Comstock Resources Inc (CRK) 2011 Q2 法說會逐字稿

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. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions) I will now turn the presentation over to Mr. Jay Allison

Thank you, Maria. Sorry for the 10-minute delay. We were just literally connected to the conference call. Anyhow, I'm sorry for that. Welcome to the Comstock Resources second quarter 2011 financial and operating results conference call. You can view a slide presentation during or after this call going 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 is update the 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 of 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 summarize the second quarter results. Our financial results are improving despite the continuation of low natural gas prices. We reported revenues up $112 million, generated EBITDAX of $87 million and net 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 break out our oil and gas production by quarter and by operating region. As you can see from the chart we had a 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 this year, our production averaged 263 million cubic feet of natural gas equivalent per day, which was a 19% increase over the first quarter 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 as we have now completely overcome the shortage of completion services which impacted our Haynesville operations in the third and fourth quarter of last year, and we are now catching up with completing the wells we drilled this 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 and North Louisiana region, mainly our Cotton Valley wells, remained steady at 41 million a day in the quarter, and we averaged 40 million a day in our South Texas region and 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 of this year. You see that the way production is trending this year that we expect to come it in at the top-end 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 of the presentation. Our realized average oil price increased 50% of 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 of 2010. Our realized oil prices in the second quarter, and for the first 6 months of this year, has averaged between 98% and 99% 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 $4.19 per million cubic feet, as compared to $4.09 in the second quarter of 2010. For the first 6 months of this year, our average gas price decreased 13% to $4.08, as compared $4.68 for the same period in 2010. Our realized gas prices averaging 97% of the average NYMEX Henry-Hub gas price so for 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 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 of 2010, as weaker natural gas prices for that period offset much of the production gains we had. Our earnings before interest, taxes, depreciation, amortization and expiration expense, and other non-cash expenses, or EBITDAX in the second quarter, increased by 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 cost 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 $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, relating to sale of our market securities.

And the six 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 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. 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. You can see on this chart we break lifting cost out into 3 components, production taxes, transportation, and then other field-level operating costs. Our total lifting cost improved significantly to $0.85 per Mcfe in the second quarter, as compared to a $1.13 per Mcfe in the second quarter of 2010, and then even the $0.90 rate that we had in the first quarter 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, our 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 and administrative costs, decreased $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 had in the first quarter of 2011. This improvement is also due to the higher production levels combined with the lower overall cash G&A in the quarter. Our depreciation depletion and amortization per Mcfe produced is shown on slide 13. Our DD&A in the second quarter averaged $3.12 per MCFE, it increased from our $2.87 rate in the second quarter 2010 and the $3.03 rate in the first quarter this year. Our DD&A rate this quarter increased $0.09 from the $3.03 we averaged in the first quarter this year, primarily due to the cost of completing the carryover wells from last year. So we basically added more costs to 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 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 spent so far in 2011 was spent to acquire additional leaseholds in either the Eagle Ford or Haynesville shales.

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 the 2.1 million shares that we hold in Stone Energy. We had a total $692 million of total debt, which is comprised of $300 million of our new 7.75% senior notes, senior notes, and $297 million of our 8.375% senior notes, and then $95 million outstanding under our bank credit facility. Taking in to account our cash on the balance sheet and our 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 will 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 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, or 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 Mark Williams, our Head of Operations, give us an update of our drilling program 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 in 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 share 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 of our 72 2010 wells have not yet been completed. The lower pie chart reflects the net well count, and shows that 23.4 of our 45 net wells have not been completed at the end of 2010. The frac crew shortage in the second half of 2010 that created a backlog has been resolved by contracting a dedicated crew, which started working for us late 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-operating wells will be caught up by the end of the third quarter.

Slide 20 shows the first 2 units and Logansport Field in DeSoto Parish, 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 simulated, and are currently being produced to recover the frac fluid and established 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 a zipper fracs to be utilized, which is a simulation method where all the wells on a pad is fraced with 1 frac fleet by alternating between the wells in a stage-by-stage procedure. We believe that this method will increase the effectiveness of the simulation as compared to tracking 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 1 existing Haynesville producer in this unit. We will begin completion operation on 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. Hill #1H was drilled to a vertical depth of 11,264 feet with a 4642-foot lateral. We tested 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, 1095 BOE per day. This well's initially production rate was based on flowing the well as a restricted rate on an 18/64 inch choke. On the second quarter, we also drilled at the Cutter Creek #1H, the Forest Wheeler # 1H, and a Rancho Tres Hijos A #1H wells, all in McMullen County.

In order to improve efficiency and reduce costs, we have are arranged to have our dedicated Haynesville frac crew also completed our Eagle Ford wells. They are currently completing the Cutter Creek # 1H well in McMullen County and will stay in South Texas to complete another 3 of our wells before returning to the Haynesville in North Louisiana. We're 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 will move between the 2 places at our direction for the rest of this year and next year. We expect to be able to acquire an additional 4000 to 5000 net acres in this area in the third quarter. I will now turn it back over to Jay.

Mark, thank you. In summary, I would refer you to slide 23. We are very pleased with how this year is 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 higher production levels and drilling and completion of 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 Eagle Ford shale acreage and we have 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 higher-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 flexibility to run anywhere from 4 to 6 rigs in 2012. We 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 of 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'll take questions only from the research analysts who follow the stocks. I will turn it back over to Maria.

(Operator Instructions) Brian Corales, Howard Weil.

Can you talk about, now that the 8-well pad on, where your current production is?

Yes. This is Mark. Our July production averaged between 265 million and 270 million equivalent per day. Those wells didn't come on until mid- to late-July. So it really hadn't had much impact on it. We don't have real good update on today's production to give you.

You talked about the $8 million well cost. Are you all mostly pad drilling in the Haynesville?

Yes. Most of our drilling now is pad drilling. We are still doing some to hold some of our minor leases and just to test some of our southern areas, but all of our future development is going to be pad drilling

And then, and 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 someone we get into the pad drilling that will be doing later this year and next year in the Eagle Ford, so we do expect it to be down 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 seeing where we can pick up the best acreage.

Brian, on slide 22, you can see the orange area, the condensate area, that we think has 80%, 85% liquids. We're really sticking along that area. Also, in answer to 1 of your questions, what we put in slide 20, which shows you the laterals, like the Logansport, that 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 the Haynesville Bossier with pad drilling, and I think the same the thing would really apply to the Eagle Ford in the future. So you should see some cost reductions coming down there, like Mark had mentioned. We wouldn't put a statement out here we think we could get another 4000 or 5000 acres this quarter unless we really think we could do that. So we would be surprised if we couldn't pick up some additional quality acreage and end up with the 25,000-plus net acres in Eagle Ford.

Leo Mariani with RBC.

Just a quick question here on Haynesville. You talked about all of your drilling going forward is going to be pad drilling. I guess that probably implies that pretty much everything in the Haynesville is held by production at his point? If not, it's going to be held by the end of this 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 1 these in our Toledo Bend South area that is still not all held by production, but is very forgiving as far as the term, it's like 2 wells a year to hold it. So 90% percent of our acreage is held and we are going to move to the development mode.

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

Leo, this is Roland. On the CapEx budget, think our highest spending level was probably the second quarter, because we were using a lot more services than we were going to use the second half of the year. All of our completion services will now be handled just by the one dedicated crew, and in the first half of the year, we were using that plus other companies too. Especially, we had a separate crew in the Eagle Ford. So, we will see a lower spending level for drilling and completion costs. Hopefully we'll be seeing lower costs on the remaining Haynesville wells that we are drilling. So I think you will see that drilling part, we still think that's going to roughly be what we budgeted.

On the leasehold acquisitions, that's a number that is very hard to budget because we are very opportunistic and just look for good opportunities. So that possibly could be a little higher than what is budgeted, but I think some of the new leases that we are doing -- expect to do, a lot of the acquisition cost is going to be paid in a future drilling carry, so it might not really impact our budget a lot this year. So we'll see. That maybe impact of budget a little bit next year as we will pay for that leasehold cost by paying their share of drilling. Because most of our opportunities, adjacent acreage through our Eagle Ford are coming with smaller operators who would like to have us operate and run the drilling programs for them. Instead of getting cash for their leasehold up front, they prefer to get a large portion of it in future drilling carry, just for tax reasons and other reasons they have.

That was a very good explanation there. Last question for you guys, could you just talk about infrastructure in the Eagle Ford in general? How are you guys getting your oil barrels the market? Are those going basically through the pipeline up the Cushing? Any comments on gas takeaway and processing and how you see that unfolding here?

This is Roland. I'll make a comment and then let Mark add to it. On the marketing side, actually we've seen the ability to get our oil trucked from the well side to the various ways it makes its way down to Corpus Christie or other areas where they can sell the oil. We've actually seen the capacity really improve in the area, and so most recently that's been actually much better than was several months ago. We are working with 2 major oil purchases 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 McMullen area, one as early as even December.

We see that our marketing group is pretty confident. They've been able to keep up with the drilling activity and the completion activity in the Eagle Ford. So we really have not suffered any real significant issues with takeaway. On the gas side, we just haven't produced very much gas. Most of our, all of our wells so far have been oil wells with most of the production oil at the wellhead. We have gas processing available. We haven't even delivered enough gas to really use up those yet. We may drill a well or 2 as we get into the southern end of the Eagle Ford that are more gas-oriented, and we'll see, that might put a little bit more need on the gas side.

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

Yes. All the processing needs, that's more the gas window, I 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 out at 2012, and we've said this on our one-on-one meeting and meeting with analysts, is that are going to see what 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'll have drilling commitments in Eagle Ford. We've have already had 2 rigs committed. We will probably have a third rig committed by late fourth quarter. But we are going to see where 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 will go. If we need to have 1 or 2 or 3 rigs in the Haynesville, we can do that. But our goal is to stay 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. I think we can meet that goal. Like the government and their debt issue.

As far as our bank line, we will have a greater sense of PDP of properties also. So we would expect probably an increase in our bank facility too at the next predetermination. So from the financials side, the production side and the percent oil liquids, I think all of those are extremely positive for us. I think the only negative, 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 1 well that we did complete. We are very pleased with, and Mark can comment on it. Again, it's our best Eagle Ford well yet, based upon where we choked it back. I think the wells that we are drilling are all in that same the vicinity of McMullen, and that is why we put the second rig that's why we will probably will put a third rig there if oil prices continued to say high. It is a very manageable program now that should get better and better and better based on a quarterly basis. And then again, on slide 20, you'll see a little delay in additional gas production because we will literally have 10 wells that will come online at the same time that Mark said will be completed at the end of December, so you will see good production in 2012. I think that is a good carryover from 2011 to 2012.

Noel Parks, Ladenburg Thalmann

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 noticed also that it was considerably shorter lateral length then the Swenson well, which not only had a higher rate, but again was much longer on the lateral. And also the Hill looks likes it's the southernmost well that you've drilled in McMullen. Can you talk about your understanding of the line between the condensate and gas window in McMullen now, given that well?

Yes, Noel. We're going to update that slide because of all of our acreage except possibly our most southern acreage is oil acreage. And when you define oil as less than a 2000 gas-oil ratio, all of our acreage, based on our test inflow data is oil. We go from about a 400 gas-oil ratio on the north end to about 1500 on the south end in the Hill well. So I think the condensate window is really south of us. It might be right on our southern edge, but I really do believe it is going to be off our acreage.

And so the definition of where that line, it sounds like it's changed. Can you just talk about the geology of why the Hill well looks like it's performed as well as it has?

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

Yes. The other thing well, Noel, that Mark had commented off the line, kind of at the end of 2008, the beginning of 2009, in the Haynesville Bossier, it took us awhile to get up on a learning curve to figure out where to drill the laterals, how to frac them properly. I think, again, I know 1 of the analysts came back and said we're getting closer to mastering this thing. It's a moving target, but, I think Mark can comment on that.

Yes, Noel. We changed our frac design somewhat. We've gone to a much more of a thin fluid base, or a hybrid-type job, from our very early jobs. I think our people in the field understand reservoir better as they fracing 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. We may have been 70% or 75% earlier, were probably 90%, 95% now. You still have the occasional problem, but overall, everybody involved, from geologist to engineers to field people, we are all getting up that learning curve as quickly as we can, and, we're seeing the benefits in terms of our well results.

And, can you give me 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 Forrest Wheeler, which is on our most southern acreage in McMullen County. And then we're completing a second well in Atascosa called the Jupee well, which will be an interesting test for us.

Out of the 12 wells that we are in, 9 of them are in McMullen and 3 are outside of McMullen. So we've focused on McMullen.

Just moving over to the Haynesville for a minute. Can you talk a little bit about, of the Bossier Wells that you have done, what their performance has been like? And do have any update on diluting the Bossier play as opposed to the Haynesville?

As far as the Bossier, there's a lot of log data on the Bossier, but other than, I believe Comstock, there has been a lot of activity in the Bossier. We have been more active than most companies because some of our acreage is primarily Bossier acreage. Our farthest South acreage is 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. I've got get my notes. We completed 9 Bossier Wells this year and we drilled 10 Bossier wells this year.

And are those, 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, the limited data we've seen, the Bossier is not as good. 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 go north, the Bossier is not going to be as good. But down in the core area, it acts very similar to the Haynesville.

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 in the Haynesville?

In the Haynesville, we haven't had any issues. In the Eagle Ford, we were having, not difficulty, but you have to schedule well ahead of time to get your proppant scheduled in the Eagle Ford. Our relationship with Schlumberger, who is 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 said 6 Bcfe per well for Haynesville. And slide 17 is 5 Bcfe per well for the Bossier, that's what Mark was talking about.

Michael Bodino, Global Hunter.

Outstanding production quarter. I have a couple follow-up questions on production, and then if you'll indulge me 1 additional question. On the production side, given the fact that you're moving more towards pad drilling and completion and that's you're drilling 6 to 8 wells per pad out there in the 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 will have to see how we scheduled the pads coming on. When you have 8 wells, if you going to try to and drill 8 wells, it could take 8 months to actually get them all drilled before the completion activity if you use 1 rig. The real answer that question is going to be based on how many rigs are we going to dedicate to the Haynesville to be able to more smooth out, pad development., We can't answer the question until we get a better feel for gas prices. I think that if gas prices don't improve from the current spot levels, I think we will be hard-pressed to leave 3 rigs in the Haynesville. Just because of the return that those same rigs can make in our Eagle Ford program now that it's performing and it is still oil-focused.

So we will have to balance that lumpiness against getting higher oil production returns. I think, toward the end of this year, our goal now is create all the flexibility between our rigs and frac crews and our acreage to be able to have that full flexibility to go between the two plays. I think we're going to achieve that. And then we'll look out in 2012 and see where can the drilling rigs and the capital that we have generate the best return overall. It may not be the absolute overall production on a Mcfe basis, and then allocate those rigs accordingly, and the extent that we allocate 2 or 1 rig over to Haynesville, it means we'll either not do a lot of pad development next year, or it will take a long time to get one drilled out. But we will start out 2012 with some cushion there by having this very large project come online in our first quarter of next year on the gas side.

We will model accordingly. On the Eagle Ford, it seems like a 2-rig program, it looks like in the numbers you'll and 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 guess, we keep raising the bar for the oil to hit there. But I think that it's still possible, and if I think we will be approaching that number, it really depends on how the strong the gas production is. I think one thing that's been a real positive now is that we've arranged to use the dedicated crew. We have much more control over the timing of the Eagle Ford completions and where they've been very slow in the first 6 months, we think we'll see a lot of efficiency and a lot of 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 the gas number has grown so large, that it's harder and harder for the oil to do that. But I think as we dedicate more resources to the Eagle Ford, we will be 10% 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 oil side.

We've just been fortunate to have exemplary Haynesville wells. If we hadn't had excellent Haynesville wells, we would definitely be at that 10%, and we haven'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 know if we'll hit it, but we will be close.

Well, speaking of hitting goals, previously we talked about an exit rate 280 million cubic feet equivalent per 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, it definitely is going to be a least that high, it possibly will be higher. We will have a strong third quarter production growth again because of the Logansport section coming on in August here. That's going to really help the third quarter. The fourth quarter, though, we won't complete a whole lot of new wells in the Haynesville, probably 3 or 4. So before we go to that really large project in December and do the 9 wells in that 10-well section, and all those will come online in January. So we don't expect to see the fourth quarter growth as large -- we think it could be a pretty good a 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 million a lot earlier than the end of the year, but whether 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're ahead of schedule on the completion side. And we actually are slowing that down a little bit by moving the completion services over to the Eagle Ford now in the second half the year versus being 100% working in the Haynesville.

Well, as we've said earlier, you got the 10 wells that will be fraced in December then coming on line in January. So 2012, we should have some fabulous production also. And as far as the production rate we gave you today, our production is north of that, as you know.

My last question, I think you had 40 million a day in South Texas. Could you give some quantification on how much of that was allocable to the Eagle Ford?

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

John Freeman, Raymond James.

I just wanted to look into the Eagle Ford acreage a little bit. I'm just eyeballing where your acreage was last quarter and after you all picked up the additional 3,000 net acres here. It looks like the adds were around the Carlson well and corner of McMullen County, and then you also looks like you added some in Atascosa. I know you we're going to do the acreage swap, which you all mentioned, so I'm just assuming that that was where McMullen got picked up. And then 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, Atascosa, Frio, and LaSalle. It's those 2 blocks that are closest to four corners?

Right. Near the Carlson well. Right?

And then the trade acreage is just on the east edge of the Carlson block. So all the acreage that we increased and changed out with the Karnes County acreage, is right there in that same area. And as far as McMullen, we are at about 13,000 right now in McMullen, a little less than 6,000 in Atascosa. A little over 2,000 in LaSalle and just a slight amount in Karnes County. That's where our acreage break-out is right now.

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. When we think about it for 2012, how do you all think about it in terms of, with th3ree rigs, possibly next year going to 4 rigs, how many frac crews do you need dedicated per the number of rigs that you're running in the Eagle Ford?

Right now, our crew is dedicated to move back and forth. And, if what we do is move a Haynesville rig 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 will be able to make it. We have a little bit of extra space in the schedule, if you will, the handle it with that 1 crew. And anything above that, we will have to negotiate additional services, either with Schlumberger or with somebody else. So we'll just go for those when we decide to make that move.

It appears that the dedicated crew we have now can service about 6 rigs, and we have 5. So as were using them now, we actually have some time when 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 could fully utilize that crew. So I think that we're really set for those services through next year.

Ron Mills, Johnson Rice.

Couple of questions just go back to I think Brian's initial question on the current production. Mark, when you talked about that 265 million 270 million a 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 the average rate, right? It mostly excluded those for the most part.

Right. A slight amount of production in that July average, but there wasn't very much, because most of it came on late in July and we step them up slowly as we get the fluid off them.

So really a current rate is higher than that, the lack of additional Haynesville completions over the remainder or most of this quarter, you probably hit the peak on the gas side. Is that the right way to look at it this quarter?

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

Right.

And when you look at the number of completions with this dedicated crew going from Haynesville to Eagle Ford. As you look at your completion schedule now, what's the schedule? I think you said you have another -- you will do 4 wells back-to-back before taking the completion crew back to Louisiana and/or East Texas and 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 Haynesville? I'm just trying to think about the completions schedule by area.

Right. Ron, we've finished the 4 wells in the Eagle Ford. We come back to the Haynesville for 2 Wells. Then we go back down to the Eagle Ford for another group and then we come back to the Haynesville for 2 or 3 more. So I think we are going to have 6 to 8 wells completed, to talk about over the next quarter call. Some of it depends on the rig schedule as well. If we drill them per the rig schedule that we have, or if they go faster or if they go a little bit slower. But that's kind of how we have it scheduled out right now.

This segway is to the 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 more than offset that financially. Directionally, you're at 1,700 to 1,800 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 3000 3500 barrels a day by year-end?

Yes. We have a much more steady production growth projected for the oil. Obviously, because we're completing the wells more steady, we're not pad drilling them the way that we are doing in the Haynesville. Although we are doing a little bit of pad drilling down there, but not to the extent that we are in Haynesville. So we should get more steady growth. And I think you're in the ballpark. We're looking at between 3000 and 4000 barrels a day exit rate, is what we're looking at on the oil side.

Yes, I think you are correct, Ron.

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 have seen on a LOE starts to flatten out or a maybe even start to go up little bit, just to account for the fact that you're getting more oily a little bit sooner than at least we were expecting.

Yes. Ron, that's correct. 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 numbers, you'll see that trend the other way. The taxes are, of course, higher on oil even than gas, and then 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 is what has driven our severance tax rates so low. Oil doesn't have that benefit. So you'll start seeing that creep back up. And the overall lifting cost, which is fairly fixed if you exclude the taxes and transportation to the Haynesville, the only increasing lifting costs is probably ad valorem taxes and stuff because a lot of the field's low cost, there are not a lot of field-level production costs that come with all this new Haynesville production. We're spreading the same cost over more volume so it's driving the rate down. So those big improvements that have driven the lifting cost 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'll be a minor offset to the profits that you have at the top line.

And then, I can't remember if it was you, Jay, or Roland, that talked about 2012 and 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 is, for lack of a better term, burdening your 2012 estimate. But at what gas prices are you assuming that you would stay at a 2-rig Haynesville, 3-rig Eagle Ford? You talk about 4 to 6 rigs, I am just trying to get a profile of to what to expect from a Haynesville versus Eagle Ford activity and the total capital plans?

Ron, this is Roland. I think if we look to the capital plans, I think as we are increasing our Eagle Ford position, we see having a minimum of 2 rigs there, most likely 3. So, on the other side, in the Haynesville program, it is more dependent on what gas price is going to be. I think to go to six rigs, we're going to have to have gas prices in excess of $5, probably in excess of $5.25 to have the cash flow to pay for a 6-rig program. So I think more gas prices are over $5, the more likely we are going to be running more rigs in Haynesville. The closer guess prices are to $4.50 or $4.25 or $4, the likelihood that we won't have very many rigs in Haynesville. And I think that's really how we're looking at it.

And what are you required to have in the Haynesville in terms of lease expiries? Is it just a 1 rig required and then if you were down to 1 rig there and had 4 rigs or whatever in the Eagle Ford, if you could support that? And I would assume what was would start to see is, the gas production start to over on the 1-rig program there.

We would keep 1 rig busy any Haynesville/Bossier just to have some activity there. You can't go dormant in our single best area. So you can budget at least 1 rig there. Now, whether we go north of that or not, our goal is to stay within our operating cash flow. We'll have to see what our exit rate looks like. Have to see what percent liquids we are versus gas. Have to see where gas price is and where 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. A lot of those questions, we won't know until the latter part of 2011. As far as how many rigs, again, like Roland said, 2 or 3 in Eagle Ford, that's a good starting point. 1 in the Haynesville, that's good starting point. That gives you your say 4, and then the question is do you add 2 more.

Given the large project that we're putting online in 2012 in Haynesville, that's going to soften that number from what it could have been otherwise. We're going to have some increases up front in 2012 on the gas site even we run no rigs in the Haynesville.

And would the drill or drilling carry, however you want to term it, that you referenced, Roland, in terms of this incremental 4000 or 5000 acres next year, would that be additive to what you would have expected to spend? Or would, say, commodity prices stay the way they are today, would you just borrow from the Haynesville to fund that drilling?

Well, I think you would budget those wells that we are drilling on that acreage at 100%, like our Eagle Ford is now. And some of those dollars would actually be going towards paying for the leasehold. Is not a real large number in the scheme of things, so that's not a major factor in how we look at the budget next year.

Richard Tullis, Capital One South Coast.

Just following up on Ron's question there. Say you do go with a lower rig count in Haynesville next year based on lower gas prices at the 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 Haynesville and 3, 4 rigs in the Eagle Ford?

We're not really ready to speculate on that at this point. Once we do allocate our budget out we will give some guidance on production, but just to speculate, if you stopped all drilling doing, what it will be, that is not really what we're at all focused on right now. It's more allocating the resources to the best return overall. So we're certainly not going to focus on top-line production as the only number. We would think the market's wouldn't either. It is really what can generate the most profits, the most sales. So that is how we are going to approach 2012, not worrying about a number.

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

What is the projected rate of return for the Haynesville wells? You average Haynesville wells, say even using the pad drilling $8 million well cost. Say, in a $4.50 gas environment.

Using the development pro cost that we're seeing right now on our pad drilling, 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.

And what are you looking at for expected working interest for 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 backlog?

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 in the well count (multiple speakers) --

We've gone from 2% to 18%. They are all over the board. We focus on our operated wells. We throw in the non-op just as a number, but the wells that we completed are mainly operated wells

How many non-up wells still in the backlog?

I think there were 9. 9 backlog for non-op.

9 gross?

Yes.

What is the net on that exactly?

Probably less than 2. I didn't add that number, but it's low.

It's probably closer to 1? We had several wells that were like a tenth of a percent.

And then, did you mentioned how much you paid for the 3,000 Eagle Ford acres added in the quarter?

We didn't mention that specifically. Since we are still -- obviously, it is still an active area we really don't want to get that specific on every deal.

(Operator Instructions) Dan McSpirit, BMO Capital Markets.

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

Yes, Dan. This is Mark. The Jupee well is just slightly, maybe about a mile, mile-and-a-half northwest of the NWR well. It is substantially longer lateral, it is over 7000 feet, and I believe the NWR was in the 4000-foot range. We've changed our frac design significantly since the NWR, which was our first completion, which was a cross-linked gel frac with multiple profit types. And this well, it is all sand. It is a lot more fluid, thin fluids, more of a hybrid-type designs. 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.

Generally, what is a gas-oil ratio in that part of the county? When you know from the NWR well at least.

Our NWR has about a 700 gas-oil ratio. Jupee would be similar.

That would compared to the Hill well, which I believe you mentioned carried about 1500? Is that right?

Correct.

Can you discuss the use of the restricted choke on the Hill well? That is, is this 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 are still evaluating it, but 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 at a more restricted rate. We've really done that with all of our wells. And even the NWR, which was our well that was completed and our shallowest well, that well still not on pump, it's flowing naturally. So we've been successful in not having to go to artificial lift early because we are flowing the wells at a more moderate rate.

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 completion. So we think our procedure is working.

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

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

What's the schedule here going forward over the next 12 to 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 are 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 at the end of next year, but if we add a lot of new acreage, we might be less than that.

And we can add the quality acreage we think we can, 50% is probably good, that's a good number.

At this time there 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 and fourth quarter, that looks very, very bright. I think we bottomed out as far as the sector on gas prices. I think things are bright for the future. We will continue to project 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.