Comstock Resources Inc (CRK) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third quarter 2011 Comstock Resources earnings conference call. My name is Jennifer and I will be your operator for today. At this time, all participants are in listen-only mode and later we will conduct a question and answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Jay Allison, President and CEO. Please proceed.

Thank you, Jennifer. Welcome to the Comstock Resources third quarter 2011 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and clicking presentations. There, you will find a presentation entitled third quarter 2011 results.

I am Jay Allison, President of Comstock, and with me this morning is Roland Burns, our Chief Financial Officer and Mark Williams, our Vice President of Operations. During this call, we will review our 2011 third quarter financial and operating results, update the results of our 2011 drilling program and discuss our plans for 2012.

Please refer to slide 2 in our presentation 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. If you will turn to page 3 in the presentation, it's the 2011 third quarter highlights. Please refer to page 3 of the presentation where we will summarize the third quarter results.

We have improved our financial results this year despite weak natural gas prices by increasing production and lowering our operating cost. We reported revenues of $119 million, generated EBITDAX of $94 million and had operating cash flow of $86 million, or $1.79 per share. The gain we recognized from selling some of our Stone Energy shares allowed us to make a slight profit this quarter, of $1.3 million or $0.03 per share. Our production increased 53% over the third quarter of last year and 8% over our strong second quarter.

The Haynesville program is driving the production gains this year as we have caught up on completions of wells we drilled in 2010 but were not completed due to the lack of frac services. We are very pleased with the results of our 2011 drilling program this year. We drilled 67 successful wells, including 51 Haynesville shale wells and 12 Eagle Ford shale wells. In the Eagle Ford, we have added to our acreage in this oil-rich play and have increased our holdings to 28,000 net acres. Our dedicated completion crew started working in South Texas in the third quarter. We put 4 new Eagle Ford wells on production and are currently completing 5 more.

Our balance sheet continues to be very strong. We continue to have good liquidity and currently have approximately $460 million in cash, our marketable securities, available borrowings on our credit facility. We will also talk about our preliminary plans for 2012 on this call where we plan to fund our drilling program with operating cash flow to protect our strong balance sheet. I will turn it over to Roland Burns to review the financial results for this quarter in more detail.

Thanks, Jay. Slide 4 in the presentation shows our oil and gas production on a daily basis for the last 15 quarters and is broken out by operating region. Production from our Haynesville shale program is shown in blue on that chart. In the third quarter of this year our production averaged 285 million cubic feet of natural gas equivalent per day, a 53% increase over the third quarter of last year and 8% higher than production in the second quarter of this year. The production this quarter set a third consecutive new record high for us.

Haynesville production increased to 200 million per day as compared to 176 million per day in the prior quarter. Production from our Cotton Valley wells decreased a little this quarter to 38 million a day and we averaged 40 million at our South Texas region and 7 million in our other regions. Looking ahead, we believe our production will come in between 94 and 97 Bcfe in 2011 which represents a 28% to 32% growth over 2010's production.

During the fourth quarter, our completion crew worked primarily in our South Texas region in our Eagle Ford program and returns to the Haynesville in late December to complete 9 wells in a 10 well pad development project. As a result, we expect fourth quarter production to decline by about 2% to 4% from our high third quarter level and to increase substantially in the first quarter of 2012 when this project is put online.

Oil prices continue to be strong in the third quarter which we cover on slide 5. Our realized oil price increased 35% in the third quarter of 2011 to $87.55 per barrel as compared to $64.97 per barrel in the third quarter of 2010. For the first nine months of this year our average oil price was $92.59, 39% higher than our average oil price of $66.54 for the same period in 2010. Our realized oil price in the third quarter has averaged 98% of the average bench mark NYMEX WTI price. We expect our oil price differential to improve in our Eagle Ford program by as much as $5.00 a barrel based on new marketing arrangements we are making as we have been able to capture some of the spread that exists between the WTI price and the Louisiana Gulf coast market.

Natural gas prices worsened in the quarter as shown on slide 6. Our average gas price decreased 4% in the third quarter to $4.09 per Mcf as compared to $4.24 in the third quarter of 2010. For the first nine months of this year, our average gas price decreased 10% to $4.09 per Mcf as compared to $4.55 per Mcf for the same period in 2010. Our realized gas price is averaging 97% of the average NYMEX Henry Hub gas price.

On slide 7 we cover our oil and gas sales. Driven by the 53% production increase our sales increased by 50% to $119 million in the third quarter. For the first 9 months of this year our sales increased 16% to $320 million as compared to $277 million for the same period in 2010 as the weaker natural gas prices offset some of the production gains we made this year.

Our earnings before interest, taxes, depreciation, amortization, and expiration expense and other non-cash expenses or EBITDAX in the third quarter increased by 72% to $94 million as shown on slide 8. For the first three quarters of 2011, EBITDAX increased 25% to $246 million.

Slide 9 covers our operating cash flow. The stronger revenues and production and lower per unit costs caused our operating cash flow for the quarter to increase 81% to $86 million as compared to the $47 million we had in the third quarter of last year. For the first nine months of this year operating cash flow was $219 million, 25% higher than cash flow of $175 million for the same period in 2010.

On slide 10 we outlined our earnings for this quarter and for the first 3 quarters of 2011. We reported net income of $1.3 million this quarter, or $0.03 per share as compared to a loss of $4.7 million or $0.10 per share in 2010's third quarter. For the first 9 months of this year we reported net income of $7.7 million or $0.16 per share as compared to net income for the first 9 months of last year of $1 million or $0.02 per share. The third quarter results include a gain of $2.5 million, or $1.6 million after-tax, or $0.04 per share that relates to the gains on the sales of our marketable securities during the quarter.

The 9-month financial results include several unusual items. We had a charge of $1.1 million or $0.7 million after-tax or $0.02 per share related to the early redemption of our 2012 senior notes in the first quarter. We also had a $9.8 million impairment or $6.4 million after-tax or $0.14 per share for expired leases. And, we had a significant gain from the sale of our marketable securities made so far this year of $32.2 million, or $20.9 million after-tax or $0.46 per share.

On slide 11 we show our lifting cost per Mcfe produced by quarter. Our lifting costs are comprised of 3 components, production taxes, transportation and other field level operating cost. Our lifting costs continue to improve falling to $0.79 per Mcfe this quarter as compared to $1.17 per Mcfe in the third quarter of 2010 and $0.85 per Mcfe in the previous quarter. Production taxes were only $0.01 this quarter and transportation averaged $0.31 this quarter. Refunds our production taxes previously paid lowered the taxes we had this quarter. Field operating costs averaged $0.47 per Mcfe this quarter as compared to $0.75 for the third quarter of last year and then $0.51 in the second quarter of this year. Higher production in the Haynesville combined with the absence of the high cost properties we sold in the fourth quarter of last year are allowing us to achieve the lower lifting rate.

On slide 12 we show our cash G&A per Mcfe produced by quarter excluding stock-based composition. Our general and administrative expenses decreased to $0.18 per Mcfe in the third quarter as compared to $0.29 per Mcfe in the third quarter of 2010 and $0.21 per Mcfe in the previous quarter. The improvement is due to the higher production level combined with lower G&A cost in 2011. Our depreciation, depletion and amortization per Mcfe produced is shown on slide 13. Our DD&A rate in the third quarter improved to $2.96 per Mcfe, a decrease from the $3.12 rate we had in the second quarter of this year but it's an increase from the $2.72 rate we had in the third quarter of last year.

On slide 14 we detail our capital expenditures. We spent $496 million in the first 3 quarters of this year as compared to the $393 million that we spent in 2010's first 3 quarters. We spent $344 million in our East Texas/North Louisiana region with $146 million in our South Texas region and $6 million in our other regions. $53 million of the $496 million spent so far in 2011 was for additional leasehold in the Eagle Ford shale or the Haynesville shale. We expect to spend a total of $575 million in 2011 on our drilling and completion activities. In addition, we expect to spend up to $125 million on acreage acquisitions in 2011. Now, $24 million of this $125 million will be in the form of a drilling carry that will be paid by us over the next 2 years.

Slide 15 recaps our balance sheet at the end of the third quarter. On September 30 we had $5 million in cash and $32 million in marketable securities on hand representing the 2 million shares we hold in Stone Energy. The value of these shares has increased somewhat since the September 30 balance sheet date.

In total, we have $747 million of debt which is comprised of $300 million of our 7-3/4% senior notes, $297 million of our 8-3/8% senior notes, and then $150 million outstanding under our bank credit facility. On October 31 the borrowing base for our credit facility was increased to $550 million. Taken into account the cash on our balance sheet and our marketable securities and our unused $400 million that is available on our bank credit line, we have about $460 million in liquidity. Our book equity at the end of the quarter was $1.1 billion, making our net debt about 39% of our total capitalization. I'll now turn it back over to Jay.

Thank you, Roland. If everybody will turn to slide 13 -- or 16. On slide 16 we have an updated map of our holdings in the Haynesville shale play in North Louisiana in East Texas. Our acreage is highlighted in blue. We currently have 90,000 gross acres or 79,000 net acres that we believe are perspective for Haynesville shale development, 59,000 acres are in North Louisiana, the better part of the play. Given expected well spacing of 80 acres and expected per well recovery of 6 Bcfe per well, our acreage could have 4.4 Tcfe of resource potential.

Slide 17 shows the acreage that we believe also has the potential for the development of the upper Haynesville shale or middle Bossier shale. Our acreage is highlighted in blue. We currently have 60,000 gross acres or 51,000 net acres that we believe are perspective. Given similar expected well spacing of 80 acres and expected per well recovery of five 5 Bcfe per well, our acreage could have 2.4 Tcfe of resource potential. I will now have Mark Williams, our head of operations, give us an update on our drilling program is year. Mark.

Thank you, Jay. On slide 18 we recap our activity in our East Texas/North Louisiana region for this quarter. Our activity in this region is primarily focused on developing our Haynesville and Bossier shale properties. We drilled 52 wells or 21.6 net in this region in 6 different fields in the first 9 months of this year in all but 1 of those were Haynesville or Bossier shale wells. We participated in one Cotton Valley vertical well. All of the wells were successful.

In the first 3 quarters of this year we completed 65 or 35.7 net of our Haynesville or Bossier shale wells which are put on production at an average per well initial production rate of 10 million cubic feet equivalent per day under our restricted choke program. Since we initiated our Haynesville shale program in 2008 we have now drilled a total of 169 wells, 99 net wells, soon to break the 100 mark.

Slide 20 shows the first two units in Logansport field, 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 put on production in July -- near the end of July. As you can see, we utilized 3 drilling pads to drill and complete the 8 wells which increases our efficiency and reduces our overall well cost. This process also allows zipper fracs to be utilized which is a stimulation method where all the wells on a pad are fraced with 1 frac fleet by alternating between the wells in a stage-by-stage procedure. We believe this method increases the effectiveness of the stimulations on the wells as compared to fracing them one at a time. By completing all the wells before producing any of them, we think the ultimate recovery of this section will be maximized.

The schematic on the right side of slide 20 shows our sections of 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. We will begin completion operations on this unit in late December and expect first production in early 2012.

Our South Texas region is displayed on slide 21. All of our South Texas activity in 2011 has been focused on our Eagle Ford program. We drilled 12 Eagle Ford shale wells and that was 12 net also in the first 9 months of 2011. So far this year we have completed 8 of these wells, 8 net, including a well drilled in 2010. The 8 wells had an average per well initial production rate of 683 barrels of oil equivalent per day. We have 5 additional wells that are being completed by our dedicated frac crew at this time. We plan to bring all of these wells on at the same time to maximize the effectiveness of the fracs.

On slide 22, we outline our Eagle Ford shale play in South Texas. We increased our holdings in the Eagle Ford to 32,000 gross acres and 28,000 net acres in this quarter. We closed on approximately 6,000 net acres in October in two separate transactions. Using a conservative 100-acre spacing assumption, we believe our acreage, which is all in the oil window, has the potential to recover 83 million barrels of oil equivalent net to our interest. We have 10 producing wells on our acreage including 4 wells we completed in the third quarter.

The Cutter Creek #1H was drilled to a vertical depth of 9,970 feet with a 4,824 foot lateral and was tested at an initial rate of 575 barrels of oil per day and 0.2 million cubic feet of natural gas per day or 608 BOE per day. The Forrest Wheeler #1H was drilled a vertical depth of 11,142 feet with a 5,458 foot lateral. This well was tested at an initial rate of 480 barrels of oil per day, 0.7 million cubic feet of gas per day or 597 BOE per day The Rancho Tres Hijos A #1H, on the map it's RTH A #1H, was drilled to a vertical depth of 10,911 feet with a 4,512 foot lateral. This well was tested at an initial rate of 465 barrels oil per day and 0.6 million cubic feet of natural gas per day or 565 BOE per day.

The Jupe A #1H was drilled to a vertical depth of 8,282 feet with a 7,101 foot lateral. This well was tested at an initial rate of 197 barrels of oil per day and 0.1 million cubic feet of gas per day or 218 BOE per day. The Jupe is our first disappointing well in the play and it appears to be in a low pressure area of the reservoir. This well will be the first well that we will put in an artificial lift and we expect the production rate to improve from the initial test rate when it is on pump. The well is actually on pump as of the end of last week. It is still improving and it has improved at least 50% from the test rate and is still cleaning up. All of the reported well results were obtained while following our restricted choke program. I will now turn it back over to Jay.

I will go over the final two slides which is the 2012 drilling program and then the 2011 and 2012 outlook and then probably as a group we'll go back to the slide 22 which is the Eagle Ford shale program, but if you will go to slide 23 we outline what we expect to spend in 2012 on our drilling program. With the week outlook for natural gas prices we plan to reduce our spending level next year in order to line up with our spending with the cash flow that we think will probably have. We plan to focus on our oil projects as they do have higher returns.

In the Haynesville we are reduced from 3 rigs to only 1 rig, and our East Texas/North Louisiana region we plan to spend $104 million to drill 38 wells or 13.3 net wells, this includes 11 operated wells or 7.9 net wells with remaining wells representing our share of non-operated wells that we will participate in. We will be carrying over 17 wells or about 14.7 net wells that we drilled this year to be completed in the first quarter of 2012. The cost to complete these wells is about $65 million. The rest of the budget is being spent to drill oil wells.

We're planning to drill 32 wells or about 28.9 net wells on our Eagle Ford shale acreage. We have budgeted $221 million for our Eagle Ford program which includes $14 million to complete 6 wells or 5.6 net wells that we'll drill this year. We have $6 million budgeted for other regions. In total, we plan to spend $396 million on drilling in 2012 which should come close to being 100% funded by our operating cash flow. We believe this program will provide 8% to 12% plus production growth in 2012 with oil production growing from 5% in 2011 anywhere from 10% to 12% plus in 2012. To the extent that we have stronger natural gas prices, we do have the flexibility to ramp up drilling and out of the Haynesville or Eagle Ford programs.

The final slide, which is the 2011- 2012 outlook, it's on slide 24, we are having a very good year despite the low natural gas prices. Our production growth has been very strong. We expect production to increase by 28% to 32% over last year with completion of the backlog of wells drilled in 2010. Our low-cost structure continues to improve each quarter with a higher production level and drilling and completion efficiencies that we are now seeing.

Our Eagle Ford shale program in South Texas is progressing. We have 2 rigs drilling on our Eagle Ford shale acreage and we've increased our acreage holdings to 28,000 net acres and have achieved that at a reasonable $6,000 - $7,000 per acre cost. The market value for our Eagle Ford acreage is more than 3 times our average 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 guard our strong balance sheet. We have $400 million available on our bank credit facility and $60 million in marketable securities and cash to supplement the cash flow we will generate. We plan to spend approximately $396 million in 2012 for drilling and completion activities. We expect to reduce the number of rigs drilling for natural gas in our Haynesville shale program from 3 rigs to 1 rig. We will be adding 1 drilling rig during 2012 to the 2 which are currently drilling for oil in the Eagle Ford shale development program in South Texas.

Our 2012 drilling program will focus much of our drilling activity on growing our oil production while at the same time staying within operating cash flow that we should generate. To the extent that natural gas prices improve, again we do have the flexibility to increase our drilling activity out of the Eagle Ford shale or Haynesville shale, depending upon where we can generate the best returns. For the rest of the call, we will take questions only from research analysts who follow the stock so, Jennifer, I will turn it back over to you to go open it up for questions.

(Operator Instructions). Your first question comes from Brian Corales, Howard Weil. Please proceed.

Good morning, guys how are you?

Morning.

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

Yes, Brian, this is Mark.

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

That's perfect.

Yes, Brian. On the restricted rate program, we are following the same basic procedure that we used in the Haynesville that we feel has been very successful. We bring the wells on on a small choke and work them up to maybe anywhere from a 14 to an 18/64 inch choke and maintain that steady choke size, monitoring pressure, monitoring rate and based on evaluation that we have done of our wells versus offset wells, we believe that we are getting a pretty large benefit from the restricted rate program. The IP rates that we report our -- would be pretty equivalent to 30-day rates because we don't see much decline in the very, very early life of the well for the first 30 or 60 days. They are still cleaning up and they are still steady or improving. So, these are -- the program is moderating the decline and we feel like it is giving us the best EURs.

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

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

Okay, that's helpful. And just one final. What are you seeing on the cost of the Eagle Ford? The completed well cost?

We are right now still doing it on single well deals and we're running $8.3 million to $8.5 million. When we get into our development program, and I think we will see it on our Hill lease that we just finished completing, when we get all those costs accrued we will see some improvement like we did in the Haynesville and we expect to knock maybe $0.5 million to $0.75 million off of our average well cost once we do that but we are still primarily drilling test acreage and hold leases.

All right, guys. Thank you.

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

Okay. We have done 1 full lease development and it is on the Hill lease which is some of the southernmost acreage. We have completed 5 additional wells on the Hill lease to go along with Hill #1 so it is a fully developed 6-well lease. We have completed the fracs on the 5 wells and we are currently drilling out frac plugs and starting our flow-back, but it has just been going on for a few days. And, we picked that area because the results are good, it gave us the opportunity to perform micro seismic on our wells to gain some knowledge about the frac growth, directions and things like that. We are testing various frac technologies on that lease to see which one we feel like gives us the best result. And we should have those results are by the next call unless -- along with some others.

We are also drilling a well near the Carlson well. That well will be reported with the fourth quarter results and then another Cutter Creek well which will be reported in the fourth quarter. So we're really focusing mainly in the LaSalle and McMullen area with our development activity and then we will be focusing next year on a lot of the new acreage that we picked up.

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

Your next question comes from the line of Ron Mills. Please proceed.

Morning, Jay. A question on the 6,000 acres added. I am assuming that's the 28,000 to get to that number that is what you added in October, is that correct?

Yes, that's correct, Ron.

Okay, great. And then looking at your map you have that acreage looks like it was added some over in eastern Atascosa County, some in LaSalle County and some in McMullen County. Can you - and maybe, Mark, this is more for you, when you look at that trend, especially on that far eastern Atascosa County acreage, where does that land in terms of depth and/or pressure regimen. Do you expect it to be more like the NWR well you drilled in Atascosa County or the Jupe?

This is Mark. That acreage, the way we put that on our maps and geologically, should be very similar to our Cutter Creek and Carlson area depth wise, pressure. It is on trend to the northeast with well results like our Coates and have acted very similarly to the Cutter Creek and the Carlson. We haven't added any acreage up around the NWR and the Jupe since the very beginning of the program. I think that was the first block of acreage we leased and then earlier results in the area told us don't add any acreage up there until we can prove that we should. And, that's why we drilled Jupe well with the long lateral to try to support the idea of being able to add acreage up there because it has been available and we turned down a lot of deals in that area.

We like the acreage we've added in northeastern Atascosa. Like I said, it is on trend with our Cutter Creek and all the results we see along that trend we are very satisfied with. The other acreage was in -- the other bigger block was in LaSalle and, there again, it is right on trend with our Carlson and our Cutter Creek and so we feel good about it also.

Okay and if I had to look at -- if we look at your 2012 budget when you look at 32 wells you plan on drilling in the Eagle Ford next year, can you sketch out at least as you view it today how those wells will be split between your McMullen, your Atascosa and your LaSalle/McMullen County blocks?

Six of the wells are going to be, at least planned right now, are going to be on that northeastern Atascosa or the southeastern Atascosa block to hold that acreage. Almost all of this drilling is drilling under primary terms of the leases so we will be drilling to maintain our leases and hold our acreage so 6 of the 32 wells would be up there. I believe about 10 of them are in that four corners area of the McMullen, La Salle, Frio Atascosa Carlson area. The remaining are going to be the Cutter Creek area and down in the Swenson Hill area to hold acreage down there. So about 2/3 of it is McMullen and the rest of it is on the four corners area and then 6 up to the northeast.

Okay.

By the way, we don't have any more wells planned on our Jupe NWR area at this time.

Okay when you look at the drilling plans, can you do one derivative of that in terms of compare the drilling plans with the completion plans? I know you have a lot of carryovers this year. It sounds like you'll have some carryovers in both areas in the first quarter of next year, but when you look at next year's budget and even the remainder of this year in the Eagle Ford you plan on drilling another 7 to 10 wells in the Eagle Ford this year, 32 next. How many completions do you expect to get in the Eagle Ford?

I think it's going to be pretty much a one-to-one on our drilling plans. The carryover of the Eagle Ford wells here at the end of 2011 is mainly due to us taking our frac crew to the Haynesville to frac that 10 well pad. So that kind of drives the carryover both of the Haynesville completions and of the Eagle Ford completions. We don't have any 10 well pads planned for next year because we're going to only have one rig in the Haynesville and it is going to be primarily drilling to maintain leases and we have some new acreage, a little bit of new acreage we picked up that we have to drill a couple of wells on, so we won't have any of that type of carryover activity next year.

Great. And then, Roland, one last one for you. You mentioned on the WTI pricing, or your Eagle Ford pricing, your price realizations were higher than they had been relative to WTI in the third quarter. Did you say you expect that to further increase by $4.00 or $5.00 per barrel and, if so, any more background on that marketing arrangement that you're working on?

Yes, Ron, we didn't really see much of that improvement in the third quarter yet because those are new arrangements coming in place now. But, I think for a lot of our November and December production and then first quarter next year we are going to get a better pricing, priced $5.00 better than what we have been receiving for a lot of our Eagle Ford production. We think that is kind of the start of a trend where we see that oil in the area a lot of people have been transporting that oil to Louisiana market by barges, by rail, by various means and as a lot of that capacity has ramped up there, they are now willing to start sharing some of those spreads with the producers. I think that kind of continues into next year. We're actually looking to try to price our -- we're hoping to be able to start doing our marketing there and price it off of LLS not WTI, so we are working on that at this time.

And you're working this as kind of a 12-month marketing arrangement or is this almost month-to-month or how are you approaching that negotiation?

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

Okay, let me let someone else jump in. Thanks.

Thanks, Ron.

Your next question comes from the line of Kim Pacanovsky. Please proceed. Kim, your line is open.

Oh, sorry about that. Hi, everybody. Good morning.

Good morning.

Is that marketing arrangement for 100% of your crude?

Not at this point, no. It's a lot of the new Eagle Ford production. I don't think 100% of it is in there yet, but it will be probably about the time we get in to next year.

Okay. All right. Roland, when you say that virtually all of your CapEx is going to be covered by your cash flow in 2012, what kind of price deck reason for oil and gas?

That's definitely variable because a different day you could come up with a different answer. But, generally, we're looking at market prices of at least last week, I don't know where they are today.

Okay. And, I guess kind of to play devils advocate, and this is a conversation we have had many times about hedging, and I'm just wondering if you thought about hedging some of the crude with crude prices so strong and there being so much volatility in world markets with the whole Europe thing going on. I mean, have you thought about putting a little bit of crude in hedges?

Yes, Kim, we definitely looked at that for the Eagle Ford program because of the need to have strong oil prices to support that program. Like we have been talking about, I think one of the problems is getting -- making sure that we can get the differentials where when we do hedge we have a real hedge and I think with that change in the market there to the extent you have a WTI hedge in place it may not be very good, so I think that is why we would like to see some of the contracts priced more like LLS if that is where the market is going there. So, I think all of that is kind of working together but we do have some target prices that we would not mind locking in on the oil to support some of the Eagle Ford development and then much higher, better gas prices would support maybe adding a rig to the Haynesville.

Okay, great.

We obviously aren't anywhere near there.

No, you're not.

No. So that is where we are focusing probably the oil makes more realistic sense.

Absolutely. And, that block that you were talking about in the northeastern -- actually it's really not, it's is the northeastern part of your property in Atascosa, when will you put the first well in on that new block of lease hold and also when will that 2012 rig arrive in the program, the new rig?

As far as the new lease hold in our northeastern property, southeastern Atascosa County, I think that is a December move-in date. We've still got to get all the surface work done, settle with landowners and all that, but that is what we're planning on doing is drilling the first well up there very early and then looking at the results and then moving in mid year next year to drill the rest of them.

Okay.

And the other question?

Just when the new rig is going to move in?

The new rig is scheduled to move in in June.

June. Okay, June. Okay. One more quick question. What was the 2010 average cost on the Haynesville wells? Just so we can compare that $8 million AFE that you're seeing now?

It was -- I think it was about $9.5 million to maybe even slightly higher than that for 2010.

Yes. Okay.

We probably had -- went up as much as $10 million at one point.

Yes, I remember the $10 million. That's great progress.

Yes, that definitely improved a lot in 2011.

Okay, great. Thanks a lot, guys.

Kim, I think on hedges, too, we said this before. Up until the end of 2010, we didn't have a shale play that we thought that you could really farm wells on and we think we have years and years and years of drilling in the Haynesville, Bossier so if you look at our balance sheet today and you see we pulled back from 7 rig program to now we'll have a 1-rig program next year and we are trying to drill within our operating cash flow, but I think that if prices go up and that causes us, in other words there's -- we had taken action because prices go up, then prices go up that cause us to add a rig or two either in the Eagle Ford or in the Haynesville, Bossier.

I think at that point in time if you are going to commit to a rig and commit to a completion crew then I think you can hedge that program and I think for the very first time again we have that type of program in the gas window with the Haynesville Bossier and I think now we'll probably have it in the Eagle Ford. So, when you talk about hedging now, your hedging a program that you almost know the outcome of so I think our attitude is different. Historically, we would hedge if we bought something. We didn't aggressively buy in 2006, 2007, 2008, 2009, 2010, even this year as you know. It was acreage acquisitions or purchases and it was the sell of Bois d'Arc Energy, et. cetera, but I think the hedges are a little different now when you talk about hedging program you probably know the outcome of.

But you could have hedged a program in the Haynesville that you knew the outcome of. I think --

I don't think because we didn't -- we only drilled one well in 2008. In 2009, it was the middle of 2009 until people quit drilling in Harrison County.

Oh, yes, okay.

And you start drilling in DeSoto and even if you look in 2009 we only drilled 42 wells and they were spotty. We drill them kind of like in Eagle Ford. We drilled them in all four corners of the acreage, then you go to 2010 and 2010 that's when we drilled more Bossier wells, we drilled more Haynesville wells and the bottom really fell out so starting somewhere kind of in the middle of 2010 I think at that point in time you could say, yes, you now understand your Haynesville, Bossier acreage as the other industry partners do so you can start hedging, but there's been a period where you would see a $5.00 plus gas price to hedge and, besides that, we're pulling the program back, not adding rigs.

Okay. Art, thanks, Jay. I appreciated.

Thank you, Kim.

Your next question comes from the line of Noel Parks. Please proceed.

Good morning.

Hi, Noel.

Just a couple questions. Thinking about the results at the Jupe well there, can you talk a little bit about sort of what happens geologically as you move from the south of that acreage block you have where you had the three have the NWR well about 400 barrels a day up to the Jupe. How did things change there? And are those metrics you can apply when you're looking at future acreage?

Noel, this is Mark. Yes, what we saw in the Jupe well was lower reservoir pressure and it may just be that we are just far enough north from the NWR that we've gone from a slightly over pressured reservoir to just a very slightly under pressured reservoir. And so the well wouldn't flow oil against a full call in the water. If it was flowing back frac water, but no oil was coming into the fractures from the reservoir. As soon as we got the pressure down just a few hundred pounds we started making a fair amount of oil and now that we put it on this artificial lift system, we are making substantially more oil.

So, it's a little bit under pressured, we didn't expect it to be quite that under pressure, but one of the things we think is going on that we have seen along the play is that if you get too close to the Peirsall Austin chalk production which is just immediately above the Eagle Ford, that you can have issues with being under pressure. And we thought this well was far enough away because it is still several miles away from any Austin chalk production but it may just be right on that feather edge of being affected by the Piersall field. That's one of the reasons we haven't purchased any acreage that shallow or that far north and we've really focused a little bit deeper than that and we will continue to do so based on these results.

And sorry if you said this before. The new acreage block further north in eastern Atascosa, it is deeper there?

That is correct. That depth and pressure is going to be very equivalent to our Cutter Creek so if you kind of follow the direction of the color contour lines on our map and where it drops down to the southwest, that depth is very similar to our Cutter Creek and our Coates wells, so we don't expect any issues with being under pressure at that location as compared to the Jupe.

Got it. And I just had a question on the balance sheet I wanted to check with Roland. Did you say that your bank credit line balance is $150 million right now?

That is correct, Noel.

That the total debt $747 million, am I missing something because I thought the two -- your two high yields were a little -- were less than $600 million together?

They are slightly less than -- they are slightly less than $600 million, one is $300 million and one is $297 million.

Okay so it is pretty close then?

Yes.

Okay.

And what is on the bank credit facility?

Okay, great. And just a last thing. Could you talk a little bit about what your thinking is on unit costs next year? As your mix is going to change a bit on the more oil from the Eagle Ford and then eventually a decline on the Haynesville, just how the different cost lines will look.

Sure. As we look at next year, the first half of next year we see kind of a pretty big gas growth a couple of quarters and then after that with the program kind of wound down in the Haynesville will see, that's where we see more -- our biggest oil percentage is coming in. I think these cost trends show up in the second half of next year, not so much in the first because of all that gas is coming on in the first half of the year, but if you look at our proposed budget and with the production growth targets and the change from 5% natural gas, 5% oil component to 10% to 12% oil, we would see the lifting cost increasing a little bit on a per unit basis just because we will have production taxes on oil production, it's not exempt like some of the tight gas projects are. We will have higher overall field cost but just the cost to move oil and store it and dispose the water are going to be higher. There is very little cost associated with producing a Haynesville gas well.

So, but given that the composition, we really see our lifting cost maybe going up $0.15 to $0.20 per Mcfe with result of that transition in 2012. We see the revenues per Mcfe increasing dramatically beyond that. So it's a much more profitable -- higher cash flow per unit of production with that production mix. So we would see revenues maybe increasing $0.80 per Mcfe just these current spot prices today on that same production mix with cost only going up a fraction of that.

Okay. And G&A, any significant impact on that sort of as you head in the second half of the year? I'm not sure if there's--

No, G&A is relatively stable and we expect higher production rate in the next year so that means it should be no higher than it is now if not lower.

Great.

The only pressure on costs would be on the lifting cost side.

Okay.

It would be pretty minor compared to the big growth in the revenues.

Great. Thanks. That's it for me.

Your next question comes from the line of Leo Mariani. Please proceed.

Hi, guys. How much acreage do you guys have in that area where you drilled the Jupe and NWR wells?

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

It is a gross number or net?

That is a net number.

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

I think, we've got -- Leo, this is Roland. We expect potentially that to grow maybe 2,000 more acres with stuff that we are currently trying to work on and hopefully close. So, that's kind of more the immediate. For next year, to the extent there are opportunities that fit, that made sense to us we would add acreage. I think it is not easy to come by acreage in the area that we want to develop in the Eagle Ford. I would think that we're working on some other areas, other oil areas, and that is probably where we had acreage more likely than the Eagle Ford but we will respond to opportunities that become available.

Okay. Could you guys just talk about infrastructure in the Eagle Ford? Are you guys getting in to any pipelines or are you just trucking your oil to kind of other pipelines? How are you guys kind of managing that process?

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

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

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

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

Leo, this is Mark. That's correct. That's development well cost.

Okay and I guess just to clarify one of your other comments, I guess did you guys, if I heard you correctly, said that you are not really going to be pad drilling in 2012, more just moving the rig around to hold acreage, is that right?

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

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

Will have a gas price probably north of $5.00. It's twofold. One, to provide us the cash flow to want to invest in here but even with higher cash flow we will have to evaluate our return opportunities. We might -- if we had higher gas prices we may add a rig to the Eagle Ford program versus the Haynesville just based on the ability to have a higher return. We have no real requirements to -- other than what we are doing we really don't have any requirements to keep our acreage intact so we have no obligation so we're drilling, 100% Haynesville would be drilled for return. We just evaluate our return opportunities based on the cash flow we have available.

Okay. You guys talked about going from 3 rigs in the Haynesville to 1. Is that kind of happening in the next couple of months? Can you just give us an indication of timing on that?

Yes, Leo. That is in January and February to where we will be releasing those rigs or redeploying them if we have a new opportunity.

Okay. Thanks, guys.

Thank you, Leo.

Your next question comes from the line of Amir Arif. Please proceed.

Thanks, good morning, guys.

Hi, Amir.

A few quick questions one on the Haynesville, even though your rig count is coming down your backlog is going up. Is that just related to the large pad drilling you're doing or is there anything else going on there?

Yes, Amir, this is Mark. That's all because we are drilling that 10 well section. All of our operated backlog, if you will, is because we have to get all the wells drilled before we frac them in December. The other is just some -- there's, especially on the gross well count, there is a lot of activity in non-op but it's very low working interest so it kind of looks big on a gross well count but does not affect the net very much.

Okay and if somebody should be caught up on the carryovers by the end of 2012 around the completion time?

That is probably correct.

Okay and then can you give us a rough sense of how much of the 8% to 12% growth next year is due to carryovers from 2011 versus new drilling?

I don't think -- we could look at that and get back to you. I don't think we have that number on the top of our head.

Okay. And then just going back to the previous question here in terms of what gas price would you add additional rigs and lock it in on the hedging side? For the commodity you mentioned $5.00 but then you also mentioned that incrementally you would rather add to the Eagle Ford, so just if oil stays at the current $80 level, what gas price would you need to go back to drilling in the Haynesville?

It's hard to look ahead to that, but clearly when we have over $5.00 gas, we do like the returns in the Haynesville program and we would have a lot more cash flow to work with potentially. We would have almost another $100 million which would support a whole rig in the Haynesville, and would raise our growth profile a lot if we ran another rig in the Haynesville. That's obviously a very important number, $5.00, for us to take a hard look at it. Anything north of $5.00 is very strong. I think there is a point where that gas projects would be equally attractive to the oil projects at a very high $5.00, maybe $6.00 gas price and then maybe it does switch over and say well, now our return is better in the Haynesville.

Okay, and are you thinking of adding any hedges on the oil side using the same thought process as you incrementally add the rigs into the Eagle Ford hedging as well?

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

Okay, thank you very much.

Thank you.

Your next question comes from the line of John Freeman. Please proceed.

Good morning, guys.

Hi, John.

Following up on Leo's question a while back again on the Jupe NWR acreage that you said was like 5,000 net acres so I guess just a little bit less than 20% of your acreage. I'm trying to get a sense of since there is not going to be anything drilled in that area, based on Mark's comments in 2012, sort of what to do lease expirations look like on that block?

John, this is Mark. I think those leases have 2013 expirations. So, we will look at it during the year in 2012 and then decide if we want to work on extending or letting that acreage go. A lot of that will depend on the offset drilling and how the Jupe acts once we have it stabilized.

Okay. And then a question for Roland, I am trying to reconcile, and I apologize if I missed this, but I am trying to reconcile the amount of money that has been spent to this point after including on acreage acquisitions including the 6,000 acres you picked up in October that wasn't included in the slide you all have on the $53 million you spend through the first 3 quarters. So I'm just trying to get a sense of the $125 million that you say is for acreage acquisitions in 2011, is that how much has been spent or is there still left over amount that you are just setting aside on other acreage you're trying to pick up?

No, that has not all been spent. We still have a fair amount budgeted that -- of what we would hope to try to pick up before the end of the year. So we might not spend all of that total $125 million.

And, Roland, how much of was spent on the two transactions on the 6,000 acres you picked up?

For the 6,000 acres I think we spent about $40 million they roughly cost between $6,000 and $7,000 an acre so it's a little around $40 million.

Okay.

A large part of that. Yes.

So based on your current acreage budget you all increased for the rest of the year you've targeted another roughly $30 million or so for additional acreage you're hoping to pick up?

That's right.

Okay.

That's pretty close. And then remember of that amount that we spent, $24 million of that amount really is just going to be an obligation to pay over the next two years so it was not cash, so part of the acreage we picked up, 75% of the consideration was in the form of paying their drilling cost like the drilling carry. That's included in those numbers, too.

All right, perfect. Thanks a lot, guys.

Thank you, John.

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

Just in closing, again we did -- we had strong financial results, our costs were down, we've got a strong balance sheet, we've kind of given you a glimpse of 2012. There should be a 10% production growth or more. Should have a greater financial impact in our bottom line in 2012 because it is geared toward oil. We're reducing the Haynesville rig count, as Mark said, from 3 to 2 to 1. We should have 1 rig by maybe late January, early February 2012 drilling Haynesville wells.

And then I think what you haven't seen, which I would have liked to have given you a preview on, are the 5 Eagle Ford wells in McMullen County that are in various stages of completion, so you know they're in McMullen, you know they are in a better acreage position, and you know they are in various stages of completion. So, once that -- I think once you see that I think you will be pleased with the program. And, historically, all of you have followed us for years and years and years and you know that we would not be adding acreage in a play if we do not think the play wasn't quality and we do think it is quality. And, I think Mark would tell you that the more we drill here the more comfort we have with the program and we think that our acreage we probably drill a well every 100 acres in the be Eagle Ford. So with that, again, thank you. Those were great questions. Thank you.

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