Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Executives

Paul Vincent – Director, Financial and Investor Relations

Terry Swift – Chairman and CEO

Alton Heckaman – EVP and Chief Financial Officer

Bruce Vincent – President

Bob Banks – EVP and Chief Operating Officer

Mike Kitterman – SVP, Operations

Analysts

Leo Mariani – RBC Capital

Jason Wangler – Wunderlich Securities

Michael Hall – Wells Fargo

Anne Cameron – J.P. Morgan

Adam Leight – RBC Capital Markets

Derrick Whitfield – Canaccord

Ray Deacon – Pritchard

Swift Energy Co. (SFY) Q2 2010 Earnings Call August 5, 2010 10:00 AM ET

Operator

Good morning. My name is Christy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Second 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. Please go ahead, sir.

Paul Vincent

Good morning. I am Paul Vincent, Director of Finance and Investor Relations. Id like to welcome everyone to Swift Energys second quarter 2010 earnings conference call. On todays call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, EVP and CFO will review the financial results for the second 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 [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, and projections about us, our industry, and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports to which we refer you along with cautionary statements contained in our press releases and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Terry Swift

Thanks, Paul. And thanks to everyone listening in for and joining our conference call today. We recognize that the most important aspect of developing our assets is execution and weve approached our development of the Olmos and Eagle Ford formations with this in mind.

To prepare our organization for rapid expansion, our plans have included securing acreage, ensuring access to infrastructure, water, tubular goods, and drilling and completion services, as well as testing our various acreage positions. Weve executed on this plan and met most -- met or exceeded most of our milestones along the way.

During the first and second quarters, the industry ramped up activity in South Texas resulting in a shortage of certain critical services, such as fracture stimulation services. As a result, many our original completion time schedules were delayed.

While we were disappointed that our original completion target dates were delayed, were very encouraged by actual drilling and testing results, and our new arrangement with a large oil field service provider. We have secured a dedicated frac spread and crew for the next 24 months through an exclusive strategic agreement.

This agreement should help to reduce uncertainty and risk to our production schedule and was a natural step towards consistent predictable execution of our plans. With multi-year certainty on completion scheduling, we can move effectively to execute on production reserves and cash flow growth objectives.

In addition to securing long-term completion services, weve added a third high horsepower rig to drill horizontal Eagle Ford and a lower horsepower [Technical Difficulty] low portion oil wells in the Olmos formation north of our AWP acreage in McMullen County.

We also now have an oil field tubulars goods alliance in place and have developed an extensive water production, management and disposal system that will accommodate our increased activity. As we move into a development mode, all of these planning components are necessary to increase our activity levels and deal with the various bottlenecks that are presented by the increased activity in the industry.

We are also driving better execution through improved performance. We have established new Swift Energy technical drilling limits on -- of 21 days in the Eagle Ford Shale and 16 days in the Olmos. Both of these limits were established on wells which created at over 15,000 feet measured depth.

Also, in the Olmos, we broke our service providers global record by drilling 9,569 feet in one continuous run with the PDC Bit at a rotary steerable assembly on the AFP 3H well. This broke the previous record which was set on the AFP 2H well where 9,421 feet was drilled in one continuous run with a PDC Bit and rotary steerable assembly. Were proud of the teams involved with these projects as they truly represent the spirit of continuous improvement which we embrace at Swift Energy.

We have now drilled and completed four operated and one non-operated Eagle Ford well with average initial test rates of 1,152 barrels of oil equivalent per day and with approximately 40% of initial production volumes being oil.

In total, weve now drilled and completed seven Olmos horizontal wells. The average initial production rate of these wells has been 1,248 barrels of oil per day consisting of approximately 35% liquids, most of which are natural gas liquids. These tests continue to derisk our acreage perspective for these plays in South Texas.

With current liquid prices materially higher than gas prices, we are directing more of our activity towards higher liquid yield areas. Gas versus oil volume equivalent is traditionally reported using a 6/1 ratio. However, current market pricing comparisons reflect a 17/1 ratio. Our higher liquid field areas provide slightly lower equivalent volume production rates but much higher value equivalents when compared with the dry gas activities.

Weve added two drilling rigs and a dedicated fracture enhancement crew in South Texas, which will result in increased activity targeted towards growing oil and natural gas liquids production. With these increased activity levels and our recently contracted and dedicated fracture stimulation services, we now expect our daily production rate to increase to a range of 28,000 to 30,000 barrels of oil equivalent by year end. We also expect our proven reserves to increase by 15% to 20% over year end 2009 levels, which is up from our previous guidance of 8% to 12% growth.

Our increased focus on lower rate a higher value liquids production in conjunction with the completion delays in the second and third quarters will result in full year production expectations of 8.85 to 9.15 million barrels of oil equivalent. Bruce and Bob will detail all of our operational activities and results in a few minutes.

But first, Ill review some of the highlights of the quarter, which include the Swift operated Hayes 1H and the [SMR 1H] Eagle Ford wells. The Hayes 1H, with only seven stage fracture stimulation, tested at a rate of 336 barrels of oil per day and 0.5 million cubic feet of natural gas. This wells fracture stimulation was not as effective as we believe it could have been and only seven of nine stages were actually fracture stimulated.

However, having looked at the log and the drilling records on this well, we were impressed by what we saw and we believe that other wells in this area can produce at much higher rates as we advance our program. We will continue to drill wells in this area and believe that more effective fracture stimulations can easily be achieved. The SMR 1H with a 12 stage fracture stimulation, tested at 775 barrels per day and 1.1 million cubic feet per day of natural gas. These tests continue to derisk our acreage in McMullen County.

In the Olmos formation, the Huff 1H was drilled to test existing draining assumptions of our developed acreage. This wells initial production rate of 5.4 million cubic feet per day has proven that we have further infill drilling opportunities on acreage within the AWP field, which weve been developing for over 20 years.

The AFP 2H, another Olmos test was drilled on undeveloped acreage south of our AWP field. Only eight of 14 planned stages were fracture stimulated in this well due to a potential communication problem with a well the Swift was operating and being -- and drilling nearby. This is another example of how our technical teams from our completion teams to our drilling teams work together across these disciplines and understanding operational risks before anything might happen and have various planning contingencies in place.

As a result of preparing for this possibility ahead of time, we will be able to go back into this well and pump an additional six stages that werent stimulated in this well. In spite of this perspective issue, the AFP 2H flowed back with an initial production rate of 6.4 million cubic feet a day and 51 barrels of condensate per day and flowing casing pressure of 4,451 psi on a 19/64-inch choke. This was an excellent example of infill potential in the AWP field and has additional potential behind pipes still in it.

In Southeast Louisiana at Lake Washington, we drilled and completed three wells during the quarter and continued our Lake Washington production maintenance program. We are launching an ultra shallow drilling schedule during the third quarter and may begin drilling a deeper exploitation target before the year is over. Lake Washington continues to be an amazing asset and generates much of the cash flow were using to grow other operating areas.

Finally in our East Texas/Central Louisiana area, the first well targeting the Austin Chalk in our joint venture area in the Burr Ferry Field is currently drilling. We are also preparing to drill a Swift operated Austin Chalk well in the Brookeland Field of East Texas during the second half of the year.

Strategically and financially, we are positioned to not only execute our own program but to expand our presence in all of our core areas as a partner of choice. We are actively pursuing opportunities to work with other exceptional operators to exploit additional prospects in our portfolio. We also expect to benefit from opportunities that arise from operators who did not plan correctly and have entered the plays in South Texas without the necessary scale and equipment dedication to execute their strategies.

And now, Ill ask Alton to present the second quarter 2010 financial results.

Alton Heckaman

Thank you, Terry, and good morning, everyone. Having balance in our portfolio has again served Swift well during the second quarter 2010. Our financial results for the quarter reflect this. Oil and gas sales excluding hedging effects were $105 million, a 27% increase over 2Q 09.

Our income from continuing operations was $12.5 million or $0.32 per diluted share exceeding current first call mean estimate. Cash flow, before working capital changes came into the quarter at $1.72 per diluted share and 2Q 10 production down from prior year and prior quarter levels came in just below our guidance at 2.03 million barrels of oil equivalent, as Terry explained, resulting in earnings for 2Q 10 being up substantially from prior year.

Crude oil prices came in 40% higher than prior year levels while NGL and natural gas prices were 48% and 19% higher, respectively, leading to an overall 41% higher price per Boe.

Swifts average realized price in 2Q 10 thus increased to almost $52 per Boe due primarily to crude oil averaging approximately $78 per barrel for the quarter, compared to $55 per barrel in the second quarter 2009, allowing Swift to increase its quarterly oil and gas revenues 27% over the second quarter of 2009.

As to our operating costs and metrics, G&A came in at $3.96 per barrel, favorably below guidance. DD&A came in at $19.24 per Boe within our guidance. Production costs came in within guidance at $9.83 per barrel. Interest expense was $4.05 per barrel on the high side of guidance and production and ad valorem taxes came in within our guidance at 11.1% of oil and gas revenues. The result was income from continuing operations for the quarter of $12.5 million, which is $0.32 per share both basic and diluted.

Our effective income tax rate this quarter of 34.4% is favorable to guidance. Therefore cash flow before working capital changes for 2Q 10 came in at $66 million or $1.72 per diluted share, while EBITDA was $67 million for the quarter and our quarterly CapEx on a cash flow basis was $66 million.

Let me spend just a moment to highlight Swifts solid continued financial position. As of the end of the second quarter 2010 we had no outstanding borrowings under our line of credit. With respect to this facility with our 10 member bank group that currently runs through October 2011, our borrowing base has reaffirmed this past spring remains at $278 million. With our strong balance sheet Swift is well positioned to fund our 2010 CapEx budget and implement our strategy.

Well spend a minute with respect to Swifts hedging activity. We currently have repurchased floors covering approximately 35% of our natural gas production for third quarter 2010 at an average NYMEX strike price of approximately $4.75 for MMBtu of gas. Company also purchased crude oil floors with a $79.50 strike price covering approximately 5% of its third quarter production. Please see our website for complete and current detailed hedging information.

As always, we have included additional financial and operational information in our press release including initial guidance for the third quarter and the revised full year 2010. Swift is well positioned financially to take advantage of the opportunities that are in front of us and we have the strength and flexibility to handle any price volatility which seems to have become the norm for our industry.

With that, Ill turn it over to Bruce Vincent for an overview of our operations.

Bruce Vincent

Thanks, Alton, and good morning, everyone. We certainly appreciate everybody listening in this morning. Today, Im going to review the second quarter 2010 activity including our production volumes, our recent drilling results, activity in our core operating areas and plans for the third quarter 2010, and well have Bob Banks discuss significant operational activity in the quarter and its effect on the rest of the year.

Lets begin with production. Swift Energys production during the second quarter of 2010 totaled 2.03 million barrels of oil equivalent or 12.17 billion cubic feet equivalent, a decrease of 2% from the 2.04 million barrels of oil equivalent produced in the first quarter of 2010.

As Terry mentioned, we did experience delays in bringing new wells in South Texas online due to exceptionally tight operational schedules of the service providers in the area. This resulted in second quarter production slightly below our previously guided range.

We believe that many of our competitors and partners in the industry were also affected by these same scheduling delays. Swift Energy has responded to this situation, though, by entering a long-term strategic alliance with a large oil field service provider to secure dedicated equipment, dedicated crew, for our projects, which will help us contain service cost inflation but also bring about improved efficiencies and timing and ultimately drive our costs down. Bob will discuss this alliance really in greater detail in a few minutes.

Second quarter production when compared to the second quarter of 2009 production of 2.26 million barrels of oil equivalent decreased 11%. The year-over-year declines result primarily from the reduced spending and activity levels throughout last year also fracture enhancement and completion delays in South Texas and of course, natural declines. For the third quarter of 2010 we expect production to increase only slightly as our completion activity will remain limited really until late in the quarter and moving into the fourth quarter.

For our second quarter drilling results Swift Energy successfully drilled all nine it’s operated wells during the quarter and also participated in two successful non-operated wells. Four operated horizontal wells were drilled in the Eagle Ford Shale, two operated horizontal were drilled in the Olmos tight sand formation and two non-operated horizontal wells were drilled in the Eagle Ford Shale by our partner. All of these wells were drilled in McMullen County in South Texas.

Three rigs capable of drilling horizontal wells in the Eagle Ford Shale and our Olmos are currently active in South Texas with our principle focus being the Eagle Ford. Two lower cost rigs are also active in the area. One of these lower cost rigs is drilling surface oils for our horizontal locations while the other is drilling vertical Olmos wells targeting oil.

Additionally, a non-operated rig is currently targeted in the Eagle Ford Shale and our joint venture area. This rig is operated by our partner in McMullen County. Three wells were drilled and completed during the second quarter in the Lake Washington field in Plaquemines Parish, Louisiana. Seven recompletions, four sliding sleeve shift changes and one gas lift modification were also performed at Lake Washington last quarter. There is one barge rig that is currently operating in Lake Washington.

Ill briefly review our activity in each of our core operating areas for the quarter and then let Bob really highlight some details in a few minutes. In the Southeast Louisiana core area which includes Lake Washington and Bay de Chene fields, production during the quarter averaged approximately 10,377 net barrels of oil equivalent per day or about 62 million cubic feet equivalent per day in this area. Thats a slight decrease when compared to the first quarter of 2010 average net production from the same area.

Broken down, though, Lake Washington averaged approximately 8,183 net barrels of oil equivalent per day or about 49 million cubic feet equivalent per day which was an increase of 3% when compared to the first quarter 2010 volumes. This was primarily due to drilling and production maintenance efficiency during the quarter.

Bay de Chenes sequential production actually decreased 12% to 2,195 net barrels of oil equivalent per day or about 13 million cubic feet equivalent per day. This sequential decline is due to the fact we had no new drilling and limited operational activity in the area along with natural declines. Our 2010 operating plans in this quarter include one barge rig maintaining activity in the Lake Washington field.

In our South Texas core area which includes our AWP fields, Sun TSH, Briscoe Ranch, and Las Tiendas fields. Second quarter 2010 production averaged 8,045 net barrels of oil equivalent per day or 48 million cubic feet equivalent, an 8% decrease in production when compared to the first quarter 2010 production in the same area.

To provide perspective on this, this is a 9% increase over the second quarter 2009 production and in July daily production averaged 8,910 net barrels of oil equivalent per day and 11% increase over the average daily second quarter production in the area.

The sequential decrease is a result of delays that affected our completion schedule which prevented us from bringing production online from several wells that were drilled during the quarter. We also experienced several days of heavy rains during the second quarter as a result of Hurricane Alex.

This rain slowed our operations significantly and had a slightly negative effect on production during the quarter but it also contributed to some operational timing delays. As Terry mentioned and Bob will discuss further, weve taken significant steps to ensure that beginning in the fourth quarter, third party equipment and manpower shortages will have fewer adverse effects on our completion schedule for the foreseeable future in this area.

Swift Energy currently has one rig drilling shallow surface oils, one rig drilling vertical oil wells in the northern portion of AWP field and three operated rigs drilling horizontal in the Eagle Ford or Olmos objectives in McMullen and LaSalle counties.

All activity is in areas that we believe will yield oil and liquid rich gas production. One non-operated rig is also drilling in the joint venture area in McMullen County. Bob will spend some time discussing the programs in greater detail.

The Central Louisiana and East Texas core area, which includes our Brookeland and Masters Creek and South Bearhead Creek fields along with South Burr Ferry contributed 1,836 barrels of oil equivalent per day or about 11 million cubic feet equivalent per day of production in the second quarter 2010, which was a 10% increase in production from the first quarter 2010 production. This increase is a result of strong well performance in South Bearhead Creek and eight asset stimulations performed in the quarter in our Brookeland and South Burr Ferry fields.

One non-operated rig is currently drilling a well to the Austin Chalk formation in the South Burr Ferry field. Swift Energy has a 50% working interest in this well. The rig is expected to drill at least one more well in the area after it is finished with the current well.

With regard on our South Louisiana core area which is comprised of Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island and Bayou Penchant. Production averaged approximately 1,875 barrels of oil equivalent per day or about 11 million cubic feet equivalent per day during the second quarter, minimal operational activities expected in this area for the remainder of 2010.

So let me turn it over to Bob Banks to review some operational highlights of the quarter.

Bob Banks

Thank you, Bruce. At our Lake Washington field, we drilled three wells during the second quarter, the CM #411 was drilled to a measured depth of 5,481 feet and encountered 345 feet of true vertical net pay. This well is averaged approximately 590 gross barrels of oil per day over the past 30 days.

The State Lease 212 #178 was drilled to a measured depth of 7,200 feet and encountered 75 feet of true vertical net pay. This well has averaged approximately 200 gross barrels of oil per day over the past 30 days.

The CM #412 was then drilled to a measured depth of 8,178 feet and encountered 267 feet of true vertical pay and this well was recently completed with an initial production rate of 574 gross barrels of oil per day.

Also, during the quarter at Lake Washington field, seven recompletions were performed successfully. Average initial production from these operations was approximately 244 gross barrels of oil equivalent per day. Four sliding sleeve changes were also performed during the quarter.

The average production increase from these operations was 324 barrels of oil per day. Also, one gas lift redesign was performed and production of that well increased from 98 barrels of oil per day up to 315 barrels of oil per day.

Id like to briefly touch on a couple of external events which have affected this area this year before we move on. First, the Deepwater Horizon incident earlier in the year has not had a direct operational impact on Swift Energy, but we do expect there to be derivative effects, particularly in the amount of time it takes to secure permits in our Southeast Louisiana area.

We also expect general interactions with various governmental agencies to take longer in the future than they have in the past as a result of this spill. While we cannot quantify what the effects of increasing permitting times will be, we only expect them to affect our production forecast marginally going forward.

During the third quarter we were affected by Tropical Storm Bonnie. This storms proximity to our operations caused to us shut-in Lake Washington and Bay de Chene for 48 hours. While there were no lasting damages as a result of this storm, we did defer approximately 20,000 barrels equivalent of net production in the third quarter. We will continue drilling shallow wells targeting oil in Lake Washington and will continue our production maintenance and optimization program for the remainder of the year.

Moving down to South Texas at our AWP field, we drilled two horizontal wells in the Olmos formation in McMullen County during the second quarter. The Huff 1H was drilled and completed with an eight stage fracture stimulation. This well was drilled in a developed portion of the AWP Olmos field to test field drainage assumptions and provide the opportunity to drill infill wells in the field in the future. The initial production rate of the Huff 1H was 5.4 million cubic feet per day with flowing casing pressure of 2,700 psi on a 26/64-inch choke.

While this phase of our Olmos development plan will not be a near-term focus, it is important to note that the success of this well does present the opportunity to add production and reserves from portions of our previously developed held by production Olmos acreage sometime in the future.

The second horizontal Olmos well drilled during the quarter was the AFP 2H, which was drilled in 19 days to 15,308 feet on undeveloped acreage to the Olmos formation. During the fracture stimulation of the eight of 14 stages in this well, a Swift Energy well that was drilling nearby observed pressure communication and the stimulation of the AFP 2H was ceased.

The possibility of this occurrence was known and considered before the operation commenced. Our technical teams developed and executed a contingency plan that preserved the integrity of both well operations while maintaining high safety standards.

The well initially flowed back with production of 6.4 million cubic feet per day and 51 barrels of condensate per day with flowing casing pressure at 4,450 psi on a 19/64-inch choke. We will now be able to return back to this well to pump the six remaining stages. Additionally, we have concluded drilling operations on the AFP 3H well and are in the process of drilling the (inaudible) 1H well, both are horizontal wells to the Olmos.

Updating our Eagle Ford activity during the quarter in McMullen County, we drilled four 100% operated horizontal wells. We completed two of these wells during the quarter and are in the process of bringing the other two online. The first well drilled and completed in the quarter was named the Hayes 1H, which was drilled to a TD of 15,304 feet in 21 days. The Hayes well ended up being a calibration well for our program.

First, our fracture stimulation contractor was unable to provide sufficient pumping equipment to pump our 100 barrel per minute frac design. But we elected to go ahead and proceed at a pump rate of approximately 80 to 85 barrels per minute.

Secondly, we decided to increase our fracture stage spacing by about 33% in an attempt to find an optimum spacing for this Eagle Ford reservoir. Third, we did have equipment failure during the job which did not allow us to pump two of the stages in the well.

The second well brought online during the quarter was the San Miguel Ranch 1H which was drilled to 15,210 feet. We executed the 12 stage fracture stimulation on this well. Its initial production rate was 775 gross barrels per day and 1.1 million cubic feet per day with flowing casing pressure of 2,940 psi on a 16/64-inch choke. For the month of July this well averaged 632 gross barrels per day and 0.8 million cubic feet per day.

While drilling this well we also discovered a high quality Olmos sand interval. Were currently drilling two initial vertical wells to test this section and expect to produce oil from these wells. The Discher 1-H drilled to 16,515 feet and the PCQ #4H drilled to 16,449 feet are the third and fourth Eagle Ford wells drilled during the quarter. Both of these wells are expected to be fracture stimulated and online during the month of August.

As mentioned earlier, our production during the quarter was slightly lower than our internal forecast had indicated. This was a result of fracture stimulation service delays that we experienced in South Texas. To illustrate this, we currently have six operated wells that are drilled but not yet fracture stimulated or online. And there are currently three non-operated wells that are of the same status.

We believe that many other operators are contending with similar issues. While this did impact our quarter, we make no excuses and have developed a solution which should provide us a competitive advantage in South Texas. To address the issue we entered into an exclusive and strategic 24-month multi-stage fracture service contract with a larger oil field service company for a new and dedicated frac spreading crew.

This new equipment will be available October 1st, at which time we believe we will be able to fracture stimulate up to four wells per month. Until that time we will be limited to two wells per month using an existing fleet and crew.

This agreement not only ensures that we will have a dedicated crew running on our timeline but that we will be able to budget our costs and manpower demands much more accurately moving forward. Once this program is fully operational at capacity, we should also be in a better position to provide longer term production and reserves guidance.

And then in our joint venture area in McMullen County, our partner drilled the Bracken Family 2H to 18,989 feet and the Bracken Family 3H to 18,936 feet. We are currently fracture stimulating the 3H well and expect to have it online during the month of August. The 2H well will be fracture stimulated at a later date and the fourth well, the (inaudible) 1H has been drilled to TD, and the operator was in the process of running and cementing in production strength. Additionally, we are currently drilling two 100% operated horizontal wells targeting the Eagle Ford, one in McMullen County and one in LaSalle County.

And finally in our East Texas/Central Louisiana area, we are participating at a 50% working interest level in a dual lateral horizontal well targeting the Austin Chalk and the direct venture area of our South Burr Ferry field. This well is being operated by our joint venture partner.

We anticipate following this well up with the second dual lateral well also targeting the Austin Chalk and then in the Brookeland field, we are just now getting ready to prepare to drill our own 100% working interest horizontal well targeting the Austin Chalk.

With our increased drilling and completion activity in the second half of the year, we do expect our capital expenditures to be between $360 and $375 million. Although, we will have increased activity it will be directed towards lower volume, higher value oil and natural gas liquids production.

So while we wont be able to catch up from some of these completion bottlenecks before the end of the year, we are now able to accelerate South Texas completion activity in Q4 and see the potential for higher than expected reserves bookings as well as a higher year ending production rate.

The work of our asset teams have performed this year has been of exceptional quality. As such, we continue to make long-term operational and contractual commitments to them and our shareholders, which we believe signal the companys growth potential that we see in our rapidly growing inventory. The results were seeing today in South Texas give me great confidence that Swift Energy has become a leader in developing the Eagle Ford Shale and Olmos tight sand formations.

Thanks for your attention to me this morning and Ill turn it back to Terry to recap.

Terry Swift

Thanks Bob. Before we open the line for questions, Ill summarize Swift Energys second quarter results and review some of the highlights of todays call. We have two new Eagle Ford and two new Olmos horizontal wells on production. We have added a new rig to drill horizontal wells and a new rig to drill vertical shallow Olmos oil wells.

As of today, we have four 100% and three 50% joint venture Eagle Ford and two Olmos horizontal wells that are being fracked, waiting on facilities to flow back or are waiting on completion operations. We have secured a long-term dedicated fracture stimulation spread and crew to service Swift Energy well exclusively.

Although completion bottlenecks will affect full year production guidance, increased activity levels lead us to increase our reserve guidance from growth of 8% to 12% to growth of 15% to 20% over year end 2009 levels. We also expect to see our daily production increase steadily and finish the year with a daily exit rate of 28,000 to 30,000 barrels of oil equivalent per day.

We also expect to have new drilling results from the Austin Chalk during the second half of the year. Our financial and operational performance continues at high levels and we are benefiting from a multi-year inventory of projects in all of our core areas.

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

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And your first question comes from Leo Mariani of RBC Capital.

Leo Mariani – RBC Capital

Hi. Good morning, guys.

Terry Swift

Good morning, Leo.

Leo Mariani – RBC Capital

Can you talk a little about your infrastructure in South Texas, I know that you had some wells that were producing on restricted rate, just curious whether or not some of that infrastructure has kind of caught up and what your plans are kind of in the second half to make sure that when you get these wells fracked that you can flow all your maximum production?

Terry Swift

Yeah. Let me take that. Just real quickly, we should remind everyone that we did drill a very successful well over in the Fasken area, which is in Webb County and thats producing at a very restricted rate as we prepare to bring a pipeline in the area that will open up that production late in the year.

Bob can give a little more color on that. I think it is producing less than one million cubic feet a day right new and we had a test of I believe about 9 million cubic feet a day on that well. Were really excited about that area.

As to the other areas which weve talked about today from AWP over to the TSH Sun area, weve got good marketing arrangements, pipeline arrangements for what were doing near-term. We have had some facility infrastructure issues where we had to deal with a little bit of Co2 on some wells and deal with a little H2S on a well.

But overall our infrastructure in the AWP area and over in the TSH Sun area is pretty much ready to go or ready to seek additional capacity thats been made available to us or will be made. As to how were bringing the wells on and the kind of rates were reporting in terms of initial production. Ill let Bob talk about how were doing that.

Bob Banks

Yeah. I think there is a lot of discussion (inaudible) rate. There has been a lot of stories -- studies by core lab and basically we are being very careful with these wells, how we do bring them on. Were not being overly aggressive. I mean, we could publish bigger numbers on initial rates, but I think for us we want to be sure that were not creating any kind of near well bore damage when we bring these wells on and that we try to access as much of the fracture stimulation as possible in an even pressure regime. So were bringing them on slow and steady as opposed to ripping them open and getting big rates.

In terms of the AWP area we do have the aiming unit in that Terry referred to, to handle all of our CO2 issues, so thats no longer an issue and we have made a lot of progress on our water infrastructure. Weve invested a lot of time and effort and capital into our water infrastructure and have that in a very good place now in the AWP area.

Leo Mariani – RBC Capital

Okay. And I think you guys have said that you had seven wells that are waiting on completion. I guess. theyre all -- seven of those wells in South Texas and areas where once theyre fracked they should immediately go into production?

Bob Banks

Thats correct.

Leo Mariani – RBC Capital

Okay. I guess, obviously, you took your guidance up for reserve growth. Can you give us a little bit more color in terms of whats driving that?

Bob Banks

On the reserve part, just the fact that we picked up that third rig, the fact that were drilling these wells faster now. Were setting some technical limits. Were setting some global records on how fast were getting these wells down. Weve had more time to study what that means for us in terms of locations where weve selected and how many offsets we would put with that and so we just feel like we have the program on the drilling side working more effectively and weve analyzed that better now.

Terry Swift

Yeah. This is Terry. Ill add to that a large part of our activity this year really the first half of this year has been evaluating our different acreage positions. And in many cases weve drilled vertical wells first and cored these Eagle Ford area and some cases we have even cored the Olmos down in south AWP area.

And then coming back and doing some pretty good testing, bottom hole testing work in some areas, as well as these micro seismic tests, comparing that back to the core, the petrophysics, the guys are much further along now in understanding each of these areas, all of the offset production thats been achieved by other operators and integrating that into a much better picture. Six months has provided a lot of information in this play.

Leo Mariani – RBC Capital

Okay. And you talked about drilling your wells a lot faster. Can you give us your current well costs on the Eagle Ford and on Olmos?

Bob Banks

Yeah. In terms of dry hole costs, if were not doing much in the way of coring or logging, if were just drilling, using our rotary steerable land on the curve and drilling the horizontal, we think were down around the $2 million cost number for that portion of the well.

If you look at all in, I would say its fair to say were probably right now with the increased number of fracture stages that were doing, were moving up more towards 13, 14 fracture stages. Were also including tubing in a lot of these wells, very early on because we are targeting more in the liquid rich wells that, I would say a fairer number for all of that is about $6 to $7 million.

Leo Mariani – RBC Capital

Okay. Thanks a lot, guys.

Terry Swift

Thanks, Leo.

Bob Banks

Thanks, Leo.

Operator

Your next question comes from Jason Wangler of Wunderlich Securities.

Jason Wangler – Wunderlich Securities

Good morning, guys.

Terry Swift

Hi, Jason. Good morning.

Bob Banks

Good morning.

Jason Wangler – Wunderlich Securities

In terms of the backlog of the wells and everything in the Eagle Ford, did I hear right that you can right now get two wells a month fracked?

Bruce Vincent

Yeah. Thats our current contractual arrangement up until October 1st.

Jason Wangler – Wunderlich Securities

Okay. And then when that starts do you have an idea of what you could do? Im just curious how long that backlog would exist because if you have three rigs running. Im thinking youd have three to four wells drilled at least a month and youd obviously have to be able to complete those, but so the backlog would be out by maybe first quarter or early second quarter of next year?

Bruce Vincent

Yeah. I think thats probably a fair way to look at it. I mean, well have to bring the equipment in but we really believe we can get if we have our efficiencies, once we have the dedicated crew and equipment, we think we can knock out four a month.

Jason Wangler – Wunderlich Securities

Okay. And then shifting over to Lake Washington and South Louisiana, I guess, good color as far as the Deepwater Horizon. Have you actually put any permits in since that time and seen a little bit of delay or is that more just a commentary of what you would expect, which I think is probably a good example of what we will see?

Bruce Vincent

Well, yeah, we have put in some permits. So we have seen a slight delay. Now, Im hoping thats going to remedy a little bit, obviously, everyone in the state was so pre-occupied with the Deepwater Horizon incident, but clearly there is more oversight. Theyre asking a lot more questions. We do have inspectors coming to our rigs pretty regularly now. We are meeting with the state agencies on a more regular basis now and are actually going to participate with them in a forum to help decide how best to implement regulations for the inland waters and shallow waters.

Jason Wangler – Wunderlich Securities

Great guys. Thats all I had.

Terry Swift

Thank you.

Operator

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

Michael Hall – Wells Fargo

Thanks. Good morning.

Bruce Vincent

Good morning, Michael.

Michael Hall – Wells Fargo

On the frac spread that you have procured or not procured but locked in for the next couple years, can you give any color on pricing, were you able to receive any consideration for taking on that extra term, any color around that?

Terry Swift

Well, why dont you handle that?

Bruce Vincent

Were very pleased with this agreement that weve reached. In terms of pricing and certain other aspects of the contract, it is confidential, but to answer your question directly, yeah, we believe it was a good thing for Swift Energy Companys economies of scale going forward and the pricing that well get. Obviously, you got to use the contracts and we want to get up to four fracs a month, and thats where the efficiencies come in and thats where the pricing advantages come in.

The service provider also had some advantages built into this relationship in terms of their ability to work directly with this and actually do their maintenance in such a way this they get some advantages and being able to see the program in a very focused area where they know exactly whats going to come out.

Theyre getting advantages, too. But we cant go into the particular commercial terms of it, one, because its competitive and we may be want to do another one of these. So we want to honor that agreement, but let it suffice to say its very strategic and its new equipment, and its with, actually, its not a secret who were using out there. Weve actually been using Weatherford out there. So were very pleased with it.

Michael Hall – Wells Fargo

Okay. Great. And then Petrohawk has talked about running a somewhat higher than typical backlog on its completion through the end of the year to try to help alleviate some capital constraints if you will or a ramp in CapEx. Is that taken into account in your non-op plans, I would imagine, yeah, but just curious?

Bob Banks

Yeah. Weve look at, we obviously communicate with them pretty regularly. They are having trouble accessing the frac spreads in a timely manner just like we have been and weve looked at a couple of different scenarios to understand what our guidance should be in terms of bringing these wells on. But we are hopeful that they will be able to frac those wells a little more quickly than what weve seen over the past quarter or two.

Michael Hall – Wells Fargo

Okay. Great. And then that $6 to $7 million all in cost that you gave, is that including or excluding any coring and other science?

Bob Banks

No. Thats cutting out the coring business.

Michael Hall – Wells Fargo

Okay.

Bob Banks

Yeah.

Michael Hall – Wells Fargo

Okay. And then bottom end of the CapEx range came up. Are you comfortable with keeping that top end, obviously the range is narrowing there, as we move towards the end of the year?

Bruce Vincent

Yeah. This is Bruce. I think were comfortable with that. We basically see it coming in right around the high-end of the range. There are some variables in that, but thats about where we would expect it to be.

Michael Hall – Wells Fargo

All right. And then one more if I may. In terms of infill Olmos location, was there any communication or did you look towards any communication with other wells that were already producing around the area? Any color around that?

Bob Banks

We think we might have seen one zone that had some level of communication, but others did not. Overall, we were extremely pleased.

Terry Swift

I think the thing that we have indicated before, as we develop that field it was first on 320 to 160s to 80s and we got a special permit on (inaudible) at least to go down to 40s and that was the assumption that said maybe you were draining 40s. The more work we have done on that and work we have had third parties do on that, we think weve probably drained five to 10 acres on the vertical wells.

So we definitely think there is an opportunity to go back in, but thats something thats not immediate on our agenda because obviously, were going to focus on the undeveloped acres that we need to earn. But we wanted to test this particular model because we think it has a lot of potential down the road for us.

Michael Hall – Wells Fargo

Okay. And remind me what the potential inventory of these financial wells would be?

Terry Swift

Well, I dont think weve tried to design it or quantify it in terms of number of wells, but we have about 560 producing wells in the field.

Michael Hall – Wells Fargo

Yeah. Okay. All right. Thanks very much.

Terry Swift

Thank you, Mike.

Operator

Your next question comes from Anne Cameron of J.P. Morgan.

Anne Cameron – J.P. Morgan

Hi. Good morning.

Bruce Vincent

Good morning.

Anne Cameron – J.P. Morgan

Given your fracture agreement with Weatherford, I guess, are you still estimating that theyre in development mode or if development mode is next year, the Eagle Ford wells will cost between $5 million and $7 million?

Bob Banks

Well, a lot of that depends on how long our laterals are ultimately and our spacing patterns on these acreage positions and how many stages we ultimately end up at? Because as you add stages, the costs do go up, but I would say for right now, with the current design, our current thinking, were probably more in that $6 million to $7 million range at the moment.

Anne Cameron – J.P. Morgan

Okay. Great. Thats helpful. And for the wells that you announced at the first quarter press release, I think one of them was actually completed during the first quarter for the Fasken EF 1H. Do you have handy any numbers for what those wells are producing now? What are the declines looking like?

Bruce Vincent

Fasken is not declining. That particular well as we talked about before does have some market constraints, so it is really limited about a million a day and it has been producing at that flat rate and maintaining very, very strong pressures. We are in the process, though, of working some agreements for additional pipeline capacity in the Fasken area, not just for that well but in order to proceed with the development of that acreage.

We believe that will be in place certainly by early next year if not the end of this year. Were already planning to begin drilling down there in the fourth quarter recognizing that, that agreement will be in place. The pipeline outlets will be in place and begin to ramp up production down there.

Bob Banks

Just for folks that look at pressure and that thing, that Fasken well as Bruce said is not on a decline. It has been cut back to about a million cubic feet a day but its still got roughly 5,000 psi on the well head, so real strong well.

Anne Cameron – J.P. Morgan

Okay. Thank you. And then also, do you have this handy, how much did you all spend at Lake Washington this quarter?

Bruce Vincent

Let us circle back on that. Bob is going to look that up for you.

Anne Cameron – J.P. Morgan

Okay. Thank you. Thats it for me.

Bruce Vincent

Thank you.

Terry Swift

Thanks, Anne.

Operator

Your next question is from Adam Leight of RBC Capital Markets.

Adam Leight – RBC Capital Markets

Very good morning. Sorry about that.

Bruce Vincent

Hey, Adam.

Adam Leight – RBC Capital Markets

I just had a quick follow-up to Leos question on reserve growth. Are you factoring in any price revisions given so far it looks like a lot better shape than last year and then also what expectations might you have on proportional change in oil versus gas and PUDs versus developed?

Bruce Vincent

The first question is pretty easy. Were not factoring in any revisions upward for price. As you are aware the SEC changed the pricing that you use to a 12-month lift back, so to the extent that we do look at price, there is not as much difference as you had in the past when you had that instantaneous quarter in price that you had to deal with, so as to a direct answer, were not factoring in any revisions upward to price. There may be some additional but were not expecting a lot there.

In terms of the actual reserves per well, I think Bob hit on the fact that were not trying to be aggressive here. Were actually limiting the number of offsets that we would plan on booking relative to the Eagle Ford or the Olmos activity, horizontal activity were stepping out on.

Because were real conscientious that we really want to be able to look hard at our future development plans and manage to the extent we can how we book proven producing versus proven developed versus proven undeveloped. We dont see an awful lot of value in trying to be aggressive on the undeveloped, so while certainly early in a program like this you could have a higher proportion of undeveloped. Were going to be more conservative about how we step out, do a fair amount of infill drilling around the initial Eagle Ford and Olmos area that we have proven up and not just try to get as much booked as we can in one or two years. Were not going to take that strategy.

Terry Swift

Adam, I know you know that under the SECs new reserve disclosure rules, they have added in this developed within a five-year timeframe which we have not had before, so the way you might have booked it before versus what you would do now, we want to be sure were only booking those that we absolutely believe we could develop in that timeframe, so…

Adam Leight – RBC Capital Markets

Okay. Great. I guess for Alton, the credit facility maturity is not imminent but approaching. Are you in discussions currently or are you thinking about extending?

Alton Heckaman

We are in discussions and we feel very comfortable and confident that well have plenty of dry powder there.

Terry Swift

I think the best way to answer that obviously is we dont expect any issues whatsoever in our ability to renew and extend that facility along terms that exist today.

Adam Leight – RBC Capital Markets

Okay. Great. Thats all for me. Thanks.

Terry Swift

Thanks, Adam.

Operator

Your next question comes from Derrick Whitfield of Canaccord.

Derrick Whitfield – Canaccord

Good morning, guys.

Terry Swift

Hi.

Derrick Whitfield – Canaccord

On the Eagle Ford, could you offer any additional color on what you guys have learned with the latest wells and maybe how thats changed your perspective on how to optimally drill and complete?

Bob Banks

Well, I would say weve learned an awful lot on each well we drill and I think a couple of the things, takeaways, from what were learning is, right now were honed in on a certain lateral length that we want to repeat. And we want to now vary slightly our spacing on our stages to make sure we understand how to optimize our costs versus our productivity on each of the wells. We have learned a lot on how to use the rotary steerables. In fact, were probably leading the industry right now in using rotary steerables to kick-off from vertical and drill those curves and I think the last well we drilled the curve in one day.

Thats now down from where a lot of the industry is and where we were before it at four days to five days drilling that curve, so we learned a lot on those efficiencies. I think we learned a lot on our pump rates, how high we want to pump these frac jobs, the type of recipe we want to pump, the number of stages and the spacing, so, yeah, I think we have come a long ways and now were capturing our data and now were calibrating our data.

Terry Swift

I think what I would like to add what Bob said there and mention the seismic that weve got, weve got a very strong seismic program entered around the AWP area that encompasses a good bit of the northern AWP, 3D that we already had. Thatll be merged into a seismic chute that part of which has already been shot and brought in-house and which is going to be further merged with the seismic chute that was to the south of us.

Were going to have an exclusive seismic data set that covers a very, very large -- in fact, it covers -- it will cover all of the JV acreage that we have with Petrohawk and all of the acreage south of that we have that was not in Petrohawks venture as well as the pre preponderance of our acreage north of that venture in that immediate area. So we still need to integrate that in. But thats going to really help in the development as you merge that information with all of this petrophysical and geological information, test information that Bob referred to.

Derrick Whitfield – Canaccord

Terrific. Again, congrats on the service commitments and thanks for all the color there.

Bob Banks

Thank you.

Bruce Vincent

Thank you, Derrick.

Operator

Your next question comes from Ray Deacon of Pritchard.

Ray Deacon – Pritchard

Yeah. Hey, good morning. I was just -- good morning. I was hoping you could talk about the a little bit of the -- so with the new fracking agreement you have, it sounded like you were saying you believe that typical Eagle Ford well is going to be $6 million to $7 million and I guess would that kind of go along with you talked about having drilled a 12 stage frac. Is that the prototype well at this point, do you think?

Bob Banks

Actually were probably looking more in the 13 stage to 14 stages range.

Ray Deacon – Pritchard

Okay. Got it. And do you feel like you know enough what kind of reserves youre hoping to add per frac stages or is it too early to say?

Bob Banks

We havent broken down the per frac stage piece of this yet.

Bruce Vincent

I think it is better to say that youre developing some very solid track record in overall well performance and youve got statistics in there that you got to work with because -- while you can do some downhaul work and try to determine the rate thats coming out of each stage you frac, even to the extent you do that, youre only doing it on a point in time. So it will be very difficult to dissect all of the production data back to a per stage and that will be your only rock solid tie back to reserves per stage.

Terry Swift

You will have an average. You wont be able to isolate them, so…

Ray Deacon – Pritchard

Right. All right. Got it. And I guess the same question for the Olmos. Is it still $5 to $6 million per Olmos well for four of these? Has that changed?

Bruce Vincent

No, no. I think right now I think using that actually that $6 to $7 million with the more frac stages, I think some of our earlier wells like the Huff and some we had a lot less frac stages. Were going to go to more frac stages. So that kind of balances out some of the other efficiencies we have gained on costs, so again all of this is aimed at optimizing cost versus benefit.

Ray Deacon – Pritchard

Got it. I guess just one more. Any update on Bay de Chene and potential deep tasks there? Is that part of the reason for the budget increase or no?

Bruce Vincent

Well, in Bay de Chene we actually slowed things down with the Deepwater Horizon activity because no one quite frankly knew the full extent of how that might affect the inland waters and of course, the hurricane season. We didnt really want to be in there drilling a really deep well with those unknowns, so we have revisited those plans and, yeah, we could get something started by year end. You really wouldnt see much costs in that regard, more than likely thats going to be move into early next year.

Terry Swift

And large part, we took the entire risk capital which, in the inland water area and deferred that partly because of the Deepwater Horizon incident, partly because of hurricane season. And then really increased capital spending in South Texas because of the success we were having, so and then the acreage position allowing us to also focus on oil and liquid content opportunities there.

Bruce Vincent

I am glad you bring that up. There is one deep test in particular in Bay de Chene thats my favorite and I want to get that drilled. Thanks for mentioning that.

Ray Deacon – Pritchard

Great. And I guess just lastly, is there -- so your constraints in terms of transportation on the dry gas side and the Eagle Ford, I guess with the increase in the rig count weve seen in the past couple of months, I guess, has the cost of transportation gone up, do you think? Or is the fact that there is likely to be big pieces of pipe builds going to maybe bring that transportation cost down, I guess?

Bruce Vincent

Well, really, talking about constraints on gas is -- its got a lot of different spokes on the wheel. First of all, the gas prices are lower than we think are appropriate. I mean, we think were going through a weak gas market right now and in that regard, you do prefer liquids. We mentioned that youre looking at a 17 to one ratio, so it is not really a constraint on the gas market. Weve got a lot of gas opportunities we can drill in South Texas right now, fair number of dry gas things we can get into the line right now but we moved to the liquids because of this 17 to one value relationship.

Now, when you get over into the Fasken area, yeah, there are deliverability constraints, pipeline constraints. There is several lines being built into Webb County. Those that study the area know well. There is some 10 inch lines, some 20 inch lines and even some larger lines that being laid in there and we are working with major players in that area to get a line right into our Fasken area. As we do that, that constraint should be removed.

Weve got great data, great production tests, not only us but some offset operators, so that really should come in more winter, late winter which we see the gas market will improve by then. Over in our Artesia wells area, which is also referred to -- we refer to as the TSH Sun area, you have got some pipe coming into that area.

To further complicate it, these pipelines that are coming in, they have dry gas lines and lean gas lines and wetter high BTU lines that you have to make sure you know which ones youre getting in. And in the Fasken area, thats kind of a dry gas area, so if a lean line -- if, excuse me if a high BTU line is in the area, you cant get into it. So we have been planning that as part of our program going forward.

We will be bringing the Fasken area into 2011 in a pretty strong way, but as a percent of things itll be a smaller percent of what were doing in the overall play. In terms of transportation, most of the things were dealing with will take us to the ship channel and have Houston ship channel type pricing and were finding that there is pretty competitive transportation arrangements going forward. The difference being that in the past, you have been able to move the gas pretty much on an interruptible basis, not concern yourself too much with having reserve capacity.

Were working with the pipelines and the transporters in these areas. Were discussing to actually take firm capacity going forward and dedicate acreage in some cases or certainly make some form of borrowing commitment to get the transportation item down. If you just go pure interruptible, youre probably going to find going forward that youre either going to be restricted on the gas coming out or youll be paying high transport costs or both.

Ray Deacon – Pritchard

Got it. Thanks very much.

Terry Swift

One general comment there, Ray. Just like you saw the industry get all over leasing activity down there, the mid-stream players are all over the opportunity down there. So there is a lot going on that will allow the transportation to also be there.

Ray Deacon – Pritchard

All right. Thank you.

Bruce Vincent

Take care.

Operator

There are no further questions.

Paul Vincent

Okay. Wed like to thank you again for joining us on our conference call. And we look forward to getting back with you on our third quarter results.

Terry Swift

Thanks, everyone.

Operator

Thank you. That does conclude todays conference call. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Swift Energy Co. Q2 2010 Earnings Call Transcript
This Transcript
All Transcripts