Comstock Resources Inc (CRK) 2009 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the fourth quarter 2009 Comstock Resources Earnings Conference Call. I'll 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.

Thank you, Eric. This morning as I turned on the TV. I turned on CNBC and the headlines were, quote - Winter Weather Wreaking Havoc - I just kind of smiled. Then they said from Virginia to Maryland, there's 35 inches of snow and don't worry, more is coming. Then they said this makes the blizzard in Denver in 1982 looks like a nothing. And this winter is the snowminator winter now. They talked about that, I just smiled. Then I turned off the TV. I turned on my radio to the weather station. It said possible snow in Dallas on Wednesday. I just smiled again and turned it off.

Then I turned my thoughts to the conference call today. And really, about where we were a year ago because 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 two 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. We drilled 45 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 and the Haynesville Shale horizontal drilling program with our technical people, with our strong balance sheet and on our acreage, we're more encouraged than ever that 2010 will be an even better year as we continue to realize the value of our Haynesville acreage, I think it became a lot more valuable from last year versus the year that we're in today.

If you go to page two, the 2009 highlights, please refer to page two of the presentation where we summarize our 2009 results. Low oil and gas prices in 2009 have caused reversal from the record setting profits we had in 2008. In2009 we reported revenues of $291 million. We generated EBITDAX of $199 million and operating cash flow of $224 million or $4.82 per share. The operating cash flow includes $42 million in income tax refunds from carrying back losses incurred this year. The low prices caused this report a loss of $36 million or $0.81 per share. Despite the low oil and gas prices, we're having a 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 now at 84 million cubic feet equivalent per day makes up 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 rules. Lastly, the debt financing that we complete 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?

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 up 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 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 Bcfe to 82 Bcfe. This would represent an 18% to 25% growth over 2009's 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 low 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 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 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 prices cost 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 tax depreciation, amortization, expiration expense and other non cash expenses or EBITDAX also decreased 10% in the fourth quarter to $64 million from $72 million in 2008's 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 a 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 ten, 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 nonreoccurring items that we had in 2008, especially the impairment on the value of the Stone Energy shares that we recorded, we had 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 for 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 costs decrease 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 the Haynesville Shale production.

On slide 12, we show our cash G&A per Mcfe produced by quarter which excludes stock-based compensation. Our G&A,our general 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 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 completion 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 rate 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 cost 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 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 the $175 million of our of six and seven-eighth percent senior notes and $296 million of our new eight and three-eighth percent 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. Taking 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 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'll now turn it back over to Jay.

As Roland finishes, I do need to comment that our discussions today do include forward-looking statements within the meaning of the securities laws and while we believe the expectations of such statements to be reasonable, as all of you know, there can be no assurances that 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 are 94% natural gas and 55% are Proved Developed. 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 of one 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 time frame. The new rules use 12 month average prices as of the first day of each month, realized by the Company which were $49.60 per barrel for oil and $3.54 per Mcfe for natural gas in 2009. Using the old SEC rules, the gas price used would have been $5.29 per Mcfe. This would have increased our Proved Reserves to 800 Bcfe, reducing the downward revisions by 74.

On slide 17, we review our finding costs for 2009. The Haynesville Shale program delivered excellent finding costs 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 a 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 costs of $1.21 per Mcfe or $1.12 if you exclude unevaluated lease costs.

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 them at 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 are 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 five Bcfe per well, our acreage could have 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'll now have Mack Good, our Chief Operating Officer review the results from our drilling program. Mack?

Thanks Jay. 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 have completed nine additional, successful operated Haynesville Shale horizontal wells in DeSoto 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 a BSMC 11 #1, the BSMC 13 #1 and the BSMC 5 #2 wells in the fourth quarter. Each of these wells had a lateral of approximately 4,500 feet long and were completed with 12 frac stages. The initial production rates from these wells range from 7.3 million to 11 million per day.

In the Logansport field we drilled five successful wells since our last conference call. The CARAWAY ESTATE 29 #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 #1 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 #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 #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 million cubic feet per day.

The last well on the Logansport list is the WHITEHEAD 9 #1. 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 pumped to date. And it tested at an initial production rate of 20.3 million cubic feet per day.

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

Flipping over to slide 22, we show you the number of days it's 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'll 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'll show you the number of days it's taken us to connect each of our 33 horizontal wells currently flowing to 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'll turn it back over to Jay.

Again, thanks, Mack. If you go to slide 24, our South Texas region is just -- on slide 24 and 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 million cubic feet equivalent 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 the more prolific part of the Play in North Louisiana. 27 wells were planned in Logansport and 25 were 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 a pipeline 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 the wells will be horizontal Haynesville Shale wells.

And then the final slide, which is slide 27, covers our 2010 outlook., We're 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 of Proved Reserves in 2010. We're well positioned for future growth when gas prices improve with a large inventory of drilling locations in the upper and lower Haynesville Shale, in Cotton Valley in East Texas and North Louisiana and then 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'd like to turn it over to Eric for questions.

Thank you. (Operator Instructions) Stand by for your questions. Your first question comes from the line of John Freeman with Raymond James. Please proceed.

Good morning, guys.

Good morning.

First question on the WHITEHEAD well which was the most staged you've done yet at 18 and at least on a production rate basis is one of the best ones you have had. Maybe if you can talk about going forward, were you satisfied with the incremental cost there was more than made up for with the better production rate? Is that something I would look at doing more of going forward?

John, this is Mack. And the short answer is yes. We do plan to pump more stages in most of our Haynesville wells going forward. We think we're getting a big bang for the buck there. We got about a 25% rate increase on the WHITEHEAD compared to offset wells where we pumped with a 12 stage completion. So, yes, short term data on the production comparison is that not only did 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.

Okay. Obviously you have been a lot more conservative than most in terms of the guidance for the Haynesville -- and I know you're not like changing any numbers at this point. But can you just kind of talk about looking back now, your drilling program last year -- is the tight curve you are seeing on the wells, is it better than you are internally modeling in-line?

John, we think our five Bcf guidance is valid. We're -- 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 five Bcf. We see some EURs in the Toledo Bend area that is in the four to five Bcf range. So in order to give a blanket or an average guidance level, we're sticking with our five Bcf. But you're right, we're seeing some EURs that are substantially better than five B's in our Logansport and Mansfield regions.

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?

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.

Ok, great. Last question, I'll turn it over to somebody else. With the gas rig count rebounding pretty strongly from the bottom of 665, now we're almost up to 900 gas rigs, are you starting to see any costs creep? And if so, would you still expect that to be offset by the continued drilling efficiencies you're seeing?

Yes, we are seeing some costs 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 the wells require specialized equipment to drill and complete them. But again, we do feel we can offset some of that cost increases by the improved efficiencies although not all. We're pretty far along in improvement on our drilling side.

We think we've 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 links and as you pump more stages as well, that requires some additional equipment meaning more plugs, more wire line service, et cetera. So, there will be some offset there. But we do anticipate some increased costs going forward.

Great. Thanks, guys.

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 budgeted for those increases.

Thanks, Jay.

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

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

Currently, we're estimating between $7.5 million to $8 million, Leo. That's with the increased number of fracs that we're planning to bump.

Okay. So, that's with 18 stages?

16 to 18.

16 to 18?

Yes.

Okay. It sounds like in South Toledo Bend, you mentioned you're waiting on the pipeline. Can you give us an update on what your infrastructure situation is and some of your other key areas here, primarily North Toledo Bend and Logansport and what you think that can look like during the course of 2010. Do you guys have firm capacity on any lines out there?

Yes, we've got plenty of firm capacity. Our VP of Marketing has 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're waiting on a pipeline to get laid over. We've got the firm already arranged. We just need to get a take line installed and laid over to our test well over there. But we're in pretty good shape.

Okay. I guess sticking with Toledo Bend South, you mentioned you are -- I believe you said you're -- you've got an upper Haynesville well out there that you're waiting to complete when the pipeline gets in place. What's your thought on the prospectivity of that for the lower Haynesville as well. Is that something you plan to test in 2010?

The Toledo Bend South well is the upper Haynesville or Bossier test that you mentioned. That's the one we're 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's 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 -- you may recall in the second quarter, we announced the results of our BSMC 7-2. It is an upper Haynesville test in Toledo Bend North. It was quite encouraging. We have a large database of the upper Haynesville logs and have it -- we think, well mapped. And so we're excited about the opportunity to test the upper Haynesville going forward.

Okay. Thanks, guys.

Yes, sir.

One thing that we do, when we did this at the beginning of 2009 is the technical group was allowed to say where the wells would be drilled. In other words, if we need to drill six wells or 15 upper Haynesville wells or Bossier wells, that's what we'll do in 2010, we let that be a fluid number because we're trying to prove up the greatest number of reserves. But we're also trying to prove up the value. I think the upper Haynesville is more in 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. We plan on being one of those.

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

Yes, hi. Mack, I was wondering, would you give a breakdown between the areas you were in DeSoto between Toledo Bend North and South. Kind of how the acreage breaks down?

In terms of total net acres?

Exactly, right.

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.

Okay. Got it. I guess, have you seen any recent acreage transactions or is there any -- are there any packages out there now? I heard -- there was a lot on the Texas side. Has there been any transactions of size that you guys have seen or that are on the market. I'm just trying to get a handle for recent acreage prices that people are paying.

Ray, we were very opportunistic. We look all the time. We've seen quite a few packages on the Texas side as you mentioned. We have picked up some acreage recently. You noticed our acreage count both for the upper and lower Haynesville has increased. But we've acquired most of that acreage with the Drill to Earn provisions. There is acreage that's expiring. So we'll carry an operator for quarter on the first well then we'll end up with about 75% of the lease. Then they'll have to pay their way from the second well on.

We have earned some acres like that. We have leased some acreage that was expiring. I don't think a lot of people are looking for Tier 1 acreage. I think Tier 1's defined a little differently. It depends upon if you're dropping south in Sabine or dropping south in Shelby or what part of Panola, et cetera, et cetera. But I think -- we think that maybe in 2010, we can capture some more of the Tier 1 acreage. If we have 80 acre spacing, we drill 56 or so wells, 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, at a minimum, that's our goal and we would really like to pick up more than that. But we look every day.

Right. Got it. Just, I guess, two 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're drilling in 2010 are on PUD locations? Is that right?

We have two wells that we have identified, Ray that, will be PUD to PDP conversions this year. That's it.

Okay. Got it.

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

Got it. Okay, cool. Thanks a lot.

You bet.

Thank you.

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

Yes, good morning.

Good morning.

I'm wondering, it sounds like we're in the early stages but for the upper Haynesville, looking down the road, if your two wells, the two tests you've got come in well, would you entertain the notion of perhaps selling some undeveloped acreage or even some Proved Developed producing Cotton Valley properties in order to finance an upper Haynesville development program if, in fact, those wells look better than what you've got, for example, in Texas.

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

Okay.

We'll have a very strong drilling program this year and I think we'll accelerate it more based on natural gas prices. If the gas prices are stronger, we will respond to that. If they're not, we'll 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.

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

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

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

I guess the question is would we just want to hedge the basis differential. I think what we -- basically do in that region especially with the new Haynesville production in that we have gone through and committed to -- and acquired a lot of firm capacity both 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 well-head gas.

But as far as just wanting to hedge just the basis differential because we're worried about it, large differential showing up, I mean that's probably not really in our plans. 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. It is very hard to predict. It is also not easy to hedge. It is very expensive to hedge because it is unpredictable. You could pay a very large price to try to lock in a number.

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?

I don't think there's a working capital deficit though. If you look at our -- at the end of the year, it is quite a large working capital surplus. We have --

All right. Sorry about that.

We have $273 million of current assets. Only $95 million of current liabilities. But included in the current assets is the $42 million receivable.

Oh, it is in there already. Okay.

Yes. But it is a very large surplus. Working capital surplus.

Okay. Thanks. Then the very last thing, based on the -- what your reservoir engineers have done, what is the number that we can keep in the back of our head, haven't seen other Haynesville Shale producers report reserves and we've been able to kind of back into some kind of a break even price for some of them. What about for you guys in terms of where do you reach -- what gas price allows you to reach your economic limit for a -- I know it is going to vary from well to well but I guess all-in based on what you've got in your approved reserves report, what gas price at the well-head gives you, your break even value for a well?

Well, this is Mack. Break even would be about $3.50. We like to see a $5 gas price or something close to that. To give us a reasonable rate of return on our five Bcfe EUR wells.

Thank you very much, sir.

Thank you.

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

Good morning, gentlemen.

Good morning.

Looking at the production guidance, the range you put out here, just wanted to kind of get an idea from you, what the reason for the range and is that kind of leaning more toward the transportation, how that rolls out or 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 have been putting up low double digit type sequential growth. Just kind of want to get an idea from you, how you roll that out.

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 is a number of considerations there. One is we're increasing the number of stages so the logistics in getting the work scheduled and done has changed. We're not the only operator that's doing that. And so the demand for that kind of work is going to be extremely high. So, that's 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 at a lower choke setting, 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 -- those factors that I just mentioned plus many more. And so you're 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.

I've 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.

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 so we kept that in our hip pocket for adding those reserves in Y10.

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 Y09. We felt like we could have added a lot more, the rules allowed that. We chose to be, as usual, conservative in our booking.

I've got you. Thanks a lot.

You bet.

Thank you.

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

Hi guys.

Hi, Jack.

To be in the line of one of the last ones, most of the question asked but I have a few ones. To continue on the reserve booking, it looks like you estimating 400 to 500 B's of potential booking at 2010. What kind of -- offset, factoring in that booking, potential booking. How many offset you for each producers?

Two.

Two.

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

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

Jack, I can do this. And it may or may not help you when you look at the numbers. Most of our wells are generating 30 day IPs. There are a lot of variables at 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 we're at about 75% level.

Okay. Is that tracking -- I'm trying to get on your reserve booking. It looks like conserve -- How is that tracking your EUR that you're estimating? Is it above the curve? What you're estimating?

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

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

Right now, we're at around 87 million to 88 million a day net.

And how many wells waiting to be hooked online?

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

Okay. Thanks a lot.

You bet, Jack.

Thanks.

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

Hey, guys.

Hi, Ron.

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

87.

Ok, great. Then the question just -- when you look at Toledo Bend North versus Logansport versus Mansfield and the different deliverability rates, do those -- were 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 then what's your expectation as you begin drilling in Toledo Bend South? I'm just trying to get a sense as to the breakdown.

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. We're not there yet, Ron. So, we're anticipating performance that will be very appealing. But in Toledo Bend North, we've drilled and completed 11 wells that are in the public domain. Those average -- those wells have averaged 10 million a day IP rates.

30-day average IPs are at about 80% of their initial production rates so that 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 areas - Belle Bower 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 proppant loading as well.

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 northeast portion of your Toledo Bend North field. Are you seeing things change as you move that way? And more of your activity of your -- was it 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 for you, that had a little bit better wells?

We're not prepared to put a blanket statement on the Toledo Bend North area in the northeast corner being of lesser quality. The Haynesville does change and can change quickly, in clay content and in thickness. And there can also be some splinter faults et cetera. So, we tend to, again, be a little 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're right. 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.

Okay. And then as you talk about drilling, 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. You're not concerned about that lease for the lower Haynesville?

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

Okay. And then I guess Roland, this would be for you. Based on ranges, production range and kind of your current costs and what not, my numbers -- it looks like you're between your cash on hand and cash flows should be enough to fund that $385 million budget as long as gas prices are $5.50 or so. Is that -- does that seem in the ballpark, is that kind of the way the program has been designed to -- based on that kind of price deck between your cash flow and cash on hand?

That's about correct, Ron. We looked at about -- about $5.50 for a NYMEX price. So more like a $5.25 per Mcf price realized. That would fund the program along with the cash on hand. So, that's kind of our base program and we are very comfortable with it given where the gas prices are. And like last year , we can really move the throttle forward or backwards based on kind of how we see the year play out.

I think since we're starting that kind of a lower base, it is a possibility toward the latter part of the year that we spend more. In our budget, we have about $20 million set aside for lease acquisitions. We would be happy to spend more than that if the opportunities are there to buy quality acreage. But that's kind of -- not too far off of what we spend in 2009. Just adding around leases -- leases around our existing acreage that we have

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

Well, they used to be about 84.

Less than that. I think it is -- roughly 50 Bcfe or so. Is in those other regions. Some of those reserves are probably still there but under the SEC rules, we're not going to try to claim them because we don't have those in our drilling budget.

Right.

That range is off the books, probably through reserves that were just moved to probables. So, it is roughly the same reserves that it was but just presented differently for the SEC purposes.

Is it around 50 now, Mack?

I've got about 75.

75. It used to be about 83 or 84. It is a little less now because of pricing. We hadn't spent any money there as you know in '08 or '09. We don't plan on spending any money there in 2010. So, it is a divestiture region for us.

Just trying to get a sense of the size for that reason. All right, great, guys. Thank you very much.

You bet.

In fact, if you look on the presentation slide three, we break out quote the other regions. It's at 16 million a day.

Thank you.

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

Good morning.

Good morning.

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

Sure. On the drilling side, our drilling engineers, drilling manager continued to look at the bit programs, the different vendors for the mud motors, improvements have been made that allow though the mud motors and the bits to stay in the hole longer and of course, improve rate of penetration, ROPs, that's allowed us to gain some days on our drill time curve. And of course, the costs are paired off our drill side ledger for that reason.

Improvements in completion continue. We, and other operators are looking at different perforating schemes, different levels of proppant loading. 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 it may be that 16 stages, 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 4,500 foot frac -- pardon me, lateral length with proppant 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 proppant loading. So, a long-winded answer to your question, there is a lot of variables to try and if you 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 proppant loading per stage. We're going to pump more stages with increased proppant 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.

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, maybe just looking at 2010 into 2011, do you think that the efficiency improvements will stay ahead of whatever cost inflation you might see just as it looks like we'll keep getting maybe increased rig count and increased drilling activity regionally and perhaps nationally?

That's a great question. 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. I know the vendors are working hard to improve their equipment. High pressure, high temperature environment's tough on mud motors, electronics, et cetera.

So, that's point one is that that work is on-going 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. There's also the risk component of the completions, every operator faces this when you're completing a 4,500 foot lateral, we spent a lot of time cleaning the hole so we can run our casing, for example. Well, 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 procedure in place that minimizes that risk but certainly more plugs in the hole means more things you've got to get out of the hole and so that drives up a little bit of the cost that we were talking about as well as risks. Vendors are looking at different ways to complete these wells without running plugs on wire line 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'm a market guy as perhaps most are listening to this call. If costs exceed the threshold of the operator, then you'll see the activity starting to -- start to slack up in the Haynesville until those costs come back in line to where they need to be.

Great, thanks. Just a couple more quick things. In terms of acreage, I heard you say that I think at Toledo Bend South, you're pretty much set as far as holding everything by production.

North.

North, okay, great. Can you give me an idea of roughly how much you have remaining that still has to be drilled for holding leases at this point? I know you had some acquisitions, I don't know if that changed that balance at all.

We have a time line on our leasehold. We don't publicize that obviously but we're well equipped to protect our leases with our Y10 program. We're in good shape.

Okay. And couple financial questions. GandA for the coming year, I know there was the extra $1 million charge in fourth quarter on the uncompleted deal. But is it going to be pretty close to the third quarter run rate going forward? Or do you expect to see some kickoff there as well?

No. We would probably say it is going to be roughly around $10 million a quarter. So, probably -- third quarter was the lowest of any quarter in 2009. So, if you looked at the levels, the first and second quarter, I think that would be a good way to estimate it.

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

Sure. Let me grab that for you. The interest capitalized on our unevaluated leases that were conducting drilling activities for the quarter was $2.1 million.

Okay.

That's probably a good proxy for what you would expect for for each quarter in 2010. Because now the interest is -- all our interest is under -- is fixed rate 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.

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

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

Oh, Okay. Was that as a result of a distress situation on the oil leaseholder or just land management?

No. Working all of the different opportunities around our existing acreage. We just had a lot of those close, in that quarter to allow that. A lot of those were signed up earlier in the year. You have to take due diligence to close them.

Ok, thanks a lot, guys.

We expect a similar program at a minimum this year to leasing up adjacent tracks where they're available.

Okay.

Thank you.

That's all for me. Thanks.

Thanks.

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

Good morning. Thank you. Just a couple questions that hadn't been touched on yet, I don't believe. Jay, the five Bcf EUR estimate you're giving for the Haynesville, is that for all of your acreage, the whole 73,000 including East Texas?

Yes.

What do you estimate just for North Louisiana on average?

We go anywhere from, 3.5 to 5.5. It is a blend. But what we try 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 five Bcfe is good. I know a year ago at this time, we just -- we went from four Bcfe as an EUR to five Bcfe. I always tell people that we want -- we want to be pulled across the finish line to get a six or six and a half. We're just not there internally with the results we've had or the technical people we've had for the acreage that we have. That's not to say that other acreage is not better than that. Overall, we think our acreage is probably five Bcfe as an EUR.

Okay. What were the average reserve bookings for the East Texas wells in the last report?

Not sure what -- we didn't book a lot of reserves in the East Texas Haynesville because we did not put an offset in the SEC report on those wells because of the very low gas price that we had to use.

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

Okay.

I don't think we did book any.

We didn't book any offset in those wells. They were booked as producing wells.

Okay.

So, we just booked the PDP wells for the four wells.

Are you able to say what you booked for those per well? On average?

Less than five Bcfe.

Okay. Fair enough.

Three Bcf plus or minus something is going to be our booking, That's the reason why we didn't book offsets to them. At that type of level because most of our offsets we would book at a more conservative level than the first well.

Again, we hope the other companies have better results. We're not trying to diminish their results. That's just what we did and what we booked.

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

The same for the lower.

Okay.

There's no appreciable difference.

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

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

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

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

Okay. And then are you getting any tax exemptions related to your Haynesville wells? Production tax?

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

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?

No. We have no plans at this time.

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?

Correct.

We've got maybe just a couple verticals in our budget but no Cotton Valley horizontals.

Right.

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

You bet.

Thanks, Richard.

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.

Thanks, Dan.

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

80 acres.

80 acres. Okay. Of the wells, the 57 horizontal that you will drill in 2010, how many of those will in fact, test that assumption?

We have a half a dozen well spacing test wells.

Okay. And that's 80 acres or less or just at 80 acres?

At 80.

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?

Roland, do you have that number?

I don't. You've also got to consider part of that would be the capitalized interest. That's where it shows up. So, $6.6 million of that number is just interest capitalized on the earlier expenditures, the actual new expenditures would be more than $20 million.

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, on the same side in East Texas. What's the future for that acreage?

Our Shelby County acreage is part of an AMI. We put our interest with Common and Chesapeake's and a couple of others. And we have a blended out interest in an 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 is legacy acreage. We're going to drill a couple of wells in 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.

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

Well, the commodity price would have to be extremely low for those reserves not to be added. And we're pretty much good to go all the way down to a $3, $3.50 gas price, Dan. In terms of executing this year's program just on the basis of a break even rate of return. So, we're -- I guess the shortest answer to your question is we feel pretty confident in that low number in our range.

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

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. Then as we completed those first 29 wells, and we had the production, then this year's completely different. It is based upon the footprint we have with the cost structure we have with the balance sheet we have. With offset attitude as far as reserve bookings, all based upon 80 acre spacing. We think 400 Bcfe to 500 Bcfe is probably pretty real. And if it ever changes, we would let you know.

Very good. And again, thank you, gentlemen.

Thank you, Dan.

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

Hey, Mack, I just had one more question regarding -- the days to drill it looks down significantly. Even though you're drilling more frac stages 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?

No. I think we can do better. If our department managers were in here, we would say the same thing. Consistency is what we're striving for. So, if you look at the charts, 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. If not better. So the consistency goal is what we're striving for, Ray.

I've got it. I guess just -- 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?

Well, that's a great question. There have been a lot of penetrations, obviously throughout the Bossier, or the upper Haynesville. Through our participation in 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 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 to sales. The reason for that is obvious. Most operators, us included, we want to get that lower Haynesville HBP on our leaseholds, 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 get into 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.

I've got it. And do you -- I don't want to put words 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?

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

I've got it. Thanks.

You bet.

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

Eric, again, thank you. I know it has been about an hour and a half. I would like to close and just tell you again those that are still there, our goal in 2010, while keeping our strong balance sheet intact, 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 Bcfe, 500 Bcfe is our goal but we want to do that at a low finding cost which ultimately increases shareholder value. Because that's what we're charged to do.

I think at the same time, 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 is cold outside. Get you another coat. Thank you.

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