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)   March 5, 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 accompanying the March 5, 2003 presentation to investors during the 24th Annual Raymond James Institutional Investors Conference at the Hyatt Regency Grand Cypress in Orlando, Florida.

Item 9.

Regulation FD Disclosures

            On March 5, 2003, Harold M. Korell, President and Chief Executive Officer for Southwestern Energy Company, made a presentation to investors at the 24th Annual Raymond James Institutional Investors Conference. A transcript of the 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:	July 9, 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 accompanying the March 5, 2003 presentation to investors during the 24th Annual Raymond James Institutional Investors Conference at the Hyatt Regency Grand Cypress in Orlando, Florida.

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EX-99

Exhibit 99.1

Slide Presentation dated March 5, 2003

Slide presentation accompanying the March 5, 2003 presentation to investors during the 24^th Annual Raymond James Institutional Investors Conference at the Hyatt Regency Grand Cypress in Orlando.

(slide 1)
Southwestern Energy Company
Raymond James Institutional Investors Conference
March 5, 2003
NYSE: SWN
[Picture of lock and skeleton key in weathered door. Key has keychain attached with the Company's formula inscribed.]

(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 include, 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've averaged production growth of 7% per year, 197% reserve replacement, F&D cost of $1.07 per Mcfe.
Recent successful follow-on equity offering to accelerate development drilling at Overton Field.

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)
About Southwestern
[Map showing the states of Arkansas, Louisiana, Texas, Oklahoma and New Mexico with the following E&P operating areas identified: Arkoma Basin in western Arkansas and eastern Oklahoma; Permian Basin in Southeast New Mexico and West Texas; Gulf Coast in gulf coast regions of Louisiana and Texas; and East Texas in eastern Texas; Company's utility pipeline operations shown in northern Arkansas; Ozark Pipeline shown stretching from eastern Oklahoma into and across northern Arkansas.]
[Legend indicating gas distribution pipelines from Ozark Pipeline.]
[Textboxes shown which describe characteristics of the Company's two major business segments.]

E&P Segment
2002 Reserves: 415.3 Bcfe
90% Natural Gas
2002 Production: 40.1 Bcfe (1)
Reserve Life: 10.4 years
(1)    Includes 2.0 Bcfe of production related to Mid-Continent properties sold during 2002.

Utility Segment
140,000 customers in N. Arkansas
Territory includes 6^th fastest growing region in U.S.
Filed rate case in November 2002
[Flags pointing to operating areas that indicate basin characteristics.]

Arkoma
	Reserves - 188.7 Bcf (45%)
	Production - 19.8 Bcf (49%)
Permian
	Reserves - 57.1 Bcfe (14%)
	Production - 6.9 Bcfe (17%) (1)
	(1) Includes 2.0 Bcfe of production related to Mid-Continent properties sold during 2002.
Gulf Coast
	Reserves - 58.5 Bcfe (14%)
	Production - 7.5 Bcfe (19%)
East Texas
	Reserves - 111.0 Bcfe (27%)
	Production - 5.9 Bcfe (15%)

Arkoma: Maintain our strong position through workovers and low-risk development drilling.
East Texas (Overton): Grow through low-risk infill drilling.
Permian: Focus on medium-risk exploration.
Gulf Coast: Grow through high-potential exploration.

(slide 5)
Proven Track Record
For the Periods Ended December 31,

	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 6)
Capital Investments
[bar chart showing Southwestern Energy Company's capital investments by general business activities.]

2000	$75.7
2001	$92.5 (1)
2002	$92.1
2003 Budget	$145.6

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

[pie chart showing Southwestern Energy Company's capital investments by areas of operation.]

East Texas	53%
Arkoma	16%
Gulf Coast	15%
Permian	3%
Other E&P	7%
Utility	6%

E&P capital program heavily weighted to low-risk drilling in 2003:
        - -        Low-risk Arkoma ($22.6 MM, 16%) and East Texas ($78.0 MM, 53%),
        - -        Medium-risk Permian Basin ($4.8 MM, 3%) and
        - -        Higher-risk, but larger potential Gulf Coast ($21.7 MM, 15%).
Over 83% of E&P capital allocated to drilling in 2003.
Identified exploration inventory has a net reserve exposure of 196 Bcfe.
Utility provides predictable earnings and cash flow.

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 7)
Overton Field - An Impact Project
[locator map showing Smith County, Texas; map showing Overton Field area containing 16,500 acres with producing well locations and future development drilling locations, adjacent to South Overton Farm-in Acreage area of 5,800 acres with producing well locations and future development drilling locations; legend to map indicating existing wells at year-end 2002 and development locations for 2003-2004; textbox indicating information on this slide constitutes a "forward-looking statement;" textbox indicating Overton development potential as follows:]

	Well Count	Approx. Spacing (Acres)	Reserve Potential (Net Bcfe)
Original Wells	16	640	22
2001 Development	15	400	36
2002 Development	18	250	53
2003 Proposed Development	47	120*	83*
2004 Proposed Development	53	80*	85*
Total	149	80*	279

* In higher potential areas.

Purchased for $6.1 million in 2000 (developed at 640-acre spacing).
Drilled 15 wells in 2001 and 18 wells in 2002 with 100% success (3-year average F&D cost of $0.63/Mcfe).
Opportunity to downspace to 80-acre spacing (100+ additional wells).

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 8)
Current Overton Drilling 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

Results:

Completed Well Cost	Pretax ROR	Pretax PVI
$1.5 MM (1)	35% (2)	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.

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 9)
Overton Field Gross Production
[graph showing Overton Field gross production rate, potential rate with accelerated drilling program, and estimated rate with 18 well per year program.]

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

(1)    Assumes accelerated development of Overton with equity offering.

Total Wells	Dec-01	Dec-02	Dec-03	Dec-04
18 Well Drilling Program	31	49	67	85
Accelerated Drilling Program (1)	31	49	96	149

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 10)
Overton Field - Improved Drilling Results
Drilling Days versus Depth
[graph showing the depth and drilling days. The average for Overton was 27 days in 2002 and 35 days in 2001. FINA's average drilling time was 55 days.]

Reduced drilling time by greater than 50%.
Increased initial production by 200%.
Gross EUR 2.2 Bcfe per well.

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 11)
Arkoma Basin
[map showing location of Arkoma Basin in Arkansas and Oklahoma, the Arkoma Basin Fairway, the Ranger Anticline Prospect and the Haileyville Prospect.]

Arkoma Basin
        - -        3-year average results
        - -        Reserve replacement: 97%
        - -        LOE Cost (incl. Taxes) ($/Mcf): $0.30
        - -        F&D Cost ($/Mcf): $1.08

Ranger Anticline
        - -        Success: 12/15 wells
        - -        Net EUR: 14.5 Bcf
        - -        F&D/Mcf: $.82

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

"Legacy asset" that provides SWN with a stable production/reserve base and low-risk drilling opportunities with some upside exploration potential.

Competitive advantages:
        - -        60 years of experience in the basin.
        - -        Large acreage position of 385,00 gross acres and 263,000 net acres.
2003 capital program includes drilling 30 wells and 60 workovers.

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 12)
Gulf Coast Exploration
[map showing location of the 3D seismic acquired or purchased in 2002, the existing 3D seismic, the Horeb, Havilah, Malone, North Grosbec, Gloria, Crowne Discoveries, Chenier (2) and Duck Lake seismic area.]

Gulf Coast	3 - Year Avg. Results
Reserve Replacement:	246%
LOE Cost (incl. Taxes) ($/Mcfe):	$0.65
F&D Cost ($/Mcfe)	$1.83

8 discovery wells out of last 19 wildcats drilled in South Louisiana.
Exploration inventory with net reserve potential of over 170 Bcfe in 2003.
Duck Lake 3-D project data now in-house:
        - -        135-square mile 3-D survey in a highly prospective area in St. Martin and St. Mary Parishes.
        - -        SWN is operator and owns a 50% working interest. Drilling to commence in 2003.
Acquired license to over 1,000 square miles of 3-D shelf data in 2002.

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 13)
Exploration Potential - 196 Net Bcfe

							Gross Res.	Net Res.
		Spud	Working				Potential	Potential
Prospect Name	Operator	Date	Interest	Depth	Objective		(Bcfe)	(Bcfe)
Arkoma Basin
Midway	SWN	1Q 2003	60.0%	11,400	Atoka		20.0	10.5
Permian Basin
Birds of Prey	SWN	Drilling	100.0%	5,000	Cherry Canyon		6.0	5.0
S. Roepke	SWN	Completing	50.5%	8,100	Devonian		4.0	1.6
Gaucho Deep	Devon	3Q 2003	25.0%	15,000	Devonian		30.0	6.0
Gulf Coast
Jericho	SWN	Dry	35.0%	14,300	Frio		-	-
Shiloh	SWN	Drilling	75.0%(1)	14,000	Cris R		164.0	92.3
Ben Nevis	SWN	3Q 2003	50.0%	12,900	Miocene		45.0	16.9
Duck Lake (3)	SWN	3-4Q 2003	50.0%	16,000	Planulina		95.0	35.6
N. Shiloh	SWN	4Q 2003	75.0%	13,500	Planulina		50.0	28.1
			Total Reserve Potential			414.0			196.0

(1)    SWN's % share of drilling and completion costs is 62.5%.

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 14)
How Have We Been Doing?
[graph showing the company's results in PVI, F&D Cost and Reserve Replacement from 1997 to 2002.]

	1997	1998	1999	2000	2001	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: All metrics calculated exclude reserve revisions.

(1)    PVI metrics calculated using pricing in effect at year-end (except for 2000 which was calculated at $3.00 per Mcf natural gas price).

(slide 15)
Unit Cost Comparison - SWN is Competitive
[bar chat showing SWN's unit cost versus a peer group.]

	Magnum Hunter (1)	Cimarex (3)	St. Mary	Westport	Chesapeake (2)	XTO	Mean	Median	Southwestern (4)
Interest	$0.64	$0.02	$0.05	$0.36	$0.60	$0.23	$0.32	$0.30	$0.41
G&A	0.22	0.22	0.22	0.18	0.12	0.22	0.20	0.22	0.32
Operating	1.12	0.69	0.97	0.89	0.65	0.78	0.85	0.83	0.64
F&D	4.48	3.79	2.03	1.69	1.35	1.01	2.39	1.86	0.99

Source: RBC Capital Market
Note: Income statement data for the LTM ended 9/30/02 unless otherwise indicated. Finding cost data includes revisions and is for the year ended 12/31/01.

(1)    LTM income statement data pro forma for the acquisition of Prize Energy Corp.

(2)    LTM income statement data pro forma for the acquisition of Canaan Energy Company.

(3)    Due to insufficient disclosure, Cimarex Energy Co. drilling data is not pro forma for the merger and instead is historical data for Key Production Company, Inc.

(4)    Data for the year ended 12/31/02.

(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 Commodity Price Assumptions
	$3.22 Gas (1)	$3.50 Gas	$4.25 Gas	$5.00 Gas
	$25.27 Oil (1)	$22.00 Oil	$24.50 Oil	$28.00 Oil
Earnings	$14 MM	$25 MM	$35 MM	$48 M
EPS	$.55	$.73	$1.02	$1.40
Operating Income	$47 MM	$62 MM	$78 MM	$98 MM
Cash Flow	$80 MM	$101 MM	$118 MM	$138 MM
EBITDA	$100 MM	$120 MM	$137 MM	$157 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 assuming the full exercise of the underwriters' over-allotment option). 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.

[textbox indicating information on this slide constitutes a "forward-looking statement".]

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

Cash flow from operating activities	$78 MM
Add: Changes in 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	2003 Guidance NYMEX
	Actual	Commodity Price Assumptions
	$3.22 Gas	$3.50 Gas	$4.25 Gas	$5.00 Gas
	$25.27 Oil	$22.00 Oil	$24.50 Oil	$28.00 Oil
	($ in millions)
Net Income	$14	$25	$35	$48
Deferred Income Taxes	9	15	22	30
Interest Expense	21	19	19	18
Depreciation, Depletion and Amortization	56	61	61	61
EBITDA	$100	$120	$137	$157

(slide 17)
Gas Hedges in Place Through 2004
[chart showing gas hedges in place by quarter for the years 2003 and 2004.]

	Type	Hedged Volumes	Average Price per Mcf (or Floor / Ceiling)	Percent of Total 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	14.0 Bcf	$3.71 / $5.44	25 - 30%

Note: Southwestern has approximately 340,000 barrels of oil hedged at a fixed WTI price of $26.58 per barrel in 2003.

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 18)
Summary of Follow-On Offering
Captures Overton value in a high commodity price environment.
        - -        PVI= 1.9 @ $4.00 gas price.
Accelerates production and reserve growth.
Improves balance sheet and financial flexibility.
        - -        Debt-to-capital ratio improves to 48.6% (pro forma) from 65.9% at 12/31/02.
Improves liquidity - 42 new institutional holders added.