SilverBow Resources Inc (SBOW) 2010 Q3 法說會逐字稿

Good morning. My name is Dorothy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy third quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. I will now turn the conference over to Paul Vincent, Director of Finance and Investor Relations. Sir, you may begin.

Thank you. Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. I'd like to welcome everyone to Swift Energy's third quarter 2010 earnings conference call. On today's call, Terry Swift, Chairman and CEO, will provide a overview. Alton Heckaman, EVP and CFO, will review the financial results for the third quarter, and then Bruce Vincent, President, and Bob Banks, EVP and COO, will provide an operational update. Terry Swift will then summarize before we open it up to questions. Also present on the call is Jim Mitchell, SVP, Commercial Transactions and Land.

Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates, and projections about us, our industry, and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports to which we refer you, along with cautionary statements contained in our press releases, and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes, and have allowed additional time for questions.

Thanks, Paul. And thanks to everyone listening for joining our conference call today. Before we discuss third-quarter operational and financial results, I believe it's necessary to take a pit stop and review how strongly Swift Energy is positioned despite the current economic and operating environment. Our resource base currently includes held by production, low-risk oil development opportunities, and deeper, mature exploitation and exploration inventory in South Louisiana. In South Texas, approximately 79,000 prospective acres in the Eagle Ford shale and approximately 41,000 prospective acres in the Olmos tight gas sands, plus over 100,000 net acres prospective for Austin Chalk in Central Louisiana and East Texas. We have two joint ventures in place with leading oil and gas companies to accelerate the development of our resource base, in addition to production infrastructure, gathering, processing, and transportation capacity to bring hydrocarbons to the markets. We also contractually secured three high-powered drilling rigs for our 2011 South Texas operations.

Financially, our balance sheet is in excellent shape. We extended our $300 million borrowing base through 2015, and expect the borrowing base to increase as our production and reserve base grows. Our current exposure to a large growing liquids-rich resource base, coupled with the financial strength and liquidity to develop it, place Swift Energy in a unique position to deliver multiyear high-return production and reserve growth. As most industry participants and observers know, demand for critical oil field services has gotten stronger over the past six months. This rapid increase in demand has impacted both the availability and performance of providers and vendors, especially high-pressure pumping services for fracture stimulation.

In many cases, previously agreed upon frack schedules have been delayed or canceled. While this represents additional challenges to meeting forecast and performance targets, Swift Energy remains committed to improved performance and efficient execution of its operating plans. These scheduling delays have resulted in a significant backlog of industry wells awaiting fracture stimulation. As of the end of the third quarter, we had 12 horizontal wells waiting on fracture stimulation. With our current drilling activity, we expect to have nine to 12 horizontal wells waiting on fracture stimulation services by the end of the year. This number of backlog completions is well above our original expectations and has reduced our full-year production and lowers our year-end exit rate target.

Starting in the fourth quarter, Swift Energy began using dedicated fracture stimulation equipment and services under a completion services agreement. This increased control of our completion activity in South Texas, combined with recent completion performance improvements, gives us confidence that our adjusted performance targets will be met. However, as a result of the uncertainty and high-pressure pumping service scheduling and performance for much of 2010, we are lowering our forecasted year-end corporate daily production rate to 26,000 to 28,000 net barrels of oil equivalent per day. This new range is a 15% to 24% increase from our third-quarter average daily production rate of 22,500 barrels of oil equivalent per day.

The impact of these unexpected scheduling delays is approximately 525,000 barrels of oil equivalent, of production which will be delayed past the end of this year. As a result, our full-year 2010 production is expected to be 8.3 to 8.5 million barrels of oil equivalent. This equates to a 2% to 9% sequential increase in fourth-quarter production over third quarter 2010. Our focus on liquids-rich opportunities will result in our production mix remaining approximately 60% liquids at year-end 2010. Based on our year-to-date drilling and appraisal program, we expect our year-end 2010 reserves to increase by 15% to 20% over last year's year-end levels. During the third quarter, prior to the arrival of the dedicated equipment and crew, we completed an average of one horizontal fracture stimulation job per month.

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

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

The Quintanilla Me-You 1-H had a 12-stage fracture stimulation perform, and tested at the rate of 494 barrels of oil a day and 1.3 million cubic feet of gas per day. This well came online during the fourth quarter. The Bracken JV 3-H, a non-operated well drilled earlier in the year, was completed by our joint venture partner during the quarter with a ten-stage fracture stimulation. This well's initial production rate was 5.8 million cubic feet per day, with flowing casing pressure of 5,753 psi on a 16/64" choke. These tests continue to derisk our acreage in McMullen County, and provide additional evidence that our technical work is sound.

In Southeast Louisiana, at Lake Washington, we completed three wells during the quarter and continued our Lake Washington production maintenance program. We expect to spud a deep exploitation target in the fourth quarter at Lake Washington. Finally, in our Central Louisiana/East Texas area, the first well targeting the Austin Chalk in our joint venture area in the South Burr Ferry field was drilled. Initial production rates of this well were 13 million cubic feet of gas per day and 1,000 barrels of oil per day. Those are gross numbers. Swift has a 50% working interest in this well. In this same joint venture area, a second well is currently drilling. In the Brookeland field in East Texas, we are drilling a Swift-operated Austin Chalk well and we are participating in a non-operated well targeting the same formation, and expect both to be online by the year-end 2010.

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

Okay. Thank you, Terry, and good morning, everyone. Again, having balance in our portfolio has served Swift well during the third quarter 2010, as oil prices have stabilized while natural gas prices remain sluggish. Swift Energy's financial results for the third quarter reflect this. Oil and gas sales, excluding hedging effects, were $106 million, an 8% increase from 3Q 2009. Our income from continuing operations was $9.4 million, or $0.24 per diluted share, up from 3Q 2009 but down from the previous quarter. Cash flow before working capital changes came in for the quarter at $1.62 per diluted share, beating current first-call estimate. And 3Q 2010 production was up 2% from second-quarter levels, yet on the low side of our guidance, at 2.07 million barrels of oil equivalent.

As to our price realizations, crude oil prices were 12% higher than third quarter 2009 levels, while natural gas prices for 2010 were 36% higher, leading to an overall 16% higher price for BOE in 3Q 2010. Swift's averaged realized price in 3Q 2010 therefore increased to $51.06 per BOE, due primarily to crude oil prices increasing to an average of approximately $76 per barrel, compared to $68 per barrel a year ago, allowing Swift to increase its quarterly oil and gas revenues 8% over the third quarter of 2009.

As always, we again continue to focus on our controllable costs and metrics. G&A came in slightly above guidance at $4.21 per barrel. DD&A came in at $19.69 for BOE, within our guidance. Production costs came in slightly above our guidance, at $10.12 per barrel. Interest expense of $3.99 per barrel was on the high side of guidance. And production and ad valorem taxes came in at 10.2% of oil and gas revenues. The result was income from continuing operations for the quarter of $9.4 million -- again, $0.24 both basic and diluted. Our effective income tax rate for the quarter was within guidance, at 37.5%. Cash flow before working capital changes for 3Q 2010 came in at $62 million, or $1.62 per diluted share, while EBITDA was $65 million for the quarter and CapEx on a cash flow basis was $99 million.

Now let me spend just a moment to again highlight Swift's solid financial position. As of the end of the third quarter 2010, we had no outstanding balance under our line of credit. And as Terry mentioned, we also renewed and extended our $500 million line of credit facility with nine major banks through October 2015, and initially set our borrowing base at an increased $300 million. As also indicated in our release, we recently purchased an initial tranche of floors covering 520,000 MMBtu's of January 2011 natural gas production. Please see our website for complete and current detailed hedging information.

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

Thanks, Alton. And good morning, everyone. And thanks for being on the call. Today I'll review third-quarter 2010 activity, including production volumes, recent drilling results, activity in our core operating areas, and our plans for the fourth quarter of 2010. Bob Banks will then discuss significant operational activity of the quarter and its effect on the remainder of the year and moving into next year.

Beginning with production, Swift Energy's production during the third quarter of 2010 totaled 2.07 million barrels of oil equivalent or 12.43 billion cubic feet equivalent, an increase of 2% from the 2.03 million barrels of oil equivalent or 12.17 billion cubic feet equivalent produced in the second quarter of 2010. Third-quarter production, when compared to third quarter of 2009 production of 2.22 barrels of oil equivalent or 13.32 billion cubic feet equivalent, actually decreased 7%. Year-over-year declines resulted primarily from our reduced spending and activity levels throughout 2009, continuing fracture enhancement and completion delays in South Texas, and natural declines. For the fourth quarter of 2010, we expect production to increase 2% to 10% over third quarter 2010 production, as our dedicated fracture stimulation equipment and crew build momentum and improve efficiencies and completion activity will accelerate.

For our third-quarter drilling results, Swift Energy drilled 17 operated development wells, one of which was plugged and abandoned in Lake Washington. It also participated in two non-operated development wells. The Company also drilled one operated exploration well and participated in one non-operated exploration well. Three operated horizontal development wells were drilled to the Eagle Ford shale. Five operated horizontal development wells were drilled to the Olmos sand, one of which will be completed as a water source well after encountering mechanical difficulties. Two non-operated horizontal development wells were drilled by our joint venture partner to the Eagle Ford shale, and five operated vertical development wells were drilled to the Olmos sand.

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

In the Lake Washington field in Plaquemines Parish, Louisiana, four development wells were drilled, and three were completed, and one was plugged and abandoned during the third quarter. Six sliding -- sliding sleeve shift changes were performed during the quarter, resulting in an average production increase of 277 gross barrels of oil equivalent per day per operation. Drilling activity is expected to resume in Lake Washington later in the fourth quarter.

I'll briefly review our activity in each of our core operating areas for this quarter, and then let Bob detail some of the highlights of the activity. In the Southeast Louisiana core area, which includes Lake Washington and Bay de Chene fields, production during the third quarter averaged approximately 10,152 net barrels of oil equivalent per day, or about 61 million cubic feet equivalent per day in this area. The 2% decrease, when compared to our second quarter 2010 average, net production from the same area.

Lake Washington averaged approximately 8,058 net barrels of oil equivalent per day, or about 48 million cubic feet equivalent per day, a decrease of 2% when compared to second quarter 2010 volumes, primarily due to lower levels of recompletion and maintenance activity and natural declines. Bay de Chene's sequential production decreased 5% at 2,093 net barrels of oil equivalent per day, or about 13 million cubic feet equivalent. This sequential decline is due to no new drilling activity and limited operational activity, as well as natural declines. Our fourth quarter 2010 operating plans in this core area include bringing a barge rig into Lake Washington field to drill an exploitation test in December.

In our South Texas core area, which includes our AWP, Sun TSH, Briscoe Ranch, and Las Tiendas fields, third quarter 2010 production averaged 8,648 net barrels of oil equivalent per day, or about 52 million cubic feet equivalent per day, a 7% increase in production when compared to second quarter 2010 production from the same area. This also represents a 25% increase over third quarter 2009 production in this area. Production in this area increased as a result of increased activity, improved drilling efficiencies, and production optimization. Production growth in this area is extremely sensitive to the performance and timing of third-party service providers and vendors. For most of 2010, we have been disappointed with the ability of these third parties to perform along agreed-to schedules and timelines.

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

Swift Energy currently has three operated rigs drilling horizontal Eagle Ford objectives in LaSalle and Webb Counties. One non-operated rig is also drilling in our joint venture area in McMullen County. The Central Louisiana and East Texas core area, which includes our Brookeland, Masters Creek, South Bearhead Creek, and South Burr Ferry fields, contributed 1,987 barrels of oil equivalent per day, or about 12 million cubic feet equivalent per day of production in third quarter of 2010. That was a 8% increase in production from the second quarter of 2010. One operated rig and one non-operated rig are drilling wells to the Austin Chalk formation in East Texas and our Brookeland field. We have a 100% working interest in the operated well and a 40% interest in the non-operated well.

One non-operated rig is also drilling a well in the Austin Chalk formation in our South Burr Ferry field. Swift Energy has a 50% working interest in this well. In our South Louisiana core area, which is comprised of Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island, and Bayou Penchant, production averaged approximately 1,575 barrels of oil equivalent per day, or about 9 million cubic feet equivalent per day during the third quarter. Minimal operational activity is expected in this area for the remainder of 2010. Now I'm going to turn it over to Bob, who is going to review some operational highlights during the quarter.

Thanks, Bruce. First, at our Lake Washington field, we drilled four wells during the third quarter, completing three and P&Aing one. The CM #413 was drilled to a measured depth of 2,922 feet and encountered 48 feet of true vertical net pay. This well has averaged approximately 270 gross barrels of oil per day over the past 30 days. The state-leased 17266 #25 was drilled to a measured depth of 5,037 feet and encountered 246 feet of true vertical net pay. This well has averaged approximately 100 gross barrels of oil per day over the past 30 days. The CM #414 was drilled to a measured depth of 1,622 feet and encountered 90 feet of true vertical pay. This well was recently completed, and will be tested following a facility upgrade.

Also during the quarter at Lake Washington field, six sliding sleeve changes were performed during the quarter. The average production increase from these operations was 277 barrels of oil per day. Additionally, we will spud a deeper exploitation well later in the fourth quarter and will continue our production maintenance and optimization program for the remainder of the year at Lake Washington. Moving to our Central Louisiana/East Texas core area, a non-operated exploration well targeting the Austin Chalk was drilled and completed in the South Burr Ferry field by our joint venture partner. Initial production test rates of this well were 13 million cubic feet of gas per day and 1,000 barrels of oil per day, gross production. Swift Energy has a 50% working interest in this well, which will be produced to sales upon completion of a saltwater disposal well. A second well in this area has been drilled and will be completed during the fourth quarter. We do expect to be active in the Austin Chalk in 2011.

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

During the third quarter, we also drilled four vertical wells targeting oil in the Olmos formation in the northern portion of AWP in McMullen County. At the end of the quarter, three of these wells were completed, but have not yet been brought online. The initial production rate of the most recently completed well, the SMR 7, was 318 barrels of oil per day and 0.8 million cubic feet of gas per day, with flowing tubing pressure of 1,900 psi on a 12/64" choke. We concluded this drilling program after a sixth well was drilled during the fourth quarter.

Now moving and updating our Eagle Ford activity during the quarter in McMullen County, we drilled three 100% operated horizontal wells. We completed three of these wells during the quarter, and brought on two of the wells during the quarter and one early in October. The Discher 1-H and the PCQ 4-H, both drilled during the second quarter, were brought online during the third quarter. A 14-stage fracture stimulation was performed on Discher 1-H, and this well's initial production rate was 448 barrels of oil per day, 1.6 million cubic feet of gas per day, with flowing casing pressure of 3,275 psi on a 12/64" choke. The PCQ 4-H was completed with a 13-stage fracture stimulation, and this well's initial production rate was 528 barrels of oil per day and 1.9 million cubic feet of gas per day, with flowing casing pressure of 4,903 psi on a 14/64" choke.

The Quintanilla Me-You 1-H was drilled in the third quarter and was brought online early in October. This well had a 12-stage fracture stimulation performed. The initial production rate of this well was 494 barrels of oil per day and 1.3 million cubic feet of gas per day, with flowing casing pressure of 21 psi on a 18/64" choke. And the Carden 1-H, an exploration well, was drilled to test the Eagle Ford shale formation on Swift Energy acreage in LaSalle County during the third quarter. A 14-stage completion was performed on this well, which is in the process of flowing back and being brought online.

In our joint venture area in McMullen County, our joint venture partner completed the Bracken JV 3-H during the quarter. This well was drilled earlier in the year and was completed during the quarter with a 10-stage fracture stimulation. This well's initial production rate was 5.8 million cubic feet of gas per day, with flowing casing pressure of 5,753 psi, on a 16/64" choke. Another well, the Bracken JV 2-H, is currently being fracture stimulated and will be online in the fourth quarter. Two additional wells, the Whitehurst JV 1-H and the Bracken JV 6-H, have been drilled but not yet completed in this area as well.

Now, as Terry mentioned earlier, we've lowered our full-year production guidance range, primarily due to continuing schedule and performance delays of our completion-related service providers. While we now control our own frack spreading crew, too much work has been delayed for us to catch up volume-wise before year-end. In July, our planning contemplated that we could complete and have online 19 of our Eagle Ford and Olmos horizontal wells for the second half of 2010. We had also believed that we could have had five JV wells fracked and 24 vertical Olmos refracks completed during the second half. Three different fracture stimulation providers involved have not been able to perform to the agreed schedules. During the months of July to September, which is the period prior to our receiving our dedicated equipment and crew, we only achieved three of seven fracture stimulations that we had firm, scheduled dates for. This loss of program production has resulted in a reduction of 525,000 barrels of oil equivalent to our expected second half 2010 production.

Perhaps a better way to evaluate how our horizontal fracture stimulation efficiency is progressing, we should review performance before and after our dedicated frack crew arrived. In the second quarter of 2010, and before we had built a significant inventory of wells, we averaged an one frac job per month pace of activity. In the third quarter, we again only averaged a one-frack job per month pace of activity, even though we had two per month scheduled and committed. During this period, we experienced severe equipment problems and delays, as service companies stretched their spreads, time lines, and maintenance schedules too thin.

In October, after the abrupt arrival of our dedicated frack [spread] and crew, we worked at a four frack job per month pace, which represents a four-fold increase over the previous two quarters. This performance pace is also carrying forward into early November results, as we've just finished up the AFP 4-H within five days. As such, we are still expecting a strong ramp-up in fourth-quarter production, but we have also widened our anticipated year-end daily production rate range, as a result of lower confidence levels in project scheduling where third-party completion services are concerned.

Let me be very clear, however, our vendors and contractors do an outstanding job when they are actually working on our behalf. Until recently, they have simply been too inconsistent in delivering their services for us to have high confidence in our timetables and work schedules. If service reliability were to improve, or put more simply, if schedules are maintained at this point, we do still believe that we can exit the year above the midpoint of our revised 26,000 to 28,000 barrels of oil per day exit rate forecast. And I believe that the performance we are now seeing since the beginning of October is a very positive sign.

Terry mentioned earlier the strong operational and financial position this Company is in. As we've continued to execute on our operational plan, stabilize our completion operations, and drill in more of a development type mode in South Texas, I believe we will surpass even his expectations. From all of our remote field locations to our home office in Houston, hundreds of people have worked tirelessly to get us such an advantageous position, and I can't wait to see the results as they continue to gain momentum. Thanks for your attention this morning, and I'll turn it back to Terry to recap.

Thanks, Bob. Before we open the line for questions, I'll summarize Swift Energy's third-quarter results and review some of the highlights from today's call. We have three new Eagle Ford wells on production. As of today, we have five 100%, three 50% joint venture Eagle Ford, and three Olmos horizontal wells that are being fracked, waiting on facilities to flowback, four are waiting on completion operations. Our long-term dedicated fracture stimulation crew arrived and completed four stimulation jobs and began a fifth in the month of October. This crew will complete at least three wells per month during the fourth quarter.

Completion schedule bottlenecks will affect our full-year production guidance. We maintain our reserve guidance of growth at 15% to 20% over year-end 2009 levels. We also expect to see our daily production increase steadily and finish the year at 26,000 to 28,000 barrels of oil equivalent per day, a 15% to 24% higher rate than our third-quarter daily average production rate. We have encouraging results from our first Austin Chalk joint venture well in Louisiana. A second well is currently drilling in this area, and we are drilling a Swift Energy-operated well to the Austin Chalk in our Brookeland field in East Texas. We have secured long-term gathering and transportation agreements for natural gas production in Webb County, Texas, and we have also extended our $500 million credit facility with a $300 million borrowing base through 2015. With that, we'd like to begin the question-and-answer portion of our presentation.

(Operator Instructions) We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Jason Wangler with Wunderlich Securities.

Good morning, guys.

Good morning.

Just a quick question. Now that you have that frack crew on the ground, is four probably a good number, the max that they could do per month? And like you said, Terry, three is a good average per month?

Yes, I mean -- this is Bob. I think that the performance we are seeing, we think we can do three, if everything is going reasonably well. We're already at a four per month pace, and things look pretty smooth at this point. There are -- there is even opportunity down the road, probably not within the next month or two, to get even above that pace. So, we -- we've just seen a material turnaround since we've gotten the dedicated crew, equipment, we're able to work with our provider on maintenance scheduling services and the way we time that maintenance into our operations, it is all just smoothing out for us.

Okay.

Excuse me, this is Terry, I hate to complicate a good answer. But I think I will here. Bob mentioned a lot of people working behind the scenes and a lot of effort put on -- on our folks and our service providers. And one of the things that we need to be clear about is we had been doing the slick water fracks principally in this whole program to date. Now, we have recently done some hybrid fracks, and for those that aren't familiar with that, the slick water fracks typically take longer to do, and as you move to the hybrid fracks, you do get some performance advantage in terms of time. We're working with that, because we don't think that's the right answer for every area and every situation, but -- but we certainly do think the hybrid fracks are going to be a part of our ongoing program, particularly up in the oil rich area.

Okay. That -- that helps. And then, just maybe one more on the frack schedule. Since you have kind of that backlog, is there any thought to maybe still jumping onto the schedule for some of the service providers and just hoping to maybe even get an incremental frack put in there, or are you just going to stick with your crew and let them get that backlog worked out other the next couple of quarters?

No, we are -- this is Bob, we are very actively engaged with a number of service providers. In fact, we have a non-dedicated crew right now fracking one well that was a backlog. We're working on a couple of more dates. We -- we have not built those into our planning because dates have not always been the most reliable in the past two quarters. But clearly, we are engaged with all the service providers on future dates and that really is part of our plan in the -- in the first part of next year and maybe even a little bit more in fourth quarter to get some more fracks done.

Great. Thanks, guys.

Thank you.

Thank you.

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

Hey, good morning, guys.

Hey, Leo.

Looks like you guys had a pretty good well there on the Austin Chalk. Curious as to what the well cost was there for you?

Over in the Austin Chalk area, I think it -- we -- we basically need to know, that first well was an exploratory well. And the good news is it -- it really has tested much better than we thought. The difficulty in drilling the well was we ran into some really high pressures, and that well did have some mechanical problems, although we were able to go ahead and get a really good test on it. And so the initial costs on that well, Bob, is --

Yes, it -- it was about about $10 million with -- with the trouble time. The good news is, we worked in a collaborative way with the operator on the second well design, and that second well has come in significantly under that first well, more in about the $5.5 million range. So we -- we have a good working relationship with the operator. And I think we're making some adjustments in real time, and they're showing up now in the second well.

Okay. And you think that $5.5 million number is pretty good, going forward, and you guys have an estimated EUR on that first Austin Chalk well?

Yes, I -- I think that's a reasonable number, because we -- we, again, had the pressure, we had the mud cap drilling, but we made it a much less complicated well bore construction design. So I think both -- both partners are onboard that that's the way to go forward in the future.

Okay. And the -- any estimate of what you think the EUR was on that first well?

No, not yet. Not yet.

Okay.

We -- we've only done an initial test on it. We're waiting to hook it up and get some more production history before I think we -- we'd be comfortable talking about an EUR.

Okay. All right. Jumping over to the Eagle Ford, I guess you've got some gathering lines on in -- in Webb County over there. Could you talk about your infrastructure in your other two areas, and you still have wells that are producing at restricted rates or are you able to -- to flow your wells full bore? I mean, it looked like some of the choke sizes you guys had in some of those wells looked a little smaller than some of your peers.

Yes, I think starting down Webb County, we're in the process now of getting that infrastructure hooked up. We think that will be in to where we can be flowing, open up our wells, and frack our next two wells in December. So we -- we've really tackled that and handled that infrastructure issue. Up in the artisian wells area, or what we call North Sun TSH, we still have -- we still have some facility issues we're working through. We expect those to be debottlenecked here within the -- within the next quarter or so.

And then, over in the AWP area, we're -- we're pretty much -- we're pretty much open up. I think one thing that you saw on our test rates is we -- we really are working on restricted chokes here now, as opposed to -- so we're not really as interested in getting the -- the higher IP numbers. We're -- we're really looking at some models where we're trying to hold those levels back, bring them in more slowly, and -- and see if that doesn't confirm our suspicions that we'll get better EURs within a short period of time out of the well, managing the well bore that way as opposed to, you know, opening it up and pulling it a little harder. So I think that's what you're really seeing.

Okay. Jumping over to Lake Washington, you guys have a deep exploitation well you talked about getting ready to spud later this quarter here. Just curious as to, you know, size of that target, and I guess you could describe it as exploitation as opposed to exploratory. Can you give us a little bit more color on that?

Yes, that's -- that is what I'd call a partial [pot]. It is updeck from known production, very, very good sand quality. So, yes, we -- we've -- we think this well has potential to be a very good oil producer. In terms of size, I -- I think we would probably say the range is 750,000 barrels to maybe 1.5 million barrels for that particular location.

All right. Thanks, guys.

Thank you.

Thank you.

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

Thanks, good morning.

Good morning, Michael.

I guess, quickly first, in the Eagle Ford, a few questions. If I recall the kind of -- the cost parameters around the dedicated crew are somewhat related to your utilization level of the crew, if you are doing about four per month, I don't know if it is called three per month or four per month, what's the kind of expected cost looking like per well now?

Why don't I take a stab at that? The contract, as you properly noted, is really a exclusive, dedicated crew. So obviously, if we don't get any wells fracked in a month, then we're paying money and not getting anything done. But if we are up around two fracks a month, we think that we're still under the current spot market price of fracks out there. Current spot market frack jobs clearly depend on whether you are doing a slick water, a hybrid, whether you are doing nine stages or 14, the amount of sand you are putting in, all operators have different mixtures there.

But a -- a spot market job can easily be $3 million to $4 million. If you are trying to do a really big job, we've heard some exceptional numbers above that. But really, two jobs a month will put us under the spot market in terms of a average type of frack out there. We think we can get up to four. And we think we'll be seriously beating what you would be seeing in terms of that average spot market job, materially beating it.

Would you care to put a number around what the total well costs would be at four per month?

At four per month, Bob, do you want to take a shot at that?

Yes, I think depending upon a number of other issues, frack recipe design, you know, I -- I have been saying all along that -- that as long as we're not really stepping out there, you know, testing new positions, as long as we're really getting more into a development mode, there's no reason why we can't be drilling these for $6 million to $7 million. I think we're sticking with that -- we're still sticking with that.

Okay. Great. And -- and, I guess, also just curious as it relates to the reporting of the results in the Eagle Ford, the gas stream that you are reporting with those wells, is that a -- a light gas stream, and would there be some sort of NGL uplift associated with that, you know, post processing? How should I think about that?

Absolutely. We -- we clearly segregate it out as gas at the test ,but that is a wet gas stream with a high BTU, would have some nice liquids with it.

Okay. What's -- what's kind of average BTU looking like on the wells at this point?

Well, it's -- it's --

Yes, 1250 to 1300 BTU on the gas.

Okay. Yes. Good deal. And then thinking about the exit rate guidance, the 26 to 28, what, I guess, are the key variables on the high end, low end, I mean, what is the -- is it really just timing of Eagle Ford wells, or is there any other kind of one-off items that we've got to think about?

The big -- the biggest issue probably is the timing. We've run a couple of different paces out through the end of the year to come up with our numbers. The other variable is these Austin Chalk wells, how those -- how those come on, clean up, and produce into sales. One we got a good test on, we had to shut in awaiting hookup. So that's getting ready to come back on here imminently. And then, the second well we have not tested yet, but we liked what we saw. So those two factors are the biggest variables.

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

Yes. Well, actually as you look forward to next year, and again, we've got to be a little bit careful. We haven't come out with all of the 2011 budget strategies, so we'll be doing that as we go across year-end and certainly into our analyst meeting next year. But I -- I can tell you this right now, we're very excited about the Austin Chalk. We really have four areas that we're working in the Austin Chalk. We've got our bread-and-butter area over in the Brookeland area. There's some nice things to do there.

So, will you definitely see us drilling a well or two over there next year, working with a partner over there who has some working interest in some of our units, we have our Masters Creek area. We're pretty excited about some of the things we can do to revitalize, reinvigorate some of that production over there. Again, that's kind of a -- both of those areas are bread-and-butter areas, no facility issues to speak of, whatever production you get, you are ready to put in. Whatever gas you've got, you are ready to process. Burr Ferry is close to facilities, if you will remember, we had production in that area a while back, but one of the things that time has done for us, the new technologies are helping us stay in zone better, get -- get much better completions in terms of, you know, in the old days you had to worry a lot about the mud cap and [indiscernible] cement and then your fractures.

Today, we're doing a better job staying in zone, but we're drilling exploratory and appraisal wells first. We've got one very large AMI with a joint venture partner. We do intend next year to come back in there and have some offsets, where it's appropriate. As Bob noted, we've got some early production results that look good, and if those hold up, then next year you'll see us drill some development wells that would offset that, basically continuing the appraisal program of a very large acreage position. And we do have additional acreage all along that trend that we'll probably put some more exploratory wells in next year.

Okay. Great. That's -- that's helpful, thanks. And then, I guess, just one more, if I may. The third quarter exit rate, what -- what's that running at?

Bob, do you want to take that? The average production for the third quarter was about 22,500 barrels across the entirety of the third quarter.

How about the exit rate, though?

I don't think it was much higher than that.

Yes. I don't think -- I think with a lot of these wells just coming on in October --

Right. I think 22,500 to 23,000 --

Yes. We've had some flush days where we got up to 24,000. But the way we're trying to manage this business is to give you numbers that are -- are usable.

Yes.

In that regard, Bob, why don't you refresh him on how we actually come up with these test rates that we're reporting?

Well, yes. I mean, we have a -- a standard on our test rates that for a -- certain type of wells, gas condensate wells, you know, we're -- we're really picking the IP at day number five. And then, for some of the Olmos wells, that we get more water back, and maybe some of the more dry gas wells, we're picking day number ten. So -- so we're trying to be very consistent on the day we're picking our IP's, so that helps us with our models internally in calibrating our production history back to our pre-drilled [bottle]. So that -- that's what we're -- that's what we're picking on the numbers here. And on -- on day six or day seven, it may be higher. But we -- we've just chosen to pick that -- that consistent date every time.

Okay. Appreciate it. Thanks, guys.

Thank you.

Thanks, Michael.

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

Good morning, guys.

Hey, Derrick.

Hi, Derrick.

Staying on the Eagle Ford, did the latest wells change your view on the delineation of the gas condensate [indiscernible] at AWP?

I think the latest wells are pretty consistent. However, I would say there's still some tinkering to do, where you had a line that might have been a gray area a couple of miles wide, now that gray area I think is maybe a mile wide. We are finding -- I think we found more oil, I don't think there's any doubt we were oilier than we expected in terms of our northern AWP program. But also, there's an area in northern -- in the northern JV area that we're just getting into, and that's going to be a pretty critical well. We think the northern part of our JV area has got some really nice liquids based on this program. So -- that's a long answer, but yes, we did learn something. We're fine-tuning that line and when we think it bodes well for the northern portion of the JV acreage.

Got it. And then, moving over to the Austin Chalk trend, could you comment on how the geology compares across each of your key project areas?

Well, it -- it -- if you look at the Austin Chalk, of course it goes all the way along the Texas Gulf Coast. It's a big, big, massive trend. And when you get into the Masters Creek area, we drilled some very deep, high-pressure wells on -- on units that had 2,000 acre spacing units. So that was the kind of spacing back in the 1990s when those were being drilled. As you move across that play, it does change somewhat.

In the Masters Creek area, there was a lot of water associated with initial production, but you definitely had oil wells that would come in in excess of 2,000, 3,000 barrels of oil a day, and some of the [cumes] on those wells were over 2 million barrels equivalent. As you moved west over to the Burr Ferry area, you generally would get a little bit shallower. You would begin to have less water, and by the time you got to Brookeland, you were even shallower in terms of the play fairway that was being developed, and you typically had no water drive by the time you got to Brookeland. It had a nice oil component, probably 50/50 oil and gas over there.

We now really do believe, and other operators have shown, that the play is -- has extended deeper, south of Brookeland, that there's been a nice opening up of the play. And as we match that extension of the Brookeland area south, pull it over to the Masters Creek area, you see a lot of opportunity for the play to -- to continue. So, that's what we're -- that's what we're exploring.

Got it. Very helpful. Then maybe a little more color on your first JV well if you could, was this well [successful in zone], say, across 80% or better, the horizontal? And do you think it's representative of what you could expect in this part of the trend on a go-forward?

Yes, I think on the first well, we -- we geosteered this well independently. And I can say that well was very well kept in zone. There -- there were some mechanical difficulties with that well, but probably actually compromised even the test rates we reported. The second well, also -- we geosteered that independently and it looks like that well was strictly in zone. So, a very good job on keeping the well bores in zone on these first two wells.

Good. And maybe, jumping over to Bay de Chene, any updates on your deeper test targets there?

Yes, we -- we clearly have two wells over in that area that we are -- we just need -- they are [saucered] and blowed, and ready to drill. One is what we call the Teton, but it's principally a gas, it's principally [HBP'd]. So, we're kind of slowing down on that because of the gas market, but we want to drill that in a bad way. We have another one called South Shasta that's just to the north and east of Bay de Chene, but in the general Bay de Chene area. That South Shasta well we do intend to drill next year, probably take about a 50% position and operate that well. It should have a very nice liquids component associated with it, based on the work we've done, based on -- you know, we did have a discovery of Shasta north of there that's given us a lot of encouragement that we could have a very, very nice exploration target there next year.

Good. Well, thanks for all the color on these topics, guys.

Thank you.

Yes.

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

Hey, good morning, guys.

Good morning.

I -- I just wanted to get a sense with these more liquid-rich wells, do you have a sense as to what kind of EUR expectations?

Well, the models we've been talking about publicly, like at [Doug] and other places, it is still kind of in the range of about, you know, 250 million to 375 million -- or 250,000 to 375,000 barrels EUR on those real -- real liquid-rich wells.

I see. And what percentage of your -- your AWP acreage would you say fits into that category?

Well, I -- I wouldn't put it on a percentage basis, because I just can't calculate that fast. But we had what we call our northern AWP area that really -- there's probably about 12,000 acres up there, from our SMR area over to our Discher area over to our Hayes area. Those are wells that we've talked about, or had -- PCQ area, there's probably about 12,000 or more acres there.

We also have a block of acreage that's very oily, that sits in the trend that is [HBP'd], that's probably about 4,000 to 5,000 acres. And then we also have the northern part of our JV area where we think that's going to be very, very oily, probably put it in the gas condensate, but still very oily. And that portion is probably 4,000 to 5,000 acres. And then the artisian wells, which is another 12,000 -- 14,000 acres over there, we believe is in the oil condensate window.

And then, as you look out into 2011, at what kind of level are you guys comfortable at spending cash flow, and should I think about it in net terms or should I think about it in terms of setting the cap metrics that you guys traditionally look at?

Yes, I think that the best way to answer that is we're absolutely committed to protect the balance sheet. And in that regard, all of our look will be at cash flow. Obviously, we've got to try to figure out what gas prices are going to do, and oil prices, because that is a material thing. We do expect some really nice production gains next year. As we do our modeling, which we're doing right now, working with the board, it's clear that the gas bogey is probably the most uncertainty. And I would say that it is very clear that we intend to spend cash flow to the extent that we can accelerate the oil piece and liquids piece, then we've got a line of credit that's, you know, $300 million.

So we could go into that somewhat. But we also have options in terms of maybe selling some non-strategic properties. We'll be putting all of that together for you as we go across the year and early into 2011. But we will protect the balance sheet.

I see. And -- at a minimum, though, do you think you'll do -- you'll keep that one frack crew?

Oh, yes. Oh, yes.

Working? And basically drill up 40 wells?

Yes. I --

40 operated --

We -- we have numerous scenarios and plans, but we clearly have a plan where we protect the acreage as well without stressing the balance sheet in any way.

And then, one last one for me, it's just -- on the wells you guys have drilled to date, I realize going forward they are going to be lower, but what's been the average cost to drill, and then the average cost to complete?

Well, you know, as Bob mentioned, we've done a lot of exploratory work this year -- a lot of appraisal work, we put our water facilities in around these wells so that we're ready to do the fracks, we've had some infrastructure that we've put in. So this year's average number probably does not fit real well in terms of development. I would say that this year, we had looked at some $7 million to $8 million, $8.5 million types of wells. We've had wells that we cored. We've done micro-seismic out there. Just a whole litany of science to give us a leg up on this. But going forward, as Bob said, you get into the oily areas, we ought to be able to drill these now on a development mode in the $6 million to $7 million dollar range.

Okay. Thanks, guys.

Thank you.

Thanks, Brian.

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

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

Thanks.

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