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Comstock Resources, Inc. (NYSE:CRK)

Q3 2009 Earnings Call

November 3, 2009 10:30 am ET

Executives

Jay Allison - Chairman, President and CEO

Roland Burns - SVP and CFO

Mack Good - VP of Operations

Analysts

John Freeman - Raymond James

Leo Mariani - RBC

Sven Del Pozzo - C.K. Cooper

Ron Mills - Johnson Rice

Dan McSpirit - BMO Capital Markets

Noel Parks - Ladenburg Thalmann

Ray Deacon - Pritchard Capital

Mark Lear - Sidoti & Co

Richard Tullis - Capital One Southcoast

Mitch Wurschmidt - KeyBanc

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter Comstock Resources Earnings Conference Call. (Operator Instructions).

I would now like to turn the call over to your host, Mr. Jay Allison, Chairman and CEO. Please proceed.

Jay Allison

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 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.

If you'll refer to tab 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 to us report a loss of $13 million or $0.28 per share.

Despite the low oil and gas prices, we are having a very successful year with the drill bit. We drilled 38 successful wells, including 28 horizontal Haynesville Shale wells, three vertical 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 9 we completed a public debt offering where we sold $300 million in new 8 3/8% senior notes 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?

Roland Burns

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 the 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/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 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 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 six 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 $201million as compared to $464 million for the same period in 2008.

Our earnings before interest, taxes, depreciation, amortization, exploration expense and other non-cash 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, a 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. It's also a result of some refunds from recently completed IRS audits of other prior years. 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 the 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 of 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 of 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 of 2008. G&A cost 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 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 bank 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 the 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 the new 8-3/8% senior notes.

We repaid all of our bank debt and our borrowing base for our bank 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 and then less than a million on our other regions.

I will now turn it back over to Jay.

Jay Allison

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 Shale 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 planned Haynesville Shale wells. Four other wells are in Texas in the Waskom and Blocker fields. 37 other wells are being drilled in the prolific part of the plain North Louisiana. 23 of the operated wells have been completed and are now producing over 80 million cubic feet equivalent per day net to our interest.

I'll have Mack Good, our COO, go over these wells.

Mack Good

On slide 20 we show the results of our first 24 Haynesville Shale horizontal wells. Since our second quarter conference call, we've completed 10 successful operated Haynesville Shale horizontal wells in De Soto Parish in North Louisiana. Five of these wells 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 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 is each of sections 5, 6, 8, 9 and 17. These wells initial production rates ranged from 9 million to 10 million equivalent per day. In the Logansport field, the Caraway Number 3 well was drilled to a vertical depth of 11,103 feet with a 4,181 foot horizontal lateral. The well was subsequently completed with 10 frac stage and was tested at an initial production rate of 21.1 million equivalent per day.

The Collins 15 Number 2 well was drilled to a vertical depth of 11,239 feet with a 3,680 foot horizontal lateral. The well was completed with 10 frac stages and subsequently tested at an initial production rate of 21.9 million equivalent per day. Comstock has 100% working interest in both of the aforementioned wells.

We also drilled the Miller Land Number 1 and it was drilled to a vertical depth of 11,523 feet with a 4,180 foot horizontal lateral. The well was completed with 10 frac stages and subsequently tested at an initial production rate of 15 million equivalent per day and we have a 63% working interest in this well.

Also in the Logansport field, the Brown Number 1 well was drilled to a vertical depth of 11,491 feet with a 4,254 horizontal lateral. We completed this well with 12 frac stages and tested the well at an initial production rate of 15.7 million equivalent per day. We have a 76% working interest in this well.

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

Following on slide 21, we show the number of days it has taken us to 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 it has taken to connect each of our 24 horizontal Haynesville wells current flowing to sales. Our average connect time is approximately 105 days for all 24 of these wells current 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 horizontal or 30.6 net Haynesville shale wells.

With that, I'll turn it back over to Jay.

Jay Allison

This is the final slide. If you go to slide 24, we'll show you the 2009 outlook. We are 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 is 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 are well positioned for future growth when gas prices improve for the large inventory of drilling 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 are having in the Haynesville Shale, we have a clear path to developing strong reserve and production growth next year.

Operator, I'll turn it back over to you for questions. Thank you.

Question-and-Answer Session

Operator

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

John Freeman - Raymond James

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

Jay Allison

Initially the vast majority of the well will be at Lower Haynesville. We have not put together our 2010 budget so far. We have six rigs right now that we operate that we're drilling at Haynesville Shale wells and to have the six rigs through next year is our goal as far as initial look at 2010 budget. We also said we might add a seventh rig. That depends upon commodity prices. As far as wells that would specifically target Upper Haynesville, I'll Mack address that now, although we have not approved a budget or a drilling program for 2010. So this would still be speculation, okay?

Mack Good

Obviously we have significant acreage position in the Upper Haynesville to test. We're excited about the 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. 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.

Jay Allison

Remember, as we drill the Lower Haynesville, 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. That's at 45,000 net acres and that's at 2.1 Tcfe of upside. In a very professional manner, we'll develop that. We don't want to drill Upper when in fact you'd have to drill the Lower to hold the acreage anyhow. So we'll factor that in.

John Freeman - Raymond James

The one area just looking at the Haynesville and Louisiana that there hasn't been as much activity on your acreage is in Toledo South. Any idea when you get some results in that area?

Mack Good

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

John Freeman - Raymond James

Just looking at the overall completed well cost what your guidance has been, I believe your first rig comes up for repricing in December is 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 at the lower rig rate probably offsets that?

Jay Allison

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

John Freeman - Raymond James

Mack, how much of the science do you think is still going on in terms of initially we were look at trying slickwater versus gel, different lateral lengths, frac stages, do you feel like you are at the point where you've got it down and there's not much science left?

Mack Good

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. I mean, there's a lot of data that's being gathered. A lot of that data is still being analyzed.

I'll give you an example. The idea of longer lateral lengths and the orientation of those laterals where to place them as 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 proppant 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's coming to the forefront here is the geomechanics, I mean 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 time 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. 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 from that in the Haynesville.

Operator

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

Leo Mariani - RBC

I am curious to see if you have any current or plan for the near future activity in Shelby County? I know there have been a lot of industry wells in that area.

Jay Allison

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 as a non operated position, but we'll be probably drilling in that AMI in a non-op position next year, with our acreage contribution.

Leo Mariani - RBC

Jay, you are specifically referring to Shelby County here?

Jay Allison

Right.

Leo Mariani - RBC

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

Mack Good

That's an average for us. 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.

Jay Allison

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

Leo Mariani - RBC

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

Mack Good

It's approximately 2,500 acres or something.

Operator

Your next question comes from the line of Sven Del Pozzo from C.K. Cooper.

Sven Del Pozzo - C.K. Cooper

Your comments on the 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, are we talking about the unit finding and development costs, or both, for that matter? I'm just kind of wondering what reserve numbers to have in the back of my head to understand what you guys are getting at.

Roland Burns

This is Roland. What we use for the DD&A rate is mostly the proved/development reserves for new wells drilled. So we really haven't seen the impact of the reserves that 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.

As you see the DD&A rate come down in the third quarter, it's more a result of not so much of a lot of reserves yet really getting booked on the Haynesville, it's more of a result of the production coming from certain fields because our DD&A calculation is due to successful efforts company' s has done on a field-by-field basis. So each one is done separately. We expect the trend as reserves are added in Haynesville to continue to drive down that DD&A rate as our finding cost is expected to be significantly lower this year than they have been in the past.

Sven Del Pozzo - C.K. Cooper

Looking back to your operational update before, 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 Number 2H and the lower part of the Logansport, is that a newer one?

Roland Burns

That was not a newer well. I think we reported that well in the second quarter. I think the wells that you're looking on slide 20, the newest wells would be the Collins 15 Number 2, that one had a 22 million a day IP. That's in Logansport. The RLS Number 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.

Sven Del Pozzo - C.K. Cooper

Just for a sense of the balance of cost, CapEx for your wells in the Haynesville aside from the day rate, well I guess if you could tell me both, I mean how much money are you saving when you drill in fewer days, so if you could tell me the day rate there? Also what about the rest of the well costs, like steel and tubulars?

Mack Good

This is Mack. Our average day rate on our rigs is approximately $24,000 per day. So that will give you an easy way to get to the arithmetic on cost savings, but it is more than just the day rate, it is 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 labors' supervisory time, et cetera. So we estimate with every day that we cut off of the drilling time we save approximately $50,000 per day.

Now, in terms of overall cost, certainly service costs have come down. The cost of fracing at Haynesville well a year ago was about two and a half times current cost. Our current cost is anywhere from a $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 a question concerning the science in the play, et cetera. 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, et cetera, and at what depth? The bottom line here 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 material. Now, the additional cost savings come from operational efficiencies.

Sven Del Pozzo - C.K. Cooper

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

Mack Good

Yes. 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.

Operator

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

Ron Mills - Johnson Rice

Couple of 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 that you put in your ops update?

Jay Allison

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

Ron Mills - Johnson Rice

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

Mack Good

We have a few wells waiting on completion. At the end of this week we'll have three wells probably waiting on completion. Two of our rigs will be skidding to new projects.

Ron Mills - Johnson Rice

As you look ahead to yearend, 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 fees, is that still in the fairway, or how much could that be impacted by the average gas pricing this year?

Jay Allison

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 of 100 cotton valley vertical wells in those two years, and that's where 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.

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. We softly entered the Haynesville arena, although, we had a huge acreage position for the sized company that we are and our cost basis is probably competitive with any peer 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 and 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 Black Stone Mineral 7 Number 1, which is a [99] a day IP rate, and we thought that we had probably underbooked that well, because of performance, performance exceeded what we thought would happen. So based upon that we felt like we exposed ourselves anywhere from 200 to 300 Bcfe 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 in some of the script, the results have exceeded what we thought would be excellent and it's exceeded that, and the drilling costs have come down. You can already see it is impacting our DD&A rate, our finding cost rate, I mean it's coming down. I think the great thing that just reports on what we operate. This is not that we're non-operating, 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 said we'll probably have double-digit production growth in '09, 10% plus and then maybe 19 to 20% plus growth in 2010. That just depends on how many Haynesville wells we choose to drill. We don't choose to drill them because of lease expiration issues. We choose to drill them because Mack and G&G Group and the Reservoir Engineering Group would think that would benefit Comstock and it would create more wealth for the stockholder on a per share basis. That's why we would aggressively drill the Haynesville in 2010. That's a long, long answer to your simple question, but no, we feel like the 200 to 300 Bcfe is a real target.

Ron Mills - Johnson Rice

Refresh my memory, last year from the Black Stone Minerals Number 7 and the accompanying one or two PUDs what did you have in terms of reserves, was it 9 or 10 Bs?

Jay Allison

We booked that one well, two offsets and a little part of the El Paso well. That was 11 Bcfe. Out of our roughly 582 Bcfe reserves that we started this year off with which are booked reserves, 11 Bcfe of the 582 Bcfe was Haynesville oriented. So, we had very little exposure in our reserves at the end of '08 with Haynesville. I think what you'll 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. I think we've started improving that.

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 net production and you were to try to go buy it, I mean who knows how many hundreds and hundreds and hundreds and hundreds and hundreds and hundreds of billions of dollars it would cost you. We've done that through the drill bit. For a company our size, $1.7 billion of assets, $1.50 million of equity and $700 million of cash liquidity, to have that type program, our reserve potential versus booked reserves just in the Haynesville is probably 10 times greater the Haynesville exposure. The additional reserve is 10 times greater than what we've booked already. Maybe we'll be off on this, but that's what we believe right now based upon our own programs.

Ron Mills - Johnson Rice

Lastly, you just mentioned in recent presentations you've talked, if you had a six-rig program you think it could be 19, 20% type production growth for 2010? I know that 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 probably towards the upper end or above what the typical well profile would be?

Mack Good

As you indicated, we're developing our '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 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 timeframe 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 timeframes, we roll forward to the 18 to 20% production growth over this year.

Ron Mills - Johnson Rice

Just to clarify, the 5 Bs you're talking, that's net to your revenue interest, right?

Mack Good

That's a gross number.

Operator

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

Dan McSpirit - BMO Capital Markets

Looking at the abundant liquidity that you are 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? 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.

Jay Allison

I think in generalities because I wouldn't want to answer that in 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 or an 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.

We have picked up some acreage recently. It's in blocks of 100, maybe 500, 600 acres at a same 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 and then heads-up after the first well, and then we'll operate it. We're seeing those opportunities. I think we, company-wide, still believe that we still are in a recession and we still believe some of those opportunities will be out there. I know some of the public companies have tapped into the equity market and/or the bond market as we did and they've 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 are still some wonderful companies out there that are suffering that have good footprints. As you know, we're always seeking to improve our acreage position there as we've been doing since third quarter of 2007. 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. 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 from now.

So what you're 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. I think as we said on the script, '09 was kind of a watershed year for us. To think that you could discontinue a proven Cotton Valley program and you could kickoff what at that time was an emerging Haynesville program and it exceeds your expectations, all of a sudden you don't have a molecule of production a year ago and today you've got 80 million net from a program, it's pretty phenomenal. It's exactly what you would want to do in the pricing environment that we're in. So I think we just continue to be disciplined and create wealth on a per share basis.

Dan McSpirit - BMO Capital Markets

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 at 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?

Roland Burns

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. Our existing field operations in that area from our legacy fields there, that labor out there and those field offices service us well. So, that's kind of a fixed cost and additional volumes drive it down. The additional costs, really just production taxes, will be really dependent on gas prices. 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 continue to improve. What we really want to see improve is the lifting 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 because that will make us much more profitable.

Dan McSpirit - BMO Capital Markets

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?

Mack Good

You can expect more efficiency gains because that's our goal. 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 should continue to see the kind of performance profiles that we've put in front of you for the third quarter.

Jay Allison

We've got a lot of near term catalysts. Like Mack said, we focused on improving our return on capital that we spent and we focused 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. 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.

Operator

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

Noel Parks - Ladenburg Thalmann

I just had a question. 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?

Roland Burns

I'm sure. You're talking about the current tax benefit in the quarter?

Noel Parks - Ladenburg Thalmann

Yes.

Roland Burns

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 and those really 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.

Then at the same time, during the quarter, we paid a lot of income taxes last year with 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 to not to capitalize as much as 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, and 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.

Noel Parks - Ladenburg Thalmann

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

Roland Burns

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

Noel Parks - Ladenburg Thalmann

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

Roland Burns

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

Noel Parks - Ladenburg Thalmann

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. I just want 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?

Mack Good

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.

Noel Parks - Ladenburg Thalmann

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

Mack Good

Yes, sir.

Operator

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

Ray Deacon - Pritchard Capital

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

Mack Good

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. Although limited, it's encouraging. Our well, the BSMC 7 Number 2, has held up extremely well. We think it's a 5 Bcfe plus EUR-type well. Of course, the geologists get involved and map the Upper Haynesville across our acreage and elsewhere. So that's really the driver, those two elements, the database that I mentioned, capturing all of the performance data and then correlating that to the G&G interpretation.

Ray Deacon - Pritchard Capital

I know you spoke a little bit about the one well that was on 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?

Mack Good

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. 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.

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-acare block of acreage that we're talking about that that one well is in. So we're looking at that hard and I think we'll make some improvements.

As for as the Toledo Bend South block, we're going to spud our first well down there this month, as I mentioned earlier. 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 interpretations. 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.

Operator

Your next question comes from the line of Mark Lear from Sidoti & Co.

Mark Lear - Sidoti & Co

Just had one last question on that Upper Haynesville regarding the Black Stone 1H and the 2H you just referred to. Just kind of wanted to get an idea of 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?

Mack Good

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 well in Haynesville play was 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. 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 in developing it, obviously, 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 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.

Mark Lear - Sidoti & Co

If I am not mistaken, those lateral legs were right on top of each other?

Mack Good

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 also a 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 contains the frac height, so that 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. There's a few hundred feet separating the Upper from the Lower.

Operator

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

Richard Tullis - 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?

Mack Good

Well, they are underperforming versus our Louisiana side wells. 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 us the rate of returns that most of us need and want. To be more specific about answering your question, we believe there are 3.5 to 4 Bcf type wells that we've drilled on an EUR basis. That's over the life of the well, obviously. We're interested in wells that will give us substantially higher fraction of the total EUR upfront so we can get a better return.

Richard Tullis - Capital One Southcoast

Are you seeing any difference in decline rates between the Texas side and the North Louisiana side?

Jay Allison

That's a great question and the short answer is yes. It involves a longer answer, too long for this conference call. There are 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. 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.

Richard Tullis - Capital One Southcoast

Just to make sure I understand, you are seeing maybe a more shallow decline in Texas side initially?

Jay Allison

No, we're not seeing that. I know that 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.

Richard Tullis - Capital One Southcoast

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?

Jay Allison

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.

Richard Tullis - Capital One Southcoast

Any plans for South Texas wells in 2010, the Wilcox, Vicksburg?

Jay Allison

We're pretty well focused on the Haynesville, the allocation of our capital targets, the Haynesville for a number of reasons, 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.

Richard Tullis - Capital One Southcoast

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

Jay Allison

No, we don't have any hedged.

Richard Tullis - Capital One Southcoast

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

Jay Allison

To the extent we made an acquisition, that's when we usually do hedging. We really 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.

Richard Tullis - Capital One Southcoast

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

Jay Allison

In the Upper and the Lower or just the Lower, just the Upper? We have an interesting mix.

Richard Tullis - Capital One Southcoast

I guess the Haynesville, the Lower.

Jay Allison

Probably 70%-30%, somewhere in there, Louisiana side, 65-35.

Mack Good

If you look on slide 17, we've got 50,000 net acres in the Lower.

Jay Allison

In Louisiana, and then 22,000 in East Texas.

Mack Good

22,000 in East Texas. Then on slide 18 we have 51,000 gross acres in the Upper Haynesville, 45,000 net acres.

Richard Tullis - Capital One Southcoast

Of that 45,000, how much would be East Texas?

Mack Good

All that 45,000, Upper Haynesville is Louisiana.

Jay Allison

Other than Shelby County.

Mack Good

Other than 2,500 acres in Shelby County.

Richard Tullis - Capital One Southcoast

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 5 million shares that you have?

Roland Burns

We still think that Stone is way undervalued and 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 till it gets back to where it should be. We think it was overly punished. It is a Gulf of Mexico company. They are not in favorite now, so we don't have any plans on selling that.

We don't have any restrictions. That'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. 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.

Operator

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

Mitch Wurschmidt - KeyBanc

Just wanted to ask on timing on well completions. I know you talked about drilling days and whatnot, but I was curious how to think about well completions between now and yearend and into 2010, and then also how your pipeline takeaway looks at Logansport and Toledo North and how that works in with your well completion timing.

Mack Good

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 wakes to move in and initiate completion operations, to rig up all of the equipment and get ready. The actual timeframe that it takes to complete a well is fairly brief. If things go well on location and there are no equipment failure issues, et cetera, in about seven days we have a completed well. Our best to-date is about 2.5 days to 3 days to get 10 stages fraced and to start out drill out procedures to 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. Takeaway capacity, we're staging additional takeaway capacity. We feel like our marketing group here at Comstock has done a great job in providing the takeaway capacity timed with our completion cycle of wells going to sales. So we're in pretty good shape.

Mitch Wurschmidt - KeyBanc

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

Mack Good

You bet. I mean, you can see that in the previous slide that we discussed where our time to sales has dramatically come down as a consequence of the additional takeaway 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 arranged for the take away capacity to be layered in as the pipes were installed and connected to our specific areas.

Jay Allison

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

Operator

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.

Jay Allison

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

Operator

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

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Source: Comstock Resources, Inc. Q3 2009 Earnings Call Transcript
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