8-K/A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K/A
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported)   August 7,  2003
SOUTHWESTERN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Arkansas	1-8246		71-0205415
(State or other jurisdiction	(Commission		(I.R.S. Employer
of incorporation)	File Number)		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)
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Item 7.(c)

Exhibits

(99.1) Transcript of slide presentation given August 7, 2003 to institutional investors and analysts at the 8th Annual Oil and Gas Conference held at the Pinnacle Club in Denver, Colorado. 

Item 9.

Regulation FD Disclosures

            On August 7, 2003, Greg D. Kerley, Executive Vice President and Chief Financial Officer for Southwestern Energy Company, made a presentation to institutional investors and analysts at the 8th Annual Oil and Gas Conference held at the Pinnacle Club in Denver, Colorado. The transcript of the accompanying slide show is furnished herewith as Exhibit 99.1. 

            Southwestern Energy Company is furnishing under Item 9 of this Current Report on Form 8-K/A the information included as Exhibit 99.1 to this report.

Note: The information in this report (including the exhibit) is furnished pursuant to Item 9 and shall not be deemed to be "filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section. This report will not be deemed an admission as to the materiality of any information in the report that is required to be disclosed solely by Regulation FD.

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, thereunto duly authorized.

		SOUTHWESTERN ENERGY COMPANY
		Registrant
DATE:	September 5, 2003	BY:	/s/ GREG D. KERLEY
			Greg D. Kerley
			Executive Vice President
			and Chief Financial Officer

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EXHIBIT INDEX
Exhibit No.	Description
99.1	Transcript of slide presentation given on August 7, 2003 to institutional investors and analysts at the 8th Annual Oil and Gas Conference held at the Pinnacle Club in Denver, Colorado.

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EX-99

EXHIBIT 99.1

Slide Presentation dated August 7, 2003

Slides were prepared for a presentation given August 7, 2003 to institutional investors and analysts at the 8^th Annual Oil and Gas Conference held at the Pinnacle Club in Denver, Colorado.

(Slide 1)
Southwestern Energy Company

Presentation to the Oil and Gas Conference

August 7, 2003

NYSE: SWN
[Picture of a weathered door lock and key. A keychain inscribed with the Company's formula is attached.]

(Slide 2)
Forward-Looking Statements

This presentation includes certain statements that may be deemed to be "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. All statements, other than historical financial information, may be deemed to be forward-looking statements. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. Investors should carefully consider the risk factors and other information set forth in the Company's Form 10-K in connection with an investment in the shares of the Company's Common Stock. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein inc lude, but are not limited to, the timing and extent of changes in commodity prices for gas and oil, the timing and extent of the Company's success in discovering, developing, producing, and estimating reserves, property acquisition or divestiture activities that may occur, the effects of weather and regulation on the Company's gas distribution segment, increased competition, legal and economic factors, governmental regulation, the financial impact of accounting regulations and critical accounting policies, changing market conditions, the comparative cost of alternative fuels, conditions in capital markets and changes in interest rates, availability of oil field services, drilling rigs, and other equipment, as well as other factors beyond the Company's control, and any other factors listed in the reports the Company has filed or may file with the SEC, which are incorporated by reference.

(Slide 3)

About Southwestern

Focused on domestic production of natural gas.

* 415.3 Bcfe of reserves; 90% natural gas; 10.4 R/P.

Strategy built on organic growth through the drillbit.

* Low-risk development balanced with high-potential exploration.

Track record of adding significant reserves at low costs.

* Since 1999, we have averaged production growth of 7% per year, 197% reserve replacement, and F&D cost of $1.07 per Mcfe.

Follow-on equity offering completed in March 2003. $103.2 million was raised with the proceeds being used to accelerate development drilling at Overton Field and to reduce debt. This offering decreased our debt-to-capital ratio from 66% at 12/31/02 to 45% at 6/30/03.

Strategy built on the Formula:

The Right People doing the Right Things, wisely investing the cash flow from the underlying Assets will create Value⁺.

(Slide 4)

Proven Track Record

Slide summarizes the Company's performance in four key indicators. Those indicators for the periods ended December 31 are as follows:

	1999	2000	2001	2002
Production (Bcfe)	32.9	35.7	39.8	40.1
Reserve Replacement	150%	196%	224%	209%
Reserve Additions (Bcfe)	49.3	70.1	89.3	83.7
F&D Cost ($/Mcfe)	$1.20	$0.99	$1.11	$1.02

Note: Reserve data excludes reserve revisions.

(Slide 5)

E&P Focused

Slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and New Mexico with shadings to denote areas of active E&P and lines to trace gas distribution pipelines and the Ozark Pipeline.

Our E&P segment had production in 2002 of 40.1 Bcfe (1). We had reserves of 415.3 Bcfe in 2002, 90% of which were natural gas. The average life of those reserves is 10.4 years. The Company's four operating areas, their reserve and production statistics, and their percentage of the whole are as follows:

	Arkoma	East Texas	Gulf Coast	Permian
Reserves (Bcf)	188.7	111.0	58.5	57.1
% of Total Reserves	45%	27%	14%	14%
Production	19.8	5.9	7.5	6.9
% of Total Production	49%	15%	19%	17% (1)

The Company's utility segment services 140,000 customers in Northern Arkansas, a territory which includes the 6^th fastest growing region in the U.S. according to the U.S. Census Bureau. In November 2002 we filed for an $11.0 million annual rate increase with the Arkansas Public Service Commission.

(1) Includes 2.0 Bcfe of production related to Mid-Continent properties sold during 2002.

(Slide 6)

Capital Investments

This slide contains a bar chart that breaks Southwestern Energy Company's capital investments down by general business activity, including utility and corporate, property acquisitions, capitalized expenses, leasehold and seismic, development drilling and exploration drilling. The summary of those investments is as follows:

	$ Millions
2000	$75.7
2001	(1) $92.5
2002	$92.1
2003 Plan	$173.6

(1) Net of $13.5 million reimbursement from Overton Field partnership.

This slide also contains a pie chart showing capital investments by area of operation. The results are as follows:

East Texas	52%
Arkoma	19%
Gulf Coast	13%
Permian	4%
Other E&P	7%
Utility	5%

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 7)

Overton Field - An Impact Project

This slide contains a map of Smith County, Texas where the Overton Field production area is located. This area consists of 17,600 acres in the Overton Field and an additional 5,800 farm-in acres in the South Overton area. Existing wells at year-end 2002 and development locations for 2003-2004 are shown. Also given are statistics of the Overton development potential. They are as follows:

		Approximate	Reserve
	Well	Spacing	Potential
	Count	(Acres)	(Net Bcfe)
Original Wells	16	640	22
2001 Development	15	400	36
2002 Development	18	250	53
2003 Proposed Development	55	120*	97*
2004 Proposed Development	53	80*	85*
Total	157	80*	293*

* In higher potential areas.

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 8)

Current Overton Drilling Economics

Typical First Year Economics:

Revenues - $4.00 per Mcfe

Production costs - $0.30 per Mcfe

Cash netback - $3.70 per Mcfe

F&D costs - $0.85 per Mcfe

Total Life Economics:

Completed well cost - $1.5 MM (1)

Pretax ROR - 35% (2)

Pretax PVI - 1.9 (2)

1. Current completed well cost estimate.
2. Assumes $4.00 per Mcf flat pricing and gross EUR of 2.2 Bcfe per well.

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 9)

Overton Field Gross Production

Slide contains a graph showing the Overton Field gross production rate for 2000 to 2002 and the potential rate for 2003 and 2004 under both an accelerated drilling program and under an 18 well per year program.

In addition, Overton's net production is given as follows:

	Bcfe
2000	0.3
2001	2.3
2002	5.9
2003 Forecast (1)	10 - 13
2004 Forecast (1)	18 - 20

The total number of wells under the two given drilling program options are as follows:

	Dec-01	Dec-02	Dec-03	Dec-04
18 Well Drilling Program	31	49	67	85
Accelerated Drilling Program (1)	31	49	104	157

1. Assumes accelerated development of Overton with equity offering.

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 10)

Overton Field - Improved Drilling Results

In this slide a graph is given portraying the improved drilling rate in the Overton Field since its purchase from Fina in 2001. Fina's average drilling rate was 55 days. Upon the Field's purchase we decreased that rate to 35 days. It was further decreased to 27 days in 2002 and 24 days in 2003. Thus, drilling time has been reduced by greater than 50% over the rate of previous owners. We also increased initial production by 200% and gross reserves by 60% to 2.2 Bcfe per well.

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 11)

Arkoma Basin

This slide contains a map of Arkansas and Oklahoma with shading to denote the Arkoma Basin production area. The Ranger Anticline and Haileyville prospects and the area known as the Fairway are further noted. Recent approval was given in the Ranger Anticline area to develop the field at 80-acre spacing.

Statistics for the Arkoma Basin, and the Haileyville and Ranger Anticline prospects are given as follows:

Arkoma Basin three year average results

Reserve replacement	97%
LOE cost (incl. Taxes) ($/Mcf)	$0.30
F&D cost ($/Mcf)	$1.08

Ranger Anticline

Success	17/20 wells
Net EUR	22.3 Bcf
F&D/Mcf	$.74

Haileyville

Success	16/24 wells
Net EUR	9.3 Bcf
F&D/Mcf	$.82

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 12)

Gulf Coast

This map highlights the areas within the onshore Gulf Coast region where Company 3D seismic information either already existed or was acquired or purchased in 2002. Specifically, the Horeb, Havilah, Crowne, Cheniere (2), Duck Lake, North Grosbec, Gloria and Malone seismic areas are noted.

Three-year average results for this region are as follows:

Reserve Replacement	246%
LOE Cost (incl. Taxes) ($/Mcfe)	$0.65
F&D Cost ($/Mcfe)	$1.83

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 13)

Exploration Potential - 224 Net Bcfe

This slide contains a table summarizing the exploration potential of the Company's production areas.

					Unrisked Reserve
		Spud	Working		Potential (Bcfe)
Prospect Name	Operator	Date	Interest	Depth	Objective	Gross	Net
Arkoma Basin
Midway	SWN	Dry	60.0%	11,400	Atoka	0	0
Permian Basin
Birds of Prey	SWN	Producing	100.0%	5,000	Cherry Canyon	14.8	11.8
S. Roepke	SWN	Producing	50.5%	8,100	Devonian	1.0	0.4
River Ridge	EGL	3Q 2003	12.5%	15,000	Devonian	30.0	3.0
Gulf Coast
Jericho	SWN	Dry	21.0%	14,300	Frio	0	0
Shiloh	SWN	T&A'd	100.0%	14,000	Cris R	164.0	98.2
Coleburn	SWN	3Q 2003	50.0%	12,700	Tex W	10.0	3.9
Ben Nevis	SWN	3Q 2003	50.0%	12,900	Miocene	45.0	16.9
Canvasback	SWN	3Q 2003	50.0%	18,200	Liebusella	80.0	30.0
Daffy	SWN	4Q 2003	50.0%	14,500	Siph D & Plan	110.0	41.3
Redhead	SWN	4Q 2003	50.0%	12,500	Siph D & Plan	49.4	18.5
			Total Reserve Potential			504.2	224.0

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 14)

How Have We Been Doing?

The graph contained on this slide shows how the implementation of a new management and E&P team along with a new strategy have affected F&D Cost, Reserve Replacement and PVI.

	1997	1998	1999	2000	2001 (1)	2002
F&D cost ($/Mcfe)	$2.53	$1.10	$1.20	$.99	$1.11	$1.02
Reserve replacement	77%	129%	150%	196%	224%	209%
PVI ($/$)	$ .56	$1.17	$1.07	$1.30	$1.40	$1.33

Note that all metrics calculated exclude reserve revisions.

(1) PVI metrics were calculated using pricing in effect at year-end with exception to the year 2000 which was calculated at $3.00 per Mcf natural gas price.

(Slide 15)

Unit Cost Comparison - SWN is Competitive

The bar graph given in this slide compares various expenses of the Company to similar measurements of its competitors. The data given represents 2000-2002 three-year averages, with income statement data being for the years ended December 31 unless otherwise indicated. Finding cost data includes revisions.

	Cimarex (1)	Magnum Hunter	St. Mary	Westport	Chesapeake	XTO	Mean	Median	Southwestern
Interest	$0.01	$0.70	$0.02	$0.20	$0.62	$0.34	$0.32	$0.27	$0.45
G&A	$0.18	$0.21	$0.23	$0.17	$0.09	$0.26	$0.19	$0.20	$0.33
Operating	$0.57	$1.06	$0.89	$0.82	$0.65	$0.87	$0.81	$0.85	$0.60
F&D	$4.25	$2.21	$1.53	$1.40	$1.21	$0.73	$1.89	$1.47	$1.17

(1) Cimarex Energy income statement data for the years 2000 and 2001 are for the year ended September 30.

(Slide 16)

Outlook for 2003

Production Targets:

42 - 44 Bcfe in 2003 (estimated growth of 5% to 10%).

50 - 55 Bcfe in 2004 (estimated growth of 20% to 25%).

	2002 Actual	2003 Guidance NYMEX Price Assumptions
	$3.22 Gas (1)	$5.00 Gas	$6.00 Gas
	$25.27 Oil (1)	$28.00 Oil	$28.00 Oil
Earnings	$14 MM	$43 - 46 MM	$55 - 58 MM
EPS	$.55	$1.25 - $1.35	$1.60 - $1.70
Operating Income	$47 MM	$90 - 93 MM	$109 - 112 MM
Cash Flow	$80 MM	$133 - 136 MM	$152 - 155 MM
EBITDA	$100 MM	$150 - 153 MM	$169 - 172 MM

Note: Per share estimates for 2003 assume 34.2 million weighted average diluted shares outstanding (includes 9.5 million shares issued in follow-on offering). Cash flow is before changes in working capital.

1. The average realized prices for our gas and oil production, after the effect of commodity hedge losses and basis differentials, were $3.00 per Mcf and $21.02 per Bbl, respectively, in 2002.

Note that the information contained on this slide constitutes a "forward-looking statement".

In accordance with Regulation G, a reconciliation of Cash Flow, as presented, to Net Cash Provided by Operating Activities from the Company's Form 10-K for the year ended December 31, 2002 is hereby furnished:

Net cash provided by operating activities	$78 MM
Add: Changes in operating assets and liabilities	$2 MM
Cash flow (as presented)	$80 MM

EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Southwestern has included information concerning EBITDA because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the Company's profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies. Net income is the financial measure calculated and presented in accordance with generally accepted accounting principles that is most directly comparable to EBITDA as defined.

	2002 Actual	2003 Guidance NYMEX Commodity Price Assumptions
	$3.22 Gas	$5.00 Gas	$6.00 Gas
	$25.27 Oil	$28.00 Oil	$28.00 Oil
	($ in millions)
Net Income	14	43 - 46	55 - 58
Deferred Income Taxes	9	26 - 28	34 - 36
Interest Expense	21	17 - 19	17 - 19
Depreciation, Depletion and Amortization	56	60 - 62	60 - 62
EBITDA	100	150 - 153	169 - 172

(Slide 17)

Gas Hedges in Place Through 2004

This slide contains a bar chart showing gas hedges in place by quarter for the years 2003 and 2004.

			Average Price per Mcf	Percent of Total
	Type	Hedged Volumes	(or Floor/Ceiling)	Production Hedged
2003	Swaps	13.3 Bcf	$3.47	30 - 35%
	Collars	17.1 Bcf	$3.26 / $5.05	40 - 45%
2004	Swaps	7.2 Bcf	$4.00	10 - 15%
	Collars	22.0 Bcf	$3.82 / $6.26	40 - 45%

(Slide 18)

The Road to V⁺

This slide summarizes the strategy by which the Company plans to continue to create added value in everything it does.

Invest in the Highest PVI Projects
	Accelerate Overton Development with Proceeds from Equity
	Offering (PVI = 1.9 @ $4.00 Gas Price).
Maximize Cash Flow
Stay the Course with Our Balanced Strategy
Deliver the Numbers
	Production and Reserve Growth
	Add value for Every Dollar Invested
Continue to Tell Our Story

(Slide 19)

Appendix

(Slide 20)

U.S. Gas Consumption and Sources

This slide displays U.S. gas production versus U.S. gas consumption from 1975 to the present. Net gas imports for the same period are also given. As the chart shows, U.S. gas production has been basically flat since 1994.

Source: EIA

(Slide 21)

U.S. Electricity Consumption on the Rise

This line graph shows an increase in U.S. electricity consumption in billion kilowatt-hours per month from 1990 to 2003.

Source: Edison Electric Institute

(Slide 22)

NYMEX Gas Prices

This line graph represents NYMEX gas prices in $/Mcf from 2000 to 2003.

Source: Bloomberg

(Slide 23)

U.S. Gas Drilling

This line graph denotes the number of rigs drilling for gas through the period 1988 to 2003.

Source: Baker Hughes

(Slide 24)

West Texas Intermediate Oil Prices

This line graph shows the price of West Texas Intermediate oil in $/Bbl for the years 2000 to 2003.

Source: Bloomberg

(Slide 25)

Oil and Gas Price Comparison

This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu for the period 1994 to 2003.

Source: Bloomberg