EXHIBIT 99.1

Slide Presentation dated December 19, 2006

The following slides will be presented by Harold M. Korell, Executive President and Chief Executive Officer of Southwestern Energy Company, to investors.

(Cover)
Southwestern Energy Company

December 2006 Update

NYSE: SWN

The left side of this slide contains a picture of a Monopoly© board game.  The caption above reads "Well Positioned."  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)
Southwestern Energy Company (NYSE: SWN)

General Information

Southwestern Energy Company is an integrated natural gas company whose wholly-owned subsidiaries are engaged in oil and gas exploration and production, natural gas gathering, transmission and marketing, and natural gas distribution.

Market Data as of December 18, 2006

Shares of Common Stock Outstanding	168,269,755
Market Capitalization	$6,194,000,000
Institutional Ownership	80.5%
Management Ownership	5.1%
52-Week Price Range	$24.80 (6/13/06) - $43.42 (1/23/06)

Investor Contacts

Greg D. Kerley
Executive Vice President and Chief Financial Officer

Phone:	(281) 618-4803
Fax:	(281) 618-4820

Brad D. Sylvester, CFA
Manager, Investor Relations

Phone:	(281) 618-4897
Fax:	(281) 618-4820

(Slide 2)
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 availability of oil field personnel, services, drilling rigs and other equipment, including pressure pumping equipment and crews in the Arkoma Basin; the timing and extent of changes in commodity prices for natural gas and oil; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; 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 relative 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; 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 3)
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.
	* Over 80% of planned E&P capital allocated to drilling in 2007.
* 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 over $6 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 4)
Recent Developments

*  First Nine Months 2006.
	*  Net income of $128.9 million, up 30%.
	*  Discretionary cash flow of $304.8 million, up 39%.
	*  Production of 51.6 Bcfe (up 14%); 2006 production projected at 72-73 Bcfe (growth of 18-20%).
	*  Capital investments of $632.1 million, up 85% compared to the prior year period.

* Operations Update.
	* East Texas and Ranger Anticline development programs delivering high-return growth.
	* Fayetteville Shale - progress in horizontal drilling and confirmation of play.
		* Through December 11, 2006, 157 wells were completed, including 77 SW/XL horizontal wells.
		* Production from Fayetteville Shale increased to approximately 84 MMcf per day at December 14th, compared to approximately 70 MMcf per day at October 23rd.

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

(Slide 5)
Proven Track Record

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

	1999	2000	2001	2002	2003	2004	2005	2006E	2007E
Production (Bcfe)	32.9	35.7	39.8	40.1	41.2	54.1	61.0	72-73E	105-110E
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. See explanation and reconciliation of EBITDA on page 33.

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

(Slide 6)
About the 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.

Exploration and Production Segment

* 2005: 827 Bcfe of Reserves
	93% Natural Gas
	Production: 61.0 Bcfe
* 2006 Est. Production: 72-73 Bcfe
* 2007 Est. Production: 105-110 Bcfe

Arkoma

* Reserves - 372.0 Bcf (45%)

* Production - 22.0 Bcf (36%)

East Texas

* Reserves - 368.7 Bcfe (45%)

* Production - 28.2 Bcfe (46%)

Gulf Coast

* Reserves - 27.5 Bcfe (3%)

* Production - 3.9 Bcfe (7%)

Permian

* Reserves - 58.6 Bcfe (7%)

* Production - 6.9 Bcfe (11%)

Gas Distribution 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"

* Southwestern operates in Arkansas, Texas, New Mexico, Oklahoma and Louisiana and has three segments: E&P, Midstream Services and Gas Distribution.

* E&P generates approximately 95% of operating income and EBITDA.

* Midstream Services and Gas Distribution segments provide operating synergies for the E&P business in addition to contributing to the stability of our cash flow.

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

(Slide 7)
Capital Expenditures

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

				2006	2007
	2003	2004	2005	Projected	Plan
	(in millions)
Utility & Other	$9.3	$13.0	$15.9	$22.3	$20.0
Property Acquisitions	$ -	$14.2	$ -	$ -	$ -
Cap. Exp. & Other	$12.4	$17.9	$32.4	$73.2	$86.0
Leasehold & Seismic	$19.0	$21.1	$60.6	$77.7	$139.0
Development Drilling	$119.7	$208.7	$287.6	$578.0	$937.0
Exploration Drilling	$19.8	$20.1	$35.6	$25.0	$75.0
Midstream Services	$0.0	$0.0	$15.8	$37.6	$84.0
Rig Commitment	$0.0	$0.0	$35.2	$111.2	$ -
Total	$180.2	$295.0	$483.1	$925.0	$1,341.0

This slide also contains a pie chart of Company's preliminary planned 2007 capital expenditures by area of operation, summarized as follows:

	% of Total
	Capital Investments
Arkoma Fayetteville Shale	65%
East Texas	12%
Arkoma	9%
Midstream	6%
Other E&P	4%
Permian/Gulf Coast	2%
Utility	2%

* E&P capital program heavily weighted to low-risk drilling in 2007.

* Over 80% of E&P capital is allocated to drilling in 2007.

* Plan to invest approximately $875 million in 2007 in Fayetteville Shale play.

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

(Slide 8)

East Texas

This slide contains a map of several counties in East Texas.  The Company's Overton and Angelina River Trend acreage positions are highlighted.  Various salt domes and the East Texas Salt Basin are also denoted on the map.  The cities of Tyler and Lufkin, Texas are displayed as reference points.

East Texas Activity:		Annual	Year-End
	Well	Production	Reserves
	Count	(Bcfe)	(Bcfe)
Original Wells (acquired)	16	0.3	22
2001 - 2002 Development	33	8.2	111
2003 Development	57	13.6	196
2004 Development	84	22.2	299
2005 Development	88	28.2	369
Planned 2006 Development	82	29 - 31
Planned 2007 Development	67	27 - 29

* Entered area in 2000 with purchase of Overton Field for $6.1 million.

* Current acreage position of 24,400 gross acres at Overton and 55,500 gross acres at Angelina.

* Over 300 wells drilled through September 30, 2006, with 100% success.

* Plan to drill 39 wells at Overton and 28 wells at Angelina in 2007.

* Potential for significant future development program at Angelina.

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

(Slide 9)

Arkoma Basin - Conventional

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

* 60+ years of experience in the basin, large acreage position of 428,000 net acres.

* 2007 capital program includes drilling 100 - 110 wells, including 50 - 60 wells in the company's growing Ranger Anticline area.

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 10)
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 9/30/06, 2006 remaining wells and 2007 proposed wells. A box denotes the successful extension wells.

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

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

* In July 2004, received approval to downspace field to 560 feet between wells.

* Current acreage position of 12,800 gross dev. acres and 49,900 gross undev. acres.

* Average working interest 50% - 100%.

* Plan to drill up to 60 wells in 2007.

* Area has significant growth potential/inventory.

* 2006 exploration success at Midway prospect, approx. 10 miles north of Ranger.

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
2006 Drilling Program	46
Planned 2007 Drilling Program	60
Future Potential Locations	>150

(1) Including reserve revisions.

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

(Slide 11)

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. The Wedington Incongruity is also denoted.

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

* Within the SWN play area, the shale appears to be laterally extensive across several counties in Arkansas, ranging in thickness from 50 to 550 feet and depths from 1,500 to 6,500 feet.

* SWN currently holds approximately 887,000 net acres in the Fayetteville Shale play area (equivalent to approximately 1,400 square miles).

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

(Slide 12)
Fayetteville Shale Focus Area

This slide contains a map of the Fayetteville Shale Focus Area in Arkansas.  Existing pilot areas are indicated.  The Scotland Field, Gravel Hill Field, Griffin Mountain Field, Cove Creek Field, New Quitman Field, Chattanooga Test and Ranger Anticline are also designated.  Additionally, the Carter #2-35H well (Moorefield) with an IP of 1.2 MMcf/d is indicated on the slide.

* As of December 11, 2006, SWN has drilled and completed 157 wells, of which 77 are horizontal SW/XL wells, in 28 separate pilot areas in 8 counties.

* The Arkansas Oil & Gas Commission has approved standardized field rules covering the Fayetteville Shale play area.

* We anticipate drilling 400 to 450 horizontal wells in 2007.

* Assuming average ultimate production of 1.4 Bcf gross per well and 80-acre spacing, shaded area has the potential for 8,000 horizontal wells to be drilled for an estimated ultimate recovery of 11.2 Tcf gross.

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

(Slide 13)
Fayetteville Shale - Gross Production

This line graph shows gross production in MMcf/d for the Fayetteville Shale from January 2006 to December 14, 2006. Gross production of approximately 84 MMcf/d as of December 14th.

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

(Slide 14)
Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through December 11, 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 typecurves from the company's reservoir simulation shale gas model.  This graph also displays two composite curves, one showing the SW/XL normalized production from the Company's horizontal wells and another showing the SW/XL production excluding mechanical issues.

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

(Slide 15)
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).

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

(Slide 16)
Outlook for 2007

* Production target of 72.0 - 73.0 Bcfe in 2006 (estimated growth of 18 - 20%).

* Production target of 105.0 - 110.0 Bcfe in 2007 (estimated growth of 45 - 50%).

	2005	2006 Guidance	2007 Guidance
	Actual	NYMEX Price Assumptions
	$8.62 Gas	$7.00 Gas	$7.00 Gas	$8.00 Gas
	$55.34 Oil	$60.00 Oil	$60.00 Oil	$65.00 Oil
Net Income	$147.8 MM	$160 - $165 MM	$200 - $205 MM	$245 - $250 MM
EPS	$0.95	$0.93 - $0.96	$1.16 - $1.19	$1.42 - $1.45
Operating Income	$245.9 MM	$245 - $250 MM	$355 - $360 MM	$425 - $430 MM
Net Cash Flow(1)	$321.8 MM	$390 - $400 MM	$590 - $600 MM	$660 - $670 MM
EBITDA(1)	$345.9 MM	$400 - $410 MM	$615 - $625 MM	$685 - $695 MM
CapEx	$483.1 MM	$925 MM	$1,341 MM	$1,341 MM

Note:   Guidance updated as of December 15, 2006.  2005 oil and gas prices represent actual average last-day NYMEX closing prices. 2006 oil and gas prices include actual last-day

NYMEX closing prices through November 2006 and assumes that the price deck above is held flat through the remainder of 2006.

(1)        Net cash flow is net cash flow before changes in operating assets and liabilities.  Net cash flow and EBITDA are non-GAAP financial measures.  See explanation and reconciliation

of non-GAAP financial measures on pages 32 and 33.

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

(Slide 17)
The Road to V⁺

* Invest in the Highest PVI Projects.
	* Continue Development of East Texas and the Ranger Anticline.
* Accelerate Development of the Fayetteville Shale Play.
* Deliver the Numbers.
	* Production and Reserve Growth.
	* Maximize Cash Flow.
* Continue to Tell Our Story.

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

(Slide 18)
Appendix

(Slide 19)
Financial & Operational Summary

This slide contains a table that summarizes the Company's financial and operational indicators.

	Nine Months Ended September 30,		Year Ended December 31,
	2006	2005	2005	2004	2003
	($ in millions, except per share amounts)
Revenues	$549.1	$455.6	$676.3	$477.1	$327.4
EBITDA(1)	309.2	239.5	345.9	255.3	151.4
Net Income	128.9	98.9	147.8	103.6	48.9
Cash Flow (1)	304.8	219.0	321.8	237.7	132.3
Diluted EPS (2)	$0.75	$0.65	$0.95	$0.70	$0.36
Diluted CFPS (2)	$1.78	$1.45	$2.06	$1.61	$0.97
Production (Bcfe)	51.6	45.2	61.0	54.1	41.2
Avg. Gas Price ($/Mcf)	$6.73	$6.16	$6.51	$5.21	$4.20
Avg. Oil Price ($/Bbl)	$60.24	$42.29	$42.62	$31.47	$26.72
Finding Cost ($/Mcfe) (3)			$1.51	$1.34	$1.18
Reserve Replacement (%) (3)			450%	388%	351%

(1)    Net cash flow is net cash flow before changes in operating assets and liabilities.  Net cash flow and EBITDA are non-GAAP financial measures.  See explanation and reconciliation of non-GAAP financial measures on pages 32 and 33.

(2)    Diluted earnings per share and diluted cash flow per share have been adjusted for a 2-for-1 stock split effected in November 2005.

(3)    Excluding reserve revisions and capital investments in drilling rigs.

(Slide 20)
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	63%
2007	Swaps	31.0 Bcf	$7.73	30%
	Collars	34.0 Bcf	$6.93 / $12.34	33%
2008	Swaps	13.0 Bcf	$8.78	-
	Collars	22.0 Bcf	$7.92 / $13.15	-

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

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

(Slide 21)

SWN is One of the Lowest Cost Operators

This slide contains a bar graph that compares SWN to its competitors in terms of lifting cost per Mcfe of production (3 year average).

	Lifting Cost per Mcfe
	of Production
	(3 year average)
Southwestern Energy Company	$0.71
Houston Exploration	$0.73
Kerr-McGee	$0.85
Newfield Exploration	$0.88
EOG Resources, Inc.	$0.89
Noble Energy	$0.90
Pioneer Natural Resources	$0.93
EnCana	$0.93
Chesapeake Energy	$0.95
Range Resources	$0.99
Pogo Producing	$0.99
Cabot Oil & Gas	$1.03
Anadarko Petroleum	$1.09
Devon Energy	$1.10
Apache	$1.20
XTO Energy	$1.23
Swift Energy	$1.25
Cimarex Energy	$1.26
Forest Oil	$1.34
St. Mary Land & Exploration	$1.36
Denbury Resources	$1.62

This slide also contains a bar graph comparing SWN to its competitors in terms of drillbit F&D cost per Mcfe (3 year average).

	Drillbit F&D Cost
	per Mcfe
	(3 year average)
XTO Energy	$1.12
Denbury Resources	$1.27
Southwestern Energy Company	$1.36
Anadarko Petroleum	$1.44
Range Resources	$1.49
Apache	$1.58
EOG Resources, Inc.	$1.59
Cabot Oil & Gas	$1.66
EnCana	$1.83
Devon Energy	$2.07
St. Mary Land & Exploration	$2.23
Houston Exploration	$2.65
Noble Energy	$2.65
Chesapeake Energy	$2.87
Newfield Exploration	$3.12
Pioneer Natural Resources	$3.54
Cimarex Energy	$3.64
Swift Energy	$3.75
Kerr-McGee	$4.09
Forest Oil	$5.90
Pogo Producing Co.	$7.60

Source:  John S. Herold Database

Note:  All data as of December 31, 2003, 2004 and 2005.

(Slide 22)

East Texas - Overton Field

This slide contains a map of Smith County, Texas, where the Overton Field is located.  Existing wells at year-end 2005 and development well locations for 2006 and 2007 are denoted.  It is stated that the Overton Field contains 17,600 acres and the South Overton Farm-in Acreage contains 6,800 acres.

* Purchased original 10,800 acres and 16 producing wells for $6.1 million in 2000 (developed at 640-acre spacing).

* Drilled over 300 wells from 2001 to September 30, 2006, with 100% success.

* Plan to drill 39 wells in 2007, a portion of which will be at 40-acre spacing.

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	66	60
Planned 2007 Development	39	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 23)
Overton Field Gross Production

The graph contained on this slide displays the Overton Field gross production rate (MMcfe/d) from June 2000 to September 2006. Additionally, in early 2003, the graph indicates the projected production profile from an accelerated drilling program as a result of our 2003 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	26 - 28

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

(Slide 24)
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)

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

(Slide 25)

U.S. Gas Consumption and Sources

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.  U.S. gas production has been basically flat since 1994.

Source:  EIA

(Slide 26)
U.S. 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%	*

*Supply impact of 32% vs. 19-23% is under estimated

Utilizes data supplied by IHS Energy; Copyright IHS Energy

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

(Slide 27)
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 28)
NYMEX Gas Prices

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

Source:  Bloomberg

(Slide 29)
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 30)
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 31)
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 32)

Explanation and Reconciliation of Non-GAAP Financial Measures: Net Cash Flow

Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Net cash provided by operating activities before changes in operating assets and liabilities should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles. Forecasting changes in operating assets and liabilities would require unreasonable effort, would not be reliable and could be misleading. Therefore, the reconciliation of the company’s forecasted net cash provided by operating activities before changes in operating assets and liabilities has assumed no changes in assets and liabilities. The first table below reconciles actual net cash provided by operating activities before changes in operating assets and liabilities with net cash provided by operating activities as derived from the company's financial information.

	9 Months Ended September 30,		12 Months Ended December 31,
	2006	2005	2005	2004	2003
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$304,847	$219,003	$321,758	$237,706	$132,327
Add back (deduct):
Change in operating assets and liabilities	26,289	(3,181)	(17,276)	191	(23,228)
Net cash provided by operating activities	$331,136	$215,822	$304,482	$237,897	$109,099

	2006 Guidance	2007 Guidance
	NYMEX Commodity Price Assumptions
	$7.00 Gas	$7.00 Gas	$8.00 Gas
	$60.00 Oil	$60.00 Oil	$65.00 Oil
	($ in millions)
Net cash provided by operating activities	$390-$400	$590-$600	$660-$670
Add back (deduct):
Assumed change in operating assets and liabilities	--	--	--
Net cash provided by operating activities before changes in operating assets and liabilities	$390-$400	$590-$600	$660-$670

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

(Slide 33)

Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA

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 a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles historical EBITDA with historical net income.

	9 Months Ended September 30,		12 Months Ended December 31,
	2006	2005	2005	2004	2003		2002	2001	2000		1999
	(in thousands)
Net income	$128,876	$98,904	$147,760	$103,576	$48,897		$14,311	$35,324	$20,461	(1)	$9,927
Depreciation, depletion and amortization	100,883	69,105	96,641	74,919	56,833		54,095	53,003	47,505		41,707
Net interest expense	501	13,904	15,040	16,992	17,311		21,466	23,699	24,689		17,351
Provision for income taxes	78,988	57,541	86,431	59,778	28,372	(2)	8,708	21,917	11,457		6,449
EBITDA	$309,248	$239,454	$345,872	$255,265	$151,413		$98,580	$133,943	$104,112	(1)	$75,434

(1)    2000 amounts exclude unusual items of $109.3 million for the Hales judgment and $2.0 million for other litigation.

(2)    Provision for income taxes for 2003 includes the tax benefit associated with the cumulative effect of adoption of accounting principle.

The table below reconciles forecasted EBITDA with forecasted net income for 2007, assuming different NYMEX price scenarios and their corresponding estimated impact on the company's results for 2007, including current hedges in place, as of December 15, 2006:

	2006 Guidance	2007 Guidance
	NYMEX Commodity Price Assumptions
	$7.00 Gas	$7.00 Gas	$8.00 Gas
	$60.00 Oil	$60.00 Oil	$65.00 Oil
	($ in millions)
Net income	$160 - $165	$200 - $205	$245 - $250
Add back:
Provision for income taxes - deferred	98 - 101	123 - 126	150 - 153
Interest expense	3 - 4	25 - 30	25 - 30
Depreciation, depletion and amortization	140 - 145	270 - 280	270 - 280
EBITDA	$400 - $410	$615 - $625	$685 - $695

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