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Comstock Resources Inc. (NYSE:CRK)

Q2 2009 Earnings Call

August 4, 2009 10:30 am ET

Executives

Jay Allison - Chairman, President and CEO

Roland Burns - SVP and CFO

Mack Good - VP of Operations

Analysts

Noel Parks - Ladenburg Thalmann & Co.

Ron Mills - Johnson Rice & Company

Jack Aydin - Keybanc Capital Markets

Michael Bodino - SMH Capital

Amir Arif - Stifel Nicolaus & Company

Mark Lear - Sidoti & Company

T.J. Schultz - RBC Capital Markets

Ray Deacon - Pritchard Capital Partners, LLC

Dan McSpirit - BMO Capital Markets

Ron Mills - Johnson Rice

Operator

Welcome to the second quarter, 2009 Comstock Resources Inc. Earnings Call. (Operator Instructions) I would now like to turn the presentation over to our host for today's call the President and CEO, Jay Allison, you may proceed.

Jay Allison

Josh, thank you and I would like to thank everyone for participating in the conference call. I know it's a busy day, so we're always thankful that you listen in for the 90-day report card that we give. Welcome to the Comstock Resources second 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 second 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 second 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, or we believe the expectations in such statements to be reasonable. There can be no assurance that such expectations will prove to be correct. If everyone would please refer to page two, of the presentation where we will summarize the second quarter results.

The substantial decline in oil and gas prices in 2009 caused a reversal from the record setting profits of last year. For the second quarter we reported revenues of 65 million dollars and we generated EBITDAX and operating cash flow of $42 million dollars or $0.90 cents per share. The low price has caused us to report a loss of $11 million or $0.26 per share.

Despite the low oil and gas prices we are having a very successful year with the drill bit. We have drilled 29 successful wells, including 19 horizontal Haynesville Shale wells, three horizontal Cotton Valley wells, three vertical Cotton Valley wells, and four high rate South Texas wells.

Our most recent Haynesville Shale wells at Logansport completed in the second quarter and initial production rates which averaged 18 million cubic feet equivalent per day, an improvement over our first quarter wells. We also tested our first successful horizontal well in the Upper Haynesville or Bossier Shale and DeSoto Parish that we see end of this quarter.

This success could have a significant impact on the reserve potential of our acreage and to the southern part of the Haynesville play. Despite the weak environment we continue to maintain a very strong balance sheet that has allowed us to pursue our business plan this year without having to rely on the capital markets for funding.

I will now turn it over to Roland to review the financial results in more detail, Roland?

Roland Burns

Thanks, Jay. On slide 3, we breakout our average daily production by region. In the second quarter our production averaged 169 million cubic feet of natural gas equivalent per day, 6% higher than our pro forma production in the second quarter of 2008 of 159 million per day, which excludes the 9 million per day that we divested out last year. Production was up from our first quarter average rate of 157 billion per day as our Haynesville wells are now contributing to our production rate.

Production this quarter was 3 million per day lower than it could have been due to the shut in of our largest South Texas field, the Fandango field, which was shut in for two weeks for plant maintenance. Our East Texas North Louisiana region averaged 99 million per day. South Texas averaged 56 million per day and our other regions averaged 14 million per day in the quarter.

On July 31, our production rate had increased to 190 million per day, putting us on track to meet our production guidance this year of 62 to 67 Bcfe, representing a 7% to 15% growth over pro forma production in 2008. Daily production in the third quarter of this year is expected to average in the mid 180s.

Oil prices in the second quarter were about half of last year's level as shown on slide 4. Our average oil price decreased 53% in the second quarter of 2009 to $49.24 per barrel, as compared to $105.16 per barrel in the second quarter of 2008. Our oil price in the second quarter averaged 83% of the average NYMEX WTI price. For the first half of this year, our average oil price was $41.95, which was 55% less than our average oil price of $93.32 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 5. Without considering our hedges, our average gas price decreased 69% in the second quarter to $3.38 per Mcf as compared to $10.83 in the second quarter of 2008.

Our realized gas price was 97% of the average Henry Hub NYMEX price in second quarter as basis differentials have improved from the last quarter. For the first six months of this year our average gas price decreased 60% to $3.81, as compared to the $9.56 per Mcf that we average for the same period in 2008.

Slide six shows our average gas price with the impact of our hedges. We have 11% of our gas production hedged in the quarter, which increased our realized gas price to $3.88 per Mcf. For the first half of this year our average price with the benefit of hedging was $4.30. In the remainder of 2009, approximately 10% our gas production is hedged at $8.20 per Mcf.

On slide 7 we cover our oil and gas sales. The lower prices caused our sales from continuing operations to decrease 62% to $65 million in the second quarter, as compared to $172 million in the second quarter of 2008. For the first six months of this year, our sales decreased 56% to $133 million as compared to the $300 million that we had for 2008.

Our earnings before interest, taxes, depreciation, amortization, expiration expense and other non-cash expenses or EBITDAX decreased 71% in the second quarter to $42 million as shown on slide 8. For the six months ended June 30th, 2009, EBITDAX decreased 65% to 88 million.

Slide 9, covers our operating cash flow. Our operating cash flow for the quarter also came in at $42 million a 69% decrease as compared to cash flow of $134 million in 2008 second quarter. Operating cash flow in the quarter was increased by current income tax benefit of $2.7 million. For the first half of this year, operating cash flow came in at $87 million, 62% less than the cash flow of $226 million for the same period in 2008.

In slide 10, we outline our earnings. With the very low oil and gas prices, we reported a net loss of $11.5 million, or $0.26 per share this quarter as compared to $70 million of net income or $1.53 per share in 2008's second quarter. The net loss for the first half of this year was $17.1 million or $0.38 cents per share as compared to $100 million dollars of net income, or $2.17 per share in the first half of 2008.

We outline our cost structure for the 6 month period on slide 11. Our cash costs continue to decrease in total of $1.59 per Mcfe produced so far in 2009, reflecting a reduction of $0.93 per Mcfe as compared to our cash costs in 2008. $0.31 of the savings comes from lower production taxes which fell to $0.12 from $0.43 in 2008. Ad Valorem taxes per Mcfe produced increased from $0.09 to $0.13 cents, as these taxes are still based on the high oil and gas prices driving property values in 2008.

Our direct lifting cost per unit decreased $0.07to $0.91 cents, due to the higher production level that we have in 2009. Our cash, G&A expense averaged $0.39 so far in 2009 reflecting to increase staffing level that the company has.

Cash taxes are benefit in 2009 of $0.14 per Mcfe produced with a tax loss expected for the year. Interest expense per Mcfe decreased by $0.45 to only $0.17 cents, due to the lower debt level that we now have. And the decrease in our proved reserve base at the end of 2008, which was primarily related to the decline in oil and gas prices, increased our DD&A rate so far in 2009 by 15% to $3.33.

On slide 12, we outline our capital structure at the end of the second quarter. We had $315 billion in total debt at the end of the quarter, which is an increase of $50 million from the end of the first quarter. We have $140 million outstanding under our bank credit facility, which has a borrowing base of $550 million.

Our equity at the end of the quarter was approximately $1 billion dollars, and our percentage of debt to our total book capitalization is 23%. We continue to have a very strong balance sheet and are well positioned in this tight credit environment.

Slide 13, we detail our drilling expenditures. We spent $175 million dollars in the first six months of this year for our drilling program, as compared to the $146 million that we spent in 2008 first half. We spent $145 million in our East Texas/North Louisiana region, $29 million in South Texas, and less than a million in our other regions. We funded these expenditures with operating cash flow of $87 million and borrowings under the credit facility.

I'll now turn it back over to Jay.

Jay Allison

Thank you, Roland. If everyone would please turn to slide 14, we'll focus on our East Texas/North Louisiana region. We drilled 25 wells or 18.4 net wells in this region in six different fields in the first half of this year. All of these wells were successful. 22 of these wells were horizontal wells. We've tested these wells at a per well average rate of 9.3 million cubic feet equivalent per day, the horizontal wells average 10.3 million cubic feet equivalent per day and the vertical wells average 1.6 million cubic feet equivalent per day.

I will have our Chief Operating Officer, Mack Good go over the recent results of our Haynesville Shale program, which is the focus of this year's drilling program. I'd like to note by the way that it's always nice to be able to turn the good drilling results over to a COO who's last name is Good, so Mack?

Mack Good

Thanks, Jay, and good morning, everyone. On slide 15, we show the results of our first 22 Haynesville Shale horizontal wells. Since our last operational update, we've completed seven Haynesville Shale horizontal wells and these wells are currently all flowing to sales. Six of these horizontal wells targeted the lower Haynesville Shale while one well targeted the Upper Haynesville Bossier Shale for completion.

In Harrison County, Texas, Comstock drilled and completed three wells targeting the lower Haynesville Shale and the Blocker field area. The Green, number 13H was drilled to a vertical depth of 11,055 feet with a 3,462 foot horizontal lateral. This well was completed with 10 frac stages and was subsequently flow tested at an initial production rate of 6.5 million cubic feet equivalent per day. Comstock has a 93.8% working interest in this well.

The Cox number one well also in the Blocker area was drilled to a vertical depth of 11,120 feet with a 4,181 foot lateral. This well was also completed with 10 frac stages and it flow tested an initial production rate of 8.2 million cubic feet equivalent per day. Comstock has a 99% working interest in this well.

Also in Blocker, the Woods number 1H well was drilled to a vertical depth of 11,127 feet with a 3,771 foot lateral. This well was completed with 10 frac stages and flow tested in initial production rate of 8.5 million cubic feet per day. We have a 100% working interest in this well.

Our first Upper Haynesville horizontal well the BSMC 7 number 2H was drilled in our Toledo Bend North field in to DeSoto Parish, Louisiana, to a vertical depth of 11,174 feet with a 4,441 foot horizontal lateral. This well was completed with 10 frac stages and was flow tested at an initial production rate of 11.6 million cubic feet equivalent per day. We have an 88% working interest in this well, and this is the best Upper Haynesville test to-date in the play.

We also drilled and completed three Lower Haynesville horizontal wells in our Logansport field in DeSoto Parish, North Louisiana. Comstock owns a 100% working interest in all three of these wells. We drilled our Colvin-Craner number 2H horizontal well in Logansport to a vertical depth of 11,353 feet with a 4,181 foot horizontal lateral. And after completing the well with 10 frac stages it was subsequently flow tested at an initial production rate of 21.2 million cubic feet equivalent per day.

The Broome number 1H well in Logansport was drilled to a vertical depth of 11,368 feet with a 4,051 foot horizontal lateral, and the well's completion included 11frac stages and flow tested at an initial production rate of 16.7 million cubic feet equivalent per day.

Finally, the Weyerhaeuser number 2H in Logansport was drilled to a vertical depth of 11,493 feet with a 4,181 foot horizontal lateral. This wells 10 frac completion, flow tested at an initial production rate of 16.2 million equivalent per day.

Moving over to slide 16, you will see a diagram that will give you a general picture of how we're currently drilling and completing our horizontal Haynesville Shale wells. This diagram shows that we anticipate drilling our Haynesville wells to a vertical depth ranging between 11,000 to 13,000 feet vertical depth depending on the area in the play.

We anticipate encountering a net play thickness in the Upper Haynesville ranging between 100 to 250 feet, while we expect the net pay thickness in the Lower Haynesville to range between 190 to 250 feet in various parts of the play. As shown on the slide as things stand right now, multiple laterals cannot be drilled within the same well board to develop both the Upper and Lower Haynesville intervals. We will have to drill separate wells to do that.

We expect to drill 4,000 foot long horizontal laterals targeting either the Upper or the Lower Haynesville for completion and w will generally pump 10 fracs or stimulation treatments in stages across these laterals. Currently the Haynesville horizontal completions require wire line service intervention after each fracture treatment in order to set an isolating plug and to perforate the next stage.

On slide 17, we show the number of days it has taken to drill the 19 horizontal Haynesville wells that we've drilled to-date. Our average drill time for all 19 wells drilled to-date is 44 days. Comstock's average drill time for its first four wells that we've drilled in the play was 51 days compared to the 37 day average drill time for our last four wells. Comstock's goal is to achieve a 35 day average drill time for our future Haynesville horizontal wells not requiring a pilot hole.

On slide 18, we show the number of days it has taken us to connect each of our 14 horizontal Haynesville wells currently flowing to sales. Our average connect time is about 113 days for all 14 wells currently flowing to sales. As the slide demonstrates, Comstock's connection to sales time is declining as a direct result of no longer needing to use a sputter rig to drill the vertical section of the hole, and then having to wait for a horizontal rig to come in and drill the horizontal lateral section.

Six of Comstock's first eight wells used this sputter rig approach, and the sales connection time for these six wells was 137 days. Comparatively, the eight wells that did not use this sputter rig approach, took an average of 96 days to connect to sales. We anticipate that the various pipeline connection installations that are now or soon to be in place for our Haynesville production will further reduce our average connection time to sales.

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

Jay Allison

Thank you, Mack. Our South Texas region is displayed on slide 19. In our South Texas region we drilled four or 2.9 net successful wells in the first half of this year. These wells have been tested at a per well average rate of 9.5 million cubic feet equivalent per day. We drilled two successful wells in our Fandango field in Zapata County, Texas.

The other two successful wells are in Santa Fe Ranch field in Kenedy County, Texas. In the second quarter we drilled the Santa Fe Julian Pasture number 2 well to a total vertical depth of 12,200 feet and it flow tested at an initial production rate of 12.2 million cubic feet equivalent per day. We have a 45% working interest in this well.

We still expect to spend $360 million in 2009 for our drilling program as outlined on slide 20. Cost to drill and complete wells have fallen since the beginning of the year, which will allow us to drill more wells than we anticipated in our original 2009 budget. We now expect to drill 49 or 37.4 net wells in 2009, including 38 or 29.5 horizontal Haynesville Shale wells. Our previous budget included 44 wells with 33 horizontal Haynesville Shale wells.

On slide 21, we show the latest chart on where we now plan to drill the 38 Haynesville Shale wells in 2009. Four of the wells are in Texas in the Waskom and Blocker fields. 34 of the wells will be drilled in the more prolific part of the play in North Louisiana. We expect our Louisiana wells to have twice the reserves as compared to the Texas wells drilled so far this year. Approximately two-thirds of our acreage is in Louisiana.

Now to slide 22, 2009 outlook. And looking ahead to the rest of the year, we feel we're very well positioned to continue to grow and add value for our stockholders even in this very challenging environment that we're now in. The divestitures of our stake in the Bois d'Arc Energy and the non-core properties that we completed in 2008 provide us an extremely strong balance sheet that will allow us to aggressively support the continued growth of our onshore operations, which is increasingly important given the tight credit environment that we are in.

Our 2009 drilling program estimated to cost $360 million will focus on our highest return projects this year, which means the Haynesville Shale projects. We're very pleased with our well results in DeSoto Parish, Louisiana. We're now driving down the cost of the wells from the $10 million to $14 million range that we spent on the first wells to the $7 million to $8 million range that we're currently in.

Our primary goals for this year are one to prove up a portion of the 3.3 trillion cubic feet equivalent or reserve potential that are positioned and emerging Haynesville Shale exposes us to; and two, to maintain our liquidity and strong balance sheet.

We are also excited about the establishment of the upper Haynesville as a commercial play because it adds additional reserve potential to our existing acreage. We are well positioned for future growth when gas prices improve with a large inventory of drilling locations in the Haynesville Shale and Cotton Valley in East Texas and North Louisiana, and in the Vicksburg and Wilcox trends in South Texas.

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

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from the line of Noel Parks from Ladenburg Thalmann & Co. Noel, you may proceed.

Noel Parks - Ladenburg Thalmann & Co.

I was interested in what you talked about as far as the Texas and Louisiana mix of wells, and I imagine some of that might have an eye towards coming on to the end of the year and what you might be able to do with the reserves in each area. Could you just talk a little bit about that, and also if you had any additional acreage you've been picking up lately?

Jay Allison

Yes, let me visit a little bit. If you look on slide 21, and we've always said that these slides are moving. In the first quarter we had roughly 27 Haynesville potential wells that we would drill, in 2009 we had 27 of them in the Louisiana and six in Texas. That was our 33 total wells.

If you look at slide 21 now, we have 34 of the drill sites in Louisiana, and we have four in Texas, and we've increased the number by five. We've always said that what we want to do is drill on all four to six corners of our acreage, and then our goal for the year is really not to materially increase production, although I think we'll have nice production gains, it's really to locate our wells so that we can have maximum reserve additions by year end.

So with that, let me have Mack talk to you about the drilling program, while we've moved it around a little bit, and then I'll comment or Roland can comment on any acreage that we've acquired.

Mack Good

Sure. What Jay said is totally accurate. I mean, obviously we've refocused on Louisiana, and the reason for that is the improved performance on the Louisiana side of the play across our acreage, and also included in that reasoning is the Upper Haynesville evaluation that we're also gaining by drilling on the Louisiana side.

So, the Texas side of the play is still appealing, but at higher gas prices. And we're fortunate in that most of our acreage on the Texas side is HPP, and in fact most our acreage, two-thirds of it is HPP. So we're in a fairly enviable position with regard to having the flexibility to move the rigs where we think we get the biggest bang for the buck, and add the reserves that we've targeted for this year.

Jay Allison

On acreage, we have picked up a few acres in the last 90 days. We won't tell you how many, but we have picked up a few. And we continue to look for acreage additions. We do that in small tracks, either 100 to 300 acres or larger tracks if we can do that. And we're constantly seeking add to the acreage that we think is the better part of the play.

I think we're one of the few companies that has the balance sheet to do that and not access to capital markets. In most of the acreage that we've picked up they are based upon drilling commitments. We've agreed to drill a well on say a section, and then we'll carry the non-working interest owner for a percent of the first well, and then after that, it's a program. I know they all vary, but that's kind of what we focused on right now.

I don't want to go into any other detail except that we do believe that the emerging Haynesville is real. We've been very cautious on our EUR's, and we're still at 5 Bcfe. Although in Louisiana, I did think you're going to have 6, 7, 8, maybe 9, depending upon what area you're in, in Louisiana.

We continue to spend now the remaining portion of our CapEx in '09 will be spent drilling Haynesville wells. As you all know, we've not issued equity since '05. We've not been in the bond market since probably '03, '04. We've stayed out of those ballparks. I think that gives stockholders a much greater chance of increasing the value of per well on a per share basis.

As long as we continue to spend money in the Haynesville, then I think we're pretty good indicators that we think it's going to create real value and again the value is the harder the company, which is your reserve adds, and that is why we're shuffling around a bunch of our wells in the drilling program; one, because we can; two, you'll notice in the seven wells that we connected to sales in the last 90 days, they're kind of weird wells, because we own 93% of one, 99% of one, 100% of one, 88% of another one, and 100% of the three Logansport wells.

So these are not only successful wells, we own most of them. They're very high impact wells, so we're focused on that also from the reserve adds kind of view.

Noel Parks - Ladenburg Thalmann & Co.

Okay, great. My apologies if I missed this, I had to drop off for a minute. Looking at what we've got with the strip right now and the pretty steep upward curve on it, I realize that your philosophy hasn't usually been to hedge much, but in these particularly unusual times, have you thought about anything more over maybe the next 6 to 12 months?

Jay Allison

As long as you've noticed we've never speculated on the future markets of oil or gas. What we do is, as you know, we operate 85% of our assets and our goal in '09, yes, we're going to we're going to borrow some on our available credit line. The intent is, because we made some wrong moves in '08 and we de-levered without issuing equity or entering the capital markets. We have the cushion to go ahead and have the drilling program we have in '09.

Now, if you go into 2010, our goal right now is to not outspend our free cash flow, and I'll put asterisks about that, because if we end up borrowing $170 million, $80 million, whatever it is, we'll end up borrowing on our credit line. Hopefully once the banks look at the reserve adds, which should be meaningful, our goal would be to get those dollars back. And if we had to have a similar program in 2010 as we had this year, we'd still be in the 25% debt-to-cap or so.

Someone asked, and when we were in Europe two or three weeks ago what our comfort level in the debt-to-cap is, and that's somewhere less than 30%. We had always said this year, that we want to have at least 300 million available unused on our credit facility by the end of the year. And we're sticking with that, that's one of our primary goals is; one, to prove up the Haynesville and add some cheap reserves; second, to keep our liquidity and our financial strength.

Noel Parks - Ladenburg Thalmann & Co.

Okay.

Jay Allison

We're not looking at hedging right now.

Noel Parks - Ladenburg Thalmann & Co.

Okay, thanks, that's all from me.

Operator

Our next question comes from the line of Ron Mills from Johnson Rice. Ron you may proceed.

Ron Mills - Johnson Rice & Company

Good morning.

Jay Allison

Good morning.

Ron Mills - Johnson Rice & Company

A couple questions on the Upper versus Lower Haynesville. I know that you talked about that in the Toledo Bend North area. One, how big is that field; and secondly, do you see the Upper Haynesville in other areas, or does it tend to be somewhat localized?

Mack Good

Ron this is Mack. Our Toledo Bend North acreage is approximately 12,000 acres. I can't go into detail about where we think the Upper Haynesville is prospective, because as Jay mentioned earlier, we're still trying to acquire acreage. Not everybody interprets it the same way as you know, but we think the Upper Haynesville is in certain areas not in others, it's too thin and too clay rich in some areas, but it's highly prospective as confirmed by the well that we announced today in our Toledo Bend North area with the 11.6 IP rate and that with great pressures as well. So, we're excited about the opportunity to pursue the Upper Haynesville in those other areas that we think are correlative to the Toledo Bend North result.

Ron Mills - Johnson Rice & Company

It's very early and you don't typically discuss this much, but based on what you're seeing from rock qualities and pressures and initial production rates, do you all at least internally think that the Upper Haynesville can be somewhat equivalent in terms of prospective size as the Lower Haynesville and is there any appreciable cost difference, because it looks like it's only 300 or 400 feet shallower?

Mack Good

Right, Ron. There's no appreciable cost difference. The Upper Haynesville part of the play will be smaller than the Lower Haynesville. I think everyone that's looked at it would agree upon that, the Lower Haynesville acreage, the prospective acreage is through the roof, depending on who you talk to, you'll get a different number on that. But certainly the Upper Haynesville is a sizable acreage play, and it's variable as is the Lower Haynesville.

Ron Mills - Johnson Rice & Company

I guess my, Mack I guess my question is in the areas that you have the Upper Haynesville, you would need two wells to develop it, but do you at least based on what you're seeing from the coring and your pressures and rock qualities to date think that the Upper Haynesville can have the same reserve on a per well basis potential as the Lower Haynesville?

Mack Good

I think the potential exists for that, sure in what we consider to be the core areas of both the lower versus the upper, the reserves would be fairly similar. But as you know, Ron we continue to be conservative. And as you mentioned at the very beginning of your question, it's very early, there's only, to our, as far as we've been able to gather the data that there have been only 14 Upper Haynesville flow tests that gave enough data to assess in any form or fashion, and only about six or seven of those tests have been horizontal wells. So the flow performance of production and performance from the Upper Haynesville has very little history. But given all the data that we have available to us right now, we continue to be very enthusiastic and excited about the opportunity it represents.

Ron Mills - Johnson Rice & Company

And I assume just based on depth, that additional Upper Haynesville drilling will take some time, just as you'd prefer to show a little Lower Haynesville and hold acreage?

Mack Good

Sure, absolutely. You want to get the lower first, and then the upper comes later, you bet.

Ron Mills - Johnson Rice & Company

And then Roland one just number's standpoint that you talked about the maintenance of Fandango. How much of that impacted your second quarter numbers just so we can get a more clean run rate.

Roland Burns

Yes Ron, that lowered our average daily production for the quarter by about 3 million a day. It was shut in during the month May, but it's a big field and we own a 100% of it. So, average over the quarter is been 3 million a day of production that we didn't have.

Ron Mills - Johnson Rice & Company

And on the cost side, second quarter pretty representative in terms of unit costs, what to expect going forward?

Roland Burns

I think so, Ron. I think we will see some additional improvements in the lifting costs per unit as the production levels increase, with the impact of the lower prices and severance taxes. And I think the tax rate we had for the quarter is probably pretty indicative of what we'll have for this year if we stay in a loss position.

Ron Mills - Johnson Rice & Company

All right. Let someone else jump in. Thanks, guys.

Operator

Our next question comes from the line of Jack Aydin from Keybanc. Jack, you may proceed.

Jack Aydin - Keybanc Capital Markets

Going back to Upper Haynesville, you got say 12,000 in North Toledo Bend and am I correct that you got about similar amount in South Toledo Bend?

Mack Good

Yes, sir. This is Mac. Yes sir.

Jack Aydin - Keybanc Capital Markets

Mack, is this South Toledo Bend also lending itself to Upper Haynesville?

Mack Good

You want me to extrapolate the Upper Haynesville plate where we haven't drilled yet?

Jack Aydin - Keybanc Capital Markets

Well, I mean, you could talk about it. I'm pushing a little bit.

Mack Good

I know you are and I appreciate that. We think in several of our acreage footprints in the play are prospective for the Upper Haynesville, and I would not exclude the south block certainly.

Jack Aydin - Keybanc Capital Markets

And we are assuming that you're going to, on 80 acres then, most of the drilling will be done. In this area, [basin] wise 80 acre spacing?

Mack Good

We are concentrating our drilling program now Jack on the Logansport area, another area to the east of Logansport and then the Toledo Bend North area. We have an extended clock on our new leases, so we don't have an issue, and that forces us to drill this year, although we do plan to drill a well on the southern side of our acreage. And as Jay mentioned earlier, we had several arrangements with some other companies in the area on a drill to earn basis, and so we'll look at substituting a drill to earn well for a well that's teed up at the moment, if some of those deals come forward and we're able to get those done.

Jay Allison

And right now Jack, we're saying 80 acre spacing, and, of course, it's like the Barnett, the Barnett went from 160 to 80 to 40 to 20. I think 80 is a good, that's a good number, 80 acres right now. And I think once Comstock and the other dozen or so companies continue to drill and develop out here, we'll really know if you can downsize from that, but that's a number we're kind of sticking with right now. As far as the Haynesville, the Upper Haynesville, the Bossier, is what kind of spacing on that you were just…..

Mack Good

We're still assuming the 80 acre spacing, Jay. Right now all of the operators or most of the operators are drilling one well per drilling unit for obvious reasons, to get a lot of their new leases drilled and held by production. So there has not been yet a significant, hardly any at all actually, infill drilling to test the spacing rule; what kind of spacing is the optimum spacing. The data that we have and that has been analyzed not just by us, but by several other parties, indicates 80 acres is a good initial assumption on the spacing.

Jay Allison

Remember the other thing, Jack, we are trying to add acreage that we have, and some of the wells that we've earmarked to be drilled in certain areas on that chart page 21, they'll be moved to acreage that you don't see on that chart, because of drilling commitments that we have to earn some acreage.

So, hopefully we'll have added some acreage by year-end. We'll have drilled the same number wells plus five, because we increased it by five today. So now, I think that's how you create value. We did that without increasing our CapEx budget.

I was asked before the conference call, what about other regions, and we do have the other regions. And if you look at our normal charts, which tell you that, over 80 Bcfe reserves are in other regions, which is about 15% of our total reserve base.

A lot of that is oil, and at some point in time when the sector turns around and oil becomes more valuable, those areas are divestiture areas in the future for us, not right now. We don't think it would fetch the price that we think it's worth, but I did want to comment on that as far as the amount of money we're spending and then around the regions.

Jack Aydin - Keybanc Capital Markets

Let us assume you complete all the Haynesville well that you plan to drill and hook them to production, you'd be able to book those reserves from those wells, how many offset wells you'd be able to book assuming all those that you plan to drill are on a production.

Mack Good

Well, Jack, right now the assessment would be that we could minimally book two offsets to every well we are drilling in the Haynesville. So the new SEC rules are still being vetted by all of the companies meetings and symposiums are occurring almost monthly to figure out the rules and how they apply to the reserve bookings. But there is the potential to book more than that, if an operator can prove that there's continuity and similarity between a point in the play to another point in the play that is more distant than just the one offset spacing. So.

Jack Aydin - Keybanc Capital Markets

So if I look at your reserve, at year-end 2008 and just use Wall Street's math, you could have a huge addition?

Jay Allison

Well, at the end of '08, Jack remember we booked one Haynesville well. We booked the Black Stone Mineral 7 number 1H and two offsets to that, and that was 11 Bcfe out of the 582 Bcfe of proved reserves that we reported on December 31 of '08. So that one well and two offsets added 11 Bcfe, so now our goal is to drill 38 Haynesville wells and if they're successful, book whatever reserves that we can under the new reserve rules. So again, I think we have a really good chance of having some nice reserve adds and materially lower our cost or funding cost as our goal.

Operator

Our next question comes from the line of Michael Bodino from SMH Capital. Michael, you may proceed.

Michael Bodino - SMH Capital

Just a couple of follow-up questions. Could you help us out with the pipeline infrastructure interconnects and where you are in that process and kind of how you see production moving up over the next couple of months?

Roland Burns

Sure Michael this Roland. We had several big projects, we were trying to get additional takeaway capacity for our Haynesville program, especially now that it has been more concentrated in the DeSoto Parish than our original program that we looked at the very beginning of the year. I think that we've added some additional takeaway, at the Logansport area, which has allowed us to complete those big volume wells, and so we're doing really well there.

We have additional takeaway also for our Toledo Bend area, and we don't have all the full treating and processing up and going, that should all be totally finished by November 1, but we do have, we will have capacity to a variety of interconnects. We think pretty much to try to keep the new wells that we're drilling completed and put on line.

But we won't have a lot of excess capacity in that area, until November 1, then we'll have quite a bit of capacity when the new line is up and installed and also connected to the several interconnect points that they've agreed to put it in. What it's, is as we are adding the additional takeaway, it's kind of been just in [temperament], so it's not a one complete answer. Other than by November 1, we expect everything to be finished there, but we do think we'll have a decent amount of capacity of those in some places it will be a little tight, especially Toledo Bend North until November 1.

Michael Bodino - SMH Capital

Is this going to drive your drilling program on the back half of the year, and are we going to see blocks of wells, you've drilled five wells and then all of a sudden when that interconnect comes on, we'll see these five wells completed or how do we think about the program relative to production on the balance of the year?

Mack Good

Michael, this is Mack. We've got four wells waiting on completion right now. We'll start two of those completions next week. We're scheduling our completion program to dovetail and to what Roland was talking about, the staggered capacity availability that is forthcoming. We don't see any significant delays. We discuss this internally, as you might imagine on a daily basis. And we have multiple connects, multiple points of transport. We have additional capacity that as Roland mentioned is going to be available to us in a staggered fashion, and by November 1. So again our completion schedule is designed to feed that capacity, so we're in pretty good shape, actually.

Michael Bodino - SMH Capital

Okay, and what do you think your takeaway would be kind of at the turn of the year, at December 31? Do you have a kind of a number in mind?

Mack Good

Well, yes, we've got about 100 million a day ballpark from capacity, and then we have other outlets that add to that in increments. That's the capacity we have today, and of course we're working with a couple of parties to gain additional capacity.

Michael Bodino - SMH Capital

Okay. And then I have one follow-up question on the Upper Haynesville. I know you've drilled one well, and you're in the process of getting some production history there. Are there any other Upper Haynesville wells planned in the foreseeable future?

Mack Good

We're targeting the Lower Haynesville for the remainder of the year. Obviously, every Lower Haynesville well we drill will penetrate the Upper Haynesville. We'll be gaining some additional pouring data. We also are data trading with some other partners, and we'll be getting additional data that way. So, the short answer to your question, Michael, is that we're going to target the Lower Haynesville for the remainder part of the year.

Michael Bodino - SMH Capital

Okay. Of the 14 Upper Haynesville flow tests that you've analyzed, and the 6 to 7 that have been horizontal, where are they predominantly located?

Mack Good

Well, I can give you this. They're across the play. Predominantly they're in the western part of DeSoto, there's a couple over in Red River Parish, there's a couple in Sabine and there's one in Shelby County, Texas. So, a concentration of those tests are in the Logansport region.

Michael Bodino - SMH Capital

Okay. I guess from a kind of a geologic or maybe even geographic standpoint, it sounds like the upper Haynesville is more of an [on lapping] structure above the Lower Haynesville as it gets deeper to the south. This kind of develops and gets thicker, and more prospective as you move into the term maturity window. Is that a fair statement?

Mack Good

I think that's a fair statement, although there is some exceptions to that rule.

Operator

Our next question comes from the line of Amir Arif from Stifel. Amir , you may proceed.

Amir Arif - Stifel Nicolaus & Company

A quick question on the 21 million a day wells that day you did. I mean it seems like same number of fracs and lateral [ones]. Is there anything different you are doing on that well or is that simply a sweet spot of the play?

Mack Good

That's a sweet spot of the play. We've extended that sweet spot to the west. If you've been following the high IP rate well locations, you'll see that the Colvin-Craner, our 21 million a day well, extends that sweet spot to the west.

Amir Arif - Stifel Nicolaus & Company

Is there any reason to believe that the Caraway 3 wells won't be giving you the same kind of results when you test that?

Mack Good

There's always reasons. There's a lot of variability, local and variability in the shale, but certainly our expectations are quite high Amir for that well, yes, sir.

Amir Arif - Stifel Nicolaus & Company

And then you mentioned the well costs to come down to 7 to 8 million, do you look for those costs to come down another 10%, or do you think this is where they're going to stay in the second half.

Mack Good

It's 7 million, I ask that question all the time. Can we squeeze a little more cost out of the drill and complete cost structure in Haynesville. 7 million a day is squeezing the vendors pretty hard, given this environment.

So we think that if we have no problems, we don't have to drill a pilot hole, and, of course, we're optimizing our drilling and completion operations and tweaking, that's where we can drill faster or complete faster.

We think we can push below seven, but getting another 10% or so off the seven, that would push it down to [6.3] and that's pretty tough, Amir. I think 7 million, 6.5 to 7 would be about the low window, as far as the costs that we've seen.

Amir Arif - Stifel Nicolaus & Company

And just given the fact completion costs have been dropping faster than drilling costs, any desire to try to increase the laterals or increase the number of stages in fracs?

Mack Good

Yes. But with increasing the laterals and increasing the number of stages, also comes an increased risk. When you drill the longer lateral, you have to of course run casing through that longer lateral, so just for the sake of discussion, add another 1,000 feet, 800 feet to the lateral length. In certain parts of the play, they can present a problem. In other parts of the play, it's not as bigger problem.

You also have to have a surface location outside your lease, so you can drill that extra long lateral, and build a curve and then have enough room on your drilling unit on the Louisiana side to accommodate an extra long lateral.

Buy we are certainly looking at all those. Our lateral length has gone up over the last several wells to an average of around 4,200 feet, and we were in the 3,700, 3,800 foot range. So we're gradually lengthening that lateral and we are doing all of the above in a shorter period of time.

Our drilling times are trending down. We're improving our bid program, and our operational approach to getting these wells drilled, and our completion time is improving significantly, and we are looking at changing the number of stages, the number of perforations per stage, the amount of profit per stage, et cetera, and tweaking that.

We're tweaking in fairly small steps, because we want to make sure that we find the right optimum approach in certain areas of the play. So we don't want to make a big change, and not really know what would have worked at a lower cost. …..

Amir Arif - Stifel Nicolaus & Company

That makes sense. Just one final question, your co-production, you mentioned is that 190 a day? Do you have a sense of what are your third quarter numbers, they are going to line up on the production front, for a range?

Roland Burns

Amir, we feel like the third quarter should average in probably the mid 180s.

Operator

And our next question comes from the line of Mark Lear from Sidoti & Company. Mark you may proceed.

Mark Lear - Sidoti & Company

I guess with a couple east Texas tests under your belt, and moving away from that part of the play, I guess if you could kind of give me an idea comparing the areas to your core and what you think needs to get figured out more, or whether it's just be pricing, that would get you back in there.

Mack Good

Well, Mark, this is Mack. All of our east Texas. All of our Texas side acreage in the play at this point is HPP. We don't have any lease clocks that are working to cause us to get back on that side of the play. In previous calls you may or may not have been online for those.

But Jay made it very clear that part of our strategy in pursuing the Haynesville play was to test the individual acreage footprints that we have across the play, we've done that on the Texas side, we've evaluated our acreage. We have a pretty good idea of what the potential is within those individual areas on the Texas side.

So your question is a good one, what would it take to get back on that side of the play. Well, obviously, commodity price is a big part of that answer. The current commodity price that we're seeing argues for us to be on the Louisiana side where the performance is better per dollar spent, obviously our reserve adds are better per dollar spent. Our cash flow is better. We also have all of our new leases on the Louisiana side. So we have several reasons to drill on the Louisiana side rather than on the Texas side, but the Texas side is some of ramped size is all HPP.

Jay Allison

Well, I remember we had said on kind of the 2009 outlook Mark, that with this $360 million CapEx budget, we really want to focus on our highest return projects, and if we think the reserves in part of Louisiana are twice the size of East Texas, and you've $7 million, $7.5 million to drill and complete those wells, and we're going to focus on that because we'd add more reserves for basically the same amount of money.

Mark Lear - Sidoti & Company

Right, and then I guess looking at the lack of activity in Panola and Shelby Counties. Would that be because it's been tested by other operators or just similar to what you just said about returns?

Mack Good

I won't presume to speak for other operators. I do know that a lot of that acreage is HPP as well. So I would assume that the same logic applies for them as it does for us. If they have acreage on the Louisiana side, but some only have the acreage on the Texas side, and they're trying to optimize what they have.

Mark Lear - Sidoti & Company

Right. No, I guess I was pointing more towards why you aren't testing the Shelby acreage or the stuff in Panola that has had pretty good flow rates in terms of East Texas.

Mack Good

We have all that data. Mark, we looked at it. We still feel that going to the Louisiana side is the best course of action for Comstock and our shareholders.

Mark Lear - Sidoti & Company

Okay and I guess a little bit off the mark, but just looking at your South Texas acreage. Some of it appears to be in vicinity where they're testing. Eagle Ford Shale, I was just wondering if you guys have any potential there or are looking in that area at all.

Mack Good

Not for the Eagle Ford, no, sir.

Operator

Our next question comes from the line of T.J. Schultz from RBC Capital. TJ you may proceed.

T.J. Schultz - RBC Capital Markets

Hey guys a lot covered, just kind of a follow-up on your thoughts on East Texas. I know you were still using 5 Bcf for your EUR's across the play, and obviously you're looking at twice the reserves on the Louisiana side. Can you just give me a feeling for what you're thinking on the East Texas side, and if those are half kind of what you're thinking, that's 6, 7, 8, 9 on Louisiana or just a little more clarity on your thoughts on the EUR's?

Mack Good

This is Mack. On the Texas side, we're looking at anywhere from 3 to 4 Bcf. There have been some wells drilled that are lower than that, there have been some that have pushed the 4 Bcf type number. And on the Louisiana side, again depending upon where you're drilling, you're targeting, and we've stayed conservative from the onset in our EUR's. We want to see a little more production history before we jump out and reassign a type curve EUR for some of our areas. And that's why you hear us talk a lot about the 5 Bcf type number for the Louisiana side.

But as Jay mentioned earlier, we all know here that our EUR is going to go up on the Louisiana side. We're not ready to quantify that yet, but 5 to 7 Bcf type numbers is the on the short-term side of the production history that we have. That's what it appears to be laying out. If not in certain areas significantly better than that, significantly better than the 7 Bcf number. So, we're focused on those areas that are the higher EUR areas on the Louisiana side of the play.

T.J. Schultz - RBC Capital Markets

Okay. What about well costs, is that $7 million number, is that consistent on both sides of the play?

Mack Good

Yes. That's where the costs are trending toward that $7 million number, and that's without a pilot hole, and of course no drilling delays.

T.J. Schultz - RBC Capital Markets

How many rigs are you running right now, and do you have any plans there or what's your plan by the end of the year?

Mack Good

We have four rigs currently running, and we anticipate the delivery of two more rigs within 60 days. We have a very flexible rig inventory where we can maintain that number of rigs, go to six rigs, exiting the year, or we can step back and run fewer rigs. So, we're going to be running five rigs probably exiting the year. We'll look at that sixth rig subject to the drill earns arrangements that Jay mentioned earlier. As then as we move into 2010, we'll take a hard look at our cash flow model and how many rigs we want to run in order to stay within that cash flow ceiling.

T.J. Schultz - RBC Capital Markets

Okay, great. Just one housekeeping item, can you give me your production tax number for 2Q '09?

Roland Burns

I think it's actually in the press release too. [David] why don't you call back after the call, and I'll make sure to show you where it is.

Operator

Our next question comes from the line of Ray Deacon from Pritchard Capital. Ray, you may proceed.

Ray Deacon - Pritchard Capital Partners, LLC

Mack, I was wondering if you could talk just a little bit more about the Texas side. I thought you were pretty clear, but it looked like that Woods well as you move to the west looked like your best well. And I thought your feeling was that the lower clay contents would be to the east and then you'd sort of gradually see better wells that way. Were you a little surprised by that well, I guess is my question?

Mack Good

Right. And Ray, we were a little surprised too, pleasantly so. The Woods is a little west. There are local variations as I mentioned earlier. We didn't do anything different on the Woods versus the other wells, the [Grane] and the Cox.

We're re-evaluating that particular area, but if you look at the overall data. It is true that as you trend to the west, the lower Haynesville does get more clay-rich, and the thicknesses will vary of the total Haynesville package.

But you'll see that the clay content jumps up, you'll see that the porosity falls, and it's a little harder if not a lot harder to complete, in a more clay rich Haynesville section, and obviously the gas that's there out of the ground. So, the Woods is our best well in that area to date.

Ray Deacon - Pritchard Capital Partners, LLC

The number of wells you are drilling is going up, but you are keeping that production guidance at the same level. Is that due to transportation constraints or just conservatism, I guess?

Mack Good

Well, I think in an emerging play where there's a lot of gas coming out of the area, although we feel like we've got our bases covered on the takeaway capacity, I think it's not a bad thing to have a little conservatism built into your forecast.

Jay Allison

We're trying not to disappoint people.

Mack Good

That's always a bad thing, but certainly we feel that we have the potential to do better than the numbers that the guidance that we're giving on our production side, but there are some challenges ahead of us, none that we don't think we can manage effectively, but that's the driving driver behind the forecast.

Roland Burns

The additional five wells are mostly going to be drilled in the fourth quarter, so they're really not going to impact this year anyway regardless of that.

Operator

Our next question comes from the line of Dan McSpirit from BMO Capital Markets. Dan, you may proceed.

Dan McSpirit - BMO Capital Markets

Could you discuss the choke size applied on your latest set of Haynesville shale producers and how that may have changed overtime, since you began this drilling campaign, and how you might use that going forward to better manage the decline rate?

Mack Good

Our normal approach to testing our wells and then subsequent to production is to incrementally and slowly increase the choke to a 26. And most of the data trade partners that we do business with are following that same path in most of their wells, not all, but most.

We don't want to put excessive pressure to draw down across the Haynesville. We don't want to risk bringing propane into the well bore. We certainly don't want to risk bringing shale into the well bore, into the lateral, that would cause us some problems.

So, we've got all of the data from our data trade partners and they from our wells, and we've all had a few issues on the flow-backs on putting excessive draw down on our wells too quickly.

So there's been an evolution if you will towards being very gradual with the choke change. And in terms of choking wells going-forward, certainly we look at that. It's a variable. It depends upon a lot of different factors. Takeaway capacity that's relevant to the well or wells that we're looking at operationally.

There's also some treating requirements, these wells make a little CO2 depending on the pipe you're going into, if it's a 3% CO2 pipe, in most cases for us, at least, we don't have an issue, if it's a 2% CO2 pipe, then there is some treating required, and depending upon where that pipe is, versus the treating stations, we may have to choke back for a period of time while they get additional or we get additional treating capacity to knock out the CO2. So, there's some variables there. Hopefully that answers your question.

Dan McSpirit - BMO Capital Markets

What are you modeling for first year decline rate today and how has that changed over time?

Mack Good

We're still sticking with the 81% to 83% modeled number. Most are doing the same, and that's a variable as well. There's not a whole lot of wells that have one year production out here, certainly we're looking at the break-overs in some of our wells to the tunnel decline rate is occurring more quickly. In other words, we're not saying that significant of a decline. So, we're looking into that hard than depending upon the particular area of the play. And so are our data trade partners.

Dan McSpirit - BMO Capital Markets

Lastly if I could, what would it take to drill the upper and Lower Haynesville from a single well bore. Is it feasible?

Mack Good

The drilling side, certainly is not a problem. But as to the completion side that presents all the headaches. The Haynesville is abnormally pressured. So the frac pressures, the treating pressures required are quite high, and if you can imagine having pressure containment at each of the laterals intersection to the vertical part of the well bore, that's where the problem is. There are mechanical configurations that are available, they're used offshore all the time, but you have to drill a very large hole to run this equipment and the cost would be exorbitant.

So the short answer is there's not a cost effective solution yet to do what you described. And although it's something that we would certainly like to pursue at later date, and we've talked to several vendors about this and they're looking into off the shelf modifications of existing equipment that would allow that. But there's some work to do on it.

Operator

Our next question comes from the line of Ron Mills from Johnson Rice. Ron you may proceed.

Ron Mills - Johnson Rice

Just one follow-up. Mack or Jack I can't remember who talked about the reserve bookings at the end of last year, from the one well plus the two puds, is that 11B's for that producing well, plus the two puds. Is that a pretty good number that you'll would expect going forward or what's that dependent on, and will the lower gas prices, would those have any impact on those bookings?

Mack Good

Ron it is Mack. Jay had referred to our one well that we booked last year with the offsets that was in our Toledo Bend North area that was with our original completion approach. Long story made short, we think our EUR's are going to move up in that same area, they're going to increase. We're not ready to give a firm EUR expectation yet. We're still looking at the data, but certainly the data so far is very encouraging.

So we expect our EUR's to move up in that particular area where we booked only one well and two offset puds last year, and got close to 11 Bcf net adds. So in other parts of the play, we think the EUR's will move up from that, and we'll have the consequent benefit of that. As Jay mentioned earlier, all of the wells that we've scheduled in our acreage on the Louisiana side have very high net interest impact on our production and our reserve adds.

Ron Mills - Johnson Rice

And were there any appreciable differences between the producing well and the two puds in terms of how they were booked? I guess, where the puds booked as less than what the producing well was?

Mack Good

We did book the puds at slightly less than the producing well, that's right. We risked it a little bit. We now have data that would suggest that those puds could be booked at a higher number.

Jay Allison

The other thing about that, Ron, is again, out of the seven wells we just talked about, in the second quarter, four of them we own a 100% working interest in, one we own 99%, one we own 93, in the upper Haynesville we own 88%. So those. That should be some good indicators of what the year could look like.

Operator

At this point we have run out of time for questions. Mr. Allison, you may proceed.

Jay Allison

Yes. I'd like to close, and I know we've been on in for an hour and 20 or so, but I'd like to keep everything really simple if you can. I think there's a lot of background noise that confuses what we're trying to do. I am very pleased that Mack and the operations group, the geological group, including the land and marketing and accounting, all the different departments we have here, which is a management group including the Board, I think they function very well.

If you look at what's happened in '08, we monetized our position in Burdock, we sold another $138 million of non-core properties, we materially strengthened our balance sheet, and we did that without issuing stock.

And today if you look at the company, we've had the same name for about 20 year's. We have 1.6 billion of assets, 1 billion of equity or so. We've got 15 Haynesville wells that we drilled completing connected to sales, and we're way down the path, versus where we were in the fourth quarter of '08.

And if you look at our balance sheet, it's unbelievable that a company of this size would have 410 million available under a credit line, without having issued equity, and that's I think is overlooked often, and we don't have any debt maturity issues.

We got a bond due in 2012 and that's it. But I think the group is executed, I think they've delivered good production growth, I think it will be better in the third quarter, and hopefully in the fourth quarter.

If you look at the drilling, we've reduced our drilling and completion time materially, the service costs have gone down maybe by half, and we've done all that being the same company. We hadn't chased something weird and we didn't bet the farm on anything. We've simply hunkered down and developed what we had helped discover in the third quarter of '07 and it is working.

So I thank you for your patience, I know that we don't put out press releases, usually in between our 90-day reporting period. I know some people get kind of anxious on hearing what we're doing, and we've always told you something really bad happens, you're going to hear about the minute it happens, and if we have really good results, like we've had, usually you hear about at the quarterly conference call.

So we're thankful to serve you, and work for you, and report to you. So Josh, that's it thank you.

Operator

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. Q2 2009 Earnings Call Transcript
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