Exhibit 99.1

Slide Presentation dated September 27, 2002

Slides prepared for use with September 27, 2002, presentation to investors at the John S. Herold Pacesetters Energy Conference .

(slide 1)
Southwestern Energy Company
Presentation to 2002 John S. Herold Pacesetters Energy Conference
[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 +.]

(slide3)
Creating the Netback
Costs are only part of the equation. Swn's focus is creating the netback! The economic concept that is the foundation for all that we do is PVI.

(slide 4)
What is PVI?
PVI = Present Value Added per Dollar Invested
PVI = PV¹⁰ divided by Investment = PV¹⁰ ((Price * Mcfe) - (Cost * Mcfe)) divided by Investment

(slide 5)
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.

(slide 6)
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%)
Texas/New Mexico
	Reserves - 79.4 Bcfe (20%)
	Production - 7.6 Bcfe (19%)
South Louisiana
	Reserves - 42.4 Bcfe (11%)
	Production - 4.8 Bcfe (12%)
Overton
	Reserves - 57.6 Bcfe (14%)
	Production - 2.3 Bcf (6%)
Arkoma and Overton reflect low LOE & F&D South Louisiana reflects high rates

(Slide 7)
Strategy

• Invest in the highest PVI projects. In 2002, add $1.30 to $1.50 of discounted value for each dollar invested.
  • Focus is on adding value through drilling;
  • Not on acquisitions - not buying just to get bigger.
• Maximize cash flow to fund E&P program and pay down debt.
• Over a multi-year program, achieve 10% annual growth in production and reserves.
• Reduce debt-to-total capital ratio over time to 50%

(slide 8)
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 (table with LOE Cost and F&D Cost circled)
            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 9)
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	#Wells
		@160s	@80s
	Orginial wells	16	16
	2001 Drilling	15	15
	Future Development	32	94
	TOTAL	63	125
Purchased 7.5 Bcfe for $6.1 million in 2000 (developed at 640-acre spacing). Downspacing to 160 acre units. Have drilled 7 wells in the first half of 2002. Opportunity to downspace to 80-acre spacing (87 wells).

Overton Acquisition - Average working interest -97%

(slide 10)
 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 11)
Drilling Time Improvement at Overton
[graph showing the depth and drilling days of the Last 3 Wells,  SWN's Average and Prior Drilling]

(slide 12)
Overton Drilling Economics

Revenues	$3.75per Mcfe
Production costs	$0.40 per Mcfe
Cash netback	$3.35 per Mcfe
F& D cost	$0.85 per Mcfe
Results:
Completed Well Cost	Pretax ROR	Pretax PVI
$1.5 MM(1)	43%(2)	2.1(2)
(1) Current completed well cost estimate facilitated by pricing program.
(2) Assumes $3.75 per Mcf flat pricing and gross EUR of 2.3 Bcfe per well.
Forward -Looking Statement

(slide 13)
South Louisiana Exploration
[map showing location of the 2002 proposed wells, discovery wells, the 3-D project areas, the Horeb, Havilah, Malone, North Grosbec, Gloria, and Crowne Discoveries and Duck Lake seismic area..

	Discovery Date	W.I.	Current Gross Producing Rate
Gloria	Dec 1999	50%	1.0 MMcfd and 27 Bopd
North Grosbec	Feb 2000	25%	22.1 MMcfd and 802 Bopd
Havilah	Nov 2000	28%	4.2 MMcfd and 263 Bopd
Malone	Feb 2001	33%	10.3 MMcfd and 188 Bopd
Horeb	Nov 2001	21%	2.0 MMcfd and 30 Bopd
Crowne #1	Dec 2001	40%	3.0 MMcfd and 11Bopd

(slide 14)
Exploration Potential - 251 Net Bcfe

						Gross Res.	Net Res.
		Spud	Working			Potential	Potential
Prospect Name	Operator	Date	Interest	Depth	Objective	(Bcfe)	(Bcfe)
Arkoma Basin
Midway	SWN	4Q	80.5%	11,400	Atoka	39.0	27.0
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	45.0	8.6
SE Grand Lake	Ballard	Drilling	25.7%	14,000	Planulina	65.0	12.4
Little Chenier Bayou	Ballard	3Q	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	3Q	62.5%	12,700	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	1Q 2003	50.0%	12,900	Miocene	45.0	16.0
Tigris	SWN	1Q 2003	50.0%	13,600	Frio	74.0	27.8
				Total Reserve Potential		698.3	251.2
Forward-Looking Statement

(slide 15)
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

(slide16)
E&P Results - Standing Out
For the Periods Ended December 31, 2001

	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 17)
Keys to "Netback"

The Right People

• Creative and Innovative People.
• Appropriate Incentives for Employees and Contractors.

Doing the Right Things

• Focus on PVI.
  • Low Cost Operating Areas.
  • Areas of High Potential per $ of Investment.
• Apply Latest Technology.
• Find Gas.

(slide 18)
Gas Hedges in Place Through 2003
[chart showing gas hedges in place by quarter for the years 2002 and 2003]

	Hedged	Avg. Floor
Period	Volumes	Price
2002	27.4 Bcf	$3.07/Mcf
2003	27.4 Bcf	$3.28/Mcf
2004	7.2 Bcf	$3.58 Mcf

Note: Approximately .2 Bcf hedged at a fixed NYMEX price of $2.75 per Mcf in first six months of 2003.
Southwestern also has approximately 280,000 barrels of oil hedged at a fixed WTI price of $20.07 per barrel in 2002.

(slide 19)
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.