Comstock Resources Inc (CRK) 2009 Q3 法說會逐字稿

Good day, ladies and gentlemen and welcome to the third quarter Comstock Resources earnings conference call. I will be your operator for today. at this time all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of today's conference. (Operator Instructions) I would now like to turn the call over to your host, Mr. Jay Allison, Chairman and CEO. Please proceed.

Thank you and welcome to the Comstock Resources third quarter 2009 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 2009 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 2009 third quarter financial and operating results as well as update the results of our Haynesville shale focused drilling program. Our discussions today will include forward-looking statements within the meaning of Securities law. While we believe expectations in such statement to be reasonable there can be no assurance that such expectations will prove to be correct.

Please refer to slide two of the presentation where we summarize the third quarter results. Low oil and gas prices in 2009 have caused a reversal from the record-setting profits of last year. For the third quarter we reported revenues of $67 million, and we generated EBITDAX of $47 million and operating cash flow of $70 million, or $1.50 per share. The operating cash flow includes $26 million in tax refunds that the Company expects to receive. The low prices caused us to report a loss of $13 million, or $0.28 per share. Despite the low oil and gas prices we're having a very successful year with the drill bit. We drilled 38 successful wells including 28 horizontal Haynesville shale wells, three horizontal Cotton Valley wells, three vertical Cotton Valley wells, and four high rate south Texas wells. The Haynesville shale results in Louisiana have gotten stronger.

Several of our most recent wells in Logansport and Mansfield completed in the third quarter had initial production rates over 21 million cubic feet equivalent per day. On October the 9th we completed a public debt offering where we sold $300 million in new 8 3/8% senior notes due in 2017. As a result of the offering we repaid all of our bank debt and have $127 million in cash on the balance sheet. Combined with the investment in stone common stock and our unused $500 million bank credit line, we have over $700 million in liquidity. I will turn it over to Roland to review the financial results in more detail. Mr. Burns.

Thanks, Jay. On slide three we break out our average daily production by region and we highlight the production from our new Haynesville shale wells in red. In the third quarter our production averaged 184 million cubic feet of natural gas equivalent per day which was 13% higher than our production in third quarter 2008 of 163 million per day. Production was also up from our second quarter average rate of 169 million per day as our Haynesville wells are now making a significant contribution to our rate.

Our east Texas and north Louisiana region averaged 116 million per day with 60 million coming from our Cotton Valley wells and 56 million coming from our Haynesville shale wells. Our south Texas region averaged 55 million per day and our other regions averaged 13 million per day in the quarter. We expect our fourth quarter production rate to slightly exceed 200 million per day which would give us production for 2009 of around 65 Bcfe representing a 12% growth over our pro forma production in 2008.

Oil prices in the third quarter were down significantly from last year as shown on slide four. Our average oil price decreased 45% in the third quarter of 2009 to $57.96 per barrel as compared to $105.15 per barrel in the third quarter of 2008. Our oil price in the third quarter averaged 85% of the average NYMEX WTI price. For the first nine months of this year our average oil price was $46.42, 53% less than our average oil price of $97.74 for the same period in 2008.

The most significant factor impacting our financial results this quarter were low natural gas prices as shown on slide five. Without considering our hedges, our average gas price decreased 69% in the third quarter to $3.17 per Mcf as compared to $10.37 in the third quarter of 2008. Our realized gas price was 94% of the average Henry Hub NYMEX price in the third quarter. For the first nine months of this year our average gas price decreased 64% to $3.57 per Mcf as compared to $9.83 for the same period in 2008.

Slide 6 shows our average gas price with the impact of our hedges. We had 10% of our gas production hedged in the quarter which increased our realized gas price to $3.63 per Mcf. For the first nine months of this year our average price with the benefit of hedging was $4.05 per Mcf. For the fourth quarter, approximately 9% of our gas production is hedged at $8.20.

On slide seven we cover our oil and gas sales. The lower prices caused our sales from continuing operations to decrease 59% to $67 million in the third quarter as compared to $164 million in the third quarter of 2008. For the first nine months of this year our sales decreased 57% to $201 million as compared to $464 million for the same period in 2008.

Our earnings before interest, taxes, depreciation, amortization, exploration expense and other noncash expenses, or EBITDAX, decreased 66% in the third quarter to $47 million, as shown on slide eight. For the nine months ended September 30, 2009 EBITDAX decreased 65% from 2008's level to $134 million.

Slide nine covers our operating cash flow. Our operating cash flow for the quarter came in at $70 million at 47% decrease as compared to cash flow of $133 million in 2008's third quarter. Operating cash flow in the quarter was increased by current income tax benefit of $26 million. This large tax benefit is the result of a tax planning strategy we adopted which will provide a refund of some of the taxes we paid last year, and is also the result of some refunds from recently completed IRS audits of other prior years. For the nine months, for the first nine months of this year operating cash flow came in at $157 million, which was 56% less than cash flow of $359 million for the same period in 2008.

On slide 10 we outline our earnings. With the very low oil and gas prices, we reported a net loss of $12.6 million or $0.28 per share this quarter as compared to $54.8 million and net income of $1.18 per share in 2008's third quarter. The net loss for first nine months of this year was $29.7 million, or $0.66 per share as compared to $154.6 million in net income, or $3.36 per share in 2008.

On slide 11 we show our lifting cost per Mcfe produced by quarter. Our lifting cost decreased to $0.94 per Mcfe as compared to $1.44 per Mcfe in the third quarter of 2008. Lifting costs also decreased by $0.20 from the second quarter rate of $1.14. The decrease is a result of the lower cost Haynesville production which is now making up a larger percentage of our total production. Production taxes accounted for $0.11 of the $0.94 in total lifting costs this quarter as compared to $0.41 in the third quarter 2008 with the higher oil and gas prices.

On slide 12 we show our cash G&A per Mcfe produced by quarter. Our general and administrative costs increased to $0.28 per Mcfe as compared to $0.26 per Mcfe in the third quarter 2008. G&A costs decreased by $0.06 this quarter from the second quarter rate of 0.34. The decrease is a result of the higher production level that we now have.

Our depreciation, depletion, and amortization per Mcfe produced is shown on slide 13. Our DD&A rate in the quarter averaged $3.17 per Mcfe, slightly higher than the $3.06 rate that we had in the third quarter of 2008. Our DD&A rate this quarter decreased $0.13 from the $3 .30 we averaged in the second quarter. The lower finding costs of the Haynesville shale wells are starting to cause an improvement to our DD&A rate.

Slide 14 presents our capital structure at the end of the third quarter and on a pro forma basis for our recently completed bond offering. At the end of the quarter we had $90 million in cash and marketable securities on hand, $340 million of total debt including $175 million of our existing 6 7/8% senior notes and $165 million outstanding under our credit line.

On October 9, we completed a public debt offering where we sold $300 million of new 8 3/8% senior notes due in 2017. Adjusted for the sale of notes we would have $214 million in cash and marketable securities on hand, $475 million of total debt including the $175 million of our existing 6 7/8% senior notes and $300 million of a new 8 3/8% senior notes. We repaid all of our bank debt, and our borrowing base for our credit facility was recently reaffirmed at $500 million. Taken into account our cash on the balance sheet and our marketable securities, and the unused $500 million bank line, we have over $700 million in liquidity. Our book equity at the end of the quarter was $1.1 billion, making our net debt only 17% of our total capitalization.

On slide 15 we detail our capital expenditures so far in 2009. We spent $254 million in the first nine months of this year for our drilling program as compared to the $309 million that we spent in 2008's first nine months. We spent $220 million in our east Texas, north Louisiana region, $33 million in south Texas, then less than $1 million on our other regions. I will now turn it back over to Jay.

Roland, thank you. On slide 16 we focus on our east Texas north Louisiana region. We drilled 34 wells in this region in six different fields for the first nine months of this year. All of these wells were successful. 31 of these wells were horizontal wells. We have tested these wells at a per well average rate of 11.1 million cubic feet equivalent per day. The horizontal wells averaged 12 million per day and the vertical wells averaged 1.6 million per day.

On slide 17 we have updated our leasehold in the Haynesville shale play in north Louisiana and east Texas. Our acreage is highlighted in green. We currently have 85,000 gross acres and 72,000 net acres that we believe are prospective for Haynesville development. 50,000 net acres are in Louisiana and 22,000 net acres are in east Texas. Given expected well spacing of 80 acres and an expected per well recovery of 5 Bcfe per well our acreage could have 3.4 Tcfe of reserve potential.

On slide 18 we outline our holdings in the emerging upper Haynesville or Bossier shell play. We currently have 51,000 gross acres and 45,000 net acres that we believe are prospective for upper Haynesville development. Given expected well spacing of 80 acres and an expected per well recovery of 5 Bcfe per well, our acreage could have an additional 2.1 Tcfe of reserve potential.

On slide 19 we show the latest plan on where we now plan to drill the 41 plant Haynesville shale wells. Four other wells are in Texas, in the Waskom and Blocker fields. 37 of the wells are to be drilled in the more prolific part of the play in north Louisiana. 23 of the operated wells have been completed and are now producing over 80 million cubic feet of natural gas equivalent per day net to our interest. I will have Mack Good, our COO go over these wells. Mack.

On slide 20 we show the results of our first 24 Haynesville shale horizontal wells. Since our second quarter conference call we have completed 10 successful operated Haynesville shale horizontal Wells in De Soto parish in north Louisiana. Five of these are in our Toledo Bend North field, four in the Logansport field, and one is in the Mansfield field. These 10 wells were tested at an average initial production rate of 14.5 million of natural gas equivalent per day per well. These results were 14% higher than the seven wells reported with the second quarter results. In Toledo Bend north, we drilled five successful wells. One in each of sections 5, 6, 8, 9, and 17. These wells initial production rates ranged from 9 million to 10 million per day. In the Logansport field, the Caraway # 3 well was drilled to a vertical depth of 11,103 feet with a 4,181 lateral. The well was subsequently completed with 10 frac stages and was tested at an initial production rate of 21.1 million per day. The Collins 15 # 2 well was drilled to a vertical depth of 11,239 feet with a 3680 foot horizontal lateral. The well was completed with 10 frac stages, and subsequently tested at an initial production rate of 21.9 million per day. Comstock has 100% working interest in both of the aforementioned wells.

We also drilled the Miller land # 1, and it was drilled to a vertical depth of 11,523 feet with a 4,190 horizontal lateral. The well was completed with 10 frac stages and subsequently tested at an initial production rate of 15 million per day. We have a 63% working interest in this well. Also, in the Logansport field the Brown number one well was drilled to a vertical depth of 11,491 feet with a 4,254foot horizontal lateral. We completed this well with 12 frac stages and tested the well at an initial production rate of 15.7 million per day. We have a 76% working interest in this well.

In the Mansfield well, the RLS # 1 well was drilled to a vertical depth of 12,317 feet with a 4,398 foot horizontal lateral. We completed this well with 10 frac stages and tested it at an initial rate of 20.6 million per day. We have an 81% working interest in this well.

Following on slide 21, we show the number of days it has taken to us drill the 24 horizontal Haynesville wells to date. Our average drill time for all 24 wells drilled to date is approximately 43 days. Our average drill time for our first four wells in the play was 51 days compared to 38 days for our last four wells. Our goal at Comstock is to achieve a 35-day average drill time.

On slide 22, we show the number of days that it has taken to connect each of our 24 horizontal Haynesville wells currently flowing to sales. Our average connect time is approximately 105 days for all 24 of these wells currently flowing to sales. Comstock's average days from spud to sales for its first four wells was approximately 130 days as compared to 72 days for our last four wells. A marked improvement.

On slide 23, we outline what we expect to spend in 2009 for our drilling program. We now expect to spend approximately $355 million, including $10 million to acquire new leases. Cost to drill and complete our Haynesville wells have fallen since the beginning of the year which has allowed us to drill more wells than was anticipated in our original 2009 budget. We now expect to drill 52 gross wells or 38.4 net wells in 2009, including 41 gross or 30.6 net horizontal Haynesville shale wells. With that I'll turn it back over to Jay.

Thank you, Mack. This is the final slide. If you'll go to slide 24, we'll show you the 2009 outlook. We're very pleased with how 2009 has developed so far this year, despite the low natural gas prices that we've received. Our 2009 drilling program estimated to cost $355 million, has focused on developing our Haynesville shale acreage. Our recent results in north Louisiana have been outstanding and have exceeded our original expectations for this play. The establishment of the upper Haynesville, or Bossier shale as a commercial play is also very exciting and adds additional reserve potential to our existing acreage.

Our recent debt offering allowed us to repay all of our bank debt and provides us with over $700 million in liquidity. We're well positioned for future growth when gas prices improve for a large inventory of locations in the upper and lower Haynesville shale and Cotton Valley in east Texas and north Louisiana and in the Vicksburg and Wilcox trends in south Texas. We are currently planning for 2010. With our strong balance sheet and the outstanding results, we're having in the Haynesville shale, we have a clear path to developing strong reserve and production growth next year. With that, I will turn it back over to you for questions. Thank you.

(Operator Instructions) And your first question comes from the line of John Freeman with Raymond James.

Good morning, guys.

Good morning.

First question I had, when I'm kind of looking at 2010, you will be entering the year with about six rigs. If you assume you kind of drill roughly 50 Haynesville wells, with that kind of a rig count, how should I think about the Bossier or upper Haynesville? In terms of, of that mix how many wells do you think you will be testing in the Bossier?

Initially, John, the vast majority of the wells will be lower Haynesville. We have not put together our 2010 budget so far. We have said we have six rigs right now we operate that are drilling Haynesville shale wells, and we'll keep those six rigs through next year is our goal as far as initial look at the 2010 budget. We also said we might add a 7th rig depending on commodity prices. Then as far as wells that would specifically target upper Haynesville, I will let Mack address that now. Although, John, we have not approved a budget or a drilling program for 2010, so this would still be speculation, okay?

Understood.

Obviously we have significant acreage position in the upper Haynesville to test. We're excited about that opportunity. We'll be spudding our second upper Haynesville test before the end of the year. We're still evaluating and assessing the exact number of upper Haynesville wells that we want to spud next year in various parts of our Haynesville acreage footprint. But we are definitely going to drill a few upper Haynesville wells, coupled with our lower Haynesville program. The exact number I can't give you because we haven't developed that yet, but certainly we're going to drill more than we have this year, which is two.

Okay.

Remember, as we drill the lower Haynesville, John, I mean, we'll be able to log the upper Haynesville, and we're pretty confident that probably 60% of our acreage in the Haynesville shale holds this upper Haynesville potential, and that's at 45,000 net acres. And that's at 2.1 Tcfe. So we'll in a very professional manner develop that. We don't want to drill up when, in fact, you would have to drill the lower to hold the acreage anyhow, so we'll factor that in.

The one area at least looking at the Haynesville and Louisiana that there hasn't been as much activity on your acreage is in Toledo south. Mack or Jay, any idea when you get some results in that area?

That will be early in the first quarter of next year. We're going to spud the first well -- our first well in Toledo Bend south sometime this month.

Then just looking at the overall completed well cost, kind of what -- guidance has been, I believe your first rig comes up for repricing in December, is kind of the way to think about it even if the rig count rebounds and we get a slight uptick in maybe completion side of the equation that the lower kind of rig rate probably offsets that?

Yes, sir, we think the $7 million to $7.5 million drill and complete cost for horizontal Haynesville is a reasonable range.

Excellent. Last question, I'll turn it over to somebody else, Mack, how much of the science do you think is still going on in terms of initially we were look at trying slick water versus gel, different lateral lengths, frac stages, do you feel like you kind of are at the point where you've got it down and there's not much science left?

No, I don't feel that way at all. I think the Haynesville play is so large, it has such an extent, and in various parts of the play, there's the upper versus the lower, that operators are still approaching the development of the Haynesville in a scientific way. There's a lot of data that's being gathered. A lot of that data is still being analyzed. I will give you an example. The idea of longer lateral lengths and the orientation of those laterals, where to place them precisely in the Haynesville section that you're targeting, and then what size of fracs to put on those longer lateral lengths, meaning what kind of loading concentrations, how much fluid to pump, what kind of perforating orientation and clusters, meaning the density of the perforations per stage. And then the other thing that is kind of coming to the forefront here is the geo mechanics. What kind of rock attributes are we talking about here that guide the design of the fracs. So roll that all up together, the various studies that were initiated at the beginning of the year are still ongoing. There's a lot of data being pumped into those studies and we've come a long way. We're way up the learning curve, but obviously, and I will use the Barnett as an example, certainly took the operators in the Barnett a few years to guide their designs to where it was pretty much a straightforward procedure that everyone adopted, and we're some distance away there that in the Haynesville.

Great, I appreciate it. Thanks, guys.

Thank you, John.

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

Good morning, guys.

Hi, Leo.

Hey, curious to see if you have any current or plan for the near future activity in Shelby County. There's been a lot of industry wells in that area.

No, sir, not at this time. We're currently assessing a variety of areas in the play to focus on. We have joined with some other operators in an AMI. We've contributed our acreage to that it's in a non operated position. But we'll be probably drilling in that AMI in a nonoperated position next year, with our acreage contribution.

You're specifically referring to Shelby County here?

Right.

Okay. I didn't hear the entire call but I think you guys had mentioned a number, about 5 Bcf EURs in the Haynesville. Is that an average across your acreage in terms of what you've seen thus far, and is that number higher at Logansport?

That's an average for us. We, as you know, we've been fairly conservative from the very start with our EURs. We want to see sufficient production data to support the EURs that we put out to the public. So we're using the 5 Bcf as a foundation or a platform EUR across the play. But certainly in Logansport we're seeing higher EURs, and across our acreage footprint there.

We've given, as far as EURs. We've given the Louisiana side a higher number, Leo, than the Texas side so far.

Okay. Could you remind of us how much acreage you do have in Shelby County, what you guys contributed?

It's approximately 2,500 acres or so.

Okay, thanks, guys.

Yes, sir.

Your next question comes from the line of Sven Del Pozzo, of CK Cooper.

Your comments on DD&A rate, I was just wondering what kind of internal reserve measures are you using to come out and say that the depletion rate is relatively lower? Were you talking about the unit finding and development costs, or both, for that matter? I'm just kind of wondering kind of reserve numbers to have in the back of my head to kind of understand had what you guys are getting at?

Yes, this is Roland. What we use for the DD&A rate is mostly the proved developed reserves for new wells drilled. We haven't seen the impact of the reserves we might add by the end of the year but we are seeing now that more production is coming from certain fields, mainly Logansport and Toledo Bend North. Those fields have generally just lower historical finding costs than maybe some of the fields that contributed production before so that's more a result of not so much of a lot of reserves really getting booked on the Haynesville, it's more of a result of the production coming from certain fields because our DD&A calculation as successful efforts company is done on a field by field basis. So each one is done separately.

All right.

We expect the trend as reserves are added in Haynesville to continue to drive down that DD&A rate as our finding costs expected to be significantly lower this year than they have been in the past.

Okay. And looking back a second, your operational update before, a few weeks ago, I'm trying to figure out which of the wells that you've got on slide 20 are the newest ones in the 20 million cubic foot IP range. Is it perhaps Colvin Craner # 2H, the lower part of the Logansport? Is that a newer one?

That was not a newer well. I think we reported that well in the second quarter. I think the wells that were -- if you look on slide 20, the newest wells would be the Collins 15, # 2, that one had a 22 million a day IP. That's at Logansport. The RLS # 1H, which is number 14 on that slide, is in the Mansfield field, and 21 million a day IP. Those are probably some of the newer highest volume wells we reported.

Okay. And just for a sense of the balance of cost, CapEx, for your wells in the Haynesville, aside from the day rate, if you could tell me both, how much money are you saving when you drill in fewer days? If you could tell me the day rate there. Also what about the rest of the well cost, like steel and tubulars?

This is Mack. Our average day rate on our rigs is approximately $24K per day. So that will give you an easy way to get to the arithmetic on cost savings but it's more than just a day rate. It's what we call the spread rate. It's all the rental equipment that goes with a drilling operation, including down hole drilling tools, rental equipment, various labor, supervisory time, etc.. So we estimate with every day that we cut off of the drilling time we save approximately $50,000 per day.

In terms of overall costs, certainly service costs have come down. The cost of fracing the Haynesville well a year ago was about two and a half times the current costs. Current cost is anywhere from $1 million to $1.5 million. The cost of everything has come down, obviously. Pipe has stabilized. We're starting to see a little up tick in certain grades of pipe. An earlier question today was the question concerning the science in the play, etc.. Well, the other thing that follows is the change in the tubulars, the grade of tubulars, how those casing strings and tubing strings are set etc.. The bottom line that I'm going for is that the costs have come down. I think we've squeezed just about all of the costs out of the equation, with regard to service and materials. Now the additional cost savings come from operational efficiencies.

Thank you. So it seems like your dramatic decrease in unit lifting costs isn't just driven by production growth, it's also the actual costs?

That, in part, but certainly going forward it's going to be the production growth and the efficiencies that we bring to the table in improving our drill time and our drill to sales.

Thank you, gentlemen.

Yes, sir.

Your next question comes from the line of Ron Mills from Johnson Rice.

Couple questions. I think, Jay, you mentioned the Haynesville production is currently at 80 million a day versus the third quarter average of 56 million a day. Is that following the hook-up of those three most recent wells, or does that include the impact of really all 10 of those during -- that you put in your ops update?

That's 23 wells that are netting us that 80 million a day.

With your six rigs, it sounds like you have a number of wells in progress. Are some of those already drilled awaiting completion or are they really all in the drilling stage at this point?

We have a few wells waiting on completion. At the end of this week we'll have three wells, in, waiting incompletion. And two of our rigs will be skidding to new projects.

Okay. And as you look ahead to year end, I know, Jay, you had talked earlier in the year about the Haynesville program this year being more of a reserve growth than a production growth, although the production is showing nice growth. Based on your 30 net wells, I think at one point you had talked about potential bookings from the area of 250 plus Bcfe. Is that still in the fairway, or how much could that be impacted by the use of average gas pricing this year?

Number one, Ron, that's a great question. If you go back to the beginning of this year, we said that production growth might be 5%, because we didn't really know, because we were discontinuing a very successful Cotton Valley program that we had accelerated in '07 and '08. We probably drilled a couple hundred Cotton Valley vertical wells in those two years. That's when we had the 27% production growth in '07, 32% growth in '08. But then we knew that we would discontinue that program because there was 250,000 net acres that was held by production that we didn't have to drill Cotton Valley wells on. Although we had drilled about 600 of those wells since '95 and had a 97% success rate, and we had 600 operated locations to drill in the future we didn't think that was the best path for this Company to take this year. So the transition was you discontinue that program, you start the Haynesville program. And we were -- we softly entered the Haynesville arena, although we had a huge acreage position for the size Company that we are and our cost basis is probably competitive with any our company, if not less than all of them.

So as you go forward we said that initially we would drill probably 34 Haynesville wells, we're at 38, 39, 40. We're going to end up with probably 30 net Haynesville wells. We also said, Ron, that last year we only booked one well, which is a Blackstone Minerals 7 # 1 well, which is a 9 million per day IP rate and we thought that we probably underbooked that well because of performance. Performance exceeded what we thought would happen.

So based upon that we felt like we exposed ourselves to anywhere from 200 to 300 Bcfe in reserve adds through the Haynesville program and we still stick with that number based upon 10 months and however many days we are down the year 2009, I think as we said the results have exceeded what we thought would and the drilling costs have come down. You can already see it's impacting our DD&A rate, our finding cost rate. It's coming down. The great thing, is that we are just reporting, Ron, on what we operate. This is not that we're not operating, and we're participating with somebody else. This is our own program. So, no, we do feel comfortable with that. In fact, instead of the 5% production growth, as you know recently, we've said we'll probably have double-digit production growth in '09, 10%, then maybe 19 to 20% plus growth in 2010, and that just depends on how many Haynesville wells we choose to drill, and we don't choose to drill them because of lease expiration issues. We choose to drill them because Mack and the G&G group and the reservoir engineering group would think that would benefit Comstock and it would create more wells for the stockholder on a per share basis. That's why is we would aggressively drill the Haynesville in 2010. But, no, that's a long, long answer to your simple question, but no, we feel like the 200 to 300 Bcfe is a real target.

Refresh my memory. Last year from the Blackstone Minerals # 7 and the accompanying one or two PUDs what did you have in terms of reserves? Is it 9 or 10 B's?

We booked that one well and two offsets, and a little part of the El Paso well. And that was 11 Bcfe.

Okay.

So out of our roughly 582 Bcfe reserves that we started this year off with, which are booked reserves, of the 582 Bcfe, 11 Bcfe of that 582 was Haynesville oriented. So we had very little exposure in our reserves at the end of '08 with Haynesville, and I think, which you will see in '09, even though commodity prices have been bad. We're probably in the single best region to create real wealth in a low commodity price environment, and I think we've started proving that and it's amazing, if you were to go back in the '06, '07 and first half of '08 days, and you were to try to add 80 million a day of net production and you were to try to go buy it, I mean, who knows how many hundreds of millions of dollars would it cost you. We've done that through the drill bit, and for a Company our size, $1.7 billion of assets and $700 million of cash liquidity, to have that type program, our reserve potential versus booked reserves just in the Haynesville, it's probably 10 times great there Haynesville exposure. The additional reserves is 10 times greater than what we booked already, now figure we'll be off on that sum but that's what we believe right now based upon our own programs.

Lastly you just mentioned in recent presentations you talked about if you had a program, you think it could we kind of a 19, 20% type production growth for 2010? I know the plan is still flexible and not yet finalized, but can you provide a little additional information as to how you get to that number, in terms of what you're expecting from a typical well especially given that some of your recent wells have been towards the upper end or what the typical well profile would be?

This is Mack. As you indicated, we're developing our Y-10 schedule, but we've mixed in a number of wells on a pro forma basis in developing our plan, drilling in the Logansport Mansfield area with our Toledo Bend area. We're still gravitating away from Texas under the current market conditions and using our average tight curves and applying a very conservative time frame on when those wells would each be going to sales at the average EURs of 5 Bcf. You can easily see where that's fairly conservative especially when you talk about the Logansport area. In rolling those forward, each well contributing certain production within those time frames, we roll forward to the 18 to 20% production growth over this year.

And just to clarify, the 5 B's you're talking, that's net to your revenue interest. Right? So--?

No, that's gross number.

Great, thanks, guys.

Sure.

And your next question comes from the line of Dan McSpirit from BMO Capital Markets.

Thanks for taking my questions.

You bet, Dan.

Looking at the abundant liquidity that you're now sitting on, how do you guys weigh preserving capital and/or investing in your current deep drilling inventory versus building your asset base in the Haynesville shale through acquisitions. And I guess the acquisition assumption part of that question referring to forfeited leasehold opportunities that you may see here on the horizon over the next six to nine months?

I think kind of in generalities, because I wouldn't want to answer in that a micro manner. One, we've been in this region for 20 years. In fact, probably half our Haynesville acreage we've owned 10 years and didn't even know it was valuable, because the value was created in '07 when several companies drilled it and developed it horizontally. I think that we're kind of a go to Company. If you have an issue, as a mineral owner, or as a working interest owner, operator, and you're losing some acreage, I mean, we can shift probably five of our six rigs over to your acreage, and we can drill it and hold it. I don't know that many can do. That we can do that without forfeiting any of our existing acreage in 2010. I think that we have picked up some acreage recently. It's in blocks of 100, maybe 500, 600 acres at a time and it's been a drill to earn type event where we will come in and drill on some acreage and carry somebody maybe for a quarter, then heads-up after the first well. And then we'll operate it. But we're seeing those opportunities.

I think we Companywise still believe that we still are in a recession, and we still believe some of those opportunities will be out there, and I know some of the public companies have tapped into the equity market and/or the bond market as we did and they have straightened out their balance sheet as far as the bank debt. But I think there will be some opportunities out there from the private sector. There's still some wonderful companies out there that are suffering that have good footprints. So we're always, as you know, we're always seeking to improve our acreage position there as we've been doing since third quarter of 2007. And I think our balance sheet will allow us to do that.

Our corporate goal always, as you do know is to create wealth for the stockholders, and you do that one share at a time, and you just create more value per share, and we've not been a big believer of diluting existing stockholders for the sake of future growth two or three years now. So what you are going to see us do is we're going to develop our Haynesville shale acreage, and we'll manage our balance sheet at the same time, and we'll -- I think as we said '09 was kind of a watershed year for us. To think that you could discontinue a proven Cotton Valley program, and you could kick off what at that time was an emerging Haynesville program, and it exceeds your expectations, and all of a sudden you don't have molecule of production a year ago, and today you've got 80 million net from a program, it's pretty phenomenal, and it's exactly what you would want to do in the pricing environment that we are in. So I think we just continue to be disciplined and create wealth on a per share basis, Dan.

Very good. I appreciate that context, Jay. One more, if I could. Certainly you guys are enjoying the benefits of Haynesville shale volumes in the denominator or the ratio when you're looking at unit costs. We saw it with LOE breaking $1 in the third quarter of this year. What does that look like midyear next year or at the end of 2010, meaning at what point do you break $0.50?

That's a Roland question.

We do think that the cost per unit will continue to improve, especially as production grows. The Haynesville production is not really bringing a lot of new lifting costs along with it. O existing field operations in that area from our legacy fields and those field offices service these wells, so that's kind of a fixed costs, so additional volumes drive it down. The additional costs really are just production taxes which will be really dependent on gas prices. So that part, hopefully that comes back up next year and won't be at this low level. I don't know if we get down to $0.50, but we do expect it continue to improve. What we really want to see improve is the finding costs and the DD&A rate, and we think that's where we really want to see that come down below $3. That's where we want to see the big impact. That will make us much more profitable.

Great, thank you. And one more if I could. Forgive me if this question was asked earlier in the conference call. But the last four wells that you highlighted in slides 21 and the 22, is there anything special about those operations, or should we expect more of the same going forward here in terms of efficiency gains?

This is Mack. You can expect more efficiency gains because that's our goal. And I have a lot of confidence in our technical staff here to achieve those goals. The spread of our activity will pretty much stay the same, meaning we plan to run half of our rigs in our Toledo Bend area and half our rigs in the Logansport and Mansfield area. So you will continue -- you should continue to see the kind of performance profiles that we've put in front of you for the third quarter.

Very good. Thank you, gentlemen.

I think, Dan, we've got a lot of near-term catalysts. Like Mack said, we're focused on improving our return on capital that we spend and we focus on return enhancement, not just stressing growth through acquisitions for the sake of growing. At the same time we want to protect the deep pockets that we have. I think, again, it is kind of a world of have and have-not's in the energy sector so we want to protect the $700 million in liquidity that we've accumulated.

Much appreciated. Thank you.

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

I wanted to get a little bit more understanding of the deferred tax item you had in the quarter. Could you just go over how that was generated?

Sure. You're talking about the current tax benefit?

Yes.

For the quarter.

Yes.

The large current benefit from income taxes is really a result of several things happening together. One was, we completed some IRS audits of prior years. Several years ago, and those resulted in some acceleration of deductions that they wanted us to make. So we made those revisions, which generated a pretty sizable refund. So that refund will come in by the end of the year. And then at the same time during the quarter, we paid a lot of income taxes last year the sale of Bois d'Arc Energy. So any losses we generate this year can be carried back and a refund collected. So in addition to that refund, that was generated from the IRS audit, we also decided not to capitalize as much of our intangible drilling costs as we were before, and generate a larger tax loss. So we now expect between all those items to receive about a $40 million refund of income taxes, which will be coming in, some in the fourth quarter, some in the first quarter of next year. Instead of those taxes being deferred, it's really in this quarter changed its classification to current. So that's really what created that large provision. So a fair amount of it was catch-up, so you will see another current tax benefit in the fourth quarter also as we record the rest of that. But this quarter did contain a pretty unusual amount of catch-up entry for that.

Okay. So if I understand right, then the $40 million refund in taxes is that on the balance sheet now as a receivable?

Yes. It's in the current assets. Really, it's really just a classification between the taxes were always recorded. They were in long-term deferred taxes, and just the the cash timing of when they're being received is changed, so that's what runs through your current provision.

Okay. Got it. And after the coming two periods, fourth quarter and first quarter, there won't be any sort of other recurring items like this, or is there any part of this that has some other accrual element? I don't know if the Bois d'Arc losses or something like that might give rises to similar losses in the future?

The gain of the Bois d'Arc sale gives us the opportunity for the next three years. If you see some opportunities to take or generate a tax loss, you can carry it back and get a refund. Once that carry back period is closed and you won't have that have refund, but we still have several more years of opportunity to do that.

Okay. Just a couple more quick things. If you look at the fourth quarter going forward, and into the future periods, you've talked a good bit about your outlook for costs, but I just wanted to make sure I had this straight. Are you assuming that we will not have, or I should say is your planning for next year assuming that we won't really have a meaningful strengthening on the service cost side for 2010?

No, our assumption is currently that there will be a strengthening on the service cost side, and we factored that into our cost estimates on a pro forma basis for Y '10.

So obviously if costs stay flat, activity doesn't ramp up sharply that could end up being a pretty conservative assumption then?

Yes, sir.

Okay. I think that's it for me. Thanks a lot.

Thank you.

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

Mack, I was curious, it seems like you're much more positive about to upper Haynesville. Is that based on seeing more results out of competitors or just kind of the one well you guys have drilled?

No, we've got a database in house, Ray, that has captured all of the upper Haynesville tests, both on a vertical and horizontal basis, and although limited, it's encouraging. Our well, the BSMC 7-2 has held up extremely well. We think it's a 5 plus Bcfe EUR-type well. Of course, the geologists get involved and map up the Haynesville across our acreage and elsewhere, of course. So that's really the driver. Those two elements, the database that I mentioned, capturing all of the performance date and then correlating that to the G&G interpretation.

Got you. Thanks. Just was wondering, I know you spoke a little bit about the one well that was sort of the, I guess the southwest corner of Toledo bend north. Maybe that acreage is not as perspective as acreage to the east, I guess. Is that a fair way to look at it? I guess also, just on your Sabine Parish acreage, what do you think about that at this point? Are there any data points down there?

The first question that you asked, Ray, about the Toledo Bend North acreage, we're still pretty bullish on that acreage. That's where our upper Haynesville well is. This particular well that you mentioned that had the lower IP rate was in the northwest part of our acreage, and it appears to be a little more clay rich, a little tighter. We think we can improve performance through tweaking our frac designs and our lateral lengths and where we place the lateral and it gets back again to the earlier question about science and the play. There's not one key that unlocks all the locks in the Haynesville play, that's for sure.

So we're still bullish on the total acreage block. By no means are we at the point where we think that one well dooms or condemns this particular section. It's a 640-acre block of acreage that we're talking about that that one well is in. So we're look at that hard. I think we'll make some improvements.

As far as the Toledo Bend South block we're going to spud our first well down there this month. As I mentioned earlier. And we have a really high quality interpretation that uses all of the well data in our database on the G&G side. We're still pretty bullish on that. There are some operators to the east and to the south of us, vertical penetrations, primarily that give us some additional data to go on. We folded that into our interpretation. So I'm a firm believer in let's wait until we get our drill drilling, and we get some data, some hard data to look at. But the interpretation that we have in house is pretty robust. I have a lot of confidence in it.

Thanks, Mack.

Thank you, Ray.

Your next question comes from the line of Mark Lear from Sidoti and Company. Please proceed.

Good morning. I just had one last question on that upper Haynesville regarding those -- the Blackstone 1H and the 2H you just referred to. Just kind of wanted to get an idea how performances continue to hold up there, and I guess what you think is ultimately going to be the best way to develop those two Horizons going forward.

Well, this is Mack. We only have one upper Haynesville test here at Comstock and that's the 7-2. The 7-1, our very first, was the lower Haynesville test. The production from the 7-2 rate versus pressure draw down has held up extremely well. Just to put a point to it, it has exceeded expectations. And so at this point, given the G&G interpretation that I mentioned earlier, and that single data point, coupled with some of the other vertical penetrations in the area we're pretty bullish on the upper Haynesville across the Toledo Bend South acreage block.

As far as going forward and developing it, obvious given current technology, it will require two well bores, two wells, separate wells, one for the lower Haynesville and one for the upper Haynesville, although we are working with vendors to find a cost effective solution where -- and I believe that that cost-effective solution is forthcoming. Some pretty smart engineers are tackling the problem, because it's in their best interest, obviously, to develop the mouse trap that they can sell to operators to drill one well to capture both the upper and the lower, via two horizontal laterals. The big question is right now, what kind of mouse trap will withstand the pressures that it will be exposed to during the completion cycle. So a lot of work has to be done to solve that problem. But right now, going forward, it's one well bore per reservoir, and that's the way we'll be approaching it going forward in the near term.

Good. And if I'm not mistaken, those lateral legs were, I guess, right on top of each other?

They're separated by a few hundred feet. Kind of depends on where you are in the play. There's a real hard, believe it or not, it's always shale, but it doesn't have the gas productivity that obviously the Haynesville sections that we're talking about. It separates the lower from the upper, and we believe it will contain the frac height, so that one completes, or the completion of the lower will not interfere with the completion of the upper, and vice versa. So that's kind of how it lays out. If there's a few hundred feet separating the upper from the lower.

Understood. Thank you.

Yes, sir.

Your next question comes from the line of Richard Tullis from Capital One Southcoast.

Just touching a little bit on the east Texas Haynesville wells, I guess the four you had drilled a little earlier this year, how are those wells performing currently?

Well, they're underperforming versus our Louisiana side wells. And as we've mentioned earlier, we believe that the Texas side part of the Haynesville play, especially through Harrison and Panola County, are waiting on higher gas prices to give the kind of rate of returns that most of us need and want. So to be more specific about answering your question, we believe there's 3.5 to 4 Bcf type wells that we've drilled on an EUR basis. And that's over the life of the well, obviously. And we're interested in wells that will give us substantially higher fraction of the total UR up-front so we can get a better return.

Seeing any difference in decline rates between the Texas side and the north Louisiana side?

That's a great question. The short answer is yes. But it involves a longer answer, too long for this conference call. There's different declines in different parts of the Texas footprint. All four of our wells tested different areas in Texas. It also matters on how you completed the well. A couple of the Texas wells that we completed, we completed prior to our current frac design technology that we've applied, so there's a factor there. A variable there that's affected the decline, and also the lateral lengths. In Texas, you have to be very careful and plan way ahead in order to get the drilling unit geometry or configuration such that you can drill a longer lateral length 4,000 feet is the targeted lateral length by most operators. In Texas that's more difficult to achieve, just because of the way the tracks lay out and the way you form your drilling units. So all of the above affect the declines that we see in Texas, and Louisiana, for that matter, but in Louisiana, as you know, it's much easier to drill a standard 4,000-foot lateral or maybe even greater, just because of the section, township, and range configuration.

So I guess just to make sure I understand, so you are seeing maybe a more shallow decline in Texas side initially?

No, we're not seeing that. I know some operators have observed that in some of their wells, so they've reported that, anyway. We have not seen that shallow decline that some of the other operators indicate.

Okay. What about the two Chesapeake wells in the eastern part of Harrison County? Does that change the equation any, or how do you view those wells?

Well, we really don't have all of the detail on those wells. We've data traded with Chesapeake on a couple of their wells. We're primarily interested in their completion and drilling procedures as they were on ours, so I really can't comment in any reasonable way concerning the performance of the Chesapeake wells in detail.

Okay. Any plans for south Texas wells in 2010? The Wilcox, Vicksburg?

We're pretty well focused on the Haynesville, the allocation of our capital targets, the Haynesville for a number of ropes. The return on investment, the protection of some of the leasehold. So, no, we don't have any plan at this time to focus on the south Texas project.

Okay. For 2010, do you have any gas hedged at this point?

No, we don't. We don't have any hedged.

Okay. What point would you look to put some on or you're comfortable just going--?

To the extent we made an acquisition, what's when usually do hedging. We don't believe hedging is a good strategy for a drilling program because your drilling costs are not fixed, so it's just not a strategy we think that's very prudent.

Roughly what's the net acreage split between your different areas in east Texas, north Louisiana, Logansport, Toledo Bend, east Texas?

In the upper and the lower or just the lower? Just the upper? We have an interesting mix.

I guess the Haynesville, the lower.

Probably 70%/30%, somewhere in there, Louisiana side. 65/35. 50,000 acres are in, if you look on--?

If you look on slide 17, Richard, weve got 50,000 net acres in Louisiana, and 22,000 in east Texas.

Then on slide 18 we have 51,000 gross acres in the upper Haynesville, 45,000 net acres.

And of that 45,000, how much would be Texas?

All that 45,000, upper Haynesville is Louisiana.

Other than Shelby County.

Other than 2,500 acres in Shelby County.

I think that's all I had. Oh, yes, regarding the Stone ownership, I know you're in a very good liquidity position right now. At what point would you look to possibly monetize some or all of that five million shares?

We still think that Stone is way undervalued, we don't have any intent at all right now to monetize any of it. Like you said, with our balance sheet and our cash on the balance sheet and our $0.5 billion undrawn on our credit line, there's no need to do that. We're going to wait until it gets back to where it should be. We think it was overly punished. It is a Gulf of Mexico company. They're not in favor right now, so we don't have any plans on selling that. We don't have any restrictions. It's a good thing. Because all the shares had to be registered by the end of August, which they were. So there are no restrictions. And I think the 5.3 million shares that we own, if we ever decided to monetize some of it, Stone trades probably 1.2 million, 1.3 million shares a day. I don't think we'd have any trouble in monetizing it at that point in time when we decide to do that but it's not part of our business plan right now.

Thanks very much.

Thank you, Richard.

Your next question comes from the line of Mitch Wurschmidt from KeyBanc.

Hey, guys.

Hi, Mitch.

Just wanted to ask on timing on well completions. Could you talk a little bit about -- I know you talked about drilling days and whatnot but I just was curious how to think about well completions between now and year end and into 2010, and then how your pipeline take-away looks at Logansport and Toledo North and how that works in with your well completion timing?

This is Mack. We expect to have approximately the same number of wells completed and flowing to sales for the fourth quarter as we've had for the third quarter. The actual completion time after the well is drilled, and casing set and the rig moves off location, it takes approximately two to three weeks to move in and initiate completion operations, to rig up all the equipment and get ready. The actual time frame that it takes to complete a well is fairly brief. If things go well on location, and there are no equipment failure issues, etc., in about seven days, we have a completed well, and our best to date is about two and a half days to three days to get 10 stages fraced and to start out the drill-out procedures. To final finalize the completion.

Going forward in 2010, we'll have several wells spud late in December that we'll be completing in January, as part of our program coming out of this year. Take away capacity, we're staging additional take-away capacity. We feel like our marketing group here at Comstock has done a great job in providing the take-away capacity time with our completion cycle, wells going to sales, so we're in pretty good shape.

So safe to say probably just the take away or the completion timing might even improve as you're getting more experience and you've got take away in front of you?

You bet. You could see that in the previous slide that we discuss, where our time to sales has dramatically come down as a consequence of the additional take away capacity being available as well as the pipes being in place. That was the thing that delayed us in a number of projects. We had had arranged for the take away capacity to be layered in as the pipes were installed and connected to our specific areas.

If you look, Mitch, on slide 21, the last four wells, it took us 38 days to drill them, then on slide 22, we said the last four wells from spud to sales was 72 days. So roughly 38 days to drill a well, then another 34 days from when you TD the well to when you connect it to sales.

That's great, I appreciate your response. Congratulations. Thanks.

Thank you.

Ladies and gentlemen, we are sorry, but we have run out of time for questions. I will now hand the call over to Mr. Jay Allison for closing remarks. Please proceed.

First of all, thank you for hosting us. Second, whoever is still there, I know there are a number of companies reporting and presenting today. So we as management, all the 135 employees at Comstock we are all thankful that you took your time to listen to the results. So again, we're always appreciative of that. So thank you.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.