8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported)   September 16, 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		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 September 16, 2003 presentation to investors during the RBC Capital Markets 2003 North American Energy and Power Conference at The Houstonian Hotel, Club and Spa in Houston.

Item 9.

Regulation FD Disclosures

        On September 16, 2003, Harold M. Korell, President and Chief Executive Officer for Southwestern Energy Company, made a presentation to investors at the RBC Capital Markets 2003 North American Energy and Power Conference. 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:	September 16, 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 September 16, 2003 presentation to investors during the RBC Capital Markets 2003 North American Energy and Power Conference at The Houstonian Hotel, Club and Spa in Houston.

- 3 -

EX-99

EXHIBIT 99.1

Slide Presentation dated September 16, 2003

The following slides were presented September 16, 2003 to institutional investors and analysts at the RBC Capital Markets 2003 North American Energy and Power Conference held at the Houstonian Hotel, Club and Spa in Houston, Texas.

(Slide 1)
Southwestern Energy Company

Presentation to RBC Capital Markets 2003 North American Energy and Power Conference

September 16, 2003

NYSE: SWN

This slide contains a picture of a weathered door lock and key. The attached keychain is inscribed with the Company's strategic formula . This formula summarizes the Company's belief that the right people doing the right things, wisely investing the cash flow from the underlying assets will create value +.

(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 August 29, 2003

Shares of Common Stock Outstanding	35,575,442
Market Capitalization	$646,000,000
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

The Company is focused on the domestic production of natural gas, with 90% of our 415.3 Bcfe of reserves being natural gas. The average life of those reserves is 10.4 years.

Our strategy is built upon a foundation of organic growth through the drillbit. This growth is balanced between low-risk development and high-potential exploration.

We have a proven track record of adding significant reserves at low costs. This can be shown in the fact that since 1999 we have averaged production growth of 7% per year, a 197% reserve replacement and a finding and development cost of $1.07 per Mcfe.

Southwestern Energy Company completed a follow-on equity offering in March 2003. This offering raised $103.2 million. These proceeds are being used to accelerate our development drilling in the Overton Field. They are also being used to reduce debt, improving our debt-to-capital ratio to 45% at 6/30/03 from 66% at 12/31/02.

Our Company has a strategy built around the formula . This formula summarizes our belief that 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 summarizes the Company's performance in four key indicators, production, reserve replacement, reserve additions and finding and development (F&D) cost. Those indicators for the periods ended December 31 are as follows:

	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)

E&P Focused

Slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and New Mexico with shadings to denote areas of active E&P and lines to trace gas distribution pipelines and the Ozark Pipeline.

E&P Segment

The Company's E&P segment had production in 2002 of 40.1 Bcfe (1). We had reserves of 415.3 Bcfe in 2002, 90% of which were natural gas. The average life of those reserves is 10.4 years. Our E&P segment is comprised of four main areas, the Arkoma Basin, the East Texas Overton Field, the Gulf Coast and the Permian Basin. The reserve and production statistics, and the percentage of the whole for each area are as follows:

	Arkoma	East Texas	Gulf Coast	Permian
Reserves (Bcfe)	188.7	111.0	58.5	57.1
% of Total Reserves	45%	27%	14%	14%
Production (Bcfe)	19.8	5.9	7.5	6.9
% of Total Production	49%	15%	19%	17% (1)

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

In the Arkoma Basin our strategy is to maintain our strong position through workovers and low-risk development drilling. Growth through low-risk infill drilling is our strategy in the East Texas Overton Field. We plan to focus on medium-risk exploration in the Permian Basin and high-potential exploration in the Gulf Coast region.

Utility Segment

The Company's utility segment services 140,000 customers in Northern Arkansas, a territory which includes the 6^th fastest growing region in the U.S. according to the U.S. Census Bureau. In November 2002 we filed for an $11.0 million annual rate increase with the Arkansas Public Service Commission.

(Slide 7)

Capital Investments

This slide contains a bar chart that breaks the Company's capital investments down by general business activity, including utility and corporate, property acquisitions, capitalized expenses, leasehold and seismic, development drilling and exploration drilling. The summary of those investments is as follows:

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

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

This slide also contains a pie chart displaying capital investments by area of operation. The results are as follows:

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

As the chart shows our E&P capital program is heavily weighted to low-risk drilling in 2003, with 52% or $90.2 million being spent in East Texas and 19% or $33.4 million being spent in the Arkoma Basin. The medium-risk Permian Basin has received 4% or $6.2 million of total capital investments, and the higher-risk, but larger potential Gulf Coast region received 13% or $22.7 million. Over 80% of the E&P capital has been allocated to drilling in 2003. The utility segment is very valuable in that it provides predictable earnings and cash flow.

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 the Overton Field production area is located. This area consists of 17,600 acres in the Overton Field and an additional 5,800 farm-in acres in the South Overton area. The Company originally purchased 10,800 acres containing sixteen producing wells in 2000 for $6.1 million. The original wells were developed at 640-acre spacing. During 2001 and 2002 an additional 33 wells were drilled with 100% success. The three year average F&D cost for those wells is $0.63/Mcfe. The 2003-2004 drilling program contains plans to downspace to 80-acre spacing, creating 100 plus additional wells. Twenty-four wells were drilled in the first half of 2003. There is also the potential for further downspacing in the future. A summary of the 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 (1)	97 (1)
2004 Proposed Development	53	80 (1)	85 (1)
Total	157	80 (1)	293

(1) 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 for the years 2000 to 2002. The potential gross production rate for 2003 and 2004 is also given under both an accelerated drilling program and under an eighteen well per year program.

The Overton Field's net production for the same years is as follows:

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

The total number of wells under the two given drilling program options are as follows:

	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 production area. The Ranger Anticline and Haileyville prospects, and the area known as the Fairway are further noted. The 2003 capital program includes the drilling of 35 to 40 new wells in the Basin and the performance of 60 workovers. In addition, recent approval was given in the Ranger Anticline area to develop the field at 80-acre spacing.

The Arkoma Basin serves as a "legacy asset" for our Company. This area provides a stable production/reserve base and low-risk drilling opportunities with some upside exploration potential. In addition, our 60 years of experience in the Basin and our large acreage position of 385,000 gross acres and 263,000 net acres, provide us with a distinct competitive advantage over other producers.

Statistics for the entire Arkoma Basin, and the Haileyville and Ranger Anticline prospects are given as follows:

Arkoma Basin Three Year Average Results:

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

Ranger Anticline Prospect Results:

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

Haileyville Prospect Results:

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 map of the Ranger Anticline prospect. Our exploratory acreage and acreage held by production are designated with shading. Producing wells at 6/30/03 and 2003 proposed wells are also shown.

In early 2003, we received approval to downspace the Ranger Anticline field to 80 acres per well. We plan to drill fourteen wells in 2003 and have the potential for significant exploration and development drilling thereafter. We hold a large acreage position of 4,500 gross developed acres and 35,200 gross exploratory acres. Our average working interest in the area is 50% - 100%. A summary of the Ranger Anticline development potential 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

(Slide 14)

Gulf Coast Exploration

This map shows Company exploration activity within the Louisiana onshore Gulf Coast region. The Horeb, Havilah, Crowne, Cheniere (2), Duck Lake, North Grosbec, Gloria and Malone exploration areas in particular are highlighted. Shading denotes the areas where 3D seismic information either already existed or was acquired/purchased in 2002. Specifically, a license to over 1,000 square miles of 3-D shelf data was acquired in 2002. In addition, the 135-sqare mile Duck Lake 3-D project data is now in-house. Duck Lake is a highly prospective area in St. Martin and St. Mary Parishes where we are the operator and a 50% working interest owner. Drilling in the area is to commence in 2003.

The Gulf Coast map also points out areas of discovery and the locations of 2003 prospect wells. Out of the last nineteen wildcats drilled in South Louisiana we have produced eight discovery wells. Three-year average results for the region are as follows:

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 15)

Exploration Potential - 109 Net Bcfe

This slide contains a table summarizing the exploration potential of the Company's production areas.

					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	3Q 2003	50.0%	13,000	Tex W	10.0	3.9
Canvasback	SWN	4Q 2003	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 16)

How Have We Been Doing?

The graph contained on this slide shows how the implementation of a new management and E&P team along with a new strategy has affected F&D Cost, Reserve Replacement and PVI.

	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 that all metrics calculated exclude reserve revisions.

(1) PVI metrics were calculated using pricing in effect at year-end with exception to the year 2000 which was calculated at $3.00 per Mcf natural gas price.

(Slide 17)

Unit Cost Comparison - SWN is Competitive

The bar graph given in this slide compares various expenses of the Company to similar measurements of its competitors. The data represents 2000-2002 three-year averages, with income statement data being for the years ended December 31 unless otherwise indicated. Finding cost data includes revisions.

	Interest	G&A	Operating	F&D	Production(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

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

(Slide 18)

Outlook for 2003

The Company has a targeted production of 42-44 Bcfe in 2003. This translates into an estimated growth rate of 5% to 10%. For the year 2004 the planned growth is 20% to 25%, or a production target of 50-55 Bcfe. Following are other key indicators under varying price assumptions.

	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
Earnings	$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. 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 Actual	2003 Guidance NYMEX Commodity 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)

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%

Additionally, the Company 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 20)

The Road to V⁺

This slide summarizes the strategy by which the Company plans to continue to create added value in everything it does.

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