SilverBow Resources, Inc.

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

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Hi. Good morning, guys.

Good morning, Leo.

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?

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?

Okay. Thanks a lot, guys.

Thanks, Leo.

Thanks, Leo.

Good morning, guys.

Hi, Jason. Good morning.

Good morning.

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?

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?

Thank you.

Thanks. Good morning.

Good morning, Michael.

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?

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?

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?

Okay.

Yeah.

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?

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?

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

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

Yeah. Okay.

All right. Thanks very much.

Thank you, Mike.

Hi. Good morning.

Good morning.

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.

Okay. Thank you.

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

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

Thank you.

Thanks, Anne.

Very good morning. Sorry about that.

Hey, Adam.

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?

Thanks, Adam.

Good morning, guys.

Hi.

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

Thank you.

Thank you, Derrick.

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?

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?

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?

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.

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.

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.

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.

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.

Got it. Thanks very much.

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.

All right. Thank you.

Take care.

Thanks, everyone.