EXHIBIT 99.1

Slide Presentation dated May 25, 2006

The following slides will be presented by Harold M. Korell, President and Chief Executive Officer of Southwestern Energy Company at the Annual Meeting of Shareholders of Southwestern Energy Company held in Houston, TX.

(Cover)
Southwestern Energy Company

2006 Annual Meeting

May 25, 2006

NYSE: SWN

The left side of this slide contains a picture of a Monopoly© board game. The Company's formula is located in the bottom-left corner.  The top-right corner of this slide contains the company logo.

© 2006 Hasbro

(Slide 1)
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. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company’s future operations, are forward-looking statements. 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. The company has no obligation and makes no undertaking to publicly update or revise any forward-looking statements. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company’s actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in commodity prices for natural gas and oil; the timing and extent of the company’s success in discovering, developing, producing and estimating reserves; the extent to which the Fayetteville Shale play can replicate the results of other productive shale gas plays; the potential for significant variability in reservoir characteristics of the Fayetteville Shale over such a large acreage position; the extent of the company’s success in drilling and completing horizontal wells; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the company’s lack of experience owning and operating drilling rigs; the company’s ability to fund its planned capital expenditures; future property acquisition or divestiture activities; the effects of weather and regulation on the company’s gas distribution segment; increased competition; the impact of federal, state and local government regulation; the financial impact of accounting regulations and critical accounting policies; changing market conditions and prices (including regional basis differentials); the comparative cost of alternative fuels; conditions in capital markets and changes in interest rates; the availability of oil field personnel, services, drilling rigs and other equipment; and any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

The Securities and Exchange Commission has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms “estimated ultimate recovery,” “EUR,” “probable,” “possible,” and “non-proven” reserves, reserve “potential” or “upside” or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company.

(Slide 2)
About Southwestern

* Focused on domestic exploration and production of natural gas.
	* 827 Bcfe of reserves; 93% natural gas; 13.6 R/P at year-end 2005.
* E&P strategy built on organic growth through the drillbit.
	* Approximately 80% of planned E&P capital allocated to drilling in 2006.
* Track record of adding significant reserves at low costs.
	* From 1999 through 2005, we've averaged annual production growth of 11%, reserve growth of 15%, 263% reserve replacement, and F&D cost of $1.47 per Mcfe.
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to approximately $5 billion today.
* Strategy built on the Formula:
	The Right People doing the Right Things, wisely investing the cash flow from the underlying Assets will create Value+.

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

(Slide 3)
Recent Developments

* Fiscal Year 2005.
	* Net income of $147.8 million, up 43%.
	* Discretionary cash flow of $321.8 million, up 35%.
	* Production of 61.0 Bcfe (up 13%) and reserves of 826.8 Bcfe (up 28%).
	* Equity offering in September 2005 to accelerate development of Fayetteville Shale play.

* First Quarter 2006.
	* Net income of $58.4 million, up 79%.
	* Discretionary cash flow of $125.4 million, up 70%.
	* Production of 15.9 Bcfe (up 14%); 2006 production projected at 74-76 Bcfe (up 21-25%).
	* Capital investments of $166.5 million, more than double prior year period.

* Operations Update
	* Overton and Ranger Anticline development programs delivering high-return growth.
	* Fayetteville Shale play - progress in horizontal drilling and confirmation of play.
		* Through May 22, 2006, 78 wells were on production, 32 of which were horizontal wells.

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

(Slide 4)
Proven Track Record

This slide contains bar charts for the periods ended December 31.

	1999	2000	2001	2002	2003	2004	2005	2006E
Production (Bcfe)	32.9	35.7	39.8	40.1	41.2	54.1	61.0	74-76E
Reserve Replacement	150%	196%	224%	209%	351%	388%	450%
EBITDA ($MM)(1)	$75.4	$104.1	$133.9	$98.6	$151.4	$255.3	$345.9
F&D Cost ($/Mcfe)	$1.20	$0.99	$1.11	$1.02	$1.18	$1.34	$1.51

Note: Reserve data excludes reserve revisions and capital investments in drilling rigs.

(1)    EBITDA is a non-GAAP financial measure.

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

(Slide 5)
Southwestern Energy Company

This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and New Mexico with shadings to denote the Arkoma and Permian Basins, the Gulf Coast and the East Texas regions. Lines trace gas distribution pipelines and the Ozark Pipeline.

E&P Segment

* 2005: 827 Bcfe of Reserves
	93% Natural Gas
	Production: 61.0 Bcfe
* 2006 Est. Production: 74-76 Bcfe

Arkoma

* Reserves - 372.0 Bcf (45%)

* Production - 22.0 Bcf (36%)

East Texas

* Reserves - 368.7 Bcfe (45%)

* Production - 28.2 Bcfe (46%)

Utility Segment

* 150,000 customers in North Arkansas

* Service area includes 6th fastest growing region in U.S. and the Milken Institute's 8th "Best Performing City"

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

(Slide 6)
Capital Expenditures

This slide contains a bar chart of Company capital investments, summarized as follows:

					2006
	2002	2003	2004	2005	Plan
	($ in millions)
Utility & Other	$6.9	$9.3	$13.0	$15.9	$22.3
Property Acquisitions	$0.1	$ -	$14.2	$ -	$0.0
Cap. Exp. & Other	$10.9	$12.4	$17.9	$32.4	$73.2
Leasehold & Seismic	$9.2	$19.0	$21.1	$60.6	$70.6
Development Drilling	$46.3	$119.7	$208.7	$287.6	$522.9
Exploration Drilling	$18.7	$19.8	$20.1	$35.6	$25.0
Midstream Services	$0.0	$0.0	$0.0	$15.8	$37.6
Rig Commitment	$0.0	$0.0	$0.0	$35.2	$78.5
Total	$92.1	$180.2	$295.0	$483.1	$830.1

This slide also contains a pie chart of Company's preliminary planned 2006 capital expenditures by area of operation, summarized as follows:

	% of Total
	Capital Investments
Arkoma Fayetteville Shale	41%
East Texas	24%
Arkoma	11%
Drilling Rigs	9%
Other E&P	5%
Midstream	4%
Permian/Gulf Coast	3%
Utility	3%

* E&P capital program heavily weighted to low-risk drilling in 2006.

* Approximately 80% of E&P capital is expected to be allocated to drilling in 2006.

* Plan to invest approximately $338 million in 2006 in Fayetteville Shale play.

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

(Slide 7)

East Texas - Overton Field

This slide contains a map of Smith County, Texas where the Overton Field is located.  Existing wells at year-end 2004 and 2005 and 2006 development well locations are denoted.  It is stated that the Overton Field contains 17,600 acres and the South Overton Farm-in Acreage contains 6,800 acres.

Overton Field Reserve Potential:

		Approx.	Reserve
	Well	Spacing	Adds
	Count	(Acres)	(Net Bcfe)
Original Wells	16	640	22
2001 - 2002 Development	33	365	70
2003 Development	57	170	98
2004 Development	83	100	145
2005 Development	80	70	102
Planned 2006 Development	83	60

Overton Field 2003-2005 Avg Results:⁽¹⁾

Reserve Replacement:	491%
LOE Cost (incl. Taxes) ($/Mcfe):	$0.51
F&D Cost ($/Mcfe):	$1.32

⁽¹⁾ Including reserve revisions.

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

(Slide 8)
Overton Field Gross Production

The graph contained in this slide displays the Overton Field gross production rate (MMcfe/d) from the year 2000 to December 2005. Additionally, in early 2003, the graph indicates an accelerated drilling program resulting from an equity offering. In 2004, the graph indicates addition of a fifth rig and curtailment issues.

Overton Net Production:

	Bcfe
2000	0.3
2001	2.3
2002	5.9
2003	13.6
2004	21.8
2005	26.7
2006 Forecast	27 - 29

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

(Slide 9)
Overton Field - Improved Drilling Results

This slide of drilling days versus depth portrays 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 in 2001 SWN decreased that rate to 35 days.  It was further decreased to 27 days in 2002, 23 days in 2003, 19 days in 2004, and 18 days in 2005.

* Reduced drilling time by >50%.

* Increased initial production by 200%.

* Increased gross reserves by 60% (avg. gross EUR of 1.8 Bcfe per well in 2005)

(Slide 10)

Arkoma Basin - Conventional

This slide contains a map of Arkansas and Oklahoma with shading to denote the Arkoma Basin. The Ranger Anticline and the area known as the Fairway are further noted. 

Arkoma Basin 2003-2005 Avg Results:⁽¹⁾

Reserve replacement:	239%
LOE Cost (incl. Taxes) ($/Mcf):	$0.54
F&D Cost ($/Mcf):	$1.06

Ranger Anticline (inception thru 12/31/05):⁽¹⁾

Success:	77/87
Net EUR:	82.1 Bcf
F&D/Mcf:	$1.07

(1) Including reserve revisions.

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

(Slide 11)
Ranger Anticline

This slide contains a map of the Ranger Anticline prospect with the Company's exploratory and held by production acreage designated with shading.  Also shown are SWN's producing wells at 12/31/05, and 2006 proposed wells.

Ranger Anticline (inception thru 12/31/05):⁽¹⁾

Success:	77/87
Net EUR:	82.1 Bcf
F&D/Mcf:	$1.07

Ranger Anticline Potential:

		Reserve
	Well	Adds
	Count	(Net Bcfe)
Successful Wells at 12/31/02	13	14
Successful Wells in 2003	10	12
Successful Wells in 2004	20	31
Successful Wells in 2005	34	25
Planned 2006 Drilling Program	60
Future Potential Locations	138

(1) Including reserve revisions.

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

(Slide 12)

Fayetteville Shale Play

This slide contains a map of Oklahoma, Arkansas, and portions of Louisiana and Texas.  Shading denotes the Fayetteville Shale in the Arkoma Basin, the Barnett Shale in the Fort Worth Basin and the Frontal Belt area.

* Mississippian-age shale, geological equivalent of the Barnett Shale in north Texas.

* The shale appears to be laterally extensive across several counties in Arkansas.

* SWN currently holds approximately 880,000 net acres in the Fayetteville Shale play area (equivalent to over 1,300 square miles).

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

(Slide 13)
SWN Fayetteville Shale Focus Area

This slide contains a map of the Fayetteville Shale in Arkansas.  The focus Area and existing pilot wells are indicated.  The Scotland Field, Gravel Hill Field, Griffin Mountain Field, Cove Creek Field, New Quitman Field, Moorefield Test and Chattanooga Test are also designated.

* As of May 22, 2006, we have drilled and completed 90 wells in 18 separate pilot areas in 7 counties.

* The Arkansas Oil & Gas Commission has approved field rules for 5 pilot areas.

* We anticipate drilling 175 to 200 wells in 2006, nearly all are planned to be horizontal.

* Assuming average ultimate production of 1.4 Bcf gross per well and 80-acre spacing, shaded area has the potential for 5,000 horizontal wells to be drilled for an estimated ultimate recovery of 7.0 Tcf gross.

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

(Slide 14)
Focus on Horizontal Wells

Results to date indicate that optimal development of the resource will primarily require horizontal wells.

* As of May 22, 2006, we have drilled and completed 38 horizontal wells with 59 in progress.

* The average initial gross test rate for 30 out of 32 completed horizontal wells is 2.0 MMcf/d (21 of which are nitrogen foam frac'd wells), excluding two horizontal wells which had mechanical problems.

* Production and modeling data through May 22, 2006, indicate that the ultimate gross production from these horizontal wells will be between 1.3 and 1.5 Bcf per well.

.

* Recent wells completed with slickwater are displaying shallower initial decline rates, potentially pointing toward higher EURs than nitrogen foam frac'd wells.

* Costs of recently completed slickwater frac'd wells have averaged $2.1 million per well with an average vertical depth of 3,300 feet and average lateral length of 2,200 feet.

* Expected drainage from horizontal wells is currently estimated to be less than 80 acres per well.

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

(Slide 15)
Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through May 21, 2006, for the company's horizontal wells drilled on acreage outside of that held by conventional production.  The production data is compared to 1.3 Bcf and 1.5 Bcf type curves from the company's reservoir simulation shale gas model, excluding two wells which encountered mechanical problems.  This graph also displays a composite curve showing results using slickwater fracture stimulation.

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

(Slide 16)
How Have We Been Doing?

Graph shows F&D cost ($/Mcfe), reserve replacement (%) and PVI ($/$) after new management, a new E&P team and a new strategy were implemented in 1997.

	1997	1998	1999	2000 (1)	2001	2002	2003	2004	2005
F&D cost ($/Mcfe)	$2.53	$1.10	$1.20	$.99	$1.11	$1.02	$1.18	$1.34	$1.51
Reserve replacement (%)	77%	129%	150%	196%	224%	209%	351%	388%	450%
PVI ($/$)	$ .56	$1.17	$1.07	$1.30	$1.40	$1.33	$1.42	$1.40	$1.43

Note:  All metrics calculated exclude reserve revisions and capital investments in drilling rigs.

(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 17)
Southwestern Energy Company

2006 Annual Meeting

May 25, 2006

NYSE: SWN

The left side of this slide contains a picture of a Monopoly© board game. The Company's formula is located in the bottom-left corner.  The top-right corner of this slide contains the company logo.

© 2006 Hasbro

(Slide 18)
U.S. Gas Consumption and Production

This slide displays U.S. gas production versus U.S. gas consumption from 1975 to the present. Net imports for the same period are also given.

Source:  EIA

(Slide 19)
U.S. Natural Gas Production Decline Rate

This graph portrays U.S. natural gas production history.  The graph indicates a 32% 2006E decline rate.

	Production Decline Rate of Base
1990		17%
1991		17%
1992		16%
1993		18%
1994		19%
1995		19%
1996		20%
1997		21%
1998		23%
1999		23%
2000		25%
2001E		24%
2002E		27%
2003E		28%
2004E		29%
2005E		30%
2006E		32%

Utilizes data supplied by IHS Energy; Copyright IHS Energy

Chart prepared by and Property of EOG Resources, Inc.; Copyright 2006

(Slide 20)
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 2006.

Source:  Edison Electric Institute

(Slide 21)
NYMEX Gas Prices

This line graph represents NYMEX gas prices in $/Mcf from 2000 to 2006.

Source:  Bloomberg

(Slide 22)
U.S. Gas Drilling

This line graph denotes the number of rigs drilling for gas through the period 1988 to 2006.

Source:  Baker Hughes

(Slide 23)
West Texas Intermediate Oil Prices

This line graph shows the price of West Texas Intermediate oil in $/Bbl for the years 2000 to 2006.

Source:  Bloomberg

(Slide 24)
Oil and Gas Price Comparison

This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu and $/Bbl, respectively, for the period 1994 to 2006.

Source:  Bloomberg

(Slide 25)
Gas Hedges in Place Through 2008

This slide contains a bar chart detailing gas hedges in place by quarter for year 2006, year 2007, and year 2008.  A summary of these outstanding gas hedges is as follows:

			Average Price per Mcf	Percent
	Type	Hedged Volumes	(or Floor/Ceiling)	Hedged
2006	Swaps	7.0 Bcf	$6.27	10%
	Collars	43.0 Bcf	$5.47 / $10.13	61%
2007	Swaps	12.0 Bcf	$6.66	-
	Collars	30.0 Bcf	$6.71 / $12.18	-
2008	Collars	12.0 Bcf	$7.77 / $14.81	-

Note:  Southwestern has approximately 120,000 barrels of oil hedged at a fixed WTI price of $37.30 per barrel in 2006.