Comstock Resources, Inc. (CRK) Q4 2010 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to Fourth Quarter 2010 Comstock Resources Earnings Conference Call. My name is Carmen and I'll be your coordinator for today. [Operator Instructions] I would now like to turn the call over to your host for today, Mr. Jay Allison, Chairman, CEO and President. Please proceed.

Carmen, thank you. I want to welcome everybody to the Comstock Resources Fourth Quarter 2010 Financial and Operating Results Conference Call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and clicking Presentations. There you'll find a presentation entitled Fourth Quarter 2010 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 2010 fourth quarter and 2010 annual financial and operating results, as well as updated results of our 2011 drilling program and our outlook for this year. If you'll turn to Slide 2, please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. On Slide 3, we have our 2010 highlights. Please refer to Page 3 of the presentation where we will summarize our 2010 results. Continued low natural gas prices created a difficult backdrop for the company in 2010. With higher production and slightly stronger natural gas prices, we were able to grow our oil and gas sales, 19% to $349 million and we generated EBITDAX of $249 million and operating cash flow of $220 million or $4.66 per share. We reported a net loss of $20 million or $0.43 per share for 2010, an improvement from the net loss we had in 2009 of $36 million. Most of 2010's loss was due to a $17 million after tax loss we recognized from the sale of our Mississippi properties that we closed in the fourth quarter. Without that loss, we would have been very, very close to a breakeven year. Despite the financial results, we had a very successful year with the drill bit. We drilled 78 successful wells in 2010, all but two were horizontal wells and 72 were Haynesville or Bossier Shale wells. Our drilling program grew our proved reserve base by 45%, as we added 431 Bcfe of proved reserves at a very attractive all-in finding cost $1.26 per Mcfe. The Haynesville program accounted for 402 Bcfe of new reserves at a finding cost of $1.01 per Mcfe. The drilling program provided 12% production growth in 2010. Our production growth was stymied in the second half of 2010 due to limited access to frac services. As a result, more than half the wells we drilled in 2010 were not completed and will be carried over to 2011. And lastly, we're maintaining our strong balance sheet and liquidity position despite the low natural gas price environment that we are currently in. I'll turn it over to Roland to review our financial results in more detail. Roland?

Thanks, Jay. On Slide 4, we break out our production by quarter and by each of our operating regions, and we highlight the production from the Haynesville shale wells in red. In the fourth quarter of 2010, our production averaged 188 million cubic feet of natural gas equivalent per day, which is just slightly higher than our production in the third quarter of 2010. Haynesville production increased to 94 million per day, as compared to 84 million per day in the prior quarter. Much of that gain, however, was offset by lower production from our other properties. We had 46 million coming from our Cotton Valley wells, 37 million from our South Texas region and 6 million from our other regions. We also had another 5 million a day related to our Mississippi properties which were sold on December 10 and which will no longer be part of our production in the first quarter of 2011. Production in the quarter was adversely impacted by the shut-in of producing wells for mechanical repairs and the new practice of shutting in producing Haynesville wells, while wells nearby are being fraced. The impact of these shut-ins was approximately 5 million a day to our average rate in the fourth quarter. Our production at the end of January was running around 207 million per day. However, in early February, there have been a number of production interruptions due to pipeline or plant downtime due to the extreme cold weather that we had last week. We do expect production in 2011 to approximate 85 to 90 Bcfe, which would represent a 16% to 23% growth over our 2010 production. And it would be up to a 27% increase if you exclude the production from the properties that we sold in 2010. On Slide 5, we show our average natural gas price. Our average gas price declined 16% in the fourth quarter, to $3.73 per Mcf as compared to $4.43 in the fourth quarter of 2009. For all of 2010, our average gas price increased 5% to $4.35 per Mcf as compared to $4.16 per Mcf in 2009. Our realized gas prices averaged about 99% of the NYMEX Henry Hub gas price in 2010. We did have 9% of our gas production hedged in 2009 and none of our production was hedged in 2010. Our realized oil prices are shown on Slide 6. Our realized average oil price increased 15% in the fourth quarter of 2010 to $74.75 per barrel as compared to $64.76 per barrel in 2009. For all of 2010, our average oil price was $68.35, which was 34% higher than our average oil price of $50.94 in 2009. Our realized oil price averaged 86% of the average benchmark NYMEX WTI price in 2010. This discount to the NYMEX WTI will improve this year with the divestiture of our Mississippi properties. On Slide 7, we cover our oil and gas sales. Weaker natural gas prices and lower production caused our sales to decline by 21% to $73 million for the fourth quarter. For all of 2010, our sales increased 19% over 2009 to $349 million due to the 12% increase in production that we had and the improvement in natural gas prices. Our earnings before interest taxes, depreciation, amortization of exploration expense and other non-cash expenses, or EBITDAX, also decreased in the fourth quarter by 20% to $51 million as shown on Slide 8. For the full year in 2010, EBITDAX increased 25% over 2009 to $249 million. Slide 9 covers our operating cash flow. Our operating cash flow for the quarter came in at $45 million, which was 34% lower than cash flow of $68 million in the 2009 fourth quarter. However, the cash flow number in 2009 included the current benefit from income taxes of $11 million. For all of 2010, operating cash flow was $220 million, 2% lower than cash flow of $224 million for all of 2009. The 2010 cash flow was up 21% from 2009, if you exclude the $42 million in current income tax benefit that was included in the reported 2009 number. On Slide 10, we outline our earnings. We reported a net loss of $20.6 million or $0.45 per share compared to a net loss of $6.8 million or $0.15 per share in 2009's fourth quarter. The loss was mostly related to the after-tax loss we recorded on the sale of our Mississippi properties of $16.8 million or $0.37 per share. Excluding the loss, the fourth quarter would have been around $3.8 million or $0.08 per share. In the fourth quarter, we also had the benefit of a $7 million after-tax gain, which is $0.15 per share on the sale of 1 million shares of our Stone Energy stock. For the full year 2010, we reported a net loss of $19.6 million, or $0.43 per share, as compared to a net loss in 2009 of $36.5 million or $0.81 per share. Again, the loss on the property sale accounted for most of the net loss. Without the divestiture, we would have reported a net loss of $2.8 million or $0.06 per share. The 2010 annual results include total after-tax gains from the sale of $1.5 million shares of our Stone Energy stock, up $10.7 million, which would equate to $0.24 per share. On Slide 11, we show our lifting cost per Mcfe produced by quarter. We have broken out our lifting cost in three components: production taxes, transportation cost and other field level operating cost. Our total lifting cost averaged $1.02 per Mcfe produced in the fourth quarter of 2010 as compared to $1.07 in the fourth quarter of 2009 and $1.17 in the prior third quarter of 2010. The decreased rate in the quarter was mostly due to lower production taxes. Most of our Haynesville Shale wells qualify for exemptions from Louisiana severance taxes. With many of these wells coming online in 2011, we expect to continue to have a very low production tax rate for all of 2011. Our field operating cost averaged $0.71 this quarter, an improvement from the $0.75 per unit produced in the third quarter. With the sale of our higher operating cost Mississippi properties and the continued benefit of low production taxes, combined with higher production levels expected for this year, we expect our lifting cost per Mcfe produced to be below $1 in 2011. On Slide 12, we show our cash G&A expense per Mcfe produced by quarter, which excludes stock-based compensation. Our general administrative cost averaged $0.23 per Mcfe produced in the fourth quarter of 2010 as compared to $0.34 in the fourth quarter of 2009 and $0.29 in the third quarter of 2010. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 13. Our DD&A rate in the fourth quarter averaged $2.91 per Mcfe, an improvement from the $3.21 rate we had in the fourth quarter of 2009. The Haynesville shale reserve additions that we had in 2010 caused the lower DD&A rate. On Slide 14, we detail our capital expenditures for 2010. We spent $396 million for our drilling activities in 2010 as compared to $317 million that we spent in 2009. We spent most of that, $356 million, in our East Texas/North Louisiana region with $40 million in our South Texas and other regions. We also spent $138 million to acquire acreage in 2010. $56 million was spent to acquire over 5,000 additional net acres respected for the Haynesville and Bossier Shale in North Louisiana, and we also spent $82 million to acquire 18,000 net acres in the emerging Eagle Ford Shale in South Texas. Referring to Slide 15, we completed the previously announced sale of our oil and gas properties located in Mississippi on December 10. The sales price was $75 million in cash, with an effective date of July 1. Net production from the properties we sold averaged 1,300 barrels of oil equivalent per day, and the proved reserves we sold were 4.7 million barrels of oil equivalent. We recognized a net loss, after income taxes, of $16.8 million on this divestiture. Slide 16 outlines our capital structure at the end of 2010. At the end of last year, we had $1 million in cash and $85 million in value of our marketable securities, which represents 3.8 million shares of Stone Energy. We had $45 million outstanding on our bank credit facility, which has a borrowing base of $500 million. We also had $172 million of our 6.78% senior notes and $296 million of our 8.38% senior notes outstanding, for a total debt of $513 million. Our book equity at the end of the quarter was $1.1 billion, making our net debt only 27% of our total capitalization. I'll now turn it over to Mack Good to review our proved reserves at the end of 2010 and the results of our 2010 drilling program.

Thanks, Roland, and good morning, everyone. We have a slide on our proved reserves and finding costs on Page 17 of the presentation. Our proved reserves, as you can see, at the end of 2010 were estimated to be almost 1.1 Tcfe compared to the 726 Bcfe at the end of 2009. Our reserves composition are 98% natural gas and we operate 92% of the total reserve base; 50% of our reserves are proved developed. Our 2010 drilling program increased our proved reserve base by 45% and replaced 582% of our production. We produced 73 Bcfe of reserves in 2010 and divested 28 Bcfe from the sale of our Mississippi assets. Our drilling program added 431 Bcfe of reserves with 402 Bcfe of those reserves related to our Haynesville shale wells. We had a small downward revision of 4 Bcfe and we eliminated approximately 20 Bcfe of undeveloped reserves that we estimate will not be drilled within five years of their booking. Most of the impact of the undeveloped reserves were offset by upward performance revisions to our developed reserves. We also used very conservative assumptions for our undeveloped reserve booking. We have no more than two undeveloped locations for any of our drilled wells and we have no undeveloped reserves that will not be developed within five years. We also used conservative EURs for the undeveloped wells, which we estimate to be between 20% to 25% less than what we expect to recover, based on our assessment. Our drilling program delivered excellent finding cost in 2010, even with these conservative assumptions. We spent $537 million in 2010 on exploration and development activities, which added 427 Bcfe to our proved reserve base, resulting in a finding cost of $1.26 per Mcfe. If you exclude the $135 million that we spent on unevaluated leases on 2010, the finding costs improves to $0.94. The drilling program added 215 Bcfe to our proved developed reserves in 2010, which increased 32% over those additions made in 2009. And on a fully-developed basis, our finding cost in 2010 came in at $1.87 per Mcfe. On Slide 18, we focused on our East Texas/North Louisiana region. Our activity in this region is focused on developing our Haynesville and Bossier shale properties. We drilled 73 wells or 45.6 net wells in this region in seven different fields in 2010. All of those wells were successful, and 72 of them were horizontal wells. Our average IP for those wells that we completed in 2010 had a core well average initial production rate of 10.1 MMcfe per day. Many of those wells were initially produced on a choke-back rate. We are continuing to limit the initial rates on our wells in the region to around 10 million a day to maintain reservoir pressure in the wells; we believe this will help improve recovery. We show the status of the 72 Haynesville and Bossier Shale wells we drilled in 2010 on Slide 19. We completed 37 of these wells in 2010, just over half of the wells drilled. On a net well basis, we only completed 48% of the wells or 21.6 net wells with 23.4 net wells uncompleted. Looking at just the 50 operated wells, which make up 42.3 of the 45 net wells drilled in 2010, we completed 24 of them or only 48%. For the operated wells, on a net well basis, we also completed 48% of them or 20.2 net wells. Basically, rolling all of that up, we completed less than half of the wells we drilled in 2010 and this impacted our inability to meet our production goals that we set for 2010. The shortage of frac crews available to us caused this problem and that problem has been addressed on a go-forward basis this year. We have arranged for dedicated completion services that will allow us to complete the backlog of wells in the region this year. We have also contracted for dedicated completion services in the new Eagle Ford play, so we don't have the same delays in South Texas this year. On Slide 20, we show the number of days it has taken to drill the 86 operated horizontal Haynesville wells that we drilled to date. Our average drill time for all 86 wells is 37 days. The average drill time for our first five wells that we drilled in the play was 51 days compared to 32 days for our last five wells. Our most recent well set a new record for the shortest drill time, that being 21 days to TD. Our improved drill bid design and drilling program has allowed us to drill these wells very efficiently. On Slide 21, we show the number of days it has taken to connect each of our 55 operated horizontal Haynesville wells that are currently flowing to sales. Our average connect time is 109 days for all 55 wells currently flowing to sales. Our average days from spud to sales for our first five wells was 96 days compared to 135 days for our last five wells. As we work through the backlog, our wells waiting on completion, we should see this timeframe return to normal by the end of this year. Our South Texas region is displayed on Slide 22; we drilled four wells in the region during 2010. We drilled a well in our Ball Ranch field in the first quarter and we've drilled three wells on our new Eagle Ford acreage. And on Slide 22 (sic) [Slide 23], we show our holdings in the emerging Eagle Ford play in South Texas. In 2010, we acquired 18,000 net acres distributed across the play in three counties: Atascosa, McMullen and Karnes, counties in South Texas. We believe that our acreage position is very prospective for Eagle Ford development, and as a result, we have recently drilled and completed a well in each of those counties where we hold acreage. We are currently evaluating each wells' production profile after its initial completion. And so far, these wells are meeting our expectations. We drilled the NWR #1H, our first Eagle Ford well at Atascosa Country to a vertical depth of 8,706 feet with a 5,209 foot lateral. After the frac completion, this well flowed at an initial rate of 381 barrels of oil per day on a restricted rate and is currently producing to sales on a very shallow production decline. We subsequently drilled the Rancho Tres Hijos #1 well in the McMullen County to a vertical depth of 8,715 feet with a 4,091 foot lateral. After frac, this well floated at an initial rate approaching 432 barrels of oil per day. Just as with the NWR well, it too is currently producing to sales on a restricted choke and it is also on a very, very shallow production decline. We drilled our next well, the Coates #1 in Karnes County, to a vertical depth of 9,706 feet with a 5,422 foot lateral. And this well is currently flowing back frac fluids after its completion on cleanup. As you can definitely see from the above activity, we are testing our Eagle Ford acreage position just as we did with our Haynesville position. We're methodically testing each of our acreage footprints across the play. We believe that doing it this way will allow us to better prioritize our subsequent Eagle Ford drilling program, and will also allow us to optimize our well completion strategies. We are also being just as conservative as we were, and still are, on Haynesville, concerning how we produce and how we forecast the EURs for our Eagle Ford wells. But I can say that the results from our first two Eagle Ford wells that have some production history, the NWR well and the Rancho Tres Hijos well, are extremely encouraging. Based on our preliminary evaluation, we believe the EURs for these oil window wells will fall within our expected 225,000 to 300,000 barrels of oil equivalent range. We expect the condensate window wells that we are drilling and will drill, will have much higher EURs. On Slide 24, we show an overview of our 2011 drilling program. We have budgeted to drill 67 wells at a cost of $412 million. All of these wells are horizontal wells, 45 will be in the Haynesville or Bossier shale and 22 will be in the Eagle Ford shale. We also budgeted $110 million to complete the 35 wells or 23.4 net wells that are being carried over from the 2010 drilling program. Our total capital expenditures for 2011 are currently estimated at $522 million. And with all of that, I'll turn it back over to Jay.

Mack, thank you. Roland, thank you. If you would turn to Slide 25, which is our 2011 outlook, I refer to this slide. And as you listened to Roland and Mack, I really, despite the bumpy ride we had in 2010, with rising service cost and frac crews shortages, we were still able to strengthen the company as we head into 2011. We finished the year with over a Tcfe of proved reserves, with half of those developed. The strong drilling results from 2010, along with the divestiture of assets that we felt had limited growth prospects for us will improve our already stellar cost structure in 2011. I guess you can say, we're already the fourth lowest cost producer and maybe headed to the third position, and we expect our cost to continue to improve. More than half of the wells we drilled in 2010 were not completed, as Mack reported to you. Those wells will give us strong production growth in 2011, even as we reduce the number of wells that we'll be drilling in 2011. We have started developing our acreage in the Eagle Ford shale, in South Texas, methodically as Mack said. During this period of weak natural gas prices, the Eagle Ford program gives us a high return area to grow our oil condensate and natural gas liquids production in 2011. The 22 Eagle Ford wells that we hope to drill give us a chance to exit the year with 10% of our production coming from oil and condensate. We continue to manage our longer-term commitments to allow us access to the services we need for our drilling program, while at the same time, giving us flexibility to respond to stronger or weaker prices. We have reduced the rigs that we're using, from seven to five, and have the flexibility to release another one early this year. We've had to make amendments to have adequate completion services, but we maintained flexibility to reduce the exposure if prices erode. The Eagle Ford program, once it is up and running, gives us the flexibility to focus on oil, if oil prices remain strong and gas prices do not improve. We continue to maintain a very, very strong balance sheet. We have $455 million available on our bank credit facility and almost $100 million in marketable securities to supplement the cash flow we'll generate. For the rest of the call, we'll take questions from the research analysts who follow the stock. So Carmen, I'll turn it back over to you.

[Operator Instructions] And your first question comes from the line of Brian Corales from Howard Weil Incorporate.

Could you talk about where you are, currently -- your current production rate?

We said, we were -- January, we were about 207 day-to-day [ph], was kind of the company average rate. February, the first week of February, I'm not exactly sure where we were, we knew some of the plants were down and pipelines were down with freezing problems. I think this week, things are kind of back to normal.

And then switching to the Eagle Ford. What percentage of your -- or can you maybe give the breakdown of acreage between, kind of the condensate window and the oil window?

This is Mack. It's interpretive, as you know, but based on our current assessment, we believe about 3/4 of our acreage is in the condensate window and the rest, the remainder is in the oil window.

And the drilling plan for 2011, similar breakdown?

No, we're concentrating on the condensate window. We drilled a couple of wells in the oil window and we're going to be concentrating on defining, more precisely, the condensate window with our drilling. But based on the current interpretation, all the wells that we plan to drill will be in the condensate window.

The Haynesville EURs, how did that look compared to last year on a per well basis? And then, do think the bias is still kind of to the upside? Or do think it's kind of a fair number today?

No, as I mentioned in my commentary earlier, we're being very conservative. We're still evaluating the choke back or restricted rate program and the impact on EURs. But based on the preliminary analysis, we believe that the recoveries could be 20% to 25% greater than we're currently booking. So we feel we're being pretty conservative, not only with the offsets that we're booking on the PUD-side of the equation, but also on EUR. So I hope that answers your question. We continue to be somewhat conservative with our EUR assessments on our Haynesville. We'd rather add later than take them off.

And the next question comes from the line of Michael Bodino from Global Hunter Securities.

Can you give us a clue on these production rates? What your GURs [ph] look like in Eagle Ford?

The first well that we drilled in Atascosa has a very low GUR [ph], I'd say it's less than 500 Mcf, less than 500 on the GUR [ph] . That's the NWR, I'm sorry. Less than 500 on the GUR [ph] , in Atascosa. The Rancho Tres Hijos is somewhat better. It's closing in on 1,000, on the GUR [ph] .

And then you've had the McMullen County well on for, about two months now? Is that about right? Can you give us an indication of what the production profile has been thus far? You said you're on restricted rates.

Yes, we are. The well came in at over 400 barrels a day and it's still pretty close to that rate. It's about 360, 370 barrels of oil per day. And it's very flat, almost no decline at this point.

And relative to the program this year, 22 net Eagle Ford wells. Could you give us a sense of, on a quarterly basis, how you expect these things to get drilled? Is it going to be very back-end loaded? Or...

Well our current plan is to keep the one rig running until June. And as I mentioned earlier, we're going to let the results dictate where we go and how fast we go there with the second rig. And certainly, if expectations hold, it is possible that we move a third rig into the Eagle Ford play, deep third quarter, early fourth quarter. So the drill times on these Eagle Ford wells are surprisingly fast. As I mentioned and I think Roland also referred to our contracts that we have in place to secure frac services on our Eagle Ford wells. So we're in pretty good shape there. So I anticipate having -- as we get into the end of the first quarter, getting one to two wells completed about every six weeks and we'll be drilling -- that's through the first half of the year and we'll be drilling with that second rig hopefully by June or July.

And my thought, like the business models, it's set up just exactly like Mack said. It's the second rig there maybe in June or so. And with the five rigs, we have busy now, the four in the Haynesville, one in Eagle Ford. Any of those rigs could drill Eagle Ford wells. So there, we can move them. And as Mack said, really this program is kind of like the Haynesville program. Based upon the results, it will tell us how many rigs we need to move to the Eagle Ford. And it'll then tell us how many -- of course gas prices will tell us how many rigs we need to be using or not using in the Haynesville also.

A follow-up to Brian's question on the production rate. First quarter, given the timing of these Eagle Ford wells, on the sale of Mississippi. Out of the 207 million a day production in January, what was your oil production? The round number?

For the first quarter, oil production will only be about 2% of that total production. Remember because we sold Laurel [Laurel, Mississippi], that's at 1,300 barrels a day.

The next question comes from the line of Kim Pacanovsky from MLV. Kim Pacanovsky - McNicoll, Lewis & Vlak LLC: One of your peers, who's also fairly new in the Eagle Ford, mentioned that if they had to drill their first well again, it would likely have come in at a much higher EUR and IP, just because of what they've learned from subsequent wells. And I know you've only drilled, or are in the process of completing, at least, your third well. Can you tell us what you've learned and if there were any hiccups with those first two wells?

Sure, this is Mack, Kim. And you're exactly right. You learn a lot in drilling your first well or two in a play just as we did with the Haynesville. So it goes in the Eagle Ford. And yes, we would do things differently, certainly. Especially on the completion side. There's no question that the longer lateral is preferred, whether you're talking Haynesville or Eagle Ford. Also, the completion strategy matters a lot and thinner fluids, more profit, more stages. There's an optimum there and no one has figured that out in the Eagle Ford yet. There's a lot of different things being tried, but certainly, we would complete the wells slightly differently. I don't know that we'd do a whole lot differently on the drilling side. To be honest, we follow the drilling programs that are being used by all the major players. We might tweak it a little bit here and there, there's always improvements that could be made, as you know. But on the completion side, we would alter the frac design up certainly, change it. Kim Pacanovsky - McNicoll, Lewis & Vlak LLC: And I know that you're going into the condensate window now. When will you move back into the oil window again and kind of apply what you've learned?

I'm not real eager to go back into the oil window quickly. We have a lot of condensate acreage over -- about 3/4 of our acreage is in the condensate window. So we certainly need to get some of those wells drilled. We have multiple tracks across McMullen County, within the condensate window, so we need to test each of those tracks to better define the condensate window. And we do have, at the Atascosa acreage, that's in the oil window, certainly. We want to take a good hard look at our first well performance to see how that production profile is fitting our type curve, make sure that the EURs are on the upper end of our expectation range. And then we'll take a look at moving a rig in there and drilling another well. There are other operators that are drilling north of us and east of us in the Atascosa, and we want to take a look at those results as they become available. That will be valuable information as well. Kim Pacanovsky - McNicoll, Lewis & Vlak LLC: Just one quick question for Roland. What are the future plans for the Stone shares? The remaining shares?

We don't have a definitive timetable on when we might divest of those. But you can see we've sold some of our position in 2010 at 1.5 million shares. So definitely the valuation of Stone has improved a lot from -- we held it through the periods where it really fell down in value. And they're doing very well, have lots of catalysts going on with the company, so we're kind of watching that. And they have a lot of exposure to oil I think, so which is a positive.

Kim, we always say though, you don't own us because we own Stone. You'd much rather see us use those dollars to our own drilling program or our own acquisition program. So we understand that, that's why we monetized some of the shares last year. And we'll continue to do that, we think, in 2011.

The next question comes from the line of Noel Parks, Ladenburg Thalmann. Noel Parks - Ladenburg Thalmann & Co. Inc.: Looking ahead to the condensate wells in the Eagle Ford. Do you anticipate the complexity of the completion being greater there than it was in the oil window? Or similar? I guess, I was thinking about the differences in pressures, for example?

No, sir. This is Mack. I don't anticipate substantial difference in complexity. We're certainly configuring future wells to obtain the maximum lateral length possible, given the configuration of the drilling units that we formed and we want to take full advantage of drilling the extra long lateral. And to answer your question about complexity, the longer the lateral obviously, the more stages are involved in the frac design, et cetera. And that obviously complicates things a little bit, but not substantially so. Noel Parks - Ladenburg Thalmann & Co. Inc.: As far as just the direction, the orientation of the wells. Is that pretty much open and shut? Or is that also a major factor in figuring out how to get the longest lateral on a given lease?

There's some flexibility. Certainly, we like the north-south orientations as do most of the other operators in the play. But there's some flexibility there, certainly. You're not going to find anybody drilling east- west laterals, for example. But you can configure a lateral to be northwest or northeast, slightly off the vertical. Hopefully that answers your question. Noel Parks - Ladenburg Thalmann & Co. Inc.: And just looking ahead for the next couple of years in the Eagle Ford. And I know of course, it's real early, just because you're just in your first few wells. But I mean, do you envision that, I guess the learning curve being greater on sort of the efficiency side of completing and producing the wells? Or on just shorting out the geology in the different areas of the play?

I would think that the learning curve is -- we're well at the learning curve on the drilling side of the equation. We drilled a ton of horizontal shale wells obviously in Haynesville and so that's certainly transferable knowledge to the Eagle Ford, to a certain extent. There some differences obviously. The same thing to be said for the mechanical and the logistics that go with the completion in the Eagle Ford. We've learned a ton in doing our Haynesville wells. But there's obviously going to be some improvements, some optimization in the Eagle Ford as we move forward, and especially, especially on the completion side. 3D seismic is valuable, whether you're in a Haynesville or you're in the Eagle Ford, and we're taking advantage of the data availability and that 3D seismic will help us orient our laterals, which is an off-reference to an earlier question. So obviously, there will be some optimization as more information becomes available. And the engineers, the geologists correlate the data to how to get wells drilled faster with better hold conditions, how to complete the wells more optimally and tie all of that to performance, and that's the key. And that's why everyone is participating, a lot of operators are participating in the same kind of analysis groups and same kind of data trading groups that were initiated in Haynesville. I think the leasing part of the Eagle Ford play isn't totally over, but certainly close to being over. So operators are more agreeable to trading information.

And the next question comes from the line of Amir Arif from Stifel, Nicolaus. Amir Arif - Stifel, Nicolaus & Co., Inc.: I think most your Haynesville acreage is already held by production, and just given the current gas price, any reason why you wouldn't want to move a rig over sooner to Eagle Ford? To sort of test the area out and get a better sense of what you're sitting on?

Well, this is Mack. We consider that every month, when do we want to move the rig over. We want to get some data on some wells. Not only our wells, but some information from the surrounding operators that will allow us to more appropriately define exactly where we want to move the rig. You're right, most of our acreage is held by production in the Haynesville, but we certainly want to take advantage of some of the benefits of developing offsets to our Haynesville wells prior to getting excessive drawdown in a producing well or around a producing well. So we want to keep a certain level of activity in the Haynesville for reasons that have to do with recovery and benefiting the production profile. But the bottom line is, as soon as we feel that our Eagle Ford acreage is appropriately defined to where we can move that second rig, we will move that second rig. If we can move it faster than we have currently modeled, which is around June or so, we'll do that.

I think what we're trying to do is, remember back in '08, we had a 100-well Cotton Valley program going on even though we had 78,000 net acres in the Haynesville, 50,000 in the Bossier. And we had a great footprint at a very low cost. And most of that footprint is in what we would call Tier 1 acreage. There were a lot of aggressive drilling stories in '08 in the Haynesville and we drilled one Haynesville well that we operated. We participated in one non-op at El Paso and we booked about 11 Bcfe of reserves. And even during that year, I mean, there was like the Haynesville hype. Everybody was hyping it and selling equity and whatever. And we said, well, we do think that our assets are valuable. We're going to treat them valuable. We don't want to blow any money drilling wells we shouldn't be drilling. Let's let some other companies figure out where the better part is. And if you remember back then in '09, we got comfortable at the end of '08, we completely shut down our Cotton Valley program. It was all held by production. We started an aggressive Haynesville program. We did that in '09 and last year, and things were going great until the end of the second quarter, and then it wasn't that we didn't hit great Tier 1 Haynesville wells. It was that we didn't have the frac services. So what we've tried to do now is, we've tried to continue to be balanced. And if you remember the first couple of wells, the Haynesville wells we drilled in '09, we had a frac stack blowout. We had a big giant problem at the very beginning. I think that's kind of what Kim Pacanovsky was asking about, would we do things different. I think anytime you're in a new play, your learning curve, you go up in a hurry, it's not on the drilling side. In the Haynesville, it was on the drilling side and the completion side. I think on the Eagle Ford, it's mainly the completion side. And our goal, and we've try to communicate it, is to drill in all the counties that we own acreage in. And in McMullen, we own a lot more acreage, maybe 60% of our whole footprint in Eagle Ford and McMullen. And as Mack said, we'll drill a lot more wells in McMullen County. And then we wanted to get rid of the frac issues. We have a crew for the Eagle Ford wells to frac all those wells, 22. We have a dedicated crew to frac the Haynesville/Bossier wells, and then the rigs that we have can drill in and out of the Haynesville area or the Eagle Ford area. And as you had mentioned, we probably only have to drill 11 or so wells to hold our Haynesville acreage. So we try to keep flexible so that when we're very, very comfortable that we need to increase our Eagle Ford program, we can go do that in a period of a quarter. But we're not there yet. Amir Arif - Stifel, Nicolaus & Co., Inc.: So I take it that the rig that you have out there is just going to be focused in McMullen County?

The rig we're using right now, yes sir, that's correct. Amir Arif - Stifel, Nicolaus & Co., Inc.: Just a question on drilling versus gas prices. I mean, I take it you guys still prefer just to remain unhedged and just allow operation flexibility to move the program up or down as needed? Because of the drilling CapEx?

On hedging, we don't see -- because our oil program is too new to be able to -- and we don't have a lot of oil production currently. So it doesn't make sense to hedge that at this time. There's not enough of it to effectively hedge. On the gas side, the current prices out there, we don't see them being attractive enough to lock in. So I mean, I think we might evaluate if there's better prices for gas that now that the Haynesville program has become very predictable in a long-term basis. We'll evaluate that, if those become available. But we don't see the current prices as something that you want to lock into. Amir Arif - Stifel, Nicolaus & Co., Inc.: But at the current strip, your current drilling program, you would still spend about $500 million at the current spot prices that you see out there?

Yes, the current strip, yes. Unless service costs come down, that's what we expect to spend right now. We have a number of rigs net currently running that are budgeted for.

I think the other comment is, if you know the G&G staff and the reservoir staff and operations staff, the same group that really helped create the wealth in the Haynesville/Bossier, it's the same group that's focused on the Eagle Ford. I think that's a good thing.

The next question comes from the line of Dan McSpirit from BMO Capital Markets.

Any thoughts on refinancing the 6 7/8% notes due 2012? And have you got any read from the market currently on rates?

Dan, that's definitely on our list to look at this year, is to refinance the 2012 maturity bonds. I think the market's pretty strong. I don't think that right now, that we could get that exact same rate, if it was a great execution. But the closer we can get to that similar rate, the more interested we are in refinancing. But it's something we'll try to get accomplished this year.

Remember they're due a year from March.

Future development cost associated with your 2010 reserves. Do you have that number?

Yes. The future development costs associated with all the reserves, all the proved reserves, is about $1.3 billion.

How many shares do you own of SGY [Stone Energy Corporation] today?

At the end of the year, we owned 3.8 million shares of Stone.

And then turning to the Eagle Ford Shale, the two wells that were completed. Can you give us the costs on those two wells? And then what should we estimate for costs going forward on the 22 wells, is it as simple as dividing the $169 million, $170 million that you have budgeted by the 22 net wells?

Yes, that's basically what we budgeted. We own, really a 100% working interest in, right now, in all of our Eagle Ford wells.

And then the costs of the first two wells that were completed?

They were a little higher, at around $9 million a piece, because we drilled a pilot hole and a water well.

Is there much water associated with the two wells that were completed? And how might that differ between the oil and condensate windows?

We're not sure about the condensate windows yet, Dan, because we're just now drilling those wells and completing them. And a lot of the fluid -- you recover a higher percentage of your frac fluid in an Eagle Ford completion versus a Haynesville completion. And so that pushes those numbers higher and it takes a while of course, to recover your frac fluids and for that water to fall back. So kind of a general answer to your question. But that's just based on two wells that we've completed.

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

Just a quick question on here on the Haynesville. I'm trying to get a sense of what your sort of current well costs are there and what you're budgeting for 2011?

We're looking at around $10 million drill and complete, per well.

And that's pretty much current and it's kind of the same number for 2011 budget as well?

Yes, sir. There will be some fluctuation, depending on whether we drill a pilot hole and that sort of thing.

And have you drilled any wells recently to the Bossier? Do you anticipate doing that at all in 2011?

Yes, we're targeting approximately 15 wells or so for the upper this year, as part of our Haynesville drilling program.

And have you had any other recent wells in the fourth quarter to speak of?

None, that we haven't reported on, no.

Just in terms of your 2011 CapEx, you talked about potentially moving a third rig over late third quarter. Is that factored into your guidance at all? Or is that, you see that as kind of being a zero-sum game, if it stops drilling Haynesville and starts drilling Eagle Ford?

Well, I made that comment earlier in response to a question about moving additional rigs, removing rigs to the Eagle Ford faster. We have the flexibility to do that. And that response that I gave about the third rig was just to demonstrate that we had the flexibility to do it if the well results indicate that we should. So our current model is to move the second rig in -- to start drilling in the Eagle Ford in late June and that's what our model is based on.

And the total CapEx budget, that assumes five rigs busy all year long, whether it's Eagle Ford or whether it's Haynesville.

I guess, in terms of Haynesville, I guess you guys still have a relatively substantial well backlog there. Can you give us some sense as to, kind of when that returns to more of a normal operating level? Do you expect to get through that here in the first half? Or are you going to get through most of it in the first quarter? How should we think about that?

That's going to take the entire year to go through. We've kind of based our plan on just working through those and keeping up with the drilling rigs, and it almost takes the entire year through the fourth quarter to get back to kind of a normal backlog.

So we should, for modeling purposes, we should kind of steady state that backlog depletion throughout the year?

Correct. We see the production and really just the activity -- the completion level will pick up a little bit in the second quarter. Because at the very end of March our dedicated frac crew goes to work and so we'll be completing a couple more wells a month than we are in the first quarter. But basically, we see production growing every quarter, including the end of fourth quarter throughout the year with the way we are completing the wells.

If you remember, initially we thought we would have this indicated crew active by the end of January, early February. And just last week, we received a date that they would actually start and it's late March. So again, you can't control the date that they would start. But they have given us a date, and it's late March. So that's why Roland said it will take the next nine months to frac those wells.

I think you folks have kind of talked about sort of 207 million a day of production here in the month of January. Do you expect February, March to kind of continue sort of tick higher? Just trying to get a sense of kind of where first quarter may shake out?

We do expect February, March to be higher. The only caveat is, if there's a bunch of transportation problems, processing problems. Had a little bit of that last week, but if that doesn't reoccur, we should see a stronger rate in the next two months.

Jumping over to Eagle Ford, you guys said 75% of your acreage in the condensate window. Can you give us a breakdown by your three counties there, Atascosa, Karnes, McMullen, in terms of how much acreage you have in each?

Well I can tell you about 60% of our acreage is in McMullen, and it's in a condensate window, almost all of it. And about 15% of our acreage or so is in Karnes; it's largely in the condensate window. And then the rest is in Atascosa and it's in the oil window.

And I guess in terms of the well you drilled in McMullen, do you characterize that as being in the oil window? Is that kind of on the northern most part of your acreage there?

Correct.

Last question, kind of a financial one. Looks like your cash G&A was down a fair bit in the fourth quarter versus some of the prior levels. Is anything sort of going on there? Is that just more of, sort of, kind of a one-time thing? How should we think about your G&A going forward?

I think the quarter was a little lower than it probably would be on a go-forward basis. If you're comparing it to the fourth quarter of 2009, we had some -- we had $1 million of cost related to unsuccessful acquisition there. That was very unusual item. This quarter though, we basically had lower -- mainly lower compensation really drove down the numbers in the fourth quarter. And going forward, we'd probably expect to see a level about $9 million to $9.2 million maybe for G&A per quarter, would be a reasonable expectation as we go into 2011. Very flat, maybe slightly down.

And the next question comes from the line of Ron Mills from Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: Just on the Eagle Ford. You talked about, on the oil window, 225,000 to 325,000 BOEs. I think on your overall Eagle Ford you're talking about plus or minus 400,000 BOEs. So what is you alls expectation on the condensate window? Plus or minus half a million?

Well, it certainly a moving target. But it's going to be north of 400,000 barrels, that's for sure. Depends on the GUR [ph] and the quality of the Eagle Ford that we encounter across our acreage tracks. So again, a general answer to your question, since we're just now drilling our McMullen wells in the condensate window. Ronald Mills - Johnson Rice & Company, L.L.C.: And the McMullen well that you've already brought online. How many frac stages was that and did you get all of those frac stages off? Because it looks like it was right on that cusp of that oil condensate area.

Right. Well 14 stages I believe is the number that we completed. And we did have two or three stages that we had some difficulty with. But most of the 80% to 90% of the stages were completed as designed. And as I mentioned in an earlier comment, we would change our design, our frac design to thinner fluids, a little different profit package and perhaps tighter spacing on the stages on that well. If we had to do it over again, that's part of the learning curve deal. Ronald Mills - Johnson Rice & Company, L.L.C.: And were you using cross-linked gel or are you using I guess what some people are talking about as the hybrid?

Yes, we were hybrid, but we were more strongly weighted toward some of the cross-linked fluids that we would do today. Ronald Mills - Johnson Rice & Company, L.L.C.: And then, the drilling plans in the Eagle Ford going to two rigs and potentially a third. Is the timing of that also somewhat limited by the overall infrastructure and exactly what your infrastructure needs are, depending on your gas oil ratio and the characteristics of your condensates? Is that also one of the factors limiting how quickly you accelerate down there?

The short answer is, sure. We wouldn't move a third rigs in and drill wells that we couldn't get the infrastructure to. I mean, that's certainly the case. But we feel very confident in the second rig moving in June; we've got some assurances that the infrastructure will be in place. Now again, these are oil wells. But if you're in the condensate window, you're going to be making substantial gas volumes too, and we certainly want to take advantage of selling that product to market. So we would want the pipes to be there. Ronald Mills - Johnson Rice & Company, L.L.C.: Lastly, the Bossier activity. You'll have quite a bit of Bossier activity this year. I know you have a pretty good relationship with one of your bigger lessees. Any issues with targeting that many Bossier wells, in terms of losing some Haynesville acreage? Or what's the plan? And should we read into that in over some areas, some of the Bossier is looking as attractive, if not more so than the Haynesville?

In most of our acreage, we've already penetrated the lower and so the Bossier wells that we would be drilling in those areas obviously don't represent any issue whatsoever. And you're right, we do have a good relationship with one of our larger lessors. So we're in good shape as far as going forward and completing the upper. And those places where we complete the upper or the Bossier, in preference to the lower, that's certainly a decision that we make based on the commerciality issues. So the short story from us on that is that we have a lot of wells targeted on the upper, about 20 or so this year, 15 or so. And half of them will be in an area where we've already got the lower behind producing and the other area, we feel the upper is by far the better target. Ronald Mills - Johnson Rice & Company, L.L.C.: There's been talk the past, I don't know, two or three months, but especially over the course of the last two weeks, about potential lower Smackover [Smackover Formation] over portions of North Louisiana and East Texas. Any commentary on that, in terms of -- given y'alls acreages is further south, whether there's any overlap with either your Louisiana or maybe even more likely some of your stuff in Harrison County that you're not really targeting for the Haynesville at this point?

Well, we are looking into that. That's an interesting sidebar on the Haynesville play, certainly in Harrison County. We have some data in Northern Louisiana that suggests that it's pretty sparse in that area. But we're gathering data.

Ron, the other thing on the Eagle Ford, again, as Roland mentioned, it's kind of an unusual footprint. I mean, we've got about $4,500 an acre in it, and we operate all of it and we own about 100% working interest. So those are three variables that are positive too.

The next question comes from the line of Jack Aydin from KeyBanc.

What is the mix of the molecules in that well in McMullen? What percentage was liquids, condensate, natural gas? Could you give us a breakdown?

In the Rancho Tres Hijos well we had about 400 barrels of oil, we had about 400 Mcf gas. And I don't have the water rate or the frac load rate that we were producing at the initial test point.

On your booking on the Haynesville EURs, what level did you book for the PUD?

We're still at about a five, 5 1/2 Bcf per well level.

I think it's, it calculates at about 5.3 Bcfe for the PUDs, which is in the developed wells. If you average those, are closer to six, about a Bcf higher. About 6.3 Bcf for the developed wells.

Jack, we're being conservative as we mentioned earlier.

If you look at your Eagle Ford versus Haynesville, on economics. If you have to choose today, which one you pick up? Which one you will focus more and more? Based on economics.

My answer, Jack, is based on what do we know the most about, what has the least risk. If you look at our drilling program in the Haynesville, we're targeting upper, lower risk wells, mid-Bossier wells that we feel will give us a high recovery. We're also targeting our Logansport area, where we think the EURs are going to be significantly better than our bookings. So the risk economics of the Haynesville are extremely predictable and appealing, even in this gas price environment and the cost structure environment that we face. And as we go forward in the Eagle Ford, and we get the risk elements better defined and we get into the condensate window, we're just now drilling that and we find out more about what those EURs are in the recovery rates, certainly that answer can change. And I expect it to. We find the Eagle Ford very appealing on the economics. The potential there is substantial for Comstock and that's why we picked up, obviously picked up 18,000 net acres and dedicating two rigs to it this year.

Mack, what would make you happy in terms of the condensate window in the Eagle Ford IP wells? What will make you happy, what will make static?

Jack, I'll tell you what. On this IP business, everybody gets all excited about an IP and then they go home and they forget about it. I'm more interested, not in what that initial rate is, but I'm more interested in how that decline is. What is with the pressures and that sort of thing. I'm interested in how this thing projects. Is it a stable 400 barrels a day? I'll take that. The IP at a 500 and 600 a day, it's flat at 400 a day, it's got good pressure and it's going to produce a 400-a-day for the next year or so on a very, very slight decline and my EURs are going to go into the 500,000 barrel, 400,000 barrel range. I'm good. But give me an IP at 1,000 barrels a day and it's on a 30% decline, or greater, and you're gutting the well and you get into a lower recovery situation. I want to see, in the condensate window I want to see the 400 to 500 MBOE, EUR, Jack. And certainly to get there, you're going to have IPs well north of 500 a day, I mean, that's obvious. And I want to see that decline rate very, very soft, a very shallow decline.

Next question comes from the line of Ray Deacon from Pritchard Capital.

Mack, I had a question about -- would Enterprise and Kinder Morgan be the main mid-stream players in the areas where you're active in the Eagle Ford?

They're certainly active. But I don't know if they're the main ones. Ray, I wish Steve Neukom was here, he could certainly answer that. He's our VP of Marketing. They're active, that's for sure.

Does there come a point where your production gets to the level where you'd feel you'd need to sign some kind of large agreement? Or sort of form transportation or you don't think that's issue on '11? Or...

No, sir. Not this year. But certainly as the volume grows, we would want to sign some sort of arrangement that would secure trading capacity and pop [ph] availability, that's for sure.

The 10.4 million a day IP rate in the Haynesville. That's still a 30-day rate, is that...

Yes, sir. Yes, and 8 million to 10 million a day, it depends on where the well's drilled and how hard we choke it back and that sort of thing.

And the next question comes from the line of Patrick Rigamer from Iberia Capital Markets.

It sounds like, I mean, you mentioned having the service contracts in place for the Eagle Ford. Does that anticipate the second rig moving down in June?

Yes, sir.

What about the third rig?

Well, we have an option to negotiate additional capacity with the completion services that would accommodate that third rig if we chose to move it in there.

And then the 23.4 net wells on backlog, in the Haynesville. Is that a current number or is that an end of the year number?

That was the end of the year, Patrick, number. Current number is probably, it might be a well less than that or so.

And then I guess the other question I had was the third well that you're drilling in the Eagle Ford and -- I'm sorry, the one that's flowing back and you have another one drilling. Will we, should we expect to hear something from those with the first quarter release? Or before then, or?

Well, Patrick, we expect to have at least three, maybe four or so Eagle Ford wells, including that one, which just missed this quarterly release. We had hoped that would be ready for today. But it's going to miss it by about a week. But we should have a handful of those wells report with our first quarter results. We don't plan to report -- our practice has not been to report wells on a well-by-well basis. Every quarter, we'll update where they are.

And ladies and gentlemen, we have run out of time. I would now like to turn the call back over to Mr. Jay Allison for closing remarks.

All right. Carmen, thank you. And again, it was a long conference call. We had a lot of, I think important information to give to the market. I'm sorry we weren't able to report on the third Eagle Ford well. Our expectations are high on that. But like Roland said, we're probably a week or 10 days away from having the real results. So again, thank you for your participation.

This concludes the presentation for today. Ladies and gentlemen, you may now disconnect. Have a wonderful day.