Comstock Resources, Inc. (CRK) Q3 2011 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Third Quarter 2011 Comstock Resources Earnings Conference Call. My name is Jennifer, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Jay Allison, President and CEO. Please proceed.

Thank you, Jennifer. And welcome to the Comstock Resources Third Quarter 2011 Financial and Operating Results Conference Call. 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 Third Quarter 2011 Results. I am Jay Allison, President of Comstock. And with me this morning is Roland Burns, our Chief Financial Officer; and Mark Williams, our Vice President of Operations. During this call, we will review our 2011 third quarter financial and operating results, update the results of our 2011 drilling program and discuss our plans for 2012. Please refer to Slide 2 in our presentations. And note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you'll turn to Page 3 of the presentation, this is the 2011 third quarter highlights. Please refer to Page 3 of the presentation where we will summarize the third quarter results. We have improved our financial results this year despite weak natural gas prices by increasing production and lowering our operating cost. We reported revenues of $119 million, generated EBITDAX of $94 million and had operating cash flow of $86 million or $1.79 per share. The gain we recognized from selling some of our Stone Energy shares allowed us to make a slight profit this quarter of $1.3 million or $0.03 per share. Our production increased 53% over the third quarter of last year and 8% over our strong second quarter. The Haynesville program is driving the production gains this year, as we have caught up on completions of wells we drilled in 2010, but were not completed due to the lack of frac services. We're very pleased with the results of our 2011 drilling program this year. We drilled 67 successful wells, including 51 Haynesville shale wells and 12 Eagle Ford shale wells. In the Eagle Ford, we have probed up our acreage in this oil-rich play and have increased our holdings to 28,000 net acres. Our dedicated completion crew started working in South Texas in the third quarter. We put 4 new Eagle Ford wells on production and are currently completing 5 more. Our balance sheet continues to be very strong. We continue to have good liquidity and currently, have approximately $460 million in cash or marketable securities, available borrowings on our credit facility. We will also talk about our preliminary plans for 2012 on this call, when we plan to fund our drilling program with operating cash flow to protect our strong balance sheet. I'll turn it over to Ronald Burns to review the financial results for this quarter in more detail. Roland?

Thanks, Jay. Slide 4 in the presentation shows our oil and gas production on a daily basis for the last 15 quarters, and it's broken out by operating region. Production from our Haynesville shale program is shown in blue on that chart. In the third quarter this year, our production averaged 285 million cubic feet of natural gas equivalent per day, a 53% increase over the third quarter of last year and 8% higher than the production in the second quarter of this year. The production this quarter set a third consecutive new record high for us. Haynesville production increased to 200 million per day, as compared to 176 million per day in the prior quarter. Production from our Cotton Valley wells decreased a little this quarter to 38 million a day, and we averaged 40 million in our South Texas region and 7 million in our other regions. Looking ahead, we believe our production will come in between 94 and 97 Bcfe in 2011, which represents a 28% to 32% growth over 2010's production. During the fourth quarter, our completion crew worked primarily in our South Texas region and our Eagle Ford program and returns to the Haynesville in late December to complete 9 wells in a 10-well pad development project. As a result, we expect fourth quarter production to decline by about 2% to 4% from our high third quarter level and then increase substantially in the first quarter of 2012 when this project is put online. Oil prices continue to be strong in the third quarter, which we cover on Slide 5. Our realized oil price increased 35% in the third quarter of 2011 to $87.50 per barrel, as compared to $64.97 per barrel in the third quarter of 2010. For the first 9 months of this year, our average oil price was $92.50, 39% higher than our average oil price of $66.54 for the same period in 2010. Our realized oil price in the third quarter has averaged 98% of the average benchmark NYMEX WTI price. We expect our oil price differential to improve in our Eagle Ford program as much as $5 a barrel based on new marketing arrangements we are making, as we've been able to capture some of the spread that exist between the WTI price in the Louisiana Gulf Coast market. Natural gas prices worsened in the quarter, as shown on Slide 6. Our average gas price decreased 4% in the third quarter to $4.9 per Mcf, as compared to $4.24 in the third quarter of 2010. For the first 9 months of this year, our average gas price decreased 10% to $4.09 per Mcf, as compared to $4.55 per Mcf for the same period in 2010. Our realized gas price is averaging 97% of the average NYMEX Henry Hub gas price. On Slide 7, we cover our oil and gas sales. Driven by the 53% production increase, our sales increased by 50% to $119 million in the third quarter. For the first 9 months this year, our sales increased 16% to $320 million, as compared to $277 million for the same period in 2010, as the weaker natural gas prices offset some of the production gains we've made this year. Our earnings before interest, taxes, depreciation, amortization and expiration expense and other noncash expenses or EBITDAX in the third quarter increased by 72% to $94 million, as shown on Slide 8. For the first 3 quarters of 2011, EBITDAX increased 25% to $246 million. Slide 9 covers our operating cash flow. The stronger revenues in production and lower per unit cost caused our operating cash flow for the quarter to increase 81% to $86 million, as compared to the $47 million we had in the third quarter of last year. For the first 9 months of this year, operating cash flow was $219 million, 25% higher than cash flow of $175 million for the same period in 2010. On Slide 10, we outlined our earnings for this quarter and for the first 3 quarters of 2011. We reported net income of $1.3 million this quarter or $0.03 per share, as compared to a loss of $4.7 million or $0.10 per share in 2010's third quarter. For the first 9 months of this year, we reported net income of $7.7 million or $0.16 per share, as compared to net income for the first 9 months of last year of $1 million or $0.02 per share. The third quarter results include a gain of $2.5 million or $1.6 million after tax or $0.04 per share that relates to the gains on the sales of our marketable securities during the quarter. The 9-month financial results include several unusual items. We had a charge of $1.1 million or $0.7 million after tax or $0.02 per share related to the early redemption of our 2012 senior notes in the first quarter. We also had a $9.8 million impairment or $6.4 million after tax or $0.14 per share for expired leases, and we had a significant gain from the sale of our marketable securities made so far this year of $32.2 million or $20.9 million after tax or $0.46 per share. On Slide 11, we show our lifting cost per Mcfe produced by quarter. Our lifting costs are comprised of 3 components: production taxes, transportation and then other field level operating cost. Our lifting costs continued to improve falling to $0.79 per Mcfe this quarter, as compared to $1.17 per Mcfe in the third quarter 2010 and $0.85 per Mcfe in the previous quarter. Production taxes were only $0.01 this quarter, and transportation averaged $0.31 this quarter. Refunds of production taxes previously paid lowered the taxes we had this quarter. Field operating costs averaged $0.47 per Mcfe this quarter, as compared to $0.75 at the third quarter of last year and then $0.51 in the second quarter of this year. Higher production in the Haynesville, combined with the absence of the high-cost properties we sold in the fourth quarter of last year, are allowing us to achieve the lower lifting rate. On Slide 12, we show our cash G&A per Mcfe produced by quarter, excluding stock-based compensation. Our general and administrative expenses decreased to $0.18 per Mcfe in the third quarter, as compared to $0.29 per Mcfe in the third quarter of 2010 and $0.21 per Mcfe in the previous quarter. The improvement is due to the higher production level, combined with the lower G&A cost in 2011. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 13. Our DD&A rate in the third quarter improved to $2.96 per Mcfe, a decrease from the $3.12 rate we had in the second quarter of this year, but it's an increase from the $2.72 rate we had in the third quarter of last year. On Slide 14, we detailed our capital expenditures. We spent $496 million in the first 3 quarters of this year, as compared to the $393 million that we spent in 2010's first 3 quarters. We spent $344 million in our east Texas/north Louisiana region, with $146 million in our South Texas region and $6 million in our other regions. $53 million of the $496 million spent so far in 2011 was for additional leasehold in the Eagle Ford shale or the Haynesville shale. We expect to spend a total of $575 million in 2011 on our drilling and completion activities. In addition, we expect to spend up to $125 million on acreage acquisitions in 2011. The $24 million of this $125 million will be in the form of a drilling carry that will be paid by us over the next 2 years. Slide 15 recaps our balance sheet at the end of the third quarter. On September 30, we had $5 million in cash and $32 million in marketable securities on hand, representing the 2 million shares we hold in Stone Energy. The value of these shares has increased somewhat since the September 30 balance sheet date. In total, we have $747 million of debt, which is comprised of $300 million of our 7 3/4% senior notes, $297 million of our 8 3/8% senior notes and then $150 million outstanding under our bank credit facility. On October 31, the borrowing base for our credit facility was increased to $550 million. Taking into account the cash on our balance sheet and our marketable securities and our unused $400 million that's available on our bank credit line, we have about $460 million in liquidity. Our book equity at the end of the quarter was $1.1 billion, making our net debt about 39% of our total capitalization. I'll now turn it back over to Jay.

Thanks, Roland. If everybody will turn to Slide 13 -- or 16. On Slide 16, we have an updated map of our holdings in the Haynesville shale play in north Louisiana and east Texas. Our acreage in highlighted in blue. We currently have 90,000 gross acres or 79,000 net acres that we believe are prospective for Haynesville shale development. 59,000 acres are in north Louisiana, the 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 4.4 Tcfe of resource potential. Slide 17 shows the acreage that we believe also has potential for the development of the upper Haynesville shale or middle Bossier shale. Our acreage is highlighted in blue. We currently have 60,000 gross acres or 51,000 net acres that we believe are prospective. Given similar expected well spacing of 80 acres and expected per well recovery of 5 Bcfe per well, our acreage could have 2.4 Tcfe of resource potential. I will now have Mark Williams, our Head of Operations, give us an update on our drilling program this year. Mark?

Thank you, Jay. On Slide 18, we recap our activity in our East Texas/North Louisiana region for this quarter. Our activity in this region is primarily focused on developing our Haynesville and Bossier shale properties. We drilled 52 wells or 21.6 net in this region in 6 different fields in the first 9 months of this year, and all but one of those were Haynesville or Bossier shale wells. We participated in one Cotton Valley vertical well. All of the wells were successful. In the first 3 quarters of this year, we completed 65 or 35.7 net of our Haynesville or Bossier shale wells, which were put on production at an average per well initial production rate of 10 million cubic feet equivalent per day under our restricted choke program. Since we initiated our Haynesville shale program in 2008, we have now drilled a total of 169 wells, 99 net wells, soon to break the 100 mark. Slide 20 shows the first 2 units in the Logansport field, DeSoto Parish, Louisiana, where we are fully developing the Haynesville on 80 acres spacing. Section 22, shown on the left, is a 640-acre unit, which was put on production in July -- near the end of July. As you can see, we utilized 3 drilling pads to drilling and fleet the 8 wells, which increases our efficiency and reduces our overall well cost. This process also allows zipper fracs to be utilized, which is a stimulation method where all the wells on the pad our frac-ed with one frac fleet by alternating between the wells in a stage-by-stage procedure. We believe this method increases the effectiveness of the stimulations on the wells, as compared to frac-ing them one at a time. By completing all the wells before producing any of them, we think the ultimate recovery of the section will be maximized. The schematic on the right side of Slide 20 shows our sections 19 and 20, also on Logansport field, which are combined to form an 800-acre unit. Here, we are in the process of drilling 9 wells to develop the unit, as there is already one existing Haynesville producer. We will begin completion operations on this unit in late December and expect first production in early 2012. Our South Texas region is displayed on Slide 21. All of our South Texas activity in 2011 has been focused on our Eagle Ford program. We drilled 12 Eagle Ford shale wells, and that was 12 net also in the first 9 months of 2011. So far this year, we have completed 8 of these wells and 8 net, including a well drilled in 2010. And the 8 wells had an average per well additional production rate of 683 barrels of oil equivalent per day. We have 5 additional wells that are being completed by our dedicated frac crew at this time. We plan to all bring of these wells on at the same time to maximize the effectiveness of the fracs. On Slide 22, we outlined our Eagle Ford shale play in South Texas. We increased our holdings in the Eagle Ford to 32,000 gross acres and 28,000 net acres in this quarter. We closed on approximately 6,000 net acres in October in 2 separate transactions. Using a conservative 100-acre spacing assumption, we believe our acreage, which is all in the oil window, has the potential to recover 83 million barrels of oil equivalent net to our interest. We have 10 producing wells on our acreage, including 4 wells we completed in the third quarter. The Cutter Creek #1H was drilled to a vertical depth of 9,970 feet, with a 4,824-foot lateral and was tested at an initial rate of 575 barrels of oil per day and 0.2 million cubic feet of natural gas per day or 608 BOE per day. The Forrest Wheeler #1H was drilled to a vertical depth of 11,142 feet, with a 5,458-foot lateral. This well was tested at an initial rate of 480 barrels of oil per day, 0.7 million cubic feet of gas per day or 597 BOE per day. The Rancho Tres Hijos "A" #1H, on the map it's RTH "A" #1H, was drilled to a vertical depth of 10,911 feet, with a 4,512-foot lateral. This well was tested at an initial rate of 465 barrels of oil per day and 0.6 million cubic feet of natural gas per day or 565 BOE per day. The Jupe "A" #1H was drilled to a vertical depth of 8,282 feet, with a 7,101-foot lateral. This well was tested at an initial rate of 197 barrels of oil per day and 100.1 million cubic feet of gas per day or 218 BOE per day. The Jupe is our first disappointing well in the play, and it appears to be in a low pleasure area of the reservoir. This well will be the first well that we will put on artificial lift, and we expect the production rate to improve from the initial test rate when it's on pumped. The well is actually on pump as of the end of last week. It's still improving, and it's improved at least 50% from the test rate and is still cleaning up. All the reported of the well results were obtained while following our restricted choke program. I'll now turn back it over to Jay.

I'll go over the final 2 slides, which is the 2012 drilling program and then the 2011 and 2012 outlook. And then probably as group, we'll go back to the Slide 22, which is the Eagle Ford shale program. But if you go to Slide 23, we outlined what we expect to spend in 2012 on our drilling program. With the weak outlook for natural gas prices, we plan to reduce our spending level next year in order to line up with our spending with the cash flow that we think that we'll probably have. We plan to focus on our oil projects, as they do have the higher returns. In the Haynesville, we're reduced from 3 rigs to only 1 rig. In our east Texas/north Louisiana region, we plan to spend $104 million to drill 38 wells or 13.3 net wells. This includes 11 operated wells or 7.9 net wells, with the remaining wells representing our share of non-operated wells that we will participate in. We'll be carrying over 17 wells or about 14.7 net wells that we drilled this year to be completed in the first quarter of 2012. The cost to complete these wells is about $65 million. The rest of the budget is being spent to drill oil wells. We're planning to drill 32 wells or about 28.9 net wells on our Eagle Ford shale acreage. We have budgeted $221 million for our Eagle Ford program, which includes $14 million to complete 6 wells or 5.6 net wells that we'll drill this year. We have $6 million budgeted for our other regions. In total, we plan to spend $396 million on drilling in 2012, which should come close to being a 100% funded by our operating cash flow. We believe this program will provide 8% to 12%-plus production growth in 2012, with oil production growing from 5% in 2011 anywhere from 10% to 12-plus percent in 2012. To the extent, we have stronger natural gas prices, we do have the flexibility to ramp up drilling and out of the Haynesville or Eagle Ford programs. The final slide, which is the 2011 and 2012 outlook, is on Slide 24. We are having a very good year despite the low natural gas prices. Our production growth has been very strong. We expect production to increase by 28% to 32% over last year, with completion of the backlog of wells drilled in 2010. Our low-cost structure continues to improve each quarter, with a higher production level and drilling and completion efficiencies that we're now seeing. Our Eagle Ford shale program in south Texas is progressing. We have 2 rigs drilling on our Eagle Ford shale acreage, and we've increased our acreage holdings to 28,000 net acres and have achieved that at a reasonable $6,000, $7,000-per-acre cost. The market value for our Eagle Ford acreage is more than 3x our average cost per acre. During this period of weak natural gas prices, the Eagle Ford program gives us a high return area to grow our oil, condensate and natural gas liquids production. We continue to guard our strong balance sheet. We have $400 million available on our bank credit facility, and $60 million in marketable securities and cash to supplement the cash flow we will generate. We plan to spend approximately $396 million in 2012 for drilling and completion activities. We expect to reduce the number of rigs drilling for natural gas in our Haynesville shale program from 3 rigs to 1 rig. We will be adding one drilling rig during 2012 to the 2, which are currently drilling for oil in the Eagle Ford shale development program in South Texas. Our 2012 drilling program will focus much of our drilling activity on growing our oil production, while at the same time staying within operating cash flow that we should generate. To the extent that natural gas prices improve, again, we do have the flexibility to increase our drilling activity in either the Eagle Ford shale or Haynesville shale depending upon where we can generate the best returns. For the rest of the call, we will take questions only from research analysts who follow the stock. So Jennifer, I'll turn it back over to you to open it up for questions.

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

Can you maybe talk little bit more about the restricted rate in the Eagle Ford, maybe how the production looks over the first couple of months versus not restricting the wells as much?

Yes, Brian. This is Mark.

Everyone, you might want to go to Slide 22, which is the Eagle Ford shale program and maybe we can hit a lot of questions around the Eagle Ford and restricted rate and where the other 5 wells are drilled and what we expect in the future of those wells. Something like that, Brian. Is that okay?

That's perfect.

Yes, Brian. On the restricted rate program, we're following the same basic procedure that we've used in the Haynesville that we feel had been very successful. We bring the wells on, on a small choke and work them up to maybe about $14 to an $18.64 choke and maintain that steady choke size, monitoring -- pressure monitoring rate. Based on the evaluation that we've done of our wells versus offset wells, we believe that we're getting a pretty large benefit from the restricted rate program. The IPE rates that we report are -- would be pretty equivalent to 30-day rates because we don't see much decline in the very, very early life of the well for the first 30 to 60 days. They're still cleaning up, and they're still steady or improving. So these are -- the program is moderating the decline, and we feel like it's given us the best EUR.

And does this match your type curve on the 400,000 barrels -- assuming the 650 barrels a day that stays relatively flat for a month or 2, and does that match your type curve to the 400,000 barrels?

All right. Yes, it does. That's an average type curve. The acreage to the north is basically in Atascosa County is a little bit less than that. The acreage south, in McMullen is a little higher than that. So on average -- on a weighted average, with our acreage, 400 is a good number. The 400 really matches that 600, 550 to 650 IPE rate. And then the wells down to the south like the Hill #1, that had 1,095, that was going to be a good bit over the 400 MBOE number.

Okay. That was helpful. And just one final. What are you seeing now on the cost of the Eagle Ford, the completed well cost?

We're -- right now, we're still drilling on single well deals, and we're running $8.3 million to $8.5 million. When we get into our development program, and I think we'll see it on our Hill lease that we just finished completing and we get all those costs accrued, we'll see some improvement like we did in the Haynesville. And we expect to knock maybe $0.5 million to $750,000 million off of our average well cost once we do that. But we're still primarily drilling to test acres and hold leases.

I think with that same question, Mark. Why don't you go into the wells, the location of the wells that have not been reported on.

Okay. We have done one full lease development. It is on the Hill lease, which is the -- some of the southernmost acreage. We have completed 5 additional wells on the Hill lease to go along with the Hill #1, so it's a fully-developed 6-well lease. We have completed the fracs on the 5 wells, and we're currently drilling out frac plugs and starting our flowback, but it's just been going on for a few days. And we picked that area because the results were good. It gave us opportunity to perform microseismic on our wells, to gain some knowledge about the frac growth directions, things like that. And we're testing various frac technologies on that lease and to see which one we feel like gives us the best result. And we should have those results here by the next call, along with some others. We're also drilling a well near the Carlson. That well will be reported in the -- with the fourth quarter results and then another Cutter Creek well, which would be reported in the fourth quarter. We're really focusing mainly in the La Salle, McMullen area with our development activity. And then we'll be focusing next year on a lot of the new acreage that we've picked up.

I think that's an important piece of the story. In other words, you've seen 4 more, but there are 5 Eagle Ford wells, all at McMullen that are in various stages of completion. And I think if you were to see those, you'd be a little more pleased with the total results that we've shown you from before.

Your next question comes from the line of Ron Mills. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Question on the 6,000 acres added. I'm assuming that's the 28,000 is -- to get to that number that's what you added in October. Is that correct?

Yes, that's correct, Ron. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, great. And then looking at your map, you have -- that acreage looks like it was added some over in eastern Atascosa County, some in La Salle County, and some in the McMullen County. Can you -- and maybe Mark this is more for you. When you look at the trend, especially on that far eastern Atascosa County acreage, where does that land in terms of depth and/or pressure regime? Do you expect it to be more like the NWR well you drilled in Atascosa County or the Jupe?

This is Mark. That acreage, the way we put that on our maps and geologically, it should be very similar to our Cutter Creek and Carlson area, depth-wise, pressure. It's on trend to the northeast with well results like our Coates well, that have acted very similarly to the Cutter Creek and the Carlson. We haven't added any acreage up around the NWR and the Jupe since the very beginning of the program. I think that was the first block of acreage we leased. And then the early results in the area told us don't add any acreage up there until we can prove that we should. And that's why we drilled the Jupe well with a long lateral to try to support the idea of being able to add acreage up there because it's been available, and we've turned down a lot of deals in that area. We like acreage we've added in north eastern Atascosa. And like I said, it's on trend with our Cutter Creek, and all the results we see along the trend, we're very satisfied with. The other acreage was in -- the other bigger block was in La Salle, and there, again, it's right on trend with our Carlson and our Cutter Creek. And so we feel good about it also. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And if I look at -- if we look at your 2012 budget when you look at the 32 wells you plan on drilling in the Eagle Ford next year, can you sketch out, at least as you view it today, how those wells will be split between your McMullen, your Atascosa and your La Salle/McMullen County blocks?

Six of the wells are going to be on that -- at least planned right now, are going to north eastern Atascosa or that southeastern Atascosa block to hold that acreage. Almost all of these drilling is drilling under primary terms of leases. So we will be drilling to maintain our leases and hold our acreage. So 6 of the 32 wells would be up there. I believe about 10 of them are in that 4 corners area of the McMullen, La Salle, Frio, Atascosa, the Carlson area. The remainder are going to be the Cutter Creek area and then down in Swenson, Hill area to hold acreage down there. So about 2/3 of it is McMullen and the rest of it is on that 4 corners area and then 6 at the northeast. By the way, we don't have any more wells planned on our Jupe, NWR area at this time. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then when you look at the drilling plans. And can you do one derivative of that in terms of compare the drilling plans with the completion plans? I know you had a lot of carryovers this year. It sounds like you'll have some carryovers in both areas in the first quarter of this year. But when you look at next year's budget and even the remainder of this year in the Eagle Ford, you plan on drilling another 7 to 10 wells in Eagle Ford this year, 32 next. How many completions you do expect to get in the Eagle Ford?

I think it's going to be pretty much a one for one on our drilling plans. We're -- the carryover of the Eagle Ford wells here at the end of 2011 is mainly due to us taking our frac crew to the Haynesville to frac that 10-well pad. So that kind of drives the carryover, both of the Haynesville completions and of the Eagle Ford completions. We don't have any 10-well pads planned for next year because we're going to only have one rig in the Haynesville and it's going to be primarily drilling to maintain leases, and we have a little of some new acreage -- a little bit of new acreage we've picked up that we've got to drill couple wells on. We won't have any of that type of carryover activity next year. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then Roland one last for you. You mentioned on WTI price or your Eagle Ford pricing, a, your price realizations were higher than they had been relative to WTI in the third quarter. And did you say you expect that to further increase by $4 or $5 per barrel? And if so any more background on that marketing arrangement you're working on?

Yes, Ron. We didn't really see much of that improvement in the third quarter yet because those are new arrangements coming in the plays [ph] now. But I think for a lot of our November and December production and then first quarter next year, we're going to get a better pricing, priced $5 better than what we have been receiving in there for a lot of our Eagle Ford production. And we think that's kind of the start of a trend where we see that the oil in that area is -- a lot of people have been transporting that oil into Louisiana market by barges, by rail, by various means. And a lot of that capacity has ramped up there, they're now willing to start sharing some of those spreads with the producers. So I think that, that kind of continues into next year. And we're actually looking to try to price our -- we're hoping to be able to start doing our marketing there and price it off of LLS and not WTI. And so were working on that at this time. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then you're working, is this a kind of a 12-month marketing arrangement or is this almost month to month? Or how are you approaching that negotiation?

I think the -- I don't think we're -- I think to the extent, if we really like it, we might go to a longer term. But right now, typically, we do 6-months-type marketing arrangements.

Your next question comes from the line of Kim Pacanovsky. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Is that marketing arrangement for 100% of your crews?

Not at this point, no. It's a lot of new Eagle Ford production. I don't think 100% of it is in there yet. But I think it will be probably about the time we get into it next year. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay. All right. And Roland, when you say that virtually all of your CapEx is going to be covered by your cash flow in 2012, what kind of price deck are you using for oil and gas?

That's definitely variable because at a different day, you could come up with a different answer. But generally, we're looking at market prices at least last week. I don't know where they are today. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay. And I guess kind of to play devil's advocate. This is a conversation we've had many times about hedging, and I'm just wondering if you thought about hedging some of the crude, with crude prices so strong and there being so much volatility in world markets with a whole Europe thing going on. I mean, have you thought about putting a little bit of crude in hedges?

Yes, Kim. We definitely looked at that for the Eagle Ford program because of the need to have strong oil prices to support that program. Like we've been talking about, I think one of the problems is getting -- making sure that we can figure it -- get the differentials where, when we do hedge, we have a real hedge. And I think, there's -- with that change in the market there to the extent you have a WTI hedge in place, it may not be very good. So it may not be very -- so I think that's why we'd like to see some of the contracts price more like LLS, that's really markets going there. So I think all that's kind of working together, but we do have some target prices that we wouldn't mind locking in on the oil to support some of the Eagle Ford development. And then much higher -- better gas prices would support maybe adding a rate to the Haynesville. So we obviously aren't anywhere near there. So that's why we've been focusing probably on the oil. It makes a more realistic sense of [indiscernible] Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Absolutely. And that block that you were talking about in northeastern -- or actually it's really not, it's the northeastern part of your property in Atascosa, when will you put the first well in on that new block of leasehold? And also when will that 2012 rig arrive in the program, the new rig?

As far as that new leasehold on our northeastern property, southeast of Atascosa County. I think that the December move in date. We still got to get all the surface work done, settle with landowners and all that. But that's what we're planning on doing, just drilling the first well up there, very early and then looking at the results and then moving in midyear next year to drill the rest of them. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay. Just when the new rig is going to move in?

The new rig is scheduled to move in, in June. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: June? Okay, June. One more quick question. What was the 2010 average cost on the Haynesville wells? Just so we can compare that $8 million AFC that you're seeing now.

I think, it was about $9.5 million to maybe even slightly higher than that for 2010. We probably had -- it went up to as much as $10 million at one point or maybe near. And that's definitely improved a lot in 2011.

Kim, I think on hedges, too. We've said this before. Up until the end of 2010, we didn't have a shale play that we thought that you could really farm wells on them. We think we have years and years and years of drilling in the Haynesville, Bossier. So if you look at our balance sheet today, and you see we pulled back from 7 rig program now to -- we'll have a one rig program next year. And we're trying to drill within our operating cash flow, but I think that if prices go up and that causes us -- in other words, we had taken action because prices go up. If prices go up that cause us to add a rig or 2 out either in the Eagle Ford or in the Haynesville, Bossier, I think at that point of time, if you're going to commit to a rig for a year -- you can commit a completion crew for a year, then I think you could hedge that program. And I think for the very first time, again, we have that program in the gas window at the Haynesville Bossier. And I think now we'll probably have it in the Eagle Ford. So when you talk about hedging now, you're hedging program that you almost know the outcome of. So I think our attitude is different. Historically, we would hedge if we bought something. We didn't aggressively buy in '06, '07, '08, '09, '10 and even this year, as you know. There was acreage acquisitions or purchases, and it was the sell of Bois d'Arc et cetera. But I think the hedges are a little different now when you talk about a hedging program that you probably know the outcome of. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: But you could've hedged a program in the Haynesville that you knew the outcome of. I think ...

No, I don't think because we didn't -- we only drilled one well in '08. In '09, it was -- the middle of '09 until people quit drilling in Harrison County and you start drilling in DeSoto. And even if you look in '09, we've only drilled 42 wells, and they were spotty. We've drilled them kind of like in Eagle Ford. We drilled them in all 4 corners of acreage. Then you go to 2010. In 2010, that's when we drilled more Bossier wells. We drilled more Haynesville wells, and the bottom really fell out . So starting somewhere kind of in the middle of 2010, I think, at that point in time, you can say yes, you now understand your Haynesville Bossier acreage as the other industry partners do, so you can start hedging. But there's not been a period where you would see a $5-plus gas price to hedge. And so they were pulling the program back, not adding rigs.

Your next question comes from the line of Noel Parks. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Just a couple of questions. Thinking about the results of the Jupe well there. Can you talk a little bit about sort of what happens geologically as you move from sort of the south of that acreage block you have, where you have the NWR well about 400 barrels a day up to the Jupe. How did things change there? And are those metrics you can apply when you're looking at future acreage?

Noel, this is Mark. Yes, what we saw in the Jupe well was lower reservoir pressure. And it may just be that we're just far and up north from the NWR that we've gone from a slightly overpressured reservoir, to just a very slightly underpressured reservoir. And so the well wouldn't flow oil against a full column of water. If it was flowing back frac water, but it wasn't. No oil was coming into the fractures from the reservoir. As soon as we got the pressure down, just a few hundred pounds, we started making a fair amount of oil. And now we put it on this artificial lift system, we're making substantially more oil. So it's a little bit underpressured. We didn't expect it to be quite that underpressured, but one of the things we think is going on and we've seen along the play is that if you get too close to the Pearsall Austin Chalk production, which is just immediately above the Eagle Ford, that you could have issues with being underpressured. And we thought this well was far enough away because it's still several miles away from any Austin chalk production. But it may just be right on that feather edge of being affected by the Pearsall field. One of the reasons we haven't purchased any acreage that shallow or that far north, and we've really focused a little bit deeper than that and will continue do so based on these results. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: And sorry if you said this before. The new acreage block further north and east in Atascosa, it is deeper there?

That's correct. That depth and pressure is going to be very equivalent to our Cutter Creek. So if you kind of follow the direction of the color contour lines on our map and where it drops down to the southwest, that depth is very similar to our Cutter Creek and Coates wells. So we don't expect any issues with being under pressure at that location, as compared to the Jupe. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Got it. And I just had a question on the balance sheet. I wanted to check with Roland. Did you say that your bank credit line balance is $150 million right now?

That's correct, Noel. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: But the total debt $747 million, am I missing something? Because I thought the 2 -- your 2 high yields were less than $600 million together?

They are slightly less than $600 million, one's $300 million and one's $297 million. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Okay. So it's pretty close then?

Yes. This is what's on the bank credit facility. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Okay, great. And just a last thing. Could you talk a little bit about what your thinking is on unit costs next year, as your mix is going to change a bit on more oil from the Eagle Ford and then eventually a decline on the Haynesville? Just how the different cost lines will look?

Sure. As we look at next year, the first half of next year we see kind of a pretty big gas growth couple of quarters. And then after that, with the program kind of wound down in the Haynesville, we'll see -- that's where we'll see more our biggest oil percentage coming in. So I think these cost trend show up in the second half of next year not so much in the first because of all that gas is coming on in the first half of the year. If you look at our proposed budget and with the production growth targets and the change from 5% natural gas, 5% oil component to 10% to 12% oil, we would see the lifting cost increase a little bit on a per unit basis just because we'll have production taxes on oil. Production is not exempt like some of the tight gas projects are. And we'll have higher -- we'll have some higher overall fuel costs, but just the cost to move oil and store it and dispose of water are going to be higher. They're very little cost associated with producing a Haynesville gas well. But given the composition, we really see our lifting cost rate in the aggregate maybe going up $0.15 to $0.20 per Mcfe, with the result of that transition in 2012. We see the revenues per Mcfe increasing dramatically beyond that. So it's a much more, higher cash flow per unit of production with that production merit [ph] . So we would see revenues maybe increasing $0.80 per Mcfe, just use current spot prices today on that same production mix, with costs only going up a fraction of that. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Okay. And G&A, any significant impact on that, sort of as you had in the second half of the year? I'm not sure if there's...

G&A is relatively stable, and we expect higher production -- higher production rate in general next year. So that means it should be no higher than it is now, if not lower. The only pressure on cost would be on the lifting cost side. It would be pretty minor compared to the big growth in the revenues.

Your next question comes from the line of Leo Mariani.

How much acres do you guys have in that area where you drilled the Jupe and NWR wells?

Leo, this is Mark. We have about 5,000 acres in the Jupe and NWR area.

Okay. Is that a gross number or net?

That's a net number.

Okay. I guess, continuing that to add Eagle Ford acreage, obviously, you added some pretty significant acreage here in October, can we expect that to continue to grow going forward? And if you guys could just comment on how that might look within, say, 12 months from now.

Leo, this is Roland. We expect potentially that to grow by maybe a couple of -- about 2,000 more acres with stuff that we're currently trying to work on and hopefully close. So that's kind of more the immediate -- I think we would have to -- for next year, we just really -- to the extent of the opportunities that makes sense to us, we would add acreage. I think it's not easy to come by acreage in the area that we want to develop in the Eagle Ford. I would think that -- we're working on some other areas, other oil areas and, that's properly where we add acreage, more likely than the Eagle Ford. But we'll respond to opportunities that come available.

Okay. And could you guys just talk about infrastructure in the Eagle Ford? Are you guys getting into any pipelines? Are you just trucking your oil to kind of other pipelines? Or how are you guys kind of managing that process?

Leo, we're pretty much selling our oil at the well side. So it's picked up by truck, and then it depends on what our purchasers -- sometimes they're able to offload it in a pipeline. Sometimes they're -- some of it, they were actually moving by rail car and others to ultimately get it to -- transport it to the Gulf Coast markets, where they are trying to move all the oil because that's where they're getting the premium prices. But were not transporting -- we're not involved in actually transporting our oil at all. We're selling it at the wellhead.

Got you, okay. And there haven't been any issues with the trucks not showing up on time or anything like that? For the most part, you guys have been able to get it all sold?

Yes, not at all. Matter fact, we're improving our pricing now. I think the last couple months, we've seen a big increase in their ability to take the oil, and they're interested in locking up long-term supply. We see it a very good improving marketing area for us. We're located in kind of the center of the Eagle Ford here. And we really have very little gas to process, and we've had -- we're hooking up some of our wells and getting that gas processed now without any problem. But we really aren't going to produce a lot of gas in our program, from our program there.

Okay. I guess, in the Haynesville, you guys talked about $8 million well cost. Just wanted to clarify a couple of things. Is there any well costs when you're actually doing pad drilling there?

Leo, it's Mark. That's correct. That's development well cost.

Okay. And I guess just to clarify. In one of your other comments, I guess, did you guys -- if I heard you correctly, said that you're not really going to be pad drilling in 2012, more just moving the rig around to hold acreage. Is that right?

That's correct. Leo, we've got a few leases that we've got a drill a well or 2 a year on, so we're going to move the one rig around it. It's really difficult to do this full section development with 1 rig because if you put it in there, you're looking at completing one time a year. We’re going to forgo that until prices allow us to move more rigs in and then drill it more efficiently.

Okay. And what type of price do you think is reasonable or you could go more towards a multi-rig program with pad drilling there in the Haynesville?

We'll have a gas price probably north of $5. It's twofold: one, provide us the cash flow that we want to invest in here. But even with higher cash flow, we'll have to evaluate our return opportunities. And so we might -- if we had higher gas prices, we may add a rig to the Eagle Ford program versus the Haynesville just based on the ability to have a higher return. We have no real requirements to do other than what we're doing. We really don't have any requirements to keep our acreage intact. So we have no drilling obligations. So we're drilling -- 100% of the Haynesville will be drilled for return. So we just evaluated our return opportunities based on the cash flow we have available.

Okay. And you guys talked about going from 3 rigs in the Haynesville to one, is that kind of happening in the next couple of months? Can you just give us an indication of timing on that?

Yes, Leo. That's in January and February. We'll be releasing those rigs or redeploying them if we have a new opportunity.

Your next question comes from the line of Amir Arif. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just a few quick questions, one on the Haynesville. With your rigs sort of -- even though your rig count is coming down, your backlog is going up. Is that just related to the large pad drilling you're doing? Or is there anything else going on there?

Yes, Amir. This is Mark. That's all because we're drilling that 10-well section. All of our operated backlog, if you will, is because we have to get all the wells drilled before we frac them in December. The other is just there's a -- especially on the gross well count, there's a lot of activity, and it's very low working interest. So it kind of looks big on a gross well count, but doesn't affect the net very much. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then so it sounds like you should be caught up on the carryovers by the end of '12 on the completion side?

That's probably correct. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then can you give us a rough sense on how much of the 8% to 12% growth next year is due to carryovers from '11 versus sort of new drilling?

I don't think -- we could look at that and get back to you. I don't think we have a number off the top of our head. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then just going back to the previous question here in terms of what gas price would you add additional rigs and lock it in on the hedging side for the commodity. You mentioned $5, but then you also mentioned that incrementally you would rather add to the Eagle Ford. So just if oil stays at the current $80 level, what gas price would you need to go back to drilling in the Haynesville?

It's hard to look ahead of that, but I mean, clearly when we have over $5 gas, we do like the returns in the Haynesville program, and we would have a lot more cash flow to work with potentially if we would have almost another $100 million, which should support a whole rig in the Haynesville. And we'd raise our growth profile a lot if we ran another rig in the Haynesville. That's obviously a very important number, $5, for us to take a hard look at it. Anything north of $5 is very strong. I think, there is a point where the gas projects would be equally attractive to the oil projects. At a very high $5, maybe $6 gas price, then maybe it does switch over and say, "Well, now our return is better in the Haynesville." Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And are you thinking of adding any hedges on the oil side, given the -- using the same thought process, as you incrementally add the rigs into the Eagle Ford heading into '12?

We are looking at that. I think we'd like to get -- of course, make sure we have a stable -where we could get very comfortable with what we're ultimate priced off of because we don't want to have an ineffective hedge or be tied into WTI when it's still under -- it's having less of a benchmark for our area there. So I think that's -- we're working on that to lock in our marketing arrangements and then we have some target prices. And so we probably -- with acreage acquisitions we closed in October, we do have some drillings we need to do in the Eagle Ford more so than in the Haynesville, so we wouldn't mind trying to protect some of that required drilling in the Eagle Ford with some hedges, and market prices are there already to provide really good returns for that program.

Your next question comes from the line of John Freeman. John Freeman - Raymond James & Associates, Inc., Research Division: A follow-up on Leo's question, a little back again kind on the Jupe NWR acreage that you said was like 5,000 net acres, so I guess, just a little bit less than 20% of your acreage. I'm trying to get a sense of -- since there's not going to be anything drilled on that area based on Mark's comment in 2012, sort of what do lease expirations look like on that block?

John, this is Mark. I think those leases do have a 2013 expiration. So we'll look at it during the year in 2012 and then decide if we want to work on extending or letting that acreage go. A lot will depend on the offset drilling and how the Jupe acts once we have it stabilized. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And then a question for Roland. I'm trying to reconcile -- I apologize if I miss this. I'm trying to reconcile the amount of money that's been spent to this point after including -- on acreage acquisitions, including the 6,000 acres you picked up in October, that wasn't included in the slide, you'll have on the $53 million notes spent through the first 3 quarters. So I’m just trying to get a sense of the $125 million that you'd say that's for acreage acquisitions in 2011, is that how much has been spent? Or there's still leftover amount that you're just setting aside on other acreage you're trying to pick up?

No, that has not all been spent. So we still have a fair budgeted what we would hope to try to pick up before the end of the year. So we might not spend all of that total $125 million. John Freeman - Raymond James & Associates, Inc., Research Division: And Roland, how much was spent on the 2 transactions on the 6,000 acres you've picked up?

For the 6,000 acres, I think we spent about $40 million. They roughly cost between $6,000 and $7,000 an acre. And so it's around $40 million. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. So it's...

A large part of that, yes. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. So based on your current acreage budget, you'll increase for the rest, you've targeted another roughly $30 million or so for additional acreage you're hopeful to pick up?

That's right. That's pretty close. And then remember, of that amount that we spent, $24 million of that amount really is just going to be an obligation to pay over the next 2 years. So it wasn't cash, but it's a part of the acreage we picked up, 75% of the consideration was in the form of paying their drilling costs, like drilling carry. We did in those numbers too.

There are no further questions at this time. We will now turn the call back over to the presenters.

All right. Just in closing, again, we did -- we had strong financial results. Our costs were down. We've got a strong balance sheet. We've kind of given you a glimpse of 2012. There should be a 10% production growth or more. It should have a greater financial impact on our bottom line in 2012 because it is geared toward oil. We're reducing the Haynesville rig count, as Mark said, from 3 to 2 to 1. We should have one rig by maybe in late January, February 2012 drilling Haynesville wells. And now I think what you haven't seen, which I would've liked to had given you a preview on, are the 5 Eagle Ford wells in McMullen County that are in various stages of completion. So you know they're in McMullen, you know they are better acreage position, and you know they're in various stages of completion. So once that -- I think ,once you see that, I think, you'll be pleased with the program. And historically, all of you had followed us for years and years and years, you know that we wouldn't be adding acreage in a play if we didn't think the play was quality. We did think this is quality. And I think Mark could tell you that the more we drill here, the more comfort we have with the program. And we think that our acreage, we'd probably drill the well over 100 acres in Eagle Ford. So with that, again, thank you. Those are great questions. Thank you.

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