys had some pretty successful shallow oil wells up there. Trying to get a sense of what you may have remaining kind of up there in inventory on the oil side.

We clearly have several more to drill up there in terms of vertical wells. We are contemplating drilling couple of horizon wells in that area. We think vertical wells can recover 70,000 to 80,000 barrels. We think horizon wells can do better. We still have some running room that will go in to next year in that program.

Okay. What do those vertical oil wells cost you guys to drill up there?

They are AFE is about 1.1 to 1.2. We are seeing very good drilling performance. We think we can go down from there.

Okay, thanks, guys.

Your next question comes from the line of Ken Carroll with Johnson Rice.

Good morning. Hoping to get a little more color on the two new horizontal Olmos wells, particularly the 34H, it seems to be a pretty quick decline down to the 1.8 million a day, you talk about it being stabilized. How long has the well been on and stabilized at the 1.8 million day rate?

The well I don't have the exact date when that well came on. August I guess or something like that. It's been on for a couple of months. It actually started turning hyperbolic fairly rapidly and you have to remember that what we are doing is we are really stepping out in to south and the southwestern parts of our field. We are spacing wells out strategically to understand the deposition I think as I mentioned in the 36H we drilled a vertical well pilot hole and cut two cores, we want to study those cores. We clearly see the Olmos out here, we see porosity development, maybe some deposition changes going on we need to understand better. We are going to learn from these cores and then we are going to optimize our completion design around the study work over the cores and prepare an optimal program going forward from here.

In terms of 35H, pretty solid rate in terms of the IP rate, very high pressure on that well. Post the mechanical issues and clean up, seem to be much lower pressure. Can you put color on that? What is going on with that change in pressure?

We don't fully know. It's very early in that well. When we went in with coil tubing we did find sand at the curb of the well, that's the first time we had seen sand in the well bore like that. We got that sand cleaned out and had pressure right behind it. We still don't know if the entire horizon lateral has opened up. We still have to do some investigation work on that lateral to see if we have some other sanding problems in there. It's still a little early to speculate there.

Appreciate it, thank you.

(Operator Instructions) Your next question comes from the line of [Brian] (Inaudible) with (inaudible).

Good morning, guys. When you look at your Eagle Ford program in 2010, can you put a range as to how many wells you think you can drill on your own or with the JV?

Well we actually won't come out with out with our complete budget and presentations until the February analyst meetings where we go through all that in detail. We are clearly looking at that. Within the venture in AWP with Petrohawk, we expect for rig to continue to run all year drilling Eagle Ford wells in that venture. There maybe a slow down initially between the first couple of wells in order to get some good data, and we will be spotting those wells across the acreage, it's a big position. We will have those first several wells be more like appraisal wells before we go in to what we hope to be a manufacturing mode. But I think it's reasonable to expect a rig to run in there all year.

Additionally, I think in our other Eagle Ford positions you will see us stepping around the play as we noted several of the positions we think are extremely highly perspective, and then there are some other areas we are looking at drilling of others, we may stay away from that and watch the results of others before we move in to there, but you could expect us maybe have a rig running in other parts of our acreage throughout all 2010. We could easily be moving that rig between Olmos and Eagle Ford, you are not going to distinct wish much between that. One of the real advantages of AWP is you are tied right into the market to you can get stuff on production immediately. Some areas have more gas marketing and distribution issues and you will need to both evaluate the acreage and understand the performance that you can get and then deal with market access. Sometimes that takes a little time so you want to do drill a bunch of wells and keep them shut in.

Okay. The right way to think about it though is you guys probably have won horizon rig that you guys are operating in south Texas next year?

Likely to have one horizon drill, one horizon drilling well drilling program on 100% swift acreage whether it be Olmos or Eagle Ford.

Okay. Perfect. When I look at the oil program that you guys are talking about here, help me understand this is just the northern most part of your AWP acreage and how large is the acreage position that has oil potential?

Well, I mean the whole northern part of AWP historically has been more oily, as you move in to the central and southern part of AWP it's more gassy. This is an area that we actually acquired acreage position here a year or so back that we are drilling on now. We've drilled a lot of our northern AWP acreage, per se. Now we are going in to new acreage positions up in the north and applying the same concept. We are using some of our 3D survey data and attribute analysis to help us high grade where to drill these vertical wells in the extential area. We are talking I guess in the range of 3,000 to 5,000 acres immediately that we are looking at in this drilling program.

There is also some acres we developed back the 1990s with vertical wells that have a high liquid content. They were developed with smaller holes using slim hole drilling techniques back at the time but because of the high liquid nature we had some lift issues. One of the things we are going to evaluate is there there is sufficient remaining reserves to go back in and exploit them differently than the way you would do it today. That is something we have under evaluation.

Yes, just a little more texture on Bob's comment about the acreage that we think is perspective of shallow oil wells. We do have a 3D in that area we reprocessed and looked at in great detail. We believe there will be additional 3D shot out there next year, the Olmos sand in that area does have stratigraphy issues. It's not like drilling for the Eagle Ford shale, so we are going to definitely rely on some of the 3D work we done to maximize how we exploit those acres.

Then just moving to south Louisiana, I wanted to, one, make sure I heard your Lake Washington production number right at 10,100 barrels a day. Is that correct?

Yes, that's a gross number. Gross average.

For the quarter? What was Q2?

I don't have Q2 in from of me. We could get that.

I'm more interested as to where you guys are today, relative to the Q3 number.

I think gross oil productions is above that 10,000 barrel number now. So between 11,000 and 12,000 today I think.

We will come back with an answer to that. Before we leaf the call.

Okay that's perfect. Thanks, guys.

Thanks, Brian.

Your next question comes from the line of Andrew Coleman with UBS.

Couple of questions on Lake Washington there. I was on a bunch of calls this morning, but how many injectors do you guys have down there right now and is that still a program that you guys are working hard on or is most of the incremental production coming from the shallow drilling program right now?

Most is it, Andrew, is coming from the shallow or to mid depth drilling program of 5,000 to 7,000 feet. We have a lot of fault blocks either up dip of known reserves or offset blocks that are in a probable possible category. That's what we are working on right now. In terms of New Port, what I think you are referring to, we still only have the one injector there. We basically have a team breaking that deposition apart. Going in and trying to optimize that before we start water flooding and impacting those wells in an incorrect way. We are still finding recompletion opportunities in individual sand loads that are unswept in that area that are delivering us good production results. Some of the recompletions that we did were over in those New Port wells where we just went to another formation and perforated the unswept loads and got some nice production. So we have to be sure that we get through all of those unswept loads before we start too much more injection. We do have a team that's breaking that all apart and building those sub surface models for when it is time to really come after it harder with injection.

Okay. Scanning through the press release here, moving to as we think about that we are looking at two quarters to get the conclusion of the injection program? Or I guess get in a place where you can review how you would scale that up or something we would hear by year end on?

No. I think we probably need another couple of quarters, we have enough work to do out there with some of these recompletions, some of these individual sand loads that have been unswept but the modeling is going on, so I would say we probably still need a couple of quarters before we have that forward plan totally worked out.

I would add to that that the priority in Lake Washington really came down to what we refer to as our low hanging fruit or our bread and butter. Recompletion program that Bob described while it had a few that were in the New Port area, it really was sprinkled all over the dome and from a capital deployment standpoint it was extremely low cost production add so that's where we focused.

Okay. I didn't see it in release as I am quickly perusing here, but with the south Texas Olmos wells, have you been adjusting the number of frak stages per well in 34, 35, 36 Bracken wells?

We are currently, we are still we have been using the expandable sleeves, we are pretty much limited to nine stages. That's one of the things we're looking pretty hard at. In fact, in this 36H well we are going to go to a cemented liner and do kind of a perp and plug, we are looking at the final how we want to perforate that currently. We are looking at a couple of different completion designs out there now.

Okay. And you are using, is this -- I think we had this discussion in the past where the formation is not nearly as high pressured say in (inaudible) so you don't have to worry about having designer sand in there, is that correct?

We put some resin coating in the tail.

Next question come from the line of Ann Cameron with JPMorgan.

My questions have been answered, thanks.

Final question comes from the line of Ken Carroll with Johnson Rice.

Just one quick follow up in terms of the Bracken 33H and you (inaudible) towards the higher end of that 35 DCF range, can you talk about where that well is producing today and how that curve is looking?

Yes, that well is behaving very nicely. It's very flattened out . It's producing at 1.8 million cubic feet a day, about

Okay. Very good. Appreciate it, guys.

This is Bruce. Let me follow up on the earlier question from Brian if you are still on the phone, I misspoke earlier when I referred to the 10,112 barrels of oil filled production in Lake Washington, that's a net number, not a gross number, and that's equivalent, oil and gas on equivalent basis. Comparable number today is slightly above that, more like 10,250 or so approximately.

I think our Q2 number there was about 9,976 with that in context.

Okay. I guess we are ready on conclude our conference call for the third quarter. We appreciate your tuning in with us and look forward to getting back to you after the fourth quarter.

Thank you. This concludes today's conference call. You may now disconnect.