Comstock Resources Inc (CRK) 2009 Q1 法說會逐字稿

I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call Mr. Jay Allison, President and CEO, please proceed.

Thank you, nd good morning, everyone, and welcome to the Comstock Resources 2009 financial and operating results conference call. You can view a slide presentation during or after this cal by going to our website at www.comstockresources.com and clicking presentations. There you will find a presentation entitled first 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 first quarter financial and operating results as well as update the results of our 2009 drilling program. Our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements o be reasonable there can be no assurance that such expectations will prove to be correct. Please refer to page two of the presentation where we summarize the first quarter results. Low oil and gas prices in the first quarter caused a reversal from the record setting profits of last year. In the first quarter we reported revenues of $68 million and we generated EBITDAX and operating cash flow of $45 million or $0.99 per share. The low prices caused us to report a small loss of $6 million or $0.12- per share.

Our 2009 drilling program is off to an excellent start. We drill 14 successful wells including six horizontal Haynesville shale wells, three horizontal Cotton Valley wells, two vertical Cotton Valley wells and three high rate south Texas wells. Our last three Haynesville shale wells had initial production rates ranging from 12 million to 16 million cubic feet equivalent per day. A strong improvement from our first wells. We believe the improved results are in response to changes in our completion method. In addition to proving up our Haynesville shale acreage our other priority is maintaining a very strong balance sheet that will allow us to pursue our business plan this year without having to rely on the capital markets for any funding. I will turn it over to Roland Burns to review the financial results in more detail. Roland?

Thanks, Jay. On slide three we break out our average daily production in the first quarter by region. In the first quarter our production averaged 157 million cubic feet of natural gas equivalent per day. 4% higher than our pro forma production in the first quarter of 2008 of 151 million per day which excludes the 9 million we divested out last year. Production was down from our fourth quarter average rate of 164 million per day due to processing plant shut downs in east Texas and north Louisiana area during the quarter and in the early delays we experienced in drilling our Haynesville wells.

Our east Texas region averaged 84 million per day. South Texas averaged 58 million per day. And our other regions averaged 15 million per day. Despite the slow start, we still expect production in 2009 to increase to 62 to 67 bcfe or 7% to 5% higher than pro forma production in 2008. Production in the second quarter is expected to exceed 170 million per day. We recently entered into an arrangement to expand our take away capacity in Desoto parish Louisiana to handle these high rate Haynesville wells. Capacity approaching 100 million per day will be available to us by July. We plan to delay completions in our next batch of wells in DeSoto Parish by up to 45 days. Until the added capacity it is available to us.

The first quarter saw a rapid fall in oil prices which we cover on slide four. The average oil price decreased 57% in the first quarter of 2009 to $35.03 per barrel as compared to $81.49 per barrel in the first quarter of 2008. Our oil price in the first quarter averaged 81% of the average NYMEX WTI price in the quarter.

Slide five shows our gas price which also decreased significantly in the first quarter. Our average gas price decreased 48% in the first quarter to $4.29 per mcfe as compared to $8.24 in the first quarter of 2008. Our realized gas price was 88% of the average Henry Hub NYMEX price in the first quarter which continues to reflect the wider differentials we've been experiencing since the fourth quarter last year. We had 12% of our gas production hedged in the quarter which increased our realized gas price to $4.75 per MCF and the remainder of 2009 approximately 10% of our gas production is hedged at $8.20 per MCF.

On slide six we cover our oil and gas sales. The lower price has caused our sales from continuing operations to decrease 46% to $68 million in the first quarter. Our earnings before interest taxes, depreciation, amortization and exploration expenses and other noncash expenses or EBITDAX from our continuing on shore operations also decreased 56% to $45 million as shown on slide seven.

Slide eight covers our operating cash flow. Our operating cash flow for the quarter also came in at $45 million a 51% decrease as compared to cash flow of $92 million in 2008s first quarter. Operating cash flow in the first quarter was increased by current income tax benefit of $1.4 million.

On slide nine, we outline our earnings with the lower oil and gas prices, we reported a net loss of $6 million or $0.12 per share. Compared to the $29 million in net income or $0.64 per share in 2008's first quarter. There were no unusual items in the net loss for the quarter.

We outlined our cost structure for the quarter on slide 10. Our cash cost averaged $1.69 per mcfe produced in the first quarter reflecting a reduction of $0.82 per mcfe as compared to our cash cost in the first quarter of 2008. $0.35 of the savings comes from lower production taxes related to the lower oil and gas prices. Our production tax has averaged about $0.08 per mcfe in the quarter. Ad valorem taxes per mcfe produced increased from $0.09 to $0.15 in the quarter and these taxes are still based on the higher oil and gas prices driving property valuations in 2008. Our direct lifting cost per unit increased $0.03 to $0.97 per mcfe due to the lower production level we had in the quarter.

Our cash G&A averaged $0.44 per mcfe. Reflecting the increased staffing level of the Company. Cash benefits are a benefit for the quarter of $0.10 per mcfe with a tax loss expected for the year. Interest per mcfe decreased by $0.53 to only $0.15 per mcfe produced due to the lower debt level we now have. The decrease in the proved reserve base at the end of 2008 which was mainly related to the decline in oil and gas prices increased our DD&A rate in the quarter to $3.36 per mcfe. That's compared to $2.85 per mcfe in 2008's first quarter. This DD&A rate was comparable to our fourth quarter DD&A rate.

On slide 11, we outline our capital structure at the end of the first quarter.. We had $265 million in total debt at the end of the quarter. An increase of $55 million from year-end. We now have $90 million outstanding under our bank credit facility.

On May 1, our banks redetermined our borrowing base at $550 million. A small reduction from the prior $590 million borrowing ase. Reflecting the lower oil and gas prices used by the banks in their determination of borrowing bases. At the end of the quarter, we ended up with stock holder's equity at about $1 billion. So our percentage of debt to our total book capitalization was at 20% at the end of the quarter. We continue to have a very strong balance sheet with the substantial liquidity and we're very well positioned in this continuing tight credit environment.

On slide 12, we detail our drilling expenditures in the quarter. We spent $97 million in the first quarter for our drilling program as compared to the $62 million that we spent in 2008's first quarter. We spent $73 million in East Texas, North Louisiana region. And $24 million in South Texas. We funded these expenditures with operating cash flow of $45 million. And borrowings under the credit facility. This quarter probably will represent the most that we will spend in any quarter for capital expenditures as we are now primarily just working the five rigs that we have under contract for the Haynesville shale. And we don't anticipate a lot of activity in the other regions. I will turn it back to Jay.

Thanks, Roland. If you would turn to slide 13, we will focus on our East Texas/North Louisiana region. We drilled 11 wells, 9.2 net wells in this region in four different fields in the first quarter. All of these wells were successful. Nine of these wells were horizontal wells, we had tested these wells at a per well average rate of 7.3 million cubic feet equivalent per day. The horizontal wells averaged 5 million cubic feet equivalent per day and the vertical wells averaged 1.6 million per day.

On slide 14, we outlined our holdings in the emerging Haynesville shale play in North Louisiana and in East Texas. Our acreage is outlined in green. We currently have 86,032 gross acres and 70,504 net acres that we believe are prospective for Haynesville development. Given expected well pacing of 80 acres and expected well recovery of 5 bcfe per well our acreage could add 3.3 trillion cubic feet equivalent of reserve potential. We've completed eight successful horizontal Haynesville shale wells so far. And I will have Mack Good, our Chief Operating Officer go over the next several slides and go over the wells. Mack?

Thanks, Jay. Good morning, everyone. On slide 15 you'll see a diagram that will give you a general picture of how we are currently drilling and completing our horizontal Haynesville shale wells. This diagram shows that we anticipate completing a Haynesville lobe, varying thickness between 190 to 250 feet thick and we currently pump 10 fracture stimulation treatments across the typical wells planned 4,000-foot long horizontal lateral. The Haynesville horizontal completion requires numerous wire line service interventions after each fracture job and in order to set an isolated plug and another wireline intervention to perforate the next stage.

On slide 16, we show the number of days it has taken to drill the 12 Haynesville shale horizontal wells we have driven to date. The six wells displayed with the red bar in the graph show that we have taken between 37 to 61 days to drill the horizontal wells. These wells include a pilot hole that we drill to determine the exact position of the Haynesville shale to replace the lateral. The six blue bars represent represent wells where we didn't have to drill a pilot hole. Our drilling team has worked with a company called Pathfinder to reduce the drilling time for each of these wells. Our most recent well, the Caraway was drilled in 29 days which we believe is a record for the shortest time to drill a horizontal well in a Haynesville play to date.

On slide 17, we show the results of our first eight Haynesville shale horizontal wells. Since our last report, we have successfully completed another six horizontal wells in the Haynesville play. We drilled the Bogue 6 in the Waskom Field in Harrison County, Texas to a vertical depth of 10,858 feet with a 2600-foot horizontal lateral. The well was completed with seven frac stages and subsequently tested at an initial production rate of 7.4 million cubic feet per day and we have 100% working interest in this well. The Hart number 1 was drilled in the Logansport field in Desoto Parish, Louisiana to a vertical depth of 11,553 feet with a 3,770-foot horizontal lateral. The well is completed with 10 frac stages. And was tested at an initial production rate of 7.2 million cubic feet per day. And we have an 88% working interest in this well.

The Moneyham one in the Longwood Field in Cattle Parish Louisiana was drilled to a vertical depth of 10,572 feet with a 3,840-foot horizontal lateral. The Moneyham was completed with 10 frac stages, however during operations after the fracs coal tubing was lost in the well lateral. But the well's initial production rate was subsequently measured at 6.6 million cubic feet per day. Despite this problem. We have 100% working interest in this well. The Hendrick number 1 in the Logansport field was drilled to a vertical depth of 11,525 feet with a 4,060-foot lateral. The well was completed with 10 stages and was subsequently tested at an initial production rate of 15.1 million cubic feet per day and we have a 100% working interest in this well. The homes also in Logansport field was drilled to a vertical depth of 11,442 feet with a 4,010 foot horizontal lateral. The Holmes was completed, also, with 10 frac stages and was tested at an initial production rate of 16.2 million cubic feet per day. We have a 78% working interest in this particular well.

Our most recent Haynesville well is in our Toledo Bend North Field in Desoto Parish, Louisiana. The VSMC12 number one H was drilled to a vertical depth of 11,535 feet. With a 4,135 foot horizontal lateral. And the well was completed with 10 frac stages and tested at an initial production rate of 11.6 million cubic feet per day. We have an 88% working interest in this well.

We have scheduled the completion of four Haynesville horizontal wells, the Grain 13H in Harrison County, Texas and the Broome number 1H, Caraway number 3H and the Colvin-Craner 2H in Desoto Parish, Louisiana. We currently have five operated horizontal Haynesville wells drilling. And we are participating in four nonoperated horizontal Haynesville shale wells.

On slide 18, we compare the seven operated wells that we have drilled and put to sale so far. Our first three Haynesville shale horizontal wells utilized a formation stimulation process that utilized cross length heavier gel frac lifts and 20-40 ceramic province. As the slide reveals these wells had initial production rates that ranged from 7.2to 8.9 million cubic feet per day.

Based on results that other operators achieved and Comstock's own internal evaluations we decided to modify the formation stimulation process to primarily go with noncross length lighter frac fluids or slick water. And smaller 40/70 resin coated sand or ceramic province. Initial production results from wells using the new completion method were notable superior to wells using the old method. And support to wells using the old hod. The three wells using the new completion method have ranged from 11.6 to 16.2 million cubic feet per day. With IP. The Moneyham number 1H and along with Peeled and Cattle Parish, Louisiana used a cross hair heavier gel frac lifts, but did use the smaller 40/70 profit. You can see that in the graph with the transition design label. The well encountered several problems during completion and it had an initial rate of 6.6 million cubic feet per day. With that I will turn it back over to Jay.

Thanks, Mike. I know we've been marketing in the last two or three months, and everyone has been really interested in that part of the presentation. So, that's an excellent excellent job. If you will turn to slide 19, our South Texas region is displayed on slide 19, and our South Texas region we drilled 2.5 successful wells in the first quarter. These wells have been tested at a per well average rate of 8.5 million cubic feet equivalent per day. We drilled two successful wells in our Fandango field in Zapata County, Texas. And the other successful well was in a Ball ranch field in Kennedy County, Texas. The Santa Fe, Julian Pasture number 1 well was drilled to a total vertical depth of 13,388 feet. And completed with an initial production rate of 9.9 million cubic feet equivalent per day. We have a 45% working interest in this well.

On slide 20, we have a map of our Fandango field. In the first quarter we drilled Muzza number 13, to a 16,300 foot vertical depth. And completed this well with an initial production rate of 7.3 million cubic feet equivalent per day. We also drilled a Trevino number 3 in the first quarter. This well was drilled to a vertical depth of 14,720 feet and was successfully completed with an initial production rate of 8.4 million cubic feet equivalent per day. We have a 100% working interest in these wells.

If you turn to slide 21, we do expect to spend $360 million in 2009 for our drilling program as outlined on slide 21. Our budget has us drilling approximately 44 wells which is 34.8 net wells this year. The drilling program will continue to be focused on our high returned opportunities primarily our extensive acreage position in the Haynesville shale. The East Texas/North Louisiana operating region accounts for the largest portion of the 2009 budget with forecasted expenditures of $322 million. We now we plan to drill 39 wells or 31.4 net wells in this region, in 2009, which includes 33 Haynesville shale horizontal wells and three Cotton Valley horizontal wells. We expect to spend $38 million in our South Texas region to drill five wells in 2009.

On slide 22, we show the latest plan on where we plan to drill the 33 Haynesville shale wells. Six of these wells are planned for Texas and the Waskom, Barker, Anadarko fields. The remaining wells are in North Louisiana.

Then the 2009 outlook, slide 23. In looking ahead really to the rest of this year. We feel that we are very well positioned to continue to grow and add value on a per share basis for our stockholders. Even in this very challenging environment. The divestiture 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 in our onshore operations which is increasingly important given the tight credit environment that we are currently in.

Our 2009 drilling program, estimated to cost $360 million will focus on our highest return projects this year which primarily means the Haynesville shale projects. We are pleased with our last three Haynesville wells which demonstrate that we have moved up on the learning curve on how to complete the wells. We're now driving down the cost on the Haynesville wells from the 10 million to $14 million range that we spent on the the first wells to the current 8 million to $9 million range that we are in today. Our primary goals for this year are one, to prove up a portion of the 3.3 trillion cubic feet of reserve potential that our position in the emerging Haynesville shale exposes us to and two, to maintain our liquidity and strong balance sheet. We are well positioned for future growth when gas prices improve with our large inventory of drilling locations in the Cotton Valley and the Haynesville shale and East Texas and North Louisiana and in our Vicksburg and Wilcox trends in South Texas. And with that, we will open it up for the Q&A session, please.

(Operator Instructions) First question comes from the line of John Freeman.

Hi, John.

Hi. First question I had. You are clearly making big strides on the drilling days based on the Caraway well. The only one that stuck out is a little bit of an outlier is the Holmes which wound up being a decent bit higher than the Hedrick or the BSMC, which, from what I'm looking at looks like they were all similar depths, lateral links et cetera, just any sort of issues that happened on that well that would have made that one longer on the drilling days?

John, this is Mack. And we did have a problem building the curve on that well. And that, that's the primary reason why you see an elevated drill time on that.

Okay. Then if I exclude that one and just look at the BSMC and the Hedrick, what were roughly the completed well costs on those wells?

Completed well costs for the last six wells on the bar graph, would be between 8 to $9.5 million. And the costs are definitely trending downward, John. We are getting substantial reductions from the vendors. And of course, the drill time improvements certainly helps that cost.

Right. This may be difficult to judge just given the issues with the Moneyham well but -- since it was the only transition. But any thoughts you could venture on if -- what's driving the lion's share of the improvement in the Haynesville results and looking at slick water, at the change going to slick water versus a different size profit?

Sure. We think there is a number of factors a work here, the primary factor is the completion design improvement going with the lighter fluids going to slick water and of course the 40/70 province, but also part of the equation here is where the lateral is placed within the overall Haynesville thickness. And we are drilling them and locating them in a little bit of a different part of the Haynesville thickness than we did our original wells. We think that has substantial benefit. There is also some additional data that is being accumulated through data trading with our data trade partners. We're also participating in several studies, the core consortium that you may have read about. There's also a reservoir study that is ongoing that is giving us some information about the quality of the play and the different areas and that's allowing us to make decisions about where we place the lateral. So that's part of the answer, John.

As you are tweaking the different completion techniques, are there any plans to experiment with some longer laterals?

Yes, sir. We are going to do that in Louisiana where it lends itself to that kind of effort without great issue. The way to achieve that is start your surface location outside of the lease that you are going to extend the lateral into. And we hope to achieve some lateral links approaching the 4800-foot level.

Great. I will get back in the queue, thanks, guys.

Thank you, John.

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

Good morning. A couple of questions as you just went through your borrowing base determination and a lot of questions are starting to be asked about your fall for everybody. When you look at the well performance, especially with your new completion techniques and how do you look at the, especially with your goal of proving up a fair amount reserves, the timing of reserve bookings and how they play flow through in terms of leading to a more improved liquidity position in the fall?

Hey, Ron, this is Roland. The question on the Haynesville shale wells, if you look at the year-end reserves that we provided in connection with the redetermination of the borrowing base, there really was virtually no credit given to the Haynesville shale wells. The only one we have producing was really the one well at Toledo Bend north. We are hopeful there is a significant amount of value that will be available when we do our October redetermination. October, November time frame, with the wells that we have drilled, with the great performance of the wells and plus there will just be a lot of developed producing value which is what the banks really look at. So, we are hopeful that that supports a stronger borrowing base. We don't know what the bank's view of gas prices will be at that time. If it is weaker or stronger. But regardless, there will be more reserves to work with, fro the bank's viewpoint.

Can you just clarify in terms of the timing, of the pipeline expansions, and in particular, the Desoto Parish, or Toledo Bend north and Logansport sounds like you have a nother $100 million a day that should be available to you at some point during the third quarter and how the higher IP rates that you are achieving of late. How those work to at least off set the production impact from some completion delays. Is that the right way to look at your--?

This is Mack. We are expecting those pipe installs to occur and be available to us in July. And so, we are, as mentioned earlier in one of the exhibits, we're delaying some completions on three wells to accommodate that delay. Thee wells we are drilling should not be delayed at all and the information we have been given from the operators of those new pipes is that they are on schedule. We expect $100 million a day for them to be available within that same time period.

Okay. Then on the slide 17, where it shows your wells and where you are drilling and how drilled, you look to be starting to hop scotch quite a bit over some of your acreage. Can you explain or provide a little bit of color as to the timing of drilling the green well up in northern Harrison county where there have been -- some results have not necessarily been as good as the southern part of Harrison county and starting to drill in Desoto Parish and the home grow Caspiana area, just comment a little bit on the timing issue as you move across the different acreage blocks?

Sure. The five wells we are currently drilling, Ron, as you pointed out, the Green 13, we are completing that well right now. And certainly, very interesting test in an area that has not yielded excellent results thus far. Although we have, as I mentioned in an earlier response a little different approach in the drilling and completion process up there. And so we are very interested in the results that we will see. The timing as you mentioned moving from the, moving from that particular area. From the Green 13 and then into the Desoto area. We have drilled several wells in Louisiana already. With great IP results. And Logansport obviously being a more recent target. The Benson area or north Toledo Bend, our most recent well. The BMC12, also an excellent rate well, so we are tailoring our approach to the drilling program and the drilling program to be able to give us some results across the footprints that we have in the play.

One thing I would like to point out to the listeners is the significant size of the play and our different footprints in it. If you move from south to north starting from Toledo Bend south to Toledo Bend north, the distance between those two acreage blocks, that Comstock has 88% working interest in is about 15 miles. It is a significant area. If you continue to connect the dots, Ron, going to Toledo Bend north to Logansport from the center to the center of those acreage blocks, it is another 16 miles. So, just looking at the distance from Toledo Bend south to Logansport, that's a little over 30 miles of play area. Then we have a significant acreage position within. And further, if you extend from Logansport to Waskom area where we are testing, that is another 27 miles distance from Logansport to Waskom center to center. So overall, Comstock's footprint extends a distance approaching 60 miles from Toledo Bend south to Waskom. It's a significant position that we have in the play.

And just one other point. When talking about the distance, the distances from one field to another within the Haynesville play with regards to two well that is we reported on today, the BSMC12 to the Hendrick number 1, the BSMC12 and Toledo Bend north to the Hendrick number 1, that's a distance of 19 miles. So Comstock's position in this play is significant, we have various footprints to test. And that's what we are doing in accordance with the time lines that we are dealing with here.

Hey, Ron, if you will again, look at slide 17, we are going to get Mack to go over why we are drilling wells 14 and 15 particularly. There is some interest in those two areas. I am going to have him go over that.

Sure. The two wells that Jay mentioned, the BSMC 7, number 2 being one of them, is an upper Haynesville test that Comstock is drilling. And as some may recall, there has been a lot or some discussion at least about the division of the Haynesville between upper and lower. There is no doubt in some parts of our acreage that the upper Haynesville is -- demonstrates high quality on the open logs, gas shales are prevalent. And there has not been a test within the upper Haynesville in any of our immediate areas to date within the play that we know of. And we have a pretty accurate database. So, this is an extremely intriguing and interesting test driven by the reservoir data. And the Cox number 1. Another well, it's been targeted on the Texas side, it is an interesting well. That is in Darco, it will be the most western test in our acreage position so we are evaluating the edge of the play with that well.

Then, just with the Moneyham, it sounds like you had mechanical problem in terms of the coal tubing being lost yet despite those issues you still had one of the better production rates up in the Longwood area. Is there any way to do any kind of diagnostics to figure out anything about potential stages that didn't get completed? Or how that -- how much of that production was impacted by some of those mechanical issues.

Well, on that particular well, the Moneyham. That would be difficult to do because the coil tubing that is in the hole. Meaning to go in the hole with various measuring devices to get pressures and rights et cetera. We would have to contend with that. So, it is a disappointment from that respect on that particular well. Although, we are certainly pleased with the result despite the problems that we had. And keep in mind that the Moneyham got a lot heavier fluids. Frac fluids, even though we used the smaller profits, so that is why we call it a transition completion design.

One well that I left out earlier, is the RLS number 1. It is 15, item 15 on slide 17. That particular well is in an area near Mansfield and surrounded by significant high rate wells and we are extremely interested in that result. We are drilling that well right now. We have a couple of sections of acreage in that environment. So that's -- that will be our easternmost test in a play to date and I mentioned, the reason I plucked that out, I mentioned that Cox is our most westernmost test.

Remember, Ron, our goal at the beginning the year was to take the four corners of our acreage which is in the green on slide 17 and test up the four corners and then the center of our acreage position. Because what our goal is is once we are comfortable as a technical group. We can drill and complete and produce these wells, particularly on the completion side. At a maximum event. Then when we get comfortable with that. And we get comfortable what the EURs are per well. Then if the area is held by production if you go into 2010 and you still have a low gas price environment then our goal is not to drill on that acreage that's helped our production. And we would get in there within our free cash flow in 2010 in the Haynesville area and we continue to keep our strong balance sheet and hopefully, like number 7 well, which is the only well we connected to sales at year-end.

We booked 11 BCFE or so of reserves in that one well and two offsets if we can drill 33 wells, which is about 28 net Haynesville wells in 2009 we should be able to book a bunch of reserves if they are there. And so far we are pleased with the outcome. And again I thank Mack and his group, they created the well in South Texas with the Vicksburg and the Wilcox plays. They created wells in double A they created wells on the vertical wells last year in Cotton Valley we drilled 114 of those. This year we said we are transitioning over with our engineering group and geological group we are transitioning over. So that we can be comfortable within the four walls on the Haynesville play. And we have been able to do that without issuing stock and not incurring any junk bonds or high yield we've been able to do it within our balance sheet. And hopefully like Roland said in October we have added some meaningful reserves. We've lowered our DD&A and replenished any dollars we borrowed under our bank credit facility. And it is still a very viable program. And if it changes, we would announce that.

Okay. Great. Thank you, guys.

Thanks, Ron.

The next call comes from Noel Parks with Ladenburg Thalmann.

One quick housekeeping item. Roland, on the interest for the quarter, was capitalized interest amount a little lower than I guess about the $1.7 million that I was looking for?

Yes. It was slightly lower. It was $1.6 million in the first quarter. Capitalized interest.

Okay.

That number, that will slowly decline as the year progresses each quarter. Two reasons, our average interest rate will decline a little bit. Because as we borrow under the bank credit facility it's a substantially lower rate than the bonds. So the rate will decrease a little bit. And also as we prove up the acreage with our Haynesville drilling program. We will be transferring cost from unevaluated into evaluated properties and no longer capitalized interest on them. That number slowly decline during the year:

Okay. Great. And sorry if I missed this. But, the sequential decline in the Haynesville, well, east Texas and north Louisiana region for the quarter. Was the completion delays that were mentioned in the press release was the main reason for that. Because I guess it was a little bit more of a decline than I would have expected even just if it was base decline for one quarter.

No, there were two reasons. One was just some plant shut downs that we had during the quarter. In that region. The Carthage plant with the damage they had to the pipelines, the Telagada plant caught on fire. It was down close to three weeks. And we move a lot of production through the plant for processing. All we had to shut down a fair amount of production for that period of time. We also had some plant problems which caused our Toledo Bend north area not to be on production for some of the quarter. I think that was approximately 4 million a day. At least the average over the quarter impact.

And then, the remaining decrease from the fourth quarter production rate. We really had the decline in the Cotton Valley wells and really did not get some of the Haynesville wells on production until much later in the quarter than we had anticipated. We hoped to see the production stay pretty flat in the first quarter to the fourth quarter. But because of those reasons it was down a little bit in that region. We did see that. We wrap up track starting in March and going into April and to the second quarter. And really back on track to our original production forecast. And we'll be able to make up the small shortfall from the first quarter. To the extend that transportation is available in the Desoto Parish area we can actually get way ahead of our forecast. But we're still not promising that yet until that pipeline is in.

Great. As far as the completion delays in the Haynesville, I was just curious. Was it more just the vendors were slow. Or just their, were not getting on site at the times they originally promised. Or were there issues of weather or anything else that slowed down the completions there?

We had a couple of wells that were delayed because of some internal assessments we were making on the completion designs and making the choices that we mentioned earlier. We also extended the lateral on a well. And that of course increased the drill time. Which would, of course delay the completion. The vendors are available. We have not seen any issue at all of being able to get service in this environment. So, just in general, the answer to your question is it was primarily due to a combination of factors. Not vendor related.

Again, my apologies if this has come up already. I recall the Green well, that's where you were doing the dual laterals and one in the Cotton Valley as well as Haynesville. Is that right?

Yes, sir. We drilled a horizontal Cotton Valley well in that area. And in a separate well, the Green 13. We drilled a Haynesville horizontal, the Green 11 was our Cotton Valley horizontal.

Okay. Great. I just wondered, I know it is still early and the industry is just gradually spreading out across the play. Just wondered if anyone else's work on tighter spacing was anywhere close to where you are, if it gave you any information about how that might look?

Well, the spacing question is definitely unanswered. The primary reason of course is that most operators are drilling their new leases. And in order to hold those leases, they are drilling one well per section. Or for drilling in it. They are not interested at this time in developing a denser type of drilling pattern. So, they are drilling one well per section. So that leaves obviously the space in question open. And then a further interesting element to that overall space in question is the potential impact of the upper Haynesville in certain parts of the play. So you can use your imagination. And come up with some very interesting spacing requirements for those two reservoirs.

Okay. Great. My last couple of questions were about the south Texas. The Landecker well, what is the current production rate on that now?

The Landecker 10 is currently producing about a million a day from an upper T-6 Wilcox sand. And we are evaluating that upper T-6 sand for future efforts in the field.

Okay.

It is major, the most of its reserves are in a zone above that.

We have two behind pipe zones up the hole.

Okay. I know you booked the 13 (inaudible) at your end. Okay. And what were the well costs like on the couple of new Fandango wells you had this quarter, the Muzza and the Trevino?

Those are $both $10 million wells in that ballpark.

So finding cost looks like it might come out and in the low $1 to $1.50 range for those?

Boy, I hate to give you a number at this point. We are still evaluating the reserves. Until we get enough data, I would hate to get out there on the land with the finding and development cost but I certainly expect it to be low.

These would represent some of the wells that, even at really low gas prices, you still would be able to get good economics for it. Safe to say?

Yes. You bet.

That's great.

Thanks.

That's all I have.

Thank you.

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

Kind of sticking with south Texas. Curious as to when the Muzza and the Trevino wells started producing?

They've been on about three to four weeks.

Primarily in the second quarter.

How have they held up on the production side since coming online?

Flat. We are very pleased. No decline.

Were you folks also going to drill some offsets to that Landecker well at one point?

We have a couple of plans on the drawing board. But given our emphasis on the Haynesville we have deferred those projects.

The main reason it's helped our production, we do own 100% of it and we want to keep our balance sheet strong.

Okay. You guys spoke about Haynesville taking away capacity and said you are going to get access to 100 million a day from capacity in roughly in July here. Can you talk about what your infrastructure needs are maybe for the rest the year in the Haynesville play. And in 2010, obviously you have had some pretty high rate wells and are planning on drilling a fair number of wells this year. It seems as though the 100 million a day could potentially get used up pretty quickly.

Sure. We are negotiating with other opportunity providers on take away capacity. And when we get finished with those negotiations, we will certainly make that information available. In terms of infrastructure that we would be responsible for, we are looking at a couple of short pipeline lay projects in order to connect to sales but nothing beyond 3 miles or so, 4 miles. And that's pretty much our game plan. The 100 million a day is going to be in our lap. We will have that. We will have the other opportunities that I can't get specific on. Hopefully under wraps here in the next two to three months.

Okay. Based on your success. And your latest crop of wells here. Are you looking for firm capacity on some of these main lines at this point or are you still trying to be flexible?

I think we have said this before. We are looking at everything. Our VP of marketing is leaving nothing off the table. For discussion. Certainly we are interested in firm for obvious reasons and that's our priority. We are interested in getting our gas to sales, so whatever opportunity avails itself. We want to take advantage of it.

Next question comes from the line of [Michael Godino] of SMH Capital.

Just a couple of follow-ups. One on Leo's question. Relative to the infrastructure project on in July. Any sense of the timing of ramp up and your net volumes there of how you accommodate the $100 million a day of capacity?

Well, currently, our gross production is around 48 million a day. We have about 30 million a day net. That has not hit any of the firm capacity we are talking about. So we are moving that Haynesville volume across the sales meter as we speak. The ramp up certainly would start in the late June/July time period with regard to those three delayed wells that I mentioned. And certainly we certainly expect to fill up the pipe with those completions and the other opportunities that I mentioned that our VP of Marketing is negotiating will be the increased capacity that I think you are talking about that would provide the pressure release on our added volumes past that point. Now, keep in mind these Haynesville wells, all of them in the play have a, no matter what their IP rates are they have significant declines over the first few months of production. And then the kicker is is when does that production profile flatten out. And at what rate does it flatten out. And we are seeing some very interesting, and it is preliminary, some very interesting results on the flattening part of that production profile. So that all goes to answering your question on timing. It's a matter of when is the pipe available but it's also a matter of the decline rates on these wells.

Any sense of, based on what you are seeing in terms of decline? How many rigs you would have -- let's say you had 100 million into that pipe, how many rigs you would have to run to keep the level flat?

We like the five rig program for a lot of reasons. One, it keeps us within our declared budget. And our focus on keeping that clean balance sheet, as Jay mentioned is one of our primary goals. And of course, if you go back to I believe it is the slide 21, it shows the allocation of our effort in the Haynesville and you'll see at Logansport with 17 wells. 15 of those being Haynesville, it is going to get a large allocation of our effort. And that's where we have had the highest IP rates and we have got those wells in Logansport timed appropriately, we think to take advantage of the firm capacity as it is available.

Michael, we do have four nonoff wells we're participating in right now. Three are Chesapeake, one is Petrohub.

Relative to the capacity right now, I assume that most of the production is going through Logansport The wells that are delayed right now, those are more of that southwestern, Desoto Parish; is that correct.

We have got two in Logansport. That are delayed. I think it is mentioned in the earlier slide here. The Colvin-Craner, the Broome, and the Caraway are the three delayed wells, they are scheduled for start up on completions later in May and early June. And those are at the Logansport gate.

Okay. If you will indulge me just a couple more questions. More big picture. From a -- trying to track all these wells in the Haynesville certainly moving from Elm Grove towards the Southwest toward Shelby county. There seems to be as we move from some wells that are mid-20s into the 20s into the high and mid teens. It seems like that trend -- like Simmons and Southwest across have been some of the more prolific wells. Is that a function of depth and pressure? Is that a quality of rock? What are you all seeing and how do you think about your northern Haynesville acreage on a relative rate of return basis?

Well, a lot of unanswered questions at this point about Haynesville shale rock quality. And the attributes that go into determining performance in part. You got to have the rock. And where is the best rock. Or shale. And so your question is currently unanswered. in terms of specific rock or core I guess. Now, we're a member of the core consortium. We have access to all of the analysis that has been provided thus far. There is no question that around the Elm Grove area you got IPs ranging anywhere from 15 million to $28 million a day.

We've got a database that currently includes 84 producing horizontal Haynesville wells and we've done probability distributions on IPs and of course, you get into the question of how different operators report IP rates and there's really no advantage to launching into a discussion on that. But just using the numbers that have been made publicly available the average, currently the median IP rate across the play is about 9 million a day using those number of wells. So if you look at the wells specifically in Elm Grove area we think fracturing is part of the deal. Natural fracturing, I mean, but we just have very skimpy data to support that theory. As you move into our Logansport area we have a 16 million a day well and we did not pull it that hard to get that 16. It came right up to the 16 million a day. We didn't have to open it up on a 48 choke to achieve that. Hopefully some of the listeners will know what I'm talking about.

We kept it on a very moderate choke to get that right. So we know that the Logansport area is in the higher quality area as well. Our Toledo Bend north with an IP approaching 12 million a day is also high quality. So getting more specific than that about pressures we think pressures are about the same across the play. We think the depth of the Haynesville obviously varies as you go south, it thins toward the north. How far up north can you go and still make an economic well at a $5 gas price is the unanswered question at this point. So the bottom line here, Michael, is that there's a lot of unanswered questions with regard to reservoir quality despite the fact that we've got about in the mid 80s number of horizontal wells flowing to sales just because of the size of the play that I referred to earlier. There's -- it's such an expansive play that there's not a whole lot of data in any one part of it.

I think a lot of it goes back to your 80 acre space hanger. Whatever your spacing might be. Maybe the higher IP wells recovers a greater number of reserves versus the Moneyham maybe. So we, again, I think that's part of our business plan in 2009 is to get answers to those good questions. I think we'll have a handle on that by the end of the year.

One last question and I'll get back in queue if the other ones don't get answered, but relative to the upper Haynesville test, I know you've taken log and you've gone through an exhaustive log analysis. Is there any core data that would suggest different gas in place volumes for the Haynesville or anything that can give us any clue on what has made you so excited about testing this concept?

We have not seen any significant volume of data on the upper Haynesville from the coring that has been done. There has been very little Haynesville cored and not in -- the couple that I have seen it has been in a different area than we're drilling. We're drilling the upper Haynesville based on gas shales and log analysis, petrophysical analysis.

The next question comes from the line of [Mark Rhett] with Sidoti and Company.

Do these recent completions with the new frac design increase your confidence to raise your AUR assumptions in the play?

Yes. Short answer, but yes. Certainly going to the newer design and getting in crude performance we have had some adjustments on our -- and they're initial adjustments. As you may or may not know, Comstock has been very careful and very conservative in the past in launching tight curve AURs for the Haynesville because one number does not fit all. Different areas, different characteristics. I think we talked a little bit about that earlier. So we're very careful about -- before we have confirmation which means we have to get a little production history to confirm a tight curve adjustment. We don't -- we're not going up on our tight curve at this point but we feel very comfortable and confident that there is going to be an adjustment in a couple of areas just because of these performances that we're seeing. Then extremely pleasing to see that the change in the frac load and the profit size and where we're placing the lateral and how we're perforating each stage with the number of purse and the number of clusters per stage that has really allowed the performance to improve.

I was just curious, is there anything going on in Texas regulatorywise or other that's going to allow you to permit longer laterals a bit easier? Just noticed that Bogue well has a pretty short lateral.

Yes. We're working on a couple of things. And this State of Texas things move, not as fast as we would like at the Regulatory Commission but certainly that is an issue. When you have acreage and you're confined, just the geometry of the drilling unit limits you to the length of lateral that you can drill that's certainly a disadvantage. That's one reason why we're allocating most of our efforts into the Louisiana area. Now, in order to get a longer length lateral currently in Texas, you have to start your drilling the surface hole, the vertical section off lease. So when you build the curve you're building it pretty much off lease and by the time you go to the lateral section, the horizontal section you're on lease and that way you don't use up your usable real estate within a drilling unit by drilling the surface hole within a lease. Do you follow me on that?

I do.

Okay. And so we're doing -- we're looking at some of that. We got to make the arrangements to do that kind of work and we're certainly looking at doing that. But it's much easier in Louisiana, I assure you, to drill those 4500 foot lateral lengths that -- and we're looking at going longer than that if -- in a couple of places. We have offsite, or off lease surface locations to start the hole.

Got you. Thanks a lot.

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

Mack, I was wondering, does that 29 day -- were you able to drill that for less than $8 million?

The drill and complete costs were approached about the $8 million mark.

And I was just wondering, what do you consider, I mean, that 7 million, 8 million a day IP rate in Texas looks like one of the better ones out there. Where, with the new completion techniques on this Green well would you be happy or can you talk about what you might be targeting on the Texas side?

Yes. With Texas you start with the lateral length and we want to make sure that we can get a plus 3500 foot lateral length on our Texas side efforts and that's the goal. So that's number one. Number two, is we certainly want to make sure that we get at least 10 stages and that -- and we're looking at different perforating schemes. The reason why that's obviously important is getting the frac initiated and making sure that we expose the reservoir through the fracturing -- the subsequent fracturing, hydraulic fracturing. And then the third element, is, of course, the completion design. And in order to initiate on the Texas side so far we've had to use some heavier gels to get that initiated. So there's a little bit of a difference between Texas and Louisiana on the operational side and getting these fractures started. But we -- our goal is to use the lighter frac fluids as much as possible along with the 40/70 smaller provin. And we think that will be a significant contributor to improving performance on not -- well, on both sides. On both states, Texas and Louisiana.

Got it. And I guess, you don't have any plans to drill the Shelby acreage this year and it will quick give a fairly big chunk of acreage there. Is that something you plan for early 2010 or--?

Yes. Currently it's on the 2010 schedule. Right. We're looking at it. It's a -- the one thing that Comstock has going for it is that a large part of our acreage is HBP so we're not forced to drill to -- on a clock on a lot of our acreage. So we have the flexibility to move those rigs around more so than we would otherwise. So Shelby we're looking at what can we do to put drilling units together that make sense down there and if so which drilling units would be highlighted and when. But right now, you're right, 2010 looks like the time frame for doing anything in Shelby.

Thanks very much.

You bet.

Ladies and gentlemen you are out of time for questions. You may call the Company with additional questions. I would now like to turn the call back over to Mr. Jay Allison.

Thanks again. Remember, our goal this year, I mean, it is to prove up a portion of that 3.3 trillion cubic feet of potential reserves in the Haynesville. I think we've taken really good strides toward doing that and we've reduced cost and as Mack mentioned we did go from last year at about 4 bcfe's in AUR and we started out in January at 5 bcfe's in AUR and maybe we can go up from there but we'll do it when we're comfortable increasing that number.

And then the second thing is we've kind of put a stake in the ground and we said we want to maintain our liquidity and strong balance sheet. Last year when we divested ourselves of our stake in Bois d'Arc and the noncore properties that allowed us to have an extremely strong balance sheet in the environment that we're in and we want to keep it that way. So our goal is to add a lot of reserves by year end. Secure the bank facility again and continue to develop the Haynesville and not have to access the capital markets to do it. So we thank you for your patience and in another 90 days we'll report on the Haynesville again. Thank you.

You're welcome, sir. Ladies and gentlemen that concludes the presentation. Thank you for your participation. You may now disconnect. Have an excellent day.