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): May 2, 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 May 2, 2005, at 10:00am Eastern, Southwestern Energy Company will host a telephone conference call for investors and analysts.  The prepared teleconference comments are furnished herewith as Exhibit 99.1.

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

Exhibit Number	Description
99.1	Prepared teleconference comments for May 2, 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: May 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	Prepared teleconference comments for May 2, 2005 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Announces Record First Quarter 2005 Results

Teleconference

Harold Korell; Southwestern Energy Co.; President, Chairman, and CEO
Richard Lane; Southwestern Energy Co.; EVP, Exploration and Production
Greg Kerley; Southwestern Energy Co.; CFO

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

If you have not received a copy of the press release we announced on Friday regarding our first quarter 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 assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

We are off to a great start in 2005. Our first quarter financial results were the best in the company's history, as we set new records for earnings and cash flow due to our production growth and higher commodity prices. We continue to have excellent results in our drilling programs at the Overton Field in East Texas and the Ranger Anticline in the Arkoma Basin.

In addition, we continue to make progress in our Fayetteville Shale play. By the end of the quarter, we had drilled 39 wells in six pilot areas in four separate counties in the play. We have begun testing horizontal wells with encouraging results, which Richard will discuss.

On the land front, we are continuing to lease new acreage, and to date we have leased approximately 630,000 net acres in the undeveloped play area and we control an additional 125,000 net developed acres in the traditional "Fairway" area of the basin. We have also seen increasing competition for leases over the last few months.

Overall, we continue to be excited about the potential of the Fayetteville Shale play. Our drilling program will remain flexible throughout the year and will continue to be impacted by a number of factors, including the results of our drilling efforts, our progress in determining the most effective fracture stimulation treatment, the performance of wells we drill in new pilot areas, prevailing costs for services and materials and the gas commodity price environment.

We have had an excellent start to what I believe will be a very exciting year for Southwestern Energy. I'll now turn the teleconference over to Richard Lane, who will tell you more about our E&P results, then to Greg Kerley to discuss our financial results, and then answer your questions.

Richard Lane: Thank you Harold, and good morning.

During the 1^st quarter of 2005, we continued with an active drilling program in East Texas and the Ranger Anticline Field in the Arkoma Basin. In addition, we have been evaluating fracture stimulation techniques and testing horizontal technology in our Fayetteville Shale play. We currently have 6 rigs running in East Texas, 3 at Ranger and 3 in the Fayetteville Shale. In the 1^st quarter, we spudded a total of 64 wells including 21 wells in East Texas, 13 wells at Ranger, and 18 wells in the Fayetteville Shale play.

Our production volumes for the 1^st quarter were 14.0 Bcfe, up 22% from the 1^st quarter of 2004 despite the curtailment of a portion of our production at our Overton Field in East Texas. Due to continued curtailments at Overton into the 2^nd quarter, we are revising our 2^nd quarter production guidance down slightly from a range of 15.0 Bcfe to 15.4 Bcfe to a new range of 14.8 Bcfe to 15.2 Bcfe. We are continuing to hold our full year guidance at 61.0 to 63.0 Bcfe. At this time, we expect all curtailment issues at Overton to be resolved by the end of the 2^nd quarter. Of the 14.0 Bcfe of 1^st quarter 2005 production, 5.9 was from East Texas, 4.9 from our conventional Arkoma Basin properties, 1.8 from the Permian Basin, 1.2 from the Gulf Coast Region, and 0.2 from our Fayetteville Shale play.

In the first quarter of 2005, we invested approximately $20.1 million in our Fayetteville Shale play, including $11.9 million to drill 18 wells and $6.9 million for leasehold acquisitions. As of March 31^st, we held approximately 630,000 net acres in the undeveloped play area. In addition, we control approximately 125,000 net developed acres in the traditional "Fairway" area of the Arkoma Basin that is held by production.

Since beginning our drilling program in the Fayetteville Shale in 2004, we have drilled a total of 38 wells and participated in one outside-operated well. The wells are located in six separate pilot areas located in Franklin, Conway, Van Buren and Faulkner counties in Arkansas. Of the 39 wells, 27 are producing, eight are in some stage of completion or waiting on pipeline hook-up, and four are shut-in due to marginal performance.

To date, we have drilled three horizontal wells in three separate pilot areas. Of the three horizontal wells, two have been completed and tested and one is waiting on completion. The first horizontal well was drilled in the company's Griffin Mountain field area with a 1,857' lateral and required 32 days to reach total depth. We initially planned to perforate and stimulate four different intervals along the length of the horizontal section. However, problems with wellbore isolation limited the potential stimulation of the well to effectively only one stage at the tail of the horizontal section. This well had a final test rate of approximately 580 Mcf per day. The second horizontal well, completed in the company's Rainbow pilot area had a 2,264' lateral and required 11 days to drill. This well was successfully fracture-stimulated in four separate stages, tested at a rate of approximately 3.7 MMcf per day and will be put on production later this week. The third horizontal well, located in our Brookie pilot area, took 19 days to drill and had a 2,170' lateral. We expect to be completing this well over the next few weeks. We are currently drilling our fourth horizontal well which is located in our Rainbow pilot area.

The average drill and complete cost for the first three horizontal wells was approximately $2.1 million per well. Excluding extraordinary and non-recurring costs, we estimate that our horizontal well costs during the second quarter will range between $1.5 to $2.0 million per well.

We also recently placed a new vertical well on production at a rate of approximately 1,300 Mcf per day with a flowing tubing pressure of approximately 1,100 psi in our Brookie pilot area and tested another vertical well at a rate of 1,283 Mcf per day with a flowing casing pressure of 490 psi in our Rainbow pilot area. The costs to drill and complete our vertical wells range from $440 thousand to $650 thousand per well, with the higher cost wells predominately in our Griffin Mountain Field area.

We are continuing to get more history on our producing wells. As was expected, we have begun seeing some variance in the Fayetteville Shale's productivity between the different pilot areas. Initial potentials of the vertical wells have ranged from 300 Mcfpd to 1,500 Mcfpd. The first 30-day average producing rate from the 13 wells which have been on production more than one month is 375 Mcfpd. The second 30-day average rate from the 8 wells producing this long is 214 Mcfpd. Assuming a first year average exponential decline rate of 75%, a second year decline rate of 45%, a third year decline rate of 20% with further flattening in the out-years, we currently estimate that the ultimate recoveries from our existing vertical wells will be between 300 and 750 Mmcfe per well. The wells in the Griffin Mountain area, which represent over half of the producing wells, are expected to average approximately 300 Mmcf. No estimates have current ly been made for the completed horizontal wells.

Our activity for the remaining part of the year will include continued efforts in improving the fracture stimulations on vertical wells, drilling additional horizontal wells, some seismic acquisition, and testing of additional new areas of our acreage. The key word here is flexibility to pursue the best path forward for value creation.

As I mentioned previously, we spudded 13 wells in the Ranger Anticline Area in the 1^st quarter of 2005. All of these wells are either on production now or are currently being tested. The Ranger Anticline, located in Yell and Logan Counties, Arkansas, produces from the Borum sands between 5,500' and 8,500'. Of the 13 wells, 10 are located in the core producing area of the field, 2 are located in the western expansion area we began developing last year, and one, the Standridge #1-10 well, was drilled as a nine mile eastern step-out of the core producing area. As mentioned last time, the Borum sands were tight in the Standridge well, however, the well did penetrate 150 feet of gas pay in the Basham and Turner sands at 3,550'. This well is currently waiting on pipeline connection. We plan to drill offsetting wells in 2005 to determine the extent of these shallower pay sands as well as to continue testing the deeper Borum sands.

The success of our Ranger Anticline drilling program is reflected in the field's increasing production. We are currently producing 25 Mmcfpd gross from the field, up from 8 MMcf per day at year-end 2003.

We continue to be very pleased with the results of our development drilling program at our Overton Field, located in Smith County, Texas. In the first quarter, we spudded 18 wells at Overton and have maintained a 100% success rate. We have now drilled 191 wells since we acquired the field in 2000. The average estimated ultimate recovery for our 1^st quarter 2005 wells is approximately 1.6 gross Bcfe per well. The combination of our cost controls and continuing good well performance is allowing us to continue to exceed our economic hurdle rates at Overton.

As mentioned earlier, our production at Overton is still being curtailed due to the failure of a transmission line into which a large part of Overton Field's gas sales are made. The operator of the line is continuing to seek regulatory approval to return the line to its normal operating pressure. To partially offset the curtailment caused by the line failure, additional compression was recently added to a second transmission line serving the Overton Field. Plans also call for "looping" this line to further increase take-away capacity. We expect all curtailment issues at Overton to be resolved by the end of the 2^nd quarter.

In addition to our Overton Field, we continue to be active in other areas in East Texas. The Reavley #1 well, located in our Black Bayou Prospect located in Nacogdoches County, is currently producing 1.3 MMcfpd from the Travis Peak formation at approximately 11,000; We are currently staking two offsets to this well which we operate with a 40% working interest.

At our Doyle Creek prospect in Cherokee County, we are currently completing our Session Heirs #1 well. This well encountered 94 feet of pay in the Travis Peak formation at 10,900'. We expect this well to be on production in late May.

Also in East Texas, we plan to spud two of our exploration tests in the second quarter. The Watts #1 well in our Pines prospect in Marion County, will test the Lower Cotton Valley and Boosier sands at 11,350'. This well is currently drilling. We also plan to drill a test of our Ginger Quill prospect, located southeast of our Black Bayou discovery in Nacogdoches County, late in the second quarter.

Moving on briefly to the Permian Basin, at our No Bluff project in Eddy County, New Mexico, we are developing a shallow oil play in the Glorieta/Yeso formations at 3,700'. To date in 2005, we have drilled two wells producing 144 Bopd and 93 Bopd, respectively. Although fairly small, at these shallow depths and at $50+ oil pricing, this project yields an excellent PVI. We plan to drill an additional 2 to 5 wells here by the end of 2005.

In summary, we continue to be encouraged by our results at Overton, at Ranger Anticline, and particularly at our Fayetteville Shale Play. We are looking forward to strong results for the remainder of the year.

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, our results for the first quarter were excellent, primarily fueled by our strong production growth and higher realized commodity prices. Earnings for the first quarter were a record $32.6 million, or $0.87 per diluted share, up 33% from the first quarter of 2004. Cash flow provided by operating activities before changes in operating assets and liabilities also set a new record for the first quarter at $73.6 million, up 30% from the same period in 2004.

Operating income for our E&P segment was $47.7 million for the first quarter of 2005, compared to $33.4 million for the same period last year. The improved results were primarily due to a 22% increase in our production volumes combined with a 16% increase in our average gas price.

We realized an average gas price of $5.71 per Mcf for the first quarter of 2005, up from $4.92 per Mcf for the same period last year. The company's hedging activities had minimal impact on the average gas price realized during the first three months of the year, compared to our hedges in place during the first quarter of 2004 which lowered our average price by $0.42 per Mcf. Locational differences in market prices for natural gas have continued to be wider than historically experienced. Disregarding the impact of hedges, our average realized gas price during the first quarter of 2005 was approximately $0.55 per Mcf lower than average NYMEX spot prices. This was in line with our previous guidance and about $0.20 wider than our average for the prior year period. We currently estimate that our average realized market differentials for the second quarter will range between $0.40 to $0.50 per Mcf lower than average NYMEX spot market prices, excluding any impact from our commodity hedges. We have approximately 70% - 80% of our targeted gas production hedged in 2005 and our current hedge position is detailed in our Form 10-Q that was filed Friday.

Our E&P segment continues to be one of the lowest-cost producers in the industry. Lease operating expenses per unit of production were $0.45 per Mcfe in the first quarter of 2005, compared to $0.38 per Mcfe for the same period in 2004. The increase in our unit operating expenses was primarily due to increased compression costs and higher oil field service costs. General and administrative expenses per Mcfe were $0.39 during both the first quarters of 2005 and 2004. Our full cost pool amortization rate rose to $1.29 per Mcfe, compared to $1.18 per Mcfe a year ago, primarily due to increased finding and development costs.

Operating income for our utility segment was $7.4 million in the first quarter, down from $8.8 million in the same period in 2004. The decrease in operating income resulted primarily from decreased deliveries due to warmer weather in the utility's service territory during the first quarter, and higher general and administrative expenses. On December 29, 2004, our utility filed a rate increase request of $9.7 million annually with the Arkansas Public Service Commission. The scheduled hearing date for the rate increase request is in September, and any increase allowed would likely be implemented in the fourth quarter of 2005.

Operating income from our gas marketing activities was $1.0 million during the quarter, up slightly from the first quarter of 2004.

Our capital investments for the first three months of 2005 totaled $80.9 million (including $78.5 million for our E&P operations), up from $58.6 million during the first quarter of 2004. Our strong cash flow enabled us to fund our increased capital expenditures and also pay down $27 million of debt during the quarter. As a result, our total debt-to-capitalization ratio improved to 40% at March 31, 2005, down from 42% at year-end.

Our outlook for the balance of 2005 is very positive. As Richard indicated, we are targeting total oil and gas production of 61 to 63 Bcfe for the year, and if you assume NYMEX commodity prices of $7.00 per Mcf of gas and $50.00 per barrel of oil, we are targeting net income of $120 to $130 million, and net cash provided by operating activities (before changes in operating assets and liabilities) of $290 - $300 million. Our current planned capital investments for 2005 of $352.7 million are expected to be funded by our cash flow from operations and borrowings under our revolving credit agreement. We currently have $427 million of available capacity under our credit facility.

That concludes my comments, so now we'll turn back to the operator who will explain the procedure for asking questions.