Comstock Resources, Inc. (CRK) Q1 2011 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the First Quarter 2011 Comstock Resources Inc.'s Earnings Conference Call. My name Marissa, and I'll be your coordinator for today. [Operator Instructions] I would now like to turn this presentation over to your host for today's call, Mr. Jay Allison, the CEO and President. Please proceed.

Thank you, Marissa. Welcome to the Comstock Resources First Quarter 2011 Financial and Operating Results Conference Call, everyone. You can view the 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 First Quarter 2011 Results. I'm Jay Allison, President of Comstock. With me this morning is Roland Burns, our Chief Financial Officer; and Mark Williams, our VP of Operations. During this call, we will review our 2011 first quarter financial and operating results, as well as updated results of our 2011 drilling program. Please refer to Slide 2 in our presentations and note that our discussion 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. Our 2011 first quarter highlights. Please refer to Page 3 of the presentation where we summarize the first quarter results. The weak natural gas prices continue to hold back our financial results despite the strong production growth we had in the first quarter. We reported revenues of $88 million, generated EBITDAX of $65 million and had operating cash flow of $56 million or $1.18 per share. The gain we recognize from selling some of our Stone shares allowed us to make a profit this quarter. We reported net income of $2.4 million or $0.05 per share. This quarter, a solid return of strong production growth as our production increased 18% over the fourth quarter 2010 number. We are back on track in our Haynesville operations having overcome the shortages of track crews that adversely impacted our production in the second half of last year. With our dedicated crew in place, we are more confident about our production growth and are increasing our guidance for production from a 16% to 23% increase to a 26% to 32% increase. Our 2011 drilling program is off to a good start. We drilled 19 successful wells, including 15 Haynesville shale wells and 2 Eagle Ford shale wells in the first quarter. We are most excited about our most recent Eagle Ford shale well in McMullen County, which has recently put out production at a rate of 1,264 BOE per day. Our balance sheet continues to be very, very strong. We completed a $300 million senior notes offering in the first quarter, which extended the maturities of our debt and added to our liquidity. I will turn it over to Roland to review the financial results for this quarter in more detail. Roland?

Thanks, Jay. On Slide 4 in the presentation, we break down our oil and gas production by quarter and by operating region and we highlight our production from the Haynesville program in blue on the chart. In the first quarter of this year, our production averaged 222 million cubic feet of natural gas equivalent per day and 18% increase over the fourth quarter of last year and 6% higher than production in the first quarter of last year. Production in this quarter set a new record high for onshore operations as we have now overcome the shortage of completion services, which impacted our Haynesville operations in the third and fourth quarter of last year. Haynesville production increased to 133 MMcfe per day as compared to 94 MMcfe per day in the fourth quarter of last year. Production from our Cotton Valley wells declined to 41 MMcfe per day, and we averaged 38 MMcfe in our South Texas region and 10 MMcfe per day in our other regions. Despite a number of interruptions due to plant or pipelines being down due to the extreme cold weather we had in the very early part of the quarter, the reduction of completion activity for our Haynesville wells allowed us to have a strong production quarter. With our dedicated frac crew now in place and operating very effectively, we now expect 2011 production to approximate 92 Bcfe to 96 Bcfe, which represents a 30% to 36% growth over 2010 production if you exclude the 4% of 2010 production that related to the properties that we sold last year. Oil prices continue to be very strong in the first quarter, which we cover on Slide 5. Our realized average oil price increased 34% in the first quarter of 2011 to $89.94 per barrel as compared to $67.08 per barrel in the first quarter of 2010. Our oil price in the first quarter averaged 96% of the average benchmark NYMEX WTI price. With 96% of our production natural gas, the weak natural gas prices offset the strength of oil prices and had an adverse impact on the financial results this quarter. Slide 6 shows our average gas price, which decreased 25% in the first quarter to $3.96 per Mcfe as compared to $5.30 in the first quarter of 2010. Our realized gas price was 96% of the average NYMEX Henry Hub gas price during the quarter. On Slide 7, we cover our oil and gas sales. The lower natural gas prices offset the 6% production increase, and our sales declined by 17% to $88 million in the first quarter. Our earnings before interest, taxes, depreciation, amortization and exploration expense and other noncash expenses or EBITDAX also decreased by 19% to $65 million, as shown on Slide 8. Slide 9 covers our operating cash flow. Our operating cash flow for the quarter also came in at $56 million, 22% lower than cash flow of $72 million in 2010's first quarter. On Slide 10, we outlined our earnings this quarter. We reported net income of $2.4 million or $0.05 per share as compared to earnings of $7.3 million or $0.16 per share in 2010's first quarter. Our first quarter financial results included several unusual items. We retired our senior notes, which were due in 2012, in the quarter, with proceeds from a $300 million senior notes offering. The first quarter 2011 results included a charge of $1.1 million or $0.7 million on an after-tax basis or $0.02 per share related to the early redemption of the 2012 senior notes. Other unusual items reflected in the first quarter include an impairment of $9.5 million or $6.1 million after tax or $0.13 per share to write off leases that we expect to expire during 2011 without drilling activity. These 2 charges to income in the first quarter were offset by a significant gain that we realized from the sale of our marketable securities during the quarter of $21.2 million, which would be $13.8 million after tax or $0.30 per share. Excluding these items from what we reported the net loss this quarter of $0.10 per share. On Slide 11, we show our lifting cost per Mcfe produced by quarter. Lifting cost for the company is comprised of 3 components: production taxes, transportation cost and other field-level operating cost. Our total lifting cost this quarter improved to $0.90 per Mcfe as compared to $1.08 per Mcfe in the first quarter of 2010 and $1.02 per Mcfe in the fourth quarter of 2010. Production taxes were $0.04 and our transportation cost per unit produced was $0.28 in the first quarter. With our increasing Haynesville shale production, we are transporting more of our gas to the longer-haul pipeline rather than selling our gas at the well head. Field operating cost averaged $0.58 this quarter as compared to $0.75 in the first quarter of 2010. The improvement is due to the higher production level we have. Also, it's due to the absence of the high-cost properties that we sold in the fourth quarter of last year. On Slide 12, we show our cash G&A expense per Mcfe produced by quarter, which excludes stock-based compensation. Our general and administrative cost decreased to $0.26 per Mcfe in the first quarter of 2011 as compared to $0.30 per Mcfe in the first quarter of 2010. The improvement is due to the higher production level combined with lower G&A cost in the quarter. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 13. Our DD&A rate in the first quarter averaged $3.03 per Mcfe, an improvement from our $3.15 rate in the first quarter of 2010. Our DD&A rate this quarter increased $0.12 from the $2.91 that we averaged in the fourth quarter due primarily to the lower natural gas prices that we had to use in the DD&A calculation and their impact on our reserve estimates. On Slide 14, we detail our capital expenditures during the quarter. We spent $158 million in the first quarter as compared to $94 million that we spent in 2010's first quarter. We spent most of that, $124 million, in our East Texas/North Louisiana region with $34 million in our South Texas region. $13 million of $158 million was spent in first quarter on acquired additional leasehold perspective for other Haynesville or Bossier shale development. Slide 15 recaps our balance sheet at the end of the first quarter. On March 31, we had $4 million in cash and $81 million in marketable securities on hand. We had a total of $597 million of debt comprised of $300 million of our new 7 3/4% senior notes and $297 million of our 8 3/8% senior notes. We have nothing outstanding on our bank credit facility, which has the unused borrowing base of $500 million, which was recently affirmed by our bank group. Taking into account the cash in our balance sheet and our marketable securities and the unused $500 million bank credit line, we have $585 million in liquidity. Our book equity at the end of the quarter was $1.1 billion, which makes our net debt 31% of our total capitalization. As we mentioned earlier, we closed on $300 million on these senior notes in early March and used the proceeds to redeem our senior notes that were due in 2012 and to repay the amounts outstanding under our bank credit facility. And as a result of this transaction, the average life of our debt has increased to 7.3 years from 4.5 years. I'll now turn it back over to Jay.

Thank you, Roland. On Slide 16, we recap our holdings in the Haynesville shale play in North Louisiana and East Texas, which is updated for additional acreage that we acquired this year. Our acreage is highlighted in blue. We currently have 93,000 gross acres and 81,000 net acres that we believe are perspective for Haynesville shale development, 60,000 acres are in North Louisiana, which we think is a better part of the play. Given expected well spacing of 80 acres and an expected per well recovery of 6 Bcfe per well, our acreage could have 4.6 Tcfe of reserve potential. On Slide 17, we showed the acreage that we think also has potential for the development of the upper Haynesville shale, our middle Bossier shale. Our acreage is highlighted in blue. We currently have 62,000 gross acres and 52,000 net acres that we believe are perspective. Given similar expected well spacing of 80 acres and an expected per well recovery of 5 Bcfe per well, our acreage could have 2.4 Tcfe reserve potential. I will now have Mark Williams, our new Head of Operations, give you an update on the drilling program this year. Mark, as most of you know, has been with Comstock for the past 15 years and he was appointed VP of Operations March 16 of this year, when Mack Good, our former COO had retired. So Mark, it's your day in the sun.

Thank you, Jay. Slide 18, we recap our activity in our East Texas and North Louisiana region for this quarter. Our activity in this region is focused on developing our Haynesville and Bossier shale properties. We drilled 15 horizontal wells, 6.9 net wells in this region in 5 different fields in the first quarter, as shown on the map. All of these wells were successful. And 11 of the wells were Haynesville wells, 4 of the wells were Bossier shale wells. Since we initiated our Haynesville shale program in 2008, we have now drilled a total of 133 wells or 84.6 net wells. During 2011's first quarter, we completed 13 operated and 8 non-operated Haynesville or Bossier shale wells. These wells were put on production at an average per well initial production rate of 11.2 million cubic feet equivalent per day. On Slide 19, we provide an update of our backlog of uncompleted Haynesville and Bossier shale wells. On the upper left pie chart, we illustrate our situation at the end of 2010, where 35 of our 72 wells that we had drilled in 2010 had not yet been completed. The lower pie chart reflects the net well account and showed net 23.4 of our 45 net wells drilled in 2010 have not been completed. As previously announced, the frac crew shortages which plagued us in the second half of 2010 have been resolved by contracting a dedicated crew, which started work for us late in the first quarter. As shown on the bar graphs to the right, at the end of the first quarter, the backlog has been reduced from 35 wells to 29 wells on a gross basis and 23.4 to 19.2 on a net basis. Our current backlog is 18 Haynesville wells and 11 Bossier shale wells. The backlog in March 31 includes 12 gross wells and 5.8 net wells that we drilled this year, so the number of 2010 wells still waiting on completion has been reduced from 35 to 17 or 23.4 net to 13.4 net. With a dedicated crew that we currently have, we expect to work off the backlog by sometime in the third quarter this year. On Slide 20, we've updated the number of days it has taken to drill the 93 operated horizontal Haynesville wells that we've drilled to date. Our average drill time for all the 93 wells to date is 37 days. The average drill time for our first wells was 51 days compared with 33 days for our last 5 wells. We expect the average drill time for future wells continue to average approximately 33 days. Slide 20 outlines our planned activity this year to further develop our Haynesville and Bossier shale acreage. We currently plan on drilling 46 wells or 29.7 net wells to our interest, 33 of which are Haynesville wells and 13 are Bossier wells. 32 of the 46 are operated. 27 wells are planned for Logansport, 15 are planned for the Toledo Bend North in Toledo Bend South areas and 3 wells for Mansfield. We're also growing 1 well at Waskom in East Texas. We're currently using 4 rigs for this program and plan to move 1 of these to our Eagle Ford program in late June or early July. Our South Texas region is displayed on Slide 22. In South Texas, we drilled 2 successful Eagle Ford shale wells at McMullen County in the first quarter. On Slide 23, we outlined our Eagle Ford shale play in South Texas. We drilled -- as stated here, we drilled the 2 wells in McMullen County in the first quarter and we also completed our well drilling in Karnes County, the well we drilled in Karnes County last year. Since the end of the quarter, we have finished drilling another well in the Wheeler Ranch in McMullen County, which will be completed later this month and if started drilling, an additional well in McMullen County. The Carlson #1 (sic) [Carlson #1H] was drilled in the oil window in McMullen County to a vertical debt of 9,070 feet with a 5,874-foot lateral. We booked this well on production at an initial rate of 548 barrels of oil per day and 200 Mcf of natural gas per day or 585 BOE per day. The well is currently producing to sales on a restricted choke with a shallow production decline. This Swenson #1 (sic) [Swenson #1H] was also drilled in McMullen County on our Wheeler Ranch acreage in the condensate window to a vertical debt of 11,150 feet with a 6,119-foot lateral. This has been our best well to date. We tested this well at an initial rate of 1,045 barrels of oil and 1.3 million cubic feet of natural gas per day or 1,264 BOE per day. We've also completed the Coates #1H, which was drilled in 2010 in Karnes County to a vertical debt of 9,706 with a 5,422-foot lateral. This well was tested at an initial rate of 507 barrels of oil per day and 22 million cubic feet of natural gas per day or 538 BOE per day. Given the small amount of acreage we have in Karnes County, we are in the process of trading our acreage with another operator for initial acreage in McMullen County. And given the nature of results for the most recent well, we are excited about the potential of our acreage at McMullen County and plan to continue to expand our holdings in this area. On Slide 24, we outlined what we expect to spend this year on our drilling program and on our acreage acquisitions. With the recent efficiencies achieved in the company's Haynesville and Bossier shale program in North Louisiana, both in shorter drilling times and in completion times, we have recently revised our capital expenditure budget for 2011 to reflect increased activity, as well as expenditures to increase our exploratory acreage primarily in the Eagle Ford shale trend in South Texas. We now expect to spend approximately $570 million or drilling in completion activity this year and an additional $40 million on leased acquisitions in 2011. $115 million of the drilling and completion budget is related to wells that were drilled but not completed in 2010 due to the frac crew shortage and are instead being completed in 2011. We expect to drill 46 gross or 29.7 net wells in the Haynesville or Bossier shale in East Texas and North Louisiana region in 2011 or 21 net wells on our Eagle Ford acreage, targeting primarily liquid hydrocarbons. I'll now turn it back over to Jay.

Mark, that's excellent. That's a lot of script for your first time. Thank you, Mark. That's a great report. And now this Slide 25, I think, is one of our most important slides other than all the questions we're going to have asked in a moment about Eagle Ford, which Mark will answer. But as -- Roland put a slide together for the internal funding of CapEx. I know that many investors are critical of the company outspending our cash flow this year and last year. So Roland put this slide, which is Slide 25, together, which clarifies the situation for Comstock because we're an unusual E&P company because of our divestitures that we've made. Since 2008, when we divested our offshore properties, to the end of last year, we spent $1.3 billion on our drilling program, which has allowed us to transition from a conventional exploration company to where we are now, with all of our growth coming from unconventional shale development. During the same period, we generated operating cash flow of $938 million and had proceeds from asset sales of $520 million, which has more than funded our expenditures. And the key, we did not incur additional debt or sell any equity to the public to fund our program. If you include our expected 2011 activity, our total expenditures for the total four-year period of $1.9 billion will more or less equal our total internal sources of funds, as shown in this graph. We should be 100% funded from internal sources to the end of this year and for the previous 3 years. I do not believe that many of our competitors can make the same statement. Our 2011 outlook, which is on Slide 26, and summary, I refer you to Slide 26, we're very pleased with how this year is progressing even though we've had weak natural gas prices. The outlook for production growth is very strong. We expect production to increase by 26% to 32% over last year, with completion of the backlog of wells drilled in 2010. Our low-cost structure is the strength in this period of low gas prices. We saw a continued improvement to our cost structure in this quarter. Our Eagle Ford shale program in South Texas is progressing as we expected. We have now tested our acreage and we'll focus on developing our acreage in McMullen County in the condensate window in 2011. During this period of weak natural gas prices, Eagle Ford program gives us a higher return area to grow our oil condensate and natural gas liquids production. 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 to weaker prices. We've reduced the rigs we're using from 7 to 5 and have the flexibility to release another 1 early this year. We had to make amendments to have adequate completion services, but we maintain flexibility to reduce this exposure if prices erode. We continue to maintain a very, very strong balance sheet. We have $500 million available on our bank credit facility and $81 million in marketable securities to supplement the cash flow we would generate. And as shown on Slide 25, the earlier slide, we've been able to fund the growth in our reserve and production exclusively from internally-generated funds over the last 3 years and through the end of this year. For the rest of the call, I will take questions from research analysts who follow the stock. Marissa, I'll turn it over to you.

[Operator Instructions] You have your first question from the line of Leo Mariani from RBC.

Just a couple of quick questions here for you. Just trying to get a sense of what your current well costs are in the Haynesville and Eagle Ford these days.

Yes, this is Mark. In the Haynesville, we're probably between $9.5 million and $10 million on an average well cost. In the Eagle Ford, our initial wells are all pilot holes and have additional science, so they're a little north of $9 million. But our development well plans are in the $8 million, $8.5 million range. So we're a number down from there.

Got you. All right. And I wanted to get a sense of how some of your Eagle Ford wells have kind of held in there if you got 4 on production now. If I'm right about that?

We've been pleased overall with our decline rates are less than our initial projected decline rates. And so we've adjusted our type curve somewhat and we're still monitoring that. It's early on these wells and we're still evaluating, but we're very pleased with the declines so far.

Okay. And I guess you have those wells on pumps, I imagine. And can you maybe give us a little bit more color around sort of how they performed better than the decline curves, maybe quantify that at all for us?

All of our wells are still producing naturally. We have not installed artificial lift on anything. We're probably getting fairly close on the NWR well but it's still producing adequately without.

Okay, got you. Just last one question here for you. I noticed that your other gas production was up sequentially this quarter of about $3 million a day. I was curious. Are you guys drilling some wells elsewhere on your property outside of the Haynesville and Eagle Ford? Just trying to get a sense of what was driving some of the growth on your other properties there.

Yes, this is Roland. Yes, the other regions had a little burst of extra production this quarter, and that's mainly due to a Granite Wash well that we participated in as a non-operator in our kind of mid-continent region. So I think we had one of those last year. This is the second one. So there's probably a few of those out there.

All right. Then I guess there would be a couple more of those potentially on the schedule for this year?

I don't know. Not really sure, because it's really up to the operator on the timing. So we don't have any pending AFPs for a Granite Wash well right now.

Thank you, Leo. Remember one thing, Leo. Our goal in Eagle Ford is like an $8 million well and we're about $8.5 million, as Mark said. And then Haynesville is about $9 million or $9 million, $9.5 million. Those are similar numbers that we gave out last time. And the goal in Eagle Ford, we're treating Eagle Ford like we treated the Haynesville. We wanted to drill a well on each of the counties as Coates or Karnes and McMullen. And you'll notice that we focused on McMullen. We've got another well as TD, and we're drilling another well, as Mark said, in McMullen currently. And the acreage in Karnes County, since it's a couple of thousand acres, we did think we'll probably be able to trade it and add it to our McMullen acreage. And our budget as far as lease budget, a lot of that is to add Eagle Ford acreage. So that's to kind of clarifying some of your questions.

That's very helpful, Jay. And I guess there's a quick follow-on to that. You said you have a couple of thousand acres in Karnes. I guess how much do you have currently have in McMullen?

Outside, 13,000. Out of the 18,000 net, it's probably 13,000, 14,000. It's the key.

And your next question comes from the line of Kim Pacanovsky from MLV. Kim Pacanovsky - McNicoll, Lewis & Vlak LLC: I was wondering, Mark, if you could talk about some of the completion issues you had on a few wells. Obviously, there's a big difference in IP rate between the Swenson, which was a very strong well, and the other 2 wells drilled in McMullen County. And I realized that the lateral lengths are a little bit different, particularly with the Rancho Très Hijos. But if you could just talk about maybe some of the issues you have had, is it some stages not coming off, and what kind of a tax you're taking to solving these problems. And have you had any issues staying in zone?

Kim, on the initial well on RGH, we've had a little more trouble staying in zone than we did on the Swenson. It's a little more complex. It was our first well and very little well-controlled area. But most of that interval is in zone. Like you said, it's a short lateral. It was our initial frac job. We have adjusted the frac designs to larger hybrid-type designs from more of a cross-linked-type design, which we feel has improved things. The lateral length has improved. Overall, we've been able to get our stages pumped. We may have one here or there that doesn't pump to completion. But generally, the wells, they frac adequately. So I think the frac design has been -- change has been one of the keys. The Swenson is in a deeper part of our acreage, which is going to provide more energy, and we feel like it's going to be the better part on an IP basis, anyway. So we've got some benefit from that. I think all those things together. Kim Pacanovsky - McNicoll, Lewis & Vlak LLC: Great. And have you thought about the booter [ph] potential on your acreage?

We are monitoring what's going on but we have not evaluated the booter yet. We do get information when we drill the pilot holes and we log through the Buddha and get that data. And we'll monitor what some of the other operators’ doing, but we have not really evaluated. Kim Pacanovsky - McNicoll, Lewis & Vlak LLC: Okay. And finally, what are the leasehold commitments that are remaining in the Haynesville closure?

We had -- since the beginning of the year, we needed to drill, I think, 16 wells in order to hold our acreage, which is either Haynesville or Bossier. And we'll drill 29 net wells this year. So we'll have HBP'd [held by production] all of our acreage for 2011, 2012. We might have some commitments starting back in 2013 but we really don't have any commitments that I'm aware of in 2011.

2012.

I mean 2012. Kim Pacanovsky - McNicoll, Lewis & Vlak LLC: Okay, great. And I guess I'll just ask one more question. Do you have any water issues in the Eagle Ford?

In terms of source water or... Kim Pacanovsky - McNicoll, Lewis & Vlak LLC: In terms of source, yes.

No, we've been able to drill regional wells to get our source water at this time, and everything's worked out fine. Kim Pacanovsky - McNicoll, Lewis & Vlak LLC: Okay. Super. All right. Thanks.

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

I just have a couple of quick follow-up questions. I may have missed something, switching conference calls here. But Roland, could you give us a little color on the exploration expense and then why it's so high for the quarter, and then your thoughts on the exploration expense going forward?

Sure, Michael. Included in the exploration expense is an impairment that we took this quarter on our, mainly our Haynesville lease position. As we come to the end of the initial 3-year terms of these leases, there is a handful of leases in kind of struggling areas. I'd say a lot of that was either Shelby County, Texas or Caddo Parish that, yes, that we don't see that are -- it's on the very marginal part of Haynesville, so we went through it and did a process of scrubbing down the acreage and saying these are going to probably expire without us drilling. And so that's what that $9.5 million charge for lease is in the quarter, which shows up an exploration expense because it was for evaluated properties, but it's actually more of an impairment. So on a go-forward basis, we really don't see very much in exploration expense. Every now and then, we acquire a little seismic to support the exploration program and that's been our exploration expense in the past, so I think it would be a very small number going forward. And we typically, we just don't like to drill dry holes anymore, so we don't have much of that in exploration expense, and hopefully, we continue to do that.

Very good and on the South Texas production, can you break that down in terms of the Eagle Ford production in conventional South Texas for us for the quarter?

I don't I have that number right on hand, but I think the Eagle Ford -- what do you think the Eagle Ford's averaged about? A lot of wells, like the Swenson well, didn't come on production until the second quarter, really. I think it was...

[ph] 11% or something like that the most.

Yes. It's not a large percentage. It's a good percentage of the oil there because we didn't have hardly any oil there before.

[ph] Another, we had -- when we sold Laurel, Mississippi we had about 1,200 BOE that we sold on our -- our Eagle Ford production is greater than that. When we have our first well, it was 381 barrel of oil per day. The second well was 432. The third well was like 450. The Carlson well was over 500 and we've added the Swenson well.

Yes. I'd say about probably 20% of our South Texas production is now Eagle Ford on a quick calculation. We averaged about 1,000 barrels a day for oil production in the South Texas region in the quarter.

Okay. One last question. I'll jump back in the queue. You're relative to do an acreage swap in South Texas. Would you end up exceeding your core position? And in McMullen County, would you contemplate moving more aggressively in terms of a drilling program there? Would you put several production facility then?

Well, I think, our goal is to move a second rig, which would be a rig we have in the Haynesville to the Eagle Ford, probably next month or the beginning of July. And then when we have our third quarter conference call, I think we'll indicate to you if we're going to move a third rig over, which would be sometime in the fourth quarter. If not, early on in 2012. But at the beginning of this year, we said it probably would be a 3.5 rig program in the Haynesville and a 1.5 rig program in the Eagle Ford for the year. That would be average for the year. But if again, I think the way we're set up with the rigs and with the service crews, the frac crews and even our position in Eagle Ford, if we drill 21 gross wells, it's actually a net #2. Because we own a 100% working interest in these wells. So we completely have the ability to shift a rig more sooner than later to the Eagle Ford out of the Haynesville if we want to. And that will be based totally upon commodity price, really, and performance of the wells that we drill in McMullen, particularly on the Wheeler Ranch. And again, we drilled another well since this conference call. We haven't tested it, and we're drilling another well. And that's where we will focus. And we expect the results to be good. So if anything, we would accelerate our Eagle Ford drilling and decelerate the Haynesville. And stay within the new CapEx budget. And we did add dollars for leasehold cost because we do plan on adding some acreage if possible in Eagle Ford play.

And your next question comes from the line of Brian Corales from Howard Weil.

To your Slide 25 that you all put in the presentation, can we assume maybe in 2012, that you'll be close to kind of totally in funding with internal sources for 2012 --

Yes, Brian, this is Roland. Yes, that is definitely going to be a major objective because as Slide 25 does show, that the proceeds that we had available for the very large divestitures, especially offshore divestiture, which this year as we have in steady energy, are really just part of those proceeds. And we will have pretty much used those this year with this year's program. So the goal is to come up with a program next year to get us the best reserve and production growth within cash flow, and we'll look forward and see if gas prices have strengthened. I think what we've been trying to do this year is develop the ability to grow on the oil and liquid side, and that's what the Eagle Ford program -- as it continues to have good results, we put together more acreage. We put together our infrastructure. We want to see that -- that could be the big program for 2012 if the oil and gas prices are still in the same relationship and it warrants. But we're definitely going to have a lot more tools available to us at the end of this year, and we won't have any real commitments to have to hold our acreage in the Haynesville next year either. So this year gets a lot of things in place to be able to accomplish that for next year.

Yes. That Slide was really to show you, I mean, visibly that we intentionally have recreated the company. We didn't sell boggard[ph] because it was a distress sale in this town. We sold it because it was the right thing to do. And we weren't one of the companies that purchased at the market peak. We didn't do that either. And then I don't think we're a company that became reckless drilling wells in the Haynesville prematurely. We drilled one net well in the Haynesville in '08. We drilled 43 in '09, 72 last year and we'll drill our share this year. But that slide shows you that we're running this company based upon a per-share-stock appreciation. And we have an issue, the equity or head in the out balance sheet, type financings in order to create the transition that we've accomplished. We've added the Eagle Ford at right price. And like Roland said, in 2012, we should exit this year with this 30%, 35% plus production growth, and you can take that production rate and you can use whatever oil and gas price you want to use. But I mean, we should have $400 million, $500 million of operating cash flow and that is what we expect our CapEx budget to be in 2012. It will be a balanced budget is our goal. And again, as we said, we won't have to fund any Haynesville program in order to hold acreage now. I would anticipate a rig or a rig and a half in the Haynesville just to keep production at a decent rate. But we'll focus more on the oil and condensate windows, which is what Mark has done recently.

Okay, guys, that was very helpful. And then just one final question. Can you maybe comment about what's your current production is and what's your current oil production is?

Brian, this is Roland. I think our current production is running close to about $240 million a day. And now the last week or so, with the tornado activity in North Louisiana especially, we had some significant shut-ins while power was down in some of our big gas-producing areas, but those lasted virtually maybe a day or 2. So it probably won't have a significant impact for the second quarter is coming up. But we do have a lot of production that is concentrated out of our Logansport area, especially at our largest producing area. And a regional problem like that can affect us. Hopefully, the weather gets calmer out there the rest of the quarter. So that's kind of more or less the -- that, that's the total equivalent of production. I don't really have a current breakdown on the oil, but it's probably up and Mark probably has it here anyway.

1,800 to 2,000 barrels a day, I think, with the Eagle Ford right now.

And your next question comes from the line of John Freeman from Raymond James. John Freeman - Raymond James & Associates, Inc.: I just want to go into the CapEx a little bit more. I'm just trying to get a sense of where the bulk of the increase is going? I'm just sort of looking at the net wells drilled, 50 wells roughly. That's 50 last time. And it looks like the carry-over impact from 2010 was about $5 million of what you all had previously said. So I'm just trying to get a sense of what the new number of completed wells is for 2011 versus you all were budgeting?

Basically, they were 2 -- virtually, 2 new net wells in the Haynesville program that are in that budget versus the other one. So it didn't sound like a lot, but the wells, at $9 million to $10 million they add a lot of cost. And some of those are non-operated. Just more proposals from other operators that we participate in the Haynesville. And then also just a little shorter drilling time has affected that number. But the big impact on it was the fact that the completion crew is much more efficient and effective, and now that it's in place, we see getting through the entire backlog. And then not only that, what was happening before was even though -- you see the carry over, we always thought we'd get those done more or less, but it's really the wells drilled in 2011. Would all those completed? And this new budget assumes that for the most part they will because we see our dedicated crew really -- as we get to the fourth quarter, it's going to be almost looking for work. So we don't see that we have any delays at all. So we're going to have our -- we'll be down to a very few wells at the end of the year that aren't been completed. And that's a change in the earlier budget estimate where we thought we might carry over as many 10-plus wells to the next year to be completed. And since more than half of the cost are completion costs, it can add a fair amount of dollars. I think the Eagle Ford program is pretty similar to our original projection. It hasn't changed much at all. And then we added the $40 million. As we see opportunities to acquire leases that we didn't think we would have in the Eagle Ford in the area we want to focus in, we feel like that money will get spent so want to get that in the budget.

Remember we had budgeted for this dedicated crew to complete about 4 wells per month, and in fact, they've completed about 6 wells per month. I mean, they're, as Roland said, they are very efficient and effective and the production rate shows that. John Freeman - Raymond James & Associates, Inc.: So of the roughly $48 million increase in the actual drilling budget, it's mainly just a difference, as you just said, Jay, and you were budgeting 4 wells complete a month to south of 6.

You're almost completing 10 more wells period for the whole year.

And these are 100%-owned wells.

So it's not really a new cost that's going to be incurred in total by the company. It's just the timing of it. It would have been cost that would go into 2012. So in general, it's not a new cost for the company in general. It's just how does it fit into the calendar years. Where last year, services prevented us from getting the things done and put in the proper calendar year. This year, it's the opposite. We're going to have more than enough services to get all the work we could possibly want to do in the Haynesville done this year. John Freeman - Raymond James & Associates, Inc.: Okay. That's very helpful. And then just one more for me. Last quarter, you all had mentioned that the only kind of constraint on you all going from 2 rigs here in the Eagle Ford midyear to adding a third rig at some point, which is the infrastructure. Can you just sort of give any update? Is that still the case that would prevent you from being able to add a third rig some time later this year?

Well, really, it's a combination of how much acreage we have and how fast we can get it prepared to drill and the rig commitment we need to drill that acreage. So as we add acreage this year with our proposed expenditures in the budget, that will enable us to look forward and bring a third rig in. Whereas right now with our acreage count, we're pretty comfortable with the 2-rig program for this year. Infrastructure wise, there are a lot of issues in South Texas with getting the oil transported out. It's not so much a gas issue as it is an oil issue, but our marketing group, our marketing VP is working with 2 large oil haulers and we expect that problem to be minimal for us.

And your next question comes from the line of Noel Parks from Ladenburg Thalmann. Noel Parks - Ladenburg Thalmann & Co. Inc.: Just a few questions. You mentioned in the press release and you've tested on it a little bit over the course of the call, but your improved efficiencies in the Haynesville. Just now you talked about some of that is the frac crews working faster than you'd expected. Can you give me an idea of maybe what we might see, the unit cost trend looking like, say lifting cost for a total oil if you like, as we progress through the year?

Sure, Noel. On lifting cost, because you saw the -- as production started to come back and from the Haynesville, you saw the big improvement in lifting cost and that was not just the Haynesville. It was also we've removed our very highest cost property. Is one reason we sold the Laurel properties because of the very high lifting cost. So basically, our fixed lifting cost, if you exclude transportation and production taxes is relatively flat in our Haynesville program. So the higher volumes just drive the unit cost down. That number is different and the Eagle Ford becomes more and more -- there's more and more oil production from the Eagle Ford. There's going to be the opposite of that. That's going to be in a higher cost production to handle because we have both the oil storage, oil handling also some water disposal. These oil properties are generally, are much more expensive to operate than gas properties. So that will start to offset some of those big savings from the Haynesville. But I think the Haynesville is growing so fast this year with the completions that you won't notice the inferred additional cost. But I think it's something for next year. I think we'll probably drive down the very low lifting rate this year, but then we'll start to have to see that increase especially for 2012 if we focus on the oil side. Converse is you have, yes, much higher revenues to offset that. Noel Parks - Ladenburg Thalmann & Co. Inc.: Then for Haynesville lifting cost, where do you think on a unit basis the trough quarter might be? Do you think you'll actually be fourth quarter? Do you think third will be kind of...

Fourth will be the lowest because it's going to be -- we think that will be our very largest production quarter. Noel Parks - Ladenburg Thalmann & Co. Inc.: I'm sorry, is that fourth?

Yes, fourth quarter. We continue to see it build unless we have some disruptive event or trends change. But we expect to see the fourth quarter be the largest production quarter from the Haynesville, and then it'll all depend on our budget for 2012, how much we devote to that area. The only cost that's going to be very variable and maybe even slowly increasing is transportation cost. That's going to be based on the volumes there and the more volumes and the higher percentage the Haynesville makes up, the larger that will look. But it's more than offset by the savings in the fixed cost, and production taxes continue to be fairly very modest this year because most of the new wells that we're completing -- the Haynesville are exempt initially from production taxes for their first up to 2-year period. So until the Eagle Ford becomes a bigger share of the production, where you're going to have -- oil has higher production tax rates plus it's not exempt. You'll see those numbers getting better and better. Noel Parks - Ladenburg Thalmann & Co. Inc.: Great. And actually on the drilling time side on the Haynesville, I think the average was 33 days for the last few wells. Do you think that's about come down as to as fast as it will be? Do you think we'll still see a little bit more improvement by the end of the year?

I think we squeezed most of our improvement and efficiency out of the drilling side of the equation. And we should hold pretty flat at that 33 from here on. Noel Parks - Ladenburg Thalmann & Co. Inc.: Okay. Great. And also you had talked a little bit about the differences among your Eagle Ford wells so far. And I was wondering, aside from being able to stay in zone better and better completion and so forth, can you kind of contrast between, say, your earliest wells like, the NWR well and the most recent one, just I guess you've more or less have been heading south than east. Just sort of the differences into the geology as you've had in the McMullen and as you've talked about just variability of the rock and what that means for how important or how difficult it will be to sight wells going forward?

Well, I had said earlier that kind of give us an overview, and I'll let Mark comment. Remember, our goal, we talked -- if we look on Tab 23, the middle of the condensate window as we've drawn it is our Wheeler Ranch. No, we didn't drill our first well in McMullen. We drilled it at Atascosa, a shallow oil, and then we went to the kind of Wilson-Karnes type area. Then, we drilled to the northwest in McMullen, but our goal was to drill wells on all of our acreage footprints. I don't think that we ever thought the Atascosa well would be one of our better wells, but we wanted to drill it anyhow. And we finally ended up, as Mark mentioned earlier, we have a big ranch like the Wheeler Ranch. I mean, it's probably a 40-page lease. And you have to work with the landowner and middle owner to find out where you can drill these wells and we've finally -- we're able to get our locations in place. And the top wells that we've hit – out at the Wheeler Ranch, really the top wells. We expected to have this 400,000 barrel recoverable per well. So as we have said during this meeting, we've finally progressed to the point we drilled enough wells in all of these areas. We're pretty comfortable with what we think the outcome will be, and that's why we're focused between here and year end on drilling wells, really on the Wheeler area. So Mark, with that.

Yes. As far as the geology goes, there is some variation in the geology across the play as you would expect. We don't see any extreme changes from the North to the South. The rock quality gets a little bit better for us in McMullen county acreage and that's part of the reason we believe the performance is better. Depth is probably the biggest factor. We're at 8,000 feet at the NWR in Atascosa and we're down at 10,500 depth on our Swenson acreage. And that just provides a lot more energy to drive the oil out of these tight rocks. So that's probably one of the biggest things. But as far as complexity, it's pretty similar. There's some minor faulting in some of the areas we have to contend with or watch for, but nothing extreme and we think they're going to be pretty similar. [technical difficulty]

Your next question comes from the line of Ron Mills from Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: A couple of questions. On the frac services, you talked about your frac, you have a dedicated crew but you may be working through most of your backlog by the fourth quarter. Is that crew somewhat fundable in the sense that you can maybe use that rig both in the Haynesville and the Eagle Ford as we look to you adding that second rig and potentially a third rig or what would the use for that, for those time slots to the extent that you work to your backlog sooner than expected?

The contract is pretty flexible after mid-year and that we can renegotiate portions of it, and they could look for other work if we have some openings in our schedule without really costing us any penalty. And so that's one option, would just to release the crew part of the time, later in the year if we don't need it and have the vendor go look for other work. They have also talked about maybe taking it down south to the Eagle Ford like 2 weeks at a time or 3 weeks at a time to catch some of our work down there, but we haven't committed to that at this time.

Now remember, Ron, Schlumberger is a dedicated crew and we have a different crew on Eagle Ford right now. Ronald Mills - Johnson Rice & Company, L.L.C.: Right. And I assume for you to add the second rig, you're already in discussions to add incremental services in the Eagle Ford or can your provider there also -- if you could handle any increase from Eagle, from 1 to 2 rigs?

Well, we've signed an agreement. We're on a one rig program. We'd have a frac group for any wells in the Eagle Ford that we would drill basically on a one-rig program and then if we move a rig up, which we plan to do in June or early July. Then if we wanted to under the same frac crew commitment, we could add an attachment to that and they would frac any additional wells we'd be drilling with the second rig. We, internally, don't think we'll have a frac-ing crew issue right now. Other than the Haynesville, Bossier or in Eagle Ford. Ronald Mills - Johnson Rice & Company, L.L.C.: Okay. And just to clarify, the leasing you've done year-to-date, the $13 million, it looks like that's been mostly in the Haynesville so far, is that correct?

That's correct, Ron. $3 million of that is cap off interest, which of course, just goes in all of the leases in general. It's more of accounting. The balance of that, the $9 million or so is leases that we did early in the year mostly. It's Haynesville, Bossier acreage. A lot of it's kind of a Renard, Toledo Bend South area.

It's a couple of thousand net Haynesville like a thousand net Bossier. That's where we ended up. Ronald Mills - Johnson Rice & Company, L.L.C.: And so that would leave about $30 million for incremental leasing over the remainder of the year and it sounds like that's what you plan on targeting in Eagle Ford. And if so you, you're at 18,000 acres now. I know you have spoken in the past of not necessarily being able to increase that much. What kind of magnitude do you think you can increase your acreage position by? Are we talking about 40% or 50% or 70% rather?

And again, it's not -- the $30 million or so that's remaining in that budget, I mean we paid about $4,300 per acre for the acres we own today in Eagle Ford. For course it may go anywhere from $6,000 to $10,000 to $14,000 to $15,000 depending upon if it's out right to leases or JV partners. But I think our goal would be to add anywhere from 5,000 to 10,000 net acres if we could. Now we may or may not spend those dollars doing that. It may be less than that. We're not putting $1.00 per acre on that. We're just saying, if we could increase it by 5,000 to 10,000 acres, that would probably be a good goal. And we don't really see any Tier 1 acreage in the Haynesville, Bossier coming open. We think most of that or all of that will be HPP[ph] , about the middle of this year, which we're almost there. Now there's Tier 2 acreage and Tier 3 acreage, whatever. That will be opened in the Haynesville, Bossier, but I don't think the real growth in any company right now is going to be adding a large acreage position in the Haynesville, Bossier. That's probably behind us. So the question is can you come in and pick up some small acreage blocks in the Eagle Ford. And we've been in South Texas 20 years and been really active 10 years. We've got good reputation. We spend our own money drilling wells. So I think we will be afforded the opportunity to pick up that acreage. Ronald Mills - Johnson Rice & Company, L.L.C.: Okay. And then, Jay, you mentioned earlier, I mean, once you'd spend less on leasing, you don't have to carry over. That you've generate $400 million to $500 million of operating cash flow that, that's would be pretty similar to what your CapEx would be and that you have mentioned kind of a 2- to 3-rig program in the Haynesville. Just given the way you're ramping production over the course of this year and if you go down just a couple of rigs in the Haynesville, is that sufficient to be able to offset gas declines or would we start to see some gas declines, which would then be from a revenue standpoint made up for the growing Eagle Ford oil?

Well, I think, what we'll do, Ron, looking at the next year, we're not tied to having a production from the Haynesville after being certain of growth path. It's going to be -- we'll look at the resources if we can -- should be able to afford a 4- to 5-rig program. We'll look at the economics of those wells. And whether you grow gas production by 5% or don't, but if you grow sales by 20%, maybe we're going to look at what can you grow revenues by and allocate our resources that way. And so I mean we're not at all focused on trying to maintain a certain production level on a particular region. We developed Eagle Ford and the whole area to give us alternatives and higher return projects and in the end, we'll allocate our capital. Next year, where is the highest return projects in our portfolio? And if oil and gas prices are in the same relationship, it might not go to the Eagle Ford. So it's all -- that's the decisions, that we'll have all those ability to make those decisions in November so it doesn't make a lot of sense to speculate on what we'll do now because it's just too early.

But I think that's at Slide 25. I mean what Slide 25 tells you is that from '08 through 2011, 4 years. I mean where will we be, hopefully, at January of 2012. We will have completely proven up what we think is the good and bad part of the Bossier and the Haynesville. Will it be completely comfortable with the Eagle Ford. We'll have HPP, our acreage and Essex, North Louisiana. We should have phenomenal production growth. I mean we already are at a new record high on shore production level today, and we have a lot of wells that we own 100%, that there are Tier 1 wells that will be frac-ed by the Schlumberger crew. They're doing a great job with that. I think we're just at the tip of the iceberg with what we're doing at the McMullen County in the Wheeler. And again, if we drill a well, we own 100% of it. We hadn't watered ourselves down to own 1/3 or 1/2 or 1/4, whatever. So these will all be big impact wells. We have about the same amount of shares today as we had in '08. So everything we do, it's amplified to the better. And even if you all look at our percent of natural gas, we're 96% natural gas, 4% oil. By year end, maybe we're 8% to 10% oil and by year-end 2012, maybe we're almost 20% oil. I mean we're focused on that and I think we're doing it the right way. Ronald Mills - Johnson Rice & Company, L.L.C.: Okay. And that was one of my last questions. If you look at that gas production mix, I think in the past you had talked next year being able to kind of on an average basis be plus or minus 10% oil. But as we look ahead to the remaining quarters of this year, just given the completion profile in the Haynesville, it seems like if you might exit -- you said 8% to 10% liquids, but the average will still be pretty similar in the first quarter because most of your Haynesville additions are going to dwarf your Eagle Ford until the latter part of the year or is that incorrect?

No, it's -- I mean the good and bad about our production profile is we had so many Tier 1 wells that carried over from 2010 to 2011. You already see this in the Haynesville, Bossier. You already see this big production growth. I mean even though we are -- for our side, as a company we're growing our oil/condensate liquids portion pretty material for us. But it is, it's kind of dwarfed with the type of production we have for the Bossier and the Haynesville. Gas is coming online even though we are a low cost producer in that area. But I think they'll more or less normalize itself in the fourth quarter. And then you're going to see what our production really looks like and what our big exit rate will be, and then is when we start adding more and more rigs to the Eagle Ford, McMullen County hopefully. I mean you'll see a greater percent of our production be the oil/condensate, which we feel pretty comfortable about that. Ronald Mills - Johnson Rice & Company, L.L.C.: And then I don't know if it was you, Jay, or Mark that mentioned talking about EUR. I know you talked target 400,000 barrels with some of your early wells may not have gotten there or nor would they really have been expected, but if you look at your Wheeler Ranch in McMullen County and as you move deeper and with the early results given the flatter decline rates, I mean, is that still a pretty good target in your minds in terms of the average EURs?

Yes, Ron, I think 400,000 is still a good target. I don't know. I guess our goal would be more than that but as far as what we believe, we feel comfortable with that projection at this time on the McMullen County acreage. Yes. Ronald Mills - Johnson Rice & Company, L.L.C.: And can you describe what's going on from a well restriction standpoint? There aren't as many people restricting liquids oils -- I don't think in -- how is that lower IP rate with a shallower decline kind of play into the whole EUR picture?

We firmly believe in the Haynesville that the restricted rate program has been a big improvement to the performance, and I guess, until we are proven or proven otherwise to ourselves, we think the same concept should apply to the Eagle Ford. It's a shale. It's frac-ed very similarly. It produces -- although it's oil instead of gas, it still produces very similar. We believe the restricted rig program is the way to go. We're holding our wells back to a 14 to 16, 64 choke and monitoring the production decline and we said we're very pleased with our decline rates at this point.

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

You spoke about adding about 5,000 to 10,000 net acres in South Texas in the Eagle Ford. That is a stated goal. What's your price sensitivity? That is what's the price per acre where the economics don't work by your estimates?

We couldn't give you a specific number on that. I mean, I think you have to look is it closer to the dry gas windows? Is it closer to the shallow oil window? Is it right in the middle of condensate window? Are you closer to Mexico? Are you closer to Gonzales County? I mean, this thing is what, 200 miles long and 50 miles wide, and we've got -- we have an appetite to acquire more acreage within this "condensate window," that our G&G[ph] group feels comfortable with. And we've just -- we stuck out a budget there because as a stockholder, you need to know what our budget is. And our goal -- we might not add one acre. But our goal is to increase our footprint there.

Okay. And then based on your answer, Jay, am I to assume that you won't limit your search to McMullen County?

That's correct.

Okay. And then you spoke about trading Karnes acreage for McMullen County acreage. How much acreage are we looking at here? Is it just a couple of thousand acres? In the terms of that trade, would it be one for one?

Yes, about 2,200 acres if I recall correctly and it's just an acre for acre trade.

Okay. Great. And just a point of clarification or confirmation on my part. Will the remaining wells drilled to the Eagle Ford shale this year be located in McMullen County?

We may deviate one or 2 wells. But no, I'd say 90-plus percent of them.

Yes. I think we have one well scheduled at this time for Atascosa and everything else is in McMullen.

Correct.

Okay. And any estimates on the number of locations on your current McMullen County acreage and specifically, locations on the Wheeler Ranch acreage?

We've just said 80-acre well spacing is what we're with right now. And again, I think in McMullen, 13,000, 14,000 net acres is our footprint.

And your next question comes from the line of Rehan Rashid from FBR. Rehan Rashid - FBR Capital Markets & Co.: Roland, on the LOE per unit. As we kind of ramp up Haynesville, what is a good kind of a number to think about as we exit the year on a corporate level?

Well, I think at an overall corporate level, where we hit the $0.90 this quarter, it could improve a little bit by the fourth quarter, yes, but probably down to the mid-80s maybe I'd still say we're not going be maybe $0.85, $0.84 is kind of the way. A lot depends on how South Texas and other factors kind of come into play because we'll have increased costs from the area at a higher rate. But then, as the Haynesville is coming out with so much production, it's kind of overwhelming and most of our new costs from the Haynesville's only going to be mostly in transportation costs. Not going to have a lot of traditional field cost or severance taxes to go along with that production. Rehan Rashid - FBR Capital Markets & Co.: And haven't tested the VUDA[ph] yet, but any plans to?

Not at this time.

And your next question comes from the line of Jack Aydin from KeyBanc Capital Markets.

Most of my questions were answered, but I got a couple of one. You got some other operation like in San Juan and mid-continent. Are those assets for keep or...

They will all be divestiture candidates but they're natural gas and we don't think the market's right to sell those right now. But they're in other categories because they're not a major part of Comstock's assets.

Okay. The second question, what you think your inventory by year end? You think you will have some inventory wells by year-end 2010 or you're going to be caught up completely?

Virtually, be caught up completely and then lever operationally, you couldn't have get to -- there might be a well or 2, but I think as we'll be actually trying to find some work with our completion crews maybe towards the end of the year. So we'll definitely -- they'll have to be able to complete anything that's available.

The final question, you mentioned that based on current pricing, it looks directionally you are of the mindset that your CapEx is going to be down versus this year.

I think, Jack we won't have the $115 million kind of at a period cost, so hopefully, that part is out of the equation. And then we get down to a range that yes, we'd like to see it. The normal range for us would be, for even this year, it would be $115 million less, and so next year should be close to that level and hopefully, we'll have some -- look and try to achieve some savings in the completion area especially in the different plays and try to drive a CapEx budget that comes close to the cash flow we'll generate next year.

And your next question comes from the line of Chris Pikul from Morgan Keegan. Chris Pikul - Morgan Keegan & Company, Inc.: Just want to clarify one point. You've addressed a lot of my questions, but if I look at the location of your Swenson well, it's kind of in the broadly speaking, the liquids window, but the oil yield still seems very high. Does that make you rethink at all where the play becomes more or less oily or are we thinking about that right in terms of north south?

Yes. This is just a very general math and things don't break from oil to condensate to dry gas. It really grades as you go down, so I think in the true definition of condensate, that area is probably much, much narrower. But we kind of correlate high yield oil with condensate in terms of just talking points and how we view things. And so it covers a much broader area if that answers your question. Chris Pikul - Morgan Keegan & Company, Inc.: Yes. It does.

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

Most of my questions have been answered. I just wanted to follow up on some comments earlier. You talk about $400 million to $500 million in operating cash flow next year and as I look out into 2012, natural gas drip kind of getting above 5, call it 5 1/4 range. I know you guys get asked this a lot, but do we start to think about layering in some hedges here or is there a price at which that becomes attractive?

Well, on our budget, one, I'll answer that. I mean, what I've said is you take our exit rate, which should be up again 30% to 36% versus this year. And then you take whatever commodity price tag you have and maybe it's a $100 oil and $550 gas. I don't know. That's where I come up with this kind of imaginary $400 million, $500 million. It is whatever it is based on commodity price in our production rate. So that is what I've said, Roland said we're trying to keep our CapEx budget within that number. And then as far as hedges, I'll let Roland answer that.

I think as the Eagle Ford program becomes more predictable and dependable. I think yes, we would with oil at very high levels, I could see us wanting to hedge that with some of the high oil prices. Again, gas, if gas was at attractive levels, we might consider hedging now that Haynesville program has become so predictable and we would not hedge anything if we consider weak or low prices. Instead, we would divert our capital to the areas we can have higher returns.

Yes. We said like at double meeting[ph] And other meetings that if we've got a 4, 5 rig program in the Haynesville, Bossier, whatever, it's predictable program. It's an announced program and we know we've kind of contract the rigs to drill those wells in any given year. Then, you would do that based upon a certain gas price because that's a gas play. So we would be very much inclined to hedge a lot of that to protect that program.

Are you willing to say what price that would be?

No.

We wouldn't lock in low prices in order to look to hedging to be the answer to prices, I think it can be used as a tool to protect commitments, you make on the drilling and completion side. But again, the strength of our company is being flexible in adapting to the environment versus forcing, trying to force the environment to adapt our plans.

Ladies and gentlemen, that concludes the question-and-answer portion of today's call. I would like to turn it back to Mr. Allison for closing remarks.

Marissa, thank you. I know we've had a long conference call so now we're in like 20 or 30 minutes and for most of you that stayed from beginning to end, we're very thankful. Again, we tried to put in a good day's work to create great value on a per-share basis. I think Mark's a great addition to the team. He has been here 15 years. He has now stepped up to VP of operations. I expect great things from him. I think you did a good job today. So anyhow, thank you for your support.

Ladies and gentlemen, that concludes today's presentation. Thank you for your participation. You may now disconnect. Have a great day.