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)   November 13, 2002
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)
- 1 -

Item 7.(c)

Exhibits

(99.1) Transcript of slide presentation accompanying the November 13, 2002 presentation to investors at the Houstonian Hotel, Club and Spa in Houston, Texas during the RBC Capital Markets North American Energy Conference.

Item 9.

Regulation FD Disclosures

            On November 13, 2002, Harold M. Korell, President and Chief Executive Officer for Southwestern Energy Company, made a presentation to investors at the Houstonian Hotel, Club and Spa in Houston, Texas for the RBC Capital Markets North American Energy Conference. The slide show was made available on the Company's web site (www.swn.com) the day of the presentation and a transcript of that 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

- 2 -

EXHIBIT INDEX
Exhibit No.	Description
99.1	Transcript of slide presentation accompanying the November 13, 2002 presentation to investors at the Houstonian Hotel, Club and Spa in Houston, Texas during the RBC Capital Markets North American Energy Conference.

- 3 -

EX-99.1 CHARTER

Exhibit 99.1
Slide Presentation dated November 13, 2002

Slides prepared for use with November 13, 2002, presentation to investors at the Houstonian Hotel, Club and Spa in Houston, Texas during the RBC Capital Markets North American Energy Conference.

(slide 1)
Southwestern Energy Company
Presentation to RBC Capital Markets North American Energy Conference
November 13, 2002
[NYSE: SWN]

[picture of crescent and other wrenches.]

(slide 2)
Business Strategy
[slide stating formula which represents Company's strategy:  The Right People Doing the Right Things, supported by the value of underlying Assets will create Value⁺.]

(slide 3)
[slide stating formula which represents Company's strategy emphasizing the Right People doing the Right Things.]

(slide 4)
[slide stating formula which represents Company's strategy emphasizing the Right People doing the Right Things, wisely investing the cash flow from the underlying Assets.]

(slide 5)
[slide stating formula which represents Company's strategy emphasizing the Right People doing the Right Things, wisely investing the cash flow from the underlying Assets will create Value⁺.]

(slide 6)
Southwestern Energy Company
[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; Anadarko Basin in North Texas and western Oklahoma, including the panhandle; 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.]

2001 Reserves: 402.0 Bcfe, 90% Gas
Shares Outstanding; 25.7 MM
52-Week Range: $9.64 - $15.19
Debt Ratings: BBB (S&P)
                     Ba2 (Moody's)

(slide7)
2001 Segment Contributions
[pie charts showing contribution from E&P, Gas Distribution, and Marketing & Other.]

	Operating Income	Cash Flow	Assets	Capital Investments
Exploration & Production	84%	86%	71%	93%
Gas Distribution	12%	12%	23%	5%
Marketing & Other	4%	2%	6%	2%
Total	$57.8 MM	$112.7 MM	$743.1 MM	$106.1 MM

Note: Cash Flow is before changes in working capital.

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, 2001 is hereby furnished:

Cash flow from operating activities	$144.6 MM
Less: Changes in assets and liabilities	31.9 MM
Cash flow (as presented)	$112.7 MM

(slide 8)
Cash Flow per Mcfe - SWN is Competitive
[graphs comparing Southwestern Energy Company's 3-year average Cash Flow per Mcfe of Production and Cash Flow per Mcfe of Reserves versus a peer group.]

Notes: All data as of December 31, 1999, 2000 and 2001. Cash Flow defied as Cash Flow from Operations before changes in working capital.
BR- Burlington Resources, CHK- Chesapeake Energy, COG - Cabot Oil & Gas, DVN - Devon Energy, EOG- EOG Resources, NFX - Newfield Exploration, NBL - Noble Affiliates, OEI - Ocean Energy, PXD- Pioneer Natural Resources, VPI - Vintage Petroleum, WRC - Westport Resources, XTO - XTO Energy.

(slide 9)
Key Developments - Organic Growth
1999
Positive E&P results.
        - -        Reserve additions of 49 Bcfe replaced 150% of production at $1.20 per Mcfe.*
        - -        First success in Gulf Coast exploration (Gloria).
        - -        Developed excellent inventory of internally-generated exploration prospects.
2000
Strong E&P results.
        - -        Reserve additions of 70 Bcfe replaced 196% of production at $0.99 per Mcfe.*
        - -        Production increased over 8% from 1999 levels.
        - -        Two meaningful discoveries in South Louisiana (N. Grosbec, Havilah).
Arkansas Supreme Court upheld jury verdict and judgment of $109 million.
2001
Record E&P results.
        - -        Reserve additions of 89 Bcfe replaced 224% of production at $1.11 per Mcfe.*
        - -        Production increased 11% from 2000 levels.
        - -        Three exploration discoveries in South Louisiana (Malone, Horeb, Crowne).
Drilled 15 wells at Overton. Well performance exceeded expectations.
Reduced long-term debt by $46 million.

*Excludes reserve revisions.

(slide 10)
E&P Results - Standing Out
For the Periods Ended December 31,

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

Note: Reserve data excludes reserve revisions.

(slide 11)
Objectives
Primary
Maximize the net present value of the enterprise.
        - -        Invest in the highest PVI projects.
        - -        In 2002, add $1.30 to $1.50 of discounted value for each dollar invested.
        - -        Maximize cash flow to fund E&P program and pay down debt.

Secondary
Over a multi-year program, achieve 10% annual growth in production.
Reduce debt-to-total capital ratio over time to 50%.

(slide 12)
What is PVI?
PVI = Present Value Added per Dollar Invested
PVI = PV₁₀divided by Investment = PV₁₀((Price * Mcfe) - (Cost * Mcfe)) divided by Investment

(slide 13)
E&P Assets and Strategy - Organic Growth
[map showing the states of Arkansas, Louisiana, Texas, Oklahoma and New Mexico with the following areas identified: Mid-Continent in north Texas and western Oklahoma, including the panhandle; Arkoma in western Arkansas and eastern Oklahoma; Texas/New Mexico in southeast New Mexico and eastern, central and the gulf coast areas of Texas; South Louisiana in gulf coast region of Louisiana; and Overton in eastern Texas.]

Mid-Continent
	Reserves - 36.6 Bcfe (9%)
	Production - 2.8 Bcfe (7%)
Arkoma
	Reserves - 186.0 Bcfe (46%)
	Production - 22.3 Bcf (56%)
	2002 Capital - $18.5 MM (23%)
Texas/New Mexico
	Reserves - 79.4 Bcfe (20%)
	Production - 7.6 Bcfe (19%)
	2002 Capital - $9.5 MM (12%)
South Louisiana
	Reserves - 42.4 Bcfe (11%)
	Production - 4.8 Bcfe (12%)
	2002 Capital - $21.2 MM (26%)
East Texas
	Reserves - 57.6 Bcfe (14%)
	Production - 2.3 Bcf (6%)
	2002 Capital - $32.1 MM (39%)

(slide 14)
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: 96%
            LOE Cost (incl. Taxes) ($/Mcf): $0.26
            F&D Cost ($/Mcf): $1.05

Ranger Anticline
            Success: 10/14 wells
            Net EUR: 12.4 Bcf
            F&D/Mcf: $.69

Haileyville
            Success: 13/20 wells
            Net EUR: 9.7 Bcf
            F&D/Mcf: $.74

(slide 15)
Overton Field - Multi-Year Drilling Program
[map showing Overton Field area, including South Overton farm-in acreage of 5,800 acres, with producing well locations.]

		Overton Field Drilling Potential
	# Wells @ 80s		Net Reserve Potential
Year-End 2001	31		58
2002 Drilling	18		33*
Future Development	76		137*
TOTAL	125		228
* Estimated gross reserves of 2.3 Bcfe per well.
Note: Excludes South Overton farm-in acreage.

Overton Field Gross Production Rate
[graph showing Overton Field gross production rate increasing from 1.7 MMcfe/d in June 2000 to over 20.0 MMcfe/d in August 2002.]

(slide 16)
South Louisiana 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.]

Recent Gulf Coast success: 8 successful wells out of last 14 drilled.
Current gross production from discoveries: 46 MMcfe per day (9 MMcfe per day net to SWN).
Exploration inventory with net reserve potential of 225 Bcfe through 2^nd quarter of 2003.
Currently processing seismic data for Duck Lake 3-D project.

(slide 17)
Exploration Potential - 225 Net Bcfe

						Gross Res.	Net Res.
		Spud	Working			Potential	Potential
Prospect Name	Operator	Date	Interest	Depth	Objective	(Bcfe)	(Bcfe)
Arkoma Basin
Midway	SWN	4Q	60.0%	11,400	Atoka	39.0	20.5
Permian Basin
N. Roepke	SWN	Producing	88.0%	8,100	Devonian	3.0	2.0
Birds of Prey	SWN	Evaluating	100.0%	5,000	Cherry Canyon	6.0	5.0
High Lonesome	SWN	Prod/Eval	25.0%	11,000	Morrow	15.0	3.0
Gaucho Deep	Devon	1Q 2003	50.0%	15,000	Devonian	30.0	12.0
Gulf Coast
Crowne	SWN	Prod/Eval	40.0%	13,500	Planulina	35.0	10.1
Tulleymore	SWN	Dry	40.0%	12,500	Planulina	-	-
Bushmills	SWN	Dry	70.0%	15,200	Planulina	-	-
W. Grand Chenier	Ballard	Completing	25.7%	6,700	Big hum	2.0	0.4
Middle Chenier	Ballard	Completing	25.7%	13,500	Planulina	6.0	1.1
SE Grand Lake	Ballard	Dry	25.7%	14,000	Planulina	-	-
Little Chenier Bayou	Ballard	Drilling	25.7%	11,000	Siph D	35.0	6.7
W. Grand Chenier Deep	Ballard	4Q	25.7%	12,500	Siph D	40.0	7.6
Piedmont	SWN	Drilling	62.5%	13,300	Planulina	28.3	14.0
Jericho	SWN	1Q 2003	35.0%	14,200	Frio	72.0	18.9
Shiloh	SWN	1Q 2003	62.5%	13,500	Planulina	164.0	79.9
Ben Nevis	SWN	2Q 2003	50.0%	12,900	Miocene	45.0	16.0
Tigris	SWN	2Q 2003	50.0%	13,600	Frio	74.0	27.8
			Total Reserve Potential			594.3	224.9

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

(slide 18)
E&P Capital Investments
[bar chart showing Southwestern Energy Company's capital investment by general business activities.]

1999	$59.0
2000	$69.2
2001	$85.5 (1)
2002 Budget	$81.3

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

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

East Texas	39%
South Louisiana	26%
Arkoma	23%
Permian	12%

(slide 19)
Outlook for 2002
Targets:
        - -        Production target of 40 - 41 Bcfe in 2002.
        - -        Excess cash flow goes toward long-term debt reduction.

	NYMEX Commodity Price Assumptions
	$2.25 Gas	$3.00 Gas	$3.50 Gas	$3.75 Gas
	$21.00 Oil	$21.00 Oil	$21.00 Oil	$21.00 Oil
Earnings	$10 MM	$15 MM	$19 MM	$21 MM
EPS	$.40	$.60	$.73	$.80
Cash Flow	$76 MM	$85 MM	$91 MM	$95 MM
CFPS	$3.00	$3.30	$3.50	$3.67
EBITDA	$97 MM	$106 MM	$112 MM	$116 MM

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

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.

	$2.25 Gas	$3.00 Gas	$3.50 Gas	$3.75 Gas
	$21.00 Oil	$21.00 Oil	$21.00 Oil	$21.00 Oil
		($ in millions)
Net Income	$10	$15	$19	$21
Deferred Income Taxes	6	10	12	14
Interest Expense	22	22	22	22
Depreciation, Depletion and Amortization	59	59	59	59
EBITDA	$97	$106	$112	$116

(slide 20)
Gas Hedges in Place Through 2003
[chart showing gas hedges in place by quarter for the years 2003 and 2004.]

	Hedged Volumes	Average Floor Price
2002	28.0 Bcf	$3.10/Mcf
2003	27.4 Bcf	$3.28/Mcf
2004	7.2 Bcf	$3.58/Mcf

Note: Southwestern has approximately 280,000 barrels of oil hedged at a fixed WTI price of $20.07 per barrel in 2002 and 240,000 barrels of oil hedged at a fixed WTI price of $25.40 per barrel in 2003.

(slide 21)
The Right People Doing the Right Things
[graph showing the company's results in PVI, F&D Cost and Reserve Replacement from 1997 to 2001.]

Note: PVI metrics calculated using pricing in effect at year-end (except for 2000 which was calculated at $3.00 per Mcf natural gas price). All metrics calculated exclude reserve revisions.

	1997	1998	1999	2000	2001
F&D Cost ($/Mcfe)	$2.53	$1.10	$1.20	$.99	$1.11
Reserve Replacement	77%	129%	150%	196%	224%
PVI ($/$)	$ .56	$1.17	$1.07	$1.30	$1.40

(slide 22)
The Road to V⁺
Invest in the Highest PVI Projects.
Maximize Cash Flow.
Stay the Course with Our Balanced Strategy.
Build on Exploration Success.
Reduce Debt with Excess Cash Flow.
Deliver the Numbers.
        - -        Production and Reserve Growth.
        - -        Add value for Every Dollar Invested.
Continue to Tell Our Story.

(slide 23)
Forward-Looking Statements

All statements, other than historical financial information, 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. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. 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 for derivative instruments, 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.

(slide 24)
Appendix

(slide 25)
Financial and Operational Summary

		9 Months Ending September 30,		Year Ended
		2002	2001	2001	2000(1)	1999
($ in millions, except per share amounts)
Revenues	$188.8		$272.5	$344.9	$363.9	$280.4
EBITDA	74.9		103.4	134.9	103.8	76.7
Net Income	9.8		27.9	35.3	20.5	9.9
Cash Flow (2)	58.9		86.4	112.7	82.4	60.8
Diluted EPS	$0.37		$1.09	$1.38	$0.82	$0.40
Diluted CFPS	$2.26		$3.38	$4.40	$3.29	$2.44
Production (Bcfe)	30.6		29.3	39.8	35.7	32.9
Avg. Gas Price ($/Mcf)	$2.89		$3.97	$3.85	$2.88	$2.21
Avg. Oil Price ($/Bbl)	$20.87		$24.67	$23.55	$22.99	$17.11
Finding Cost ($/Mcfe) (3)				$1.11	$0.99	$1.20
Reserve Replacement (%) (3)				224%	196%	150%

(1)        Before the effects of unusual and extraordinary items.
(2)        Cash Flow is before changes in working capital.
(3)        Excluding reserve revisions.

In accordance with Regulation G, a reconciliation of Cash Flow, as presented, to Cash Flow from Operating Activities from the Company's Form 10-Q for the nine months ended September 30, 2002, and Form 10-K for the year ended December 31, 2001 is hereby furnished:

		9 Months Ending
		September 30,			Year Ended
			2002	2001	2001	2000(1)	1999
		($in millions)
Cash flow from operating activities			$68.4	$114.7	$144.6	$58.1	$58.1
Less:	Changes in assets and liabilities		9.5	28.3	31.9	(24.3)	(2.7)
Cash flow (as presented)			$58.9	$86.4	$112.7	$82.4	$60.8
	(1) Before the effects of unusual and extraordinary items

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.

	9 Months Ending
	September 30,			Year Ended
		2002	2001	2001	2000(1)	1999
	($in millions)
Net Income		$9.8	$27.9	$35.3	$20.5	$9.9
Deferred Income Taxes		6.1	17.8	21.9	12.9	6.4
Interest Expense		16.1	18.3	23.7	23.2	17.4
Depreciation, Depletion and Amortization		42.9	39.4	54.0	47.2	43.0
EBITDA		$74.9	$103.4	$134.9	$103.8	$76.7

(slide 26)
U.S. Gas Consumption and Sources
[graph showing U.S. gas consumption, U.S. gas production, and net imports in Bcf per year from 1975 to 2001; textbox indicating that U.S. gas production is basically flat since 1994.]
Source: EIA

(slide 27)
U.S. Electricity Consumption on the Rise
[graph showing an increase in U.S. electricity consumption in billion kilowatt hours per month from 1990 to 2002.]
Source: Edison Electric Institute

(slide 28)
NYMEX Gas Prices
[graph showing NYMEX gas prices in $/Mcf from 2000 through 2002.]
Source: Bloomberg

(slide 29)
U.S. Gas Drilling
[graph showing the number of rigs drilling for gas from 1988 through 2002.]
Source: Baker Hughes

(slide 30)
West Texas Intermediate Oil Prices
[graph showing intermediate oil prices in $/Bbl in West Texas from 2000 through 2002.]
Source: Bloomberg

(slide 31)
Oil and Gas Price Comparison
[graph comparing prices of Henry Hub natural gas and WTI crude oil from 1994 through 2002.]
Source: Bloomberg