Comstock Resources Inc (CRK) 2006 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the first quarter financial results conference call. At this time all participants are in a listen only mode. Later we will conduct a question and answer session. Please note that this conference is being recorded. I will now turn the call over to Mr. Jay Allison. Mr. Allison, you may begin.

Welcome to Comstock Resources first quarter 2006 financial and operating results conference call. You can view a slide presentation during or after this call by going to our Web site at www.comstockresources.com and clicking "Presentations." There you will find a presentation entitle "First Quarter 2006 Results." To change the page in the presentation click on the arrow on the page. 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. With this call I will review our first quarter 2006 financial and operating results as well as results to date of our 2006 drilling program. Our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations and such statements of be reasonable, there can be no assurance that such expectations will prove to be correct.

Slide two, strong oil and gas prices and increasing production from our onshore properties contributed to strong financial results in the first quarter of 2006. Our revenues reached $70 million and we generated EBITDAX of $52 million and operating cash flow of $47 million. We also generated a profit of $24 million or $0.55 per share excluding the unrealized mark to market gain of $8.8 million we recognized this quarter. Including this gain we reported net income of $30 million or $0.68 per share. Our onshore production increased by 26% this quarter reflecting the emphasis we have placed on investing in our onshore properties with the IPO of bois d'Arc Energy. Bois d'Arc had a solid quarter, which we just reported which also contributed to our bottom line this quarter. Bois d'Arc's production, revenues and net income were up substantially as the company has recovered from the 2005 hurricanes. Bois d'Arc also reported excellent drilling results this year with five discoveries that will add to its production and reserves.

Our onshore drilling program is off to a good start with 30 successful development wells drilled. We are facing some setbacks in achieving our goals this year due to delays in getting oil field services. On slide three we outlined our onshore production by quarter and by region. Our onshore production averaged 97 million cubic feet equivalent per day in the first quarter, which is an increase of 26% over 2005's first quarter. Our East Texas-North Louisiana region averaged 49 million per day. Our Southeast Texas region averaged 17 million per day and our South Texas and other regions averaged 31 million per day during the first quarter of 2006. We expect our onshore production to increase this year, as we are able to connect the wells we are drilling in East Texas-North Louisiana to sales. We have scaled back our expectations for increased production in that region because of a delay in deploying the three additional rigs we have under contract. We now expect the additional rigs to be on location in June.

The slide on page four details the components to our production forecast for East Texas-North Louisiana. Production from new wells drilled is shown in green. With the new production from the drilling program we are forecasting this region's production to grow by 28% this year.

Slide five; our onshore average oil price increased 12% in the first quarter of 2006 to $53.69 per barrel as compared to $47.81 per barrel in the first quarter of 2005. Our average oil price in the first quarter was 85% of the average NYMEX WTI price in the quarter.

Slide six; our average onshore gas price increased 27% in the first quarter to $7.82 per mcf as compared to $6.16 in the first quarter of 2005. Typically our realized natural gas price is very close to the average NYMEX gas price. In the first quarter our realized gas price was only 87% for the Henry Hub NYMEX price, mainly due to large differentials from East Texas and the Houston ship channel and the Henry Hub NYMEX price. With NYMEX prices declining we have seen these differentials decline. The May Houston Ship Channel Index is now $0.37 less than Henry Hub as compared to the $2.77 differential we had in January.

Slide seven, during the first quarter we had a mark to market gain of $8.8 million to reverse a portion of the unrealized losses we took in 2005 on our hedge position. In the first quarter we paid out $700,000 on these positions as gas prices exceeded the ceiling price of $9.02. In 2006 approximately 17% of our gas is subject to a $9.02 ceiling.

Slide eight, oil and gas sales. To best compare oil and gas sales we have broken out onshore and offshore. We have also included the sales that we did not pick up from bois d'Arc as a result of changing to the equity method. For the first quarter of 2006 our oil and gas sales increased to $100 million, which represented a 43% increase from 2005's first quarter oil and gas sales of $70 million. Our sales from our onshore operations increased 59% to $70 million in the first quarter of 2006 from $44 million in 2005's first quarter.

EBITDAX shown on slide nine, our earnings before interest, taxes, depreciation, amortization and exploration expense and other non-cash expenses, decreased 5% in the first quarter of 2006 to $52 million as compared to $55 million in the first quarter of 2005. The decrease is due to using the equity method of accounting for our ownership in bois d'Arc. We no longer pick up any of bois d'Arc's EBITDAX, which would have added $23 million to our EBITDAX this quarter.

Operating cash flow on slide ten. Our cash flow from operations increased 1% in the first quarter of 2006 to $47.2 million as compared to cash flow of $46.5 million in 2005's first quarter. Using the equity method we did not include $21 million in operating cash flow related to our share of bois d'Arc's operations, which if included would have increased our cash flow to $68 million in the quarter for an increase of 45% over 2005.

Earnings, slide eleven. Excluding the mark to market gains or losses from our derivatives, we reported net income of $24 million or $0.55 per share for the first quarter of 2006 as compared to net income of $18 million in the first quarter of 2005 or $0.48 per share. The impact of reversing part of the unrealized loss on our hedge position created an $8.8 million gain or $5.6 million after tax in the first quarter, which we excluded from our reoccurring income.

Slide twelve, first quarter costs per mcfe. With rising oil and gas prices our unit costs have been increasing also. Our lifting costs per mcfe produced increased $0.35 in the first quarter of 2006 to $1.59 as compared to $1.24 in the first quarter of 2005. Higher production taxes and higher ad valorem taxes due to the higher gas prices account for much of the increase. Our depreciation, depletion and amortization per mcfe produced increased $0.24 in the first quarter of 2006 to $1.86 per mcfe as compared to $1.62 per mcfe in 2005's first quarter.

Capitalization shown on slide 13. During the first quarter our debt did not change from year-end. Our equity increased by $31 million to $614 million from $583 million at the end of 2005. Our debt to total book capitalization has improved to 28% at the end of the quarter as compared to 29% at the end of last year. In addition, our stake in bois d'Arc has a market value of $524 million compared to our $260 million cost basis.

On slide fourteen we break out our onshore drilling expenditures by region. We spent $49 million in the first quarter on our onshore properties as compared to the $24 million that we spent in 2005's first quarter. 30 of the 32 wells drilled in the first quarter of 2006 were successful with only two dry holes. We spent $38 million to drill the 32 development wells. We spent an additional $9 million for workovers and re-completions and other development costs and 2 million on acquiring leases. $29 million was spent on our East Texas drilling program. $20 million was spent on our other regions. We still plan to spend approximately 200 million on our drilling program this year.

East Texas-North Louisiana region, we drilled 17 successful wells in East Texas-North Louisiana in the first quarter as shown on slide fifteen. They were drilled in seven different fields. The wells drilled had an initial average production rate of 1.4 million cubic feet equivalent per day per well. We currently have 4 rigs drilling in this region and we expect to add 3 additional rigs in June to ramp up this program. Since we have fallen two months behind on adding the new rigs, we are working to add a ninth rig by at least the fourth quarter to catch up.

Slide sixteen, our South Texas region; we drilled 2 successful wells in our South Texas region in the first quarter. They've been tested at a per well rate of 3.2 million cubic feet equivalent per day. These wells were drilled in our Ball Ranch and Javelina fields and we are currently drilling 2 wells in this region.

Other regions, slide seventeen. In the first quarter we drilled 6 wells in our mid-continent region. 5 were successful and 1 was a dry hole. We drilled 3 successful wells in our Laurel Field in Mississippi. These wells are in the process of being completed. We participated in drilling 4 wells in the San Juan Basin in New Mexico. 3 of these were successful and 1 was a dry hole.

Bois d'Arc Energy, slide eighteen. Our Gulf of Mexico operations are now reflected in our 48% equity ownership of bois d'Arc. Bois d'Arc is off to an excellent start this year with successful results from our exploration program. To date in 2006 bois d'Arc has drilled 5 successful wells out of a total of 6 drilled for an 86% success rate. The successful wells include the Laker 5 well at ship show block 111, a successful extension well in ship show block 99 and the number 1 well at Eugene Island 166 to test the Pickle prospect. The largest discoveries include the Steelhead well and our most recent discovery the Sockeye well at South Pelto 22. The one unsuccessful well was drilled in the first quarter of 2006 at South Timbalier Block 11. The discoveries made to date by bois d'Arc will more than replace their 2006 annual production.

Slide nineteen, 2006 outlook. Looking at 2006 we are very excited about the prospects for Comstock. We expect to spend $200 million on our onshore drilling program this year, which is a 64% increase from the $122 million that we spent on our onshore drilling program in 2005. The 96 well Cotton Valley drilling program we had planned in 2006 will continue to drive production growth this year. We have 408 operated low-risk drill sites to support our continued drill bit growth in future years. Our investment in bois d'Arc Energy is performing well with an outlook for strong reserve and production growth this year. And our debt is only 28% of our total capitalization giving us a strong balance sheet to support future growth. With that, Rose, I'll open it up for questions.

[Operator Instructions] Our first question comes from Larry Busnardo from Petrie Parkman & Co.

Jay, can you just talk about what's the cause of the delay in getting those rigs? Is it just operators that currently have them taking longer with them?

Yes I'll make a comment and Mack, Larry, he can complete it. We've got two Patterson rig and one unit rig that were supposed to have been delivered latter part of March, early April and then they would all be drilling by today and I know one of them had draw works issues. They've all been delayed anywhere from six to eight weeks. We have been constantly on them because we just were informed of that in April. So the one thing we said we've got to do is we've got to get the 96-98 wells drilled and completed even if we can't get them connected to sales. That's why we've committed to this ninth rig. But with that, Larry, I'll have Mack give you some detailed information on that.

Larry, just briefly the situation with the rigs, as Jay mentioned, we were informed early April, the first week of April, that there would be a delay and primarily the reasons are pumps and draw works. The manufacturers of that equipment are just overwhelmed and there's delays getting that equipment to the rig contractors. All of the rigs that we have coming in June-- that's the latest forecast on delivery-- all of these rigs are, two of them are refurbs and one is a brand new rig coming into the market, so all three rigs are new to the market coming into East Texas. So they're being built as we speak and as late as Wednesday of this week we were informed that we're still on track to get delivery of all three of those in the first week of June, by the first week of June. And we're having discussions with a couple of our primary contractors to furnish us another two rigs that are currently being refurbed.

Do you need that ninth rig to meet the program target of 96 wells?

Yes we do.

If you don't get that how many do you think you would be able to get done provided those rigs, these three rigs show up in early June?

88.

Okay so it would be a little bit less?

Right.

In terms of the operations, IP rates of 1.4 million a day, it looks like that's just a little bit lower than the historical rate I think that you guys have shown of 1.6. Can you just talk about that? I mean is the program meeting expectations? Do you feel everything is going according to plan?

Absolutely. We're very pleased with the performance to date. We're seeing excellent performance from the first quarter wells and we're in some areas now until the production is in for the next two to three months I can't talk about specifics but I can tell you generally the performance is better than we've seen in the first quarter.

Wayne Andrews from Raymond James & Associates.

Another follow-up question to that, Jay, when you talk about going and adding a ninth rig, you're really talking that's for Company wide, is it not? And you're operating I take it four in East Texas and adding three more so you're going to seven. Is that right?

We're talking about adding another rig in East Texas. That would be eight working in East Texas and then one in Mississippi for nine total rigs in the Company and we have an off discussion with another vendor to add a ninth rig in East Texas later this year.

Right now, Wayne, we have one in Mississippi. We have four in East Texas so that's five. We've got three more coming and those go to East Texas, which is that's eight. And we're talking about adding a ninth or a tenth if we have to add even that tenth rig, our goal is to get the holes drilled. I mean even if we don't have the time to produce the wells, our goal is to get all those holes drilled and completed and hopefully we could get them producing but-- and if it takes another rig or two to do that then what we're communicating today is we're going to do that. It's not-- we didn't cause the delay in the three rigs and what we're trying to do is to overcome that problem by telling you that if we have to add another two rigs and we can find them and we have to sign the contracts that are the normal contracts today, then we probably will do that.

And the original 98 well program was based on operating six rigs in East Texas. Is that right?

Seven rigs starting in April, the first week of April and, of course, we've been delayed until June to bring those three in and we have well locations built, ready that are awaiting the delivery of those rigs and they've been ready for three months.

Yes what we did is we-- remember in September we said we wanted to drill, we said 100 wells in East Texas/North Louisiana in '06. We ended up with like 96-98. And we said we have four rigs; we need to get three more. We got commitments for those three. We got commitment dates and then the drilling program was based upon those commitment dates and we had a little wiggle room in there but if you start pushing it back two months and these wells come in at 1.4 million and 1.5 million today, that's where you get hurt and that's what happened to us kind of early-mid April, kind of the 10th or so, and really we couldn't do anything about it. We're trying to continue to push the contractors and, like Mack said, the delays in the pumps and the draw works because of demand.

Wayne, the bottom line here is that this is an industry wide problem that other companies are waiting on rigs as well.

Absolutely yes.

You know this has been pushed back and continues to be an issue.

My question that I had with Mack and Larry asked this, and that is is the performance as good or better than expected from what you drilled? And the answer is it's a little better than expected so--

Well very good. I'll expect to see a pretty significant ramp in the second half and thanks for your time. Good work.

Rhett Bruno from First Albany Capital.

It's actually Eric Hagen but some questions on East Texas. First off, how much net acreage do you have in that play, East Texas/North Louisiana Cotton Valley play?

Roland, what's that? Do you have that in front of you?

Well, our whole-- we've got 300,000 acres of properties now. Some of that's held by production or some of it isn't but just a lot of these wells are drilled in down spacing situations so--

So well I noticed that you're drilling in seven different fields this time. I mean historically haven't you concentrated in just a few different fields and is the intent this year more to evaluate the acreage rather than just increase production by say drilling pud locations?

Yes what we did last year, Eric, we concentrated I think 46 of the wells were in Beckville and Blocker and really we drilled the proved undeveloped locations, which are those legacy puds that we had bought mostly when we bought [Sonan] back in '95. And the goal in 2006 was to spread that drilling program out over fifteen separate fields. We've got almost thirty separate fields. We wanted to spread it out over fifteen because the goal was to attempt to add anywhere from 40 to 60 bcfe in step out locations through that drilling program. In fact, this is the first year that we've started drilling some acres that we acquired when we bought the insight properties in June of 2005.

Now most of the other operators are drilling on 40 acre spacing. I mean how many of these fifteen fields are being drilled on 40s or do you even you know--?

About half of the fields in the first quarter have been drilled on 40s. The remaining half, and you mentioned this in your question, is where we're drilling in some of the insight fields where the second-- drilling the second well in a unit, a 704 acre unit, so there's plenty of room to develop. We're setting up offset locations and it's been an exciting first quarter in developing some of those fields.

And then one final question on Laurel, what's the size of those wells and what kind of success rate-- I mean do you estimate on those?

We've just drilled our fifth well in Laurel. The first three were sidetracks that we drilled in the fourth quarter of last year and we're making about 200 to 250 barrel a day average wells there. Two of the wells are currently completing and being put on artificial lifts so we're evaluating those and we're getting ready to drill the sixth.

And the well cost on those?

Varying costs because we're going to different depths with different directional components but we're looking at $2.5 to $3 million for a grass roots well. The sidetracks were about a million.

Ron Mills from Johnson Rice & Company.

To follow up on Eric's question at the Laurel field, can you expand a little bit on what your position is there, running room and/or potential to expand your footprint?

We have a significant potential to expand the footprint. The Laurel field is a layer cake stacked reservoir field, as some of you know. It is aerially has a small footprint but we've expanded our leasehold in the region and we'll be developing that expansion through the remainder of this year and we'll see how it goes. We have reason to believe that there's significant room to continue the development.

And then in the Cotton Valley with the rig delays it looks like basically your growth wedge from that area is basically pushed off about a quarter. Is there-- is that correct and then secondly if you bring in the eighth rig and then what kind of timing would you suggest from bringing in the eighth rig so we could start to have that show up in production volumes?

Of course, I wish I could give you an exact date but that's difficult to do in this environment since it's an industry wide issue but we're making-- we're in negotiations now for delivery of an additional rig and we'd like to bring it in in the third quarter, earlier the better. Exactly when the additional rig, rig number eight and rig number nine if needed, would be delivered I can't tell you at this point. But that's the goal is to get it in the third quarter, earlier the better.

But from a pure production impact though you're really looking at a late '06 and early '07 impact from having your full seven to nine rig program in Cotton Valley?

Absolutely right. We'll get some benefit in the fourth quarter of '06. If we were just to play the what if game, if we can get a delivery of rigs eight and nine early in the third quarter then obviously we'd get the benefit of the additional production in the third quarter and throughout the fourth quarter from those two rigs from being able to complete those wells.

Hey, Ron, the need for those two rigs, I mean we already had that need. We didn't plan on using them right now but remember we said that preliminarily we'll probably drill 130 plus wells in this area in 2007 so you're going to need another one or two rigs anyhow.

And are those wells still taking roughly a month to drill and another month to complete and can you give us an update on what kind of costs you're seeing?

Yes our average drilling complete cost is about 1.8 million on the Cotton Valley Wells and our average spud to sales cycle right now is about 50 days.

And from the reserves standpoint I'm assuming based on the results coming in as expected that you still feel pretty comfortable with your prior reserve estimate, which I think was 1.3 to 1.5 b's or so per well?

We're still evaluating some of the areas but based on the IP rates we have no reason to think otherwise. They're performing very well like I mentioned earlier.

And then, Roland, from a financial standpoint with pushing out the production, can you update me a little bit on your borrowing base because I think now you'll probably have to dip into that borrowing base?

Yes our borrowing base, Ron, currently is at $350 million. There's a lot of availability so to the extent we have to use it in-- based on it really depends on, of course, what happens with prices in the last part of the year, but right now we're forecasting to borrow a little bit to fund the $200 million program but it's a fairly small amount and it's real contingent on what happens with prices. You know, if they come back like the futures market says in the fourth quarter, then we won't have to borrow very much at all.

Van Levy from Dahlman Rose & Co.

Hey, let's beat this East Texas thing to death now. You guys are the most rational or some of the most rational people I know in the oil business. I guess what concerns me a little bit is that just focusing on hitting your target could drive your prices for services up and finding costs up etcetera. What's the kind of yin and yang there, Jay?

Well, on the I guess you're saying-- I guess we would look at it as we still-- of course, it is a price sensitive play and we're monitoring the performance of gas prices. We still feel real comfortable with the program with the current price levels out there and we see it as we'd really like to get these wells drilled to the extent that prices are going improve. And for next winter we'd like to have these things drilled and on production. We think it's important to do.

Right but so you're going to be rational about it if to get the ninth rig or whatever becomes too expensive.

You know what we've said is we've always hopefully been sensible. Our budget was that $1.8 million to drill and complete the wells and we're kind of still in there. Look at a price stick of $6, $6.50 and get a phenomenal return so we're still there. We've paid down over $30 million in the fourth quarter of last year on our debt so I think we have maybe $175 million of bonds that are eight year notes and then over and above that maybe 65 million or so of just bank debt so not nervous about borrowing dollars if we had to. We probably won't have to but if we do it's not that big a deal. And, as you know, we've got five different service companies, Van, that we have contracts with to drill these wells so we've not-- it's not like a monopoly group that's out there drilling all of our wells. We've tried to spread it out in drilling. We try to do that to keep it somewhat competitive or honest, which is kind of--

Right.

The service companies are there. Like Mack said, even if you get a rig you've got an issue of do you have a stock five stage completion in two stage? I mean what-- how many really frags can you have and with the amount of wells you want to complete and we are reevaluating everything. No we've--

No I mean again you guys are the most rational. I think the market can understand delays in terms of sacrificing economics to make production targets. It just-- and I know the way you burn your business it doesn't make sense.

No one of the drivers too-- there's several drivers. One, if you look at the components of Comstock, we have an expiration engine that was created actually a year ago today. It was the bois d'Arc IPO. I mean we've got 260 million invested in it. We've got 530 or 540 million in value there and on our books there's no debt. I mean it is a total growth engine. Well, then what that did we went from 53% debt to cap to 28% debt to cap at Comstock and we doubled the amount of wells that we'd ever drilled. We doubled that in 2005 and there's another 60 some percent increase in 2006. Our bunch of engineers and geologists, we've been-- we haven't hired-- we've hired good people. We've been very slow to hire good people and they're hard to find. And then what we did is we put a program in that we felt very comfortable that we could manage. Now three of those rigs are late and that should have been expected but once you've beat it up for a couple months and you get those assurances and it just I guess wishful thinking that you can get them and we didn't. And we didn't find that out until April and then what you do is you kind of work to see whether those dates are good, the new dates. And then, of course, the rig owners have to go back to the manufacturers of the pumps and draw works etcetera, etcetera.

If you look in '07 and we've always said, Van, that with over 400 drill sites that we operate-- that doesn't include the ones we don't operate. We'd like to drill 130 or 140 wells in '07 depending upon commodity prices and service costs so we're not afraid to have another rig or two because we'd have to have that anyhow. And like Roland said, you really want to have it hopefully when winter hits again.

You know in a weird way it's actually pretty good because it underscores the tightness in the industry, which underscores if you're having trouble a lot of other people are having trouble, which means not enough gas is coming on which means prices will be higher, so in a weird way it kind of affirms the gas story.

We're a pretty good barometer because we're what, a billion and 40 or 50 million in size? We've been in East Texas for fifteen years. We've got plenty of money to pay our bills and we drill a lot of wells so we're a pretty good barometer for the service side and the E&P side really.

Other question, you mentioned in your presentation what if the bois d'Arc component of cash flow. The reason you're not capturing their cash flow in your sources and uses statement is because you're below the 50% threshold. Would it make sense to buy back enough stock to move you above that threshold and--?

Well we looked at that and the numbers are materially different if you consolidate it and I mean they are. You just--

The investment wouldn't be that large to change the accounting.

Right. I mean I think the market when you look at your cash flow and your multiples you look a lot richer than if you could really run through the statements the bois d'Arc components.

Oh I mean, you just look at like on slide eight. I mean $100 million, which represents a 43% increase from 2005's first quarter oil and gas sales of $70 million and that--

Well that would, if you consolidate it, the numbers would even be larger because we'd have 100%, not just 48%.

Right, well you know why we did that, Van. We did it because we wanted to make sure that any stockholder and any analyst had complete clarity on both companies and that was the reason. We just though it would be the better thing to do and we thought that the market and the analysts would give us a value for owning 48% of an unbelievable successful exploration company that we helped create in the Gulf of Mexico. So no, we always look at that and evaluate it. We've elected not to own 50 point percent interest so that is always something that we could do.

That would be a nice-- I think you give probably too much credit to analysts, myself included.

The numbers, they're phenomenal. If you look-- what we attempted to do at Comstock when bois d'Arc was created the goal was to whatever reserves that Comstock pushed over to bois d'Arc in that creation was to add those reserves back to Comstock and with the inside acquisition and the Ovation acquisition you notice first quarter numbers. They were as good or better than last year and that's excluding the bois d'Arc production, so we replaced that. We already replaced that and now the next bogey is kind of growing that but we've already replaced that with the inside acquisitions and some drill bit success and Ovation. So no, it's been a wonderful story. It's still a little murky to understand.

And then the last question, in your Analyst Meeting I think you said that Mississippi this year you'd drill-- or maybe it was the other area you'd drill 27 wells but with the majority in Mississippi. Could you refresh my memory on that? And also, these 6 wells you've drilled to date, it doesn't sound like these are some of the bigger flank wells or flank prospects that you could drill.

Well Mississippi we said for '06 our goal was to drill 16 wells, spend $30 million and at the Analyst Meeting I think we had drilled 3 or 4 of those wells. Is that right, Mack?

That's right.

And, Van, those were re-entries and-- they were sidetracks, Van.

And we've just now started the grass roots wells as we're stepping out away from established production so we really haven't-- we've just scratched the surface on that process.

Well in fact, we've had a neighbor's rig on a location for about thirty days longer than it should have been there, so we've had a little drilling problem there and as far we also reported that we were trying to acquire several thousand acres and we've been successful in acquiring a little of that, or at least half of it.

So, Mack, could you lay out a couple of the higher potential wells, what their names are, when they would likely spud?

We're getting ready to spud one of those right now. It's the 31-13 number 5, City of Laurel and we anticipate that that could be a 500 barrel of oil per day well. We're completing the 31-13 number 4, just started that. It has excellent logged pay, both in the [Rodessa sligo] and through the Upper Toast Reservoirs just to put names to them and we're just now starting to start the completion process but I think that could be anywhere from 300 to 1,000 barrels of oil per day depending on what we complete. And those are the first two grass roots wells in the program.

Kelly Krenger from Banc of America Securities.

A quick question on what you're seeing on the M&A front, I know that you guys it seems like you've been much more focused on your internal projects and from what I remember you said that you didn't see great value in the M&A market but I just was curious if that is still the case?

What we do is we always look at that. We always look at data runs and we always look at one off private acquisitions. I mean we're busy doing that all the time. The M&A market is depending upon what area you're in and depending upon how many rigs you control, which it didn't use to be like that, and how many probable and possible reserves you want to pay up for. I mean there's all kinds of different nuances right now because the sector is kind of frothy. So we look all the time. We never quit looking.

Okay but from what you're seeing standpoint it's--

Hyper competitive is how we would, especially the onshore property market, very, very rich prices having to pay for properties, not really tracking what's happened on the commodity prices really

Paul Childs from Steadfast Financial.

I had a few questions here. In terms of your new guidance since-- what is the-- what are you assuming in terms of the rigs coming on in your new guidance?

The time frame or the rate?

Yes, this just assumes you get to three rigs in June. Is that right?

Correct. Mack, you want to--?

When you talk about guidance, you mean how many wells those rigs would drill?

No. I'm talking about the slide--

Those three rigs--

Slide three that has your, slide three or four that has your projected guidance on the onshore. I assume that's--

Slide four is the production forecast.

Are you-- in other words, Mack, all the rigs Paul is asking, all the rigs do you assume they're all drilling by the end of June?

Yes.

And that does not-- this doesn't assume that you get another rig that you add with the one or two more rigs, right?

Right.

Okay so now it's one or two rigs that if you do get them would be incremental?

We would accelerate the ramp.

So the goal is if you get all the rigs drilling by the end of June, then you should drill at least 88 of the wells. Okay is that what you're looking for?

That's about right. Also curious about in terms of you have the four rigs drilling, have you-- when you have these three rigs coming on and as you said [inaudible] on the new build and they're all going to be new to the oil field, have you basically assumed a longer drilling time, a less efficient--?

On the first two wells we have.

So you're assuming for those first two wells on each rig are going to be less efficient?

Right, breaking in the rigs.

Now for [Patterson] you didn't say are these will be new crews that they'll put on these or will they take people-- how are they going to crew these?

Actually the way it's working in the oil patch is that companies are stealing other company's crew hands and because there aren't that many out there it's a rolling problem. What solves a problem for Comstock would easily create a problem for another company using another vendor's rig so that's part of the answer, the candid answer. Those hands, a number of them, would be experienced hands but there would also be a mixture of some people that would be getting training on the job so to speak and that's why we've assumed the inefficiencies.

Just on the first two, okay. Now I was also sort of curious I think falling back to another question is you've talked about your willingness to maybe sign one of these longer-term contracts. Now one of the reasons that you probably in the latter part of last year and into this year that you tried delayed getting some of your rigs is you weren't really willing to sign a long-term contract at the current rig rates that you saw. Is that sort of a change in your outlook on things or your--?

No in September I wasn't willing to do that and by October-November the contracts if you want a-- if you really want a rig for a program and you don't own the rig, it's an eighteen month to two-year contract and so what we've said is we're not bashful. If that's the going rate in our area for a good rig and crew and we need another rig or two, then that's what you have to do so we're communicating to you, the stockholders, that we will probably need those two rigs anyhow for '07 so we'd be looking to do that.

Right. Have you changed your rate of return assumptions now that you're willing to take these rigs? Is it slightly lower or is it--?

What we wanted to do was we wanted to on a more gradual slope ease into having say nine rigs in East Texas/North Louisiana. We went from three to four last year. We're going to go from four to seven this year and then at the end of the year, the beginning of '07, we could add another two and that's on your wish list and druthers and it doesn't work right now because we're going to be a couple months behind.

All right and I was just sort of curious because it-- your production growth will still be good. I just wanted to make sure you weren't sort of rushing to complete wells.

No we're not. We're teeing up really and this is Ron Mills alluded to, we're teeing up '07's program earlier than the fourth quarter of '06. We're going ahead and going to try to get those one or two rigs because we're going to need them anyhow and we're going to project that they're going to be a quarter late than what we think we'll get them. That's all that amounts to.

Now I guess you didn't really change your cap ex guidance. I guess I think it was originally 200 million and you haven't really changed it. Is that right?

Right. Because what we really looked-- even though we won't be spending that money in the second quarter but we've since we're going to try to add the rigs later in the year, we'll still try-- we'll still be if we're going to try to drill all the wells, we'll still use all the cap ex up.

Okay so your cap ex assumption assumes that you get these rigs but your production assumption assumes that you don't get the rigs. Is that right?

Right but what the most likely scenario is that you get them but they're going to be completed so late in the year that they're just not going to be a big factor in the production and we can review that if they come a little earlier. In the best case they'll affect the fourth quarter and so I think this is the most realistic look now.

Right, no I think that's fine. I think showing the most conservative route is probably the best way to do it and.

Remember our goal is if you can't get them producing at least you want to get them drilled so--

So they're there for '07.

Right.

Right that makes sense and personally I think that the going back to the other comment I think that the way you split out the bois d'Arc was probably the cleanest way to do it as opposed to having the 100% consolidation, probably is the cleanest way to do it, just personal opinion. But in any case I just wanted to maybe some questions for Roland here. What were the severance production taxes for Comstock in the--?

Yes of the 13.9 million in total lifting costs?

Right.

Severance and taxes were 2.9 million and 11 million was the other lifting costs.

Right and how much of your taxes were deferred in the quarter?

The taxes, the total taxes is 16.9 million provision for taxes and that was about a 36.3% kind of total rate. 92% is deferred or 15.5 million we were able to-- we have to defer a lot because of the active drilling program.

Right and actually maybe if I could get your-- what were those numbers for bois d'Arc as well?

I had those earlier but nobody asked them.

I tried to ask them but they cut me off.

I think they're--

No, that's okay. If you don't have them I can always just--

Yes you can call back a little later but their deferred rate I'm pretty sure like 86% of the total tax provision and I know the production taxes for bois d'Arc were 400,000 out of the total lifting costs and they have a very small amount of--

Right because it's the Gulf of Mexico. Now are those sort of the rates that we should be using in terms of your deferral?

Well I think Comstock I would probably, the 92%, I'd probably go back to-- still that probably more like 85 to 90. It might not quite be as strong as this in all the other quarters. It really depends. It's an interplay between how hot prices are and income and a lot of different things but it shouldn't be any less than 85% and maybe it will be around 90. At bois d'Arc we're using about 85%.

Now I guess just one final question on your DD&A rate it seemed to go up again during the-- what do you expect for that going forward?

Well that will be-- I think it will be a pretty similar rate. It was up a little bit from the fourth quarter mainly because we haven't really been able to add any new reserves yet to the production base. Mid-year we'll probably have the ability to take a look at the reserves that we've added from the drilling program. So I think it'll be a fairly comparable rate to where it is now.

That's fine. And 37% is for the full-year is probably still right on the tax rate. Is that right?

Right well yes, 37's probably more conservative. A lot will depend on-- the higher the income level, like if gas prices are stronger then they appear now, then that percentage would go down because what's driving the difference between 35% in tax rate is [tempernament] differences, which are fixed. So 37's probably a good way to model it and then if--.

All right. That's great. Thanks a lot for your help.

Our next question comes from Rehan Rashid from Friedman, Billings, Ramsey.

Most of the questions have been answered, but I'm not getting hung up on East Texas, but this year alone Jay you've mentioned 130 to 140 wells next year. Two quick questions on that front, would 9 rigs be enough to deliver or 8 rigs be enough to deliver on that 130, 140 kind of range and from a planning perspective if you could give us a feel for what else needs to go into the thought process of executing on that next year's program of 130, 140.

This is Mack and yes 9 rigs in the [Arco, Texas] region would drill that number of wells. Obviously, planning for '07 now we're involved in discuss with pipe suppliers, compression companies, construction companies in order to gain some preemptive agreements that would allow us to go forward with that level of the program. Infrastructure modifications would also, obviously, occur and just like they did for this year's program and that's an ongoing process, but the bottom line is the rigs would drill that number of wells services. And again, it will be an industry wide problem for active companies that are trying to execute aggressive programs. The frack companies, the pumping service companies, the logging companies, the perforating companies, etcetera are all building additional capacity to meet the market demand for obvious reasons and we're having discussions with them as well.

Any incremental thoughts on putting in floors or [inaudible], Roland?

No, I mean we haven't had a lot of discussions on that. Recently we've been trying to get rid of the current ones that we have going back from really 2004. Yes, especially now I think the longer-term markets are pretty strong for putting in some positions. Obviously, this summer you wouldn't want the fairly weaker markets, but we really don't think that we really think we can adjust the capital program because if prices are that low instead of trying to artificially support the program with derivatives, which we would rather re-deploy efforts into other areas that would make more sense in that price environment.

And on another broader question from just maybe in terms of adding more depth to the overall portfolio, why there's [inaudible] on an expiration standpoint, can we talk a little bit more about what's going on in South Texas or some other places, or where else are you looking to maybe Greenfield the next leg of growth come '07, '08 whatever it might be?

As you know, we are involved with [Abico]. We have an exploration joint venture with them and we have teed up with those guys a number of exploration projects that will be executed this year. There's a-- and again we're in the process of firming up those prospects to drill this year, so I can't be real specific about it other than to say we have a 25,000 acre region that we're focusing on for exploration and that's I addition to the Ball Ranch area that we're already actively drilling and the Javelina field in Hidalgo where we're drilling with Abico. We have additional exploration prospects in Mississippi that we're excited about and we're firming up our lease-hold position there in areas outside of Laurel and by that I mean those exploration prospects in Mississippi are not connected to Laurel. They're in other areas, other regions.

Our next question comes from [Kim Stevens] from Schneider Capital Management.

I would like to circle back to East Texas and again and when I was down there for your analyst meeting just a couple months ago you highlighted a property, the Douglas property, and I noticed you drilled three wells during the first quarter. I was wondering if you could just talk a little bit about the initial production rates you're seeing there and do you plan to increase activity on this property?

Drilled the three wells in the first quarter, as you mentioned, and we've just completed drilling a fifth well. The first three wells are on production tests now and we're extremely pleased with the results. We've drilled one well in each of three units meaning we proved up additional pud locations in each of those three units. Production rates from those three wells range from 1.4 million a day to 2.2 million a day on an IP basis, so performance is excellent. We are getting a number of additional pud locations permitted as we speak in addition to those that we've already got on the board targeted for 2006 in preparing for 2007 ramp up in that region with the additional rigs that we're going to have. We've got an excellent acreage position. We're excited about the west Douglas area.

So the initial production rate, I remember the first well was significantly higher. I think it was 2.5 per day.

Yes, it was.

And you guys were doing extra fracking and everything. Are you doing that on these other wells as well?

Yes, we are.

And you plan to increase activity further or you're going to stay with what you've already budgeted for the year?

Well, right now we want to drill additional wells in other units to firm up the area and get a strategic program for the latter part of '06 going into '07. So right now we're staying with the established program for '06.

[Operator Instructions] We have a follow-up question from Paul Childs from Steadfast Financial.

Maybe just a follow-up on Rehan's point on the hedging in terms of you do see some very robust prices on cost of callers in 2007. Would it make some sense to bare some of those on even at sort of 10 to 15% of production, just sort of protect some level of cash flow?

Well, I think, Paul, one thing you have to look is those are very robust prices on a NYMEX basis.

Right.

And the NYMEX has proven over the last period has not been a very good-- has diverged itself from what we really can sell gas for and just like our costless caller now, which is half Houston Ship Channel and half NYMEX, that NYMEX part was not indicative of what we were receiving, so I don't think it really-- if you try to get those type of callers with the basis differential they're not that robust looking and--

For Houston Ship Channel?

Yes.

For your production?

For our production or where this-- and so what happens is, yes, it's really artificial looking-- those hedges may work out and they may not. It's just a lot of derivative risk and so we already look at that as a great option to protecting this production because it may or may not track NYMEX's and that's what the last six months have proven. Companies have thought they were protecting their production and they weren't. We paid out $700,000 on our hedge position and didn't receive that at the wellhead because of that dislocation between NYMEX and the real physical gas market.

So your ability-- The basis of the ability to hedge the basis is much--?

Much is not near as attractive as what you're seeing on the screen for NYMEX hedges. In the long-term there's just not the liquidity in the specific index market, nor are people willing to take the risk because they are not-- the best gas marketers can't predict what's going to happen at these at these different locations. It's been very difficult to follow.

All right, that makes sense. Thanks.

We have no further questions at this time.

All right, Rose, thank you. Thanks, everyone, for staying with us for a full hour. I mean it's been quite a year, as we said on the bois d'Arc conference call earlier, it is a year ago this afternoon that we priced the IPO, so that company has changed materially and so has Comstock. And, again, we all thank you for listening to the call and listening to the performance.

Thank you, ladies and gentlemen. This concludes the first quarter financial results conference call. Thank you, for participating, you may all disconnect.