Comstock Resources Inc (CRK) 2010 Q3 法說會逐字稿

Welcome to the third quarter 2010 Comstock Resources earnings conference call. My name is Keith, and I will be your operator for today. (Operators Instructions) I will now like to turn the conference over to your host for today, Mr. Jay Allison, Chairman and CEO. Please proceed, sir.

Keith, thank you. Again, everyone, welcome to the Comstock Resources third quarter 2010 financial and operating results conference call. You can view slide presentation during or after this call by going to our web site at www.comstockresources.com and clicking "Presentations." There you will find a presentation entitled "3rd Quarter 2010 Results." I am Jay Allison, President of Comstock, and with me this morning is Roland Burns, our Chief Financial Officer, and Mack Good, our Chief Operating Officer. During this call we will review our 2010 third quarter financial and operating resulted, as well as updated results of 2010 drilling program and our outlook for the rest of this year.

Please refer now to Slide 2 in our presentations, and note that our discussions today will include forward looking statements within securities laws. While the expectations and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Please refer to Page 3 of the presentation where we summarize the third quarter results. Higher oil and gas prices have improved our financial results in the third quarter compared to the third quarter of 2009. Our production in the third quarter increased 1% to 17.2 billion cubic feet of natural gas equivalent ("Bcfe"). For the quarter we reported revenues of $80 million, generated EBITDAX of $55 million, and had operating cash-flow of $47 million, or $1 per share.

We had a small loss in the quarter of $4.7 million or $0.10 per share. We continue to have strong results in our Haynesville shale drilling program.

We drilled 58 successful wells, including 54 horizontal Haynesville and Bossier shale wells, in the first nine months of this year. We got off track from the strong production growth we had in the first two quarters of this year, due to the unavailability of high pressure pumping services that are needed in order for us to complete our Haynesville shale wells.We reported earlier that we have secured completion services, starting in the fourth quarter, which will allow us to timely complete the Haynesville shale wells we are currently drilling, and begin to address the backlog of 26 wells waiting on completion that we had at the end of the third quarter. Despite the production set back we are anticipating strong reserve growth this year driven by our Haynesville shell drill program. And lastly, we're maintaining our strong balance sheet and liquidity position, despite the low natural gas environment we're currently in. I will turn it over to Roland Burns to review the financial results for this quarter for more detail. Roland.

Thanks Jay. On Slide 4 we break out our production by quarter and by region, and then we highlight the new production from Haynesville shale wells in red on the chart. For the third quarter of this year our production averaged $187 million cubic feet of natural gas equivalent ("MMcfe") per day, which was 1% higher than the production in the third quarter of 2009 of 184 million per day.

As Jay mentioned earlier, production was down almost 15% from our second quarter average rate of 219 million per day, due to completion delays in the Haynesville shale program. Our East Texas North Louisiana region averaged 134 million per day, with 49 million coming from our Cotton Valley wells, and 85 million coming from the Haynesville shale wells. The Haynesville wells made up 45% for our total rate. Our South Texas region averaged 39 million per day, and our other regions averaged 14 million per day in the quarter. As we announced earlier, we're selling our Mississippi properties, which make up 8 million per day of the 14 million per day in our other regions. And we've separated that production on this slide as Sold Properties.

We expect our production to begin increasing again starting this month, with completion activity picking up in the fourth quarter in Haynesville program. We now expect production for all of 2010 to approximate 73, to 75 Bcfe, which would represent an 11% to 15% growth over 2009.

Slide 5 shows our average gas price. Our average gas price increased 17% in the third quarter to $4.24 per Mcf as compared to $3.63 in the third quarter of 2009. For the first nine months of this year our average gas priced increased 12% to $4.55 per Mcf as compared to $4.05 for the same period in 2009. Our realized gas prices averaged 97% of the NYMEX Henry Hub gas price in the third quarter of this year.

Last year we had 9% of our gas production hedged and then none of our production was hedged this year.

Our realized oil prices are shown on Slide 6. Our realized oil price increased 12% in the third quarter of 2010 to $64.97 per barrel, as compared to $57.96 per barrel in the third quarter in 2009. For the first nine months of this year, our average oil price was $66.54, 43% higher than our oil price of $46.42 for the same period in 2009. Our realized oil price has averaged 85% of the average benchmark NYMEX WTI price in the third quarter.

In Slide 7, we cover our oil and gas sales. The improved natural gas prices increased our sales by 18% to $80 million in the third quarter. For the first time this year our sales increased 38% to $276 million as compared to $201 million in the same period in 2009.

Our earnings before interest, taxes, depreciation, amortization, and expiration expense, and other non-cash expenses, or EBITDAX, grew by 17% to $55 million this quarter as shown on Slide 8. For the nine months ending September 30, 2010 EBITDAX increased 47% to $189 million.

Slide 9 covers our operating cash flow. Our operating cash flow for the quarter came in at $47 million which was 33% lower than cash flow with $70 million in 2009's third quarter. Cash flow in 2009's third quarter included an extraordinary benefit from an income tax refund of $26 million. For the first nine months this year, operating cash flow was $175 million, 11% higher than cash flow of $157 million for the same period in 2009.

On Slide 10 we outline our earnings. We reported a net loss of $4.7 million or $0.10 per share, as compared to net loss of $12.6 million or $0.28 per share in 2009's third quarter. Improved oil and gas prices and the production growth account for the lower loss. For the first nine month this is year we reported net income of $1 million or $0.02 per share, as compared to a net loss of first three quarters of last year $29.7 million or $0.66 per share.

On Slide 11 we show our lifting cost per Mcfe produced by quarter for the last couple of years. We've broken out our lifting cost in three components, production taxes, transportation, and then other field level operating costs. Starting with the fourth quarter of last year we're transporting more of our gas from our Haynseville operations to long haul pipelines, rather than selling it at the well end. The result is an increase in our lifting cost which has been offset by improved gas price realizations. Our total lifting cost averaged $1.17 per Mcfe in the third quarter of this year, as compared to $0.94 in the third quarter of 2009, and $1.13 in the second quarter of 2010. The increased rate was mostly due to lower volumes this quarter. Our production taxes averaged $0.18 per Mcfe and transportation averaged $0.24 per Mcfe in the third quarter. Field operating cost average $0.75 this quarter, which was the same rate as we had in the third quarter of 2009. Pro forma for the sale of Mississippi properties, our lifting cost would be reduced by $0.08 per Mcfe, once those properties are out of our reported numbers.

On Slide 12 we show our cash G&A per Mcfe, produced by quarter, excluding stock based compensation. Our general administrative cost averaged $0.29 per Mcfe in the third quarter of 2010, as compared to $0.28 per Mcfe in the third quarter of 2009, $0.27 per Mcfe in the second quarter. Our depreciation, depletion, and amortization (DD&A) per Mcfe produced, as shown on Slide 13. Our DD&A rate in the third quarter averaged $2.72 per Mcfe, an improvement from our $3.18 rate in the third quarter of 2009. Our DD&A rate this quarter decreased $0.15 from the $2.87 that we averaged in the second quarter. The Haynesville shale reserve additions are hoping to lower our DD&A rate. And then without the Mississippi River properties, we'll see our DD&A rate fall by another $0.04 from where it is now.

On Slide 14 we detail our capital expenditures for the first nine months of this year. We spent $263 million for our drilling program so far this year, as compared to the $243 million that we spent in the same period of 2009. We spent most of that $250 million in our East Texas/North Louisiana region with only $13 million spent in South Texas and our other regions. We spent $130 million this year to acquire exploratory acreage. $50 million was spent to acquire additional acreage respective for the Haynesville and Bossier shale in North Louisiana. Then we also spent $80 million to acquire 18,000 net acres in the emerging Eagle Ford shale trend in South Texas.

Referring to Slide 15, we recently announced that we entered into agreement to sell our oil and gas properties located in Mississippi to privately-held Petro Harvester. The sales price of $75 million in cash with effective date of July 1. Net production from the properties to be sold averaged 1,300 barrels of oil equivalent per day. At the end of last year we had 5.1 million barrels of oil equivalent assigned to these properties included in our proved reserves. The sale is expected to close in December and is subject to the completion of customary due diligence by the purchaser. Based on a sales price of $75 million, we expect to realize the net loss after income taxes of approximately $16.6 million on this divestiture.

Slide 16 presents our capital structure at the end of the third quarter. On September 30, we had $4 million in cash, and $71 million in marketable securities on hand. We had $60 million outstanding under our bank credit facility which is unused borrowing base of $440 million. We also have $172 million of our 6 7/8% senior notes, and $296 million of our 8 3/8% senior notes outstanding, for total debt of $528 million. Our book equity at the end of the quarter was $1.1 billion, making our net debt only 28% of our total capitalization.

I'll now turn it over to Mack Good for an update on our drilling program.

Thanks, Roland. As you can see on Slide 17, we focus on our East Texas North Louisiana region. Our activity in the region is focused on developing our Haynesville and Bossier shale properties. We drilled 55 wells gross, 33.6 wells net in this region in seven different fields in the first nine months of this year, and all of the wells were successful. 54 of those wells were horizontal wells. We've tested 25 wells, that have been completed at a per well average rate of 10.4 million of natural gas equivalent per day. And many of our newer wells as you know are being produced under our choked back program which we feel will lead higher reserve recoveries from those well.

On Slide 18 we show the number of days it has taken to drill the 74 operated horizontal Haynesville wells that we've drilled to date, and our average drill time for all 74 wells, drilled to date is 38 days. The average drill time for our first five wells was 50 days, compared to 28-day average drill time for our last five days. Our shortest drill time so far is 24 days. With our improved drilling program we are drilling these wells extremely efficiently.

On Slide 19, we show the number of days it's taken to connect each of our 47 operating horizontal Haynesville wells that are currently flowing to sales. Comstock's average connect time is approximately 100 days for all 47 wells currently flowing to sales. Our average days from spud to sales for our first five wells was 96 days, compared to 164 days for our last five wells. Last year the lack of pipeline infrastructure was the major factor contributing to the time to connect a well to sales. We overcame most of the infrastructure issues and have reduced the time frame to connect to sales down to as low as 49 days.

Starting in the second quarter of this year we began to experience very long delays in getting the wells completed. The larger frac jobs that all of the operators started pumping in the Haynesville, along with the increased rig count in the region, created very high demand for pressure pumping services. At the end of the third quarter we had 26 drilled Haynesville or Bossier shale wells that were waiting on frac. Going forward Comstock has been successful in obtaining pressure pumping and other related services, with which allow us to frac 14 to 15 wells before the end of this year. With six operating rigs drilling in the Haynesville and Bossier shale, we expect to drill another 10 wells in the fourth quarter, giving us an estimated 22 wells to carry over into our year 2011 cycle. We have also entered into an agreement with the major service provider to provide us with a 24 hour dedicated frac for North Louisiana operations in 2011. This dedicated crew will allow us to complete our backlog of Haynesville and Bossier shale wells during 2011, as well as keep current with our 2011 anticipated drilling activity.

Slide 20 outlines our planned activity this year to further develop our Haynesville and Bossier shale acreage. We plan on drilling 70 wells, 42.8 net to our interest. 49 of the 70 wells are operating. 41 wells are planned for Logansport, and 18 are planned for the Toledo Bend North and South regions, with nine wells in the Mansfield area.

We've moved one of our seven operated rigs out of the region to our new acreage in the Eagle Ford during late August, and we are looking to move a second one there by June 2011. We plan on releasing another rig this month from our Haynesville program, and we're considering releasing two more rigs as we determine what we want to spend on our 2011 CAPEX program.

Our South Texas region is displayed on Slide 21. We drilled two wells in this region so far this year. We drilled a well in our Ball Ranch field in the first quarter and drilled one well on our new Eagle Ford acreage this quarter.

On Slide 22, we have our holdings in the Eagle Ford shale in South Texas. We've acquired 18,000 net acres to date that we feel is prospective for developing in the emerging shale play, the Eagle Ford, and McMullen, Karnes and Atascosa counties in South Texas. We are focusing primarily on the oil condensate windows in this play due the better economics of oil versus natural gas. We hope to acquire an additional 10,000 net acres in our focus area. So far we have drilled the Tres Hijos #1H in McMullen County to a vertical depth of 11,020 feet, with a 4,091-foot lateral in the third quarter and drilled the NWR No. 1H in Atascosa County to a vertical depth of 8,715 feet with a 5,209-foot lateral in October. These wells are scheduled for completion in November of this year. We are currently drilling our third Eagle Ford shale well in Karnes County.

Finally on Slide 23 we outline what we expect to spend this year on our drilling program and our acreage acquisitions. We've currently expect to spend $385 million for our drilling program to drill 77 wells. 74 are horizontal wells, 70 of those are in Haynesville or Bossier shale and four are in the Eagle Ford shale. We have spent $130 million so far this year for our acreage acquisitions. Our total capital expenditures are currently estimated at $515 million if we do not acquire any more acreage. We are still evaluating acreage opportunities mainly in the Eagle Ford and may have additional acquisitions before the end of year. And with that I'll turn it back over to Jay.

Thank you, Mack, thank you Roland.

In summary I'll refer to you to Slide 24. We continue to be excited about our prospects for reserve growth this year, despite the weak natural gas prices and the completion delays we experienced this quarter, we are still well positioned to have substantial reserve growth at a very low finding cost. Our 2010 drilling program estimated to cost $385 million we're focused almost primarily on developing our Haynesville shale acreage. We think our Haynseville shale program can add 400 to 500 Bcfe approved reserves in 2010.

With pressure popping services so hard to obtain we will not reach the 20% to 25% production growth that we envisioned at early on this year, but we still have production growth of 11% to 15% that will carry over part of the growth of 2011 which allow us to reduce our drilling activity in our Haynesville shale in 2011 and still have a strong production year. We're starting the development of acreage in the Eagle Ford shale in South Texas as Mack stated earlier. During this period of weak natural gas prices, the Eagle Ford program gives us a higher return area to grow our oil, condensate, and natural gas liquids production in 2011. We're maintaining our inventory of drilling locations and have a large inventory of drill sites and the upper and lower Haynesville shale and Cotton Valley in East Texas and North Louisiana and in the Eagle Ford, Vicksburg and Wilcox trends in South Texas that we can accelerate many when natural gas prices improve.

We continue to maintain a very strong balance sheet with $440 million available on our bank credit facility and plan the use proceeds from our Mississippi asset divestiture to retire some of the borrowings we've made to purchase acreage For the rest of the call we'll take questions from the research analysts who follow the stock. Please limit your questions to two or maybe three so we have time to answer all the analysts' questions that are asked. So with that Keith I'll turn it back over to you for questions.

(Operators Instructions) Your first question is from the line Brian Corales with Howard Weil. Please proceed.

Good morning, guys. Just a couple of questions. In the third quarter how many wells did you complete and how does that compare to the fourth quarter for the Haynesville?

This is Mack. We've completed four wells, operated wells, in the third quarter. The rest of your question, I'm sorry, -- how did it compare to what?

In the fourth quarter, do you all currently have 14 scheduled?

Yes, we have the frac dates arranged for those 14 going forward.

Oh, okay. How many of have you all done so far?

We've done four.

Okay. I'll just do one final question, how many wells can a dedicated crew complete in a year, is that kind of one a week, is that a good estimate?

24 hour crew can frac four to five a month, if all goes well.

Okay, and I apologize, one final question. On the restrictive rate program, what are you all seeing over the first year? I mean, is it -- is production falling, is it maintaining much better than what you all were doing before? And -- what is like the total , say in year one? If you all have that production

Well, we are still evaluating. As you may know, we like to get sufficient data before we pin down some numbers. But I can tell you this, the EURs that we're seeing in our choke back program are 20% to 30%, and in a few cases even higher than that, especially in our Logansport and Mansfield area. So, our original guidance was five Bcfe across the play. You can estimate that the reserves from the choke back program, so far the data is indicating that those reserves are going to jump by 20% to 30%.

All right, guys, thank you.

Your next question is from Jack Aydin with KeyBanc. Excuse me.

Hi, Jack.

Hello. Roland, on the third and fourth quarter production, you lowered the lower guidance from -- the growth from 15% to 18%, to 11% to 15%. Is that for the asset sale -- did you make in the asset sale in those numbers?

Well, we did reflect the asset sale, and that production would be out of our numbers in the month of December, but it mostly reflects the third quarter rate being low and, there's only limited amount of time, to really catch up in production. I think we'll have a strong production in November and December. October production was not too different than what the third quarter averaged.

So the completions are picking up again, it takes -- you just don't have many months left in this year. But I think we will be leaving the year with very strong production growth in the fourth quarter -- having a nicer fourth quarter. We just didn't have enough production in the third quarter to get us to the top end of our guidance, but we will still be, within the range.

Mack, when you mentioned about the rig count, going potentially to two rigs in the Haynesville area, when do you think that decision will be made, or what, if everything goes according to your schedule, when you do you think you will be active in the Haynseville?

Jack, I'm not going to lay it on the line this morning and say we're going to go to two rigs in the Haynesville and guarantee you that. We're considering that, certainly. As you know we're running six rigs now in the Haynesville, we're going to release a rig this month to go to five rigs.

A decision hasn't been reached yet as to when we would go to the fewer number of rigs in the Haynesville and exactly what that number might be. Certainly, the Eagle Ford acreage that we've put together is offering a lot of opportunity and we're considering reallocating our resources in that direction. Exactly how many of those resources are yet to be determined.

My final question is what does the average cost per well running for you complete according to the Haynesville in today's environment.

Right now it's about $9.5 million.

Thanks a lot.

You bet.

Thank you, Jack.

Thank you.

Your next question is from the line of John Freeman with Raymond James. Please proceed.

First question I had, in the release you all put out on October 19, it talked about having 22 wells in the completion at the end of the year. In the presentation it says 25 to 30 now and I'm just interested maybe did anything material change if that, I guess couple weeks when that released when you locked up the crews.

Well, John, we're estimating to drill maybe one or more wells -- like additional wells in the Haynesville just because of the quicker drilling time. Then I think the -- the other thing on the number, is when do you consider ready for completion.

The very second that the drilling rig leaves they're not ready to be completed. So there's kind of a couple of weeks there for preparation for completion, and I think that's probably part of the difference there. So we would have, 22 wells definitely ready for completion, but we probably have, three and four other wells that would be already drilled that will also be carried into next year. So it's just a slightly definitional difference.

Remember, John, last year we drilled 43 and we carried eight of them over this year.

There's always going to be some that are not ready to start completion just in a normal course.

Sure, I understand. I guess the efficiencies baked in, I thought as you were dropping the rig I guess I wouldn't expect you to drill more wells than previous in the fourth quarter. On the spud to sales time if we sort of look out once you've got all your frac crews in place, Mack, what are you looking at for the spud to sales times you estimate for 2011? Like if you're 164 days now on your last five, what do you think that is like in 2011 on average?

Well, once we get caught up, I would think 60 to 70-day cycle time would be our goal. 60 days with 35 to 40 days to drill, another 20 to 30 days to get the wells completed. But we've got to work through this backlog first, obviously.

Last question, you had mentioned in the past, Mack, about looking at possibly treating your wells at a lower rate sort of 65 to 70 barrels a minute you've been pumping in the past. When would you expect to test that concept to see if it works?

We're doing that now. The back story on that is that some areas of the Haynesville, you may not want to pump at a lower rate. It depends on exactly what kind of stage or what size the stage is, how much proppant you're putting away, et cetera. We're currently fracing wells in our Logansport area as part of the 14 to 15 wells we plan to frac before the end of the year, at that lower rate and it's working quite well, no problems.

Great, thanks, guys.

Yes, sir.

Thanks, John.

Your next question is from the line from Kim Pacanovsky with MLV. (Operators Instructions)

Good morning gentleman. Those 14 or 15 wells that you plan to frac before the end of the year. You don't have your dedicated crew until 2011; is that correct?

Right.

So how confident are you in getting these 14 to 15 wells to getting completed.

Very.

Very?

Very.

I can take that to the bank?

Yes.

Then we have a separate group which is dedicated contract.

Okay.

We have three separate frac crews Kim that will be fracing these wells. Then we have a separate group which is dedicated contract for 2011.

So we are in good shape Kim. It's not just a hand wave, it's -- they are set up frac dates right now.

Okay, great. Thank you. How many of the Haynesville rigs that have expirations coming up, I guess one now, one December, one February, one March, could all of those go to the Eagle Ford or are any of them lower quality rigs that you wouldn't want to keep.

We believe that all but one can go to the Eagle Ford if we chose.

Okay. What kind of strip price would you need? When I spoke to Roland yesterday, I mean, one of the concerns was, if you -- when you let a rig go, it's hard to get a rig back. What kind of strip are you looking at to not go down to two rigs in the Haynesville -- if there could be a magic number for you?

What we're drilling in the Logansport, in the Mansville area, as well as the upper in our Toledo Bend area, it's extremely low, it's -- we're profitable down into the $2s.

Okay. Wow. All right. I'll ask you more questions off line. Thanks a lot, guys.

Thank you, Kim.

Your next question is from the line of Noel Parks with Ladenburg Thalmann. Please proceed.

Good morning.

Good morning.

Sorry if I missed this earlier, could you talk a little bit about South Texas and I guess the most recent well you drilled there and also what you saw during the quarter in respect with Eagle Ford.

We've participated in a well with our partner Abaco in Ball Ranch, as previously mentioned. And the other well was a Granite Wash well that we participated in. And -- as a partner. Do you need any more specific information?

No. That was generally what I was looking for. And just -- sorry, I just a housekeeping question. The production growth you're looking for next year, I guess your trailing average IP in the Haynesville about 10.8 million a day, the figure that you had. What's a good figure going forward for new up coming online assuming the choke back.

I think a 10 million a day number is a very reasonable day.

Even with the choke back.

Absolutely.

We're saying 10 to 12 Noel.

Okay. Great. Thanks. That's all from me.

Your next question is from the line from Ray Deacon with Pritchard Capital. Please proceed.

Hello. Jay, I was wondering if you can talk a little bit how active you think you'll be in the Eagle Ford and potentially how you could fun more acreage purchases there going forward?

Ray, you know what we have done -- we've -- throughout this year we've added the 18,000 net acres. We probably had $4,200 to $4,300 an acre invested in that. If you JV it at $10,000, $11,000, $12,000 an acre, there's probably $100 million profit there. So, I think our cost basis is right. We operate all of them. We own 100% working interest in it.

It's the same G&G group that helped create in wealth in the Haynesville that we started drilling in first quarter of' 2007, and then really the first quarter of 2008 that we relied upon internally to start leasing acreage from what we thought early this year was the condensate window. You know, we've avoided JVing any of the Eagle Ford. We've avoided JVing any of the Haynesville so far. We think we know the value of Haynesville.

I think if we were to bring in a JV partner it would be because we've added material acreage in the Eagle Ford because we don't want to stretch our balance sheet. We want to keep it strong. I think if you look at what we try to do at the end of the second quarter, we didn't put a press release out there that we were in Eagle Ford. We just told you on the second quarter conference call that we've added 18,000 net acres. We're right now attempting to add another 10,000 net acres that are quality that we would operate.

As far as rig commitments, when you drill wells in Eagle Ford, you do give up reserves and you give up rate and you do add materially to your return on your investment. But you give up two things. When we look at the Eagle Ford, we said, well, the Haynesville is in the position by the end of December, we think, we'll completely understand the lower Haynesville. I think we need to drill some more wells to understand the upper Haynesville of the Bossier, if we keep a rig and a half no more than 2 rigs busy in the Haynesville.

We can satisfy any drilling requirements that we have company wide in all of East Texas North Louisiana. That brings us up quite a bit to ship those rigs throughout next year to the Eagle Ford. I think if you see $80 to $90 oil, high condensate prices, and this goes back to what Jack had asked earlier and actually what Kevin asked. I think what you will see us doing is once we've taken care of transportation issues, I think you'll see us shifting of the rig count to the Eagle Ford, if we need to ship, one, two, three, rigs there, whatever, I think we'll be able to do that.

I don't think we'll be forced to do that because of lease obligations. We would do that because of the rate of return. We would end up kind of doing to the Haynesville what we did beginning of 2009 to the Vicksburg, Wilcox, and the Cotton Valley program, we've inventoried all of those programs. If you take this company and go back 15 years from January of 2009, I mean, we just drilled vertical wells and in really those three formations and we probably drilled less than 10 of those wells since January of 2009. We've inventoried all of those.

I think we would take the same attitude. If you have a very low gas price and we feel very comfortable with the quality of our Haynesville acreage, I think you'll see it's kind of inventorying that, we'll -- the dollars that we would have used to drill the Haynesville wells we'll ship them over to the Eagle Ford acreage, or the Eagle Ford program. What you've done in years and years we've not really incurred any net debt. We've kept our strong balance sheet, we've kept $.5 billion dollars. We did tell the world that we'd incur about $60 million.

We'd use $60 million on our credit facility this quarter. We've also told the world that we've got $75 million in divestitures in laurel. And we also have another $70 million to $80 million of Stone Energy shares that we could monetize at any given time. We look at that when we look to see whether we incur any net debt or not.

I think, Ray, that's our attitude toward the program.

You know, no one knows if the gas prices will rebound -- I think they have the symptoms of rebounding. But we've put ourself in the position where we don't have to mandatorily drill a lot of wells. We don't have a bunch of rigs that we have to farm out to somebody. We don't have a JV partner that will force us to drill wells that we shouldn't be drilling. I think one of the greatest things in all of this, no matter what business you're in, you need to be the low cost producer and our charts show us we're one of the lowest cost producers in E and P world.

We haven't issued any equity in almost six years. Those are all quality things. Finally I would look at where the acreage is, whether it's Eagle Ford or Bossier or the Haynesville. I think most of it is quality tier 1 acreage and then, you're thankful we're not trying to divest ourselves of any of the Gulf of Mexico assets. We were fortunate to do that at the end of 2008. I don't know if that answers your question. That kind of is a broad brush. But I think you need to know that because all those components, equal what we do or don't do in the Eagle Ford.

Got it. No. Thank you very much. Could I ask Mack, I was curious, across the three areas of Atascosa, McMullen, and Karnes, do you -- how different do you expect the wells to be from EUR and return standpoint.

We believe our Atascosa acreage is our lowerer tier acreage. As far as McMullen and Karnes, we think that is in the condensate -- so as far as EURs, we were circumspect concerning that.

We followed the public data that's out there, we're evaluating daily the EURs from wells that are nearest to our acreage. But the fact of the matter is there's not a whole lot of data within two or three miles of the acreage holdings that we have. So, we're being pretty conservative as far as the launching numbers out there. But we're obviously optimistic about the Atascosa acreage despite the fact that it's on our lower tier, as I said, the McMullen and Karnes acreage we think that's going to be a condensate play for us.

Got it. Great. Will you release results of the three wells before fourth quarter earnings or --

Well, we currently plan frac two of those wells in November and we're hoping to get the third completed in December. So those numbers should be available.

Ray, we don't plan to do well by well releases on Eagle Ford wells. I think that's a bad practice for companies to follow.

Thanks very much.

Thank you.

Your next comes from the line of Don Crist with Johnson Rice, please proceed.

Good morning guys. How are you all doing?

Good morning.

Can you -- with the large backlog of wells that you are all are going to shift in 2011, despite the less drilling that you're going to do, can you talk about your production growth, the 11% to 13% that you're projecting for 2010?

Yes, Don, we feel like our production growth will be stronger next year than this year just with the big carry over wells into next year getting into our program will benefit 2011's production versus 2010's. So we do think that it will be stronger than the upper range of our guidance this year, and once we kind of determine our final allocation of rigs between the Eagle Ford and Haynesville and the number of rigs that were run which we'll do, typically we get that approved and so at that point we'll kind of come out with some guidance.

We do see a strong production year next year and we're looking to see if we can't lower our capital spending too so we can bring our, overall bring our total capital expenditures closer to what the cash-flow can be with the lower gas prices that seem to be expected for next year.

I think the great thing is you've got 22 plus wells that will carry forward. We think they're in tier one locations in the Haynesville or the Bossier. So you're looking at, you know, 10 to 12 million a day rates is our guess and we own probably 75% of that. So we're going to kind of be on a springboard at the beginning of 2011 and as Mack mentioned earlier, we do have a dedicated frac rate to complete those wells in all of 2011. I think it will be more predictable and the growth will be more predictable on a quarterly basis.

Hello, guys, just to follow up on that, the question is, you know, the 20% to 25% growth became 11% to 13% because of completion delays and because you'll be cycling through those -- that backlog and plus, apparently keeping up with your 2011 drilling program directionally, will it go back to what your original expectations were, you think?

You talking about for 2011?

For 2011. Your original expectations for 2010 were 20% to 25% growth.

I think we can definitely have we have the wells to achieve that of next year. A lot of -- I think if we run the lower number of rigs I think it's going to have a bigger impact on what we can do for 2012.

And then the sequential decline you saw third quarter versus second quarter, is that a pretty good representation of what your basic line rate, if you're not completing many new wells, 15%.

What influenced that is the choke back program. We were monitoring the pressures versus rights on a number of our Haynesville wells and adjusting the choke accordingly so that had an impact as well.

Remember, Don, when we reported the second quarter, we had about 9 million to 10 million per day of that production that was really production from increased ownership interest in wells that we'd gone back and after we had and determined that we had a little higher interest and when they finally finished- all of the title work on those wells. So there was about 8 million to 10 million a day of second quarter production that was attributable to earlier in the year.

So that also made that decline of almost 15% , it kind of exaggerated it. But I think the decline will be softer with the new choke back program than without that kind of adjustment in

All right. Guys, thank you.

Thank you, Don.

Your next question is from the line of Rehan Rashid with FBR Capital Markets, please proceed.

Good morning. Just to double-check on the Haynesville lower choke back decline rate, is it -- if this were -- would have been completely the normal way, what rate could we have seen?

A lot of the wells would have been 18 to 20 Rehan. This is Mack.

18-20. Eagle Ford good progress in terms of continuing to reallocate capital, what else can -- are we thinking about any of the particular areas that seem to be of interest or any tell or like that you're working on.

I always tell people we shop all the time and only after we buy do you though what we've bought. Unlike the Haynesville and kind of like the eagle Ford.

Geologically speaking anything particular that stands out, anything that stand out? But geologically speaking, anything that fits into your --

You know, our states are, Texas, Louisiana, Mississippi. So geologically within those three states.

Okay. All right. Perfect. Thank you.

Yes, sir.

Your next question is from the line Justin Tugman with Perkins Investment Management, please proceed.

Good morning. I know it's kind of early, but Jay or Roland, can you give me any sense of what 2011 CAPEX looks like?

Hey, Justin, it's a little early because we're still, running different models and going to go to our board and continue to look at the outlook for 2011 to decide. But we can tell you the framework we basically we're. As far as the rigs that we have, we'll run a program that's at the minimum of three rigs and probably a maximum, of five rigs.

So that's the range. We'll carry over the wells to be completed, which all the wells drilled including what's ready to complete right away, it's roughly maybe 25 wells that will get completed. We've got the crew to back that up, so, it's the completions a well, so $4 million to $4.5 million a well so that's large dollars that will be part of the base, so, I guess the ranges are anywhere from, a budget that's similar to this year's, $350 million at the minimum maybe to $500 million.

Okay. I'm sorry. You said the completions you're waiting on figure about $4.5 million.

Right. The component of even with the lower rigs that's a big component of cost that we'll have to -- we'll carry into next year. Of course that also be the driver of the strong production growth next year without having to spend the full amount for the well, the $9.5 million.

And go back to your 2010 CAPEX you mentioned $515 million that's assuming you don't buy any more acreage, I guess can you kind of give me a sense of where you're at on that? Do you have something lined up that's just not announced or are you looking to buying 10,000 more acres and calling it good and maybe that slips into 2011.

We don't have anything definitive right now, but we do have -- we have things we're interested in. But we're very particular about the price we'll pay. It's got to fit our -- what we feel it's worth.

We're probably not putting a high likelihood, that's why we didn't include it in our estimate. There's not only a couple of months left, so there's nothing pending so even typically if we would decide to buy something it might not even close this year because where we are now. I think the $515 million is our best estimate and what we think we'll actually spend this year and then we'll know kind of if we identify another tract of acreage that we really want to buy.

If that falls over into 2011, let's say you get 10,000 acres bought in January, does that mean you're done for the year?

I think we always evaluate opportunities for the company. We have a strong balance sheet. We have other assets to divest of overtime. We just respond -- if the opportunity is a great one, and if there's the capital to do it. We don't put ourselves in a box that we have to buy this acreage at whatever the market price is because we have enough for nice program, so I think we'll just kind of adapt to what's available.

But to the extent that what, we won't over pay for acreage and pay more than we feel like it's worth, we'll just set in ways for opportunity later. A lot of Eagle Ford is getting pretty expensive is kind of what we're seeing.

Jay and Roland and I guess final question and it's a bit more conceptual. You repeatedly state about the strength of the balance sheet, but if you look at what's gone on this year and obviously with gas prices where they are, it's not as strong of balance sheet as it was. If we are talking another $400 million program next year, and we assume looking at next 12 month strip to $4.20 today, you'll be over spending. At what point do you pull back on the reigns to maintain the strong balance sheet?

We've always told you we're not going to give up the strength on our balance sheet. Just because we used $60 million to buy Eagle Ford acreage, and we are going to close laurel, and today have zero net debt or unused all of our availability used by year end if we wanted to. I think 28% net debt to cap is not in danger zone by any means. We are a $2 billion asset based company with about $500 million unused in our credit line. That's pretty strong.

We've added 18,000 net acres and didn't overpay and didn't JV it. We could JV it. Bring in some partners. There's so many tools out there that give us flexibility that again you have to trust that we are not going to over leverage the company. I think our drilling requirements we don't have to. That's why I was telling Ray Deacon earlier, that if we need a rig and a half in Haynesville, we'll have a rig and a half, because gas prices are low.. We'll move over to the Eagle Ford, if we need one rig in Eagle Ford, that's fine. If we need two, we can do that.

I think we looked through 2011 because we should have material production growth. Like Roland said, our goal in 2011 is to protect our balance sheet. But if you protect too hard in 2011, you're going to have no growth in 2012. You're going to have no reserve additions. You've got to have a smooth landing in some predictable growth.

The 22 to 25 well carry over in 2011 is great then some time in 2012, you're going to have to be pitted against that to see how we grow in 2012. So, again, I don't think you've ever had to worry about our balance sheet. I don't think you lose any night's sleep over that. If you do, we should probably come visit with you in person.

Okay. Thank you.

And ladies and gentlemen we are out of time for our question and answer session today.

All right. Well, Keith, from Colorado, I hope you're wearing about 10 coats today because we want it to be cold in Colorado. I think Justin's question was really good one at the end about our balance sheet. Because I think if you give up your balance sheet and the market that you're in, you get up trouble.

When you get in trouble, you have off balance sheet financing and you have all kind of weird derivatives and things that you have to add and wells that you have to drill. We've not jumped in that playground yet at all. We don't plan on jumping in there.

I think our goal is to continue to decrease our cost structure continue to hold on to tier one quality acreage, continue to add to that tier one if you can. We didn't mention or discuss it. We did add 6,000 acres in tier one in Bossier at $7,500 an acre earlier this year and I think it's worth far more than that, from what some recent transactions would tell you. We're going to be careful in guiding the company and growing it. We did lower our production guidance from January of 2010 through today from the 20%, 25% down to the 11% to 15%. I don't think that's a good thing but I don't feel like we gave up too much because we're in a low gas price environment anyhow.

So to carry that over maybe have little better gas prices next year may not be a bad thing. Our goal was to always monetize our assets that are not core. They can be good assets, but if we don't develop them properly, we should sell them, which is what we do in Mississippi.. And I think the final statement is, our growth comes from organic growth. It's come from our G&G group, it's come from our reservoir group, it's come from Mack and our operations group.

It's been organic and it's pretty unbelievable that we could sell our interest in Bois d'Arc in 2008 and by the end of '09 add 325 Bcfe of Haynesville reserves at low finding costs. And by the end of this year,add more reserves than that at even lower fining costs potentially. So I think we're on the right road.

And, again, if there's any analyst or stockholders that think we're deviating from that, you don't need to wait for a quarterly conference call, you can call and we can talk about it, because we're not trying to lose any value here at all. We're trying to get stronger in a bad environment. So thanks for the hour that you've spent and the support.

Ladies and gentlemen, that concludes today's conference. Thank you for participating. (Operators Instructions) Everyone have a great day.