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Executives

Jay Allison – Chairman, President and CEO

Roland Burns – SVP and CFO

Mack Good – COO

Analysts

John Freeman – Raymond James

Leo Mariani – RBC

Ray Deacon – Pritchard Capital

Sven Del Pozzo – C.K. Cooper

Mark Lear – Sidoti & Co

Jack Aydin – KeyBanc

Ron Mills – Johnson Rice

Noel Parks - Ladenburg

Richard Tullis – Capital One Southcoast

Dan McSpirit – BMO Capital Markets

Comstock Resources, Inc. (CRK) Q4 2009 Earnings Call Transcript February 9, 2009 10:30 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the fourth quarter 2009 Comstock Resources earnings conference call. My name is Eric. I will be your audio coordinator for today. (Operator instructions)

At this time, I would now like to turn the call over to your host, Mr. Jay Allison, President and CEO of Comstock. Please proceed sir.

Jay Allison

Thanks Eric. You know, this morning as I turned on the TV, I turned on CNBC and the headlines were, “Winter weather wrecking havoc.” I thought, I just kind of smiled, and then I said from Virginia to Maryland there is like 35 inches of snow, and don't worry more is coming. And then I said the blizzard in Denver in 1982 looks like a nothing. And the winternater [ph] winter, which is the snowminater [ph] winter now, they talked about that. I just smiled and then I turned off the TV. I turned on my radio to the Mininova [ph] station faster snow in Dallas on Wednesday. I just smiled again and turned it off, and then I turned my thoughts to the conference call today and really about where we were a year ago. Because if I look back a year, and if you go back a year and a month or so, in the fourth quarter of 2008, we were producing less than 2 million cubic feet of gas per day from the Haynesville.

By the end of the fourth quarter in 2009, we were producing 84 million cubic feet of gas from the Haynesville. And we did that without buying anything. We did that through the drilling program. Today the Haynesville gas production makes up 40% of our total production at Comstock. This production is primarily from our first 29 operated Haynesville wells only.

We drilled 29 Haynesville wells to date, and we expect to drill 56 Haynesville wells in 2010. We increased our production and added 325 Bcfe of new reserves because of the results of the 2009 Haynesville program. And we did that without diluting our stockholders. Because of the success we had in 2009, again I go back a year, in the Haynesville Shale horizontal drilling program with our technical people, with our strong balance sheet and on our acreage, you know, we are more encouraged than ever that 2010 will be an even better year as we continue to realize the value of our Haynesville asset. I think it became a lot more valuable from last year versus the year that we are in today.

If you go to page 2, the 2009 highlights, please refer to page 2 of the presentation where we summarize our 2009 results. Low oil and gas prices in 2009 have cost reversal from the record setting profits we had in 2008. In 2009, reported revenues of $291 million, and we generated EBITDAX of $199 million, and operating cash flow of $224 million or $4.82 per share. Operating cash flow includes $42 million income tax refunds from carrying back losses incurred this year. The low price has caused us to report a loss of $36 million or $0.81 per share.

Despite the low oil and gas prices, we are having a very, very successful year with the drill bit with our Haynesville Shale drilling program. We drilled 54 successful wells, including 43 horizontal Haynesville Shale wells, three horizontal Cotton Valley wells, three vertical Cotton Valley wells and five high rate South Texas wells. The success we had in our drilling program in 2009 is evidenced by our production growth. Fourth-quarter production was up 27% from the fourth quarter of 2008, and up 13% from the prior quarter.

Our Haynesville Shale production had 84 million cubic feet equivalent per day, makes it 40% of our total production. The Haynesville Shale program also allowed us to grow our proved reserve base by 25%, despite the very low gas price required in the new SEC reserve rules. The Haynesville program added 325 Bcfe of new reserves, offsetting the negative impact of the new rule. And lastly the debt financing that we completed in October allows us to start 2010 with over $700 million in liquidity.

I will now turn it over to Roland Burns to review the financial results in more detail. Roland?

Roland Burns

Thanks Jay. On slide three we break out our average daily production by quarter and by region, and we highlight the production from our new Haynesville Shale wells in red.

In the recently completed fourth quarter, our production averaged 208 million cubic feet of natural gas equivalent per day, which was 27% higher than our production in the fourth quarter of 2008 of 164 million per day. Production was also up 13% from our third quarter average rate of 184 million per day as our new Haynesville wells are now making 40% of our total production rate.

Our East Texas/North Louisiana region averaged 142 million per day with 58 million coming from our Cotton Valley wells, and 84 million coming from our new Haynesville Shale wells. Our South Texas region averaged 50 million per day and our other regions averaged 16 million per day in the fourth quarter. This year, we anticipate stronger production growth than we had in 2009, now that we have fully made the transition from the Cotton Valley vertical drilling program to the Haynesville horizontal drilling program. We expect production in 2010 to approximate 77 to 82 Bcfe. This would represent an 18% to 25% growth over 2009 production.

Oil prices improved in the fourth quarter but were down for the full year from 2008 as shown on slide four in our presentation. Our average oil price increased 24% in the fourth quarter of 2009 to $64.76 per barrel as compared to $52.16 per barrel in the fourth quarter of 2008. Our oil price in the fourth quarter averaged 83% of the average NYMEX WTI price. For all of 2009, our average oil price was $50.94, 42% less than the average oil price of $87.15 in 2008.

The most significant factor impacting our financial results in 2009 were low natural gas prices, which we show on slide five. Without considering our hedges, our average gas price decreased 36% in the fourth quarter to $4 per Mcf as compared to $6.25 in the fourth quarter of 2008. Our realized gas price was 95% of the average Henry Hub NYMEX price in the fourth quarter. For all of 2009, our average gas price decreased 59% to $3.70 per Mcf as compared to $8.92 per Mcf in 2008.

Slide six shows our average gas price with the impact of our hedges. We had 9% of our gas production hedged in the fourth quarter, which increased our realized gas price to $4.34 per Mcf. For all of 2009, our average price with the benefit of hedging was $4.13 per Mcf. We have no hedges in place in 2010.

On slide seven, we cover our oil and gas sales. The lower natural gas price has caused our sales from continuing operations to decrease 10% to $90 million this last quarter, as compared to $100 million in the fourth quarter of 2008. For all of 2009, our sales decreased 48% to $291 million as compared to $564 million in 2008.

Our earnings before interest, taxes, depreciation, amortization, exploration expense and other non-cash expenses, or EBITDAX, also decreased 10% in the fourth quarter to $64 million from $72 million in 2008 fourth quarter, as shown on slide eight. In 2009, EBITDAX decreased 57% from 2008's level to $199 million.

Slide nine covers our operating cash flow. Our operating cash flow for the quarter came in at $68 million, a 15% decrease as compared to cash flow of $80 million in 2008's fourth quarter. Operating cash flow in the quarter was increased by current income tax benefit of $11 million, due to the ability to carry back losses generated this year to prior years. For all of 2009, operating cash flow was $224 million, 49% less than cash flow of $438 million in 2008.

On slide 10, we outline our earnings. With low natural gas prices, we reported a net loss of $7 million or $0.15 per share for the fourth quarter. This compares to a loss of $96 million or $2.09 per share in the fourth quarter of 2008. If you exclude the nonrecurring items that we had in 2008, especially the impairment on the value of the Stone Energy shares that we reported, we had a reoccurring net income of $10 million or $0.22 per share in the fourth quarter of 2008. For all of 2009, we had a loss of $37 million or $0.81 per share as compared to reoccurring net income from continuing operations of $148 million or $3.20 per share in 2008.

On slide 11, we show our lifting cost per Mcfe produced by quarter. Our lifting cost decreased to $0.98 per Mcfe in the fourth quarter of 2009 as compared to $1.37 per Mcfe in the fourth quarter of 2008. Lifting costs increased by $0.04 from the third quarter rate of $0.94 due mainly to higher production taxes. Production taxes accounted for $0.17 of the total $0.98 in total lifting costs this quarter. Excluding production taxes, our lifting costs will continue to improve as a result of the lower cost of Haynesville shale production.

On slide 12, we show our cash G&A per Mcfe produced by quarter, which excludes stock-based compensation. Our general and administrative costs decreased to $0.34 per Mcfe in the fourth quarter of 2009 compared to $0.57 per Mcfe in the fourth quarter of 2008. Included in the fourth quarter of 2009, we had approximately $1 million related to an acquisition prospect that we pursued that we ultimately did not close on. Those costs are excluded from the $0.34 rate that we show on the slide.

Our depreciation, depletion and amortization per Mcfe produced is shown on slide 13. Our DD&A rate in the fourth quarter averaged $3.21 per Mcfe, an improvement from the $3.34 rate we had in the fourth quarter of 2008. Our DD&A rate this quarter increased $0.03 from the $3.18 we averaged in the third quarter. The reserve revisions from the new SEC reserve rules had a negative impact on the rate, while at the same time the lower finding costs of the Haynesville Shale program is having a positive impact on the rate.

With our Haynesville Shale production increasing, we expect to see our DD&A rate to continue to improve in 2010.

Slide 14 presents our capital structure at the end of 2009. On December 31, 2009, we had $90 million in cash and $96 million in marketable securities on hand. We had a total of $471 million of total debt, including $175 million of our 6.875% senior notes and $296 million of our new 8.375% senior notes that were sold in October. We had nothing outstanding under our bank credit facility, which has an unused borrowing base of $500 million.

Taken into account our cash on the balance sheet and our marketable securities and the unused $500 million bank credit line, we have $686 million in total liquidity at the end of the year. Not included in this number is a 42 million dollars income tax refund that we expect to receive in the first or second quarter of this year.

At the end of the year, our book equity was at $1.1 billion, which makes our net debt only 19% of our total book capitalization.

On slide 15, we detail our drilling expenditures. We spent $345 million in 2009 for our drilling program as compared to $426 million that we spent in 2008. We spent $309 million in our East Texas/North Louisiana region, $35 million in our South Texas region, and only $1 million was spent in our other regions. $116 million of the $426 million that was spent in 2008 was spent to acquire unevaluated leasehold in the Haynesville Shale play. We spent an additional $26 million in 2009 on leases.

I will now turn it back over to Jay.

Jay Allison

As Roland finishes, I do need to comment that our discussions today do include forward-looking statements within the meaning of securities laws, and while we believe the expectations of such statements to the reasonable, as all of you know there can be no assurances as such expectations will prove to be correct.

If you turn to slide 16, we have a slide on our proved reserves on page 16 of the presentation. Our proved reserves at the end of 2009 were estimated at 726 Bcfe compared to the 582 Bcfe at the end of 2008. Our reserves were 94% natural gas and 55% of proved to develop. We operate 90% of the proved reserve base. In 2009, we increased our proved reserve base by 25% and replaced 321% of our production.

We produced 65 Bcfe of reserves in 2009 and divested 1 Bcfe. Our drilling program added 350 Bcfe of reserves with 325 of that related to our Haynesville Shale wells. The proved reserves were negatively impacted by downward revisions of 140 Bcfe. These revisions were primarily the result of the low natural gas prices required by the new SEC rules to determine whether the production or development of future reserves will be economic, and the new requirement that proved undeveloped reserves be drilled within five years of their booking. We removed 49 Bcfe of proved undeveloped reserves that we do not plan to drill within the required timeframe.

The new rules use the 12-month average prices as of the first day of each month realized by the company, which were $49.60 per barrel of oil and $3.54 per Mcf for natural gas in 2009. Using the old SEC rules, the gas price used would have been $5.29 per Mcf. This would have increased our proved reserves to 800 Bcfe reducing the downward revisions by 74.

On slide 17, we review our finding cost for 2009. The Haynesville Shale program delivered excellent finding cost in 2009. We spent $345 million in 2009 on acquisitions, exploration and development activities, which added 210 Bcfe to our proved reserve base resulting in finding cost of $1.64 per Mcfe. If you exclude the $26 million we spent on unevaluated leases in 2008, the finding cost improves to $1.52.

Excluding revisions, our drilling only finding cost came in at $0.91. Using the old SEC prices, we would have had all in finding cost of $1.21 per Mcfe or $1.12 if you exclude unevaluated lease cost.

On slide 18, we focus on our East Texas/North Louisiana region. We drilled 49 wells in this region in six different fields in 2009. All of these wells were successful. 46 of these wells were horizontal wells. We have tested these wells at a per well average rate of 12 million cubic feet equivalent per day. The horizontal wells averaged 12.5 million per day and the vertical wells averaged 1.6 million per day.

On slide 19, we recap our holdings of the Haynesville Shale play in North Louisiana and East Texas. Our acreage is highlighted in blue. We currently have 86,000 gross acres and 73,000 net acres that we believe our perspective for Haynesville development. 70% of our acreage is in North Louisiana, the better part of the play. Given expected well spacing of 80 acres, and an expected per well recovery of 5 Bcfe per well, our acreage could add 3.4 Tcfe of reserve potential.

On slide 20, we outlined our holdings in the emerging upper Haynesville Shale play or the Bossier Shale as some call it. Our acreage is highlighted in blue. We currently have 52,000 gross acres and 46,000 net acres that we believe are perspective for upper Haynesville development. Given the same well spacing of 80 acres and expected per well recovery of 5 Bcfe per well, this acreage could have an additional 2.2 Tcfe of reserve potential. I will now have Mack Good, our chief operating officer, review the results from our drilling program. Mack.

Mack Good

Thanks Jay and good morning everybody. On slide 21, we show you the results of our first 33 operated Haynesville Shale horizontal wells. Since our third quarter conference call, we've completed 9 additional successful operated Haynesville Shale horizontal wells in De Soto Parish in North Louisiana. Three of these wells are in the company’s Toledo Bend North field, while five are in the Logansport field and one is in our Mansfield area.

In our Toledo Bend North field, we drilled the BSMC 11 number one, the BSMC 13 number one, and the BSMC 5 number 2 wells in the fourth quarter. Each of these wells had a lateral of approximately 4500 feet long and were completed with 12 frac stages. The initial production rates from these wells range from 7.3 to 11 million per day.

In the Logansport field, we drilled five successful wells since our last conference call. The Caraway State 29 number 1 was drilled to a vertical depth of 11,080 feet with a 4,461 foot horizontal lateral. The well was completed with 12 stages and it tested at an initial production rate of 18.9 million per day.

The Collins 10 number one well was drilled to a vertical depth of 11,460 feet. It had a 4,452 foot horizontal lateral. It was completed with 12 frac stages as well, and it tested at an initial production rate of 17 million per day.

The Horn 8 number 1 was drilled to a vertical depth of 11,228 feet. It had a 4,371 foot horizontal lateral. It too was completed with 12 frac stages and it tested at an initial production rate of 17.5 million a day.

The Lackey 21 number 1 was drilled to a vertical depth of 11,465 feet. It had a 4,436 foot horizontal lateral. It was completed with 12 frac stages as well and tested at an initial production rate of 14.7 MMcfe per day. The last well on the Logansport list is the Whitehead 9 number 1, and it was drilled to a vertical depth of 11,421 feet. It had a 4,403 foot horizontal lateral. It was completed with 18 frac stages, our largest number of frac stages upon today, and it tested at an initial production rate of 20.3 MMcfe per day.

In our Mansfield area, the Calhoun number 1 well was drilled to a vertical depth of 12,306 feet. It had a 3,723 foot horizontal lateral, and was completed with 10 frac stages and it tested at a production rate of 17.5 MMcfe per day.

Flipping over to slide 22, we show you the number of days that has taken us to drill the 33 horizontal Haynesville wells on the prior slide. Our average drill time for all 33 wells drilled to date is 49 days. You will see that the average drill time for our first five wells that we drilled was 51 days, compared to an average drill time of 37 days for our last five wells.

The Lackey well, which is the well we drilled since our last conference call, is our best drill time well to date. We drilled it in 27 days.

Flipping over to slide 23, we will show you the number of days it has taken us to connect each of our 33 horizontal wells currently flowing into sales. Our average connect time is 98 days for all 33 of these wells. Our average days from spud to sales for our first five wells drilled was 110 days, compared to a 77-day average connect time for our last five wells.

And with all of that, I will turn it back over to Jay.

Jay Allison

Again thanks Mack. If you go to slide 24, our South Texas region is displayed on slide 24. In our South Texas region, we drilled five successful wells in 2009. These wells were drilled in the Ball Ranch and Fandango fields and have an average initial well rate of about 9.5 Mmcfe per day.

Slide 25 covers our planned activity this year to further develop our Haynesville Shale acreage. All but three of the planned 56 wells will be drilled in a more prolific part of the play in North Louisiana. 27 wells are planned in Logansport and 25 are planned in Toledo Bend North and South. Most of these wells will target the lower Haynesville Shale, but we do plan to drill several upper Haynesville wells, including our first well at Toledo Bend South, which is awaiting the completion of our prop line [ph], before we complete it in early March.

Slide 26 outlines our budget for this year. We plan to spend 385 million this year to drill 59 wells, 56 of these wells will be horizontal Haynesville Shale wells, and in the final slide, which is slide 27, our 2010 outlook.

We are very pleased with how the company is positioned coming into 2010. Our 2010 drilling program estimated to cost 385 million will focus almost exclusively on developing our Haynesville Shale acreage. We expect to have 18% to 25% production growth this year driven by our Haynesville Shale program. Based on results we had in 2009, we think our Haynesville Shale program could add 400 Bcfe to 500 Bcfe proved reserves in 2010.

We are well positioned for future growth when gas prices improve with a large inventory of building locations in the upper and lower Haynesville Shale in Cotton Valley in East Texas/North Louisiana, and in the Vicksburg and Wilcox trends in South Texas. We entered 2010 with a very strong balance sheet. We have $500 million available on our bank credit facility, and $186 million in cash and marketable securities on hand.

With our strong balance sheet, coupled with our very successful Haynesville Shale program in 2009, we are well positioned to build value on a per share basis to continuing to develop our Haynesville Shale acreage in 2010. With that I would like to turn it over to Eric and for questions.

Question-and-Answer Session

Operator

(Operator instructions) Your first quarter comes from the line of John Freeman with Raymond James. Please proceed.

John Freeman - Raymond James

Good morning guys.

Jay Allison

Good morning.

John Freeman - Raymond James

First question on the Whitehead well, which was the most stage done yet at 18, and at least on a production rate basis, it was one of the best ones you had, maybe if you could just talk about going forward, were you satisfied at the incremental cost there, was more than made up for with the better production rate. Is that something you’ll look at doing more going forward?

Mack Good

John this is Mack, and the short answer is yes. We do plan to pump more stages in our Haynesville -- in most of our Haynesville wells going forward. We think we're getting a big bang for the buck there. We have got about a 25% rate increase on the Whitehead compared to offset wells, pumps with a 12 stage completion. So, yes, short-term data on the production comparison is that not only do we get a good IP, but the pressures were better as well. So we're redesigning our completion strategies going forward to accommodate a larger number of fracs.

John Freeman - Raymond James

Okay, and obviously you all have been conservative most in terms of the guidance for the Haynesville, and I know you are not changing any numbers at this point, but can you just kind of talk about looking back now and you're drilling program last year is the tight curve, we all are seeing in these wells, is it better than you were internally modeling in line?

Jay Allison

John, we think our 5 Bcf guidance is valid. We are, as you said, a conservative estimator of the Haynesville reserves compared to a number of other forecasts that are out there. We see EURs in our Logansport area, for example, that are substantially greater than 5 Bcf. We see some EUR in the Benson [ph] that is in the 4 to 5 Bcf range. So in order to give a blanket or an average guidance level, we're sticking with our 5 Bcf, but you are right. I mean we are seeing some EURs that are substantially better than 5 Bcf in our Logansport and Mansfield regions.

John Freeman - Raymond James

Okay, and then of the 57 wells, are you able to break out at all, of those 57 horizontal wells, how many of those are going to be targeting the Bossier?

Jay Allison

Yes, we have a pro forma estimate of those, and of course, it is subject to change as results dictate. We plan to drill probably around 15 or so upper Haynesville or Bossier tests.

John Freeman - Raymond James

Okay, great, and then last question I will turn it over to somebody else, with the gas rig count rebounding pretty strongly from the bottom of 665 now almost up to 900 gas rigs, are you starting to see any cost creep, and if so would you still expect that to be offset by the continued drilling efficiencies you are seeing?

Jay Allison

Yes, we are seeing some cost creep as a consequence of the increased demand for the Haynesville services. As you know, the Haynesville is unique among the shale plays since it is an abnormally pressured shale, and requires specialized equipment to drill and complete them. But again, we do feel we can offset some of that cost increase by the improved efficiencies although not all, we are pretty far along in improvements on our drilling side. We think we have got a few days we can shave off on the drilling end, but as you increase the lateral length, you also increase the number of days that are required to drill those increased lateral lengths.

And as you pump more stages as well, that requires some additional equipment, meaning, more plugs, more wireline service et cetera. So there will be some offset there, but we do anticipate some increased costs going forward.

John Freeman - Raymond James

Great. Thanks guys.

Roland Burns

John, we did -- we put some extra costs in our CapEx budget for anticipated costs that would increase in 2010 versus where we were in 2009. So hopefully we have budgeted for those increases.

John Freeman - Raymond James

Thanks Jay.

Operator

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

Leo Mariani – RBC

Hi guys. Was hoping you would expand a little bit on that cost question, and try to get a better sense of what your current well costs are, when you guys drill wells at Logansport and Mansfield, and also with North Toledo Bend out there?

Roland Burns

Currently we are estimating between $7.5 million to $8 million. That is with the increased number of fracs that we are planning upon.

Leo Mariani – RBC

That is with 18 stages.

Roland Burns

16 to 18.

Leo Mariani – RBC

16 to 18?

Roland Burns

Yep.

Leo Mariani – RBC

Okay, it sounds like at South Toledo Bend you guys mentioned, you were waiting on the pipeline, can you give us an update on what your infrastructure situation is in some of the other key areas here primarily in North Toledo Bend and in Logansport, and you know, what you think that can look like during the course of 2010 and you guys have for capacity how many lines out there?

Roland Burns

Yes, we have got plenty of firm capacity. Our VP of marketing is aligned us with several takeaways, and our firm is scheduled such that it tapers as we increase our drilling activity and get more production. The infrastructure in the Logansport and Toledo Bend North area is where we need it, and when we need it. So we have no issues there. Toledo Bend South, I think is as Jay mentioned earlier, we are waiting on a pipeline to get laid over.

We got the firm already arranged. We just need to get to take line installed and laid over to our test well over there. But we are in pretty good shape.

Leo Mariani – RBC

Okay, I guess sticking with Toledo Bend South, you guys mentioned that you are, I believe you said you are upper Haynesville well out there that you were waiting to complete when the pipeline gets in place, you know, what is your thought on the prospect to be that for the lower Haynesville as well. Is that something you plan to test in 2010?

Jay Allison

The Toledo Bend South well is the upper Haynesville or Bossier test that you mentioned. And that is the one we are waiting on that pipeline for. And in most of our acreage, quite a bit actually, two thirds of it, we find the upper and the lower Haynesville both prospective in the same acreage tracks.

So the first things first, we want to drill to the lower Haynesville and test the lower Haynesville to keep the deep rights through the lower Haynesville, and the upper Haynesville is considered the next level target, although on the logs. And as you know, you may recall in the second quarter, we announced the results of our BSMC 7-2, and it is an upper Haynesville test completed by north, and it was quite encouraging.

And we have a large database of the upper Haynesville logs, and have it we think well mapped, and so we are excited about the opportunity to test the upper Haynesville going forward.

Leo Mariani – RBC

Okay. Thanks guys.

Jay Allison

Yes.

Roland Burns

You know, wanting that we do and we did this at the beginning of 2009 is, the technical group was allowed to say where the wells will be drilled. In other words, if we need to drill six wells or 15 upper Haynesville wells or Bossier wells, and that is what we will do in 2010. We left that be a fluid number, because we are trying to prove up the greatest well, but we are also trying to prove up the value. I think the upper Haynesville is more in the emerging stage like the lower Haynesville was a couple of years ago.

So I think hopefully a year from now, a lot of companies will have a lot of information hopefully on the success of the Bossier, the upper Haynesville and we plan on being one of those.

Operator

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

Ray Deacon - Pritchard Capital

Yes, hi. Mack I was wondering if there -- would you give a breakdown I guess between the areas you guys are in De Soto between Toledo Bend North and South, kind of how the acreage breaks down?

Mack Good

In terms of total net acreage?

Ray Deacon - Pritchard Capital

Exactly right.

Mack Good

We have about 25,000 net acres between those two tracks, 25,000, 26,000 and it is split pretty evenly between the two areas.

Ray Deacon - Pritchard Capital

Right. Got it, got it. And I guess have you seen any recent acreage transactions or is there any -- are there any packages out there now. I mean I heard there was a lot of them in the Texas side, but has there been any transactions of size that you guys have seen or that on the market. I'm just trying to get a handle for kind of recent acreage prices that people were paying.

Mack Good

You know, we are very opportunistic and we look all the time and we have seen quite a few packages on the Texas side as you mentioned. You know, we have picked up some acreage recently. You have noticed our acreage both for the upper and lower Haynesville have increased. But we have acquired most of the acreage will drill to earn provision. There is acreages expiring, so we will carry an operator per quarter on the first well and then we'll end up at about 75% of that well. And then they will have to pave their way in the second well alone. But we have earned some acreage like that.

Ray Deacon - Pritchard Capital

Got it.

Roland Burns

We have leased some acreage that was expiring. You know, I don't think there is -- I don't think a lot of people are looking for Tier 1 acreage, and I think Tier 1 is defined a little differently. It depends upon if you are dropping south in Sabine or dropping south in Shelby or (inaudible) et cetera, et cetera. But I think -- you know, we think that maybe 2010 we can capture some more of the Tier 1 acreage. If we have 80 acre spacing, we drilled 56 or so wells, and if we can pick up 5,000 or 6,000 net acres, you realize we would have replaced our entire drilling program in 2010 -- by the end of 2010 by picking up just that amount of acres. So as a minimum that is our goal and we would really like to pick up more than that, but we look every day.

Ray Deacon - Pritchard Capital

Got it. And just I guess to more quick ones. Will you say which area your -- the Bossier tests are going to be in, and also I guess, am I remembering right that none of the drilling, the wells you were drilling in 2010 are on PUD locations is that right?

Mack Good

We have two wells that we have identified right that will be PUD, PDP conversions this year and that is it.

Ray Deacon - Pritchard Capital

Okay, got it.

Mack Good

And we plan to drill our upper Haynesville tests on our south blocks Toledo Bend North and South and we also plan to test in Logansport.

Ray Deacon - Pritchard Capital

Got it. Thanks a lot.

Jay Allison

Thank you.

Operator

Your next question comes from the line of Sven Del Pozzo with C.K. Cooper. Please proceed.

Sven Del Pozzo - C.K. Cooper

Hi, good morning.

Jay Allison

Good morning.

Sven Del Pozzo - C.K. Cooper

I'm wondering, it sounds like the -- we are in the early stages, but for the upper Haynesville, looking down the road if your two wells, the two tests that you have got coming well, would you entertain the notion of perhaps selling some undeveloped acreage or even some proved reducing Cotton Valley properties in order to finance an upper Haynesville development program, if in fact the -- those wells look better than what you got for example in Texas?

Roland Burns

As far as -- this is Roland. As far as financing our program, I mean that as one of our -- not one of our huge concerns. We have got a lot of liquidity cash on the balance sheet to invest in marketable securities, ultimately to divest and invest in the program. So, as far as looking for financing sources that is one of our -- least of our problems. So we really, as far as selling acreage in our core area East Texas/North Louisiana, I don't think that is a great idea. We're still looking at lot of different ideas even for East Texas area, and so we would not want to sell out our acreage early on, just to accelerate drilling.

Sven Del Pozzo - C.K. Cooper

Okay.

Roland Burns

We will have a very strong drilling program this year, and it is going to be more. I think we will accelerate it more based on natural gas prices, and if the gas prices are stronger, we will respond to that. If they are not, we will respond to that. But as far as having the funds to finance it, I mean that we are in great shape with the completely undrawn credit facility, lots of cash to invest, and…

Jay Allison

With our balance sheet right now, with our drilling program, you know, our guess is that we would not use any of our availability. But we probably wouldn't use any of our marketable securities. We just use the free cash flow plus the cash that we have in the bank right now. So, I mean, you get a company [ph] this $1.1 billion of equity, almost $2 billion of assets and we have got $700 million of other unused availability of marketable securities or cash. It is a pretty strong numbers. So I think we would look at monetizing some of some of the areas we are not active in.

I mean, we are not active in Mississippi. We are not active in the mid-continent. We're not active in San Juan. So those are areas, and we have 15, 16 million a day of production in those areas. So I think if the market is right and the price is right, we would look at monetizing those and redeploying those dollars in our core area.

Sven Del Pozzo - C.K. Cooper

Okay, and you already mentioned that 2010 unhedged, but I was wondering if you had any view on perhaps hedging the basis differential, so basically to insulate yourself from any regional basis widening in the future, and what is your reasoning for doing so or not doing so?

Jay Allison

I get the question, would we just want to hedge the basis differential. I think what we basically do in that region, especially with the new Haynesville production is we have gone through and committed to and acquiring a lot of firm capacity, to gather the gas and ultimately transport it to the markets. As far as looking at, worrying about the basis differential and trying to lock that in, I mean we typically, if we were to hedge we always like to hedge the basis differential, because we want a perfect hedge that actually matches the wellhead gas. But as far as just wanting to hedge just the basis differential because we are worried about it, there is a large differential showing up.

I mean that is quite not really in our plans. You know, basically the differentials have been fairly low throughout most of the different markets, due to the availability of a lot of transportation out there. So, sometimes they do get wide, but it is very hard to predict. But it is also not easy to hedge. It is very expensive to hedge because it is kind of unpredictable, where you could pay a very large price to try to lock in a number.

Sven Del Pozzo - C.K. Cooper

Okay, and the working capital deficit that we saw accumulated at the end of the year, I guess that will start to turn around when you get that -- the income tax refund sometime in the first or second quarter of 2010. Is that -- are those two things linked?

Roland Burns

Yes, well, I don't think there is a working capital deficit though. I mean if you look at our, at the end of the year, it is quite a large working capital surplus. I mean, we have…

Sven Del Pozzo - C.K. Cooper

All right. Sorry about that.

Roland Burns

…$273 million of current assets and only $95 million of current liabilities. But included in the current assets is the $42 million receivable.

Sven Del Pozzo - C.K. Cooper

Oh, it is in there already. Okay.

Roland Burns

But it is a very large surplus, working capital surplus.

Sven Del Pozzo - C.K. Cooper

Okay, thanks. And then the very last thing, based on what your reservoir engineers have done, what is the number that we can keep in the back of our head, you know having seen other Haynesville shale producers report reserves, and we have been able to kind of back into some kind of breakeven price for some of them. What about for you guys in terms of where do you reach the -- what gas price allows you to reach your economic limit for -- I know it is going to vary from well to well, but I guess all in, based on what you have got in your proved reserve report, what kind of a gas price or what gas price at the wellhead gives you your breakeven value for a well.

Mack Good

Well, this is Mack. Breakeven will be about 350. We would like to see a $5 gas price or something close to that to give us a reasonable rate of return on our 5 Bcfe wells.

Sven Del Pozzo - C.K. Cooper

All right. Thank you very much.

Jay Allison

Thank you.

Operator

Your next question comes from the line of Mark Lear with Sidoti & Co. Please proceed.

Mark Lear - Sidoti & Co

Good morning gentlemen.

Jay Allison

Good morning.

Mark Lear - Sidoti & Co

Looking at the production guidance the range you guys put out here. Just wanted to kind of get an idea from you, what is the reason for the range and is that kind of leaning more towards the transportation, how that rolls out or you know, it seems that you can get to the high-end of the range putting up about 3% sequential production growth each quarter in 2010, where recently you guys have been putting up low double-digit type sequential growth. So just kind of want to get an idea from you guys how you roll that out?

Mack Good

This is Mack. One particular point to make about the range is that, we in building the range wanted to accommodate some of the changes in scheduling that would affect the production, and when the production comes online and how quickly it comes online, there are a number of considerations there. One is we are increasing the number of stages so the logistics in getting the work scheduled and done has changed. We're not the only operator that is doing that. And so the demand for that kind of work is going to be extremely high. So that is number one.

Number two is we're looking at the possibility of producing our wells at a lower choke setting in order to evaluate the performance profiles, a number of operators are doing that as well. And looking at the impact on producing the wells’ lower choke setting at a slightly lower rate and the impact of that on the declines and the consequent result on EURs.

So in building the range, we looked at all of those factors that I just mentioned plus many more, and so you are right, we could be at the upper end of that, but certainly given the variables we wanted to make sure that we put a lower side range in place.

Mark Lear - Sidoti & Co

Got you, and just looking for a little more granularity on Haynesville reserve bookings. I was just kind of curious, what the recovery per well and how many PUD locations you are able to book per net well drilled in 2009?

Jay Allison

Well, with the drilling program that we had in place in 2009, we targeted and limited ourselves really to two offset PUD locations per well drilled. We did not assign two PUDs in every case. We wanted to make sure that we had performance that justified that. In certain instances, we didn't think that the well had produced long enough to substantially prove the two offsets that we kept that in our hip pocket for adding those reserves in FY 10.

And on the flip side of that, we did claim eight third offset PUDs that we felt were justified and supported by all of the technical data. So, overall we had a total of 74 Haynesville PUDs that we added during the course of well 9. We felt like we could have added a lot more. The rules allowed that. We chose to be as usual conservative in our booking.

Mark Lear - Sidoti & Co

Got you. Thanks a lot.

Jay Allison

You bet.

Roland Burns

Thank you.

Operator

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

Jack Aydin – KeyBanc

Hi, guys.

Jay Allison

Hi Jack.

Jack Aydin – KeyBanc

To be in the line one of the last ones, most of the questions were asked, but I have a few ones, to continue on the reserve booking it looks like you are estimating 400 to 500 bids of potential bookings in 2010. What kind of you know, offsets factoring in that booking, potential bookings. How many offsets for each producer?

Jay Allison

Two.

Jack Aydin – KeyBanc

Two.

Jay Allison

Yes, sir. We're not, again -- we're keeping with our conservative approach and not exaggerating the offset numbers of PUDs.

Jack Aydin – KeyBanc

Mack, do you have -- would you care to give us 30 day or 60 day average production for some of the wells that have been online for at least 6 months to a year?

Mack Good

Jack, I can do this. It may or may not help you when you look at the numbers. Most of our wells are generating 30 day IPs, and there are a lot of variables that work here obviously. But around 75% of the reported IP, the initial production rate reported for a well and then when you look at that rate versus the 30-day average were at 75% level.

Jack Aydin – KeyBanc

Okay, is that tracking -- you know, I'm trying to get your reserve booking, looks like conservative, how's that tracking your EUR that you are estimating, is it above the curve, what you are estimating?

Jay Allison

In some cases it is significantly above the curve Jack. And in other cases, it is just below it. So, again, without muddying the water here on EURs and getting specific in one area versus the other, our average guidance we think continues to be appropriate. It is obviously conservative. We choose to stay conservative with our EUR guidance.

Jack Aydin – KeyBanc

Okay, would you care to give us the exit rate for the Haynesville right now, what you're producing. I know what the average for the quarter, do you care to give us what is the exit rate now?

Roland Burns

Right now, we are around 87 to 88 million a day net.

Jack Aydin – KeyBanc

And how many wells waiting to be hooked online?

Roland Burns

We have three waiting on completion just about ready to go to a fourth.

Jack Aydin – KeyBanc

Okay. Thanks a lot.

Roland Burns

You bet Jack.

Jay Allison

Thanks.

Operator

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

Ron Mills - Johnson Rice

Hi, guys.

Jay Allison

Hi Ron.

Ron Mills - Johnson Rice

Just to repeat on that one number, Mack your current production in the Haynesville, you said it was 86 million or 87 million a day.

Mack Good

87.

Ron Mills - Johnson Rice

Okay, great. Then a question just, when you look at Toledo Bend North versus Logansport versus Mansfield and the different deliverability rates, where those production rates kind of as expected for each of the different areas. It looks like Toledo Bend North is not as high a production rate as Logansport, and what is your expectation as you begin drilling in Toledo Bend South. I'm just trying to get a sense as to break down?

Jay Allison

Sure. We have relatively high expectations for Toledo Bend South, but having said that we haven't completed our first well there yet. And so, for us the proof is what we put into the pipeline, and we're not there yet, Ron. So we're anticipating performance that will be very appealing. But Toledo Bend North we have drilled and completed 11 wells that are in the public domain, that those average -- those wells have averaged 10 million a day IP rates, 30 day average IPs are about 80% of their initial production rate. So a softer decline there on average.

We do plan as I mentioned earlier to increase the number of stages. We think that will improve performance as well. And to your question about expectations elsewhere, our Logansport Mansfield area (inaudible) et cetera, they have met expectations. We also anticipate performance improvements as a result of the completion change to a larger number of stages, and perhaps increased profit loading as well.

Ron Mills - Johnson Rice

Okay, and as I look at your -- the map of your 33 completions. The well that came on at 7 million a day looks to be more in the far north-east portion of your Toledo Bend North field. Are you seeing things change as you move that way, and more of your activity was at 24, 25 wells planned for that area this year, I guess 19 in Toledo Bend North. Is it going to be moving back to the south and west where you had a little bit better wells?

Jay Allison

You know, we're not prepared to put a blanket statement on the Toledo Bend North area in the north-east corner being of lesser quality. The Haynesville does change and can change quickly in a play content in thickness, and there can also be some splinter falls et cetera. So we tend to again be a little bit more pragmatic in our approach to testing these areas. We don't think one well is the answer for a particular area. So we do plan to drill another well or two in that corner. But you are right. I mean most of the activity in Toledo Bend North is going to be distributed across all of our blocks, all of our drilling units, pardon me.

Ron Mills - Johnson Rice

Okay, and as you all talk about drilling you know, 14, 15, 16 upper Haynesville wells this year, are those going to be drilled in areas where you've already drilled lower Haynesville, and why the first well in Toledo Bend South only going through the upper Haynesville. Was that leased -- you're not concerned about that lease for the lower Haynesville or just --

Jay Allison

Well, we have plenty of time on our lease clocks. We are not concerned at all about the Toledo Bend South clocks now. We did drill through the lower in the Toledo Bend South well. We drilled through the lower Haynesville, and we know what that looks like. We’ve chosen to test the upper to get a read on the upper Haynesville performance in that block. So in the Toledo Bend North it's a little bit different strategy. We have tested the lower in almost every drilling unit there. So we've held those leases by production.

Ron Mills - Johnson Rice

Okay, and then I guess Roland this would be for you, based on ranges, the production range and kind of your current cost and what not. My number is -- it looks like your -- between your cash on hand and cash flow should be enough to fund that $385 million budget, as long as gas prices are you know, $550 million or so. Is that seem in the ballpark, is that kind the way the program has been designed to, you know, based on that kind of price debt between your cash flow and cash on hand?

Roland Burns

That's about correct Ron. We looked at about that. You know, above 550 type of NYMEX price, so we are looking at 525 per Mcf price, realized, you know, would fund, you know, that program along with the cash on hand, but that's kind of our base program and very comfortable with that, given where the gas prices are, but, you know, like last year and all the years, you know, we can really move the throttle forward or backwards you know, based on kind of how we see the year play out, and I think since we're starting that kind of a lower base, you know, there is a possibility towards the latter part of the year that we you know, spend more.

In our budget we have you know, about $20 million, you know, set aside for lease acquisitions and that's just kind of a -- but we'll happy to spend more than that if the opportunities are there to buy you know, quality acreage, but that's kind of, you know, not too far from what we spent in 2009 just adding around, leases around our existing acreage that we have now.

Ron Mills - Johnson Rice

Great, and Jay I think you said you have about $15 million or $16 million a day producing from your other regions. What are your -- the reserves associated with those other regions?

Jay Allison

Well that used to be about 84.

Roland Burns

Actually it's less than that in the year before it. I think it's -- maybe roughly 50 Bcfe or so in those other regions. Now some of those reserves are probably still there, but under the SEC rules, we're not going to try to claim them, you know, because we don't have those in our drilling budget.

Ron Mills - Johnson Rice

Right.

Roland Burns

So that range is you know, off the books, you know, probably proved reserves that we are just moving [ph]. It's roughly the same reserves that it was but is presented differently for SEC purposes.

Ron Mills - Johnson Rice

Is it around 50 now Mack?

Mack Good

I guess about 75.

Ron Mills - Johnson Rice

75.

Jay Allison

It used to be about 83 or 84. It's a little less than that because of pricing. You know, we haven't spent any money there as you know in ‘08 or ‘09, and we don't plan spending any money there in 2010. So it is a divestiture region for us.

Ron Mills - Johnson Rice

I was trying to get a sense for that region. Right, great guys. Thank you very much.

Jay Allison

You bet.

Mack Good

Mack, if you look on the presentation slide 3, we breakout “the other regions” at that $16 million a day.

Ron Mills - Johnson Rice

Thank you.

Operator

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

Noel Parks - Ladenburg

Good morning.

Jay Allison

Good morning.

Noel Parks - Ladenburg

Just I had a couple of things. Actually Mack you touched on 15 minutes ago some of the experimentation, and I guess improvements you are still doing in the Haynesville regarding completion. I think you mentioned increased profit loading, for example. Can you sort of summarize maybe how you optimize completions over the last six months or so, just some of the changes and some things you maybe tweaked. We're talking a lot less now than we were a year ago about challenges with getting wells done. So, just wanted to hear more about what you had covered on the learning curve.

Mack Good

Sure. On the drilling side, our drilling engineers, drilling manager continued to look at bid programs, the different vendors for the mud motors. Improvements have been made to allow the mud motors and bits to staying whole longer, and of course improve rate of penetration, ROPs. That has allowed us to gain some days on our drill time, and of course the costs are paired off our drill side ledger for that reason. Improvements in completion continue and other operators are looking at different perforating schemes, different levels of profit loading, and different numbers of stages.

It depends on the area that you're in, for example, it may or may not be the case that 18 stages is the optimum number of stages in Logansport, and maybe that 16 stages, and of course 16 stages cost less than 18, but 16 may give you the same performance as 18. That's the kind of optimization that has not yet been done in any area. Most operators have been staying between 12 and 14 stages over a 4500 foot frac, pardon me, lateral length with profit loadings anywhere from 200,000 to 300,000 pounds of profit per stage.

Now as the first round or the first phase of the Haynesville Shale play has been conducted over 2009, operators are starting to change their approach, improving not only the drill side equation, but looking at how can they get the biggest bang for the buck and improve production performance with increased numbers of stages, different perforating schemes and profit loading. So long-winded answer to your question, there's a lot of variables to try and if it change everything at once, you won't know what really worked and what contributed the most to the performance improvements that you hope to gain.

So we're trying to approach this in an incremental fashion, changing one thing at a time and as we go forward this year, we're going to pump more stages with the same profit loading per stage. We're going to pump more stages with increased profit loading per stage and measure the hoped for improvements in an effort to optimize our completion designs for each of the areas that we control.

Noel Parks - Ladenburg

Okay, great. That's just what I was looking for. And as you look at that and think about how costs are likely to improve going forward, and maybe just looking at 2010 and 2011, do you think that the efficiency and improvements will stay ahead of whatever cost inflation you might see just this -- it looks like you'll keep getting -- you know, maybe increased rig count or increased drilling activity regionally and perhaps nationally.

Jay Allison

It's a great question, and I wish I had a crystal ball that I could gaze into and give you a decent answer. I know we made incredible improvements from the start and to where we are now, and other vendors are working hard to improve their equipment, you know, the high pressure, high temperature environment is tough on mud motors, electronics, down [ph] electronics, et cetera. So, you know, that's point one is that that work is ongoing and hopefully the improvements that will be made over the next several months will offset some of these price increases that we're talking about earlier.

You know, there's also the risk component of the completions every operator faces this, when you're completing a 4500 foot lateral. You know, we spend a lot of time cleaning the hole, so we can run our casing for example. Time is money and we want to shave days off of that process. So operators, vendors are looking at ways to improve that to cut the time that it takes to clean the hole prior to running the production casing.

The number of plugs that we set. Obviously we got 18 stages. We're setting more plugs over each stage. The total number of plugs in the hole that we have to drill out has increased substantially. That's more mechanical risk. We think we've got a process in place or a procedure in place that minimizes that risk, but certainly more plugs in the hole means more things you get out of the hole, and so that drives up a little bit of the cost that we're talking about as well as risk.

Vendors are looking at different ways to complete these wells without running plugs on wireline or on cold tubing. So all of that rolled up into a ball doesn't answer your question, but it gives you an idea of some of the work that's going on to improve the efficiencies of the drilling and completion practices in the Haynesville, and whether or not it offsets costs. I am a market guy -- as perhaps most are listening to this call. If costs exceeds the threshold of the operator, then you'll see the activity start to slack up in the Haynesville until these costs comeback in line where they need to be.

Noel Parks - Ladenburg

Great, thanks, and just a couple of more quick things. In terms of acreage, I heard you say that, I think Toledo Bend South you're pretty much satisfied holding everything by production?

Jay Allison

Toledo Bend North.

Noel Parks - Ladenburg

I'm sorry. It was North, okay great. Keeping the idea of roughly how much you have, meaning that still have to be drilled for the holding leases at this point. I know you’ve had some acquisitions, I don’t know if that changed that balance at all.

Jay Allison

No, you know, we have a timeline on our leasehold, you know, we don't publicize that obviously, but we're well equipped to protect our leases with our Y 10 [ph] program. We're in good shape.

Noel Parks - Ladenburg

Okay, and a couple of financial questions. G&A for the coming year. I know there was the extra $1 million charge in fourth quarter on the uncompleted deals, but is it going to be pretty close to the say the third quarter run rate going forward or do you expect to see some pick up there as well?

Roland Burns

No, we'll probably say it's going to be roughly around $10 million a quarter. So probably that third quarter was the lowest of any quarter in 2009. So if you look to you know, the levels, the first and second quarter, I think that would be a good way to estimate it.

Noel Parks - Ladenburg

Okay, great, and just a housekeeping question. What was capitalized interest in the quarter? Sorry if I missed that before.

Roland Burns

Sure. Let me grab that for you. Yes, interest capitalized on our unevaluated leases that we are conducting drilling activities for the quarter was $2.1 million.

Noel Parks - Ladenburg

Okay.

Roland Burns

And that's probably a good proxy for you know, what you'd expected you know, for at least for 2010 a quarter but now the interest is, most -- all our interest is under the -- is fixed rate you know, under the -- under our two bond issues. So the increase of capitalized interest really from the third-quarter really relates to the higher interest rate on the bonds versus the bank debt.

Noel Parks - Ladenburg

Right, it's just the way I was asking, and just the last thing if I understood right, the acreage acquisitions you made were clustered mostly in the fourth quarter. I think it's about $17.6 million. Was that a single package or buying out a single operator. Was that just all incremental, because I was surprised it is such a big number in the quarter.

Jay Allison

We improved our positions in Toledo Bend North and South by acquiring interests that we didn't control in drilling units that we had formed in the way of the majority interest in. So it was an improvement in our positions within Toledo Bend North and South.

Noel Parks - Ladenburg

Okay, and was that a result of a distress situation on holdings [ph] holder or just, you know, --

Jay Allison

No.

Noel Parks - Ladenburg

Needed land management.

Jay Allison

We're working all the different opportunities around our existing acreage. We just let a lot of those close I think after the next quarter. They were a lot of those were signed up earlier in the year and took a long, you know, due diligence to close them.

Noel Parks - Ladenburg

Okay, great. Thanks a lot guys.

Jay Allison

We expect a similar program at a minimum this year to, you know, leasing up adjacent tracks where they are available.

Noel Parks - Ladenburg

Okay.

Mack Good

Thank you.

Noel Parks - Ladenburg

That's all from me. Thanks.

Jay Allison

Thanks Noel.

Operator

The next question comes from the line of Richard Tullis with Capital One. Please proceed.

Richard Tullis - Capital One Southcoast

Hi, good morning. Thank you. Just a couple of questions that hadn't been touched on, yet I believe. Jay, the 5 Bcfe EUR estimate you given for the Haynesville, is that for all your acres that hold 73,000 including East Texas?

Jay Allison

Yes.

Richard Tullis - Capital One Southcoast

What do you estimate just for north Louisiana on average?

Jay Allison

You know, we go anywhere from you know, 3.5 to 5.5 Richard. It's a blend. But what we tried to do is we try to add that with our Louisiana acreage, and we come up with again like Mack said probably a conservative number, but overall we think 5 Bcfe is good. I know a year ago at this time we just, we went from 4 Bcfe as an EUR to 5 Bcfe. I always tell people that we want to be pulled across the finish line to get a 6 or 6.5. We're just not there internally with the result we've had with the technical people we've had for the acres that we have. That's not to say that other acreages is not better than that, but overall we think our acreage is probably 5 Bcfe as an EUR.

Richard Tullis - Capital One Southcoast

Okay, what were the average reserve bookings for the East Texas wells in the last report?

Jay Allison

I'm not sure with the -- we didn’t book a lot of reserves in the East Texas, Haynesville because we did not plan to offset from the SEC report, you know, on those wells because the very low gas price that you had to use.

Mack Good

Remember, only four of the wells that we drilled in '09 were on the Texas side.

Richard Tullis - Capital One Southcoast

Okay, what --

Mack Good

I don't think we did book in.

Jay Allison

We didn’t book any offset.

Mack Good

We (inaudible).

Jay Allison

So we just booked a PDP well for the four wells.

Richard Tullis - Capital One Southcoast

Right. Are you able to say would you book for those per well on average?

Jay Allison

Less than 5 Bcfe.

Richard Tullis - Capital One Southcoast

Okay, fair enough.

Mack Good

The 3 Bcfe plus or minus something. That's going to be our -- that's the reason why they -- we didn’t book offsets to them at the type of level because most of our offsets we book a little more conservative than the first well.

Richard Tullis - Capital One Southcoast

Okay.

Jay Allison

And again, you know, we hope the other companies had better results than that. We are not trying to diminish their results. It is just what we did and what we booked.

Richard Tullis - Capital One Southcoast

Sure. What are your expected well cost for your upper Bossier wells?

Jay Allison

The same for the lower.

Richard Tullis - Capital One Southcoast

Okay.

Jay Allison

There's no appreciable difference.

Richard Tullis - Capital One Southcoast

And the LOE for the Haynesville wells, I noticed you had the progress a couple of quarters back and it looks like it kind of leveled off due partly to the production taxes. What are you getting for LOE for the Haynesville wells right now say on average?

Jay Allison

Well, it's hard to separate out because our Haynesville wells are in our existing fields, and so they are going to bear the fixed cost of the field as they are in the same field as the Cotton Valley. So, you know, incrementally it is not adding a lot of cost but it is going to have to absorb, you know, the field operation cost.

Richard Tullis - Capital One Southcoast

What do -- for 2010 stripping out production taxes. What sort of improvement do you see versus fourth quarter '09?

Jay Allison

I think we see -- on a rate business you know, on a unit production basis, you know, we'll see continued improvement, you know, it's hard to exactly forecast, but, you know, we really don't see adding a lot of new fixed cost to the Haynesville production until you start adding compression to the wells, which probably is in the you know, third-year or so. So really won’t affect us very much in 2010.

Richard Tullis - Capital One Southcoast

Okay, and then are you getting any tax exemptions related to your Haynesville wells production tax?

Jay Allison

We are, you know, the way the tax -- the production tax release in Texas is really that program. That's where you see kind of some, you see our production taxes kind of a little erratic is because you know, we've drilled a lot of wells in Texas in the Cotton Valley program, and then even some of the Haynesville program, and then you get kind of some relief to recover your cost and then they go back to their full rate. So, you don't get quite as much relief in Louisiana. So --

Richard Tullis - Capital One Southcoast

Okay, and then I know you don't need this at all for liquidity purposes, but any plans to do anything with the Stone shares?

Jay Allison

No, we have really no plans at this time you know, so --

Richard Tullis - Capital One Southcoast

Okay, and then finally I don't think you have any plans to drill any Cotton Valley horizontals in East Texas in 2010. Is that correct?

Mack Good

Correct.

Jay Allison

No, we've got maybe just a couple of verticals in our budget, but no Cotton Valley horizontals.

Mack Good

Right.

Richard Tullis - Capital One Southcoast

All right. Well, thanks. That's all I have. I appreciate it.

Jay Allison

You bet.

Mack Good

Thanks Richard.

Operator

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

Dan McSpirit - BMO Capital Markets

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

Jay Allison

Thanks Dan.

Dan McSpirit - BMO Capital Markets

Turning back to the reserve bookings, 2009 reserve bookings in the Haynesville Shale, what was the development spacing assumption applied in those bookings?

Jay Allison

80 acres.

Dan McSpirit - BMO Capital Markets

80 acres, okay. And in other wells the 57 horizontals that you drill in 2010, how many of those will in fact test that assumption?

Jay Allison

We have a half a dozen well spacing test wells.

Dan McSpirit - BMO Capital Markets

Okay, and that's 80 acres or less or just that 80 acres?

Jay Allison

At 80.

Dan McSpirit - BMO Capital Markets

Okay, okay great. And then of the $26 million that was invested in acreage acquisitions in 2009 what was the amount of acreage associated with that $26 million.

Jay Allison

Roland, you have that number?

Roland Burns

I don't. It's -- Mack might.

Mack Good

You know part of that, you know, (inaudible) part of that would be the capitalized interest, you know, that's where it shows up, and so $6.6 million of that numbers, it's just interest capitalized on the earlier expenditures, but the actual new expenditures would be you know more than 20.

Dan McSpirit - BMO Capital Markets

Right. Okay. okay, and then turning to slide 25 in today's presentation, looking at your activity for 2010, what's the future of your acreage in Shelby County that area just west of -- North Toledo Bend, and also I guess the acreage in West Panola County, the same side in East Texas, what's the future for that, that acreage?

Jay Allison

Our Shelby County acreage is part of an AMI, and we put our interests with common in Chesapeake and a couple of others, and you know, we have a blended out interest in operated block and those that area will start being drilled this year, and we'll retain a non-op interest in that acreage Dan. The Harrison County and Panola County acreage is all HBP. It's legacy acreage. We are going to drill a couple of wells on the Texas side to protect a couple of blocks of acreage that are exceptions to what I just said and let the gas price dictate any other activity that we might execute over there.

Dan McSpirit - BMO Capital Markets

Okay, great, and then lastly on the estimate of 400 to 500 Bcfe in reserve adds this year coming from the Haynesville, you know, what's the risk to that number? Is it more about the commodity price than it is the cost?

Roland Burns

Well, the commodity price would have to be extremely low for those reserves not to be added, and, you know, we're pretty much good to go all the way down to, you know, a 300, 350 gas price Dan in terms of executing this year's program just on the basis of a breakeven rate of return. So we're, you know, I guess the shortest answer to your question is we feel pretty confident in that low number in our range.

Jay Allison

I think Dan that even goes back to again at the very beginning, over an hour ago, I said in the, you know, fourth quarter of '08 we had less than $2 million a day of Haynesville production, and exiting the fourth quarter of '09, we have, you know, $84 million. That comfort that we were successful with our group and again with our balance sheet and our acreage. I mean that is why we feel comfortable saying we should add 400 to 500 you know, Bcfe.

It's based upon what we did in '09. Of course, this time last year we didn’t give you those numbers. We just said we thought we would have increased production, not 20% or 30%. You know, we ended up with double-digit production increase, and we thought. Remember the sentence was, if we could add significant reserves at low cost. But we didn’t give you a number because we didn't know it was a guess, and then as we you know, completed those first 29 wells and we had the production. And this year is completely different. It's based upon the footprint we have, with the cost structure we have, with the balance sheet we have, with the offset added to as far as reserve bookings, all based upon 80 acre spacing. You know, we think 400 to 500 Bcfe is probably pretty real, and if it ever changes we'd let you know.

Dan McSpirit - BMO Capital Markets

Very good, and again thank you gentlemen.

Jay Allison

Thank you Dan.

Operator

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

Ray Deacon - Pritchard Capital

Yes, hi Mack. I just had one more question regarding you know, the days to drill looks down significantly even though you're drilling more fracs per well, and I guess do you see progress from here or do you think you're getting close to as efficient as you can get?

Mack Good

No, I think we can do better. I would -- if our department managers were in here, they'd say the same thing. You know, consistency is what we're striving for. So if you look at the chart sheet, you'll see a little bit of scatter and we want to take the scatter out of the performance. We want to stay at a 75-day spud to sales number, and we want to do it for each and every well, and if not better. So you know, the consistency goal is what we're striving for right.

Ray Deacon - Pritchard Capital

Got it. Okay. And I guess just, you know, I hadn't seen you talk this definitively about the upper Haynesville before I guess. What is the sample set at this point? Do you know how many wells have been drilled? I mean is that…

Jay Allison

Well, that's a great question. There've been a lot of penetrations obviously through the Bossier or the upper Haynesville, and so through our participation and the various study groups, Haynesville study groups core consortium, object reservoir, and then data trading with our partners, working interest partners, wells that we participated in on a non-op basis in the Haynesville plus unique data trades that we've done. We've managed to map the upper Haynesville and we feel confident in our interpretation.

There has only been a handful really of upper Haynesville wells completed and tested the sales. The reason for that is obvious most operators, us included, we want to get that lower Haynesville HBP on our leasehold, any new leasehold, and so we've chosen and other operators have chosen to complete that, the lower Haynesville preferentially to the upper, but now we're starting to enter a phase where you're going to start seeing some additional upper Haynesville tests that will make the interpretation in terms of performance more supportable.

Ray Deacon - Pritchard Capital

Got it, and do you -- I don’t want to put this in your mouth, but do you feel like because of the lower decline rate, the returns could be pretty close to the lower or you just not know yet I guess or…

Jay Allison

Just don't know. I mean, you know, I would speculate so, but that's just based on all the other data that I've looked at, but again it's what you put into the pipeline, and the performance that will support that.

Ray Deacon - Pritchard Capital

Got it. Thanks.

Jay Allison

You bet.

Operator

Ladies and gentlemen, this is all the time that we have for questions at this time. I would like to turn the call over to Mr. Jay Allison. Please proceed.

Jay Allison

Eric again, thank you. I know it has been about an hour and a half. I'd like to close and just you know, tell you again those that are still there, our goal in 2010, you know, while keeping our strong balance sheet intact, you know, we will be able to have an aggressive drilling program that should increase production rates materially, and add significant reserves as Ray had said earlier, Dan McSpirit said earlier maybe 400 to 500 Bcfe is our goal, but we want to do that at the low finding cost, which ultimately increases shareholder value because that's what we charge to do.

And then I think at the same time you know, we can take advantage of any opportunity to expand our acreage position, which you've seen we've done that a little bit in the fourth quarter of 2009. So again thank you for your patience. Thank you for allowing us to have a transition from being kind of a conventional company to a resource play company and again, I smile when I think about the weather. It's cold outside. Get you another coat. Thank you.

Operator

Thank you for your participation in today's conference. This concludes our presentation. You may now disconnect and have a good day.

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Source: Comstock Resources, Inc. Q4 2009 Earnings Call Transcript
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