Comstock Resources, Inc. (CRK) Q3 2010 Earnings Report, Transcript and Summary

Welcome to the Q3 2010 Comstock Resources’ Earnings Conference Call. (Operator Instructions) As a reminder this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Jay Allison, Chairman and CEO. Please proceed sir.

Welcome to the Comstock Resources’ third quarter 2010 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and clicking Presentations. There you will find a presentation entitled Third 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 results as well as updated results of our 2010 drilling program and our outlook for the rest of this year. Please refer to slide two in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in 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 summarized the third quarter results; higher oil and gas prices 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 Bcfe. For the quarter we reported revenues of $80 million, generated EBITDAX of $55 million and net operating cash flow of $47 million or $1 per share. We had a small net 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 on 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 setback, we are anticipating strong reserved growth this year driven by our Haynesville Shale drilling program and lastly, we are maintaining our strong balance sheet and liquidity position despite the low natural gas environment we are currently in. I will turn it over to Roland Burns to review the financial results for this quarter in more detail. Roland?

Thanks, Jay. On slide 4, we break out our production by quarter and by a region. And then we highlighted new productions from our Haynesville Shale Wells in red on the chart. For the third quarter of this year, our production averaged a 187 million cubic feet of natural gas equivalent per day, which is 1% higher than the production in the third quarter of 2009 of 184 million per day. As Jay mentioned earlier, production was down to almost 15% from our second quarter average rate of 219 millions per day due to completion delays in the Haynesville Shale program. Our East Texas/North Louisiana region averaged a 134 million per day with 49 million coming for our Cotton Valley Wells and 85 million per day coming from Haynesville Shale wells. The Haynesville wells made up 45% of 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 are selling our Mississippi properties, which make up 8 million per day of the 14 million per day in our other regions and we 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 the Haynesville program. We now expect production for all of 2010 to approximate 73 to 75 Bcfe, which would represented 11% to 15% growth over 2009. Slide five 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 price increased 12% to $4.55 per Mcf as compared to $4.05 for the same period in 2009. Our realized gas prices have averaged to 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 in then none of our gas productions was hedged this year. Our realized oil prices are shown on slide 6. Our realized oil price increased 12% of the third quarter 2010 to $64.97 per barrel compared to $57.96 per barrel in the third quarter of 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 bench mark NYMEX WTI price in the third quarter. On slide seven we cover our oil and gas sales. The improved natural gas prices increased our sales by 18% to $80 million to the third quarter. For the first nine months of this year our sales increased 38% to $276 million as compared $201 million for the same period in 2009. Our earnings before interest, taxes depreciation, and amortization and exploration expense and other non cash expenses or EBITDAX grew about 17% to $55 million this quarter as shown in Slide 8. For the nine months ended September 30 2010, EBITDAX increased 47% to $198 million. Slide 9 covers our operating cash flow. Our operating cash flows for the quarter came in at $47 million, which was 33% lower that cash flows of $70 million in 2009 in the third quarter. Cash flow in 2009 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 outlined our earnings. We reported a net loss of $4.7 million or $0.10 per share, compared to a net loss of $11.6 million or $0.28 per share in 2009 third quarter. Improved oil and gas prices and the production growth account for the lower loss. For the first nine months of this year we reported net income of a $1 million dollars or $0.02 per share as compared to a net loss for the first three quarter of last year at $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 into three components, production taxes, transportation and then other field level operating cost. Starting with the fourth quarter ago last year we are transporting more of our gas from our Haynesville operations to the long haul pipelines rather than selling at the well head. It resulted in an increase in our lifting cost, which is being offset by improved gas price [relegations]. Our total lifting cost averaged a $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 increase 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 averaged $0.75 this quarter, which is the same rate as we had in the third quarter of 2009 Per forma for the sale of the Mississippi properties, our lifting costs would be reduced by $0.08 per Mcfe when those properties are out of our reported numbers. On slide 12, we showed our SG&A per Mcfe produced by quarter excluding stock-based compensation. Our general and 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 and $0.27 per Mcfe in the second quarter. Our depreciation depletion of amortization per Mcfe produced is showed on slide 13. Our DD&A rate in the third quarter averaged $2 and $0.72 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 open to lower DD&A rate. And then without the Mississippi properties, we’ll see our DD&A rate fall back another $0.04 from where it is now. On slide 14, we detailed our capital expenditures for the first nine months of this year. We spent $263 million for our drilling programs so far this year as compared to $243 million that we spent in the same period in 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 a $130 million this year to acquire [some more] acreage, $50 million we spent to acquired additional acreage respective for the Haynesville and Bossier Shale in North Louisiana and we also spent $80 million to acquired $18,000 net acres in the emerging Eagle Ford Shale trend in South Texas. Referring to slide 15, we recently announced that entered into an agreement sell our oil and gas properties located in Mississippi to privately held Petro Harvester. The sales price is $75 million in cash with the effective date of July 1st. Net production from the properties we sold averaged 1300 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 results. The sale is expected to close at December and is subject to the completion of customary due diligence by the purchaser. Based on the sales price of $75 million we expect to realize a net loss after income taxes of approximately $16.6 million earned as divestiture. Slide 16 presents our capital structure at the end of the third quarter. On September 30th we had $4 million in cash and $71 million in marketable securities on hand. We had $60 million outstanding under our bank credit facilities which has an unused borrowing base of $440 million. We also have $172 million of 6.875% senior notes and $296 million of our 8.375% senior notes outstanding for a total debt of a $528 million. Our book equities in the quarter was $1.1 billion with our net debt only 28% of our total capitalization. I will now turn it over to Mack Good for an update on our drilling program.

Thanks Roland. As you have seen on slide 17 we focused on our East Texas/North Louisiana region. Our activity in the region is focused on developing our Haynesville Bossier shale properties. We drilled 55 wells to gross 36.6 well 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 have tested 25 wells that have been completed at a per well average right of 10.4 million equivalent per day. In many of new wells as you know are being produced under our choke back program which we feel lead to higher reserved recoveries from those wells. On Slide 18 we show the number of days it has taken to drill the 74 operative horizontal Haynesville wells we 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 drilled was 50 days compared to 28 day average drill time for the last 5 wells. 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 has taken to connect each of our 47 operative horizontal Haynesville wells that are currently deploying to sales. Comstock’s average connect time is approximately 100 days for all 47 wells currently flowing to sales. Our average days from spread to sales for our first 5 wells was 96 days compared to a 164 days for our last 5 wells. Last year lack of pipeline infrastructure was the major factor contributing to the time to connect the well to sales. We overcame most of the infra structure issues and have reduced the time frame to connect the sales down as low as 49 days. Starting in the second quarter this year we began to experience very long delays in getting the wells completed. The larger frac jobs that all of the operators starting pumping in 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 drills Haynesville or Bossier Shale wells that were waiting on track. Going forward Comstock has been successful in obtaining pressure pumping and other related services, which will allow us to frac 14 to 15 wells before the end of this year with six operated rigs drilling in the Haynesville and Bossier Shale. We expect to drill another 10 wells in the fourth quarter given us an estimated 22 wells to carry over in to our year 2011. We have also entered into an agreement with the major service provider to provide us with 24 hour dedicated frac for North Louisiana operations in 2011. This dedicated crew will allow us to complete your backlog at 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 that we plan on drilling 70 wells 42.8 net to our interest, 49 of the 70 wells are operated, 41 wells are planned for Logansport and 18 are planned for the Toledo Bend North in the South regions with 9 wells in the Mansfield area. We moved one of our seven operated rigs to our new acreage in the Eagle Ford during late August and we are looking to move a second one near by June 2011. We plan on releasing another rig this month from our Haynesville program and we are considering to 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 the wells 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 have acquired 18,000 net acres to date that we feel this prospective for development in the emerging shale play, the Eagle Ford and McMullen, Karnes and Atascosa counties in South Texas. We’re focusing primarily on the oil and condensate windows in this play due to the better economics of oil versus natural gas. We hope to acquire an additional 10,000 net acres in our focus area. McMullen County to a vertical depth of 11,020 feet with a 4,091 foot lateral in the third quarter and drilled the NWR, Number 1H in Atascosa County to a vertical depth of 8,715 feet with a 5,209 foot lateral on October. These wells are scheduled for completion in November this year. We are currently drilling our third Eagle Ford shale well in Karnes County. Finally, on slide 23, we outlined what we expect to spend this year on our drilling program and on our acreage acquisitions. We currently expect to spend $385 million for drilling program to drilled 77 wells. 74 of horizontal wells, 70 of those are in the Haynesville or Bossier Shale and four are in the Eagle Ford shale. We spent $130 million so far this year for our acreage acquisitions. Our total capital expenditures were currently estimated at $515 million, if we do not required anymore acreage. We are still evaluating acre acquisition opportunities mainly in Eagle Ford and mainly have additional acquisitions planned for the year. And with that I turn it back to Jay.

Thank you Mack and thank you Roland. In summary I would prefer to use slide 24. We continue to be excited about prospects for reserve grade 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 is estimated to cost $385 million. We are focused almost primarily on developing our Haynesville shale acreage. We think our Haynesville shale program could add 400 to 500 Bcfe of proved reserves in 2010. With pressure pumping services so hard to obtain, we have not reached 22% to 25% production growth that we had envisioned early on this year in our Haynesville Shale but we still have production growth with 11% to 15%. We will carry other part of the growth in to 2011 which will allow us to reduce our billing activity in the Haynesville shale in 2011 and still have a strong production year. We are showing the development of the acreage in Eagle Ford shale and 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 go our oil part inside the natural gas liquids production in 2011. We are maintaining our inventory of billing locations and have a large inventory of drill sites in the upper and lower Haynesville Shale and Cotton Valley in East Texas in North Louisiana and in the Eagle Ford, Vicksburg and Wilcox trends in South Texas where we can accelerate when natural gas price improves We continue to maintain a very strong balance sheet with $440 million available on our bank credit facility and plan to use the I am trying to use the proceeds from our Mississippi asset divestiture to retire some of the borrowings we hade made to purchase acreage. For the rest of the call we will take questions from the research analysts who follow the stock. Please limit your questions to two or maybe 3, so that we have time to answer all the analyst questions that were asked. So with Keith I will turn it back over to you for questions.

(Operator Instructions) Your first question is from the line of Brian Corales with Howard Weil.

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

This is Mack we have about completed four wells operated wells in the third quarter. And rest of your question I am sorry had it compared to what?

In the fourth quarter you have 14 scheduled

Yes, we have got to frac these range for those 14 going forward.

Okay. And how many have you done so far?

We have done four.

Okay. And I will 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 good estimate?

A 24 hour crew can frac 4 to 5 a month, if all goes well.

Okay, I apologize, one final question, on the restricted rate program what are you seeing over the first year. Is it production falling, is it maintaining much better then what you all are doing before and what is like that total EUR stay in year one, if you have that production history yet.

Well we are still evaluating and as you may know we like to get sufficient data before we pen down some numbers but I can tell you this the EURs that we’re saying in our choke back program are 20% to 30% and in a few cases even higher then that, especially in our Logansport and Mansfield area. So our original guidance is 5 Bcf cost of play. You can estimate that reserves from the choke back program. So far the data is indicating that those results are going to jump by 20 to 30%.

Your next question comes from the line of Jack Aydin with Keybanc

Roland on the third or fourth quarter production the you lowered the growth rate from 15% - 18% to 11% - 15%. Is that for the assets sale? Did you bake in assets sale in those numbers?

Well we didn’t. We didn’t reflect the asset sale because that would ahead of our numbers in the month of December, but its must also reflect the third quarter rate being low and it’s only a limited amount of time to really catch up in production. I think we have strong production in November, December. October, production was not too different with the third quarter averaged. And so, the completions are picking up again but 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 and in the fourth quarter we a nicer fourth quarter. But, just didn’t have enough productions in the third quarter to get us to the top end of our guidance we’d 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 Haynesville?

Jack, I’m not going to lay on the line this morning and say, we’re going to go to two rigs in the Haynesville and guarantee you that. We are 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 reach 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 put together is offering a lot of opportunity and we’re considering reallocating our resources in that direction exactly. How many of those resources is yet to be determined.

My final question is, what is the average cost per well running for you to complete that goes in the Haynesville in today’s environment?

Right now, it’s about 9.5.

Your next question comes from the line of John Freeman of Raymond James.

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 I think John, I think we are estimating to drill may be one or one more well like additional well in the Haynesville just because of the quicker drilling time and then I think anything on the number would be there is, its really when do you consider ready for completion the very second that the drilling leaves they are not ready to be completed. So it’s kind of a couple of weeks there, a preparation for a completion and I think that’s probably part of the difference there too. So we would have 22 wells definitely ready for completion but we probably have three or four other wells that would be already drilled that will also be carried into next year, so it’s just a slightly definitional difference.

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

There is always going to a little hard and quiet ready to start completion on just in the 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 sort 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 a 60 to 70 day cycle time would be our goal, 60 days with 35 to 40 days to drill another 20 to 30 to get the wells completed but we have 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?

Well we are doing that now, the back story on that is in some areas of Haynesville you may not want to pump at a lower rate. It depends on exactly what kind of stage you are, what size the stage is, how much profit you are putting away etc. but we are currently fracking wells in our Logus Port area, that’s part of the 14 to 15 wells we plan to frac before the end of the year, at that lower rate and it is working quite well, no problems.

Your next question is from the line of Kim Pacanovsky with MLV.

Good morning gentleman. This 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 these 14 or 15 wells actually getting completed?

Very,

Very, I can take that to the bank.

Yes.

There are three shifts per frac crews Kim that will be fracking these wells. Anyway, we have separate group, which is a dedicated contract. So we are in very good shape.

Okay great and how many of the Haynesville rigs that have expiration coming up and I guess one now, one December, one February, one March. Could all of those go to the Eagle Ford or any of them lower quality rig that you wouldn’t want to keep?

We believe that all but one could go to Eagle Ford 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?

Well we were drilling in Logus port which is in the Mansfield area as-well-as the upper Bossier in our Tolledo Bend area, its extremely low. We are profitable down into the twos.

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

Your next question comes from the line of Noel Parks with Ladenburg Thalmann.

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?

Well we participated in our wells with our Aboco in Ball Ranch as previously mentioned and the other wells was a Granite Wash Well they would participate in and as a partner. Do you need any more specific information?

No. That was generally what I was looking for. 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 the 10 million a day number is a very reasonable number.

Even with the choke back?

Yes. Absolutely.

Okay.

We’re saying 10 to 12 nos.

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

Hey. Jay, I was wondering, can you talk a little bit about how active you think you’ll be in the Eagle Ford and potentially how you could fund more acreage purchases there going forward?

Ray, you know what we’ve done, throughout this year we’ve added the 18,000 net acres. We probably have 42, 43, $100 an acre invested in that. So if JV it 10000, 11000, 12000 odds acres probably $100 million of profit share. So I think our cost basis is right. Again do we operate all of fully owned with a 100% working interest in and it’s the same G&G group that helped us in the Haynesville and we started drilling in the third and fourth quarter of 2007 and really the first quarter by we relied upon and that will lead to start leasing acreage than what we thought. Probably this year it was they went out. We have avoided JV in any of the Eagle Ford. We are avoiding JV in any of the Haynesville so far. We think we know the value of the Haynesville and I think if we were to bring in a JV partner it would be because we have added material acreage in the Eagle Ford, because we don’t under stretch our balance sheet we want to keep it strong. I think if you look at what we try to do. In the second quarter, we didn’t put a press release out when were in the Eagle Ford which as we told you on the second quarter conference call, we have added 18,000 net acres. We are now attempting to add another 10,000 acres at a quality that we were to operate. As far as rig commitments, when you drill wells in the Eagle Ford, you do give up reserves, you give up rate and you do add materially to your return on your investment but you give up two things and so when we looked at Eagle Ford we said well, the Haynesville is in a position by the end of December we thank the we will completely understand the lower Haynesville, and I think we need drill some more wells to understand operating up in the Boucher. But if we keep a rig and have no more than two rigs busy in the Haynesville we can satisfy any drilling requirements that we have companywide, in all East Texas and North Louisiana. And that brings us up quite a bit to shift those rigs to out next year to the Eagle Ford. And I think if you say $80 - $90 oil I have got say that this goes back to what Jack had asked earlier and actually what Kim had asked, I think we see us doing is once we have taken care of transportation issues it goes to shifting the rig out to the Eagle Ford and if we need to shift one, two, three rigs there whatever, I think we will be able to do that. I don’t think we will be forced to do that because of lease obligations. We would do that because of the rate of return and we would end up by kind of doing to the Haynesville what we did beginning of 2009 to the Vicksburg, Wilcox and the Cotton Valley program we went into all of those programs, if take this company and go back 15 years from January of ‘09 we just drilled vertical wells and in really those three formations and we’ve probably drilled less than 10 of those wells since January of ‘0 9. So we inventoried all those. And I think we’d take the same attitude if you got very low gas for us and we’d feel very comfortable with the quality of our Haynesville acreage and those just kind of inventoried that and we will add some dollars if we were to use to drill the Haynesville, we will shift them over to the Eagle Ford acreage for the Eagle Ford program. And what is nice is in years and years we have not really incurred any net debt. We have kept our strong balance sheet. We kept $0.5 billion dollar now we’ve did go rolled it. We are using about by 60 million, we used 60 million on our credit facility this quarter, but we also told the world to get $75 million of divestitures and we also have another$ 70 million to $80 million of common shares that we monetize at any giver time. We look at that when we look to see whether we incur any net debt or not, but I think when debts are added toward the program, no one knows if gas prices will rebound. I think they have got symptoms of rebounding. But we've put ourselves in a position where we don’t have to mandatorily drill a lot of wells. We don’t have bunch of rigs that we format to somebody. We don’t have a JV partner that will force us to drill wells where we really shouldn't be drilling. And I think one of the greatest things in all of this is, no matter what business you are in, you need to be the low cost producer. And our charts show us that we're one of the lowest cost producers in that be E&P world. And we haven't issued any equity in almost six years. So those are all the quality things and finally I would look into where the acreage is, whether it's in the Eagle Ford or the Bossier or Haynesville, I think most of it is quality tier 1 acreage and then, you're thankful we're not trying to divest yourselves of any of the Gulf of Mexico assets. We were forced to that at the end of ’08. So I don’t 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 Eagle Ford.

Got it. Thank you very much. Could I ask Mack, I was curious, across the three areas of Atascosa, McMullen, and Karnes, how different do you expect the wells to be from an EUR and return standpoint?

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

Got it. Great. And would you release results for the three wells before fourth quarter earnings?

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

But, we don’t plan to do well-by-well, but these two are Eagle Ford and on Haynesville wells. I think that’s a mere practice for companies to follow.

Your next question is from the line of Don Crist with Johnson Rice.

Can you, with the large backlog, a wells which are going to ship in to 2011, despite the less drilling that you’re going to do. Can you talk about your production growth compare to this year, the 11% or 13% that you’re projecting for 2010?

We felt like that our production growth will be stronger next year than this year just carry over wells in the next year good and get that in to our program will benefit 2011’s production versus 2010’s. So we do think to be stronger than the upper range of our guidance this year and what be kind of term our final allocation of rigs between the Eagle Ford and the Haynesville and the number of rigs that will run which would do typically we get that approved and so at that point we are going to come out with some guidance but we do see strong production here next year and we are looking to see if we can lower our capital spending to, so we can overall bring our total capital expenditures closer to what the cash flow could be with the lower gas prices that seem to be expected for next year.

Well that’s a great thing you got. You’ve got 22 plus wells at a carry forward and we thing they are in tier one locations in the Haynesville and the Bocher. We are looking at 10 million to 12 million a day. Our fee rates is our gas and we own probably 75% of that. So we are going to kind of be honest and springboard it to be in 2011 and as Kim had mentioned earlier we do have a dedicated crew just to complete those wells throughout all of 2011 and I think it will be much more predictable and the growth will be a more predictable on a quarterly bases.

And 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 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?

For 2011?

2011, your original expectations for ’10 were, 20% to 25% growth.

We have the wells achieved that in next year end, lot of that even 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 sequential decline you saw third quarter versus second quarter is that a pretty good representation of what’s your basic decline rate is if you are not completing any many new wells I guess? Is that 50%?

What influenced that is that well of course was the choke back program. And, we were monitoring the pressures versus rates on a number of our Haynesville wells and adjusting the choke accordingly. So that had an impact as well.

Remember Ron when we reported the second quarter, we had about 9 to 10 million a day of that production that was really a production from increased ownership interest in wells that we came back and after we had on some of that early in Haynesville wells that determined that we had a little higher interest and when they finally finished all that title work on those wells there was about 8 to 10 million a day of the second quarter production that was production that was attributable to earlier in the year and so that also kind of made that decline of almost 15%, they kind of exaggerated it a bit. But I think that decline would be softer with the new choke back program that went out with that kind of adjustment in it.

Absolutely.

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

Good morning. Just to double check on the Haynesville, if this lower choke back decline rate it. If this would have been complicate the normal rate what IP rate than could we have seen.

A lot of the wells would have been 18 to 20 Rehan at this time.

18 to 20, Eagle Ford, good progress in terms of continuing to reallocate capital, are we thinking about any another particular areas that seem to be of interest or any sales plays that and anything like that you are working on

Rehan, I always tell people we shop all the time and everybody knows we bought, unlike the Haynesville and kind like the Eagle Ford.

Geologically speaking anything in particular that stands out that would be worth thinking about no particular play per se. But geologically speaking, anything that fits into your [thoughts]?

Our states are Texas, Louisiana, Mississippi. So it’s geologically within those three states.

Your next question is from the line of Justin Tugman with Perkins Investment Management.

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?

Hi Justin, its very early and we are still are running different models and go to our board and then continue to look at the outlook for 2011 to decide, but we can tell that the framework is basically where as far as the rigs that we have, we will write a program that’s a minimum of three rigs and probably a maximum of five rigs. And so that’s the range. We will carry over the well to be completed, all the wells drilled and including the ones we have to complete right away. Its roughly maybe 25 wells and if cant complete it we have got the crew to frac that out. So that’s the completions of 4 million to 4.5 million plus per well. But that’s the large dollars that would be kind of the base .So our guess the range is anywhere from $350 million at the minimum to $500 million.

Okay. I'm sorry. You said the completions you're waiting on figure about $4.5 million. Has more acres and calling a good and may be (Inaudible) to 2011.

Right.

Okay.

It’s not a big component of it even with the lower rig, it’s not a big component cost that we will have to carry into next year. But that will also be a driver of the strong production growth next year with that I would have to spend the full amount for the well about $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.

Well. We don’t have anything definitive right now. But we do have, we have thing we are interested in. but we are very particular about the price we’ll pay and this is going to fit our what we felt is worth but probably we’re now putting to highlight that by a adding a lot of more acreage this year that when we didn’t include in our estimate. So, because there’s only a couple of months left and so there is nothing pending. So, even typically if we were to start they might not even close this year, because we are now. So, I think the 515 is our best estimate on what we think we will actually spent this year. And then, even though, kind of if we identify another track of acreage if 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?

What, I think the way, always evaluate opportunities for the company and so, we have a strong balance sheet, we have other assets to divest over time. So, we just respond to that if the opportunities is a great one, there is the capital to do it. We don’t put ourselves to the box that we have to buy this acreage whatever the market price is, because we have a nice program. So, I think we just kind of adapt what’s available. But, to the extent that we won’t overpay per acreage and pay more than we felt like its worth, we just don’t sit and wait for opportunities either. Eagle Ford was at first was getting pretty expenses, is kind of what we’re saying.

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?

Well we always thought we are going to give up the strength of our balance sheet I think just because we used $60 million a buy Eagle Ford acreage and. I think 20 offset net debt to cap is not in a danger zone by any means. But a $2 billion asset based company with about $0.5 billion unused credit line is pretty strong and we’ve 18000 net acres and didn’t over play and didn’t JV it bringing some partners. I mean there is so many tools out there that give us flexibility. Again you got trust that we are not going to leave up the company and I think as for our drilling requirements we don’t have to. As far as selling rates we told earlier that we are going to need our rig, half in Haynesville and have a rig and a half because gas prices are low we will move over to Eagle Ford. We need one rig in Eagle Ford and Haynesville we need two. We can do that I think we look towards 2011 because we should haven’t material production growth and like Roland said our goal in 2011 is to protect our balance sheet, but if we protected to 2011 you will have no growth in 2012. We are going to have no reserve adds. So you got to have smooth landing and some predictable growth. The 22 to 25 well carryover in 2011 is great but then sometime in 2012 you going to have be prepared again you have to see how they grow in 2012. So again I don’t think you ever have to worry about our balance sheet. I don’t think you loosing that sleep on that. If you do then, I will come visit you in person.

And ladies and gentleman we are out of time for our Q&A 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 a really good one in the end about our balance sheet because I think you give out your balance sheet and in the market that’s when you are in trouble. When you get into trouble, all balance sheet and the financial things and you have all kind of weird derivatives and things that you have to add. And wells that you have to drill and we've jumped in that play ground yet at all and we don’t plan on jumping in there. I think our goal is to continue to decrease out cost structure and continue to hold on to tier one quality acreage, continue to add to that tier one if we can we didn’t mention it but discuss we did 6000 acres in tier one in the Bossier. We paid about $7,500 an acre and it think its worth far more than that from what’s the recent transaction would tell you but we are going to be careful in guiding the company and growing it. We did lower our production guidance from January 2010 to today from the 20 – 25% down to the lower to the 15% I don’t think that’s a good thing but I don’t feel like we gave up too much because we are in the low pricing environment anyhow. So to o carry that over maybe have little better gas prices next year that might not be a bad thing. Our goal was to always monetize our assets that are not core, they could be good assets. But if we don’t develop them properly we should sell them which is what we are doing with Mississippi And I think the final statement is, our growth just come from organic growth. It didn’t come from our G& G group, it's come from reservoir group. It's come from a our operations group and its been organic and it's pretty unbelievable that we can sell our interest in Bois d'Arc in 2008 and by the end of the 09 bought 323 Bcfe of Haynesville reserves at much lower planning cost. And by the end of this year booked more reserves than that at even lower planning cost potentially. So I think we're on the right road. And, again, if there's is any analyst or stockholders that think we are deviating from that, you don’t need to wait for call a conference call, you can just call, We can talk about it because we are not trying to loose any value here it all. We are 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 you may now disconnect. Everyone have a great day.