8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): March 1, 2005

SOUTHWESTERN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Arkansas

(State or other jurisdiction of incorporation)

1-8246	71-0205415
(Commission File Number)	(IRS Employer Identification No.)

2350 N. Sam Houston Pkwy. E., Suite 300, Houston, Texas	77032
(Address of principal executive offices)	(Zip Code)

(281) 618-4700

(Registrant's telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

       o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

EXPLANATORY NOTE

The information in this Report, including the exhibit, is being furnished pursuant to Item 7.01 of Form 8-K and General Instruction B.2 thereunder.  Such information shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

SECTION 7.  REGULATION FD.

Item 7.01 Regulation FD Disclosure.

On March 1, 2005, Southwestern Energy Company conducted a telephone conference call for investors and analysts.  The transcript is furnished herewith as Exhibit 99.1.

Exhibits.  The following exhibit is being furnished as part of this Report.

Exhibit Number	Description
99.1	Transcript from March 1, 2005 telephone conference call for investors and analysts.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	SOUTHWESTERN ENERGY COMPANY
Dated: March 2, 2005	By:	/s/    GREG D. KERLEY
	Name:	Greg D. Kerley
	Title:	Executive Vice President and
		Chief Financial Officer

EXHIBIT INDEX

Exhibit Number	Description
99.1	Transcript from March 1, 2005 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Announces Record Fourth Quarter and Year-End 2004 Results

Teleconference

Participants:

C: Harold Korell; Southwestern Energy Co.; President, Chairman, and CEO

C: Richard Lane; Southwestern Energy Co.; EVP, E&P Operation

C: Greg Kerley; Southwestern Energy Co.; CFO

P: Ken Beer; Johnson Rice; Analyst

P: Amir Arif; Friedman, Billings, Ramsey; Analyst

P: Michael Bodino; Sterne, Agee & Leach; Analyst

P: Shawn Reynolds; VanEck Global; Analyst

P: Bob Christensen; Buckingham Research; Analyst

P: Joe Allman; RBC Capital Markets; Analyst

P: Peter Vig; RoundRock Capital Partners; Analyst

P: David Heikkinen; Hibernia Southcoast Capital; Analyst

Harold Korell: Good morning, and thank you for joining us. With me today are Richard Lane, our Executive VP of our Exploration and Production Company, and Greg Kerley, our Chief Financial Officer.

If you've not received a copy of the press release we announced yesterday regarding our 2004 financial results, 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 that 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 assumption, they are not guarantees of future performance, and actual results or developments may differ materially.

Well, 2004 marked another record year for our Company, as we set new highs in our financial results and impressive marks in all the important operational statistics. We set new records again for annual production volumes, reserve replacement, and year-end reserve levels thanks to our team of creative people and our discipline of adding value for each dollar that we invest.

Our financial results were outstanding as well as we delivered new records for earnings and cash flow due to our increased production and higher commodity prices.

Looking forward to 2005, we plan to invest up to $339 million in our E&P program, an increase of 20 percent over our E&P capital in 2004.

In East Texas, we plan to continue our high level of drilling activity at Overton by drilling 80 wells or so there.

In our conventional Arkoma Basin drilling program, we'll increase the number of wells drilled to around 86, up from 70 wells drilled during 2004.

Specifically, we will be accelerating our activity at the Ranger Anticline, where we plan to double the number of wells we drilled last year.

In our Fayetteville Shale play, we increased our leasehold position to approximately 557,000 net acres in the undeveloped play area by year-end 2004. In addition, we controlled approximately 125,000 net developed acres in the traditional Fairway area of the Basin that is held by conventional production.

As of February 28, we have drilled a total of 31 wells and participated in 1 outside operated well. These were all vertical wells located in 6 separate pilot areas in Franklin, Conway, Van Buren, and Faulkner counties in Arkansas. Of the 32 wells, 13 are on production, 7 are in the process of completion or waiting on pipeline hookup, 9 are scheduled to be completed, and 3 were shut in due to marginal performance.

Based on the average vertical well results to date and using current well costs in our current forecast for the future performance of these wells, we believe that a vertical well drilling program is economically feasible in the pilot areas drilled to date.

While the results we are reporting are of a short-term nature and not based on extended production histories, we continue to be excited about the potential of the play. We're learning more with each well we drill and have made improvements in lowering our drilling and completion costs. Additionally, we are drilling our first horizontal well in the play, and we'll be assessing its potential to further improve the economic results.

In 2005, we expect to allocate up to $100 million of our E&P capital to our Fayetteville Shale play. The Company's drilling program with respect to the shale play is very flexible and will be impacted by a number of factors, including the results of our horizontal drilling efforts, our ability to determine the most effective and economic fracture stimulation, and the gas commodity price environment.

In summary, we're proud of our results in 2004, and it looks like 2005 is shaking up to be another -- shaping up to be another record year.

I'll now turn the teleconference over to Richard Lane, who will tell you more about our E&P results in 2004 and our plan for '05, then to Greg Kerley to discuss our financial results, and then answer your questions.

Richard Lane: Thank you, and good morning.

As Harold said, we set new records for our annual production, reserve replacement, and year-end reserves in 2004. Gas and oil production totaled 54.1 Bcfe, up 31 percent from 41.2 Bcfe in 2003. The increase in 2004 production resulted primarily from the continued development of our Overton Field in East Texas, our Ranger Field in the Arkoma Basin, and increased production from our River Ridge discovery in New Mexico.

Production for the fourth quarter of 2004 was 15.1 Bcfe, up 35 percent from the 11.2 Bcfe we produced in the fourth quarter of '03.

Of the 15.1 Bcfe of the fourth quarter production, 6.3 was from East Texas, 5.4 from the Arkoma Basin, 2.2 from the Permian Basin, and 1.2 from the Gulf Coast region.

The 15.1 Bcfe produced during the fourth quarter included the effects of curtailment of production at our Overton Field in East Texas, which were caused by the failure of transmission line into which we deliver a large portion of our gas production. The current lack of full sales capacity at Overton Field due to continued disruptions during the first quarter of 2005 will likely cause our production to be approximately 1 Bcfe less than our previously estimated first quarter production guidance of 14.5 to 15 Bcfe.

Current estimates for the first quarter production are between 13.5 and 14.0 Bcfe, while our previously announced full-year guidance of 61 to 63 Bcfe remains the same.

We ended 2004 with 645.5 Bcfe of total proved oil and gas reserves, which is up 28 percent from 503 Bcfe at year-end 2003.

In 2004, we added 204.1 Bcfe from extensions in discoveries and 5.8 Bcfe from the acquisition of additional interest in our Permian Basin River Ridge Field.

Total downward revisions for the Company were 12.7 Bcfe.

Of the 645.5 Bcfe of year-end 2004 reserves, 299 Bcfe were in East Texas, 239.5 Bcfe in the Arkoma Basin, 7.5 Bcfe in the Fayetteville Shale, 60.8 Bcfe in the Permian Basin, and 38.6 Bcfe in the Gulf Coast region.

Including the effect of revisions, we replaced 365 percent of our 2004 production at a finding and development cost of $1.43 per Mcfe. Proved developed reserves accounted for approximately 83 percent of our total, and our reserve life index was 11.9 years.

In 2004, we invested $282 million in our Exploration and Production program and participated in drilling 204 wells, which compares to 139 wells in 2003. Of the 204 wells, 166 were successful, 14 were dry, and 24 were still in progress at year-end, giving us an overall success rate of 92 percent. Approximately 81 percent of the $282 million invested in 2004 was in drilling.

In 2004, we invested approximately $28 million in our Fayetteville Shale play, including $11.6 million for drilling 21 wells, bringing our total investment in the play to $38.9 million. Total proved gas reserves booked in the play at year-end 2004 were 7.5 Bcf from a total of 20 wells, 10 of which were classified as proved, undeveloped locations for an average gross estimate ultimate recovery per well of 430 million cubic feet.

As Harold mentioned, as of the end of February, Southwestern had drilled a total of 31 wells and participated in 1 outside operated well in the Fayetteville Shale play. These vertical wells are in 6 separate pilot areas located in Franklin, Conway, Van Buren, and Faulkner counties in Arkansas. Of the 32 wells, 13 are on production, 9 are in the process of completion or waiting on pipeline hook-up, 7 are scheduled to be completed, and 3 were shut in due to marginal performance.

Excluding the 3 shut-in wells, the first 30-day production average from the producing wells was 375 Mcf per day. Recent costs to drill incomplete wells in the play utilizing nitrogen foam fracture stimulation treatments ranged from 400,000 to 550,000 per well.

Based on the average vertical well results to date, current well costs, and our current forecasts for the future performance of these wells, we believe that a vertical well drilling program is economically feasible in the pilot areas drilled to date.

We anticipate drilling approximately 16 total wells during the first quarter of 2005, including 2 horizontal wells, the first of which is currently drilling. This first horizontal well is designed to drill a 2,000-foot lateral section in the Fayetteville Shale and utilize multi-stage nitrogen foam fracture stimulation technology in its completion.

Moving to the conventional side of our Arkoma Basin, in 2004, we invested approximately $53 million in our conventional program, drilling 70 wells, of which 55 were successful and 6 were in progress at year-end. We added 47.9 Bcfe approved reserves, including revisions, and our 2004 production for the Arkoma Basin is 6 percent greater than the 8.9 Bcf we produced in 2003.

In 2004, we further increased our drilling activity at our Ranger Anticline project in Yell and Logan counties, Arkansas. We successfully completed 20 out of 22 wells at Ranger in 2004, adding 29.8 Bcf in new reserves at a finding and development cost of 82 cents per Mcfe which includes revisions.

Since early 2004, we have extended the productive area of the Ranger Anticline area to both the east and west of our core producing area. The Albright No. 1-7, which we operate with an 83-percent working interest, is located in the Western portion of the Ranger Anticline and is currently producing 4.1 million cubic feet per day. Since being put on production in May of 2004, this well has already produced a total of 1.3 Bcfe.

In the first quarter of this year, we drilled a Standridge #1-10 well located to the east of our core producing area. The Borum sands, which are the main producing horizon at Ranger were tight in this well; however, the Standridge well did penetrate approximately 150 feet of gas pay in the Basham and Turner sands at about 3,500 feet, which is shallower. This well is currently waiting on pipeline connection. We plan to drill additional offsetting wells in 2005 to determine the extent of this Basham pay zone as well as to continue testing the deeper Borum sands.

Since drilling our first successful well at Ranger in 1997, we have successfully drilled 43 out of 50 wells, adding approximately 63 net Bcf of reserves at a finding cost of 72 cents per Mcf.

At December 31, '04, gross production from the field was 23.4 million cubic feet per day compared to 7.6 million cubic feet per day at year-end '03.

Our average working interest in the 43 wells is 81 percent, and our average net revenue interest is 66 percent.

As of year-end, we held approximately 7,700 gross developed acres and 43,500 gross undeveloped acres in that play.

In 2005, we plan to invest approximately $59.3 million in our conventional Arkoma program to drill approximately 86 wells, 43 of which are planned at Ranger, and to perform approximately 30 workover projects.

In East Texas in 2004, we invested approximately $156.7 million drilling 92 wells, of which 84 were successful and 8 were in progress at year-end. Of this, $148 million was invested in our Overton Field, where we drilled and completed 83 wells. We added 125 Bcfe of proved reserves, including revisions, in East Texas. Our 2004 production of 22.2 Bcfe from East Texas was 63 percent greater than the 13.6 Bcfe we produced in 2003.

The development drilling program at our Overton Field, which is in Smith County, Texas, continues to be very successful. We have experienced a 100-percent success rate at Overton since we began our development program in 2001.

The average estimated ultimate recovery of gas and oil reserves from new wells completed in 2004 was approximately 2.0 gross Bcfe per well, compared to 2.2 Bcfe in 2003.

Daily gross production capacity at the Overton Field has increased from approximately 2 million cubic feet in March of 2001 to approximately 90 million cubic feet per day at year-end 2004, resulting in net production of 21.8 Bcf during 2004, compared to 13.6 in 2003 and 5.9 in 2002.

As mentioned earlier, our production at Overton is currently being curtailed due to the failure of our transmission line into which a large part of Overton Field's gas sales are made. A leak in this pipeline was discovered on November 24 of 2004.

Since this time, the operator's line has been working on repairs and performing conformation inspections, and seeking approval of the Department of Transportation to return it to its normal operating pressure. And we currently estimate that this will occur in late March.

In addition to our Overton Field activity, we recently completed the test well on our Black Bayou prospect, located in Nacogdoches County. The Reavley #1, which we operate with a 40 percent working interest is completed in the Travis Peak at approximately 11,000 feet, and this well potentialed 4.4 million cubic feet per day in early February of 2005. We anticipate drilling up to four more wells in that area this year.

In 2005 Southwestern plans to invest approximately $147.6 million in East Texas to drill approximately 96 wells, of which approximately 80 wells are planned at Overton.

In the Permian in 2004, we invested $27 million, drilling 14 wells of which 8 were successful and 3 were in progress at yearend. We added approximately 13 Bcfe of proved reserves including revisions. Our 2004 production from the Permian Basin was 69 percent greater than the 4.2 we produced in 2003, mainly due to increased production from our River Ridge discovery.

The River Ridge discovery in which Southwestern holds a 50 percent working interest is located in Lea County, New Mexico, and produces from the Devonian formation at about 14,600 feet. After the River Ridge discovery well, which was in the end of 2003, we drilled four additional wells in the field, all of which are producers.

Cumulative net production from the field through the end of '04 was 3.2 Bcfe. Total remaining net proved reserves at year-end was approximately 11 Bcfe, bringing our overall finding and development costs in the field to $1.64 per Mcfe including reserve revisions. Current gross daily production from the River Ridge field is about 23 million cubic feet equivalent per day.

In 2005 we plan to invest approximately $4.8 million in our Permian Basin program to drill approximately 12 exploration and exploitation wells.

Moving to the Gulf Coast, in 2004 we invested $15.7 million drilling 7 wells, of which 4 were successful, and 1 was in progress at yearend. We added 3.7 Bcfe of proved reserves including revisions, replacing 80 percent of the 4.6 Bcfe we produced in 2004. Our 2004 production from the Gulf Coast was essentially flat to the 4.5 Bcfe we produced in 2003.

In December of '04, we put our Rosebank discovery in Lafourche Parish on production at a rate of 3.5 million cubic feet per day, and it is currently producing at about 4 million cubic feet per day. We hold the 50 percent working interest in this discovery, which is two miles west of our earlier Coleburn discovery. The Coleburn well is currently producing 3.2 million cubic feet per day, after being put on production in December of 2003.

As we have discussed previously, our recent drilling activities in the Gulf Coast are not meeting our economic criteria. Because of this, we continue to reduce our planned investment there, with only $4.8 million planned for '05. We plan to drill up to 8 wells in the area, and the majority of these wells will be developmental in nature.

On the exploration of new ventures front, along with our Fayetteville Shale play and our ongoing East Texas, and Arkoma Basin drilling programs, we continue to develop new prospects for future development. In 2004, we acquired approximately 47,000 net undeveloped acres outside of our four areas, associated with other conventional and unconventional natural gas and oil plays we are pursuing. In 2005, we plan to invest approximately $18 million in exploration projects and $4.2 million in new venture projects, including drilling up to 14 wells in the Continental U.S.

In summary, our program is performing well, delivering significant growth in production and reserves, while achieving our investment return target of 1.3 PVI or greater. We are continuing to develop and grow our drilling inventory with potentially significant value adding opportunities.

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, 2004 was an exceptional year for Southwestern. We ended the year with record fourth quarter earnings of $32.9 million or $0.88 per share, compared to $14.9 million or $0.41 per share for the same period in 2003.

Our net cash provided by our operating activities before changes in operating assets and liabilities was $72.4 million during the fourth quarter of 2004, up 94 percent from $37.4 million in the fourth quarter of 2003. A 35 percent increase in our quarterly production and higher realized commodity prices led to our improved results.

For the full year of 2004 we reported record net income of $103.6 million or $2.80 a share, up 112 percent from $48.9 million or $1.43 per share in 2003. Net cash provided by our operating activities before changes in our operating assets and liabilities also set a new record at $237.7 million in 2004, up 80 percent from $132.3 million in 2003.

Operating income for our E&P segment was $164.6 million in 2004, compared to $84.7 million for the same period in 2003. Including the affect of our hedges we realized an average gas price of $5.21 per Mcf in 2004, up from $4.20 a year ago.

We saw our locational price differentials for our natural gas production widen substantially in our core operating areas during the fourth quarter of 2004, lowering our gas revenues by approximately $5.9 million, and negatively affecting our earnings for the fourth quarter by approximately $0.10 per share.

Disregarding the impact of hedges, the Company's average price received for its gas production during the fourth quarter of 2004 was approximately $0.62 per Mcf lower than average NYMEX spot prices, compared to an historical average of approximately $0.20 per Mcf.

We had about 45 percent of our basis differentials protected in the fourth quarter of 2004, and have approximately 75 to 80 percent of our bases differentials protected in the first quarter of 2005.

We currently expect our average realized market differentials to be approximately $0.30 to $0.50 per Mcf lower than average NYMEX spot market prices for the full year of 2005, and we're currently estimating that our market differentials for the first quarter will range between $0.50 and $0.60 per Mcf.

Our average realized oil price in 2004 was $31.47 per barrel, compared to an average price of $26.72 per barrel in 2003. Disregarding the impact of hedges, we would expect the average price received for our oil production to be approximately $1.25 a barrel lower than average spot market prices.

Going forward, approximately 70 to 80 percent of our targeted gas production and 60 to 70 percent of our targeted oil production is hedged in 2005. Our hedge position for our 2005 production is unchanged from the detail included in our third quarter form 10-Q.

Our E&P segment continues to benefit from some of the lowest operating costs in the industry. These operating expenses per a unit of production were $0.38 per Mcf equivalent in 2004, down from $0.39 in 2003, as the affect of the increase in our production volumes more than offset rising oil field service costs.

Taxes other than income taxes per Mcf equivalent were $0.28 in 2004, compared to $0.22 in 2003. The increase in 2004 was due to increased severance and ad valorem taxes that primarily resulted from higher commodity prices.

Our general and administrative expenses per Mcfe were $0.36 in 2004, down from $0.41 cents per Mcf equivalent in 2003. The unit decrease was primarily due to the affect of the increase in our production volumes, partially offset by increases in our general and administrative expenses. Our full cost pool amortization rate averaged $1.20 per Mcf in 2004, compared to $1.17 in 2003.

Operating income for the utility was $8.5 million in 2004, up 26 percent from $6.8 million last year. The increase resulted primarily from the affects of a $4.1 million annual rate increase implemented in October of 2003, partially offset by increased operating costs and expenses, and reduced usage per customer due to customer conservation brought about by high gas prices and warmer than normal weather. Weather during 2004 and utility services territory was 10 percent warmer than normal and 9 percent warmer than in 2003.

Despite the improvement in utilities operating income our analyses indicate that current revenues in our utility segment are not sufficient to cover the costs for providing utility service and earned a rate of return authorized by the Arkansas Public Service Commission. On December 29^th, 2004, we filed a request with the Arkansas Public Service Commission for an adjustment in the utilities rate totaling $9.7 million or 5.2 percent annually. The Public Service Commissions has 10 months to review the filing and reach a decision. Any rate increase allowed would likely to be implemented in the fourth quarter of 2005.

Operating income from our natural gas marketing activities was $3.2 million in 2004, up from $2.6 million in 2003. We also recorded a pretax loss related to our investment in the Ozark Gas Transmission System of $400,000 in 2004, compared to pretax income of $1.1 million in 2003. The pretax loss in 2004 was due to a negative adjustment from the operator of the pipeline for prior period allocations of income and expenses.

In 2004 and 2003 our other revenues included gains of $5.8 million and $3.0 million, respectively, related to the sales of undeveloped real estate and certain property and equipment. Other revenues also included pretax gains of $4.5 million in 2004, and $3.1 million in 2003, related to the sale of gas and storage inventory.

Our capital expenditures for 2004 totaled $295 million, including $282 million invested in our E&P operation, $7.3 million for gas distribution system improvements, and $5.7 million for general corporate purposes.

Of the $282 million invested in our exploration production operations, approximately $20.1 million was invested in exploratory drilling, $208.7 million in development drilling and workovers, $21.1 million for leasehold acquisition and seismic expenditures, $14.2 million for producing property acquisitions, and $17.9 million in capitalized interest and expenses, and other technology related expenditures.

Our financial position and liquidity both improved during 2004. Our strong earnings helped us to decrease our total debt to capitalization ratio to 42 percent at December 31^st, 2004, compared to 45 percent at the prior yearend. And in January of this year, we amended our $300 million unsecured revolving credit facility that was due to expire in January of 2007. We increased the borrowing capacity and the facility to $500 million and extended the expiration to January of 2010. The interest rate on the

new facility is currently 125 basis points over LIBOR. And as of February 28^th we had approximately $420 million of available capacity under this revolving credit facility.

Our capital investments for 2005 are planned to be up to $352.7 million, consisting of up to $339 million for exploration and production, $10.4 million for gas distribution system improvements, and $3.3 million for general purposes. Our capital program is expected to be funded through cash flow from operations and our revolving credit facility. Despite plan borrowings under our credit facility we expect our debt to capitalization ratio to remain at or below its current level during 2005.

As Richard indicated, we are targeting 2005 oil and gas production of 61 to 63 Bcf equivalent. Assuming NYMEX commodity prices of $6 per Mcf of gas and $36 per barrel of oil in 2005 we are targeting net income of between $112 million and $114 million, and net cash provided by our operating activities before changes in operating assets and liability of $265 to $270 million in 2005.

Yesterday, we announced that our Board of Directors has approved a two for one stock split, subject to shareholder approval of an increase in our authorized shares of common stock at our annual shareholders' meeting on May 11^th, 2005. We will be proposing an increase from 75 million shares to 250 million shares and we currently have approximately 36.5 million shares of common stock outstanding. The stock split reflects the Board's confidence that our strategy is continuing to delivery value for our shareholders.

That concludes my comments. I will now turn back to the operator, who will explain the procedure for asking questions.

Questions and Answers

Ken Beer: Hello, gentlemen. Really a question more for Harold and Richard, in terms of the Fayetteville. Of the 31 wells, have any been actually drilled? Are any of the pilot areas within the Fairway, within the original held by production fairways?

Harold Korell: Yes, they're basically, of the five pilot areas, one of those pilot areas we talk about being over in the Fairway area and we've built two wells there that are on production. In fact, I think those two wells have been on production longer than any of the other wells.

Ken Beer: And that leads to my second question. And that is, if you look at what you are modeling as a typical well, which obviously it's too early to get a sense of confidence, but now you've got 31 data points at least to start to play with. As you model that out, what is the production profile look like? What kind of decline curve do you see in year one, two, three, four? And then where does it start to flatten out? Have you modeled that when you come up with your roughly 0.4 or 0.5 Bcf per well?

Harold Korell: Yes, we have. Basically we have a hyperbolic decline. And I'll let Richard describe that.

Richard Lane: Well, the data set, Ken, the 31 we're talking about are drilled. So when we're talking about being able to model production, of course we're talking about a smaller subset, less than half of that. And then when you look at those, they have varying amounts of time on production. So the data set is still small. And if you look at the decline, and again, with not a lot of production life it's a little hard to do. But the first year declines, the best way we could model them right now would be about 70 percent decline. And then it certainly, like Harold said, it's hyperbolic. So you really have to understand the full nature of the early time life of that curve.

But then our best guess is that they get flatter out into future years. So, everybody likes to try to compare it to the Barnett. If you compare it to the Barnett, our best guess right now is that it's a little more decline in the first year and then maybe flatter in the second year.

Harold Korell: I think, just to add to that, it would be unfair to say that you would start from an IP and then do 73 percent in the first year and that would be there. But the actual declines that we're seeing are very steep in the early part of the production data that we have. We have -- I don't know the full histogram on -- we have 10 wells that we reported the 375. We have some wells that have been on line longer than that. Our longest well has been on probably close to 200 days now.

But we see pretty steep -- real steep declines in the first month or two and then it's beginning to flatten. And they're hyperbolic. I guess probably to simplify all this we need to spend some time to be able to describe to those people that can do the math on hyperbolic, what the factors are in those and we need to probably do that over some period of time here.

Ken Beer: Okay. What about the well that was coming on that had an IP, I think, just north of 1 million a day, what's that decline curve look like or where is that doing?

Harold Korell: That well is not on production at this point in time. It's in one of the newer pilot areas and we have been -- a couple of things there. We've been continuing to solidify our position there, but we haven't got it on production. We'll be hooking up the equipment on that and it'll probably be coming on some time in April.

Ken Beer: Okay. And then last question, then I'll hop off. Just in terms of, you know, your program is another step up from last year, you've got a lot going on, you've got a lot of good areas to operate in. What's your view on what has happened to either availability and/or cost and quality of rigs and crews? Or do you feel like you've got enough of a focus area where you've maybe avoided some of the pitfalls of the service companies being stretched pretty thin?

Harold Korell: Well, I guess just the big picture of it in our core area is the Arkoma Basin conventional activities, the East Texas we're pretty well set there. We've had working relationships with various of the vendors that are in place and will support those ongoing programs. To this point in time we have not encountered difficulties in our Fayetteville Shale, which would be one of the areas that would be growing in activity levels. And we're still finding equipment there to serve the pace of activity that we've been wanting to carry on there.

Amir Arif: Good morning, guys, a couple of last questions for you here. In terms of the horizontal well that you're drilling, can you give us a sense of timing in terms of when you'd have that drilled and when those results would be available?

Richard Lane: We're currently drilling it, as we stated. I would think we would be at TD sometime in the next couple of weeks. A little harder to say, because that is the first one we're doing. And then probably another 30 days after that, looking at starting to test it.

Harold Korell: I guess, Richard, just a little color on that. It'd be fine to say that we've drilled the turn and we're basically trying to bend the horizontal part right now. So far it's gone pretty well, the drilling to this point in time.

Amir Arif: Okay. And then with the horizontal well and the additional 10 wells that you drilled relative to your last release, can you just give us a little more color on the geology you're seeing? Are you still seeing a lot of variability because of thicknesses and this geology?

Richard Lane: Well, we are still seeing some geologic variability. The overall thickness of the shale that we're seeing is more predictable. I think for the most part the new wells are coming in with about the thickness that we prognosed for them. So, that's a little bit more predictable. But we are seeing some geologic variability with some faulting and in the performance of the wells, which is kind of built into the average day that we have there.

And we're still trying to learn what -- when we have the log on one of these wells, what does it really mean and what can we discern from those logs and start to understand. And we're doing that by calibrating where we've taken whole cores and side wall cores and trying to cross plot that with the log data, so that when we have a log we can better understand what it means.

Amir Arif: Okay. And then the outside operated well that you participated in the shale play, can you give us any more information on that?

Richard Lane: Well, the operator is Yale, which is a small independent in the basin. We have about 40 to 45 percent working interest. They're operating and proposed the well to us and we participated. It kind of provides a little bit of kind of a new pilot for us, because it is not right in with our current pilot area. And that well is waiting on completion, I believe.

Amir Arif: And just moving away from the shale play here. The transmission lines failure, you mentioned it would be fixed here or back up and running by the end of March. But is there any risk that this would affect Q2 volumes?

Richard Lane: Well, it's in the hands of the pipeline operators, so I guess you would say there was always some risk there. The repairs are actually finished, just to kind of clarify that a little. The repairs are finished. And that line is subject to regulation by the DOT. And really the holdup right now is getting clearance on the DOT to bring it up to its former operating pressure. So we're also doing some other things with other gatherers in the area right now. We have some other projects going on that would increase capacity for Overton Field, so we should be okay. But it's not totally in our hands, Amir, and there is some risk there.

Amir Arif: I understand. One final question; The average of the differential that's widening, can you point us to which areas you're really seeing that pressure in terms of the differential?

Greg Kerley: We really saw the basis widening affect all of our operating areas. In the Arkoma Basin, in fact, it was between 50 cents and 75 cents wider than our historical averages. December was really the worst month and basis widened in the Arkoma to a little over 80 cents, East Texas about 85 cents, and our differential in the Permian was about $1.45. So, all of those were up and the smallest increment from November, was 30 cents and the largest was about 75 cents higher than what the differential had been as recently as November.

Amir Arif: Okay. And Greg, while I've got you on the phone here, just to clarify, did you say the average differential is going to be 30 to 50 cents in Q1?

Greg Kerley: We expect, for calendar 2005, it to be 30 to 50 cents lower than the average NIMEX spot market price and our first quarter estimate is that it will range between 50 and 60 cents per Mcf.

Amir Arif: And are we actively hedging this or is this just your expectation of where you think it's going?

Greg Kerley: Well, we have actively hedged our first quarter of this year to where we have 75 to 80 percent of our basis protected and we are actively hedging in the out-months also.

Michael Bodino: Thank you. I have a handful of questions myself. First of all, non-operating well in the Fayetteville Shale, did the operator do anything different on the drilling or completion of the well?

Richard Lane: It's a vertical well, so nothing really greatly different in the drilling part, that I know of. And the completion we haven't started on that yet.

Michael Bodino: Okay. With 16 wells being projected in the first quarter of '05, can you still get to the 160 to 170 well target in the Fayetteville Shale in '05?

Harold Korell: I think that, what we said earlier is that we would invest the $100 million approximately, up to $100 million and drill up to 160 wells. And I think we'll just have to see how that goes.

We're trying some horizontal wells. We've never really spelled out how many would be horizontal and how many would be vertical. We'd like to kind of keep our options open there and see what kind of results we're getting from the horizontal wells. And the effect of all that, if we can create better returns on those, then certainly we would want to move towards that. So that would affect the overall number of wells.

Michael Bodino: Richard, as you get into the optimal drilling program and we quit taking this full suite of logs and you start moving forward with the development program here, how many wells per quarter per rig can you drill?

Richard Lane: It would depend on the area that we're drilling, because of the depth differences. It would depend on the vertical versus horizontal. I think if you looked at the verticals, on the shallow area we can probably do a well every 10 days to two weeks. That would be kind of the quickest.

Michael Bodino: Okay, and the deeper area?

Richard Lane: I would have to look at that for a full quarter, Mike. I don't have that in front of me.

Michael Bodino: Okay. On the horizontal well, do you have an estimated AFE for that well?

Richard Lane: Yes, we do. We think it's probably -- the first well we have engineered kind of in a conservative manner, to make sure that we do get a lateral section of the shale drilled. And we're about $1.6 million, I believe, for that well is our estimate.

Michael Bodino: Okay. And my last question. One of the new venture areas in Nacogdoches

County, the Travis Peak well, is there any other opportunities? Is this purely a Travis Peak development or is there some opportunities in Cotton Valley or Cotton Valley Lime as you move over to Nacogdoches County?

Richard Lane: There is some Cotton Valley production over there. Primarily we're interested in the Travis Peak there. But it wouldn't be out of the ordinary for there to be some secondary Cotton Valley.

Harold Korell: Hey, Mike, I just wanted to kind of summarize this number of wells one could anticipate here in the Fayetteville Shale. The words that I have used to describe our activity here would be that it would be flexible. And the words we've used to describe it in each of our press releases has been up to 160 to 170 wells. And I think Richard covered that.

But I want you to understand that clearly, if horizontal wells give us a better PVI than vertical wells, we could wind up doing significant less wells here than 160 to 170. And we're going to react to what the data is showing us, and to how the wells, which kind of wells are performing which way, and what we find as we drill in new areas.

So our program, although we've said we could drill up to 160 to 170, we've also -- the up to is an important part of that statement. And somehow most people kind of pass by that. But there can be a lot of flexibility in the number of wells we drill here this year. And, as well, the up to $100m implies some flexibility in the amount of capital that we could put in here.

Richard Lane: I think maybe to give you a little more, in our shallowest areas Mike, we're drilling some of those wells in 3-4 days. And then in a deeper area, depending on if we have problems or not, those are more like 7 or 8 day wells. So - and that's coming down as we go.

Shawn Reynolds: Good morning guys. I just wondered if you could elaborate a little bit about why your gas realizations, or I guess your differentials, are blowing out. I know it's not unique to you. But I was wondering if you could add a little color to that.

Greg Kerley: Well, our basis widened primarily in November and December, due to the market dynamics that existed. It created a wider spread between the cash prices in all of our operating areas, and the closing price on NYMEX, which in both of those months was quite close to $8 per Mcf.

So the difference between the cash prices and the market prices jumped about $0.50 to $0.75 per Mcf from historical averages. It's not something that we're the only company that experienced it. I mean our peers in all of our core operating areas had those issues. And I think most of the continental United States did this winter. Basis differentials in 2003 were quite a bit lower than what we experienced, beginning towards the first part of 2004. And they stayed wider than historical all of 2004. And they are, so far in 2005, also.

Shawn Reynolds: You don't see any reason for that to reverse back to historical averages?

Greg Kerley: It's too hard for us to say. We typically see them moving back down a little bit in the summer months, and typically the highest in the winter months. So we're hopeful that they will return to historical levelss. When the NYMEX price spikes, the basis widens. That's just a typical event.

Harold Korell: So you're really talking about two moving -- two parts that are moving. One is what's happening in the NYMEX, in the marketplace, in financial markets. And the other is what's happening in the physical markets.

Shawn Reynolds: Okay. Thanks. The other question I had was; you made the comment that a vertical well drilling program is economically feasible. Do you have an idea of how many well locations that would entail at this point?

Harold Korell: Well, we've drilled in five pilot areas, and six pilot areas now with the outside operated wells. And we can clearly drill more locations there. We can drill more vertical wells there. We haven't seen -- I guess I would say we haven't seen the limit. I mean I don't know the limit, the upper limit by any means within those areas. We will just, in those current pilot areas, we'll continue drilling.

And then those pilot areas that we've drilled in represent a very small percentage of the total acreage, of course, that we have. And throughout this year, we will be drilling an additional five other areas. We're still leasing acreage right now. And we've been reluctant to step out and spot another well somewhere, because each time that we do, we get people coming in to try to pick up bits and pieces of acreage. So we're still consolidating our position across the areas we haven't drilled in.

And then at the end of the day, the answer to your question comes down to drainage areas. And we are a long ways from knowing all the answers on that. But obviously it could be a lot of wells.

Shawn Reynolds: Just sticking to the pilot areas only, I mean do you have an idea of how many locations that would be, if you just kind of drilled?

Harold Korell: You know, I really don't have. And here is the reason why. If you just think about this, from day one. We drilled one well, let's say in a pilot area. And then we drilled another well a mile away. And then we drilled another well a mile away.

So what happens is, around each one of those wells, depending on how they're spaced, you just get multiples. You start doing the math, and you get some big multiples. And there is nothing that, when we say a pilot area, there is nothing that limits that, if you understand what I mean. There is nothing that limits the aerial extent of it, because we've drilled there. But we can just continue to drill outward from there, until we either don't find the shale, or we find some limiting factors.

And here is the interesting thing. Each one of the places we've drilled, we've encountered gas. And we are producing gas. So it's not like that there is shale, but there is no gas in it. Each one of the places we've drilled, there is a thickness of shale that's mappable. And it has gas in it. It produces gas.

So, what our job is, of course, is to get on with development in a reasonable fashion. And we're trying to be prudent with our capital, figure out the way to get the highest return in each one of these areas.

Shawn Reynolds: Great. Thanks a lot.

Bob Christensen: Yeah. The question is; you say you're going to react to the data. There's two ways to read that, based on your earlier comments. One is we're slowing down, to 16 wells from 25 in the first quarter. On the other hand, you've got this horizontal well going down. And maybe you're so encouraged by that, you're going to get by with fewer wells. I mean how would you guide me? Glass half full? Glass half empty?

Harold Korell: Well, I am going to let you play the glass game Bob. But I will answer the question to the best of my ability here, in what we know. The horizontal, we have no results on, except that we're drilling on it now. And, as I said, we've made the turn. And we're -- so mechanically it's going okay.

What we know from the Barnett Shale and some areas of the Barnett, definitely you get a lot better economic results from a horizontal well than you do a vertical well. And that's become the well of choice over there. So we could just throw rigs out here and drill vertical wells right now in these pilot areas. But, if in fact we get better returns by drilling horizontals, then that's going to be what we'll want to do.

And so when we built our plans, and announced our activity level in our last round of press releases before this one, we knew what we knew at that time. So we don't have a result of the horizontal well. So it might be that horizontals aren't the way to go. I also would tell you I don't think one horizontal well is going to tell us the answer.

In this business, usually you need to do more of one thing, of something than one thing. So we'll be drilling another one following this one. And it is a prudent way to act, I think. Since we've got this horizontal drilling now, if we get two times the rate in reserves, or three times, or one times, or four times, we'd need to know what that answer is. Because if we drill a bunch of verticals, and say we put that money into something that wasn't as well used as if we'd have drilled horizontals.

So that's kind of the answer. We don't know the answer yet, is what it boils down to. But the rationalization of how we got there is that.

Bob Christensen: Why was that particular location chosen? Because I thought about a quarter mile away from the other Vaughn well, which appears to be one of your better wells. I mean what was the logic? Because originally that was filed as a vertical well. What changed to say hey, this is the spot for horizontals?

Richard Lane: Well, it's Richard, Bob. Are you talking about the currently drilling horizontal wells?

Bob Christensen: Yeah. It was about a quarter mile away from what I reckon to be about your second best well so far, revealed in the play. And originally this well was supposed to be vertical. But you changed your mind and went horizontal. What went into your thinking?

Richard Lane: Yeah. Well, I think there's a lot of different factors you have to look at there to do that. Some of them are just strategic in nature. Others of them are regulatory. You know, for one instance, in Griffin Mountain Field we have field rules. And we know if we drill a well we can produce it. And so that, takes away any kind of delay or obstruction you might have related to the regulatory things. That's part of why we went and did it there.

And the other thing is; we have more control in the Griffin Mountain Field, in that pilot. So we wanted a significant amount of control, so that when we drilled this first horizontal, we took away some of the geologic risk. And we want to sample, or be right on top of another well either. So a lot of different factors there. But we've landed it in the shale. And we're horizontal. And so it looks like some of that control issue stuff was mitigated by that.

Bob Christensen: When you do the completion in the horizontal well, can you give me sort of what the basics are involved? I mean I take it it's an open hole. And can you just give us some of the details, without giving away secrets, maybe there are none to give away. How is it physically done? With sidewall plugs? Or what happens when you actually stimulate 2,000 feet of lateral leg? What keeps the, I guess rock from collapsing into the hole and that sort of stuff, just in laymen's terms of what happened there?

Richard Lane: Sure. Well, I mean there's a lot of different technologies you can deploy. And it depends on where you are and what the particulars are. I can tell you that what our plan is, is that it will be a case hole completion. So we don't have hole stability issues. And so we'll be perforating the casing, and fracture stimulating through perforations in the casing.

The technology in horizontal completions is a lot of new technology coming out, very interesting and timely. What we're planning on doing is what I said in my comments, it is a multi-stage completion. And the technology is there to isolate in the casing excessive perforations, and stimulate them, and then move to the next set of perforations and isolate them and stimulate them.

So we kind of notionally have about four stages that we would think we would try to do here. It depends on how much lateral we achieve. But, about four stages. And then we would have sets of perforations separated within each stage, like maybe three sets of perforations that we would be pumping into, and trying to create a fracture in each set of those.

Bob Christensen: Okay. One final question, if I may. Let's go back to some of the wells that have been on for a while. I mean we've had some wells on - I mean you flow tested; let's say, in September and October, wells that I see flow tests, based on your filings, in the 400-500 range a day. Now where are those wells today? I mean I am trying to understand what you mean by this decline rate, what does it look like?

Richard Lane: Well, maybe a way to -- like Harold said, maybe we can get some more modeling information out on this later. But another way to look at it is if you look at the -- we talked about the first average 30 days production of being about 375 Mcf a day. So certainly they're starting higher than 375. And they're ending the first 30 days lower than that, to get to that average. And then when you go to the second phase of that, or if you look at the first 60 days, you get a lower population of wells. And I think that number is down around 260, 265 Mcf.

Bob Christensen: In other words, the wells start out at let's say 500. Thirty days later they're way less than 400, because the average is 375. And 60 days later, they're averaging 260. I'm just trying to get an understanding of what a well's first three or four months looks like if it comes on at, let's say, 500,000 a day.

Harold Korell: I think you've just described it fairly well.

Bob Christensen: Okay. And when does the flattening--you don't know when the flattening begins yet?

Richard Lane: Well, I mean, and like Harold said, we have some wells rated at 150 days of production and we're seeing--certainly, we're seeing widening of the decline curve, lower decline, out in that longer period. And all of that is built into our best estimate of what an average result is when we're saying that we think we've got an economically viable--.

Bob Christensen: What happens with compression in the field? Let's say we're out 200 days on a well, and it's 100,000 a day. Do you have to put in field compression to, you know, get this up the pipe? I mean, does all--is this going to require a tremendous amount of field compression, this whole Fayetteville shale play? And are you ready for that operation?

Richard Lane: Yeah, I mean, it is certainly the type of play, a shallow gas play, with low reservoir pressure, and not lower than anticipated. Just basically, you know, what you would surmise for something of these depths. And you're noticing you're going into--or, not noticing--we are going into a higher-pressure transmission line. These kind of plays when we are at these kind of depths, you're compressing from the start.

Bob Christensen: Right.

Richard Lane: We've been doing that. We've been building infrastructure in the pilot areas to start to build toward a centralized compression per pilot area and getting all the efficiencies we can out of, you know, out of that compressions thing. But compression is certainly a big part of the play. It's built into our economic model. When you see the statements we're making here, we're including the costs of doing those kinds of things. But compression and gathering will be a very significant part of it.

Bob Christensen: Will you own it or lease it, the compression? I mean, you know, assuming 1,000 square miles over many, many years, if this play works, will you, you know, I mean, you've done this business before as a company. But will you decide to use--I mean, what's--do you own or lease? Have you thought that far out?

Richard Lane: Well, I mean, if you look at our operations kind of company-wide, we have some that we own, we have some that we lease. You know, right now, to be flexible, I think we've been looking and multi-employing lease compression and it's, you know, it just depends on what's more economic. But right now, I would say, to be flexible we are leasing what we've done so far.

Bob Christensen: Gas price to make this play economic? Is there a--you know, can it work sub floor dollars?

Richard Lane: We clearly believe we don't need what--as high a price as what prices are today. And the end result of all that I'm hesitant to say exactly what price is needed, because we don't know the outcomes of various things we're trying in terms of horizontal wells and other things right now. But it works at today's prices. It works at prices lower than what we're seeing today.

Bob Christensen: Thank you, gentlemen.

Joe Allman: Good morning, everybody. What about slick water fracs? Any plan to do additional slick water fracs there in the favorable shale?

Richard Lane: Joe, it's Richard. I think we're certainly not at the conclusion point on what the best stimulation is here. I think you'll see us continue to try different designs and to modify what we're doing, which might include some more of that. We've only done a couple of those and the results have, you know, not been clearly better. One well is probably less than average, one is more like average. So it's hard to say right now. We certainly are going to be studying the results of the wells we're stimulating right now and trying to best understand the best way to go about it, which could include some more of that.

Joe Allman: And then, on your horizontal well, what's the threshold in terms of production and/or reserves that would make the horizontal well economically viable given the cost you've identified?

Harold Korell: We won't know that until we see some production from it and what its decline looks like, because just the production itself--production rate, really won't tell us that answer. So it's too early to answer that question, Joe.

Joe Allman: Okay. And in terms of the acreage, I mean, based on what you've seen so far, what percentage of your acreage would you say is subject to faulting or has other characteristics that would preclude you from drilling there?

Harold Korell: We haven't seen any--I mean, we aren't precluded from drilling anywhere based on faulting that we know of. In the Griffin Mountain we've seen more faulting than we have in the other areas we've drilled in. And the way that tends to reflect itself is a little bit more drilling problems.

Richard Lane: Like Harold said, I don't think anything is precluded. It's--you know, it's understanding how the faulting affects you. And, you know, another thing we're doing is we have some plans this year for requiring some seismic data. And we'll be using that to help get a better structural picture of the areas where we're drilling that are kind of new and had less control.

Joe Allman: Okay. And then, on the Ranger Anticline based on your results so far I think you are drilling, you know, 43 or so wells this year. And then, do you still have the 132 or so contingent wells beyond this year?

Richard Lane: I think that's a fair assessment and the way that we've described them, and I know that's been talked about, is they are contingent on what we see this year. We certainly have a lot of acreage there that could be developing that would support a number greater than that. But I think that's a fair statement and it will indeed be contingent of the results of these next 40 or so.

Joe Allman: Gotcha. And then, one for Greg. In terms of differentials, you know, the--if you look at the stock price, Henry Hub at 9 on NYMEX. It's pretty close right now. So, I mean, are you seeing the widening still in your basis, or has it really narrowed quite a bit at this point?

Greg Kerley: Well, Henry Hub should be right on line with NYMEX all the time, Joe. It should be very, very close. As you move away from Henry Hub is where the basis differentials widen in all parts of the country. What we're seeing in the first quarter has been fairly similar to the fourth quarter and that's why our guidance is that we expect it to range between 50 cents and 60 cents an Mcf. I think we averaged about 60 cents, a little over 60 cents, in the fourth quarter.

Joe Allman: Yeah, I mean, Henry Hub, when the contract expires, they're supposed to converge. But in the latter part of '04 we saw some big variance between spot, Henry Hub, and the NYMEX, which, of course, is based on Henry Hub. But, Greg, what would be the best kind of benchmarks or local hubs to use to represent your production?

Greg Kerley: Well, our Arkoma Basin production is really priced off of Reliant East, and it's been over 50 cents an Mcf versus an historical number that's definitely closer to 20 cents. Our Permian production is averaging right now in the first quarter about 75 cents. A large part of our Overton production is priced off Houston Ship Channel. Houston Ship Channel has been averaging about 45 to 55 cents so far in the first quarter. So you really, I mean, we've got production that is spread out in all of our different core areas and between Houston Ship Channel, Reliant East, and Texok, is probably the bulk of our production. And then, whatever is coming out of the Permian is about a 75-cent differential right now.

Joe Allman: Okay. All right. Thanks for your time.

Peter Vig: Good morning. My question, Richard, and I think you talked around, is in the Barnett, a horizontal is going to cost twice as much and you are going to get three times the rate in reserve. Is that kind of the pre-drill prognosis? And I guess a corollary to that, the $1.6 million for this first was a little bit of a learning curve. Where would you think that cost would shake out through time?

Richard Lane: Well, it's really hard to say, Peter. I mean, it depends on--you know, what we're trying to learn, we're trying to learn a couple different--several things with this well. Mechanically, how does it behave? I think your model of the vertical versus the horizontal in the Barnett is also my understanding, which is obviously the attraction to the economics. But I think, you know, where we will end up will--there are a lot of factors there. What we're trying to understand mechanically right now is, you know, how does this--how do these rocks work when you start trying to build angle to them and drill a flat horizontal well over a pretty substantial distance. And like I said, we approached the first one conservatively. There's a lot of different ways to do it. And you can drill--you know, you can drill deeper and have a shorter radius build, a quicker build into the horizontal and all of those kinds of things, which affects your casing program. And so it's really hard to say. What we're trying to understand here is that--hard to say where the cost would land. What we're trying to understand here mechanically is, you know, can we build the angle? Can we actually drill a significant lateral in the shale without a lot of mechanical problems, and then, start working on the completion side. So, you know, it's really hard to say where those costs will land. There's give and take on all that.

Peter Vig: Okay. Another question, on this well that tested over a million a day, that's so anomalous compared to the norm. Are we talking about a greater thickness here or are we talking about greater depth of burial? What's the difference in this well vis-à-vis these other wells with their rate and reserve?

Harold Korell: Well, it's in a different area. It's in a different pilot than the bulk of the--than the majority of the wells that we have drilled. It's slightly deeper. It's not a lot deeper, but it's slightly deeper. And yeah--those are--I mean, those are kind of--those are the main things that geologically there may be something different there than in the other areas. But you're--you know, you're right. It is an anomalous test.

Peter Vig: Okay. Kind of a second thing. In the recent Barnett wells, and I'm talking about these wells that are, you know, six and seven million cubic feet a day. You know, initial 30 day rate. There seems to be some corollary between that and completing in zones that have either a high quartz content or almost approach sands. Do you see that kind of variability within the Fayetteville section itself?

Richard Lane: Well, you know, I can't comment directly about the Barnett. I have read the effects of having a higher silicon--silica content in those wells and how they respond to fracturing. You know, we're seeing variabilities in the rock itself in the Fayetteville. Some of that variability is probably in the percentages and distributions of clay versus more silica rich materials. So I would say we are seeing some of that variability.

Peter Vig: Okay. Those are all my questions. Thank you very much.

David Heikkinen: Good morning, guys. You've stayed focused through this long call, and congratulations on that. The Natchitoches County--just a quick comment or question. Your acreage there, and is that included in the 47,000 exploratory acres that you acquired last year?

Richard Lane: No, that would not be included in that, David. Most of the--you know, most of these other East Texas projects we had were, you know, had 4 or 5,000 type acres that we've kind of assembled in individual projects.

David Heikkinen: Okay. That was it. Everything else answered. Thanks.

Richard Lane: Well, thank you all for joining us today and it's been one of our longer conference calls, I think. We appreciate everyone staying here with us. And without really any further comments, I think we'll bring it to a close. Thank you.