Operator: Good day everyone, and welcome to the Southwestern Energy Company third quarter 2005 earnings conference call. At this time, I would like to turn the conference over to the President, Chairman, and CEO, Mr. Harold Korell. Please go ahead, sir.

Harold Korell: Good morning. Thank you for joining us. With me today are Richard Lane, our Executive Vice President of the E&P Company; and Greg Kerley, our Chief Financial Officer. If you've not received a copy of our third quarter press release you can call Annie at 281-618-4784 and she'll fax a copy to you.

Also I would like to point out that many of the comments during this teleconference may be regarded as forward-looking statements that involve risk factors and uncertainties that are detailed in our Securities and Exchange Commission filings. We also would warn you these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

Well, to begin with, we had a great third quarter.  Yesterday we reported earnings for the third quarter of $39.5 million, up 55% from the same period last year.  Our cash flow for the third quarter was up 37% from a year ago to $80.3 million.  Both were records, and the highest ever in the Company’s history.  

We also posted record oil and gas production of 16.2 Bcfe, which is up 8% from last year.  In addition, in September we completed an equity offering that raised approximately $580 million, allowing us to accelerate the development of our Fayetteville Shale play in Arkansas.  

We have made excellent progress in understanding the Fayetteville Shale resource, since we first announced the play a little over a year ago.  We have now drilled 67 wells in 10 different pilot areas, located in five separate counties in Arkansas.  Eighteen of these wells have been horizontal.

As we discussed in our press release yesterday, we continue to experience problems with drilling equipment in the Arkoma basin, and this is affecting our plans for the Fayetteville Shale.  We are looking forward to the delivery in November of the first of 10 new drilling rigs that we are purchasing for the play.  Over the next 12-15 months we expect to further evaluate our Fayetteville Shale acreage by testing an additional 35-40 pilots.

I would like to now turn the conference over to Richard Lane, who will expand upon our operating activities and plans for the E&P area, and then to Greg Kerley to discuss our financial results.

Richard Lane:  Thank you, Harold and good morning.  During the third quarter of 2005 we continued to expand the known productive area of our Fayetteville Shale project in Arkansas.  We also maintained our active drilling programs in East Texas, the Arkoma basin and in the Permian basin.

During the first nine months of this year, we invested a total of $323.3 million in our E&P operations, up 53% from the $210.7 million we invested in the first nine months of 2004.  Through the third quarter, we have participated in 186 wells, 155 of which are productive, seven were dry and 24 were in progress at quarter end.

Our overall success rate so far in 2005 has been 96%.  We have spud a total of 65 wells in East Texas, 33 at Ranger Anticline, 44 in the Fayetteville Shale play and 44 wells in the remainder of our active areas.

As Harold said, production for the third quarter was 16.2 Bcfe, up 8% from the 15.0 Bcfe we produced in the second quarter of this year.  Of that 16.2 Bcfe produced, 7.7 Bcfe was from East Texas, 5.1 Bcfe from our conventional Arkoma properties, 1.9 Bcfe from the Permian basin, 0.8 Bcfe from the Gulf Coast region and 0.7 Bcfe from our Fayetteville Shale.

We estimate that our third quarter production was reduced approximately 0.2 Bcfe as a result of Hurricanes Katrina and Rita.  The impact to our fourth quarter production could be approximately the same, as we continue to have outside operated wells shut-in in South Louisiana.

Moving to our Fayetteville Shale play, in the first nine months of 2005 we invested approximately $84 million, including $50.8 million to drill 44 wells and $28.1 million for leasehold.  We continue to increase our significant lease holdings in the play, and as of September 30^th we held approximately 724,000 net acres in the undeveloped play area.  And in addition, 125,000 net developed acres in the traditional Fairway area of the basin, which we hold with production.

Since beginning our drilling program in the Fayetteville Shale in 2004, we have drilled a total of 66 wells and participated in one outside-operated well.  We have now drilled in 10 separate pilot areas located in Franklin, Conway, Van Buren, Cleburne and Faulkner Counties in Arkansas.   Our two newest pilot areas are South Brownie, located five miles south of our Griffin Mountain field, and Yellowstone, located 10 miles northeast of our Cove Creek field.

We have drilled one vertical well in each of the new pilot areas.  The Yellowstone well is currently being completed and the South Brownie well is waiting on pipeline connection, after testing at approximately 811 Mcf per day.  Of the 67 wells drilled, 51 are producing, 11 are in some stage of completion or waiting on a pipeline, two are shut-in due to marginal performance or temporarily abandoned, and three have been spudded but have not yet reached total depth.

Current gross production from our Shale wells is approximately 12 Mcf per day.  To date, we have drilled 18 horizontal wells in four separate pilot areas.  Of the 18 horizontal wells, 12 have been completed, two are waiting on completion, one has been temporarily abandoned due to mechanical problems, and three are in the drilling phase.

The average initial test rate for the 12 completed horizontal wells is 2.5 Mcf/d, excluding our first horizontal wells in which problems with well bore isolation limited our treatment.  Based on early production histories and modeling, we believe the average ultimate production from these horizontal wells will be between 1.3-1.7 Bcf per well.

The most recently completed costs for the horizontal wells range from $1.4-1.8 million per well, excluding non-recurring costs.  They have taken 16 days on average to reach total depth.

One horizontal well of note is the McNew #4-2 in our Gravel Hill field.  This well was our first horizontal to be stimulated with a slick water frac.  The well is producing 1.2 Mcf/d and 70-80 barrels of water per day, after being on production for almost three weeks, with pretty low decline rates at this point. We will continue to monitor this well’s performance.

As Harold mentioned, we have encountered significant mechanical problems with our contracted Fayetteville Shale rigs.  Two rigs we had previously been utilizing have been released due to excessive downtime, impacting our well count for the third and fourth quarters.  It is pretty frustrating for us to be releasing rigs in our Shale play at this time when we want to accelerate the drilling program.  We now expect to drill a total of 60-70 wells in 2005, down from our previous estimate of 80-90 wells.  

Wells being deferred from our 2005 plan will generally be development wells as we concentrate on our drilling in new pilot areas to assess the Shale potential across our acreage position.  By year-end 2005, we expect to have drilled in seven new pilot areas, including a horizontal test in the Fairway area approximately 70 miles west of our existing horizontal wells.

As a result of the reduced 2005 well count, we anticipate our production to be approximately 2.0 Bcf from the Fayetteville Shale for the year.  Combined with the production lost due to Hurricanes Katrina and Rita, we now expect our full year 2005 production to be at, or slightly below, the lower end of our guidance given earlier of 62.0 Bcfe.

In early July, we announced that we had entered into a sales agreement with a private company to build five new land drilling rigs, capable of drilling both vertical and horizontal wells in our Fayetteville Shale play.  In late September we announced that we had entered into an agreement to purchase an additional five rigs from the same company.   These new rigs have design features that we feel are optimal for drilling in our play.  The first rig is expected to be completed in late November, and expected to spud its first well in December.  

The second rig is targeted for a late December delivery, with one additional rig delivered per month after that.  In addition to these 10 newly constructed rigs, we are working on obtaining additional rigs to work in the play.  Options we are considering include constructing additional Company-owned rigs, purchasing existing rigs and mobilizing them into the basin, and term contracts with drilling contractors to utilize newly built rigs, and “spudder” rigs to drill the vertical portion of our horizontal wells.

We are currently developing our 2006 E&P capital plan and expect a significant acceleration of Fayetteville Shale play activity.  Our preliminary plan estimates that we will invest approximately $300 million in our Fayetteville Shale play, drilling approximately 175-200 wells in 2006.

Moving to the Ranger Anticline in the Arkoma basin, as I had mentioned previously we spudded 33 wells in the Ranger Anticline areas in the first nine months of 2005.  Of these, 27 were productive, two were dry and four were still in progress at the end of the quarter.

The Ranger Anticline, located in Yell and Logan Counties, Arkansas, typically produces from the Borum sands between about 5,500 feet and 8,500 feet.  Of the 33 wells, 19 are located in the core producing area of the field, eight are located in the western expansion area we began developing last year, and six are in an eastern expansion area up to nine miles from the proven productive part of the field. The three eastern-most wells we drilled in the area penetrated pay in the Basham and Turner sands, at about 3,550 feet.   During the third quarter we completed construction of a pipeline to service these eastern extension wells, and they are currently on production.

Also in the Arkoma basin we are currently drilling a 14,200 foot Arbuckle exploration test, northeast of our Ranger anticline area.  We expect the USA #1-24 well, which we operate with a 60% working interest, to be at total depth by the end of November.

In East Texas, through the first nine months of 2005 we spudded a total of 65 wells, of which 61 were productive and four were in progress at the end of the quarter.  Of these 65 wells, 55 were in our Overton field in Smith County, Texas and 10 were in our other East Texas areas.  We continue to maintain a 100% success rate at Overton after drilling 228 wells since we acquired the field in 2000. We are currently producing approximately 100 Mcf/d from Overton.

In addition to our Overton field, we continue to be active in other areas.  At our Angelina River Trend, we now have over 12,000 net undeveloped acres in four development areas located primarily in Southern Nacogdoches County.  Since late 2004, we have drilled eight wells in this trend.  Six of these are currently on production and the remaining two are being completed.  The six producing wells have tested at an average rate of 3.4 Mcf/d.  We expect to drill more wells here by the end of the year, and additional drilling planned for 2006.

Some comments about our new ventures efforts.  In addition to our Fayetteville Shale play and our established projects, we continue to pursue additional opportunities for future investments.  During early 2005, we have leased over 48,000 net acres in the Permian Basin Barnett Shale play.  We expect our first test of this play, a re-entry of an existing well bore, early next year.

In summary, we continue to be pleased by our results in East Texas, the Ranger Anticline and our Fayetteville Shale project.  We are pursuing new project areas for the future, and our drilling plans for the remainder of 2005 and 2006 in the Fayetteville Shale play will go a long ways towards understanding the potential size of this play.  We are looking forward to strong results for the remainder of the year, and expect to achieve significant year-on-year organically driven production growth by investing in our high PVI projects.

I will now turn it over to Greg Kerley who will discuss our financial results.

Greg Kerley:  Thank you, Richard and good morning.  As Harold indicated, we reported strong results for the third quarter, primarily fuelled by our production growth and higher realized commodity prices.  Earnings for the quarter were a record $39.5 million, or $0.51 per diluted share, up 55% from the third quarter of 2004. Earnings included the net effect of a pre-tax gain of $8.7 million, or $0.07 per share, related to gains on future basis hedges that do not qualify for hedge accounting.  

Cash flow provided by operating activities before changes in operating assets and liabilities also set a new record for the third quarter at $80.3 million, up from $58.5 million for the prior year period.  Our improved operating income of the E&P business drove our record results for our net as our natural gas distribution business generated a seasonal operating loss for the third quarter.

Operating income for our E&P segment was $68.9 million for the third quarter, up 60% from $43.1 million for the same period last year.  The improvement was primarily due to the general increase in natural gas and crude oil commodity prices, combined with the growth in our production volumes.  

We realized an average gas price of $6.98 per Mcf for the third quarter of 2005, up from $5.04 for the same period last year.  Our hedging activities decreased our average gas price realized during the quarter by $0.91 per Mcf compared to a decrease to $0.45 an Mcf for the same period in 2004.

Currently, we have approximately two-thirds of our targeted gas production hedged for the fourth quarter of 2005 and full year 2006.  Our current hedge positions primarily utilizes costless collars and is detailed in our Form 10-Q that we filed yesterday.  

Lease operating expenses per unit of production were $0.51 perr Mcf equivalent in the third quarter of 2005, compared to $0.38 per Mcf for the same period in 2004.  The increase in our unit operating expenses was primarily due to the increase in compression, saltwater disposal, and gas processing costs, as well as higher oil fuel service costs in general.

Our general and administrative expenses per Mcf equivalent were $0.42 in the third quarter of 2005, up from $0.33 in the third quarter of 2004, primarily due to increased compensation costs associated with increased staffing levels.  Our full cost pool amortization rate was $1.44 per Mcf for the third quarter compared to $1.19 a year ago.  The increase is primarily due to higher finding and development costs.

Our utility systems realized a seasonal operating loss of $3.2 million in the third quarter of 2005 compared to a loss of $2.7 million for the same period of 2004.  The increase in the seasonal loss was primarily due to decreased deliveries as a result of warmer than normal temperatures in our operating area and higher operating costs and expenses.  

Operating income from our midstream services, which are comprised of our gas marketing and gathering activities, was $1.5 million during the third quarter, more than double our operating gains for the third quarter of 2004.  

Our capital investments for the first nine months of 2005 totaled $340.9 million which included $323.3 million in our E&P segment.  As we announced last month, we’ve increased our capital program for 2005 to $499.5 million which includes a portion of the commitment to purchase a total of 10 new drilling rigs for use in our Fayetteville Shale play.

During the quarter we issued approximately 9.8 million shares in a follow-on equity offering, raising approximately $580 million.  Proceeds from the offering will allow us to accelerate the development of the Fayetteville Shale play and retire $125 million in notes that are due in December of this year.  

Also, earlier this week, our Board of Directors declared a two-for-one stock split.  Additional shares will be distributed on November 17^th, 2005 to shareholders of record as of November 3^rd, 2005.  The stock split reflects the Board’s confidence that our strategy is continuing to deliver value for our shareholders.

Overall, we are very pleased with our results.  Our balance sheet is as strong as it’s ever been, and we’re well positioned to continue our growth.

That concludes my comments, and we’ll now turn back to the Operator who will explain the procedure for asking questions.

Questions and Answers

Operator:  And we’ll go to Joe Allman with RBC Capital.

Joe Allman: Hey, good morning, everybody.

Harold Korell: Good morning.

Joe Allman: On that McNew well in which you use a slickwater frac, what are the results, I know generally?  But what is that telling you about the use of slickwater fracs going forward?

Richard Lane: Well, I think you hit it on the head, Joe.  This is Richard.  It’s real early.  You know, the rate that it’s producing at and that it started at is a little bit lower than the nitrogen foam jobs.  But the decline we’re seeing here in the first few weeks of production is also lower.  

So, you know, it’s a little early to say what that all means.  We’re going to do more of them, and I believe on the next one or the third one we’ll be doing some more micro seismic work to try to image the fracture propagation’s and then we can get a look at maybe is it acting differently or not.

Joe Allman: And then, lastly, on the Barnett Shale in West Texas can you just talk about the characteristics as they compare to the, you know, Ft. Worth Barnett Shale and your Fayetteville Shale?  And what your plans there are going forward?  You’ve got 48,000 plus acres.  Are you getting some more out there if you can, or?

Richard Lane: Well, you know, the properties, the reservoir properties are not well known yet, and we’ve got to get some of that rock in our hands and do the work that needs to be done.  So, I wouldn’t try to compare them at this point.  

Our activity would be, we have an old well bore there that we want to re-enter that we think we can start getting some of that data less expensive than a whole new well bore, so that’s where we’re headed, and we’ll try to – we’re going to try to kick that off early next year.

Joe Allman: All righty.  Thanks.

Operator: We’ll go next to Brian Singer with Goldman Sachs.

Brian Singer: Good morning.  With regards to the vertical well, it’s one of your new pilots that tested at about 811 Mcf a day, could you just talk about that in context?  Can you extrapolate anything in terms of the potential horizontal performance in that area?

Richard Lane: This is Richard.  I think that test rate is kind of in the range of what we’ve seen for our vertical wells.  It seems like a good rate, nothing extraordinary there.  And so I wouldn’t really anticipate the horizontal follow-ups in that area to be different than the ranges we can give in either.

Brian Singer: Okay.  You also, you had mentioned this earlier, you reclassified a couple of wells that were previously marginal.  What did you see?  And what have you learned from that process?

Richard Lane: Well, I mean we’re just trying to keep an accurate well count here for you and make sure they’re classified right.  And what’s happened there is we had some wells that we were trying to understand the water production, and we’re doing some things on the completion side to put those wells on production.  So, that’s why they’ve moved to that category.  We’re doing some down hole work, some plunger lift work type things to kick those off and make them producers.

Harold Korell: I think that to clarify that, it’s not that we would think we’ve got great wells on those wells, but the fact is that with gas prices where they are, we’re just trying to kick them off and get them back on production.  I don’t think we’re going to produce some very high volumes.  But they are going to be producing now.  So, I mean they were an asset sitting there, and we’re going to put plunger lift in them which is basically a way of helping unload the water so you can produce some gas on them.

Brian Singer: Lastly, but to the Permian Basin, Barnett Shale, what prompted you to talk about this play?  Should we assume that you’ve got the acreage positioning that you want for now?

Richard Lane: Well, just, you know, we’ve gotten a significant amount of acreage there, and just wanted them to convey that.  I don’t think we want to get into a whole lot about our strategy going forward in terms of what we’ll be doing in terms of more accumulating of land right now.

Operator: Thank you.  We’ll move next to Ryan Zorn with Simmons & Company.

Ryan Zorn: Good morning.  First of all, could you comment on the differences in cost that you saw with the slick water well versus the nitrogen foam on the horizontal?

Richard Lane: Yes, it’s pretty similar costs from what we’ve been experiencing.  I think we’re a little bit over a half million dollars just for the slick water completion, itself.  So, you know, one of the benefits potentially is that those could be lower costs as we’re getting started here, trying some, they’re probably not going to be that way until we get more efficient about doing those, if indeed we do go that way.

Ryan Zorn: Okay, all right.  And then, Harold, I wondered if you could maybe comment after another 35 to 40 pilot areas by the end of next year, that would probably give you I think a pretty good footprint.  I just didn’t know if you could quantify for us what sort of area within the shale that might represent?  If you could give us an idea of what that means, east to west and north to south?

Harold Korell: Yes, that pretty well, you know, the plan is that we would have pilots that would have tested the bulk of the net acres that we have.  It won’t, of course, be every acre, but we would have some data points pretty well spread across the whole acreage, the area we’ve been leasing in.

Ryan Zorn: Okay, any sort of concentration or differences in approach to how you are placing those pilots?  And some of the initial ones were just close to the pipeline, just so you could test the stuff?

Harold Korell: Yes, sure, because, you know, initially we were drilling along the pipelines.  And the intent here is to get out in some of the area.  There are basically two pipelines that currently can take gas out of this area, and one more or less runs along the southern border of all of it, and the other cuts off to, on the north side to the northeast.  

And so in between those two, we haven’t drilled a lot of pilots.  And this plan will have us drilling pilots in those areas.  But in addition to that, it will also have pilots, bore areas to the west, back over in what we would call the fairway area.  And what we’re interested in there is to see how horizontal wells will perform over there, where shale tends to be thinner.

Ryan Zorn: Yes, okay.  Thank you.

Operator: We’ll go next to Amir Arif with Friedman Billings Ramsey.

Amir Arif: Hi, good morning, guys.  First question is on the – you talked about maybe adding a few more rigs here.  You provided different options that you’re looking at.  Can you tell us how many rigs you’re looking to add beyond the 10 that you are purchasing by the end of ’06?

Harold Korell: Yes, we would want to get, we’d think about getting the 12 to 15 rigs by yearend ’06.

Amir Arif: Since -- do you have an option to buy any more additional rigs beyond the 10?

Harold Korell: No.

Amir Arif: Okay.  And the second question is more just along the basic differentials that you see widening in the fourth quarter.  Can you mention what’s causing that?  And, also, the basis differential, you put in place lock you into that basis or that basis come back, or are you going to still see a dollar differential?

Greg Kerley: Amir, this is Greg.  I mean the increase in the basis, you know, really is just the difference between the NYMEX price and that location, you know, whether it’s at TexOk or Henry Hub, or a Ship Channel.  And those have been increasing, obviously, from historical levels, just like gas prices have.  I mean that’s just a fairly normal correlation.  So, as gas prices, as we see gas prices go up from current levels we’ll expect prices to widen even greater.  And we’re seeing right now basis increasing in some cases almost $1.00 to $2.00 over what it was the prior year level.

We have hedged really a good portion of our production.  For example, in the quarter probably 75% to 80% of our production is hedged.  In some areas we’ve hedged close to 90%, for example in East Texas.  We’ve locked that kind of basis in at about $0.50, and the current market approach for that is close to $2.00.  So, we are going to be, you know, have a larger percentage protected in the fourth quarter, but we’re going to see basis volatility continuing in this higher gas price environment and it’s going to be reflected in running through people’s income statements if the basis continues to widen and you have basis hedges in place, like we have, we’re benefiting from those.  If gas prices go down the basis narrows, then the reverse will happen.  

But I mean we think it’s prudent for us to be hedging the amount of basis we are, and we kind of re-implemented a program really earlier this year to kind of increase the level of basis hedging that we’ve historically done, and we’re very happy that we did that.

Harold Korell: You know, to add to that, Greg, when Greg says when you see gas prices go up or go down, you’re referring to NYMEX prices.

Greg Kerley: NYMEX prices.

Harold Korell: Because you, then the basis differential is the difference between that NYMEX price and what’s actually happening on the physical market at some particular index level.  

Amir Arif: Sounds great.  Thanks a lot, guys.

Operator: We’ll go now to Travis Anderson with Gildner, Gagnon.

Travis Anderson: Hi.

Harold Korell: Good morning.

Travis Anderson: [Inaudible.]

Harold Korell: Travis, we can barely hear you?

Travis Anderson: Oh, I’m sorry.

Harold Korell: Now, that’s – now I can hear you.

Travis Anderson: I was asking about finding the crews for these 10 rigs that you’re bringing on, and how you’re going about that?  And are you finding – training them or are you finding experienced crews you’re enlisting for other places, or how are you going to do that?

Richard Lane:  It's a good question and we're hard after that right now.  The first really key step there, I think, that we're feeling good about is hiring a management group that will run that unit for us.  And we pretty much have that in place and are pretty pleased with the quality of the people we've added.  

And so now we're on to the other levels there, if you will, that we need, which will obviously include crews for the rig.  We're actively pursuing them.  We're recruiting folks and we've got some things going on in the state to recruit locally and train.  And certainly some of the other companies are potential for that.   

Travis Anderson:  Okay, thanks.  My second question is, I saw you mentioned your stepping out to the West, where the shale is thinner.  I think you mentioned once that it gets down to about 40-50 feet out West.  If that's so, how are you going to do horizontal wells and frac them without--or does it matter that the fracs go beyond the shale?

Richard Lane:  Well, it ranges in thickness out there, you know, 50 to 75 feet where we would be starting.  And we'll just have to see how that goes.  Certainly as a thickness there's no problem with the target.  We'll be doing some reentries of other wells probably as well.  But we have some understanding of what the bed boundary effects are there and how those fracs will be contained and we'll just have to see how that goes.  We don't see a big problem with it right now.  

Operator:  Robert Christensen with Buckingham Research.  

Robert Christensen:  When are you going to spud that well South side of the Ranger Anticline?  That's question one.  Question two, on the Arbuckle test, what kind of targeted reserves are we looking at and I take it there would be other tests to follow?

Richard Lane:  I think you're talking about kind of a step-out at Ranger and the Southern part of our acreage?

Robert Christensen:  Yes.  

Richard Lane:  We were trying to get that done late this year.  It could be first quarter next year.  Then we'll just have to see how that goes.  We're doing pretty well over there on the eastern side.  And so, we will work that in probably in the next couple of quarters.  

The Arbuckle test is probably 80 to 100 Bcf type potential.  We have a pretty good size acreage block down there.  And certainly, if successful, we would hope for follow-ups.  

Robert Christensen:  Now, is this like the Deep Arbuckle that ARCO and those guys pursued in, I want to say, the mid 80s, or is it something more in between?  Is it on a horst block or something like that?  What does it look like?  

Richard Lane:  There were wells pursued significantly deeper than what we're doing here, back in that time.  Wells even as deep at 20,000 feet.  We're not that deep.  I think we're about 14,000 feet.  So, it's different and hopefully that helps you on reservoir quality and things.  But, it is kind of a horst block looking feature, as you described.  And we have good objectives on the way down to it as well.  

Robert Christensen:  Okay.  Are you happy about some of these Basham sands?  I was just looking at some of the Arkansas results and, you know, I see a well at 190 a day, in the Turner, 81 out of the Basham, 448 in the Turner, another well.  Are those wells economic?  I guess everything's economic at these prices, but are you happy with those recent wells in the East?

Richard Lane:  Yes, we are.  And we're encouraged to drill more out there.  That's why we undertook that pipeline, or the gathering project there.  I think they're going to be good economic wells.  We'll have to drill some more and see.  But, you make kind of a 0.5 a Bcf type well there for the kind of cost these shallow wells are going to be and it looks pretty good to me.  

Harold Korell:  I think sort of the happy end of the whole thing is that we drilled off there 8 or 9 miles East of the main productive field, trying to extend the Borum sands over there, trying to find the Borum productive, and we found the Borum to be tight.  So, happy is we found the Basham and Turner.  

And then as we've moved midway back to the main producing area, now we've encountered the Borum, plus we've encountered the shallower sand.  So the good thing about it is, it appears we have multiple things to be drilling for.  That's always a good thing.  

And what's that's also indicative of is that we may, throughout this area, have more than one play.  And that's always a good thing to have.  

Robert Christensen:  Sure.  One final, if I may.  The Barnett shale reentry, it sounded from your remarks that you're going to try to core the well first.  It doesn't sound like you'll try complete it.  Is that what I should understand for the first quarter?

Harold Korell:  Well the first thing is, we've got a fairly difficult reentry to do, because it's an old abandoned well.  We've got to get back into it.  We're going to make an attempt on that.  Then I'll let Richard take it from there.  

Richard Lane:  It's certainly not aimed as trying to jump right into a producer there.  The key is to start gathering the data and understanding the rock and what the best approach is, going forward.  So yes, I wouldn't look for that to be turned into a producer real quick.  

Operator:  John White with Natexis Bleichroeder.

John White:  The Permian Basin shale play, what counties are the acreage located in?

Richard Lane:  It's in Culberson County.  It's in the Delaware Basin.  

Operator:  Michael Scialla with AG Edwards.  

Michael Scialla:  A question on the Fayetteville.  I think you had mentioned that you had 3 horizontals in progress.  Should we assume you've got 3 horizontal rigs drilling in the play right now?

Richard Lane:  We have 1 well that we--I believe we used a spudder rig to get it started, so it's kind of in between.  But yes, 1 in South Rainbow and 2 in our Gravel Hill field.  

Michael Scialla:  Are any of those--I think you had mentioned that you were looking to get some refurbished rigs, so are any of those the newer vintage rigs?

Richard Lane:  No, they were not started with any of the different rigs.  No, that's part of the effort here in the remainder of the year here.  We're looking at some other options to bring some more rigs in there.  We do have a firm on one of those that's moving our way and we're looking at some other options as well.  

Michael Scialla:  Okay.  And then over in the Permian, with your Barnett play over there, what's the competition look like over there, if you can say anything on that?  And have there been any competitors drilled any wells over there?

Harold Korell:  Well, Mike, there is activity over there and I think the way that people should understand our position there, is that we would appear to be maybe on the entry--we're not the first mover, let's put it that way, in that play.  But it's something we've been studying.  

There's been quite a bit of activity, leasing, in the area.  And we wanted to get a position established, so that we had a piece of whatever is going on there.  There are others that are in there and we're not the first mover like we were in the Arkoma Basin, on this.  Richard, you may want to add to that.  

Richard Lane:  Oh, I think that's accurate.  It's our understanding, from watching the activity there, that there are not a whole lot of wells drilled yet.  And I think it's really just kind of getting kicked off there and those wells will likely be the kind of wells that happen early in these plays, which is data gathering and trying some things.  

Operator:  Robert Christensen with Buckingham Research.  

Robert Christensen:  Hi, I'm going to jump on that question.  Do you own 100% of this 48,000 acres or are you with another partner?

Richard Lane:  We do have 100% of it.  

Operator:  Travis Anderson with Gilder Gagnon Howe.  

Travis Anderson:  I know XTO has said that they have 100,000 acres or so in the Fayetteville now, and Chesapeake, I believe, had said 300,000.  XTO is piggybacking on your R&D basically.  But Chesapeake has now filed for 3 wells.  I don't know how many they've completed.  And I was wondering if there's any data that you would know, since I know you have an interest in at least one of those wells, that you could share?

Harold Korell:  We have a pretty small interest.  And I think we'll let them comment, as operator, on that activity.  I think they have their like conference next week and maybe they'll discuss that.  

Operator:  There are no further questions at this time.  I'll turn the conference back over to our speakers for any additional or closing remarks.  

Harold Korell:  Well, thank you for joining us today.  Thus far, '05 has been a very good year for us.  We've experienced significant growth in some good ways and expanded our knowledge in the Fayetteville shale.  And we look forward to the next quarter and then pushing on into '06.  Thanks.  

Operator:  That concludes today's teleconference.  Thank you all for your participation.