Comstock Resources Inc (CRK) 2011 Q1 法說會逐字稿

Good day ladies and gentlemen, and welcome to the first quarter 2011 Comstock Resources Inc. earnings conference call. My name is Marissa, and I'll be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. 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 a slide presentation during or after this call by going to our web site at www.ComstockResources.com and clicking presentations. There you'll find a presentation entitled -- First Quarter 2011 Results. I am 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 update the 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 meanings of securities laws. While we believe the expectations of 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 recognized 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 saw the 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 frac 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 two Eagle Ford Shale wells in the first quarter. We are most excited about our most recent Eagle Ford Shale well in McMullen County, which was recently put on 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 out 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; an 18% increase over the fourth quarter of last year, and 6% higher than production in the first quarter of last year. Production 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 million per day, as compared to 94 million per day in the fourth quarter of last year. Production from our Cotton Valley wells declined to 41 million per day; and we averaged 38 million in our South Texas region and 10 million 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 resumption of completion activity for our Haynesville well 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 to 96 Bcfe; which would represent 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 in 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 non-cash 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.

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 in 2011 without drilling activity. These two charges to income in the first quarter were offset by significant gains 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, we would have reported a net loss this quarter of $0.10 per share.

On slide 11, we show our lifting cost per Mcfe produced by quarter. Lifting costs for the Company are comprised of three components -- production taxes, transportation costs, and other field level operating costs. 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 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 pipelines, rather than selling our gas at the wellhead. Field operating costs 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 cash G&A expense per Mcfe produced by quarter, which excludes stock-based compensation. Our general and administrative costs 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 lower natural gas prices that we had to use in the DD&A calculation, and their impact on the reserve estimates. On slide 14 we detail the 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, at our East Texas/North Louisiana region, with $34 million in our South Texas region. $13 million of the $158 million was spent in the first quarter on acquiring additional leaseholds respective for either 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 7.75% senior notes, and $297 million of our 8.375% senior notes. We have nothing outstanding on our bank credit facility, which has an 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 in new 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 prospective 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 show 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 prospective. 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.

On 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 five 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 Bossier Shale wells. Since we initiated the 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 count, and showed that 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 contains 18 Haynesville wells and 11 Bossier Shale wells. The backlog at 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 the dedicated crew that we currently have, we expect to work out the backlog by some time 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 93 wells to date is 37 days. The average drill time for our first wells was 51 days, compared to 33 days for our last five wells. We expect the average drill time of future wells to 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 and Toledo Bend South areas, and three wells for Mansfield. We are also drilling one well at Waskom in East Texas. We are 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 two successful Eagle Ford Shale wells in McMullen County in the first quarter. On slide 23, we outline the Eagle Ford Shale play in South Texas. As stated previously, we drilled the 2 wells in McMullen County in the first quarter, and we also completed our well drill in Karnes County -- that well that we drilled in Karnes County last year. Since end of the quarter, we have finished drilling another well on the Wheeler Ranch in McMullen county, which will be completed later this month, and have started drilling an additional well in McMullen County.

The Carlson #1 was drilled in the oil window of McMullen County to a vertical depth of 9,070 feet, with a 5,874-foot lateral. We put 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. The Swenson #1 well was also drilled in McMullen County on our Wheeler Ranch acreage in the condensate window, to a vertical depth of 11,150 feet with a 6,118-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 have also completed the Coates A #1H, which was drilled in 2010 in Karnes County to a vertical depth of 9,706 feet with a 5,422-foot lateral. This well was tested at an initial rate of 507 barrels of oil per day and 0.2 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 additional acreage in McMullen County. Given the excellent result of our most recent well, we are excited about the potential of our acreage in McMullen County, and plan to continue to expand our holdings in this area.

On slide 24, we outline what we expect to spend this year on our drilling program and on our acreage acquisition. With recent efficiencies achieved in the Company's Haynesville and Bossier Shale program in Northern Louisiana, both in shorter drilling times and in completion times, we have recently revised our capital expenditure budget for 2011 to reflect increased activities, as well as affected expenditures, to increase our exploratory acreage primarily in the Eagle Ford Shale trend in South Texas. We now expect to spend approximately $570 million for drilling and completion activity this year, and an additional $40 million on lease 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 Northern Louisiana region in 2011; and 21 net wells on our Eagle Ford acreage, targeting primarily liquid hydrocarbons.

I will 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.

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 the Eagle Ford, which Mark will answer. But I'd asked Roland to put a slide together for this internal finding 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 of our offshore properties, through the end of last year, we've 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 this 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 4-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 through 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 -- in summary, I refer to 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 a strength in this period of low gas prices. We saw 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 and the condensate window in 2011. During this period of weak natural gas prices, the 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 have reduced the rigs we are using from 7 to 5, and have the flexibility to release another 1 early this year. We've had to make commitments 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, with $500 million available on our bank credit facility, and $81 million in marketable securities to supplement the cash flow we will 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 followed the stock.

Marissa, turn it over to you.

(Operator Instructions)

Leo Mariani, RBC.

Hi, good morning, guys.

Morning.

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

This is Mark. In the Haynesville, we're probably between $9.5 million and $10 million on an average well cost. And 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 to $8.5 million range. Still working that number down from there.

Got you, all right. And I wanted to get a sense of how some of your Eagle Ford wells have held in there? I guess you got four 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 tight curve somewhat and we're still monitoring that. It's early on these wells and we're still evaluating, but we're pleased with the decline so far.

Okay, and you have those wells on pumps, I imagine. Can you maybe give us a little bit more color around how they performed better than the decline curve, maybe quantify that at all for us?

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

Okay, got you. Just one last 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.

This is Roland. 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 nonoperator in our 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. Would there be a couple more of those potentially on the schedule for this year?

I don't know if we're really sure because it's really up to the operator on the timing.

We don't have any pending AFEs for granite wash well right now.

Okay. Thanks, guys.

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, it's about $9 million, we're $9 million, $9.5 million. Those were similar numbers that we gave out last time. And the goal in Eagle Ford, we're treating the Eagle Ford like we treated the Haynesville. We wanted to drill a well in each of the counties -- Atascosa, Karnes, McMullen. And you noticed that we focused on McMullen. We've got another well TD'd, and we're drilling another well, as Mark said, in McMullen currently. And the acreage in Karnes County, since it's a couple thousand acres, we did think we'll probably be able to trade it and add to our McMullen acreage. And our budget as far as leased budget, a lot of that is to add Eagle Ford acreage. So, that's to clarify some of your questions.

That's very helpful, Jay. And as a quick follow-on to that, you said you had a couple thousand acres in Karnes. How much do you currently have in McMullen?

I'd say 13,000. Out of the 18,000 net, it's probably 13, 14,000. It's a [key].

Thanks, Jay.

Thank you.

Kim Pacanovsky, MLV.

Hi, good morning, everyone.

Hi, Kim.

Hi. I was wondering, Mark, if you could talk about some of the completion issues you've had on a few wells. Obviously, there's a big difference in the IP rate between the Swenson, which was a very strong well, and the other two wells drilled in McMullen County. And I realize that the lateral lengths are a little bit different particularly with the Rancho Tres Hijos. But if you could talk about some of the issues you've had, is it some stages not coming off, and what kind of attack you're taking to solving the problems and have you had any issues staying in zone?

Kim, on the initial well, on RTH, we 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 control in the 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 for 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 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 got some benefit from that. I think all of those things together.

Great. Have you thought about the Buda potential in your acreage.

We are monitoring what is going on, but we have not evaluated the Buda yet. We do get information when we drill the pilot holes and we log through the Buda and get that data. And we'll monitor what some of the other operators are doing, but we have not really evaluated it.

Okay, and finally, what are the leasehold commitments that are remaining in the Haynesville, Bossier?

We had, Kim, at 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 all of our acreage for 2011, 2012. We might have commitments starting back in 2013, but we won't have any commitments that I'm aware of in 2011.

2012.

I mean 2012.

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?

In terms of source, yes.

No, we've been able to drill our Carrizo wells to get our source water and this time, and everything has worked out fine.

Okay, super. All right. Thanks and congratulations on a very strong quarter.

Thank you, Kim. I thought you were going to ask choke size? (Laughter)

Michael Bodino, Global Hunter Securities.

Good morning, gentlemen.

Hi, Michael.

I just had a couple of quick follow-up questions. I may have missed something switching conference calls here, but Roland, can you give us a little color on the exploration expense. Why it was so high for the quarter, and then your thoughts on the expiration expenses going forward.

Sure, Michael, included in expiration expense is an impairment that we took on mainly our Haynesville lease position. As we're coming to the end of the initial three-year terms of these leases, there are a handful of leases in kind of straggling areas. I'd say a lot was either Shelby County, Texas or Caddo Parish that we don't see -- it's on the marginal part of the Haynesville. So, we went through and did a process of scrubbing down the acreage, and said these are going to probably expire without us drilling. So, that's what that $9.5 million charge really is in the quarter which shows up in expiration expense because it was for unevaluated properties, but it's actually more of an impairment.

So, on a go forward basis, we really don't see very much in expiration 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 any more, so we don't have much of that in exploration expense. So, hopefully we can continue to do that.

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

I don't think I have that number right on hand, but I think the Eagle Ford -- what do you think the Eagle Ford averaged about? A lot of wells, like the Swenson well didn't come on production until the second quarter really. It's not a large percent. It's a good percentage of the oil there because we didn't have hardly any oil there before.

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

I'd say about 20% of our South Texas production is now Eagle Ford, on a quick calculation.

Okay.

We averaged about 1,000 barrels a day for oil production in the South Texas region in the quarter.

Okay. One last question and I'll jump back in the queue. Relative to doing an acreage swap in South Texas, and you end up exceeding your core position in McMullen County. Would you contemplate moving more aggressively in terms of a drilling program there, that you can put petrol production facility then?

I think our goal is to move a second rig, which would be rig we have in the Haynesville, to the Eagle Ford probably next month or in 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'd probably 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 and the frac crews and even our position in Eagle Ford. If we drill 21 gross wells it's actually a net number too, because we own 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'll be based totally upon commodity price, really, and performance of the wells that we drill in McMullen, particularly 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'll 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. You noticed we did add dollars for leasehold costs because we did plan on adding some acreage if possible in Eagle Ford play.

Very good. Thank you, guys. Great quarter.

Thank you.

Brian Corales, Howard Weil.

Hi, guys, how are you all today?

Morning.

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

Yes, Brian, this is Roland. 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 divestiture, especially the offshore divestiture, which the shares we have in Stone Energy are really just part of those proceeds. 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 some. But I think what we've been trying to do this year is develop the ability to grow on the oil and liquids side. And that's with 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.

That slide was really to show you, visibly, that we intentionally have recreated the Company. We didn't sell Bois d'Arc because it was a distressed sale to Stone, we sold it because it was the right thing to do. We weren't one of the companies that purchased at market peak, we didn't do that either. And then I don't think we're a company that became reckless by drilling wells in the Haynesville prematurely. We drilled one net well in the Haynesville from '08, we drilled 43 in '09. 72 last year, and we'll drill our share this year.

That slide shows you that we are running this Company based upon a per share stock appreciation and we haven't issued equity or had any off balance sheet type financings in order to create the transaction that we've accomplished. We've added the Eagle Ford at the right price. And like Roland said, in 2012, we should exit this year with 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 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'll 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, 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, could you maybe comment about where -- what your current production is and what your current oil production is?

The -- 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 two. So, probably won't have a significant impact for the second quarter coming up. But we do have a lot of production that is concentrated out of our Logansport area especially, it's our largest producing area and a regional problem like that can affects us, but hopefully the weather gets calmer out there the rest of the quarter. So, that's more or less the -- that's the total equivalent production. I don't really have a current breakdown on the oil, but it's probably up. And Mark probably has it here.

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

Okay. All right, guys. Thank you.

Thanks.

John Freeman, Raymond James.

Good morning, guys.

Morning.

I just wanted 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 looking at the net wells drilled, 50 wells roughly. It was 50 last time, and it looks like the carry over impact from 2010 is within about 5 million of what you all previously said. So, I'm just trying to get a sense of what the new number of completed wells is for 2011 versus what you all were budgeting.

And basically there were virtually two new net wells in the Haynesville program that are in that budget versus the other one. So, it doesn't sound like a lot but the wells, at $9 million to $10 million, they add a lot of costs. Some of those are nonoperated. 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 would be completed.

And this new budget assumes that for the most part they will because we see our dedicated crew -- as we get to the fourth quarter, it's going to be almost looking for work. So, we don't see that we'll have any delays at all. So, we're going to have our -- we'll be down to 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 as 10-plus wells to the next year to be completed. And since more than half 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, hasn't changed much at all. And then we added the $40 million as we see opportunities to acquire leases that we didn't really think we even have in the Eagle Ford in the area that we want to focus in. We feel like that money will get spent. So, we wanted to get that in the budget.

Remember we had budgeted for this dedicated crew to complete about four wells per month and in fact they completed about six wells per month. As Roland says, they're very efficient and effective and the production rate shows that.

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 four wells completed a month, it's now six.

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

Right, and these are 100% owned wells.

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 year.

Where last year, services prevented us from getting 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.

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 two rigs, here in the Eagle Ford mid-year, to adding a third rig at some point with just the infrastructure. Can you just give the update? Is that still the case that would prevent you from being able to add a third rig sometime later this year?

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'll enable us to look forward and bring a third rig in. Whereas right now, with our acreage count, we're pretty comfortable with the two 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 two large oil haulers and we expect that problem to be minimal for us.

Great, thanks, guys.

Thank you.

Noel Parks, Landenburg Thalmann.

Good morning.

Morning.

Just a few questions. You mentioned in the press release and you've touched on it a little bit over the course of the call. But you're improved efficiencies in the Haynesville, just now you talked about some of that is the frac crews working faster than you expected. Can you give me an idea of maybe what we might see the unit cost trend looking like, say lifting cost or a total LLE 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 costs. That was not just the Haynesville. It was also the -- we removed our very highest cost property. That's one of the reasons 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.

Now, that number is different -- as the Eagle Ford becomes more and more -- there's more and more oil production from the Eagle Ford, it's going to be the opposite of that. That's going to be a higher cost production to handle because we have both the oil storage, oil handling, and also some water disposal. 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 Eagle Ford additional cost. But I think it's something for next year. I think we'll probably drive down to a very low lifting rate, but then we'll start to have to see that increase, especially for 2012 if we focus on the oil side. The converse is you'll have much higher revenues to offset that.

Then for Haynesville lifting costs, where do you think on a unit basis the trough quarter might be? Do you think it'll actually fourth quarter or do you think third will be kind of --?

It will be the lowest because it's going to be -- we think that will be our very largest production quarter.

I'm sorry, you said fourth quarter?

Yes, fourth quarter. We'll continue to see a build -- unless we have some sort of disruptive event or trends change. But we expect to see the fourth quarter be the largest production quarter from the Haynesville and then it all will depend on our budget for 2012 how much we devote to that area.

Okay, great.

And 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 volumes there and the more volumes and the higher percentage the Haynesville makes up, the little larger that will look. But it's more than offset by the savings in the fixed cost. And production taxes will continue to be fairly -- very modest this year because most of the new wells in the Haynesville are exempt initially from production taxes for their first, up to a two year period. So, until the Eagle Ford becomes a bigger share of the production, where you're going to have oil have higher production tax rates, plus it's not exempt. You'll see those numbers getting better and better.

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 to come down to as fast as it'll be or you think we'll still see a little bit more improvement by the end of the year?

I think we've squeezed most of the improvement in efficiency out of the drilling side of the equation. And we should hold pretty flat at that 33 from here on.

Okay, great. And also, you have 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 contrast between say your earlier wells, like say the NWR well and the most recent ones? I guess, you've more or less been heading south and east. Just the differences in the geology as you've headed into McMullen, and if you could talk about just variability of the rock and what that means for how important or how difficult it will be to site wells going forward.

I had said earlier, I'll give an overview and then let Mark comment. Remember our goal, if you look on slide 23, the middle of the condensate window as we've drawn it is our Wheeler Ranch. Now, we didn't drill our first well in McMullen. We drilled in Atascosa and that's shallow oil. And then we went to the Wilson-Karnes type area, and 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 that 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, when you have a big ranch like the Wheeler Ranch, it's probably a 40 page lease, and you have to work with the land owner/ middle owner to find out where you can drill these wells. And we finally were able to get our locations in place. And the type of wells that we've hit on the Wheeler Ranch are really the type of wells we expected to have this 400,000-barrel recoverable per well. As we said during this meeting, we've finally progressed to the point where we drilled enough wells in all of these areas where we're 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 on our 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 up at the NWR in Atascosa and we're down at 10,500 depth on our Swenson acreage. That just provides a lot more energy to drive the oil out of this tight rock. 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 that we have to contend with or watch for. But nothing extreme, and we think they're going to be pretty similar.

Okay, great. I think that's it for me. Bye.

Thank you. Marissa?

I'm sorry for the technical difficulties. Ron Mills, Johnson Rice.

Hi, guys, good morning.

Hi, Ron.

A couple questions, on the frac services you talked about your frac crew, you have a dedicated crew, but you may be working through most of the backlog by the fourth quarter. Is that crew somewhat fungible 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 you worked through your backlog sooner than expected.

The contract is flexible after mid-year, in that we can renegotiate portions of it and they can 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 be to release the crew part of the time, later in the year if we don't need it, and have them undergo -- look for other work. They have also talked about maybe taking it down south to the Eagle Ford like two weeks at a time or three weeks at a time to catch some of our work down there, but we haven't committed to that at this time.

Remember, Ron, Schlumberger is a dedicated crew and we have a different crew on the Eagle Ford right now.

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 couldn't handle an increase from me going from one to two rigs.

What we've signed -- we've signed an agreement where on a one rig program, we had to have a frac crew for any wells in the Eagle Ford that we would drill based upon a one rig program. And then if we move a rig over, 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.

Okay.

We internally don't think that we'll have a fracing crew issue right now, either in the Haynesville, Bossier, or in the Eagle Ford.

Okay. And just to clarify, the leasing you've done year to date, the $13 million, is that -- it looks like that's been mostly in the Haynesville so far? Is that correct?

That's correct, Ron. $3 million of that is capitalized interest which of course just goes to all the leases in general, it's just more of accounting. The balance of that, the $9 million or so, is leases that we acquired early in the year. Mostly it's Haynesville, Bossier acreage. A lot of it's around our Toledo Bend South area.

It's a couple thousand net Haynesville and like a thousand net Bossier. That's where we ended up.

Okay. 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 the Eagle Ford. And if so -- 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 40% or 50% or 75%?

The $30 million or so that's remaining in the budget, we paid about $4,300 per acre for the acres we own today in Eagle Ford. Of course, it goes anywhere from $6,000 to $10,000 to $14,000 to $15,000 an acre depending upon if it's outright 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 spent those dollars doing that. It may be less than that. We're not putting a dollar 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 see any tier one acreage in the Haynesville Bossier coming open. We think most of that or all of that will be HBP'd by the middle of this year, which we're almost there. Now, there's tier two acreage and tier three acreage or whatever, that'll be open 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, been really active 10 years, got great reputation. We spend our own money drilling wells. So, I think we'll be afforded the opportunity to pick up that acreage.

Okay. And then Jay, you mentioned earlier, once you spend less on leasing and don't have the carry over. If you generate $400 million to $500 million of operating cash flow that, that's -- be pretty similar to what your CapEx would be, and that you had mentioned a two to three rig program in the Haynesville. Just given the way your ramping production over the course of this year, and if you go down to just a couple of rigs in the Haynesville, is that sufficient to be able to offset gas declines? Or would we see start to see some gas declines which would then be, from a revenue standpoint, made up for via growing Eagle Ford oil?

I think what we'll do, Ron, looking at the next year is, we're not tied to having production from the Haynesville have to be on a certain growth path. It's going to be -- we'll look at the resources, if we can -- should be able to afford a five 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%. We're going to look at what can you grow revenues by and allocate the resources that way. We're not at all focused on trying to maintain a certain production level in a particular region. We developed the Eagle Ford in the shale area to give us alternatives and higher return projects. In the end, we'll allocate the capital next year to where we have the highest return projects in our portfolio. If oil and gas prices are not in the same relationship, it may not go to the Eagle Ford. 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.

Right.

But I think that's at slide 25. What slide 25 tells you is that from '08 through 2011, four years, we're where we'd we be hopefully at January 2012 we will have completely proven up what we think is the good and bad part of the Bossier, the Haynesville. We'll completely be comfortable with the Eagle Ford. We'll have HBP'd our acreage in East Texas/North Louisiana. We should have phenomenal production growth. We already are at a new record high on short production level today and we have a lot of wells. We own 100%. They're tier one wells that'll be fraced by this slumber jay crew, which they're doing a great job at that.

I think we're just at the tip of the iceberg on what we're doing in 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 a third or half or a quarter, 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 almost -- it's amplified to the better. And even if I 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. We're focused on that, and I think we're doing it the right way.

Okay. That was one of my last questions, you look at the gas production mix. I think in the past you had talked about 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 Haynesville. It seems like if you might exit, you said 8% to 10% liquids, but the average will still be pretty similar to the first quarter just 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, that's -- the good and bad about our production profile is we have so many tier one wells that carried over from 2010 to 2011. You already see this in the Haynesville Bossier, already see this big production growth. Even though we are, for our size company, we're growing our oil/condensate liquids portion pretty material for us. But it is -- it's kind of dwarfed with the tight production we have from the Bossier and the Haynesville gas that's coming online even though we're a low cost producer in that area. But I think that'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, as we start adding more and more rigs to the Eagle Ford and McMullen County hopefully. You'll see a greater percent of our production be the oil/condensate, which we feel pretty comfortable about that.

Okay. And then, I don't know if it was you, Jay, or Mark that mentioned talking about EURs. I know you target 400,000 barrels. Some of your early wells may not have gotten there 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, 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 at what we believe, we feel comfortable with that projection at this time on the McMullen County acreage.

Yes.

And can you describe what's going on from a well restriction standpoint? There aren't as many people restricting liquids wells, I don't think. And how is that lower IP rate but shallower decline play into that whole EUR picture?

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

Great. All right, guys. Thank you very much.

Thanks, Ron.

Dan McSpirit, BMO Capital Markets.

Gentlemen, good morning.

Morning.

You spoke about adding about 5,000 to 10,000 net acres in South Texas, in the Eagle Ford. That is 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 could give you a specific number on that. I think you have to look, is it closer to the dry gas window, is it closer to the shallow oil window, is it right in the middle of the condensate window? Are you closer to Mexico. Are you closer to Gonzales County. This thing is what, 200 miles long and 50 miles wide. We have an appetite for more acreage within this quote, condensate window that our G&G group feels comfortable with. We stuck out a budget there because there as a stockholder you need to know what our budget is. Our goal -- we might not add one acre.

We really can't give out numbers.

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 thousand acres? And the terms of that trade, would it be one for one?

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

Correct.

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 might deviate one or two wells, but no, I'd say 90%-plus 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?

No, 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.

Very good. Thanks again.

You bet. Thank you.

Rehan Rashid, FBR.

Roland, on the LOE per unit, as we ramp up Haynesville, what is a good kind of number to think about as we exit the year, on a corporate level?

I think that on an overall corporate level, where we had the $0.90 this quarter. It can improve a little bit by the fourth quarter, but probably down to the mid-80s. I'd still say it gets to be maybe $0.85 or $0.84. A lot depends on how South Texas and other factors come into play because we'll have increased costs from that area at a higher rate but then as the Haynesville was coming out with so much production, it's kind of overwhelming that. Again, most of our new costs from the Haynesville is only going to be mostly in transportation costs. We're not going to have a lot of additional field costs or severance taxes to go along with that production.

Got it. And haven't tested the Buda yet, but any plans to?

Not at this time.

Okay, thank you.

Jack Aydin, KeyBanc Capital Markets.

Hi, Jay. I know who is your favorite. But definitely not me.

We saved the best for last or the worst for last, how does that work?

(Laughter) Yes, most of my questions were answered but I got a couple of ones. A, you got some other operation like in San Juan and Mid-Continent. Are those assets are for keep or --?

They would divestiture candidates with their natural gas. And we don't think the market is 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 do you think your inventory by year end -- you think you will have some inventory wells by year end 2010, or are you going to be caught up completely?

Virtually they caught up completely other than whatever operationally you couldn't get to. There might be a well or two in -- but I think we'll be trying to find some work for our completion crews maybe toward the ends of the year. So, we'll definitely let -- they'll 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 out of period costs. So, hopefully that part is out of the equation. And then we get down to a range that we'd like to see it. The normal range for us would be, for even this year, would be $115 million less. So, next year should be close to that level and hopefully we'll have some -- looking to 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.

Okay. Thanks a lot. Good quarter.

Thanks you.

Chris Pikul, Morgan Keegan.

Hi, thanks Jay. I just wanted 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 in the, broadly speaking, the liquids window, but the oil yield is still seems very high. Does that make you rethink at all where the play becomes more or less oily? Are we thinking about right in terms of north, south?

This is just a very general map. And it doesn't -- things don't break from oil to condensate to dry gas, it really grades as you go down. So, I think that in the true definition of condensate, that area is probably much, much narrower. But we correlate high geo ore 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.

Yes, it does. Looks like a great well for you guys. Thanks again. Congratulations.

You bet, thank you.

Patrick Rigamer, IBERIA Capital Partners.

Good morning, guys.

Morning.

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 we look out into the 2012 with the natural gas strip kind of getting above $5, call it $5.25 range. I know you guys get asked this a lot, but do we start to think about layering in some hedges or is there a price at which that becomes attractive?

On the budget one, I'll answer that. What I said is, you take your exit rate which should be up, again, 30% to 36% versus this year, and then you take whatever commodity price stake you have. And maybe it's $100 oil and $5.50 gas, I don't know, but that's where I come up with this kind of imaginary $400 million, $500 million. It is whatever it is, based upon the commodity price and our production rate. So, that is what I've said, Roland said, we're try to keep the 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 we would, with oil at very high levels, I could see us wanting to hedge that, some of the high oil prices. Again, gas, if gas was at attractive levels, we might consider hedging now that the Haynesville program has become so predictable. We would not hedge anything that 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 the IPAA meeting and other meetings, that if we've got a four, five, rig program in the Haynesville Bossier, whatever. It's a predictable program, it's an announced program, and we know we're going to 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.

Okay.

We wouldn't lock in low prices. And we would not look to hedging to be the answer to prices, I think it's a -- 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 and adapting to the environment versus trying to force the environment to adapt to our plans.

Okay, that's it. Thanks a lot, guys, and congratulations on a good quarter.

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, it's an hour and like 20 or 30 minutes. And those of you that stayed from beginning to end, we are very thankful. Again, we try to put in a good day's work to create value on a per share basis. I think Mark's a great addition to the team. He's been here 15 years. He's now stepped up to VP of Operations, and I expect great things from him. I think he 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.