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): July 27, 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 July 27, 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 July 27, 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: July 27, 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 July 27, 2005 telephone conference call for investors and analysts.

EX-99

EXHIBIT 99.1

Southwestern Energy Announces Record Second 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 releases we announced yesterday, 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.

To begin, things have gone pretty well for us during the first six months of 2005. Yesterday, we reported earnings for the second quarter of a record $26.8 million, up 29% from the same period last year. Our cash flow for the second quarter was also up 29% from a year ago to a record $65.1 million. These results have been primarily driven by the current commodity price environment, and by the strong growth in our production volumes.

In our E&P program, we continue to have excellent drilling results, at our Overton Field in East Texas and the Ranger Anticline in the Arkoma Basin. In the Fayetteville Shale play we have made progress in our understanding of horizontal wells, established production in 6 pilot areas, are now drilling in a 7th pilot and are completing a well in the 8th pilot area. In addition we have obtained field rules for 3 fields in total, and are now producing at a gross daily rate of 10 MMcf per day.

As we announced yesterday, we are preparing to accelerate our drilling program in the Fayetteville Shale. In addition to the purchase of new drilling rigs for the play, we have increased our capital program for the Fayetteville Shale from approximately $100 million to $127 million for 2005, to fund our drilling program and to continue our leasing. We now plan to drill 80 to 90 wells in 2005 in the Fayetteville Shale play, with approximately 50 being horizontal wells. We also plan to increase our drilling activity at Overton, our other East Texas areas, at the Ranger Anticline, and in the Permian Basin. Richard will talk more about the capital plan and give an update on our E&P operations in a moment.

Overall, I am very pleased with what we have accomplished to date and look forward to what lies ahead for us in 2005 and beyond. 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.

Production for the 2nd quarter was 15.0 Bcfe, up 19% from the 12.6 we produced in the 2nd quarter of 2004, and up 7% from the 14.0 we produced in the 1st quarter of this year. Of the 15.0 Bcfe of 2nd quarter 2005 production, 6.5 was from East Texas, 5.2 from our conventional Arkoma Basin properties, 1.8 from the Permian Basin, 1.1 from the Gulf Coast Region, and 0.4 from our Fayetteville Shale play. Production during the 2nd quarter of 2005 included the continued effects of partial curtailment of production at our Overton Field. This curtailment issue was resolved late in the second quarter and current gross production from Overton is approximately 100 MMcfe per day as compared to 80 to 90 MMcfe per day while we were being curtailed.

We continue to be very active in East Texas and in the Arkoma Basin, particularly in our Ranger Anticline Field and our Fayetteville Shale play. Year-to-date, we have spudded a total of 119 wells including 43 wells in East Texas, 22 wells at Ranger, and 30 wells in the Fayetteville Shale play. We currently have 6 rigs running in East Texas, 4 at Ranger and 3 in the Fayetteville Shale and expect to increase our Fayetteville Shale rig count through the remainder of the year.

As a result of strong E&P revenues and our inventory of high PVI drilling projects, we have increased our E&P 2005 capital budget from $339.0 million to $425.1 million. This $86.1 million increase includes $27.0 million for additional drilling and land in the Fayetteville Shale play, $15.5 million for East Texas drilling, $5.6 million for Ranger Anticline, and $4.2 million for the Permian Basin. The remaining $33.8 million is for the purchase of five new land drilling rigs plus associated equipment we announced at the beginning of July.

In the first half of 2005, we invested approximately $55.3 million in our Fayetteville Shale play, including $33.3 million to drill 30 wells and $19.1 million for leasehold acquisitions. As of June 30th, we held approximately 690,000 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 50 wells and participated in one outside-operated well. The wells are located in eight separate pilot areas located in Franklin, Conway, Van Buren, Cleburne and Faulkner counties in Arkansas. In an east-west direction, we have drilled wells and established production approximately 40 miles apart. And in a north-south direction, 15 miles apart. Of the 51 wells, 41 are producing, six 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 nine horizontal wells in four separate pilot areas. Of the nine horizontal wells, seven have been completed and two are waiting on completion. Since our last press release on June 28, 2005, the Koone #2-34-H well located in our Gravel Hill Field was placed on production at approximately 1.7 MMcf per day. In addition, the Hall #1-12-H well located in our Brookie pilot area was production tested last week at 2.8 MMcf per day, and the Black #2-17-H well in our Scotland Field recently tested at 2.9 MMcf per day.

The initial test rates for the completed horizontal wells has ranged from 1.4 to 3.7 MMcf per day, excluding the Vaughan #4-22-H well, where we encountered wellbore problems and a limited fracture stimulation treatment. Two of these wells, the Stobaugh #2-1-H and the McNew #3-2-H, which have been on production for more than 30 days, have an average first month production rate of 2.2 MMcf per day. Based on these early production histories and our modeling work, we believe the average ultimate production from these horizontal wells will be between 1.3 and 1.7 Bcfe per well. We expect our year-end reserve assessment for our horizontal wells to be composed of both proved and probable reserves as we have limited production histories for these wells.

Our first nine horizontal wells have on average taken 15 days to reach total depth and our most recent well costs have been between $1.4 and $1.8 million per well, excluding non-recurring costs.

In June of 2005, the Arkansas Oil and Gas Commission approved rules for our Gravel Hill and Scotland Fields in our Fayetteville Shale play area that provide for 560 feet minimum distance between completions in common sources of supply within the Fayetteville Shale, up to a maximum of 25 wells per section.

To insure adequate rig availability for our development plan here, we entered into a sales agreement in early July with a private company to build five new land drilling rigs capable of drilling both vertical and horizontal well in the Fayetteville Shale. These new rigs have design features that are optimal for drilling in our Fayetteville Shale play. The first rig is expected to be completed in November with one additional rig delivered per month after that.

Our Fayetteville Shale activity in the third quarter will include drilling additional horizontal and vertical wells, some seismic acquisition, and testing of additional new areas of our acreage. For all of 2005, we expect to drill 80 to 90 wells with our remaining 2005 program, with approximately 50 being horizontal wells.

As I mentioned previously, we spudded 22 wells in the Ranger Anticline Area in the 1st half of 2005. All of these wells are either productive or are currently being tested. The Ranger Anticline, located in Yell and Logan Counties, Arkansas, produces from the Borum sands between 5,500 feet and 8,500 feet. Of the 22 wells, 15 are located in the core producing area of the field, four are located in the western expansion area we began developing last year, and three are in an eastern expansion area nine miles from the proven productive part of the field. The three wells we drilled in the eastern expansion have penetrated pay in the Basham and Turner sands at 3,550 feet. We are currently obtaining rights-of-way and beginning construction of a pipeline to bring these wells on production. Additionally, we participated in an outside-operated test between the core field area and the eastern expansion. This well penetrated the Borum sands and is now being tested.

Due to our continued success here, we now plan to drill 50 wells in the Ranger Anticline area in 2005, up from the original forecast of 43 wells.

In the first half of 2005, we invested approximately $81.7 million in East Texas. We continue to be pleased with the results of our development drilling program at our Overton Field, located in Smith County, Texas. In the first half of 2005, we spudded 36 wells at Overton and have maintained a 100% success rate. We have now drilled 209 wells since we acquired the field in 2000. As mentioned earlier, our production at Overton is no longer being curtailed. Gross production is approximately 100 MMcfe per day, up from 80 to 90 MMcfe per day due to curtailment.

In addition to our Overton Field, we continue to be active in other areas in East Texas. At our Angelina River Trend, we have acquired a total of 12,800 net undeveloped acres in four new development areas, located primarily in southern Nacogdoches county. To date in 2005, we have drilled four wells in this trend, two of which have production tested over 4 MMcf per day each, and expect to drill five more by the end of the year. We are hopeful that this area will continue to grow for us.

In summary, we are encouraged by our results at Overton, at Ranger Anticline, and our Fayetteville Shale Play. We are well on track to achieve 13% to 16% organically driven production growth for the year by continuing to invest in 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 second quarter primarily fueled by our production growth and higher realized commodity prices. Earnings for the quarter were a record $26.8 million, or $0.36 per diluted share, up 29% from the second quarter of 2004. Cash flow provided by operating activities before changes in operating assets and liabilities also set a new record for the second quarter at $65.1 million, up from $50.3 million for the prior year period.

The improved operating income of our E&P business drove our record results as our natural gas distribution business generated a seasonal operating loss for the second quarter.

Operating income for our E&P segment was $48.6 million for the second quarter, up 30% from $37.5 million for the same period last year, primarily due to the general increase in natural gas and crude oil commodity prices and the growth in our production volumes.

We realized an average gas price of $5.71 per Mcf for the second quarter of 2005, up from $5.25 per Mcf for the same period last year. Our hedging activities decreased our average gas price realized during the quarter by $0.75 per Mcf, compared to a decrease of $0.57 per Mcf for the same period of 2004. Disregarding the impact of hedges, the average price received for our gas production during the second quarter of 2005 was approximately $0.27 per Mcf lower than average NYMEX spot prices, compared to approximately $0.17 per Mcf in the second quarter of 2004. This change was due to widening locational market differentials that have occurred since the prior year period. The company currently estimates that its average realized market differentials for the third quarter of 2005 will range between $0.25 to $0.30 per Mcf. We have approximately 75% of our targeted gas production hedged in 2005 and our current hedge position is detailed in our Form 10-Q that we filed yesterday.

Lease operating expenses per unit of production were $0.43 per Mcfe in the second quarter of 2005, compared to $0.39 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 in the second quarter of 2005, compared to $0.35 in the second quarter of 2004, primarily due to increased compensation costs associated with increased staffing levels. Our full cost pool amortization rate rose to $1.38 per Mcfe, compared to $1.18 per Mcfe a year ago, primarily due to increased finding and development costs. We currently expect our full cost pool amortization rate to average between $1.40 and $1.45 per Mcfe for 2005.

Our utility systems realized a seasonal operating loss of $2.4 million in the second quarter of 2005, compared to a loss of $1.4 million for the same period of 2004. The decrease in operating income resulted primarily from higher operating costs and expenses.

Operating income from our gas marketing activities was $0.9 million during the second quarter, up slightly from the second quarter of 2004.

Our capital investments for the first six months of 2005 totaled $186.7 million, which included $181.5 million of our E&P segment. As we announced yesterday, we have increased our capital program for 2005 from approximately $352.7 million to $438.8 million, which includes the rig commitment that we announced earlier this month, and approximately $52 million to fund additional development drilling in our core operating areas.

We are currently forecasting operating cash flow for 2005 of approximately $290 - $300 million assuming that NYMEX gas prices were to average $7.00 per Mcf for the year. We expect to fund the balance of our capital investment program from borrowings under our revolving credit facility and/or proceeds from any debt or equity offering we might pursue. We filed a new shelf registration statement with the Securities and Exchange Commission yesterday which will allow the company to sell up to an aggregate $600 million of common stock and debt securities. The new registration statement will replace a shelf that was filed approximately three years ago. The registration statement combined with our revolving credit facility (which currently has approximately $400 million of available capacity) will provide us with a great deal of flexibility in funding our capital program going forward.

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