8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington D.C. 20549
	FORM 8-K
	CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date or earliest event reported) October 7, 2003
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) Slide presentation accompanying the October 7, 2003 presentation to institutional investors and analysts during the Independent Petroleum Association of America Oil and Gas Investment Symposium held at The Palace Hotel in San Francisco, California.
Item 9.
Regulation FD Disclosures
On October 7, 2003, Harold M. Korell, President and Chief Executive Officer for Southwestern Energy Company, made a presentation to institutional investors and analysts at the Independent Petroleum Association of America Oil and Gas Investment Symposium held at The Palace Hotel in San Francisco, California.  The accompanying 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 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:	October 8, 2003		BY:	/s/ GREG D. KERLEY
			Greg D. Kerley Executive Vice President and Chief Financial Officer
- 2 -
EXHIBIT INDEX
Exhibit No.		Description
99.1		Slide presentation accompanying the October 7, 2003 presentation to institutional investors and analysts during the Independent Petroleum Association of America held at The Palace Hotel in San Francisco, California.
- 3 -

EX-99

EXHIBIT 99.1

Slide Presentation dated October 7, 2003

The following slides were presented October 7, 2003 to institutional investors and analysts at the IPAA Oil & Gas Investment Symposium held at The Palace Hotel in San Francisco, California.

(Slide 1)
Southwestern Energy Company

Presentation to IPAA Oil & Gas Investment Symposium

October  2003

NYSE: SWN

This slide contains a picture of a weathered door lock and key. The attached keychain is inscribed with the Company's formula .

(Slide 2)

Southwestern Energy Company (NYSE: SWN)

General Information

Southwestern Energy Company is an independent energy company primarily focused on the exploration for and production of natural gas. Our strategy is to add $1.30 to $1.50 in discounted value for every dollar invested in a balanced exploration and production program in the Arkoma and Permian Basins, East Texas and the onshore Gulf Coast.

Market Data as of September 30, 2003

Shares of Common Stock Outstanding	35,575,442
Market Capitalization	$631,000,000
Institutional Ownership	81.0%
Management Ownership	7.3%
52-Week Price Range	$10.87 (10/18/2002)
	$18.16 (08/29/2003)

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 3)
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 inc lude, 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 4)

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.

     * Since 1999, we've averaged production growth of 7% per year, 197% reserve replacement, F&D cost of $1.07 per Mcfe.

* Follow-on equity offering completed in March 2003. Raised $103.2 million to accelerate development drilling at Overton Field and reduce debt.

     * Improved our debt-to-capital ratio to 45% at 6/30/03 from 66% at 12/31/02.

* 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 5)

Proven Track Record

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

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

Note: Reserve data excludes reserve revisions.

(Slide 6)

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 region and the East Texas region. Lines trace gas distribution pipelines and the Ozark Pipeline.

E&P Segment

* 2002 Reserves: 415.3 Bcfe

* 90% Natural Gas

* 2002 Production: 40.1 Bcfe (1)

* Reserve Life: 10.4 years

Arkoma

* Reserves - 188.7 Bcf (45%)

* Production - 19.8 Bcf (49%)

* Maintain our strong position through workovers and low-risk development drilling.

East Texas (Overton)

* Reserves - 111.0 Bcfe (27%)

* Production - 5.9 Bcfe (15%)

* Grow through low-risk infill drilling.

Gulf Coast

* Reserves - 58.5 Bcfe (14%)

* Production - 7.5 Bcfe (19%)

* Grow through high-potential exploration.

Permian

* Reserves - 57.1 Bcfe (14%)

* Production - 6.9 Bcfe (17%) (1)

* Focus on medium-risk exploration.

Utility Segment

* 140,000 customers in N. Arkansas

* Territory includes 6^th fastest growing region in U.S.

(1) Includes 2.0 Bcfe of production related to Mid-Continent properties sold during 2002.

(Slide 7)

Capital Investments

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

				2003
	2000	2001 (1)	2002	Plan
	($ in Millions)
Utility & Corporate	$6.5	$7.1	$6.9	$8.6
Property Acquisitions	$6.1	$0.7	$0.1	$2.3
Capitalized Expenses	$9.7	$9.9	$10.9	$11.5
Leasehold & Seismic	$9.5	$9.8	$9.2	$15.8
Development Drilling	$23.7	$44.2	$46.3	$116.7
Exploration Drilling	$20.2	$20.8	$18.7	$18.7
Total	$75.7	$92.5	$92.1	$173.6

This slide also contains a pie chart of Company capital investments by area of operation, summarized as follows:

	% of Total
	Capital Investments
East Texas	52%
Arkoma	19%
Gulf Coast	13%
Permian	4%
Other E&P	7%
Utility	5%

* E&P capital program heavily weighted to low-risk drilling in 2003

     * Low-risk Arkoma ($33.4 MM, 19%) and East Texas ($90.2 MM, 52%)

     * Medium-risk Permian Basin ($6.2 MM, 4%)

     * Higher-risk, but larger potential Gulf Coast ($22.7 MM, 13%)

* Over 80% of E&P capital allocated to drilling in 2003.

* Utility provides predictable earnings and cash flow.

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

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

(Slide 8)

Overton Field - An Impact Project

This slide contains a map of Smith County, Texas where Overton Field is located. Existing wells at year-end 2002, wells drilled at June 30, 2003 and development locations for 2003-2004 are denoted. It is stated that the Overton Field contains 17,600 acres and the South Overton Farm-in Acreage contains 5,800 acres.

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

* Drilled 33 wells in 2001-2002 with 100% success (3-year average F&D cost of $0.63/Mcfe).

* Two-year (2003-2004) drilling program to downspace to 80-acre spacing (100+ additional wells).

     * Drilled 24 wells in first half of 2003.

* Potential future downspacing

Overton Field development potential is as follows:

		Approximate	Reserve
	Well	Spacing	Potential
	Count	(Acres)	(Net Bcfe)
Original Wells	16	640	22
2001 Development	15	400	36
2002 Development	18	250	53
2003 Proposed Development	55	120 *	97 *
2004 Proposed Development	53	80 *	85 *
Total	157	80 *	293

* In higher potential areas.

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

(Slide 9)

Overton Economics

Typical First Year 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

Total Life Economics:

Completed well cost	$1.5 MM (1)
Pretax ROR	35% (2)
Pretax PVI	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.

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

(Slide 10)

Overton Field Gross Production

The graph contained in this slide displays the Overton Field gross production rate (Mmcfe/d) for the years 2000 to 2002 and the potential gross production rate for 2003 and 2004 under both an accelerated drilling program and under an eighteen well per year program.

Overton Field Net Production:

	Bcfe
2000	0.3
2001	2.3
2002	5.9
2003 Forecast (1)	10 - 13
2004 Forecast (1)	18 - 20

Total Number of Wells:

	Dec-01	Dec-02	Dec-03	Dec-04
18 Well Drilling Program	31	49	67	85
Accelerated Drilling Program (1)	31	49	104	157

(1) Assumes accelerated development of Overton with equity offering.

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

(Slide 11)

Overton Field - Improved Drilling Results

This slide 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 we decreased that rate to 35 days. It was further decreased to 27 days in 2002 and 24 days in 2003. Thus, drilling time has been reduced by greater than 50% over the rate of previous owners. We also increased initial production by 200% and gross reserves by 60% to 2.2 Bcfe per well.

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

(Slide 12)

Arkoma Basin

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

* "Legacy asset" that provides SWN with a stable production/reserve base and low-risk drilling opportunities with some upside exploration potential.

* Competitive advantages:

     * 60 years of experience in the basin.

     * Large acreage position of 385,000 gross acres and 263,000 net acres.

* 2003 capital program includes drilling 35 to 40 wells and 60 workovers.

Arkoma Basin Three-Year Average Results:

Reserve replacement	97%
LOE cost (incl. Taxes) ($/Mcf)	$0.30
F&D cost ($/Mcf)	$1.08

Ranger Anticline:

Success	17/20 wells
Net EUR	22.3 Bcf
F&D/Mcf	$.74

Haileyville:

Success	16/24 wells
Net EUR	9.3 Bcf
F&D/Mcf	$.82

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

(Slide 13)

Ranger Anticline

This slide contains a vertical cross-section of the Ranger Anticline area with shading to denote upper and lower borum.

* Thrust faulted/anticlinal Atokan sand play

* Repeat sections of tight gas sands

* Natural fractures that enhance productivity

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

(Slide 14)

Ranger Anticline

This slide contains a map of the Ranger Anticline prospect with the Company's exploratory acreage and acreage held by production designated with shading. Producing wells at 6/30/03 and 2003 proposed wells are also shown.

Ranger Anticline:

Success	17/20 wells
Net EUR	22.3 Bcf
F&D/Mcf	$.74

* In early 2003 received approval to downspace field to 80 acres per well.

* SWN plans to drill 14 wells in 2003; potential for significant exploration and development drilling thereafter.

* Large acreage position of 4,500 gross developed acres and 35,200 gross exploratory acres.

* Average working interest 50% - 100%.

A table giving the Ranger Anticline development potential on the Company's held by production acreage is as follows:

		Approx.	Reserve
	Well	Spacing	Potential
	Count	(Acres)	(Net Bcfe)
Producing Wells at 12/31/02	13	345	17
Wells Drilled in 1st Half of 2003	4	265	5
Remaining 2003 Development	10	165	11
Potential Future Locations:
Development	13	110	12
Prob/Poss Locations	16	80	15
TOTAL	56	80	60

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

(Slide 15)

Gulf Coast Exploration

This slide contains a map of Louisiana. Arrows desingate the Horeb, Havilah, Crowne, Cheniere (2), Duck Lake, North Grosbec, Gloria and Malone areas. The areas where 3-D seismic data was either aquired/purchased in 2002 or already existed are shaded. The map also points out areas of discovery and the locations of 2003 prospect wells.

* 8 discovery wells out of last 19 wildcats drilled in South Louisiana.

* Duck Lake 3-D project date now in-house:

     * 135-square mile 3-D survey in a highly prospective area in St. Martin and St. Mary Parishes.

     * SWN is operator and owns a 50% working interest. Drilling to commence in 2003.

* Acquired license to over 1,000 sqaure miles of 3-D shelf data in 2002.

Gulf Coast Three-Year Average Results:

Reserve Replacement	246%
LOE Cost (incl. Taxes) ($/Mcfe)	$0.65
F&D Cost ($/Mcfe)	$1.83

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

(Slide 16)

Exploration Potential - 109 Net Bcfe

This slide contains a table summarizing exploration potential.

					Unrisked Reserve
		Spud	Working		Potential (Bcfe)
Prospect Name	Operator	Date	Interest	Depth	Objective	Gross	Net
Arkoma Basin
Midway	SWN	Dry	60.0%	11,400	Atoka	-	-
Permian Basin
Birds of Prey	SWN	Producing	100.0%	5,000	Cherry Canyon	14.8	11.8
S. Roepke	SWN	Producing	50.5%	8,100	Devonian	1.0	0.4
River Ridge	EGL	Drilling	12.5%	15,000	Devonian	30.0	3.0
Gulf Coast
Jericho	SWN	Dry	21.0%	14,300	Frio	-	-
Coleburn	SWN	Drilling	50.0%	13,000	Tex W	10.0	3.9
Canvasback	SWN	Drilling	50.0%	18,200	Liebusella	80.0	30.0
Daffy	SWN	4Q 2003	50.0%	14,500	Siph D & Plan	110.0	41.3
Redhead	SWN	1Q 2004	50.0%	12,500	Siph D & Plan	49.4	18.5
			Total Reserve Potential			295.2	108.9

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

(Slide 17)

How Have We Been Doing?

The graph contained on this slide 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
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 18)

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)	$5.00 Gas	$6.00 Gas
	$25.27 Oil (1)	$28.00 Oil	$28.00 Oil
Net Income	$14 MM	$43 - $46 MM	$55 - $58 MM
EPS	$.55	$1.25 - $1.35	$1.60 - $1.70
Operating Income	$47 MM	$90 - $93 MM	$109 - $112 MM
Cash Flow	$80 MM	$133 - $136 MM	$152 - $155 MM
EBITDA	$100 MM	$150 - $153 MM	$169 - $172 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.

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

In accordance with Regulation G, a reconciliation of Cash Flow, as presented, to Net Cash Provided by Operating Activities from the Company's Form 10-K for the year ended December 31, 2002 is hereby furnished:

Net cash provided by operating activities	$78 MM
Add: Changes in operating 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. We have 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 our 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
	Actual	NYMEX Price Assumptions
	$3.22 Gas	$5.00 Gas	$6.00 Gas
	$25.27 Oil	$28.00 Oil	$28.00 Oil
	($ in millions)
Net Income	14	43 - 46	55 - 58
Deferred Income Taxes	9	26 - 28	34 - 36
Interest Expense	21	17 - 19	17 - 19
Depreciation, Depletion and Amortization	56	60 - 62	60 - 62
EBITDA	100	150 - 153	169 - 172

(Slide 19)

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 Investd.

* Continue to Tell Our Story.

(Slide 20)

Appendix

(Slide 21)

Gas Hedges in Place Through 2004

This slide contains a bar chart detailing gas hedges in place by quarter for the years 2003 and 2004. A summary of these outstanding gas hedges is as follows:

			Average Price per Mcf	Percent of Total
	Type	Hedged Volumes	(or Floor/Ceiling)	Production Hedged
2003	Swaps	13.3 Bcf	$3.47	30 - 35%
	Collars	17.1 Bcf	$3.26 / $5.05	40 - 45%
2004	Swaps	7.2 Bcf	$4.00	10 - 15%
	Collars	22.0 Bcf	$3.82 / $6.26	40 - 45%

Note: Southwestern has approximately 340,000 barrels of oil hedged at a fixed WTI price of $26.58 per barrel in 2003 and 120,000 barrels of oil hedged at a fixed WTI price of $27.25 per barrel in 2004.

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

(Slide 22)

Financial and Operational Summary

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

	6 Months Ending
	June 30,		Year Ended
	2003	2002	2002	2001	2000 (1)
	($ in millions, except per share amounts)
Revenues	$165.1	$137.7	$261.5	$344.9	$363.9
EBITDA	73.4	52.9	99.8	134.6	103.2
Net Income	23.2	8.5	14.3	35.3	20.5
Cash Flow (2)	65.2	43.3	79.8	112.7	82.4
Diluted EPS	$0.71	$0.33	$0.55	$1.38	$0.82
Production (Bcfe)	18.9	20.6	40.1	39.8	35.7
Avg. Gas Price ($/Mcf)	$4.22	$2.86	$3.00	$3.85	$2.88
Avg. Oil Price ($/Bbl)	$27.54	$20.10	$21.02	$23.55	$22.99
Finding Cost ($/Mcfe) (3)			$1.02	$1.11	$0.99
Reserve Replacement (%) (3)			209%	224%	196%

(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 Net Cash Provided by Operating Activities from the Company's Form 10-Q dated June 30, 2003 and Form 10-K for the year ended December 31, 2002 is hereby furnished:

		6 Months Ending
		June 30,		Year Ended
		2003	2002	2002	2001	2000
		($ in Millions)
Net cash provided by operating activities		70.3	42.3	77.6	144.6	(53.2)
Add back (deduct):
	Change in operating assets and liabilities	(5.1)	1.3	2.2	(31.9)	24.3
	Unusual and extraordinary items	-	-	-	-	111.3 (A)
Cash flow		65.2	43.3	79.8	112.7	82.4

EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. We have 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 our 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.

		6 Months Ending
		June 30		Year Ended
		2003	2002	2002	2001	2000
		($ in Millions)
Net income		23.2	8.5	14.3	35.3	(46.7)
Add back:
	Provision for income taxes - deferred	15.2	5.3	8.7	21.9	(28.9)
	Interest Expense	8.9	10.7	21.5	23.7	23.2
	Depreciation, depletion and amortization	26.1	28.4	55.3	53.7	46.6
	Unusual and extraordinary items	-	-	-	-	109.0 (B)
EBITDA		73.4	52.9	99.8	134.6	103.2

(A) Unusual and extraordinary items in 2000 includes charges of $109.3 million for the Hales judgement and $2.0 million related to other litigation.

(B) Unusual and extraordinary items in 2000 includes charges of $109.3 million for the Hales judgement, $2.0 million related to other litigation, a $3.2 million gain on sale of utility assets, and $0.9 million extraordinary loss on the early retirement of debt.

(Slide 23)

Unit Cost Comparison - SWN is Competitive

This slide contains a bar graph that compares SWN to its competitors.

					Production
	Interest	G&A	Operating	F&D	(Bcfe)
Cimarex (1)	$0.01	$0.18	$0.57	$4.25	49.3
Magnum Hunter	$0.70	$0.21	$1.06	$2.21	43.8
St. Mary	$0.02	$0.23	$0.89	$1.53	54.0
Westport	$0.20	$0.17	$0.82	$1.40	91.3
Chesapeake	$0.62	$0.09	$0.65	$1.21	159.0
XTO	$0.34	$0.26	$0.87	$0.73	194.3
Mean	$0.32	$0.19	$0.81	$1.89	98.6
Median	$0.27	$0.20	$0.85	$1.47	72.6
Southwestern	$0.45	$0.33	$0.60	$1.17	38.5

Note: Data represents 2000-2002 three-year averages. Income statement data for the years ended December 31 unless otherwise indicated. Finding cost data includes revisions.

(1) Cimarex Energy income statement data for the years 2000 and 2001 are for the year ended September 30.

(Slide 24)

U.S. Gas Consumption and Sources

This slide displays U.S. gas production versus U.S. gas consumption from 1975 to the present. Net gas imports for the same period are also given. As the chart shows, U.S. gas production has been basically flat since 1994.

Source: EIA

(Slide 25)

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 2003.

Source: Edison Electric Institute

(Slide 26)

NYMEX Gas Prices

This line graph represents NYMEX gas prices in $/Mcf from 2000 to 2003.

Source: Bloomberg

(Slide 27)

U.S. Gas Drilling

This line graph denotes the number of rigs drilling for gas through the period 1988 to 2003.

Source: Baker Hughes

(Slide 28)

West Texas Intermediate Oil Prices

This line graph shows the price of West Texas Intermediate oil in $/Bbl for the years 2000 to 2003.

Source: Bloomberg

(Slide 29)

Oil and Gas Price Comparison

This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu for the period 1994 to 2003.

Source: Bloomberg