EXHIBIT 99.2

Slide Presentation dated May 14, 2003                                                                                    

Slides prepared for use with May 14, 2003 presentation to shareholders during the 2003 Annual Shareholders Meeting at the Wyndham Greenspoint in Houston, Texas.

(slide 1)
Southwestern Energy Company
2003 Annual Shareholders Meeting
May 14, 2003
[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.
	-	Over the past 4 years, we've averaged production growth of 7% per year, 197% reserve replacement, and F&D cost of $1.07 per Mcfe.

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)
The Year in Review - 2002

Exploration & Production
	-	Record production of 40.1 Bcfe compared to 39.8 Bcfe in 2001.
	-	Added 83.7 Bcfe of new reserves, replacing 209% of production at a find and develop cost of $1.02 per Mcfe.*
	-	Drilling and production performance at Overton exceeded expectations.
*Reserve data excludes reserve revisions.
Utility
	-	Added over 3,300 new retail customers.
	-	Set the stage for improved operating results by filing an $11.0 million rate increase in November, the first since 1996.
First Quarter 2003
	-	Follow-on equity offering completed in March 2003. Raised $103.3 million to accelerate development drilling at Overton Field and reduce debt.
	-	Improved our debt-to-capital ratio to 44% at 3/31/03 from 66% at 12/31/02.

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

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

Note: Reserve data excludes reserve revisions.

(slide 6)
Areas of Operation
[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.]
[Text boxes 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%)

(slide 7)
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 Plan	$158.6

(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	54%
Arkoma	18%
Gulf Coast	13%
Permian	4%
Other E&P	6%
Utility	5%

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

(slide 8)
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	53	120*	94*
2004 Proposed Development	53	80*	85*
Total	155	80*	290

* In higher potential areas.

(slide 9)
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.

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

(slide 10)
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	102	155

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

(slide 11)
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.

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

(slide 12)
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: 14/17 wells
        -        Net EUR: 15.6 Bcf
        -        F&D/Mcf: $.85

Haileyville
        -        Success: 16/24 wells
        -        Net EUR: 9.3 Bcf
        -        F&D/Mcf: $.82
Recent approval to develop field at 80-acre spacing.

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

(slide 13)
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

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

(slide 14)
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)	$4.25 Gas	$5.00 Gas
	$25.27 Oil (1)	$24.50 Oil	$28.00 Oil
Earnings	$14 MM	$33 - 36 MM	$45 - 48 MM
EPS	$.55	$.95 - $1.05	$1.30 - $1.40
Operating Income	$47 MM	$76 - 79 MM	$95 - 98 MM
Cash Flow	$80 MM	$117 - 120 MM	$136 - 139 MM
EBITDA	$100 MM	$134 - 137 MM	$152 - 155 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.

[text box 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	$4.25 Gas	$5.00 Gas
	$25.27 Oil	$24.50 Oil	$28.00 Oil
	($ in millions)
Net Income	$14	$33-$36	$45-$48
Deferred Income Taxes	9	19-21	26-28
Interest Expense	21	23-22	22-21
Depreciation, Depletion and Amortization	56	59-58	59-58
EBITDA	$100	$134-$137	$152-$155

(slide 15)
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 16)
YTD 2003 Stock Performance
[chart comparing Southwestern Energy Company's YTD percent return versus a peer group. Textbox stating Southwestern Energy Company's YTD percent return was up 26.1% and was at $14.44.]

(slide 17)
The Road to V⁺
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.