EXHIBIT 99.1

Slide Presentation dated December 3, 2003

The following slides were presented December 3, 2003 to investors and analysts at the Friedman Billings Ramsey & Co. 10th Annual Investor Conference held at the Sheraton New York Hotel and Towers in New York City, New York.

(Slide 1)
Southwestern Energy Company

Presentation to the Friedman Billings Ramsey 10th Annual Investor Conference

December 3, 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 November 21, 2003

Shares of Common Stock Outstanding	35,607,787
Market Capitalization	$691,000,000
Institutional Ownership	84.9%
Management Ownership	7.3%
52-Week Price Range	$10.95 (12/18/2002)
	$20.01 (10/13/2003)

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. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, the timing and extent of changes in commodity prices for gas and oil, the timing and extent of the Company's success in discovering, developing, producing, and estimating reserves, property acquisition or divestiture activities that may occur, the effects of weather and regulation on the Company's gas distribution segment, increased competition, legal and economic factors, governmental regulation, the financial impact of accounting regulations and critical accounting policies, changing market conditions, the comparative cost of alternative fuels, conditions in capital markets and changes in interest rates, availability of oil field services, drilling rigs, and other equipment, as well as other factors beyond the Company's control. For additional information with respect to certain of these and other factors, see the reports filed by the Company with the Securities and Exchange Commission. 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. Without limiting the foregoing, all financial information and strategies contained herein have been prepared by the Company and are based on a number of assumptions that are subject to significant uncertainties and contingencies, many of which are beyond the Company's control. There can be no assurance that the assumptions will prove to be accurate or that the amounts included in the projections will be realized or transactions currently contemplated in strategies will be completed, and actual future results may be materially higher or lower than those shown.

(Slide 4)
About Southwestern

* Focused on domestic production of natural gas.

     * 415.3 Bcfe of reserves; 90% natural gas; 10.4 R/P at 12/31/02.

* 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 $103.1 million to accelerate development drilling at Overton Field and reduce debt.

     * Improved our debt-to-capital ratio to 45% at 9/30/03 from 66% at 12/31/02.

     * Record results for nine months ended 9/30/03.

* 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)
E&P Focused

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%) and

     * 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 and low maintenance capital.

(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 September 30, 2003 and potential future development are denoted. It is stated that the Overton Field contains 17,900 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).

* In 2003, began accelerated drilling program to downspace to 80-acre spacing (100+ additional wells).

     * Drilled 41 wells in first nine months of 2003 (total of 55 planned in 2003).

* A large portion of the field will likely require 40-acre spaced wells to adequately develop the field.

Overton Field development potential is as follows:

		Approximate	Reserve
	Well	Spacing	Potential
	Count	(Acres)	(Net Bcfe)
Original Wells	16	640	22
2001 - 2002 Development	33	365	89
2003 YTD Development	41	200	63
Remaining 2003 Development	14	170	22
Potential Future Development	139	<80	173
	243	<80	369

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 - 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.

* Reduced drilling time by >50%.

* Increased initial production by 200%.

* Increased gross reserves by 60% to 2.2 Bcfe per well.

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

(Slide 11)
Overton Field Gross Production

The graph contained in this slide displays the Overton Field gross production rate (MMcfe/d) from the year 2000 to the current period in 2003 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	10 - 13
2004 Forecast	18 - 20

Total Wells:

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

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 50 to 60 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	21/26 wells
Net EUR	26.2 Bcf
F&D/Mcf	$.75

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 map of the Ranger Anticline prospect with the Company's exploratory acreage and acreage held by production designated with shading. Producing wells at 9/30/03 and 2003 proposed wells are also shown.

Ranger Anticline:

Success	21/26 wells
Net EUR	26.2 Bcf
F&D/Mcf	$.75

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

* SWN plans to drill 16 wells in 2003, including two exploratory wells.

* 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	300	17
Successful Wells Through 9/30/03	8	180	9
Remaining 2003 Development	4	165	5
Potential Future Locations:
Development	13	110	12
Prob/Poss Locations	16	80	15
TOTAL	54	80	58

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

(Slide 14)
Gulf Coast Exploration

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

* 9 discovery wells out of last 20 wildcats drilled in South Louisiana.

* Duck Lake 3-D project data 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.

     * Currently drilling Canvasback prospect (80 Bcfe gross potential).

     * Two additional high-potential prospects and multiple leads in the project area.

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 15)
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	Producing	12.5%	15,000	Devonian	30.0	3.0
Gulf Coast
Jericho	SWN	Dry	21.0%	14,300	Frio	-	-
Coleburn	SWN	Completing	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 16)
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 17)
Outlook for 2003

* Production target of 42 Bcfe in 2003 (estimated growth of 5%).

	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 Actual	2003 Guidance 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 18)
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 Focused Strategy.

* Deliver the Numbers.

     * Production and Reserve Growth.

     * Add Value for Every Dollar Invested.

* Continue to Tell Our Story.

(Slide 19)
Appendix

(Slide 20)
Gas Hedges in Place Through 2005

This slide contains a bar chart detailing gas hedges in place by quarter for the years 2003 through 2005. 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%
2005	Swaps	3.0 Bcf	$4.58	--

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 21)
Financial and Operational Summary

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

	9 Months Ending September 30,
			Year Ended December 31,
	2003	2002		2002	2001	2000 (1)
	($ in millions, except per share amounts)
Revenues	$236.2	$188.7		$261.5	$344.9	$363.9
EBITDA	110.3	74.1		99.8	134.6	103.2
Net Income	34.0	9.8		14.3	35.3	20.5
Cash Flow (2)	95.0	58.9		79.8	112.7	82.4
Diluted EPS	$1.01	$0.37		$0.55	$1.38	$0.82
Production (Bcfe)	30.0	30.6		40.1	39.8	35.7
Avg. Gas Price ($/Mcf)	$4.22	$2.89		$3.00	$3.85	$2.88
Avg. Oil Price ($/Bbl)	$27.17	$20.87		$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 September 30, 2003 and Form 10-K for the year ended December 31, 2002 is hereby furnished:

		9 Months Ending
		September 30,		Year Ended
		2003	2002	2002	2001	2000
		($ in Millions)
Net cash provided by operating activities		94.9	68.4	77.6	144.6	(53.2)
Add back (deduct):
	Change in operating assets and liabilities	0.1	(9.5)	2.2	(31.9)	24.3
	Unusual and extraordinary items	-	-	-	-	111.3 (A)
Cash flow		95.0	58.9	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.

		9 Months Ending
		September 30		Year Ended
		2003	2002	2002	2001	2000
		($ in Millions)
Net income		34.0	9.8	14.3	35.3	(46.7)
Add back:
	Provision for income taxes - deferred	20.9	6.1	8.7	21.9	(28.9)
	Interest Expense	13.1	16.1	21.5	23.7	23.2
	Depreciation, depletion and amortization	42.3	42.1	55.3	53.7	46.6
	Unusual and extraordinary items	-	-	-	-	109.0 (B)
EBITDA		110.3	74.1	99.8	134.6	103.2

(A) Unusual and extraordinary items in 2000 includes charges of $109.3 million for the Hales judgment and $2.0 million related to other litigation.
^(B) Unusual and extraordinary items in 2000 includes charges of $109.3 million for the Hales judgment, $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 22)
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 23)
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 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. U.S. gas production has been basically flat since 1994.

Source: EIA

(Slide 25)
U.S. Gas Production Decline Rate

This graph portrays U.S. natural gas production history. The graph represents 94% of total U.S. natural gas production. The decline rate for 2002 was 29%.

	Production Decline
	Rate of Base
1990	16%
1991	17%
1992	15%
1993	17%
1994	19%
1995	19%
1996	20%
1997	22%
1998	23%
1999	22%
2000	25%
2001E	26%
2002E	29%

Includes data supplied by Petroleum Information Corporation; Copyright 1990-2002 Petroleum Information Corporation.

Chart prepared by and property of EOG Resources Inc.; Copyright 2002.

(Slide 26)
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 27)
NYMEX Gas Prices

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

Source: Bloomberg

(Slide 28)
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 29)
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 30)
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