Comstock Resources Inc (CRK) 2006 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth quarter 2006 Comstock Resources Incorporated earnings conference call. [OPERATOR INSTRUCTIONS] As a reminder this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Jay Allison, President and Chief Executive Officer. Please proceed.

Thank you. A lot of you probably just got off the 9:00 conference call which is a Bois d'Arc call where they reported a record year of production and earnings, so we got quite a few people joining after that call, so welcome to the Comstock Resources fourth quarter and year-end 2006 financial and operating results conference call. You can view a slide presentation during this call by going to our website at www.Comstockresources.com and clicking presentations. There, you will find a presentation entitled--fourth quarter 2006 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, I will review our 2006 fourth quarter and annual 2006 financial and operating results as well as the results of our 2006 drilling program. Our discussions today will include forward-looking statements within the meaning of securities laws, where we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

We turned in solid financial results in 2006. We had total revenues of of 512 million, and we generated EBITDAX of $387 million and operating cash flow of $349 million. We also generated a profit of $65 million or $1.48 per share, excluding an unrealized gain on derivatives, and a one-time provision for a new business tax in Texas which were reflected in the reported earnings of $71 million or $1.61 per share. The strong financial results in 2006 were driven by production growth that we achieved which helped offset the lower natural gas prices that we experienced in 2006. Our onshore production increased by 8% and our offshore production is up 44% in 2006 as compared to 2005.

Our onshore drilling program had a 95% success rate. 116 of the 122 wells we drilled were successful and added 82 Bcfe approved reserves. At Bois d'Arc, we drilled 13 wells with 10 successes and 3 dry holes for a success rate of 77% including two high impact wells, the Sockeye and Steelhead wells. These discoveries added 45 Bcfe approved reserves and an additional 42 Bcfe of probable reserves. We also completed two strategic acquisitions in 2006 which added 23 Bcfe of proved reserves at a cost of $3.48 per Mcfe. In the third quarter of 2006, we acquired additional shares of Bois d'Arc Energy which requires us to change our accounting method for our investment in Bois d'Arc, as a result, Bois d'Arc's results are now consolidated retroactive to the beginning of 2006.

On slide three, we outlined our daily production rate by quarter and by region for 2005 and 2006. Our onshore production averaged 101 million cubic feet equivalent per day in the fourth quarter as compared to to the 95 million per day we averaged in the third quarter and the 100 million per day we averaged in the fourth quarter of 2005. Our offshore production averaged 97 million cubic feet equivalent in the fourth quarter as compared to to the 91 million per day we averaged in the third quarter and the 48 million per day we averaged in the fourth quarter of 2005. With our 2007 onshore and offshore drilling programs, we expect our 2007 production to be between 76 and 80 Bcfe as compared to the 67 Bcfe we produced in 2006.

On slide four, we cover our oil prices. Our average oil price increased less than 1% in the fourth quarter of 2006 to $54.51 per barrel as compared to $54.36 per barrel in the fourth quarter of 2005. Our average oil price in the fourth quarter was 91% of the average NYMEX WTI price. For all of 2006, our realized royal price was $60.93 which was up 18% from our oil price of $51.50 in 2005. In 2006, our average oil price was 92% of the average NYMEX WTI price.

Slide five illustrates our average gas price. Our average gas price decreased 40% in the fourth quarter to $6.47 per Mcf as compared to $10.75 in the fourth quarter of 2005. Our realized gas price was 99% of the average Henry Hub NYMEX price in the fourth quarter. For all of 2006, our average gas price decreased 14% to $6.95 per Mcf as compared to $8.06 in 2005. Our realized gas price averaged 96% of the average Henry Hub NYMEX price in 2006.

On slide six, we compare our 2006 oil and gas sales to pro forma 2005 sales assuming Bois d'Arc was consolidated. Higher production helped offset the impact of lower gas prices in 2006 due to the 40% drop in natural gas prices, our oil and gas revenues decreased 11% to $127 million as compared to pro forma consolidated sales of $142 million for the fourth quarter of 2005. Offshore sales increased 36% to $ 66 million from $49 million in 2005's fourth quarter. Our onshore sales were down 35% to $61 million in the quarter as compared to $93 million in 2005's fourth quarter. For all of 2006, our oil and gas sales increased 14% to $512 million as compared to $449 million in 2005. Offshore sales increased 38% to $255 million in 2006 from $184 million in 2005. Onshore sales decreased 3% to $257 million as compared to $265 million in 2005.

As shown on slide seven, our earnings before interest, taxes, depreciation, amortization, exploration expense and other non-cash expense or EBITDAX decreased 14% in the fourth quarter to $93 million as compared to $107 million in last year's third quarter. Onshore operations contributed $43 million of the EBITDAX and Bois d'Arc contributed $50 million. For all of 2006, our EBITDAX increased 10% to $387 million as compared to $352 million in 2005. Onshore operations contributed $190 million and Bois d'Arc contributed $197 million to the consolidated EBITDAX.

On slide eight, we cover our operating cash flow. Our consolidated operating cash flow decreased 18% this quarter to $81 million as compared to $98 million in 2005's fourth quarter. Onshore operations accounted for $31 million and Bois d'Arc accounted for $45 million of the consolidated cash flow in the fourth quarter of 2006. For all of 2006, our operating cash flow was $349 million, 11% higher than cash flow in 2005 of $313 million. Onshore operations accounted for $168 million in Bois d'Arc accounted for $181 million of the consolidated cash flow in 2006.

On slide nine, we outline our earnings. Excluding our mark-to-market gains or losses from our derivatives, we reported net income of $9 million or $0.20 per share for the fourth quarter of 2006 as compared to net income of $36 million in the fourth quarter of 2005 or $0.82 per share. For the year-ended December 31, of 2006, our earnings were $65 million or $1.48 per share as compared to to 91 million or $2.21 per share in 2005. These results exclude gains or losses from our derivatives and a provision for a new Texas business tax. We have also adjusted the 2005 results presented on this slide to exclude the unrealized gains and losses on derivatives and the one-time effect of Bois d'Arc's conversion from a Limited Liability Company to a taxable Corporation and a gain from its IPO in May of 2005.

We outline our cost structure on slide ten. Our lifting cost in the fourth quarter averaged $1.60 per Mcfe as compared to $1.97 in the fourth quarter of 2005. The lower rate is primarily due to the deferred production we had in the fourth quarter of 2005 related to the 2005 hurricanes. Our depreciation, depletion, and amortization per Mcfe produced increased to $2.71 per Mcfe in the fourth quarter as compared to $1.82 per Mcfe in 2005's fourth quarter. The higher rate is a result of the higher finding costs we've experienced both at Bois d'Arc and in our east Texas north Louisiana region.

For all of 2006, our lifting cost per Mcfe produced is $1.59 per Mcfe as shown on slide 11 compared to $1.48 in 2005. Our depreciation, depletion, and amortization per Mcfe produced increased to $2.28 per Mcfe as compared to $1.74 per Mcfe in 2005.

On slide 12, you can see our capital structure at the end of 2006. At the end of 2006, we had $455 million in debt, including $100 million of debt at Bois d'Arc Energy, our equity at the end of fourth quarter was up to $683 million. Our debt to total book capitalization of 40% illustrates the strong balance sheet that we have. Our borrowing basic Comstock was just increased to $400 million giving us availability of $220 million at the end of 2006.

On slide 13, we outline our exploration and development cost in 2006 as compared to what we spent in 2005. We spent $228 million in 2006 on our onshore properties as compared to the $122 million that we spent in 2005. We spent $188 million to drill 117 onshore development wells, 113 of which were successful. We spent an additional $21 million for work overs and recompletions and other development cost. We spent $8 million to drill five exploratory wells, three of which were successful. We also spent $11 million on acquiring leases and seismic data, [$160] million was spent on our east Texas/north Louisiana drilling program. $24 million in south Texas, and $39 million was spent in our other regions.

Offshore, we spent spent 230 million in 2006 on exploration and development activities as compared to $202 million in 2005. We drilled 13 wells, 11.2 net to our interest. All but three of these were successful. We spent 152 million on drilling and completion costs for these wells. We also spent $51 million on new production facilities and $20 million on recompletions and abandonment work and $7 million on acquiring new leases and 3D seismic data.

We have budgeted $278 million for our 2007 onshore drilling program as detailed on slide 14. Development projects comprise $250 million of the 2007 budget and $28 million is allocated to exploration activities. We expect to drill approximately 170 onshore wells including 158 development wells and 12 exploratory wells. Our east Texas/north Louisiana operating region had $175 million accounts for 63% of the 2007 budget. We have budgeted to drill 116 development wells in this region this year. We expect to spend $56 million in our south Texas region to drill 21 wells which represents 20% of the budget. Included in the south Texas totals are 13 development wells and eight exploration wells. We have also budgeted $45 million to drill 14 development wells and four exploration wells on our Mississippi properties in 2007. The remaining $2 million will be spent in other regions. We currently have nine drilling rigs contracted for our 2007 onshore operated drilling activities which will be adequate to complete this work.

Slide 15. We drilled 88 wells in our east Texas/north Louisiana region in 12 different fields in 2006. All but two of these were successful. These wells have been tested at a per well average rate of 1.4 million feet equivalent per day. Our drilling in this region primarily targets the Cotton Valley formation and we were able to add 59 Bcfe of new proved reserves in 2006. The drilling activity also allowed us to increase our production in this region in 2006 by 26% from 2005. This year, we plan to drill 116 development wells in this region with the seven drilling rigs that we currently have working in the region.

We cover our south Texas region on slide 16. In our south Texas region, Comstock drilled ten successful wells in 2006. These wells have been tested at a per well average rate of of 5.6 million cubic feet equivalent per day. These wells were drilled in our Ball Ranch, Javelina, and our recently acquired Las Hermanitas fields and our drilling in this region added 19 billion cubic feet equivalent of new proved reserves in 2006. This year, we plan to drill 21 wells in the region.

Slide 17, at the end of the third quarter, we completed the acquisition of the Las Hermanitas field in south Texas and we drilled two wells in this field during the fourth quarter. We paid $67 million for three producing wells in 18 drilling locations. As a result of the acquisition and our subsequent drilling, we now have proved reserves of 25.5 Bcfe in this field and an additional 27.6 Bcfe of probable and possible reserves related to ten probable and possible drilling locations.

We drilled 24 wells in our other regions during 2006 as shown on slide 18. Seven of the wells drilled were coalbed methane wells in the San Juan Basin in New Mexico. All but one of these were successful. These wells have been tested at a per well average rate of 0.9 million cubic feet equivalent per day. We drilled 11 wells in Mississippi. Nine of the 11 were successful and two were dry holes. These wells have been tested at a per well average rate of a 153 barrels of oil per day. We also drilled six successful wells in Arkansas and Oklahoma. All but one of these were successful. This year, we plan to drill 18 wells in Mississippi and 15 wells in our other fields.

Slide 19. Bois d'Arc had very good results in 2006 from its exploration program as displayed on slide 19. They drilled ten successful wells out of a total of 13 wells drilled with three dry holes and achieved a 77% success rate. The largest discoveries made in 2006 included a well drilled at South Pelto 22 which proved up our Sockeye prospect and a discovery at Ship Shoal Block 111 which proved up our Steelhead prospect. During the fourth quarter of 2006, Bois d'Arc drilled two successful exploratory wells at Ship Shoal 166 and at South Timberlier 100.

Slide 20. Bois d'Arc plans to spend $200 million on its exploration and development activities this year. This year, they plan to drill two of their deep shelf Desperado prospects and expand to deepwater by participating in three deepwater projects, the ultra deep project Calamity Jane will be postponed until 2008. The revised budget will include $102 million to drill 15 offshore wells, an additional $67 million has been budgeted for completion an facility cost related to these wells. In addition, Bois d'Arc plans to spend $20 million on acquiring seismic data and acreage and $11 million for recompletions and for abandonment work this year. Seven of the wells in the 2007 drilling program will be drilled deeper than 15,000' all will be drilled in ultra or in deepwaters to test high potential exploration prospects. We believe that this program will expose us to over 90 Bcfe of reserve additions on a risk adjusted basis.

Slide 21. At the end of 2006, the total consolidated proved oil and natural gas reserves are estimated at 657 Bcf of natural gas and 32 million barrels of crude oil or 851 Bcfe as compared to pro forma consolidated reserves at the end of 2005 of 828 Bcfe. Our reserves are 77% natural gas, 23% oil, 66% of our reserves were developed and 34% are undeveloped. We operate 86% of our proved reserve base, 60% of the proved reserves relate to our onshore properties and 40% relate to Bois d'Arc energy. The present value using a 10% discount rate as a future net cash flow before income taxes of our proved reserves is approximately $2.3 billion using our actual December 31, 2006, oil and natural gas prices of 56.17 per barrel for oil and $5.70 per Mcf for natural gas.

The minority interest in Bois d'Arc's proved oil and gas reserves not owned by Comstock is 174 Bcf with a present value of $666 million. We replaced 135% of our 2006 consolidated production of 67 Bcfe in 2006. We added approximately 149 Bcfe of new proved oil and natural gas reserves. Acquisitions accounted for 23 Bcf of the additions with discoveries and extensions adding 126 Bcfe. Approximately 97 Bcfe of the additions were onshore and 52 Bcfe were added by Bois d'Arc.

Onshore, we acquired 16 Bcfe with discoveries and extensions adding 81 Bcfe. Bois d'Arc acquired 7 Bcfe and discovered 45 Bcfe of proved reserves and an additional 42 Bcf of probable reserves. These reserve gains were partially offset by the 59 Bcfe of downward revisions on last year's reserve base. 22 Bcfe of the revisions were due to the lower natural gas prices used and the determination of the proved reserves in accordance with the rules with the SEC. Our average realized natural gas price at the end of 2006 had fallen to $5.70 per Mcf as compared to $8.89 on the last day of 2005. The remaining revisions were performance related and were a result of lower per well assignments made by independent reserve engineers on our recently drilled and undrilled Cotton Valley wells.

Slide 22. Comstock, in 2006, had its second most profitable year in its corporate history. We are very excited about the prospects for the Company. Slide 22 outlines our outlook for this year. We expect to spend $278 million on our onshore drilling program this year which is a 22% increase from $228 million we spent on our onshore drilling program in 2006. The Cotton Valley and south Texas drilling program will be the major driver for our onshore production growth this year. We have over 400 operated low risk drill sites to support our continued drill bit growth in future years. Bois d'Arc Energy continues to build value since we formed it in 2004 and has a strong outlook for reserves and production growth this year. We continued to maintain a very strong balance sheet. Our consolidated debt is only 40% of our total capitalization, giving us a strong balance sheet to support future growth. I'll now open it up for questions.

Thank you, sir. [OPERATOR INSTRUCTIONS] Your first question will come from the line of Wayne Andrews representing Raymond James. Please proceed.

Good morning, gentlemen. Quick question. I think this one probably applies mostly to Roland and I was hoping you could just give us some commentary on how the downward reserve revision may have impacted your DD&A rate and is that -- is there more in the fourth quarter to adjust for the previous three quarters and how might that rate be going forward and then also comment on the higher tax rate in the fourth quarter also.

Okay, thanks, Wayne. Yes, the reserve revisions in the lower reserve assignments in both price related and also related to the lower assignments did have an impact on the DD&A rate in the fourth quarter. It is a stand alone quarter calculation, so you don't go back and recalculate for the previous quarters. It's also a function of more successful efforts versus full costs so it's also a function of really what the proved developed reserves are because our drilling cost is really amortized over just the developed reserves and undeveloped reserves, you can only amortize just the cost of leases.

Right.

Or lease holds. So I think it's a combination of the lower reserve assignments to the developed reserves and the higher drilling costs we had that drove up the rate especially in the east Texas region and the other area, so we would -- until we have a new reserve estimates, we would continue to use those rates going into 2007.

Okay, and then how about on the tax rate in the fourth quarter?

Yes, the tax rate in the fourth quarter was a function of having a lower net income in the quarter than what would have been estimated just based on expected performance and what happens is the permanent differences for under income tax accounting are factored into the different quarters, kind of based on what you expect for the whole year and since earnings were lower in the fourth quarter, you had to true that up and so that rate is not indicative of anything other than a lower amount of income in the fourth quarter versus the previous quarter so the total rate for the year would be more indicative of what we really achieved but the fourth quarter is a trueup.

That's helpful and obviously it explains some of the earnings that we saw during the fourth quarter. And maybe I can Get Jay, if you could comment a little bit. I think you had mentioned you had seven rigs now drilling in east Texas and are those rigs living up to the expectations that you had hoped for? And then you also mentioned that you continue to have about 400 drill sites which is about the same way as you were last year so it probably looks like you've added additional identified projects and still have a relatively high number of wells to drill for the future. Maybe you could comment just on the rigs and potential drill sites?

Let me, Wayne, if you don't mind, let me turn it over to Mack.

Great.

And let him fill you in on the rigs and the contract rate for the rigs and what we plan on doing with the rigs in all of '07 and the impact of '06. Is that fine?

Excellent.

Good morning, Wayne. We have the seven rigs running currently in the ArkLaTex region and plan to continue doing so. We've got two rigs working currently in Mississippi drilling in a couple of fields there and they will be there for the next couple of months and then we'll make a determination about where we want to send those rigs. We're currently drilling with one rig in Hermanitas and when it finishes the well its drilling, we're going to release that rig and evaluate production performance for the next 45 to 60 days and then look at contracting a rig to come in and drill another package of wells in Hermanitas for us based on the results and the evaluations. So the performance of the rigs are, of course, you always have problems but they are generally meeting expectations. We have, during the last two months, released one rig and replaced it with a better performing lower cost rig. We were able to do that based on contract.

Great. And then maybe just comment on number of identified Cotton Valley locations and any thoughts on -- you've mentioned the potential for drilling horizontal wells and how is that looking?

Yes, sir. We have a good inventory of Cotton Valley locations. It's changing all the time as we drill, we prove up additional locations and convert possibles and probables. The horizontal effort, we've conducted some reservoir evaluation tests and one of them our east Texas fields, we thought it was prudent to make a determination whether or not the horizontal drilling technology and completion technology was warranted in this particular field. Preliminary results are encouraging. We're about three weeks out, basically from getting the final evaluation of those tests and designing a frac that would optimize production so while we're looking really hard at the horizontal technology and the application that it has in several of our east Texas fields and the first rattle out of the box is our evaluation of one of them, via some fairly sophisticated reservoir analysis that we've done.

And Wayne, would you like for Mack to go over what we're actually doing to determine whether we drill a horizontal well?

I think that would be of interest to most listeners. That would be great.

I'd be happy to do that. We conducted some microseismic frac evaluation work in two wells in east Texas. We had a monitoring well that we shut in and dropped a geophone ray in that monitoring well. We frac'd one well on the first well on day one and measured the azimuth and direction of frac growth and height in that well, based on the perforated interval and then we, on the second day, frac'd the second well and conducted the same measurements, the idea being to determine not only fracture orientation for well spacing requirements. We don't want to put well location on the same axis as the frac growth orientation. That would cause an issue with depletion and interference, et cetera, so we want to offset those locations, so we got really excellent data qualities for that purpose.

We also evaluated frac height/growth because it's imperative in a horizontal well board, as you know, Wayne, to frac multiple stages and to ensure that you get frac height growth off that horizontal axis in order to communicate with the reservoir both above and below the horizontal well bore, and we found again that excellent frac heights growth was occurring and we could communicate the net pay that we've identified in this particular area with fracs off a horizontal well. The third part of the effort is the effort that we're currently conducting and that is to model different frac designs and reservoir properties in order to evaluate the performance of that well, and so the end of the road here is to look at the model performance based on all of the data and the frac design, et cetera, and to develop an economic forecast for the amount of dollars spent and what kind of reserve capture we think we can gain from that effort, so that's where we are. A number of Operators, not the least of which, Devon has done similar tests. We're certainly not doing anything new but we think it's obviously a prudent approach to take in determining the feasibility and the economics of a horizontal effort.

That's excellent. Sounds like you're doing all the necessary work that you need and it sounds like results that you're getting are encouraging to date and we look forward to hearing some additional success from that horizontal program.

Thanks, Wayne.

Thanks for your time.

Yes, sir.

Thank you, Wayne.

[OPERATOR INSTRUCTIONS] Your next question will come from the line of Ron Mills Representing Johnson Rice. Please proceed.

Good morning, this is actually [Clay Cummings]. Roland, if we could just start with you, just curious as to additional cost guidance, if we could look at kind of the lifting costs and your absolute expectations for '07?

Sure. If you look at the -- at the lifting cost, we expect the total consolidated lifting cost to be about in that $1.50 to $1.60 per Mcfe range. It's a little higher rate with the offshore properties.

Yes.

And about $0.10 lower with the onshore properties. Anyhow, we would expect that the lifting cost rate would be, the lifting cost, which are generally fixed, would be pretty comparable this quarter, will be a good indication of what we would expect next year, because since all of the acquisitions we made were in there for the full quarter, all their costs are in there and then the rate may come down though as we see production increase, because the production increases are coming from increased drilling mainly on the same fields.

Okay, and the deferred tax. It looked like, and this may be a component of that variance in the tax rate in the fourth quarter, but it looked like it was more like a 92% or a little higher than we were modeling. Is that something that we should kind of carry forward through 2007?

As far as a portion of the total tax provision that we recorded in the fourth quarter of that was deferred, it was 11.6 million for the quarter and then 66.7 million for the year, and I think that percentage being a higher percentage was more of a function of trueing up kind of the year, because we would do the lower net income in the fourth quarter, because we expected to make a little more overall, we expected to have a little higher current taxes, so given the lower income that we're going to have both for book and tax purposes, that's really that function. So really, we still go back to saying the deferred portion of the tax provision will be closer to potentially 80% in 2007.

Okay.

A lot, of course, depends on gas prices and a lot of factors, so that's -- our level of drilling is what's keeping a lot of those taxes deferred because we can deduct IDC, and so that's a big factor, so the relationship of that to the total revenues is a big factor on how that really gets determined. So it can move around a lot.

Yes. Just another comment or question on the reserve revisions that you experienced in the Cotton Valley. Did you have any further discussions with the reserve engineers as to kind of a point to, obviously it doesn't look like the IP rates are any different than I think you guys were expecting. Is there anything that they can point to to kind of guide you guys to why they made the decision, other than just being conservative? Was it something regarding the decline rates or a lower sustained rate on these wells versus other surrounding wells?

This is Mack. Yes, we've had a number of conversations with those guys and you're right. We do think that a number of the forecasts were conservative, but overall, our strong ArkLaTex acreage position coupled with our strong balance sheet allowed and required that we evaluate some of our less developed fields and looking at areas where we would step out away from established production and we found that in a number of those instances that we would have IP rates that certainly were matching expectations at one 1.4 million a day on average but the declines were somewhat more severe suggesting tighter rock, so as we stepped significantly away from established production and found those sharper declines, keeping in mind that a lot of wells were drilled in '06 during the last half of the year and the majority of those drilled in the fourth quarter, so we're looking at a fairly short production history on a number of those wells and the declines being steeper in that tighter rock, the reserve engineers gave us the steeper decline forecast, and so the consequence of that in our ArkLaTex Cotton Valley region was such that we had some puds that were given lower assignments, et cetera, and now we think that's an extremely conservative forecast. The adjustments we think will be forthcoming down the road, but we live with the audited forecast as they stand right now.

Okay.

Clay, one thing, I think this is correct, Mack, most of our wells are on 80s and some are on 40s but I don't think we have any fields that are down spaced to 20s is that right , Mack?

That's correct.

So the engineering is based upon 80 acre and some 40 acre spacing but no fields on 20s.

Okay.

So there's a lot of wriggle room for us there.

And can you--?

Acreage positions, at Douglas and Oak Hill, and others.

Right. Can you speak to where those wells were that you drilled that had the higher or steeper decline curves?

A lot of them were -- several of them were drilled in our central Louisiana fields that we purchased from insight and they were evaluative wells. We also drilled some step out wells in Blocker and we also drilled a few of them in Oak Hill.

Okay. Great, guys. Thank you very much.

Thank you, Ron.

There are no further questions at this time. I would now like to turn the presentation back over to Mr. Jay Allison for closing remarks.

Thank you. We, again, think the Company has been around for 18 or 20 years. We did have the second best year ever and quite frankly, management thought that we should have had the best year ever. We're going to work harder in 2007 and implement the program better. We're trying to stay consistent with our accounting which is a consolidated accounting format so you can understand what we've been doing. Again, we have no hedges, so our numbers will fluctuate based upon whatever the price of the commodity is. We've continued to increase our production in east Texas. It went up 26% this year, and it should go up more than that in '07 and a lot of you, again, were on the conference call at 9:00 with the Bois d'Arc management. It's been a great success story. We're glad that we control a little over half of it and we're exposed to about 90 Bcfe of reserves there through the drill bit and those reserves hopefully will be discovered just based on the use of free cash flow with no additional debt and then on the Bois d'Arc side, there's about 1.8 Tcfe of upside on 39 prospects that's in inventory so we're going to try to blend them together and grow the Company and we're thankful for your participation.

Thank you for your participation in today's conference. This concludes your presentation. You may now disconnect. Have a good day.