Comstock Resources Inc (CRK) 2010 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Comstock Resources second quarter 2010 earnings conference call. My name is Annika, and I will be your operator for today.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. At this time, I would now like to turn the call over to Mr. Jay Allison, Chairman and CEO. Please proceed, sir.

Thank you, Annika. Welcome to the Comstock Resources second quarter 2010 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 Second Quarter 2010 Results.

I am Jay Allison, President of Comstock, and with me this morning is Roland Burns, our Chief Financial Officer, and Mack Good, our Chief Operating Officer. During this call we will review our 2010 second quarter financial and operating results, as well as updated results of our 2010 drilling program.

Please refer to slide two in our presentation and note that our discussions today will include forward-looking statements within the meaning of the securities laws. While we believe the expectations and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Now, if you would, refer to page three of the presentation, where we summarize the second quarter results. Strong production growth and higher oil and gas prices improved our financial results in the second quarter compared to the second quarter of 2009. Our production in the second quarter increased 30% to 20 BCFE. For the quarter, we reported revenues of $91 million, generated EBITDAX of $63 million, and had operating cash flow of $56 million, or $1.23 per share. We had a small net loss in the quarter of $1.6 million, or $0.04 per share.

We continue to have strong results in our Haynesville shale drilling program. 47% of our companywide production is now coming from the Haynesville shale. We drilled 36 successful wells, including 34 horizontal Haynesville shale wells in the first half of this year. We are on track for another year of strong reserve growth driven by our Haynesville shale drilling program.

Our balance sheet continues to be very strong, which will allow us to pursue our business plan this year, without having to rely upon the capital markets for any funding. I will turn it over to Roland Burns to review the financial results for this quarter in more detail. Roland?

Thanks, Jay. On slide four in the presentation, we break out our production by quarter and by each operating region, and we highlight the production from our Haynesville shale red in red on the chart. For the second quarter of this year, our production averaged 219 million cubic feet of natural gas equivalent per day, 30% higher than our production in the second quarter of 2009 of 169 million per day. Production was also up from our first quarter average rate of 209 million per day. Our East Texas/North Louisiana region averaged 160 million per day, with 58 million coming from our Cotton Valley wells and 102 million coming from our Haynesville shale wells. Haynesville wells are now making up 47% of our total rate. Our South Texas region averaged 44 million per day, and our other regions averaged 15 million per day in the quarter.

We had some ownership adjustments which added some production to the East Texas/North Louisiana region in this quarter.

Starting in the second quarter, we're running behind in completing our Haynesville shale wells, due to the unavailability of pressure pumping services. We currently have 17 Haynesville shale wells drilled waiting on completion, and the backlog continues to grow.

Given the situation, we're lowering our production guidance for this year. We expect production in 2010 to approximate 74 to 77 BCFE, which represents a 13% to 18% growth over 2009. We do expect production in the third quarter to decline from our second quarter record high level.

Oil prices continue to be strong this quarter, as shown on slide five. Our realized oil price increased 37% in the second quarter of 2010, to $67.37 per barrel, as compared to $49.24 per barrel in the second quarter of 2009. For the first half of this year, our average oil price was $67.24, 60% higher than our average oil price of $41.95 for the same period in 2009. Our realized oil prices averaged 86% at the average benchmark for our NYMEX WTI price so far this year.

Slide six shows our average natural gas prices. Our average gas price increased 5% in the first quarter to $4.09 per MCF, as compared to $3.88 in the second quarter of 2009. For the first six months this year, our average gas price increased 9% to $4.68 per MCF, as compared to $4.30 per MCF for the same period in 2009. Our realized gas prices averaged right at the NYMEX Henry-Hub gas price so far in 2010. We did have 12% of our gas production hedged in 2009, and none of our production is hedged this year.

In slide seven, we cover our oil and gas sales. The improved oil and gas prices, combined with a 30% production increase, caused our sales to grow by 40% this quarter, to $91 million. For the first six months of this year, our sales increased 48% to $197 million, as compared to $133 million for the same period in 2009.

Our earnings before interest, taxes, depreciation, amortization, and exploration expense and other noncash expenses, or EBITDAX, grew by 49%, to $63 million, as shown on slide eight. For the six months ended June 30, 2010, EBITDAX increased 64% to $143 million.

On slide nine, we cover our operating cash flow. And our operating cash flow for the quarter came in at $56 million, a 33% increase as compared to cash flow of $42 million in 2009 second quarter. For the first half of this year, operating cash flow was $128 million, 47% higher than cash flow of $87 million for the same period in 2009.

On slide ten, we outline our earnings. We reported a net loss of $1.6 million or $0.04 per share, compared to a net loss of $11.5 million or $0.26 per share in 2009 second quarter. The improvement in the financial results comes from the improved oil and gas prices and the production growth. Our second quarter results included a gain from the sale of assets of $4.9 million, which primarily relates to our sale of 520,000 shares of Stone Energy which we sold in April. For the first half of this year, we reported net income of $5.7 million, or $0.12 per share, as compared to a net loss for the first half of this year of $17.1 million, or $0.38 per share.

On slide 11, we show our lifting costs per Mcfe produced by quarter. We have broken out our lifting costs into three components -- production taxes, transportation, and then other field level operating costs. With our increasing Haynesville shale production, we are transporting more of our gas to the long haul pipelines, rather than selling the gas at the wellhead. The result is an increase in our lifting costs, but this is being offset by improved gas price realizations, as is shown this year, by our average gas price realization approximating the NYMEX Henry-Hub price this year. We have reclassed all of our prior period data to be consistent with this presentation. Our total lifting costs averaged $1.13 per Mcfe, produced in the second quarter of 2010, as compared to $1.14 in the second quarter of 2009 and $1.08 in the first quarter of this year. Production taxes increased this quarter to $0.24, as this quarter, we didn't receive any refunds for some of the tight gas credits that we've received in most of the quarters before this. Transportation costs averaged $0.18 in the second quarter, and our field operating costs averaged $0.71 this quarter, as compared to $0.89 in the second quarter of 2009. The improvement is due to the higher production level, as many of these costs in the field are fixed in nature.

On slide 12, we show our cash G&A per Mcfe produced by quarter, which excludes the stock-based compensation. Our general administrative costs decreased to $0.27 per Mcfe produced in the second quarter of 2010, as compared to $0.34 in the second quarter of 2009 and $0.30 in this year's first quarter. The improvement is mainly due to our higher production level.

Our depreciation depletion and amortization per Mcfe produced is shown on slide 13. Our DD&A rate in the second quarter averaged $2.87 per Mcfe, an improvement from our $3.31 rate in the second quarter of 2009. Our DD&A rate this quarter also decreased $0.28 from the $3.15 rate that we had in the first quarter. With Haynesville shale production continuing to increase as a percentage of our total production and we're seeing our reserves grow. As a result ,it's lowering our DD&A rate.

On slide 14, we detailed our capital expenditures for the first half of this year. We spent $182 million for our drilling program this year, as compared to $167 million that we spent for the same period in 2009. We spent most of that, $178 million, in our East Texas/North Louisiana region, with only $4 million spent on our other properties in South Texas and the other regions. In addition to the drilling expenditures we made this year, we also spent $62 million this year to acquire exploratory acreage. $39 million was spent to acquire 5,000 additional net acres prospective for the Haynesville and Bossier shale in North Louisiana, and we also spent $23 million to acquire 8,000 net acres in the emerging Eagle Ford shale in South Texas.

Slide 15 presents our capital structure at the end of the second quarter. On June 30, we had $43 million in cash on the balance sheet, and we had $54 million in marketable securities representing the shares of Stone Energy. We had a total of $468 million of total debt, which is comprised of $172 million of our 6.875% senior notes and $296 million of our 8.375% senior notes. We did repurchase $3 million of our 6.875% notes at just under par in the second quarter. We have nothing outstanding under our bank credit facility, which had has an unused borrowing base of $500 million. Our book equity at the end of the quarter was at $1.1 billion, making our net debt only 24% of our total capitalization. We expect to fund our drilling expenditures and acreage purchases that we budgeted for this year with our cash flow, our cash on hand, and the proceeds from asset sales. By the end of the year, we do not expect to have increased our debt balance in any significant way and certainly have no plans to sell any equity this year to raise capital.

I would now turn it back over to Jay.

Thank you, Roland. That is an excellent report.

On slide 16, we focus on our East Texas/North Louisiana region. Our activity in this region is focused on developing our Haynesville and Bossier shale properties. We drilled 35 wells in this region in seven different fields in the first half of this year. All of these wells were successful. 34 of these wells were horizontal wells. We have tested these wells at a per well average rate of 11.3 million per day. The horizontal wells averaged 12.1 million per day, and the operated Haynesville wells averaged 12.5 million per day. Since our last operational update, we have completed five operated Haynesville shale wells. Three of the completed wells are in our North Toledo Bend field in DeSoto Parish, Louisiana. One is in our Logansport field in DeSoto Parish, Louisiana, and one in the Beckville field in Harrison County, Texas. The wells at North Toledo Bend were tested on an average per well initial production rate of 10 million per day. The Logansport well was tested at 16 million per day. And the Beckville well in East Texas was tested at 9 million per day. These wells were drilled with horizontal laterals from 4,500 feet to 5,000 feet and were completed with 15 to 18 frac stages. The initial production rates reflect our choke back program, where new completions were being tested and produced with a tighter choke to maintain a higher reservoir pressure in the well for a longer time. We believe that the ultimate reserve recovery will improve for the wells completed in this manner.

On slide 17, we recap our holdings in the Haynesville shale play in North Louisiana and East Texas, which is updated for an additional 5,000 net acres we acquired this year. Our acreage is highlighted in blue. We currently have 89,000 gross acres and 78,000 net acres that we believe are prospective for Haynesville shale development. 56,000 acres are in North Louisiana -- the better part of the play, in our opinion. Given expected well spacing of 80 acres and expected per-well recovery of five BCFE per well, our acreage could have 3.7 Tcfe of reserve potential.

Turning to slide 18, you see 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 50,000 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 2.3 Tcfe of reserve potential.

I will now let Mack Good make a few comments on our operations in the Haynesville shale. Mack?

Thanks, Jay. Good morning, everybody.

Slide 19 will show you the number of days it's taken to drill the 59 operated horizontal Haynesville wells that we've drilled to date. On this slide, you will see that our average drill time for all of these wells is 40 days. The average drill time for our first five wells drilled, of the 59 wells, was 50 days, compared to 33 days for our last five wells. Our shortest drill time to date is 25 days, to TD. Obviously, we have improved our drilling performance considerably since our initial drilling operation took place.

On slide 20, we show the number of days it's taken to connect each of our 44 operated horizontal wells in the Haynesville that are currently flowing to sales. Comstock's average connection time to sales is about 100 days for all 44 wells currently flowing to sales. Our average days from spud to sales for our first five wells was 129 days, compared to 104 days for our last five wells. Last year, as you recall, the lack of pipeline infrastructure was the major factor contributing to the time that it took us to connect to sales. We overcame most of the infrastructure issues and reduced the time frame to connect to sales down to as low as 60 days. However, starting in the second quarter of this year, we began to experience delays in getting the wells completed. Shorter drill times, larger frac jobs that all of the operators are pumping, as well as the increased rig count in the region, created very high demand for high-pressure pumping services. And as a result, we now have 17 drilled Haynesville or Bossier shale wells that are waiting on a frac completion. We're currently negotiating with several of the major service companies to gain exclusive access to some of the new crews and equipment that they plan to put in service late this year or early next year, which will allow us to catch up with our drilling completion inventory. We expect our completion backlog to continue to grow through the third quarter, and not start to improve significantly until later this year.

Slide 21 outlines our planned activity this year to further develop our Haynesville and Bossier shale acreage. 41 wells are planned for Logansport, and 15 are planned for Toledo Bend North and South fields. Most of these wells will target the lower Haynesville shale, but we do plan to drill up to 15 upper Haynesville shale or Bossier shale wells this year. We plan to move one of our seven operated rigs out of our Haynesville operations to our new acreage in the Eagle Ford late in the third quarter. Given the efficient drill times we are achieving, we will still drill all of the wells we had originally budgeted for our program, even with this rig leaving early to the Eagle Ford.

Our South Texas region is displayed on slide 22. We drilled one well in this region in the first quarter. The Julian Pasture #4 was drilled in our Ball Ranch field and was tested at an initial production rate of 8 million a day in the second quarter.

Now, I will turn the call back over to Jay to go over our plans to expand on our operations in the emerging Eagle Ford play.

Thank you, Mack. I'm sure they will have some questions in a moment.

On slide 23, we present our acreage footprint in the Eagle Ford shale, in South Texas. We have acquired our or in the process of closing on 18,000 net acres that we feel are prospective for development in the emerging Eagle Ford shale play in Karnes, McMullen, and Atascosa Counties in South Texas. We are focusing primarily on the oil and condensate windows in this play due to the better economics of oil versus natural gas. We hope to acquire up to an additional 10,000 net acres in our focus area. Given expected well spacing of 80 acres and an expected per-well recovery of 400,000 barrels of oil per well, our acreage could have 67 million barrels of oil equivalent of reserve potential. As Mack said earlier, we plan to move one of our Haynesville rigs to this region and expect to drill three Eagle Ford shale wells on our acreage by the end of this year. In 2011, after we have completed our leasing activities, we plan to have a two- to three-rig program to develop our Eagle Ford shale acreage.

On slide 24, we outline what we expect to spend this year on our drilling program and on our acreage acquisitions. Our drilling expenditures are down from our earlier estimate, even though we are drilling more wells. With the shortage of completion services, we will carry a number of drilled wells over into 2011 for completion, which delays those expenditures until 2011. We expect to spend $350 million for our drilling program to drill 69 wells. 66 are horizontal wells. 63 are in the Haynesville or Bossier shale. And three are in the Eagle Ford shale. We are budgeting $150 million for our acreage acquisitions. We expect to spend $46 million on Haynesville leases and $104 million to establish our position in the Eagle Ford shale in 2010.

In summary, I would ask that each of you refer to slide 25. We continue to be excited about our prospects for reserve growth this year. Despite the weak natural gas prices and the completion delays we are experiencing, we are still very well positioned to have substantial reserve growth at a very low finding cost. Our 2010 drilling program, estimated to cost $350 million, will focus almost primarily on developing our Haynesville shale acreage. We think our Haynesville shale program could add 400 to 500 BCFE-approved reserves in 2010. With pressure pumping services hard to obtain, we have had to trim back our expectations for production growth. Instead of having 18% to 25% production growth this year in our Haynesville shale program, our production growth will fall in the range of 13% to 18%. This production is not being lost. It is just being deferred into 2011.

Our recent leasing efforts have given us a foothold in the emerging Eagle Ford shale in South Texas. Our goal is to lease up to 25,000 net acres in the oil and condensate windows of this play. We are maintaining and growing our inventory of drilling locations and have a large inventory in the upper and lower Haynesville shale, and Cotton Valley in East Texas and North Louisiana, and in the Eagle Ford, Vicksburg, and Wilcox trends in South Texas.

We continue to maintain a very strong balance sheet. We have $500 million available on our completely unused bank credit facility. We plan to use the proceeds from our Mississippi asset divestiture, which is being marketed, to help pay for our acreage acquisitions this year. We plan to fund all of the estimated $500 million expenditures this year with cash flow, cash on hand, and the proceeds from non-core asset sales. For the rest of this call, we will take questions from the research analysts who follow the stock.

Annika, I'll turn it back over to you.

Thank you, sir.

(Operator Instructions)

Your first question comes from the line of John Freeman with Raymond James. Please proceed.

Good morning, guys.

Hi, John.

My first question has to do with the CapEx budget. Obviously, you all have got a lot more flexibility than most in the Haynesville. I believe in the past, you said you've only got to drill like three or four wells, the remainder of this year, to sort of hold the acres there.

There was going to be a pretty hard look at the budget in June, I believe you all said in your last call, because that was when the first of three of your seven rigs were due to roll off contract. I think there was one in June, one in August, and one in November. And I'm just sort of curious about what sort of took place -- when you're looking at the budget, I assume you decide to keep the rig in June that came off contract, and then sort of the plans going forward, and if there is still an opportunity to maybe lower the drilling part of the capital further.

John, this is Mack. Yes, we're evaluating that as we go. Obviously, we're stockpiling completions. We're reviewing the economics of the Eagle Ford versus the Haynesville. As Jay mentioned earlier, we're discussing here about the go forward plan for the Eagle Ford -- do we move one or two rigs early on in our entry into the drilling operations in Eagle Ford? So that will determine whether or not we release one of the seven rigs, or send it -- rather than releasing it, send it to the Eagle Ford.

Okay. Mack, and the one that was, I guess, renewed in June, can you give me what the terms of that was versus what it was on contract at?

John, we're well-to-well with that rig.

Oh, you are. Okay. And then last question, I had, and I will turn it over to somebody else -- just on the completion side in terms of, you're currently sort of negotiating with various service providers. Is the thought that you sort of do sort of a term contract where you've got guaranteed days assigned to you?

Yes, that rig, that crew -- pardon me, the frac equipment and the crew -- would be a dedicated service crew for Comstock wells only.

Great. Thanks, guys.

Yes, sir.

John, I think what will probably happen is we will evaluate -- since we picked up right at the 18,000 net acres in Eagle Ford -- we will see whether we will move one or two rigs over, like Mack had said. And the rig that rolled off in June is well-to-well, and the one in August, if we keep it, will go well-to-well. So really, I would think that -- in November would be our next, really, decision point -- to see whether we keep that rig, or we move it over to the Eagle Ford.

Your next question comes from the line of Brian Corales with Howard Weil. Please proceed.

Hi, guys. How are you?

Good morning.

Just a follow-up on the completion side -- are you all also talking about locking up some dates for the Eagle Ford as well, because I know the area has been pretty tight?

Absolutely. You bet.

Okay. And then in terms of the Eagle Ford costs, what are ya'll seeing -- is there a lot of additional running room there to add to that acreage position, and what are you seeing in terms of leasehold costs?

Leasehold costs are varying across the play. As you might expect, we're not going to pay some of the implied run-up prices that I'm sure you know about. We don't think that's appropriate at this point in the play. And so, just as we followed the approach in the Haynesville, we're targeting leasehold in the range of $2,000 to $5,000 an acre as a maximum. And we're accruing our acreage on that basis.

There is some running room in the play. At varying risk levels, of course, we are targeting some specific regions, just as we did in the Haynesville, following the same kind of strategy, where we want multiple footprints. And as Jay mentioned earlier, we're targeting the oil and the condensate windows for the leasehold efforts that we're making. So we're -- we want contiguous developable acreage where we can drill our laterals in the orientation that we prefer. So that also enters into the equation.

You know, we started looking at the Eagle Ford probably a year ago, started leasing this year. We've been invited to participate in acreage packages of 20,000, 30,000, 40,000, 50,000 plus. And what we've done -- like Mack said, we've entered this region the same way we did the Haynesville. We said we're really not willing to pay up. We want to operate. And we really right now, we think that the Karnes, McMullen, and Atascosa area is the best area for us to be in. And we will test those three counties. And we will do that the exact same way we've developed our wealth in the Haynesville.

And I think as far as the cost to get in that acreage -- because remember in '08, we sold some non-core gas properties on shore for $136 million, and we took those dollars and we used those to add to our Haynesville footprint. And hopefully that's what we do in 2010, with the sale of a package that we have right now, in Mississippi, which is mainly oil. We would take those dollars and then our free cash flow and then cash in the bank, and that's how we would enter this Eagle Ford area, with again about 25,000 net acres, which I think is a good start for us.

Okay, guys. Thank you.

Thank you.

Your next question comes from the line of Jack Aydin with KeyBanc. Please proceed.

Can you hear me?

Hi, Jack. Now we can.

Okay. Sorry. I apologize if you addressed this one. Did you guys lock up a completion crew in the Haynesville area? I apologize if you went through it.

We're negotiating on that, Jack. We feel that an agreement is imminent. But we don't have anything to announce today about that.

Okay. If you look at -- now you have about 17 wells in inventory. Going toward the year-end, what do you think, how many wells you might still have -- you might end up having in inventory?

Well, if -- there are some assumptions built into that, of course, Jack, as you know. I'm hopeful that we will be able to reach an agreement with the service provider that will allow us to have access to additional capacity in 2010. That it won't just be a 2011 solution for a completion backlog. But if so, if is just a 2011 availability, then we may have a completion backlog approaching 25 wells by the end of the year.

Okay. I'm limited to two, so I will -- thank you.

Yes, sir.

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

Good morning. A couple of questions. Obviously, all of the East Texas/North Louisiana horizontal wells that were completed in the quarter were in the Haynesville. I know that you have drilled a number of other -- of Bossier wells. What's the -- what determines the completion of Haynesville versus Bossier? Is it just locations, once you actually got the frac crews on location?

You mean the order that we plan to complete them?

Correct.

We're going to focus on getting the uppers completed. Not necessarily first, but certainly toward the front end of the operations going forward, when we do get the dedicated crew. And that is because we have so many lower Haynesville completions, that we have much more data, much more information about performance, reservoir attributes, all of that stuff, that we can use in forecasting forward our drilling program reserve adds, et cetera. So we're going to bring forward the upper Haynesville completions in going forward with the completion plan, Ron.

Okay. And then as you -- I don't know, Mack, I mean from an industry stand point, if -- what's the -- what are the discussions on the pressure pumping side in terms of the amount of frac crews that people are looking to add in the region? And then how does that impact ya'll's Haynesville acreage in terms of held by production? As John said, you had very few wells needed to maintain your 2010, and on a 7 or 8 program, you were probably through 2011. Just curious how these completion delays impact your ability to hold that production and how much capacity additions are expected.

Well, the additional capacity that we have been told will be entering the market in 2011 is a range. And it depends upon delivery time of the equipment and what the operators do. And the Haynesville operators do with regard to the use of that equipment. I will mention something about that in a minute.

At least 10 crews are -- additional crews, for the Haynesville, are anticipated for 2011. That's a maximum. And some of those 10 could be sent elsewhere, depending upon -- and by elsewhere, I mean the Eagle Ford, and the Bakken, depending upon the internal evaluations that each of the service providers are going to go through. What the operators do matters, because if the operator is in the Haynesville, for example, would lower their treatment rates to, say 60 barrels per minute, from 80 barrels per minute, that would obviously free up additional pumps that would not have to be on location to get to an 80 barrel-per-minute level, all other things being equal, and those pumps could be used to form another crew, if you will.

If a service provider has five crews in the Haynesville, and they take 20% of the pumps from each crew, well, then they could form another crew. Some operators are looking into that and have actually done that successfully. We are doing some of that as well, to see if we can adequately treat our wells at the lower rate. And so far, we have pleased with the results. We are pumping at about 65 to 70 barrels a minute, and we're looking at the possibility of going even lower, and working with the service providers and finding a common solution that's good for them. It's obviously at a lower rate. It's easier on their equipment. They have lower maintenance costs, which -- some of those cost savings can be shared with us. So, hopefully, that answers your question on that.

It does. Thank you.

Your next question comes from the line of Mark Lear with Credit Suisse. Please proceed.

Good morning.

Good morning.

I was wondering if you could kind of address -- with the full quarter under your belt in restricting rates on wells, how the production profiles have been holding up, and what you think the impact on the EUR's might be, with some more data?

Well, we're very pleased with the results. If our -- if Comstock's reservoir group manager were here, he would say, "Hey, we need a little more data to firm up the forecasts -- the improved EUR forecasts -- but certainly on a preliminary basis, we're seeing things that we hope to see." We're seeing a softening in the production decline. We're seeing higher flowing pressure maintenance, which is obviously a good thing. And then, with the initial forecast that we have done, we're seeing a 20% to 30% EUR potential improvement. So we're quite pleased with the results. We think in most places within the Haynesville play, that's going to be the way to go.

And then I guess in terms of AFE's on Haynesville wells -- where are they currently, and do you think there is more room to the upside in terms of cost inflation?

Well, that's a good question. We've seen costs escalation since the beginning of the year, between 20% to 30%. Most of that, those cost increases, have come from increases in -- on the completion side costs, with the high demand for high pressure pumping services, that's to be expected. We feel like there is some room for some additional cost inflation. Just until the additional equipment gets into the marketplace, in 2011, and some of the operational activity subsides, meaning some of the operators will take their foot off the accelerator for various reasons.

Some can't. Some can. And we think the driving force, obviously, is going to be supply of high pressure pumping equipment versus the demand for that equipment. And, now we've squeezed a lot of costs out of the drilling side. It's the escalation or inflation on the completion side costs that needs to come down and will come down.

Right. And then just where AFE's are currently?

AFE's right now are running anywhere from $9 to $10.5 million per well.

Got you. Thank you very much.

Yes, sir.

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

Leo?

Mr. Mariani, your line is open.

Hey, guys. Sorry about that. I'm curious on the production ramp. You guys kind of guided to production down, sequentially, in third quarter. Any further guidance on that as to how much you think it is going to be down roughly in 3Q?

Hey, Leo, this is Roland. Well, we do think that the third quarter will probably definitely will be down from the very high level on the second quarter. There is some real uncertainty about if we get some more completions done, and then which wells are completed, and how much they get to contribute, and we're off to a very slow start for the quarter. We believe it would probably be a little higherthan the third quarter rate of 2009, but not anywhere near the level we were at the second quarter.

So I think in the fourth quarter, we will see some improvement in the rate, and so I think you will start to see it start to get back into line in the fourth quarter. And how much it gets back in line will be determining if we get some more completions in this year. So I think overall, I would assume that the dip is in the third quarter and then you start to come back in the fourth, and then achieve that range that we've kind of put out there for the overall year, 13% to 18%.

Okay. Just jumping over to your asset sale -- you guys are selling your Mississippi oil property. Any sense of potential timing as to when the cash would come in the door, and any other potential asset sales that may happen in the near future?

Leo, this is Roland again. On the Mississippi asset sale, that process has been underway and is going very well. We're running a formal bid process, and we expect to have the bids in this month. And I would suspect that if everything goes well, we could close that asset sale very early in the fourth quarter.

As far as other assets that, for sale -- right now, we don't have any other formal plans to sell any other assets this year. I think as we formulate our 2011 business plan, we will be looking at some of the areas that don't have activity and other areas that are kind of away from our core East Texas/North Louisiana and South Texas regions, and then see if it makes sense to divest of some more of those. A lot of those are gas assets, so that's why we didn't put those on the market this year, and chose instead to sell the heavy oil field in Mississippi and the related production around that, in the state of Mississippi.

Okay. Thanks, guys.

Thank you, Leo.

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

Thanks, good morning, guys.

Hi, Amir.

A quick question on the -- in the Haynesville, just given that the backlog, if anything, will get worse, any thought of maybe cutting the number of wells you're going to drill to bring your cash flow CapEx in line?

Well, in a manner of speaking, that's what we're doing with the transfer of the rig to the Eagle Ford, although certainly the Eagle Ford service side is an issue as well. And that's why we're making it part of our discussions with the service providers and providing a dedicated crew. And then, as we mentioned earlier, we're evaluating whether or not we should send another rig to the Eagle Ford, or release it. So all of those things -- I'm sure we will make a decision by the next conference call.

Okay. And just while we're on the Haynesville, I noticed a shift away from the Toledo Bend drilling toward the Logansport. Can you just provide some color as to the quality of the drilling or just where the rigs are currently?

Well, both. We're also evaluating upper Haynesville in Toledo Bend South, so we needed to move rigs there. The Logansport area is an expansive area. It involves Belle Bower, Bethany Longstreet, Logansport, and -- as well as another area called Red River Bull Bayou, so we're necessarily drilling a number of leases within the Logansport package.

But the upper Haynesville, within the Toledo Bend North, is something we're going to be targeting going forth for the rest of this year, because frankly, we've got almost all of the leases held down through the lower Haynesville already. So, we have the opportunity to evaluate what appears to be a very good upper Haynesville opportunity in Toledo Bend North.

And then just a final question, on the Eagle Ford, are you -- I'm just trying to get a sense of drilling commitment. So are you leasing acreage from others who have already leased it? So is there a shorter fuse on acreage expiring, or do you have a full three years?

Full three years, yes.

Sounds great. Thank you very much.

Your next question comes from the line of Kim Pacanovsky with MLV. Please proceed.

Good morning, guys.

Hi, Kim.

On the Eagle Ford, where will your first location be? And is it -- and I see you have a little bit of the oil window in there, mostly condensate window -- but where will it be, or where will the first three wells be? And what are the nearest completions to these first locations?

Well, this is Mack. The first well is going to be in McMullen. We're going to be evaluating the exact location, obviously, of that well bore placement, whether it's in the condensate or deep oil windows. The second well, at this point, we plan to drill in Atascosa. And the third well, at this point, we plan to move over to Karnes.

There's not a whole lot of offset wells near us in McMullen, although the geological correlations fit very nicely through our acreage tracks in McMullen. We have the EOG wells to the north and northeast.

And of course, you've -- I'm sure followed the EOG press releases on their wells. Yes. Right.

They're quite happy in the oil well. Atascosa will be playing a little bit off of the EOG extrapolation. At Karnes, there's wells that have IP'd at over 800 barrels a day oil and 2 million a day gas within a three- to five-mile radius around our Karnes region. So that gives you a little bit of color on that.

Okay. Okay. That's great. And just assuming you could -- you do have completion crews in the Eagle Ford -- I'm not sure why you wouldn't shift two rigs over there. What's the reason you wouldn't do it? I mean, even if gas prices improved by a dollar, your economics are still better in the Eagle Ford.

I think we would do that. We're just kind of leaving ourselves a little out.

Okay.

That's probably what we will do.

Okay. Great. Those are my two questions.

Thank you, Kim.

Thanks.

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

Good morning, gentlemen.

Hi, Michael.

A couple of quick questions. Just a little follow-up, on the acreage -- you picked up some acres in the Haynesville and the Eagle Ford. Could you give us a little more clarity on where the 5,000 acres in the Haynesville was picked up?

This is Mack. Most of the acreage that we picked up is around our Toledo Bend North and Toledo Bend South areas.

Okay. And then my second question is, if you move into a two- to three-rig program in the Eagle Ford, pending success, does that imply that you would have a reduced four- to five-rig program in the Haynesville?

Yes, that's correct.

All right. Well, I can get back in the queue, if you're going to limit us to two questions.

If you got one more good one.

If I got one more good one? Okay. I will ask that then. As part of the presentation ya'll had of 8,000 acres, and the Eagle Ford locked up, and it looks like 10,000 acres is either pending -- relative to the $84 million, $82 million you have left on your budget for acreage, I take it that implies that you're pushing to get 20,000 acres for that, or as much as you can get? Or how does that break out?

Yes, we've got an agreement that is imminent for the additional acreage. We feel very positive about bringing that in. And we have an additional acreage package that we're negotiating on right now that would get us well over the 20,000 mark.

So it could be a third quarter event?

Right. And we have closed some of that acreage already in the third quarter. It just wasn't in June. It was in July. So it is a combination of all of those, but we feel pretty good about reaching our goals at the limits that we set for how much we will pay for acreage and getting there this year, because a lot of these deals are just in the due diligence process now.

Okay. Very good, guys. Thanks.

Thank you.

Your next question comes from the line of Dan McSpirit with BMO Capital Markets. Please proceed.

Gentlemen, good morning, and thank you for taking my questions.

Hi, Dan.

Question number one. The fact that Comstock is now getting into the oil business, or at least the condensate business -- what does this move say about the natural gas business? I ask in an effort to get your honest and genuine views on the commodity and the outlook here going forward.

Well, you know, I would say -- somebody approached me this morning and said it may be a blessing in disguise that we pushed some of our gas production in 2011, and may have a higher natural gas price, and I couldn't disagree with them. I do think we have -- we've got quite a bit of gas out there, as you know, and there is a lot of wells waiting to be fraced. We had told you, Dan, that we would probably add another unconventional core area that was already within our footprint, which again is the South Texas area, which is the Eagle Ford.

But we chose not to do that by participating with someone and being highly promoted and not being an operator. We, in fact, said we want to operate, and if it takes us six or seven or eight months to acquire the acreage that we would like to acquire, and it's a little harder to acquire it, but it's just as good or better, and we operate, then we would rather do that. And that's why we hadn't announced anything in the first quarter. We waited 'til now, so you'd have something meaningful in size.

I think the other thing we said we would do is, at the beginning of '09, we wanted to test the value of the emerging Haynesville, and by the end of '09, we drilled maybe 33 wells or so. And then we said at the beginning of this year that there were probably 56 wells or so we wanted to drill, driven by the geologists and by the reservoir engineers. And not that we had to drill all of those wells to hold acreage, but we needed to figure out what we thought the better acreage was. We have attempted to lease this 5,000 acres in the Haynesville in Tier One. We have attempted to figure out what percent of our acreage is in "Tier One" in the Haynesville, and you notice that we have leased some more acreage in Toledo Bend North and South. So, we kind of indirectly answered those questions.

But we also said by the end of the third quarter, that once the geological group here at Comstock was comfortable with the value of our acreage, that we may start pulling back some of the wells, and if we can push them somewhere else. Now at that time, we didn't know whether we would have enough Eagle Ford acreage to move a rig or two over. But we did make sure that in June, August, November, we would have a rig and we could move a rig or two over, depending upon the time frame.

And at the same time, we've committed to you, as an analyst and a stockholder, to create real wealth on a per share basis with transparency, as we grow the Company. You know, that transparency is a big word. I think we gave you pretty strong numbers in the second quarter except -- except what? You know. It is not that we don't have financial flexibility. We've got a premiere asset base. We've got a premiere resource play. We've reduced our drilling and completion CapEx budget by $35 million in 2010. We added that to acreage that we picked up for $3,000 or $4,000 in Eagle Ford. We've kept out of being in an area that had regulatory overhangs. We are not in any area where there is a regulatory overhang.

We do have a backlog of excellent wells that we would like to complete. I think you will like the results of the wells, the 17 wells that we have not completed. If we would have chosen some of those, versus the 5 that we did complete, you would even have a higher production rate. And our guidance, at the beginning of this year, was -- it was what we thought was right, 18% to 25%. We thought we could get the wells drilled.

And now what you're going to see is we're at the lower end of that guidance. We're 13% to 18%. I don't know if we will get to 18%. We feel comfortable with 13%. And that is not a function of do we have take-away capacity. It's not a function of do we have rigs. It's not a function of a joint venture partner.

It is just a function of completions. And when gas prices started to drop and completion prices started to go up materially, we said it doesn't make a lot of sense economically, if you're doing a kind of a ground-up evaluation of adding reserves to pay a lot higher price for completion. So we chose not to do that. I guess it's great that we have the flexibility that we don't have to do that.

But you know, in saying all of that, and you say, "Well, how did you get into your two core areas now?" I think we did it the right way. We didn't dilute you with equity in the last five or so years. And in fact, we said that you don't own Comstock stock because we own Stone shares, and we said when Stone was high enough, we would divest ourselves of some of that. And we did. On April 15 or so, we sold the 520,000 shares of Stone, and that gave us a chance to be profitable in the second quarter. And then you even look at where our gas is located. I mean, our average gas price is the NYMEX gas price.

So, I think that's our total attitude. It's to give you some transparency in a market that, as you said, I mean, the natural gas market right now is not good, particularly if we're 94% natural gas, and not hedged. Maybe a natural hedge is that we can't frac some of these wells by year-end, and we will look even stronger in 2011, and really not give up any of our strength in 2010. And I think you've followed us long enough to know those are true statements. I don't know if that's a long way to answer your question.

No, it does. That's great. I appreciate it. Thank you.

And question number two if I could, my last question. As you evaluate the targeted economics of drilling a well in South Texas versus your first core area in East Texas/North Louisiana, what gas price do you need to make that a market neutral or an economic neutral result? That is, at what price Henry-Hub does that become a situation where, or a result where the economic break-even or the economic limit between the two areas is equal?

This is Mack. We've run our internal economics on the Eagle Ford assuming a $4 flat gas price and a $70 flat oil price. And we're economically positive within our projected EUR ranges. And, you know, we are targeting the cost structure now, in bringing that into line with our expectations.

Our first wells that we plan to drill in the Eagle Ford are going to be more expensive wells because we're going to get a lot of data for subsequent evaluation, just as we did in the Haynesville. So the first group of wells, in each of our footprints, are going to be more expensive, as a result of that effort. The exact break-even, I can't give you that. I don't have that in front of me. But we can provide some guidance later on that.

Okay. Thank you.

Yes, sir.

Thank you, Dan.

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

Thank you. Good morning. It looks like a lot of my questions have been asked already. But just a couple of follow-ups. I know you've picked up, I guess, about 5,000 acres in the Haynesville Bossier area so far in Toledo Bend, North and South. And you are planning to pick up a little more. Where are you going to target for the additional acreage acquisition?

Well, we have three footprints that we really like. You mentioned two of them. And the other is in the regions that I mentioned earlier, the Logansport area, Red River Bayou, San Miguel Bayou areas. Throughout those regions, we think there are some opportunities to add to our acreage.

These are 20%, 25% royalty.

Yes, sir, 25%.

Correct. They're a quarter.

Okay. About the same acreage value, $8,000 or so, or however it worked out?

Yes, it depends on where you're at, and -- but I think between $4,000 to $8,000 an acre is a good range to use.

Okay. And then just jumping over to the Eagle Ford, the additional acreage you're expecting to pick up near term -- I guess it's about 10,000 more -- are you expecting that to be at the higher end of that range you gave, the $2,000 to $5,000?

Yes.

Great. Okay. And then just overall, of the acreage you've acquired so far, how much is actually in the oil window, what percentage?

Boy, I wish I could give you the answer to that.

Based on the math.

Give me six months, I'll be able to tell you.

Okay. Just using the map, you don't have an approximation?

Probably a third.

Okay.

Half.

All right. Well, thanks so much.

Sure.

Thank you.

Your next question comes from the line of Ray Deacon with Pritchard Capital Partners. Please proceed.

Yes. Good morning. I was just curious -- it sounds like you're not changing the amount of reserve bookings you see in the Haynesville, so I am assuming you believe you're still going to be able to get as many wells completed by year-end as you had been previously, or does the EUR change due to longer laterals, and choking back the well some, I guess?

Well I don't think it is fair to ask an eight-part question here. That's a pretty smart move.

No, the bottom line is, we haven't changed our EUR guidance on our Haynesville wells, and reserve additions with the new SEC reserve rules are still in line with what we had previously put out, because, despite the fact that we have not completed the well, we certainly have all of the offset data that supports a reserve add for not only the well drilled but the two offset locations. And you know, we've reviewed this particular issue with several audit groups, given the geological data that we have in-house, and that's already in the public domain, so we feel pretty comfortable staying with our original guidance on that.

Okay. Got you. Great. And I guess just -- I listened to the Pioneer call last week, and they talked about a one-year payout on a frac crew they were purchasing in the Eagle Ford, and I guess, I don't know, would that make any sense to you? Have you ever --

You know, when there was a rig shortage, we didn't buy any rigs. There is a frac shortage, we didn't buy any frac crews. I don't know that we're in that business. It's a service business. I mean, if Mack wants to push that to a management decision, and we would decide that. But right now, like we just said, we're not in the service business.

Got you. Okay. Great. Thanks very much.

Your final question comes from the line of Noel Parks with Ladenburg Thalmann. Please proceed.

Good morning.

Good morning.

Sorry if this got answered already, but of your Eagle Ford acreage, is there any of it that is held by production? That has led to some production on it?

No, sir. All new leases.

All new primary leases.

Okay. And three-year, typically, or?

Yes. Yes, sir.

Okay. Great. And I guess my other big one has to do with the negotiating with the service companies to get access. Just curious -- that you said that you thought a deal might be happening fairly soon on that. How tricky has it been to arrange to just get the frac crew access without getting a lot of other bundled services in there?

Well, it's not necessarily the case that we wouldn't want to bundle services. We use the primary service companies anyway on a number. We have seven rigs running. And so we have a number of those services already in the -- on our wells. So it's an advantage, really, for both parties to have an integrated service package as part of the discussion for a dedicated crew. And there is also a side benefit to that, when you do have such bundled operations, standby time for equipment is less of an issue if a problem occurs on location as a consequence of equipment failure. So you're not charged the go-forward standby time. It's a little bit of a detail, but that's a benefit of having a bundled service operation.

And just to clarify -- so would you say that you're at a point where you're not extremely worried about exactly who -- for example does your wire line logging in your new Haynesville wells from here on?

Well, I'm always worried about wire line operations. I'm not going to say that I'm not concerned about that. We -- as part of our negotiations, service quality is part of the negotiated package. And no matter who is on location doing the wire line work and the other services, it's key to have quality service. And the service providers certainly know that. There are some that are better than others at certain things. And so we address each of those issues individually.

Okay. Great. That's it for me.

All right, sir.

Thank you.

At this time, there are no further questions. I would now like to turn the call over to Mr. Jay Allison for closing remarks.

Thank you, Annika.

I think there were excellent questions, and hopefully we delivered the type quarter that you were looking for. And with the exception of the frac dates in the future, I guess at the end of the day, you have to see where your assets are located. You have to see how you got there, you have to see what kind of flexibility you have, both with your balance sheet and operationally. And then at the bottom line, you have to be the low cost producer, and I do think that of all public E&P companies, we're at the lower end of cost. So we will continue to try to seek to stay at that place and be transparent as we grow the Company. Again, I thank each of you for participating in the call.

Ladies and gentlemen, this concludes the presentation. You may now disconnect. Thank you. And have a great day.