Comstock Resources Inc (CRK) 2009 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second quarter, 2009 Comstock Resources Inc. earnings conference call. (Operator Instructions). I would now like to turn the presentation over to our host for today's call, the President and CEO, to Jay Allison. You may proceed.

I would like to directly thank everyone for participating in the conference call. I know it's a busy day, we're always thankful you'll 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'll 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 meanings 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 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 and we generated EBITDAX and operating cash flow of $92 million or $0.90 per share. The low prices 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 had initial production rates which averaged 18 million cubic feet equivalent of natural gas per day, an improvement over our first quarter wells. We also tested our first successful horizontal well in the upper Haynesville or Bossier shale in DeSoto parish, Louisiana this quarter. This success could have a significant impact on the reserve potential of our acreage in the southern part of the Haynesville play. Despite the weak environment, we continued 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?

Thanks, Jay. On slide three we break out 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 we divested of last year.

Production was up from our first quarter average rate of 157 million 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 to do 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 four. Our average oil 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 of 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 five. 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 the second quarter as basis differentials have improved from 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 for 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 for $3.88 per MCF. For the first half of this year, the 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 seven, we cover our oil and gas sales. The lower prices cause 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 156% to $133 million as compared to the $300 million that we had for the same period in 2008. Our earnings before interest, taxes, depreciation, amortization, exploration expense and other noncash expenses or EBITDAX decreased 71% in the second quarter to $42 million as shown on slide 8. For the six months ended June 30, 2008, EBITDAX decreased 65% to $88 million.

Slide nine 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's 2nd quarter. Operating cash flow in the quarter was increased by a 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 per share as compared to $100 million in net income, or $2.17 per share in the first half of 2008.

We outline our cost structure for the six 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 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 $0.07 to $0.91 due to the higher production level that we had in 2009. Our cash G&A expense averaged $0.39 so far in 2009 reflecting the increased staffing level that the Company has. Cash taxes are a 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 due to the lower debt level that we now have. 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 million 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, 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.

On slide 13 we detail our drilling expenditures. We spent $175 million 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 $1 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.

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 6 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 averaged 10.3 million cubic feet equivalent per day and the vertical wells averaged 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?

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 7 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 or Bossier shale for completion.

In Harrison county, Texas, Comstock drilled and completed three wells targeting the lower Haynesville shale in the Blocker field area. The Green, number 13 H 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 1 H 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 at an 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 2 H was drilled in our Toledo Bend North field in 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 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 2 H 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 tested at an initial production rate of 21.2 million cubic feet equivalent per day. The Broom number 1 H 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 11 frac stages and flow tested at an initial production rate of 16.7 million cubic feet equivalent per day. Finally, the Weyerhaeuser number 2 H in Logansport was drilled to a vertical depth of 11,493 feet with a 4,181 foot horizontal lateral. This well's 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 if the area in the play. We anticipate encountering a net pay 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 in the same well bore 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 we will generally pump 10 fracture 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's 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 we've drilled in the play, was 51 days compared to 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 spudder 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 use this spudder rig approach, and the sales connection time for these six wells was 137 days. Comparatively, the eight wells that did not use this spudder 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. And with that, I'll turn it over to Jay.

Thank you, Mack. Our South Texas region is displayed on slide 19. In our South Texas region we drilled 4 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 the Santa Fe Ranch field in Kenedy county, Texas.

In the second quarter we drilled the Santa Fe Julian Pasture number two well to total vertical depth of 12,200 feast 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. Costs 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 net 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 Louisiana. We expect our Louisiana wells to have twice the reserves as compared to the Texas wells drilled so far this year. Approximately two-third of our acreage is in Louisiana.

Now to slide 22. 2009 outlook. 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 Bois d'Arc Energy and the noncore 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 to 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 of reserve potential that our position in emerging Haynesville shale exposes us to, and 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 for the 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. I'll turn it back over to you for questions.

Thank you very much, sir. Our first question comes from the line of Noel Parks from Ladenburg Thalman, Noel, you may proceed.

Good morning.

Good morning.

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 toward 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?

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 well -- potential wells that we would drill in 2009, we had 27 of them in Louisiana and 6 in Texas, that was our 33 total wells. And if you look at slide 21 now, we have 34 of the drill sites in Louisiana, and we have four in Texas, we've increased the number by 5. We've always said that what we want to do is drill on all four 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 and why we've moved it around a little bit, and then I'll comment or Roland can comment on any acreage we've acquired.

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 HBP, where in fact most our acreage, two-thirds of it is HBP, so we're in a fairly enviable position with regard to having the flexibility to move the rigs where we think we can get the biggest bang for the buck, and add the reserves that we've targeted for this year.

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, 100, 200, 300 acres or larger tracks if we can do that. We're consistently seeking to add to the acreage that we think is the better part of the play. I think we're one of the few Company's that has the balance sheet to do that and not access the capital markets. Most of the acreage that we picked up, they're based upon drilling commitments.

We've agreed to drill a well on a section, and then we'll carry that -- the working interest owner for a percent of the first well, and then after that, it's a heads up program. I know they all vary, but that's kind of what we focus on right now. I don't want to go into any other details 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 do think you're going to have 6, 7, 8, maybe 9, depending on what area you're in Louisiana, and we continue to spend now the remaining portion of our CapEx in '09 will be spent drilling Haynesville wells. As we -- 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 on a per share basis, and as long as we continue to spend money in the Haynesville, then I think we're pretty good indicator that we think it's going to create real value, and again the value is the heart of 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, if you'll notice in the 7 wells that we connected to sales in the last 90 days, they're kind of weird wells, because we own 93% of one, the 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 add kind of view.

Okay, great, and my apologies if I missed this, I had to drop off for a minute. When -- I mean 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, I mean, have you thought about anything more over maybe the next 6 to 12 months?

As long as you've known us 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 borrow some on our available credit line. But that -- the intent is, because we made some right moves in '08 and delevered 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 cash flow, and I'll put an asterisk by that, because if we end up borrowing 170 million, $180 million, whatever it is,,we'll end up borrowing on our credit line, hopefully once the banks look at their reserve adds, which should be meaningful, our goal would be to get those dollars back. And if we had it 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, while we were in Europe two or three weeks ago, what our comfort level in a debt to cap is, that's somewhere less than 30%, we'd 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. It's one to prove up the Haynesville and add some cheap reserves. Second to keep our liquidity and financial strength.

Okay.

We're not looking at hedging right now.

Okay, thanks, that's all from me.

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

Good morning.

Good morning.

A couple questions on the upper versus lower Haynesville, it -- 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?

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. And 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, so with great pressures as well, so we're excited about the opportunity to pursue the upper Haynesville and those other areas that we think are correlative to the Toledo Bend north result.

It's way 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 lower Haynesville, and is there any appreciable cost difference? It looks like it's only 300 or 400 feet shallower.

There's no appreciable cost difference. And the upper Haynesville will part of the play will be smaller than he 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.

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 all, at least based on what you've seen 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 basispotential as the lower Haynesville?

I think the potential exists for that, sure. And in what we consider to be the core areas of both the lower versus the upper, the reserves would be fairly similar, as you know, Ron, we continue to be conservative and as you mentioned at the very beginning of your question, it's very early, 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 that the flow performance or production 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.

Okay, and we're -- I assume just based on depth, that additional upper Haynesville drilling will take some time, just as you prefer to drill into the lower Haynesville and hold acreage?

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

Roland, from a number's standpoint, you talked about the plant maintenance at Fandango, how much of that impacted your second quarter numbers just so we can get a more clean run rate?

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

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

I think so, Ron. The -- I think what we will see some additional improvements in the lifting costs per unit as the production levels increase. And with the impact of lower prices on severance taxes. 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.

All right. Let me let someone else jump in, thanks, guys.

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

Hi, guys.

Hi, Jack.

How are you, Jay?

We're good, Jack.

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

Yes, sir, this is Mack.

Mack is South Toledo Bend also lend itself to upper Haynesville?

Oh, you want me to extrapolate the upper Haynesville plate where we haven't drilled yet?

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

I know you are, I appreciate that. We'll -- we think several of our acreage footprints in the play are prospective for the upper Haynesville. And I would not exclude the south block certainly.

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

We're 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 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're -- we have 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.

Right now, Jack, we're saying 80 acres spacing, and, of course, it's like the Barnett, the Barnett went from 160 to 80 to 40 to 20, I mean, 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, what kind of spacing on that--?

We're still assuming the 80 acre spacing. 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 that 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.

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 the 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, hopefully we'll have added some acreage by year end.

We'll drill the same number of wells plus five, because we increased it by five today, 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, if you look at our property charts, which tell you that, over 80 BCFE of reserves are in other regions and it's 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 they 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.

Okay, looking at -- let us assume you complete all the Haynesville well that you plan to drill and hook up -- hook them to production, you be able to book those reserves from those wells, how many offset wells you be able to book assuming all those that you plan to drill are on a production.

Well, Jack, right now the assessment would be that we could minimally book two offsets to every well we're 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 the -- 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.

If I look at your reserve, at year end 2008.

Yes.

And just use Wall Street's math you could have a huge addition?

Well, at the end of '08, Jack, remember, we booked 1 Haynesville well. We booked the Back Stone Minerals 7 number 1 H 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 we can under the new reserve rules. So this -- again, I think we have a really good chance of of having some nice reserve ads and materially lower our costs, our finding costs as our goal.

Appreciate it, thank you.

Thank you, Jack.

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

Good morning guys.

Hi, Michael.

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

Sure, Michael, this is Roland. We had several big projects underwayto get additional take away capacity for our Haynesville program, especially now that it's been more concentrated in DeSoto parish, than our original program that we looked at through the end of the year, I think 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. We will have capacity through a variety of interconnects, e think pretty much to try to keep the new wells that we're drilling completed and put on line, and -- we won't have of 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 in. it's kind of a -- what it is, is as we're adding additional takeaway, it's kind of been just increments, it's not one complete answer, other than by November 1, we expect everything to be finishedthen, but we do think we'll have a decent amount of capacity on those, in some places it will be a little tight, especially Toledo Bend north until November 1.

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

Michael, this is Mack. We have four wells waiting on completion right now, we'll start two of those completions next week. We're scheduling our completion program to dovetail into 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.

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

Well, the -- yes, we got about 100 million a day, ballpark firm capacity, and then we have some 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.

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

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

Of the 14 upper Haynesville flow test that you've analyzed, and the 6 to 7 horizontal, where are they predominantly located?

Well, I -- they're across the play, they spread from -- predominantly they're in the south, 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.

Okay.

So there's a concentration of those tests are in the Logansport region.

Okay. I guess from a geologic or maybe even geographic standpoint it sounds like the upper Haynesville is more of an overlapping structure above the lower Haynesville as it gets deeper to the south, this develops and gets thicker, and more perspective as you move into the thermal maturity windows, is that a fair statement?

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

Very good. Good quarter, guys, and look forward to hearing more about some of the upcoming wells.

Thank you.

Our next question comes from the line of Amir Arif from Stifel.

A quick question on the 21 million per day- well( that you did. It seems like the same number of fracs in the lateral length, is there anything different you were doing on that well or is that simply a sweet spot of the play?

That's the 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.

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

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

Okay. And then you mentioned the well costs have come down to 7 million 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 the second half?

$ 6 million, $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're -- 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 to where we can drill faster, complete faster. We think we can push below $7 million, but getting another 10% or so off the $7 million, that would push it down to $6.3 million and that's pretty tough, Amir. I think $7 million, $6.5 million to $7 million would be the low window, as far as the costs that we've seen.

Okay, 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 numbers of stages to the fracs?

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 big a problem. You also have to have a surface location outside your lease so you can drill that extra long lateral and build the curve and then have enough room on your drilling unit on the Louisiana side to accommodate an extra long lateral, but we're certainly looking at all those, our lateral length has gone up over the last several wells to an average of around 4,200 feet.

We were in the 3,700, 3,800 foot range, we're gradually lengthening that lateral and we're doing all of the above in a shorter period of time, our drilling times are trending down, we're improving our bit program, and our operational approach to getting these wells drilled, and our completion time is improving significantly, and we're looking at changing the number of stages, the number of perforations per stage, the amount of proppant per stage, et cetera, and tweaking that we're tweaking it 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.

That makes sense. Just one final question, your current production, you mentioned about 190 a day, do you have a sense of where your third quarter numbers are going to line up on the production front? For a range?

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

Okay.

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

Good morning, 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 give me an idea comparing the areas to your core and what you think needs to get figured out more, or whether it would just be a pricing, that would get you back in there.

Well, Mark, this is Mack,. All of our Texas side acreage in the play at this point is HBP. We don't have any lease clocks that are working to cause us to get back on that side of the play. We have -- 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 on 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 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. And we also have all of our new leaseson 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 all HBP.

And remember we had said in light of our 2009 outlook market with this $360 million CapEx budget, we really wanted to focus on our highest return projects, and if we think the reserves in part of Louisiana are twice the size of east Texas, you have $7 million, $7.5 million you ought to complete those wells, we're going to focus on that because we had had more reserves for basically the same amount of money.

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?

Well, I -- I won't presume to speak for other operators. I do know that a lot of that acreage is HBP 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.

Right, no, I guess I was pointing more toward why you aren't testing the Shelby. Your Shelby acreage or the stuff in Panola that's had pretty good flow rates in terms of east Texas.

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.

I guess a little bit off the mark, but just looking at your south Texas acreage, some of of appears to be in the vicinity of where they're testing Eagleford shale, I was just wondering you guys have any potential there or are looking in that area at all?

Not for the Eagleford, no, sir.

Got you, thanks a lot.

Thank you.

And our next question comes from the line of T.J. Schultzfrom RBC Capital,T.J., you may proceed.

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 6, 7, 8, 9 on Louisiana or a little more clarity on your thoughts on EUR's.

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 on 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, that's why you hear us talk a lot about the 5 BCF type number for the Louisiana side. 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 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.

Okay, and what about well costs, is that $7 million number, is that consistent on both sides of play?

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.

And sorry if I missed this, how many rigs are you running right now, and do you have any plans there? What's your plan by the end of the year?

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 5 rigs probably, exiting the year. We'll look at that 6th rig, subject to the drill to earn arrangements that we -- that Jay mentioned earlier. And 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.

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

For the second quarter?

Yes.

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

Great, thanks, appreciate it, guys.

Thank you.

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

Yes, hey, Mack, I was wondering if you could talk to us a little bit more about the Texas side, I thought you were pretty clear, but it looked like that Woods well as you moved 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, I guess, I don't know, any -- were you a little surprised by that well, I guess is my question?

Right, and Ray, we were a little surprised too, pleasantly so.

Right.

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 Green 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 -- 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.

Got you. Great. And are you -- do you think that, I mean, the number of wells you're drilling is going up, but you're keeping that production guidance kind of in the same level. Is that due to transportation constraints or just conservatism, I guess?

Well, I think it -- 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.

We're trying not to disappoint people.

That's always a bad thing.

Yes.

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 -- the driver behind the forecast.

And I think most of -- 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.

Okay, that makes sense, so.

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

Gentlemen, good morning.

Hi, Dan.

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

Our normal approach to testing our wells and then subsequent to production is to incrementally and slowly increase the choke yo 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. And we don't want to put excessive pressure draw down across the Haynesville. We don't want to risk bringing proppant 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. 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, toward 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 upon the pipe they'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, there's 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. There's some variables there, hopefully that answers your question.

It does, thank you very much. What are you modeling for first year decline rate today and how has that changed over time?

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 breakovers and some of our wells to the turn hole decelerate is occurring more quickly. In other words, we're not seeing that significant of a decline, we're looking into that hard bend depending upon the particular area of the play. And so are our data trade partners.

Very good, very good. And lastly if I could, what would it take to drill the upper and lower Haynesville from a single well bore? Is it feasible?

The drilling side certainly is, not a problem. It's the completion side that presents all the headaches. The Haynesville is normally pressured, the frac pressures, the trading 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 configurations, 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. The short answer is, there's not a cost effective solution yet to do what you described, Dan. Although it's something that we would certainly like to pursue at a 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.

Very good. Very good, thank you again.

Yes, sir.

And our next question comes from the line of Ron Mills from Johnson Rice, Ron, you may proceed.

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

Ron, it's 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 EURs 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 add, 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, and 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.

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

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

The thing about that, Ron, is again, out of the 7 wells we just talked about, in the second quarter, four of them we own 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.

Okay, great. Thank you.

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

I'd like to close, I know we've been on for an hour 20 or so, but I'd like to keep everything really simple if you can, 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, marketing and accounting, all the different departments we have here, which is a management group including the Board, I think they function very well. And if you look at what's happened in '08, we monetized our position in Bois d'Arc, we sold another $138 million in noncore properties. We materially strengthened our balance sheet and we did that without the issuing stock. Today if you look at the Company, we've had the same name for about 20 years, we have $1.6 billion of assets, $1 billion of equity or so. We have got 15 Haynesville wells that we drilled completing connected to sales, so 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, we don't really have any debt maturity issues. I mean, we have a bond due in 2012 and that's it.

But I think the group has 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, I mean, we've reduced our drilling and completion time materially, 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 it 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, we've always told you if something really bad happens, you're going to hear about it the minute it happens, and if we have good results, like we've had, usually you hear about it at the quarterly conference call. So we're thankful to serve you, and work for you. And report to you. That's it many thank you.

Thank you for your participation in today's conference, this concludes the presentation. You may now disconnect, have a great day.