Swift Energy Co. Q3 2009 Earnings Call Transcript

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Swift Energy Co. (SFY) Q3 2009 Earnings Call November 3, 2009 10:00 AM ET


Paul Vincent - Manager of Investor Relations

Terry Swift - Chairman and CEO

Alton Heckaman - EVP and CFO

Bruce Vincent - President

Bob Banks - EVP and COO


Leo Mariani - RBC

Ken Carroll - Johnson Rice

Andrew Coleman - UBS


Good morning. My name is Latangia and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy third quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions). Thank you.

I would now like to turn the conference over to Mr. Paul Vincent. Please go ahead, sir.

Paul Vincent

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 Q3, and then Bruce Vincent, President and Bob banks, EVP and COO, will provide an operational update. Terry Swift will 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 current assumptions, estimates and projections about us, our industry and the current environment in which we operate.

These statements involve risks and uncertainties detailed in our SEC reports. To which we refer you along with cautionary statements contained in our press releases and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Terry Swift

Thanks, Paul, and thank you 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 programs 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 program in the Olmos formation of the AWP field in South Texas resumed in third quarter. We’ve also begun a vertical drilling program targeting oil formations in the northern portion of AWP as well as a fracture stimulation program designed to improve the performance of existing productive well bores. In 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 affective tax rate during the quarter. Alton will discuss these items in further detail in a few moments.

Finally, as of yesterday, we entered in to a join venture agreement in South Texas to exploit and develop the Eagle Ford shale. This particular transaction is very strategic for us. We’ve 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 the oil 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’ve built a large inventory of projects in our core areas. These protects include oil and natural gas opportunities in and around order salt domes in South Louisiana, horizontal drilling opportunities in both shale and tight gas sand formations in South Texas, as well as Austin Chalk opportunities in Central Louisiana and East Texas.

During the quarter, we continued to witness oil field service cost moderate relative to hydrocarbon prices. 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 do 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, and 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 have protected a portion of our first and second quarter natural gas pricing through our price risk management program, and we are prepared to predict additional volumes into 2010 as the opportunity arises.

We are prepared, should the operating and pricing environment deteriorate, 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 our operating activity in a few moments, but first I would like to review some of the highlights of the quarter and commend everyone involved with the organization for their capital discipline and 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 have performed well. The initial flush oil production averaged over 2,500 gross barrels of oil per day after the start up of these facilities.

Field-wide crude oil production over the last seven days has averaged about 1,100 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 in 2010 in Bay de Chene.

Our production optimization and recompletion program in Lake Washington field continued to deliver excellent results. While they types of projects may not be as exciting as the higher risk ones, they’ve 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.

At South Texas we resumed our horizontal 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.

The first horizontal well drilled in the Olmos formation late last year was the R Bracken 33H, and it continues to perform well with an 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 type to wells to average a resource potential per well of 3 to 5 Bcf 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’ve analyzed the locations and the results of wells that have been by others in the industry, and we believe our acreage remains highly prospective, 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 into 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 we’ll be cautious as we increase activity levels in the fourth quarter of 2009 and into 2010.

With that, I’ll ask Alton to present the third quarter 2009 financial results.

Alton Heckaman

Thanks, Terry, and good morning. The oil and gas sector continued to experience a lull, 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 3Q ‘08, but up 16% sequentially. Our income from continuing operations was $7.6 million or $0.21 per diluted share, down from 3Q ‘08 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 3Q ‘09 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 in 3Q ‘09 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 to approximately $123 per barrel a year ago along with natural gas prices declining to an average of $3 per Mcf compared to $10 per Mcf in 2008, resulting in a decrease in quarterly oil and gas revenues of 54% when compared to 3Q ‘08.

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’d like to point out regarding our crude oil prices received during 3Q ‘09, that the relative 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 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 ‘09 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 more detailed information on the fourth quarter and full-year estimated effective tax rates.

Cash flow before working capital changes for 3Q ‘09 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 offering in our company’s 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 ‘09. With respect to our line of credit facility with our 10-member bank group that currently runs through October 2011, our borrowing base and commitment amount will reaffirm to $300 million on November 1 2009.

We are very pleased with the steps we’ve 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’ve identified several cost-saving opportunities in each of our core areas.

We also are working closely with all vendors for additional cost savings from 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 into 2010. With respect to Swift’s hedging activity, we purchased floors covering a meaningful percentage of our domestic natural gas production for both, the first and second quarters of 2010 at an average NYMEX strike price of $4.73 per MMBtu.

Please see our website for complete and current detailed hedging information. As always, we’ve included additional 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’ve all experienced. We’ve been through these cycles before and we’re ready for the challenge. With that I will turn it over to Bruce Vincent for an overview of our operation.

Bruce Vincent

Today, now I’ll 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 of 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 of billion cubic feet equivalent, that was approximately a120,000 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 workover 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 downtime from shutting 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 of 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 continued drilling in the Olmos in the fourth 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 the 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 approximately 81 million cubic feet equivalent per day in this area, an increase of 2% compared 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 equivalent per day, a slight increase when compared to the second quarter 2009 volumes. Bay de Chene’s sequential production increase of 8% to 3336 net barrels of oil equivalent per day or 20 million cubic feet equivalent per day is primarily due to the restoration of oil production which had been shut in as a result of damage caused by hurricane Gustav.

Initial crude oil production averaged approximately 2590 gross barrels of oil per day, that along with the natural gas production of 20.4 million cubic feet a day over the first 7 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 has averaged approximately 1100 gross barrels of oil per day and 17.1 million cubic feet per day of natural gas. No new drilling activity occurred in Bay de Chene this year. In our South Texas core area, which includes our AWP, SunTSH, Briscoe Ranch and Las Tiendas fields, third quarter 2009 production averaged 6982 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 horizontal well were completed in the Olmos formation during the third thinker. 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. We’ll have Bob discuss this further 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 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 refrac program in the field. Bob will also discuss these programs in more detail. Finally, we announced yesterday a joint venture agreement with 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 the 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 the 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 amounts to cover drilling and completion cost of horizontal wells targeting the 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’ve entered the production phase, subject of course to the terms of the agreement.

The company is also planning to spud a horizontal 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 core area, which includes our Brookeland, Masters Creek and South Bearhead Creek fields, contributed 2,244 barrels of oil equivalent per day or about 13.5 million cubic feet equivalent per day of our production in the third thinker 2009. There was no significant operational activity in this area during the Q3.

In our South Louisiana core area, which is comprised of Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island and Bayou Penchant, production averaged approximately 1,553 barrels of oil equivalent per day or about 9.3 million 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 now turn the call over to Bob Banks, our Chief Operating Officer to review some of the more notable activity during the quarter.

Bob Banks

Thanks, Bruce. At our Lake Washington fields, the CM 400 and CM 403, both of which finished drilling early in the fourth quarter. The CM 00 was drilled to a measured depth of 6,023 feet, and encountered 31 feet of true vertical net pay. The CM 403 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 into 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 an inventory of both 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 to 5 billion cubic feet equivalent estimate.

The initial production rate for the R Bracken 34H was 5.7 million cubic feet per day with flowing tubing pressure of 2,175 PSI on a 36/64-inch choke. The production decline in this well has already turned hyperbolic and production has stabilized at the current production rate of approximately 1.8 million cubic feet per day.

The initial production rate of the R Bracken 34H well was 4.6 million cubic feet equivalent per day with a flowing tubing pressure of 4,200 PSI on 14/64-inch choke. Mechanical difficulties developed very early within five days of the startup of this flowback, and the well was plugged off by sand in the wellbore.

We’ve subsequently gone in and cleaned out the wellbore and are slowly bringing that well back on at a rate of 2.3 million cubic feet per day with flowing tubing pressure of 1,900 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 petrophysical properties to logs, and to be 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 horizontal 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 horizontal 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 further 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 further 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, Quintanilla #2 and #3, began drilling in the third quarter and recently concluded drilling operations. Quintanilla #2 tested about 200 barrel 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 fractured after it is connected to the production facilities.

Finally, we have identified an 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 additional fracture stimulation. 11 of these identified wells have been fracture stimulated since the beginning of September and results have encouraged us to continue on with this program.

While no one operation will be meaningful when compared to our overall production profile, 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 these vertical wells in the field.

We believe that 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 into 2010. In total, we still expect our current activity levels to support a daily production rate of between 24,000 net barrels 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.

Terry Swift

Thanks, Bob. Before we open the line for questions, I want to summarize Swift Energy’s third quarter results. To review some of the highlights from today, our Bay de Chene crude oil facility startup and our production enhancement and recompletion program performed better than expected contributing to better than guided operational performance.

We currently have one rig drilling wells in Lake Washington, one rig drilling horizontally in the Olmos at AWP and one rig drilling vertical oil targets in AWP. We recently entered into a joint venture agreement to accelerate the development of a portion of our AWP acreage believed be prospective for the Eagle Ford Shale.

We plan to spud a horizontal Eagle Ford 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 we 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.

Question-and-Answer Session


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

Leo Mariani - RBC

Curious here as to while you got the decision to go out and JV 26,000 acres, you had talked about having a bigger position, roughly 90,000 acres that are prospective, just curious as to how you got the decision to get out there and just do a portion of this versus doing a bigger piece.

Terry Swift

Clearly, we do have a very significant acreage position in South Texas, both for the Olmos and prospectively as well as the Eagle Ford Shale. The Eagle Ford Shale is a homogeneous type of resource play, but even then there are sweet spots in this play and through the drilling programs that are going on now and will go on into the next year, folks are going to find some really nice places to drill out there and some areas that maybe aren’t as good as others. We decided that was strategically important for us to accelerate our drilling in this play and to go into the play with a partner that we thought would bring exceptional technical expertise to us as it had already had 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 that strategically this was the right type of deal, it worked well with out partner. We’ve got acreage in and around it, that’s a 100%. We got acreage in other parts of the play, that’s a 100% . We are looking forward to with Petrohawk on this 26,000 acres and teaming up with their technical expertise and expanding then expanding beyond this play area where we’ve done the deal.

Leo Mariani - RBC

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

Terry Swift

Yes, we each 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. Each party has a right to propose wells. We spend a lot of time working through the agreement terms on both sides and we think we’ve ended up with a very good agreement.

Leo Mariani - RBC

Any estimate in terms of ASPs for that first well out there and what it might cost you.

Terry Swift

We going to hold back on some of that information until we actually get the first well spudded. 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 will probably be a little more expensive than the most that subsequently come forward.

Bruce Vincent

Clearly, initially we are going to drill a pilot hole, we are going to take cores, and we’re going to run a full suite of logs to understand the geology better. If you look at what Petrohawk is doing in the Hawkville field. The reason they are interested in our acreage is they believe and we believe too that the same trend runs wide underneath AWP. If you run the other side, if you look at the Pioneer well, we are right smack in the middle between the Pioneer well and what the Petrohawk has been doing. We would fully expect both, looking at Petrohawk’s experience and our experience at driving the cost down in the Olmos horizontal drilling, it should drive those cost down as you start doing repetitive drop drilling.

Leo Mariani - RBC

Jumping over to the Olmos program, you guys have pretty successful shallow oil wells up there. Trying to a get a sense of what you may have remaining up there in the inventory on the oil side?

Terry Swift

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

Leo Mariani - RBC

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

Bob Banks

Their area feed is at about 1.1 to 1.2. We are seeing very good drilling performance. We think we can go down from there.


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

Ken Carroll - Johnson Rice

Can you give a little more color on the two now horizontal Olmos well, particularly the 34H, it seems to be a pretty quick decline down to that 1.8 million a day, you talk about it being stabilized. How long has that well been on? How long has it been kind of stabilized at the 1.8 million day rate.

Terry Swift

I don’t have the exact date when the well came on. It was about August, 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 into the 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, a pilot hole and cut two cores, we want to study those cores. We clearly see the Olmos out here, we porosity development. There maybe some depositional changes going on that we need to understand better, but 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.

Ken Carroll - Johnson Rice

In terms of the 35H, a pretty solid rate in terms of the IP rate, a very high pressure on that well and then post the mechanical issues and clean up, there seems to be at much lower pressure. Can you put a little color on that with what’s going on with that change in pressure (inaudible)?

Bob Banks

We don’t fully know. It’s very early in that well. When we went in with coiled tubing, we did find sands at the curve of the well. That’s the first time that we had seen sand in the well bore like that. We got that sand cleaned out and we 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 other sanding problems in there. It’s still a little early to speculate there.


(Operator Instructions). Your next question comes from the line of (inaudible).

Unidentified Analyst

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

Terry Swift

We actually won’t come out with our complete budget and presentations until the February analyst meeting, and that’s where we go through all that in detail. However, we are clearly looking at that. Within the venture in AWP with Petrohawk, we do expect the rig to continue to run all year drilling Eagle Ford wells in that venture.

There maybe a slowdown 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, so we’ll have those first several wells be more like appraisal wells before we go in to what we hope to be a manufacturing mode. I think it’s reasonable to expect a rig to running there all year.

Additionally, I think I our other Eagle Ford positions, you’ll see us stepping around the play. As we’ve noted, several of the positions we think are extremely highly prospective, and then there is some other areas we are looking at drilling of others, and we may stay away from that and watch the results of others before we move in there. You could expect us to maybe have a rig running in the other parts of our acreage throughout all 2010.

Bruce Vincent

Yes, but we could easily be moving that rig back and forth between Olmos and Eagle Ford. You are not going to distinguish much between that. One of the real advantages of AWP is you are tied right into the market so you can get stuff on production immediately. Some areas have more gas marketing and distribution issues, and so you’ll 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 so don’t want to drill a bunch of wells and keep them shut-in.

Unidentified Analyst

The right way to think about it though is, you guys should probably have at most one horizontal rig that you guys are operating in South Texas next year?

Terry Swift

We are likely to have one horizontal well drilling program that is on 100% Swift acreage, whether it is Olmos or Eagle Ford, other rig on the joint venture acreage.

Unidentified Analyst

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

Bob Banks

The whole northern part of AWP historically has been more oily as you move into 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. So, 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 existential 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.

Bruce Vincent

There are also some acres we developed in the 90s 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’ve had some lift issues. One of the things we are going to evaluate is whether there are sufficient remaining reserves to go back in and exploit them really differently the way you would do it today. We are not starting that program but that is something we have under evaluation.

Terry Swift

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

Unidentified Analyst

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?

Terry Swift

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

Unidentified Analyst

For the quarter. What did that compare with Q2?

Terry Swift

I don’t have Q2 in from of me, but we can get that.

Unidentified Analyst

I’m more interested as to where you guys are today relative to the Q3 number?

Terry Swift

I think the gross oil production is above that 10,000 barrel number now. It’s between 11 and 12 today. We will come back with an answer to before we leave the call.


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

Andrew Coleman - UBS

I had a couple of questions on Lake Washington. How many [injectors] do you guys have down there right now? Is that still a program that you guys are working hard on or is most of the production coming from shallow drilling program right now?

Bob Banks

Most of that Andrew is coming from the shallow to mid-depth drilling program, the 5,000 to 7,000 foot. We still have a lot of fault blocks it’s either up the depth 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 Newport, which I think what 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. So, we are still finding recompletion opportunities in individual sand lobes that are un-swept in that area that are delivering us some good production results. In fact, some of the recompletions that we did were over in those Newport wells where we just went to another formation and perforated the un-swept lobes and got some nice production.

So, we have to be sure that we get through all of those un-swept lobes before we start too much more injection. However, 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.

Andrew Coleman - UBS

I’m scanning through the press release here, but I guess as you think about that then we are probably looking at about two quarters to get a conclusion of the injection program. Or I guess getting to a place where you can get a view on how you can scale that up or you think something we would hear by year end on?

Bob Banks

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 the individual sand lobes that have been un-swept, 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.

Terry Swift

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. The recompletion program that Bob described, while it did had a few that were in the Newport area, it really was sprinkled all over the dome, and from a capital deployment standpoint, it was extremely low cost production adds, so that’s where we are focused.

Andrew Coleman - UBS

I didn’t see it in the release and I’m quickly perusing here, but with the South Texas, Olmos wells, have you been adjusting the number of frac stages per well in the 34, 35, 36 Bracken wells?

Bob Banks

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

Andrew Coleman - UBS

They are using this resin coated sand, and I think we’ve had this discussion in the past where the formation is not nearly as high pressured say potentially around the (inaudible) to worry about having designer sand in there. Is that correct?

Bob Banks

Right. We do put some resin-coated in the tail.


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

Ken Carroll - Johnson Rice

In terms of the Bracken 33H and your are comfortable now that it’s towards the higher end of that 35 Bcf range. Can you talk about what that well is producing today and how that curve is looking?

Bob Banks

That well is behaving very nicely. It’s very flattened out. It’s producing at about 1.8 million cubic feet a day, about 900 pounds.

Bruce Vincent

Let me follow-up on the earlier question from [Brian] if you are still on the phone. I’d misspoken earlier when I referred to the 10,112 barrels of oil field production in Lake Washington, that’s a net number, not a gross number, and that’s an equivalent number, so that’s oil and gas on an equivalent basis. Comparable number today is just slightly above that, more like about 10,250 or so approximately.

Terry Swift

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

Bruce Vincent

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

Terry Swift



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

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