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Comstock Resources Inc. (NYSE:CRK)

Q1 2009 Earnings Call

May 5, 2009 10:30 am ET

Executives

Jay Allison - Chairman, President and CEO

Roland Burns - SVP and CFO

Mack Good - VP of Operations

Analysts

John Freeman - Raymond James

Ron Mills - Johnson Rice

Noel Parks - Ladenburg Thalmann

Leo Mariani - RBC

Michael Bodino - SMH Capital

Mark Lear - Sidoti & Company

Ray Deacon - Pritchard Capital

Operator

Good day ladies and gentlemen and welcome to the first quarter 2009 Comstock Resources earnings conference call. My name is Channel and I'll 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)

I would like to turn the presentation over to your host for today's call, Mr. Jay Allison, President and CEO. Please proceed.

Jay Allison

Thank you Channel and good morning, everyone. And welcome to the Comstock Resources first quarter 2009 financial and operating results conference call. You can get a slide presentation during you enter this call 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 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 security laws and we believe the expectations in such statements 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 calls for 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 drilled 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 an 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 improving 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 details. Roland?

Roland Burns

Thanks, Jay. In slide three, we break out our averaged daily production in the first quarter by region. In the first quarter our production averaged to 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 the East Texas and North Louisiana area during the quarter and due to early delays we experienced in drilling our Haynesville wells.

Our East Texas region averaged 48 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 Bcf 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 the takeaway capacity in to DeSoto Parish, Louisiana, to handle these high rates 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 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. 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 Mcf as compared to $8.24 in the first quarter of 2008. Our realized gas price was 885 of the average Henry Hub NYMEX price in the first quarter continues to reflect the wider differentials we've experiencing since the fourth quarter of last year. We had 12% of our gas production hedged in the quarter which increased our realized gas price to $4.75 Mcf.

In the remainder of 2009, approximately 10% of our gas production is hedged at $8.20 per Mcf.

On slide 6, 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 other expenses and other non-cash expenses or EBITDAX from our continuing onshore operations also decreased 56% to $45 million as shown on slide seven.

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

On slide nine, we out line 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 is averaged about $0.08 per Mcfe in the quarter.

Ad Valorem taxes per Mcfe produced taxes increased from $0.09 to $0.15 in the quarter, as 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 $0.097 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 taxes are benefits for the quarter of $0.10 per Mcfe with a tax loss expected for the year. Interest per Mcfe decreased by $0.53 to $0.15 per Mcfe produced due to the lower debt level that we now have.

The decrease in the proved reserve base at 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 as 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 ends the quarter, an increase of $55 million from year-end. We now have $90 million outstanding into our bank credit facility.

On May 1st, or banks re-determined our borrowing base at $550 million, a small reduction from the prior $590 million borrowing base, reflecting the lower oil and gas prices used by the banks in their determination of borrowing basis.

At the ends the quarter, we ended up with stock holder's equity at about $1 million, so our percentage of debt to out total book capitalization was at 20% at the ends of the quarter. We continue to have a very strong balance sheet with the substantial liquidity and we are very well positioned in the continuing tight credit environment.

On slide 12, we detail our drilling expenditures in the quarter. We spent $97 million in the first quarter on our drilling program, as compared to the $62 million that we spent in 2008's first quarter. We spent $73 million in our 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 were spended in any quarter for capital expenditures, as we are now primarily just working the five drilling that we have under contract for the Haynesville Shale, and we don't anticipate a lot of activity in other regions.

I'll now turn it back over to Jay.

Jay Allison

Thanks Roland if you return to slide 13 we’ll focus on our East Texas, North Louisiana region. We drilled 11 wells 9.2 net wells in this region and 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 equivalent per day. The horizontal wells average 8.5 cubic equivalent per day and the vertical wells average 1.6 million per day.

On slide 14, we outline 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 Spacing of 80 Acres and expected Well Recovery of five Bcfe per well our acreage could add 3.3 trillion cubic feet equivalent of reserve potential. With completed eight successful horizontal Haynesville Shale wells so far. And I’ll have Mack Good our Chief Operating Officer goes to next several slides and go over the wells. Mack.

Mack Good

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 our Haynesville lob varying in thickness between a 190 to 250 feet thick, and we currently pump ten fracture stimulation treatments across the typical wells plant 4,000 foot long horizontal lateral. The Haynesville horizontal completion requires numerous wire line service interventions after each fracture jaw and in order to set an isolating plug in another wire line intervention persiflage the next stage.

On slide 16, we show the number of days it has taken to drill the 12 Haynesville Shale horizontal wells that we drilled till 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 drilled to determine the exact position of the Haynesville Shale to replace the lateral.

The six blue bars represent wells where we did not 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 horizontal well in the Haynesville play to date.

On slide 17, we show the results of the 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 A #6H 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 a 100% working interest in this well.

The Hart #1H was drilled in Logansport field in DeSoto Parish, Louisiana to a vertical depth of 11,553 feet with a 3,770 foot horizontal lateral. The well was completed with ten 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 #1H in the Longwood field in Caddo Parish, Louisiana was drilled to a vertical depth of 10,572 feet with a 3,840 foot horizontal lateral.

The Moneyham was completed with ten frac stages during plain out operations after the fracs, coiled 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 a 100% working interest in the well. The Headrick #1H in the Logansport field was drilled to vertical depth of 11,525 feet with a 4,060 foot lateral. The well was completed with ten stages and was subsequently tested at initial production rate of 15.1 million cubic feet per day and we have a 100% working interest in this well.

Holmes A #1H also in Logansport field was drilled to a vertical depth of 11,442 feet with a 4010 foot horizontal lateral. The Holmes was completed also with ten 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 our Toledo Bend North field in DeSoto Parish, Louisiana. The BSMC 12 #1H was drilled to a vertical depth of 11,535 feet with a 4,135 foot horizontal lateral. And the well was completed with ten 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 scheduled the completion of four Haynesville horizontal wells, the Green #13H in Harrison County, Texas and the Broome #1H, Caraway #3H and the Colvin-Craner #2H in DeSoto Parish, Louisiana. We currently has five operated horizontal Haynesville wells drilling and we are participating in four non-operated 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-linked heavier gel frac fluids and 20/40 ceramic proppants. And as the slide reveals these wells had initial production rates that range from 7.2 to 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 non-cross linked lighter frac fluids or slick water and smaller 40/70 resin coated sand or ceramic proppants. Initial production results from wells using the new completion method were notably superior to wells using the old method.

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 #1H in the Longwood field in Caddo Parish, Louisiana cross-linked heavier gel frac fluids but did use the smaller 40/70 proppant. You can see that in the graph with the transition design label. The well encountered several problems during completion and had an initial rate 6.6 million cubic feet per day.

With that I’ll turn it back over to Jay.

Jay Allison

Thanks, Mack. I know we have been marketing the last two, three months and everyone has been really interested in that part of the presentation. So, that's an excellent job. If you return to slide 19 our South Texas region displayed on slide 19, in our South Texas region we drilled 3 or 2.5 net successful wells in the first quarter. These well are being tested at a per well average rate of 8.5 million cubic feet equivalent per day.

We drilled too successful wells in our Fandango field and Zapata County, Texas. The other successful well was in the Ball Ranch filed in Kenedy County, Texas. The Santa Fe Julian Pasture #1 well was drilled to a total vertical of 13,388 feet and completed with an initial production rate of 9.9 million cubic equivalent per day we has 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 #13, to a 16,300 foot vertical depth and completed this well with an initial production rate of 7.3 million feet cubic feet equivalent per day. We also drilled the Trevino #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 did expect to spend $360 million in 2009 for our drilling program as outlined on slide 21. Our budget as is drilling approximately 44 wells which is 34.8 net wells this year. The drilling program will continue to be purchased on our higher 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 are now planning to drill 39 wells or 31.4 net wells in this region and 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 showed the latest plan on where we plan to drill the 33 Haynesville Shale wells. Six of these wells were planned for Texas. In the Waskom, Blocker and Darco fields the remaining wells are in North Louisiana,

And then the 2009 outlook slide 23, and 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 stock holders even in this very challenging environment. The divestiture of our stake in Bois d’Arc Energy and a non-core properties that we completed in 2008 provided and extremely strong balance sheet that will allow us to aggressively support the continued growth in our on-shore operations which is increasingly important given the tight credit environment that we are currently in.

Our 2009 drilling program estimated to cost $360 million while focused on our highest return projects this year which primarily means the Haynesville Shale projects we are very pleased with our last three Haynesville wells which demonstrate that we have moved up on a learning curve on how to complete the wells. We are now driving down the cost on the Haynesville wells from the $10 million to $14 million range that we spend on the first wells to the current $8 million to $9 million range that we are in today.

Our primary goals for this year or want to prove our proportion of the 3.3 trillion cubic feet of reserve potential that are positioned in the emerging Haynesville Shale exposes us to and to, to maintain our liquidity and strong balance sheet.

We are well positioned for future growth when gas process improve with our large inventory of drilling location in the Cotton Valley and a Haynesville Shale in East Texas and North Louisiana and in our Vicksburg and Wilcox trends in South Texas and with that Channel we’ll open it up for the Q&A session please.

Question-and-Answer Session

Operator

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

John Freeman - Raymond James

First question I had you are clearly making big strides on the drilling days based on the well. The only one that kind of stuck up is little bit of an outlier was the Holmes well which you are not being decent bit higher than the Headrick or the BSMC which when I am looking at looks like they are all similar depths lateral links etcetera, just any sort of issues that happened on that well that would have made that one long on the drilling days?

Mack Good

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

John Freeman - Raymond James

Okay. And 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?

Mack Good

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're getting substantial reductions from the vendors and of course, the drill time improvements, certainly helps that cause.

John Freeman - Raymond James

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

Jay Allison

Sure. We think there was a number of factors to work here, the primary factor of course, is the completion design improvement going with the lighter fluids, go into slick water and of course the 40/70 proppants. But also part of the equation here is where the lateral is placed within the overall Haynesville thickness. We are drilling them and locating them in a little different part of the Haynesville thickness than we did on our original wells. We think that adds some substantial benefit.

There is also some additional data that's 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 is also a reservoir study that's ongoing that is giving us some information about the quality of the play in the different areas and that's allowing us to make some decisions about where we place that lateral. So, that's part of the answer, John.

John Freeman - Raymond James

Okay. And just as you kind of tweak in the different completion techniques. Are there any plans to experiment with some longer laterals?

Jay Allison

Yes, sir. We are going to do that in Louisiana where it lends itself to that kind of effort without a great issue. The way to achieve that is to 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 4,800 foot level.

Operator

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

Ron Mills - Johnson Rice

Couple of questions, just as you just went through your borrowing base re-determination and a lot of questions are starting, already 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 improving up a fair amount of reserves, the timing of reserve bookings and how those may flow through in terms of even leading to a more improved liquidity position in the fall?

Roland Burns

Hey, Ron, this is Roland. Yeah, the question on the Haynesville Shale wells, if you look at your year-end reserves that we provided at the bank group in connection the re-determination of the borrowing base, there really was virtually no credit given to the Haynesville Shale wells. Only one we had producing was really the one well at Toledo Bend North.

So, we're hoping that there is a significant amount of value that will be available when we do our October re-determination, October, November timeframe with the wells that we've drilled with the great performance of the wells and plus there just be a lot of developed producing value which is what the banks probably 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's weaker or stronger. But regardless, there will be more reserves we think to work with, from the bank's viewpoint so.

Ron Mills - Johnson Rice

Can you just clarify just in terms of the timing of the pipeline expansions, in particularly DeSoto Parish were in Toledo Bend North and Logansport, it sounds like you have another 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're achieving of late, how those work to, it looks to at least offset the production impact from some completion delays, is that the right way to look at your?

Mack Good

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

Ron Mills - Johnson Rice

Okay. And then on the slide 17, really shows your wells and where you are drilling and how drilled. You look to be starting this hopscotch 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 of not necessarily been as good as the Southern part of Harrison County and just now starting to drill in DeSoto Parish approaching kind of the on (grow) gas beyond the area, just comment a little bit on the timing as you move across your different acreage blocks.

Mack Good

Sure, the five wells that we're currently drilling. Ron and as you pointed out, one, the Green #13, we were 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're very interested in the results that we'll see. The timing as you mentioned moving from that particular area from the Green #13 and then into the DeSoto area.

We've drilled several wells in Louisiana already with great IP results. Logansport obviously being the more recent target. The (inaudible) area or North Toledo Bend are most recent well. The BSMC 12, also an excellent rate well. So, we're 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'd like to point out to the listeners is the significant size of the play and our different footprints within 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's a significant area.

If you continue to connect the dots Ron, going from Toledo Bend North to Logansport from the center to the center of those acreage blocks. It's 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's 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 distance is from one field to another within Haynesville play, with regard to two wells that we reported on today, the BSMC 12, to the Headrick #1H, the BSMC 12 and Toledo Bend North to the Headrick #1H. That's a distance of 19 miles.

So, Comstock's position and its play is significant, we have various footprints to test and that's what we are doing in accordance with the timelines that we are dealing with.

Jay Allison

Hey Ron, if you again look at slide 17, try and 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 there.

Mack Good

Sure the two wells that Jay mentioned the BSMC 12 #2 being one of them is another Haynesville test that Comstock is drilling and as some may recall there has been a lot of, some discussion at least about the division of Haynesville between upper and lower. There is no doubt and in some parts of our acreage that the upper Haynesville is demonstrates high quality on the open whole logs (gas shale) 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.

The cogs number another well has been targeted on the Texas side it’s an interesting well that is in Darco it’ll be the most western test in our acreage position so we are evaluating the edge of the play with that well.

Ron Mills - Johnson Rice

Okay and then just with the Moneyham it sounds like you had something kind of coupons in terms of the coiled tubing being lost yet despite those issued you still had, still one of the better initial production rates up in the Longwood area. Is there anyway to do any kind of diagnostics to figure out, anything about potential stages that didn't get completed or how much that production was impacted by some of those mechanical issues?

Roland Burns

Ron, that particular well at the Moneyham that would be somewhat difficult to do, because of the coiled tubing, that is in the hole, meaning to go in the hole with various measuring devices to get pressures and rates etcetera, we would have to contend with that.

So, it's a disappointment from that respect on that particular well, although we're certainly pleased with the results, despite the problems that we had. And keep in mind that the Moneyham got a lot of heavier fluids, frac fluids, even though the usually the smaller proppant. So that's why we call it a transition completion design.

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

Jay Allison

And the reason Ron, remember our goal at the beginning of the year was to take kind of the four corners of our acreage which is in the green on slide 17 and test up at 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, then we can drill and complete and produce these wells, particularly on the completion side kind of at a maximum event.

Then, when we get comfortable with that and we get comfortable with what the AURs are per well, than if the area is held by production, if you go into 2010 and you still have a low gas price environment. Our goal is not to drill really on that acreage that's held by production.

And we would then live within our free cash flow in 2010 in Haynesville area and would continue to keep our strong balance sheet and hopefully, like Roland has said Black Stone Mineral number 7 well, which is the only well that we had connected to sales at year-end. We booked about 11 Bcf peers of reserves for 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. So far we are pleased with the outcome and again, I think Mack and his group they've created the wells in South Texas, with the Vicksburg and the Wilcox plays. They've created wells in double A, they have created well field on the vertical wells lasts year in Cotton Valley we drilled 114 of those.

And this year, we said we are transitioning over with our engineering group and geological group for transitioning over, so that we can be comfortable within our kind of four walls on the Haynesville play. And we have been able to do that without issuing stock without incurring junk bonds or high yield and we've been able to do it within our balance sheet.

And hopefully like Roland said in October we've added some meaningful reserves. We've lowered our DD&A and we've kind of replenished any dollars that we'd borrowed under our bank credit facility. So I think it's still a viable program and if it changes, we would announce that.

Operator

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

Noel Parks - Ladenburg Thalmann

Just had a few things, 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?

Roland Burns

No, it was slightly lower as $1.6 million in the first quarter our capitalized interest.

Noel parks - Ladenburg Thalmann

Okay.

Roland Burns

That was slowly declined as the year progresses each quarter. But 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 would decrease a little bit and also as we prove up the acreage with our Haynesville drilling program, we'll be transferring cost from unevaluated into evaluated properties and it would no longer be capitalized interest on them. So, that would just slowly kind of decline during the year, how much we'll capitalize.

Noel parks - Ladenburg Thalmann

Okay, great. And sorry if I've missed this, but the sequential decline in let's say Haynesville well against the East Texas North Louisiana a region for the quarter. Was the completion delays that were mentioned in the press release, was that the main reason for that? Because I guess it was a little bit more of a decline than we would have expected even just if it was based decline for one quarter?

Roland Burns

No, there were really two reasons. One, were just some plant shutdowns that we had during the quarter in that region. The Carthage plant with the damage they had to the front of pipelines, the tailgate of the plant caught on fire. It was down close to three weeks. And we move a lot of production through that plant for processing. So, all that we had to shut down a fair amount of production and 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.

And so, that I think that was approximately $4 million a day. And if you average over the quarter impact. And then, the remaining decrease from the fourth quarter production rate was right you know the decline in the Cotton Valley wells and we really did not get some of the Haynesville wells on production until much later in the quarter than we had anticipated. So, we had hoped to see the production to 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're back on track starting in March and going into April in to the second quarter. And really back on track to our original production forecast and we’ll be able to make out the smaller shortfall from the first quarter to the extent that a transportation is available and the DeSoto Parish area, we can actually get away ahead of our forecast. But we are still I am not promising that yet until that pipeline is in.

Noel parks - Ladenburg Thalmann

Okay. And as far as the completion delays in the Haynesville, I was just curious. Was it more just that the vendors were slow or just they're weren't getting on site at the times they had originally promised or were there issues of weather or anything else that slowed down the completion there?

Roland Burns

We had a couple of wells that were delayed because of some internal assessments that 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 being able to get service in this environment. No, so, just in general, the answer to your question is. It is primarily due to a combination of factors. Non-vendor related.

Noel parks - Ladenburg Thalmann

Okay. And again my apologies, if this has come up already. But I recall the Green well that was the one we were doing the dual laterals, I guess one with the Cotton Valley as well as Haynesville North, is that right?

Mack Good

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

Noel parks - Ladenburg Thalmann

Okay.

Mack Good

The well sir.

Noel parks - Ladenburg Thalmann

The 11th at the Cotton Valley well though. Okay great. And I just wondered, I know it's 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?

Mack Good

Well, the spacing question is definitely unanswered. And 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 per 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 spacing question open. And then further, a further interesting element to that overall spacing 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.

Noel parks - Ladenburg Thalmann

Okay, great. And I guess my last couple of questions were about the South Texas. Leyendecker well, what's the current production rate on that now?

Roland Burns

Leyendecker #10, is currently producing about $1 million a day from an upper T6 Wilcox sand. And we are evaluating that upper T6 sand for future efforts in the field.

Noel parks - Ladenburg Thalmann

Okay.

Roland Burns

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

Mack Good

That’s right. We have two behind pipe zones up the hole.

Noel parks - Ladenburg Thalmann

Okay. Because I know you booked I think it was the 13B at year-end. Okay. And what were the well costs like on the couple of new Fandango wells you have this quarter, the Muzza and Trevino?

Roland Burns

Those are both $10 million wells

Noel parks - Ladenburg Thalmann

Okay.

Roland Burns

In that ballpark.

Noel parks - Ladenburg Thalmann

So this finding costs looks like it might come out in the low sort of Buck-to-Buck 50 range maybe for those?

Mack Good

Brad, I hate to give you a number at this point. We are still evaluating the reserve zone till we get enough data, I'd hate to get out there on the land with refining and development cost, but I certainly expected to be low.

Noel parks - Ladenburg Thalmann

Okay. And so these would represent some of the wells that even at really low gas price, that you still would be able to get good economics for your?

Operator

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

Leo Mariani - RBC

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

Roland Burns

They've been on about three to four weeks, some thing like that.

Leo Mariani - RBC

Okay.

Jay Allison

Primarily in the second quarter.

Roland Burns

Right, Leo.

Leo Mariani - RBC

Okay. And how are those wells held up on the production side since coming online?

Roland Burns

Flat. We're very pleased. No decline.

Leo Mariani - RBC

And we'll you folks also going to drill some offsets, is that lined the Leyendecker well at one point?

Jay Allison

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

Roland Burns

And a main reason it's helped our production. We do own a 100% of it. So we want to keep our balance sheet really strong.

Leo Mariani - RBC

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

Jay Allison

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

Leo Mariani - RBC

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

Jay Allison

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

Operator

Your next question comes from the line of Michael Bodino of SMH Capital.

Michael Bodino - SMH Capital

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

Roland Burns

Well currently, our gross production is around 48 million a day. We get about 30 million a day net. That has not hit any of the firm capacity that we're talking about. So, we're 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 light wells that I mentioned. We certainly expect to fill up the pipe with those completions.

And the other opportunities that I mentioned that are 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 IT rates are, they have significant declines over the first few months of production and then the kicker is, when does that production profile flatten out and at what rate does it flatten out.

We're seeing some very interesting and it's preliminary, but some very interesting results on the flattening part of the 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.

Michael Bodino - SMH Capital

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

Roland Burns

Well 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's the slide, get to in a minute to slide 21. It shows the allocation of our effort in the Haynesville and you’ll see that Logansport with 17 wells, 15 of those being Haynesville, it's going to get a large allocation of our effort. And that's where we have had the highest IP rates. We have got those wells in Logansport timed appropriately we think to take advantage of the firm capacity as it's available.

Jay Allison

And then, Michael, we do have four non-op wells that we are participating in right now. Three are just big one as (inaudible).

Michael Bodino - SMH Capital

Okay. 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 that Southwestern DeSoto Parish is that correct?

Jay Allison

We’ve got two in Logansport that are delayed, I think it's mentioned in the earlier slide. 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.

Michael Bodino - SMH Capital

Okay. If you will indulge me just a couple more questions. More big picture you know from a trying to track all these wells on the Haynesville. Certainly kind of moving from Elm Grove towards the Southwest or (Shawnee) County, there seems to be you know as we move from wells that are mid 20s, into the 20s, into the high and mid teens.

It seems like that trend like South West 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 then how do you think about your kind of Northern Haynesville acreage on a relative rate return basis?

Mack Good

Well, a lot of unanswered questions at this point about Haynesville Shale rock quality and the attributes that go into determining performance in part. It's, you got to have a rock and where is the best rock or shale. And so, your question is currently unanswered in terms of specific rock or core item. And we're a member of the core consortium.

We have access to all of the analysis that's been provided thus far. There is no question that around the Elm Grove area you've got, IP's ranging anywhere from 15 to 28 million a day.

We have got a data base that currently includes 84 producing horizontal Haynesville wells and we've done probability distributions on IP's and of course you get into the question of how operators report IP rates, is really no advantage to launching into 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 numbers of wells. So, if you look at the well 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 $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 am talking about. We kept it on a very moderate choke to get it, 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 of 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 bends towards the North. How far 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 is that 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, a number of horizontal wells flowing to sales, just because of the size of the play that I referred to earlier. There is such an expansive play that there's not a whole lot of data in any one part of it.

Roland Burns

And I think a lot of it goes back to your 80 acres spacing or whatever your spacing might be. I mean maybe the higher IP rate wells have to have more acreage, recovers a greater amount of reserves.

Michael Bodino - SMH Capital

Right.

Roland Burns

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. And I think we'll have a handle on that by the end the year.

Michael Bodino - SMH Capital

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

Jay Allison

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

Operator

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

Mark Lear - Sidoti & Company

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

Mack Good

Yes. Short answer, but, yes. Certainly going to the newer design and getting the improved performance, we have had some adjustments on our and they are initial adjustments, as you may or may not know, Comstock has been very careful and very conservative in the past in launching a type curve EURs for the Haynesville because one number does not fit all, different areas have different characteristics. So, 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 type curve adjustment. We are not going up on our type curve at this point. But we feel very comfortable and confident there is going to be an adjustment in the couple of areas just because of these performances that we are seeing.

Again extremely pleasing to see that the change in the frac fluid and the proppant size and where we are placing the lateral and how we are perforating each stage with the number of perse and the number of clusters per stage that has really allowed the performance to improve.

Mark Lear - Sidoti & Company

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

Mack Good

We are working on a couple of things. And as you know, the 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, you and your confined the geometry of the drilling unit then limits you to the length of lateral that you can drill. That's certainly a disadvantage. And that's one reason why we are allocating most of our efforts into the Louisiana area.

Now in order to get a longer link lateral currently in Texas, you have to start your drilling the surface hole, the vertical section off lease. And so when you build the curve, you are building it pretty much off lease and by the time you go to the lateral section or the horizontal section you are on lease. And that way you don't use your usable real estate within a drilling unit by drilling the surface hole within that lease. Do you follow me on that?

Mark Lear - Sidoti & Company

I do.

Mack Good

Okay. And so we are looking at some of that. We got to get and make the arrangements to do that kind of work and we are certainly looking at doing that. But it's much easier in the Louisiana I assure you to drill those 4,500 foot lateral links that. And we are looking at going longer than that if, in a couple of places, we have off site or off lease surface locations to start the hole.

Operator

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

Ray Deacon - Pritchard Capital

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

Mack Good

The drilling complete costs were approached about the 8 million-dollar mark.

Ray Deacon - Pritchard Capital

Okay.

Mack Good

Yes.

Ray Deacon - Pritchard Capital

Got it, great. And I was just wondering, what do you consider, I mean that 7, 8 million a day IP rate in Texas looks like one of the better ones out there. I guess we're with the new completion techniques on the screen well. Would you be happy or can you talk about what you might be targeting on the Texas side?

Mack Good

With Texas, you started with the lateral length. And we want to make sure that we can get a plus 3,500 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 we are 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 of the design and in order to initiate on the Texas side so far, we have 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 in getting these fracture started, but our goal is to use the lighter frac fluids as much as possible along with the 40/70 smaller proppant. And we think that will be a significant contributor to the improving performance well on both side and both states Texas and Louisiana.

Ray Deacon - Pritchard Capital

Got it. Great. And I guess, you don't have any plans to drill the Shelby acreage this year and it looks like you have a fairly big chunk of acreage there. I guess, is that something you have planned for early 2010 or…

Mack Good

Yeah, currently it's on the 2010 schedule. Right we're looking at it. The one thing that Comstock is going for it is a large part of our acreage is HPP, so we're not forced to drill 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 and so, Shelby, we are looking at what can we do to put drilling units together to make sense down there. And if so, which drilling units would be highlighted and when. But right now you're right. 2010 it looks like the timeframe for doing anything in Shelby.

Operator

Ladies and gentlemen, we 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.

Jay Allison

Channel, thanks again. Remember, our goal this year, it is to improve our proportion of the 3.3 trillion cubic feet of potential reserves in the Haynesville. And 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 four Bcfe’s in EUR and we started out in January added five Bcfe’s and EUR and maybe we can go up from there, but we'll do it when we are 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 Burdock and the non-core properties, I think that allowed us to have an extremely strong balance sheet in the environment that we are 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 do 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, Channel.

Operator

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

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Source: Comstock Resources Inc. Q1 2009 Earnings Call Transcript
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