Comstock Resources, Inc. (CRK) Q2 2011 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Second Quarter 2011 Comstock Resources Earnings Conference Call. My name is Maria, and I will be your operator today. [Operator Instructions] I will now turn the presentation over to Mr. Jay Allison. Please proceed.

Thank you, Maria. Sorry for the 10-minute delay. We were just literally connected to the conference call, so anyhow, I'm sorry for that. Welcome to the Comstock Resources Second 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 Second Quarter 2011 Results. I'm Jay Allison, President of Comstock. And with me this morning is Roland Burns, our CFO ; and Mark Williams, our VP of Operations. During this call, we will review our 2011 second quarter financial and operating results, as well as updated results of our 2011 drilling program. Please refer to Slide 2 in our presentations and note that our 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. The 2011 second quarter highlights. Please refer to Page 3 of the presentation where we summarized the second quarter results. Our financial results are improving despite the continuation of low natural gas prices. We reported revenues of $112 million, generated EBITDAX of $87 million and had operating cash flow of $77 million or $1.62 per share. The gain we recognized from selling some of our Stone shares allowed us to make a profit in this quarter. We reported net income of $3.9 million or $0.08 per share. Our production increased 19% this quarter over the first quarter of 2011, and 20% over the second quarter of last year. We expect production to continue to grow in the third and fourth quarters. We are very pleased with the results of our 2011 drilling program in the first half of the year. We drilled 39 successful wells, including 31 Haynesville Shale wells and 6 Eagle Ford Shale wells in the first half of the year. Our Eagle Ford program is progressing very well. With 2 rigs now drilling in South Texas and having the use of our dedicated completion crew, we expect to have a significantly higher level of activity to talk about on next quarter's call. 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 now turn it over to Roland Burns to review the financial results for this quarter in more detail. Roland?

Thanks, Jay. On Slide 4, we're breaking out our oil and gas production by quarter and by operating region. And as you can see from the chart, we had very strong production quarter in the second quarter this year. On the chart, production from our Haynesville Shale properties is shown in blue and you can see that's where most of the growth is coming from. In the second quarter of this year, our production averaged 263 million cubic feet of natural gas equivalent per day, which was a 19% increase over the first quarter of this year and a 20% higher than production in the second quarter of last year. Production this quarter set a second consecutive new record high for our onshore operations and we've now completely overcome the shortage of completion services, which impacted our Haynesville operations in the third and fourth quarter of last year, and we're now catching up on completing the wells we drilled last year. Our Haynesville production increased 176 million per day as compared to 133 million per day in the prior quarter. Production from our other wells in the East Texas/North Louisiana region, mainly our Cotton Valley wells, remained steady at about 41 million a day in the quarter and we averaged 40 million a day in our South Texas region and then 6 million a day in our other regions. We have completed 45 wells or 28.2 wells net to our interest in either our Haynesville or Eagle Ford shale programs in the first half of this year. And you can see that the way production is trending this year, that we expect to come in at the top of our guidance, which could put us at close to 33% growth over 2010's production and 37% growth if you look at 2010's production and exclude the properties that we sold in December of last year. Oil prices continue to be very strong in the second quarter, which we cover on Slide 5 in the presentation. Our realized average oil price increased 50% in the second quarter of 2011 to $101.02 per barrel, as compared to $67.37 per barrel in the second quarter of 2010. For the first half of this year, our average oil price was $95.89, 43% higher than our average oil price of $67.24 for the same period in 2010. Our realized oil price in the second quarter and for the first 6 months of this year has averaged between 98% and 99% of the average of the average benchmark NYMEX WTI price so far this year. Natural gas prices improved slightly in the quarter as we show on Slide 6. Our average gas price increased 2% in the second quarter to $4.19 per Mcf as compared to $4.09 in the second quarter of 2010. The first 6 months of this year, our average gas price decreased 13% to $4.08 as compared to $4.68 for the same period in 2010. Our realized gas price is averaging at 97% of the average NYMEX Henry Hub gas price so far this year. On Slide 7, we cover our oil and gas sales. Driven by the 20% increase in production and slightly improved natural gas prices, our sales increased by 24% to $112 million in the second quarter. For the first 6 months of this year, our sales increased 2% to $200 million as compared to $197 million for the same period in 2010, as weaker natural gas prices for that period offset much of the production gains we had. Our earnings before interest, taxes, depreciation and amortization and expiration expense and other noncash expenses or EBITDAX in the second quarter increased about 38% to $87 million as shown on Slide 8. For the 6 months ended June 30, 2011, EBITDAX increased 6% to $152 million. Slide 9 covers our operating cash flow. Stronger revenues and lower costs caused our operating cash flow for the quarter to increase by 38% to $77 million as compared to the $56 million we had in the second quarter of last year. For the first half of this year, operating cash flow was $133 million, 4% higher than cash flow of $128 million for the same period in 2010. On Slide 10, we outline our earnings. We reported net income of $3.9 million or $0.08 per share as compared to a loss of $1.6 million or $0.04 per share in 2010 second quarter. For the first half of this year, we reported net income of $6.4 million or $0.13 per share as compared to net income for the first half of last year of $5.7 million or $0.12 per share. The second quarter results include a gain of $8.5 million or $5.5 million after-tax or $0.12 per share related to the sale of our marketable securities and that 6 months financial results include several unusual items: First of all, 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, which we redeemed in March of this year. We also had 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 and that charge is also taken in the first quarter. And then if you look for the 6-month period, we had a significant gain for our continuing sales of marketable securities during the first half of 2011 of $29.7 million or $19.3 million after-tax, and that equates to $0.42 per share. On Slide 11, we show our lifting cost per Mcfe produced by quarter. On this chart, we break lifting cost out into 3 components: Production taxes, transportation and then other field level operating costs. Our total lifting costs improved significantly to $0.85 per Mcfe in the second quarter as compared to $1.13 per Mcfe in the second quarter of 2010, and then even the value sent [ph] rate that we had in the first quarter of this year. Production taxes in the quarter were $0.06 per Mcfe and our transportation charges averaged $0.28 per Mcfe in the second quarter. Field operating costs averaged $0.51 this quarter as compared to $0.71 in the second quarter of last year and $0.58 in the first quarter of this year. Higher production in the Haynesville, combined with the absence of the high cost properties that we sold last year in the fourth quarter, are allowing us to achieve the lower lifting rates this year. On Slide 12, we show our cash G&A per Mcfe produced by quarter and this excludes stock-based compensation. Our G&A, our general administrative costs, decreased to $0.22 per Mcfe in the second quarter of 2011, as compared to $0.27 per Mcfe in the second quarter of 2010 and the $0.26 that we have in the first quarter of 2011. This improvement is also due to the higher production level, combined with a lower overall cash G&A in the quarter. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 13. Our DD&A rate in the second quarter averaged $3.12 per Mcfe, and increased from our $2.87 rate in the second quarter in 2010 and the $3.03 rate in the first quarter of this year. Our DD&A rate this quarter increased $0.09 from the $3.03 we averaged in the first quarter of this year, primarily due to the cost of completing the carry over wells from last year and so we basically added more costs into our amortization pool with the completion when those reserves are really counted last year. On Slide 14, we detail our capital expenditures. So far this year, we spent $349 million in the first 6 months as compared to the $244 million that we spent in the first 6 months of 2010. We spent $263 million in our East Texas/North Louisiana region and $84 million in our South Texas region. $36 million of the $349 million that we spent, so far in 2011, was spent to acquire additional leasehold in either the Eagle Ford or Haynesville Shale. Slide 15 recaps our balance sheet at the end of the second quarter. On June 30, we had $4 million in cash, $62 million in marketable securities on hand, which represent a 2.1 million shares that we hold in Stone Energy. We had a total of $692 million of total debt which is comprised of $300 million of our new 7.75% senior notes and $297 million of our 8.375% senior notes and the $95 million outstanding number of bank credit facility. Taking into account our cash on the balance sheet and marketable securities and the unused $405 million bank credit line, we have about $471 million in liquidity available to us. Our book equity at the end of the quarter was $1.1 billion, which makes our net debt about 39% of our total capitalization. I'll now turn it back over to Jay.

Thank you, Roland. On Slide 16, we update our holdings in the Haynesville Shale play in north Louisiana and East Texas, our acreage is highlighted in blue. We currently have 90,000 gross acres and 79,000 net acres that we believe are prospective for Haynesville Shale development, 59,000 acres are in North Louisiana, which is the better part of the play in our opinion. 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 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 60,000 gross acres and 51,000 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 of resource potential. I'll now have a Mark Williams, our Head of Operations, give us an update of our drilling program this year. Mark?

Thanks, Jay. On Slide 18, we recap our activity in the East Texas/North Louisiana region for this year. Our activity in this region is entirely focused on developing our Haynesville and Bossier Shale properties. We drilled 31 gross wells or 14.8 net wells in this region from 6 different fields in the first 6 months of this year, all of which were Bossier or Haynesville Shale wells. All of these wells were successful. During the first half of 2011, we completed 41 or 24.2 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 rate choke program. Since we initiated our Haynesville shale program in 2008, we have now drilled a total of 149 gross wells or 92.5 net wells. On Slide 19, we provide an update of our backlog of uncompleted Haynesville and Bossier Shale wells. The upper pie chart on the left illustrates our situation at the end of 2010 where 35 our 72 2010 wells had not yet been completed. The lower pie chart reflects the net well count and shows the 23.4 of our 45 net wells had not been completed at the end of 2010. The frac crew shortage in the second half of 2010 that created the backlog has been resolved by contracting a dedicated crew, which started working for us late in the first quarter. As shown in the bar graphs, to the right, at the end of the second quarter, the backlog had been reduced from 35 gross wells to 16 gross wells, and 23.4 net wells to 7.7 net wells. Excluded from this backlog count are 9 wells, 6.2 net, that were in the process of being completed on June 30. For our operated wells, we are essentially caught up at this time and we expect that our non-operated wells to be caught up by the end of the third quarter. Slide 20 shows the first 2 units in Logansport field in DeSoto Parish in Louisiana where we are fully developing the Haynesville on 80-acre spacing. Section 22, shown on the left, is a 640 acre unit, which was drilled in late 2010 and earlier this year and the completion is underway on all 8 wells. All the wells have been fracture stimulated and are currently being produced to recover the frac fluid and establish a stabilized production rate. As you can see, we utilized 3 drilling pads to drill and complete the 8 wells, which increases our drilling and completion efficiency, and reduces our overall well cost. This process also allows deeper fracs to be utilized which is a stimulation method where all of the wells in the pad are frac-ed with 1 frac fleet by alternating between the wells in a stage by stage procedure. We believe this method will increase the effectiveness of the stimulations as compared to frac-ing the wells 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 in 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 in this unit. We will begin completion operation of this unit in December and expect first production in January of 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 6 Eagle Ford shale wells, and 6 net in the first 6 months of 2011. So far this year, we have completed 4 wells, 4 net, including a well drilled in 2010 and the 4 wells had an average per well initial production rate of 870 barrels of oil equivalent per day. On Slide 22, we outlined our Eagle Ford shale play in South Texas. We have increased our holdings in the Eagle Ford to 25,000 gross acres and 21,000 net acres in the second quarter, as well as completed an acreage swap for most of our Karnes County acreage for contiguous acreage in McMullen County. We have 6 producing wells on our acreage, including our most recent completion, the Hill #1H in McMullen County. The Hill #1H was drilled to a vertical depth of 11,264 feet with a 4,642-foot lateral. We test this well at an initial rate of 865 barrels of oil per day and 1.4 million cubic feet of natural gas per day or 1,095 Boe per day. This well's initial production rate was based on flowing the well at the restricted rate on an 1864 choke. In the second quarter, we also drilled the Cutter Creek #1H, Forest Wheeler #1H and the Rancho Tres Hijos "A" #1H wells all in McMullen County. In order to improve efficiency and reduce costs, we have arranged of our dedicated Haynesville frac crew, also complete our Eagle Ford wells. They are currently completing the Cutter Creek #1H well in McMullen County and we'll stay in South Texas to complete another 3 of our wells before returning to the Haynesville in North Louisiana. We are currently running 2 rigs in the Eagle Ford and have 3 rigs drilling in the Haynesville. Our dedicated crew can more than keep up with our 5 rigs and we'll move between the 2 plays as [ph] our direction for the rest of this year and next year. We expect to be able to acquire an additional 4,000 to 5,000 net acres in this area in the third quarter. I will now turn it back over to Jay.

Mark, thank you. And in summary, I would refer you to Slide 23. We're very pleased with how this year's progressing despite continuing low natural gas prices. Our production growth has been very strong. We expect production to increase by 26% to 33% over last year, with completion of the backlog of wells drilled in 2010. Our low cost structure continues to improve with the higher production levels and drilling and completion efficiencies that we are now seeing. Our Eagle Ford shale program in South Texas is progressing, as Mark stated earlier. We now have 2 rigs drilling in our Eagle Ford shale acreage and we've been successful in adding to our holdings at a reasonable 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 manage our long-term commitments to allow us access to the services we need for our drilling program while, at the same time, giving us flexibility to respond to stronger or weaker prices. We have 5 rigs currently and plan to have the flexibility to run anywhere from 4 to 6 rigs in 2012. I will have the ability to run any of our rigs in either the Eagle Ford or Haynesville based on where we can generate the higher returns. We continue to guard our strong balance sheet. We have $405 million available on our bank credit facility and $62 million in marketable securities to supplement the cash flow we will generate. For the rest of the call, we will take questions only from the research analysts who follow the stocks. I'll turn it back over to Maria.

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

Can you talk about now that the 8 well pads on kind of where your current production is?

Yes. This is Mark. Our July production averaged between 255, between 265 million and 270 million equivalent per day. And those wells didn't come on until mid to late July, so really haven't had much impact on it and don't have a real good update on today's production to give you.

Okay. And you talked about the $8 million well costs. Are you all mostly pad drilling in the Haynesville?

Yes. Most of our drilling now is pad drilling. We're still drilling some to hold some of our minor leases around and just to test some of our southern areas. But all of our future development is going to be pad drilling.

Okay. And then 2 on the Eagle Ford real quick. One, what are you all seeing on the current cost to drill and complete and where are you looking to add acreage? Is it that central McMullen area?

As far as the cost, we're between -- our development wells after some of the science we did earlier, we're between $8 million and $8.5 million. We expect to be able to drive that down some when we get into the pad drilling that we'll be doing later this year and next year in Eagle Ford, so we do expect it to be down a little below $8 million. As far as the acreage, we like our core area in McMullen County, and on the trend, East and west, we're really looking at the whole play and see what we can pick up the best acreage.

Brian, on Slide 22, you can see kind of the orange area, the condensate area, that we think has 80%, 85% liquids. We're really sticking along that area. And then also, in answer to one of your questions, we put in Slide 20 which shows you the laterals like the Logansport, at Section 19 and 20, that 800 acres and that's pad drilling. So yes, in the future, other than drilling a well to hold a lease, we expect to develop for the Haynesville-Bossier with pad drilling and, I think, the same thing would really apply for the Eagle Ford in the future. So you should see some cost reductions coming down there like Mark had mentioned. And we wouldn't put a statement out that we think can get another 4,000 or 5,000 acres this quarter unless we really think we can do that. So we'd be surprised if you couldn't pick up some additional quality acreage and end up with the 25,000 plus net acres in Eagle Ford.

Your next question comes from the line of Leo Mariani with RBC.

Just a quick question here on the Haynesville, you guys talked about all of your drilling going forward is going to be pad drilling. I guess that probably implies that I'm guessing that pretty much everything in the Haynesville is held by production at this point. If not, going to be held by the end of the year. Is that a fair statement?

Yes, most of our acreage is held by production, Leo. We have some new releases that we acquired in 2010 and at the beginning of this year that obviously, are primary term, but they have a lot of term left on them. We have one lease in our fleet [ph] in south area that is still not all held by production but it's very forgiving as far as the term is like 2 wells a year to hold it. So 90% of our acreage is held and we're going to move to the development mode.

And I guess a question on your CapEx, you guys talked about spending, I guess, $349 million in the first half. I think your official budget is $610 million, you talked about adding more acreage here in the third quarter. I mean it looks like your lease budget is probably going to be over what you guys had allocated. I guess does that imply some upside, your overall CapEx budget here?

Leo, this is Roland. Yes, on the CapEx budget, I think our highest spending level was probably the second quarter because we were using a lot more services than we're going to use in the second half of the year. And all of our completion services will now be held just by of the 1 dedicated crew. And then in the first half of the year, we were using that, plus other companies, too, especially in the separate crew in the Eagle Ford. So we'll see a lower spending level for drilling and complete costs, hopefully, we'll be seeing, of course, lower costs in the remaining Haynesville wells that we're drilling. So I think you'll see that drilling part, we still think that's going to roughly be what we've budgeted. On the leasehold acquisitions, that's a number that's very hard to budget because we're very opportunistic and just look for good opportunities. So that possibly could be little higher than what's budgeted, but I think some of the new releases that we're doing, expect to do -- a lot of the acquisition costs is going to be paid in the future drilling carries. So it might not really impact our budget a lot this year. So we'll see that may be impact the budget a little bit next year as we'll pay for that leasehold cost by paying their share of drilling because most of our opportunities, adjacent acreage in the Eagle Ford are coming with smaller operators who would like to have us operate and run the drilling programs for them and instead of getting cash for their leasehold upfront, they prefer to get a large portion of it and in future drilling carry just for tax reasons and other reasons they have.

I guess the last question for you guys, can you guys just talk about infrastructure in the Eagle Ford in general? How are you guys getting your oil barrels to market? Are those going basically on, on pipeline up for cushioning [ph] and just kind of any comments on gas take away and processing and how you see that unfolding here?

This is Roland. I'll make a comment then let Mark add to it. On the marketing side, actually, we've seen the ability to get our oil trucks from the wells side to the various ways it makes its way down the Corpus Christi or other areas where they can sell the oil. But we've actually seen the capacity really improve in the area, and so most recently, we've had -- that's been actually much better that it was several months ago and they were working with 2 major oil purchasers now to put in a long-term arrangement for our Eagle Ford oil. And both of those are looking at very large increases in capacity in the McMullan area. And someone as early as even as December. We see that our marketing is pretty confident. They've been able to keep up with the drilling activity and completion activity in the Eagle Ford. So we haven't really suffered any real significant issues with take away. On the gas side, we just haven't produced very much gas and most of our -- all of our wells so far, have been oil wells, and with most of the production, crude oil there at the well heads. We have our gas processing arrangements, we haven't even delivered enough gas to ease of those yet. But we may drill a well or 2 as we get to the southern end of the Eagle Ford. That is more gas oriented and we'll see then have [ph] more need on the gas side.

The issues have been coming when you drill Eagle Ford wells for gas window. We've stayed away from that.

Yes. The other processing need is a more of the gas window, think. We are kind of north of that, we think, in our McMullen acreage for the most part.

The other thing you had mentioned, Leo, if you look at 2012, and we've said this on our one-on-one meetings and meetings with analysts, is that we are going to see what are our exit rate is for our production and again, we should have a 33% to maybe 37% production increase this year over last year. We're going to see where we end up and what percent of that is liquids. And then as Mark said, 90% plus of our acreage in the Bossier-Haynesville is HBP. We will have drilling commitments in Eagle Ford. We've already had 2 rigs committed. We probably have a third rig committed by late fourth quarter. But we're going to see where we have the greatest return for the dollars that we spend. If it's to have most of the rigs in the Eagle Ford, then that's where they'll go. We need to have 1 or 2 or 3 in the Haynesville, we can do that. But our goal is to say within our operating cash flow for 2012. Except for lease purchases that we would acquire, we'd use our balance sheet to do that. But that is our goal and I think we can make that goal unlike the government in their debt issue. As far as our bank line, we'll have a greater percent of PDP of properties also. So we would expect probably an increase in our bank facility too, the next predetermination. So from the financial side and production side and a percent of ore [ph] liquids, I think all of those are extremely positive for us. I think the only negative would be -- it would've been nice for you to see another 3 or 4 completed Eagle Ford wells this quarter. That didn't happen. You can see the one well that we did complete, we're very pleased with and Mark can comment on it. Again, it's our best Eagle Ford well yet, based upon when we choked it back and I think the wells that were drilling are all in that same vicinity in McMullan and that's why we put a second rig there and that's why we'll probably put a third rig there if oil prices continue to stay high. But it is a very manageable program now that should get better and better and better based upon a quarterly basis. And again, in Slide 20, you'll see a little delay in the additional gas production because we literally have 10 wells that have come online at the next same time that said Mark will be completed at the end of December. So you'll see a good production in 2012. I think that's a good carryover from '11 to '12.

Your next question comes from the line of Noel Parks with Ladenburg Thalmann. Noel Parks - Ladenburg Thalmann & Co. Inc.: I had a couple of questions. In the Eagle Ford, the Hill well, the one you completed during the quarter, the rate on it was real solid and I know it's also that, it was considerably shorter lateral length than the Swenson well, which not only a higher rate, but again was a much longer lateral. And then also the Hill looks like it's the southernmost well you've drilled in McMullan and can you just sort of talk about your understanding of the line between the condensate and gas window in McMullan now, given that well.

Yes, Noel. We're going to update that slide because all of our acreage, except possibly our most southern acreage is oil acreage. And when you define oil as less than a 2,000 gas oil ratio, all of our acreage based on our cash inflow data is oil. So it just goes from -- we go from about a 400 gas oil ratio on the North end to about 1,500 on the south end in the Hill well. So I think the condensate window is really south of us. It may be right on our southern edge, but I really do believe it's going to be off our acreage. Noel Parks - Ladenburg Thalmann & Co. Inc.: Okay. Great. So the definition of where that line is, it sounds like it's changed. And can you just sort of talk about the geology of why the Hill well looks like it's performed as well as it has?

Well, it's a shorter lateral, but we did the same number of frac stages on it that we did on the Swenson. So our cluster spacing is a little closer. We put the same volume basically of prop and fluids in it. It's also a little bit deeper than the Swenson. So it has a little bit higher reservoir pressure, which give us a little bit more energy to produce. It's a higher GOR than the Swenson, which also provides that extra energy and it's a equivalent rock or maybe even slightly better, so we are very pleased with the results and they match what we saw in the logs and we expect offsets to be similar.

The other thing, Noel, is that had Mark commented off the line. It's kind of like at the end of '08, beginning of '09, again, the Haynesville-Bossier, it took us a while to get up on a learning curve to figure out where to drill the laterals, how to frac them properly, and I think, again, I know one of the analysts come back and said, we're getting closer to kind of mastering this thing and it's a moving target. But I think Mark can comment on that.

Yes, Noel. I mean, we've changed our frac design somewhat. We've gone to a much more of a thin fluid-based or a hybrid type job than from our very early jobs. I think our people in the field understand the reservoir better as their frac-ing it. So they can make adjustments on the fly when they have trouble on stages. So we're getting a higher percentage of our stages put away and we may have been 75% early, we're probably 90%, 95% now. I mean you still have the occasional problem but, overall, everybody involved is from geologist to engineers to field people, we're all getting up that learning curve as quickly as we can. And we're seeing the benefits in terms of our well results. Noel Parks - Ladenburg Thalmann & Co. Inc.: And just -- can you give us a sense of where the next couple of wells you plan to do in the Eagle Ford will be within your acreage?

Yes, we are completing our well called the Cutter Creek, which is in north central McMullen County and also the forest wheeler which is on our most southern acreage in McMullen County. And then we're completing a second well in Atascosa called the [indiscernible] well which has been an interesting test for us.

Out of the 12 wells that we're in, 9 of them are in McMullen. And 3 are outside of McMullen. So we focus on McMullen. Noel Parks - Ladenburg Thalmann & Co. Inc.: Okay. Great. And just moving over to the Haynesville for a minute. Can you talk a bit about of the Bossier wells that you've done. What their performance has been like and do you have any update on the delineating the Bossier play as opposed to the Haynesville?

As far as the Bossier, there's just not -- there's a lot of log data on the Bossier but other than, I believe, comp stock, there hasn't been a lot of activity in the Bossier. We've been more active than most companies because some of our acreage is primarily Bossier acreage. I mean, our farthest out acreage in Sabine Parish is really primarily Bossier acreage. So we've been pretty active, I think, we've completed 11 wells -- I'm trying to remember now. Yes, I think, we completed 9 Bossier wells this year and we drilled 10 Bossier wells this year. Noel Parks - Ladenburg Thalmann & Co. Inc.: Where are those coming out relative to your pre-drill expectations?

They're matching that acreage in our Toledo Bend south area, that's primarily Bossier acreage and those wells are matching our expectations and are very similar to Haynesville wells. As you go north, if you get too far north, we'll limit [ph] the day we've seen if the Bossier is not as good. I mean you've seen -- it kind of shows that on the map as well that you run out of the Bossier while you're still in the Haynesville. So if you North, the Bossier is not going to be as good but down on the core area, it acts very similar to the Haynesville. Noel Parks - Ladenburg Thalmann & Co. Inc.: And just my last one. On the completion side, how are things on the materials end? Thinking about, for example, sand, for example, in the Eagle Ford and also on the Haynesville?

In the Haynesville, we haven't had any issues. In the Eagle Ford, we were having, not difficulty, but it's been you have to schedule well ahead of time to get your prop and scheduled in the Eagle Ford. Our relationship with Schlumberger, who's our dedicated frac provider, has really helped us down there and we've been able to get the materials that we've needed.

Remember on Slide 16 we say 6 Bcfe per well for Haynesville and then Slide 17, it's 5 Bcfe per well for the Bossier. That's what Mark was talking about.

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

I have a couple of follow-up questions on production and then, if you'll indulge me, one additional question. On the production side, given the fact that you're moving more toward pad drilling inclusion and that you're building 6 to 8 wells per pad out there in Haynesville now, are we going to see more lumpiness in gas production going forward?

Yes, Michael, this is Roland. I think that's a possibility. We'll have to see how we schedule the pads coming on. But when you have 8 wells, if you're trying to drill 8 wells, it could take 8 months to actually get them all drilled before the completion activity is if you use one rig. So it's really the -- answer to that question is going to be based on how many rigs are we going to dedicate to the Haynesville, and to be able to more smooth out kind of pad development. And the answer to that question -- we can't answer the question until we kind of get a better feel for gas prices. I think if gas prices don't improve from the current spot levels, I think we'll be hard-pressed to leave the 3 rigs in the Haynesville just because of the return I think those same rigs can make in our Eagle Ford program now that it is performing and it's more -- it's not oil focused. So we'll have to balance that lumpiness against getting higher oil production returns and I think towards the end of this year, our goal now is to create all the flexibility between our rigs and our frac crews and our acreage to be able to have that full flexibility go between the 2 plays that I think we're going to achieve that and then we'll look out to 2012 and say, where can the drilling rigs and the capital that we have best generate the best return overall? May not be the absolute overall production on a Mcfe basis, but -- if it and then allocate those rigs accordingly and to the extent that we allocate 2 or 1 rig going into the Haynesville, it means we either are not doing a lot of pad development next year or take a long time to get one drilled out, but we will start our 2012 with some cushion there by having this very large project come on line on our first quarter of next year on the gas side.

Okay. That helps and will model accordingly. On the Eagle Ford, it seems like with the 2 rig program, it looks like in the numbers you'll end the year around 10% oil by volume. Does that seem reasonable?

Michael, that's possible, but it's probably because of the really large growth in gas, we keep raising the bar for the oil to get there. But I think that it's still possible and I think we'll be approaching that number. It Really depends on how strong the gas production is. I think the one thing that's been real positive now that we have arranged to use the dedicated crew, we have much more control over the timing of the Eagle Ford completions than where they've been fairly slow in the first 6 months. We think you'll see a lot of efficiencies and a lot of the Eagle Ford wells actually getting completed in the second 6 months of this year, and dependent on how well those perform. I think we definitely still have a shot at the 10%. But that was the gas numbers. It's grown so large that it's harder and harder for the well to do that. But I think as we dedicate more resource to the Eagle Ford, we'll be 10% oil before you know it in 2012. So again, a lot is going to depend on where we allocate the rigs and the capital next year and how aggressively we can drill on the gas side versus the oil side.

We just spent fortune to hedge exemplary Haynesville wells. If we hadn't had excellent Haynesville wells, then we would definitely be at the 10% and if we hadn't sold Laurel, the oil property, but we needed to sell Laurel and we're very fortunate to have this wonderful Haynesville-Bossier well. So I think 10% is a good goal. I don't if we'll hit it, but we'll be close.

Well, speaking of hitting goals, I mean, previously, we talked about exonerated about 289 cubic feet equivalent a day, you're already knocking on that door already, is that a number that you're ready to talk about moving up?

Michael, on the exit rate, yes, I think I don't see it -- it definitely is going to be at least that high. Possibly, it will be higher. We will have a strong third quarter production growth again because of the Logansport section coming on in August here and that's going to really help the third quarter. The fourth quarter that we won't complete a whole lot of new wells in the Haynesville probably 3 or 4 or so before we go to that really large project in December and do the 9 wells and the 10-well sections and all of those will come online in January. So we don't expect to see the fourth quarter show as we think it could be pretty good strong quarter but it won't show the same kind of growth that we saw first to second, second to third. So I think we definitely hit the 280 a lot earlier than the end of the year but whether or not we can be way ahead of that at the end of the year, we don't think so. A lot of the production increases have come because we've just got ahead of schedule on the completion side, and actually, are slowing that down a little bit by moving the completion services over to the Eagle Ford now for the second half of the year versus being 100% working in the Haynesville.

As we said earlier, you got the 10 wells that will be frac-ed December and coming January. So 2012, we should have some fabulous production also. As far as a production rate we gave you today, our production is north of that as you know.

Okay, my last question, you had 40 million a day in South Texas. Could you give us some quantification how much of that was allocatable for the Eagle Ford?

Michael, this is Mark. I believe about 8 million of it on accrual basis is Eagle Ford and the rest of it is legacy South Texas production.

Your next question comes from the line of John Freeman with Raymond James. John Freeman - Raymond James & Associates, Inc.: I just wanted to look into the Eagle Ford acreage a little bit. I'm just sort of eyeballing sort of where your acreage was last quarter and then after you all picked up the additional 3,000 net acreage here. It looks like the adds were sort of around the Carlson well, and sort of corner of McMullen County then you also looked like you added some in Atascosa. So I know you were going to do the acreage swamp, which you all mentioned. So I'm just assuming that, that was where McMullen County got picked up and the adds were Atascosa. And so just for reference, if last quarter, if memory serves, I want to say McMullen you all were around 13,000 to 14,000 net acres, where that number stands now in McMullen?

John, this is Mark. The acreage we added is right in the 4 corners of McMullen County, Atascosa, Frio and LaSalle. It's those 2 blocks the are right next -- closer to the 4 corners. John Freeman - Raymond James & Associates, Inc.: Right. Near the Carlson well, right?

Yes. And then trade acreage is just on the East edge of the Carlson block. All the acreage that we increased and changed with the Karnes County acreage is right there in that same area. And as far as McMullen, we're about 13,000 right now in the McMullen, a little less than 6 in Atascosa, a little over 2 in La Salle, and just a slight amount in Karnes County. That's where our acres breakout is right now. John Freeman - Raymond James & Associates, Inc.: And then last question I had on the Eagle Ford, as it sounds pretty likely that you'll end up moving a third rig over there toward the end of the year. Just when you sort of think about it for 2012, how do you all think about it in terms of with 3 rigs, possibly next year going into 4 rigs, like how many frac crews do you need dedicated per the number of rigs that you're running in the Eagle Ford?

Well, right now, our crew is dedicated to move back and forth and if all we do is move the Haynesville rates to the Eagle Ford at the end of this year, then we have the frac services to handle it. If we add a rig instead of moving a rig, then I still believe we'll be able to make it. We have a little bit of extra space in the schedule, if you will, to handle it with that one crew, and anything above that we have to negotiate additional services either with Schlumberger or somebody else. So we'll just go for lowest when we decide to make that move.

And John, it appears that the dedicated crew we have now can service about 6 rigs and we have 5. So as we're using them now, we actually have some time but we're releasing them because we can't fully utilize them with our 5-rig program. So if we went to a 6 rig program, we probably then fully utilized that crew, and so I think that we're really set for those services anyway through next year.

Your next question comes from the line of Ron Mills with Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: A couple of questions, just to go back to, I think Brian's initial question on the current production, Mark, when you talked about the 265 million or 270 million day rate, was that, with the inclusion of those 8 wells or are those really still in the process of cleaning up?

That was July's average rate, right? So it's mostly excluded those for the most part.

And slight amount of their production in that July average, but there wasn't very much because most of it came on late in July and we stepped them up slowly as we get the fluid off of them. Ronald Mills - Johnson Rice & Company, L.L.C.: Okay. And so really your current rate is higher than that, though, the lack of additional Haynesville completions over the remainder or most of this quarter is probably the peak on the gas side. Is that the right way to look at that for this quarter?

I think, this is Roland. When this unit is fully brought up to full rate, which probably happens soon in August here, yes, that would be a peak rate, we would think. There won't be any other completions for the most part in the Haynesville that would affect the production rate. They come online for the third quarter. But I think that'll be enough to have a very nice third quarter average rate over the second quarter.

Right. Ronald Mills - Johnson Rice & Company, L.L.C.: Okay. And when you look at just the number of completions with this dedicated crew going from Haynesville to Eagle Ford, what's as you look at your completion schedule now, what's the schedule? I think you said you have another, you'll do 4 wells back to back before taking the completion crew back to Louisiana and/or East Texas, and then bring it back to the Haynesville. So if we look out over the next 3, 4 months, are you planning on having another 6 or 8 type Eagle Ford completions? How many at Haynesville? I'm just trying to think about the completion schedule by area.

Right. Ron, I think, we finished the 4 wells in the Eagle Ford. We come back to the Haynesville for, I think, 2 wells. Then we go back down the Eagle Ford for another group and then we come back to the Haynesville for 2 or 3 more. So I think we're going to have 6 to 8 wells completed to talk about before the next quarter call. It kind of -- some of it depends on the rig schedule as well. If we drill them per the rigs schedule that we have or they go faster or they go a little bit slower but that's kind of how we have it scheduled out right now. Ronald Mills - Johnson Rice & Company, L.L.C.: Okay. And then this segue is due to production profile, we just talked about on the gas side what you should see then on the liquids especially as we work through this quarter and especially into the fourth quarter, you should really have pretty strong liquids growth which, even though, the fourth quarter you won't really have it on the gas side the margins on the oil side kind of more than offset that financially -- directionally you're 1700 or 1800 barrels a day in the second quarter, is that something, with your current wells online and the additional 6 to 8 that you can approach the 3,000, 3,500 barrels a day by year-end?

Yes. We have a much more steady production growth projected for the oil. It obviously because were completing the wells more steady than we're not pad drilling and the way we're doing in the Haynesville although we are doing a little bit of pad drilling down there but not to the same extent we are on the Haynesville. So we should get much more steady growth and I think you're kind of in the ballpark. We're looking at between 3,000 and 4,000 barrels a day exit rate is what we're looking at on the oil side.

I think you're correct, Ron. Ronald Mills - Johnson Rice & Company, L.L.C.: And then lastly on the cost structure, as you also shift to a more oily mix probably a little bit sooner than expected, I would assume that some of the unit cost improvement we've seen on LOE starts to flatten out or maybe even start to go up a little bit just to account for the fact that you're getting more oily a little bit sooner than at least we were expecting.

Ron, that's correct. I think what you'll see the Eagle Ford oil production will have production taxes on it. So where that has come down to a very small number, you'll see that trend the other way. The taxes are, of course, higher on oil even in gas and then a lot of the gas, a lot of the new gas wells we've been bringing on this year have got a 1- to 2-year exemption from severance taxes. So that's what's driven our severance tax rate down so low. But the oil doesn't have that benefit. So it will -- you'll start seeing that creep back up and the overall lifting cost which is fairly fixed, if you exclude the taxes and transportation of the Haynesville, the only increasing kind of lifting costs there is probably ad valorem taxes and stuff because a lot of the field level costs, there are a lot of field level production cost that all new Haynesville production is needing. It's just -- we're spreading the same cost over more volumes, so it's driving the rate down. So those big improvements have driven the lifting costs rate down so much. Obviously, once the Eagle Ford shows up to be counted as a bigger player in our growth. It will reverse that trend. But that will be a minor offset to the profits that you have at the top line. Ronald Mills - Johnson Rice & Company, L.L.C.: And then coming from you, Jay or Roland, that talked about 2012 being much more aligned in terms of cash flow versus CapEx, I know this year you had $110 million, $115 million of carryover completions which you won't have I guess, for lack of a better term, burdening your 2012 estimate. At what gas prices are you assuming that you would kind of stay at a 2-rig Haynesville, 3-rig Eagle Ford, or you talked about 4 to 6 rigs. I'm just trying to get a profile to what to expect from a Haynesville versus Eagle Ford activity and the total capital plans.

Ron, this is Roland. I think as we look to the capital plans, I think what -- as we're increasing our Eagle Ford position, we kind of see having a minimum of 2 rigs there, and most likely, 3. So on the other side, in the Haynesville program, it's more dependent on what gas price is going to be. And I think to go to 6 rigs, we're going to have to have gas prices in excess of probably in excess of 5.25 to have the cash flow to pay for 6 rig program. So, I think the more gas prices are over 5, the more likely we'll be running more rigs in the Haynesville. The closer gas prices are to 450 or 425 or 400, the likelihood that we won't have very many rigs in the Haynesville and so I think that's really how we're looking at it. Ronald Mills - Johnson Rice & Company, L.L.C.: And what are you required to have in the Haynesville in terms of lease expiries? Is it just a one rig required and then you were down to one rig there and add 4 rigs or whatever in the Eagle Ford, if you could support that and then I would assume what we would start to see is the gas production start to roll over on a run rate program there?

We would keep one. We'll keep one rig busy in the Haynesville-Bossier just to have some activity there. You can't get dormant in our single best area. So we would, you can budget at least 1 rig there. Now whether we go north of that or not, I mean our goal is to stay within operating cash flow. You have to see what our exit rate looks like. You have to see what percent liquids we are versus gas and to see where gas price is or oil prices are. I think we're going to have years of drilling in Eagle Ford for good acreage and I think we've got years and years and years of drilling in the Haynesville-Bossier. So a lot of those questions we won't know until the latter part of 2011. As far as how many rigs, I mean, again, like Roland said, 2 or 3 in Eagle Ford, that's a good starting point. One in the Haynesville is a good starting point, that gives your site 4 and the question is, do you add 2 more?

I think given the large project they were putting on line in 2012 in the Haynesville, that's going to soften that number from what it could have been otherwise. I mean we're going to have some increases upfront in 2012 from the gas side even if we run no rigs in Haynesville. Ronald Mills - Johnson Rice & Company, L.L.C.: And would the drill-to-earn or drilling carrier going to determine that you referenced in terms of this incremental 4,000 or 5,000 acres next year, would that be additive to what you would have expected to spend there with say, commodity prices stayed the way they are today, which you just borrow from the Haynesville to fund that drilling?

Well I think you look at, you would budget those wells that we're drilling on that acreage at 100% like what our Eagle Ford is now and some of that dollars will actually be going paying for the leasehold. It's not a real large number in the scheme of things. So it's not a major factor in how we look at the budget at all next year.

Your next question comes from the line of Richard Tullis with Capital One Southcoast.

Just following up on Ron's question there. What sort of, say, you do go with a lower rig count in the Haynesville next year based on lower gas prices at that time, what sort of production growth would you be looking at versus, say, the exit rate of 280 million plus projected for this year, say, with 1 rig in the Haynesville and 3, 4 rigs in the Eagle Ford?

We're not really ready to speculate on that at this point. I mean it's, I think, once we do allocate our budget out we'll give some kind on production, but just to speculate if you stop all drilling, what it will be? It's just us. That's not really what we're at all focused on right now. It's more of allocating the resources to the best return overall. And so we're certainly not going to focus on top line production as the only number or we would think the markets wouldn't either. It's really what can generate the most profits, the most sales and so that's how we're going to approach 2012, just worrying about a number.

And as Roland said, it's for the first time, we'll have complete flexibility whether we want to put rigs in the Haynesville-Bossier or in Eagle Ford beginning in 2011, we didn't have that luxury. And I think we'll have the balance sheet to do it.

Okay. What is the projected rate of return for the Haynesville wells, you're average change of the well, say, even using the pad drilling $8 million well cost? Say, 450 gas environment.

Using the development cost that we're seeing right now in our pad drilling, Richard, we're probably in the 20% to 30% range. I don't have that number exactly in front of me but I think that's probably pretty close.

Okay. And what are you looking at for expected working interest with the wells to be brought online in the second half of 2011 considering that you have a decent amount of non-op wells still in the back log?

I don't have that number in front of me, Richard. Our operated wells that we are drilling this year are probably averaged well over 90% working interest, the non-op wells and the well count are...

2% to 18%. I mean they're kind of all over the board. We focus our operated wells. They fill in the non-op just as a number, but the wells we complete are mainly operated wells.

Okay. How many non-op wells still in the backlog?

I think there were 9 backlog.

Nine, gross?

Yes.

What's the net on that, roughly?

Probably less than 2. I didn't add that number, but it's low. It's probably closer to one, maybe...

We had several days that are like a tenth of a 1%.

Okay. Did mention how much you paid for the 3,000 Eagle Ford acres added in the quarter?

We didn't mention that specifically since we're still, obviously, it's still active area, we really don't want to get that specific on every deal.

[Operator Instructions] Your next question comes from the line of Dan McSpirit with BMO Capital Markets.

On the Eagle Ford, you spoke to the [indiscernible] A#1H well earlier on the call. That was a well, I believe, that is located in Atascosa County and just looking at the map, it appears to be probably your northernmost located well in that county and one, I think, that was spud [ph] in late June. Can you tell us anything more about the completion plan for that particular well, plus how it may differ from the nearby NWR 1H well which carried an IP rate of close to 400 BOE per day

Yes, Dan, this is Mark. The [indiscernible] well is just slightly maybe about 1 mile, 1.5 miles northwest of the NWR well. It's substantially longer lateral, it's over 7,000 feet and I believe the NWR was in the 4,000-foot range. We have changed our frac design significantly since the NWR which was our first completion, which was a cross-linked gel frac with a multiple profit types and this well, it's all sand, it's a lot more fluid, thin fluids, more of a hybrid type design, more stages, closer cluster spacing, just a lot of changes in the completion design which we've developed over the last 6 or 7 wells.

Okay. And generally, what is the gas oil ratio in that part of the county, what you know from NWR well at least?

Our NWR has about a 700 gas oil ratio. We want [indiscernible] to be similar.

Okay. And that would compare to the kind of the Hill well, which I believe you mentioned carried about 1,500. Is that right?

Correct.

Okay. And then can you discuss the use of the restricted choke on the Hill well, that is -- is this that the standard practice here going forward or at least in that part of McMullen County, is that the standard practice going forward and why?

It is a standard practice. We've seen it be successful in the Haynesville and we're still evaluating it. We do believe it's been successful in the Eagle Ford, we think our wells have outperformed some of the wells in the vicinity of them because we haven't pulled them real hard. We've produced them at a more restricted rate and we've really done that with all of our wells and even the NWR, which is our first well that was completed and our shallowest well, that well still is not on pump. It's flowing naturally so we've been successful in not having to go to Artificial Lift early, because we're flowing the wells at a more moderate rate.

And that's 7 months or 8 months of production for that well?

Yes. And I know that other operators have put their wells on either gas lift or pump within a month or 2 after completions. So we think our procedure has worked.

Okay. And then my last question and forgive me if this was asked and already answered. But of the 21,000 net acres currently at the Eagle Ford Shale, what percentage of that leasehold is held by production today?

Probably less than 10% today. We've only drilled -- we only have 6 producing wells. So we hold 640 acres, that's, I guess, that would be 6,000 acres, that would be 25%. But I don't really think if the math works out quite that well.

And then what's the schedule here going forward over the next 12, 24 months? That is, by year-end 2012, year-end 2013, how much of the acreage will be held by production by those time periods?

Dan, that's a little bit of a moving target because we're adding acreage as we go, so our drilling for the next 2 years won't be just on the acreage that we have acquired so far. I mean, I do expect we would be maybe 50% held by the end of next year but if we had a lot of new acreage, we might be less than that.

If we can add to quality acreage, we think we can. I mean 50% is probably good, that's a good number.

At this time, there are no further questions. I'll turn the call back to management for closing remarks.

Again, I'm sorry that we started 10 minutes late. We were not connected at the time we thought we would be. I think we've given good numbers out. I think we've given -- with the third, fourth quarter looks very, very bright. I think we've bottomed out as far as the sector on gas prices and I think things are bright for the future. We'll continue to protect our balance sheet and grow this company for all the stockholders. Thanks for your attention.

Ladies and gentlemen, that concludes today's presentation. All parties may now disconnect. Good day.