Southwestern Energy Company disclosed that the company will be presenting certain preliminary information and estimates, supported by technical data, regarding wells in two proposed new fields at a public hearing before the Arkansas Oil and Gas Commission (AOGC) on June 28, 2005. The public hearing relates to Southwestern's pending applications for the Gravel Hill and Scotland fields in the company's Fayetteville Shale play. The preliminary information and estimates indicate that vertical wells in both the Gravel Hill and Scotland fields would have a likely drainage area of approximately 20 acres or less per well, based on an estimated expected ultimate recovery (EUR) ranging from approximately 300,000 to 480,000 Mcf per well. The company will also present the following test data and estimates regarding three horizontal wells in its Gravel Hill and Scotland fields:

(1)    Stobaugh EUR from COMET 3 reservoir simulation and history match.

(2)    McNew and Linkinogger EURs estimated by ratio of test rates to Stobaugh EUR.

With respect to the previously established Griffin Mountain Field in Conway county, Arkansas, Southwestern also disclosed that it will inform the AOGC that recent data from the 11 vertical wells with more than 30 days of production indicates a likely drainage area of approximately 20 acres or less per well and EUR per well ranging from approximately 150,000 to 480,000 Mcf per well, as compared to the previously estimated drainage area of approximately 30 acres or less per well and average EUR of 580,000 and 600,000 Mcf per well for the initial two wells. The reduction in the estimated EUR per well at Griffin Mountain is primarily attributed to reduced observed fracture stimulation lengths, which are about half of the estimates used in the original reservoir stimulation models. The company believes that improved EURs for the field may be obtained with longer fracture lengths and/or horizontal wells with transverse fracture stimulation treatments.

The company expects variability throughout the play area, therefore the drainage area per well, gas-in-place and ultimate recovery estimates discussed above and included in the company's AOGC filings are not necessarily indicative of the estimated ultimate drainage area, gas-in-place or recovery for the fields, the other pilot areas or the entire play area. The foregoing estimates are forward looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, actual results and the amounts of proved reserves that ultimately are recorded may be materially different. Actual results will be affected by commodity prices, operating costs, future well performance and variability within the play area, as well as other factors and risks that are more fully described in the company's Annual Report on Form 10-K for the year ended December 31, 2004.