EXHIBIT 99.1

Slide Presentation dated January 4, 2008

The following slides will be presented to investors.

(Cover)
Southwestern Energy Company

Investor Presentation

January 2008

NYSE: SWN

The left side of this slide contains a close-up picture of a leaf.  The caption above reads "Stimulating Growth."  The company's formula is located in the bottom-left corner.  The top-right corner of this slide contains the company logo.

(Slide 1)
Forward-Looking Statements

All statements, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company’s future operations, are forward-looking statements. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. The company has no obligation and makes no undertaking to publicly update or revise any forward-looking statements. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company’s actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); the timing and extent of the company’s success in discovering, developing, producing and estimating reserves; the economic viability of, and the company’s success in drilling, the company’s large acreage position in the Fayetteville Shale play, overall as well as relative to other productive shale gas plays; the company’s ability to fund the company’s planned capital investments; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services, including pressure pumping equipment and crews in the Arkoma Basin; the company’s future property acquisition or divestiture activities; the effects of weather; increased competition; the impact of federal, state and local government regulation; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets and changes in interest rates, and any other factors listed in the reports the company has filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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

(Slide 2)

Offering Summary

* Issuer:	Southwestern Energy Company
* Notes:	$400 million senior unsecured notes
* Maturity:	10 years
* Use of Proceeds:	Refinancing of credit facility borrowings
* Guarantors:	Southwestern Energy Production Company, SEECO, Inc. and Southwestern Energy Services Company
* Ranking:	Senior unsecured and pari passu with all present and future senior unsecured indebtedness
* Optional Redemption:	Non-callable for life.  Make-whole call at T + 50 bps.
* Form of Offering:	144A with registration rights
* Expected Ratings:	Ba2/BB+

(Slide 3)
Corporate Overview

(Slide 4)
About Southwestern

* Focused on domestic exploration and production of natural gas.
	* 1,026 Bcfe of reserves; 95% natural gas; 14.2 R/P at year-end 2006.
	* Approximately 95% of EBITDA generated from E&P segment.
* E&P strategy built on organic growth through the drillbit.
	* Over 80% of planned E&P capital allocated to drilling in 2008.
* Track record of adding significant reserves at low costs.
	* From 2003 through 2006, we've averaged annual production growth of 20.7%, reserve growth of 26.8%, 371% reserve replacement, and F&D cost of $1.92 per Mcfe.
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to over $9 billion.
* 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 5)
Areas of Operations

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

* 2006: 1,026 Bcfe of Reserves
	95% Natural Gas
	Production: 72.3 Bcfe
* 2007 Est. Production: 111 Bcfe
* 2008 Est. Production: 148-152 Bcfe

Arkoma

* Reserves - 577 Bcf (56%)

* Production - 31.9 Bcf (44%)

East Texas

* Reserves - 383 Bcfe (37%)

* Production - 32.0 Bcfe (44%)

Permian

* Reserves - 51 Bcfe (5%)

* Production - 5.8 Bcfe (8%)

Gulf Coast

* Reserves - 15 Bcfe (2%)

* Production - 2.6 Bcfe (4%)

Gas Distribution Segment

* 151,000 customers in North Arkansas

* Sale pending for $224 million

* 2% of Operating Income and EBITDA

* Southwestern's E&P segment operates in Arkansas, Texas, New Mexico, Oklahoma and Louisiana and generates approximately 95% of operating income and EBITDA.

* Midstream Services segment provides marketing and gathering services for the E&P business.

* Recently signed Sale and Purchase Agreement for the sale of utility business for $224 million plus working capital.  Transaction expected to close mid-2008.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 6)
Key Investment Considerations

* Large, diversified and growing reserve base.
	* Reserves have grown from 503 Bcfe in 2003 to 1,026 Bcfe in 2006, representing a CAGR of 26.8%.
* Consistent track record of organic production growth.
	* Production has grown from 41 Bcfe in 2003 to approximately 111 Bcfe in 2007 with targeted growth of 35% in 2008.
* Over 900,000 net acres in the low-risk Fayetteville Shale play.
	* Represents significant future growth in production and reserves for years to come.
* Operational efficiency.
	* Low drillbit F&D cost and high organic reserve replacement, relative to industry peers.
	* Utilize company-operated built-for-purpose rigs for large portion of drilling program.
* Strong balance sheet and financial discipline.
	* Demonstrated use of asset sales and equity to accelerate development programs.
* Conservative and well-established risk management strategy.
	* SWN has historically hedged 70% to 80% of projected gas production volumes.
* Experienced management and technical teams.

(Slide 7)
Proven Track Record

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

						CAGR
	2003	2004	2005	2006	2007E	(2003-2006)
Reserves (Bcfe)	503	646	827	1,026		26.8%
Production (Bcfe)	41	54	61	72	111E	20.7%
Reserve Replacement	351%	388%	450%	505%
EBITDA ($MM) (1)	$151	$255	$346	$415		40.1%
F&D Cost ($/Mcfe)	$1.18	$1.34	$1.51	$2.10

Note: Reserve replacement and finding & development cost 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 25.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 8)

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	$0.83
EOG Resources, Inc.	$1.04
Noble Energy	$1.04
Chesapeake Energy	$1.06
EnCana	$1.07
Pioneer Natural Resources	$1.09
Newfield Exploration	$1.10
Range Resources	$1.13
Ultra Petroleum	$1.16
Cabot Oil & Gas	$1.18
Devon Energy	$1.28
Anadarko Petroleum	$1.33
XTO Energy	$1.41
Apache	$1.49
Pogo Producing	$1.50
Cimarex Energy	$1.52
Swift Energy	$1.54
Forest Oil	$1.56
St. Mary Land & Exploration	$1.62
Quicksilver Resources	$1.67
Denbury Resources	$2.04

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)
Ultra Petroleum	$0.52
Quicksilver Resources	$1.00
XTO Energy	$1.35
Southwestern Energy Company	$1.69
Range Resources	$1.77
Cabot Oil & Gas	$1.82
EOG Resources, Inc.	$1.90
EnCana	$1.93
Apache	$2.02
Devon Energy	$2.05
Denbury Resources	$2.31
Noble Energy	$2.89
St. Mary Land & Exploration	$3.22
Newfield Exploration	$3.29
Anadarko Petroleum	$4.29
Pioneer Natural Resources	$4.47
Cimarex Energy	$4.48
Forest Oil	$4.58
Chesapeake Energy	$4.58
Swift Energy	$7.18
Pogo Producing Co.	$7.34

Source:  John S. Herold Database

Note:  All data as of December 31, 2004, 2005 and 2006.

(Slide 9)
Operations Overview

(Slide 10)
Capital Investments

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

					2007	2008
	2003	2004	2005	2006	Guidance	Plan
	(in millions)
Utility & Other	$9.3	$13.0	$15.9	$32.7	$19.0	$24.5
Property Acquisitions	$ -	$14.2	$ -	$18.0	$ -	$ -
Cap. Exp. & Other	$12.4	$17.9	$32.4	$62.0	$78.0	$141.7
Leasehold & Seismic	$19.0	$21.1	$60.6	$70.0	$140.0	$103.1
Development Drilling	$119.7	$208.7	$287.6	$421.4	$1,034.0	$1,019.9
Exploration Drilling	$19.8	$20.1	$35.6	$196.0	$83.0	$66.1
Midstream Services	$0.0	$0.0	$15.8	$48.7	$101.0	$100.7
Rig Commitment	$0.0	$0.0	$35.2	$93.6	$ -	$ -
Total	$180.2	$295.0	$483.1	$942.4	$1,455.0	$1,456.0

This slide also contains a pie chart of the company's preliminary planned 2008 capital investments by area of operation, summarized as follows:

	% of Total
	Capital Investments
Arkoma Fayetteville Shale	72%
Arkoma	9%
East Texas	8%
Midstream	7%
Other E&P	2%
Corporate	1%
Utility/Other	<1%

* E&P capital program heavily weighted to low-risk development drilling in 2008.

* Plan to invest over $1 billion in the Fayetteville Shale play in 2008.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 11)

East Texas

This slide contains a map of several counties in East Texas.  The company's Overton, Angelina River Trend and Jebel Prospect acreage positions are highlighted.  The East Texas Salt Basin is 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
2006 Development	78	32.0	383
2007 Development	80	29.6
Planned 2008 Development	42	27 - 29

Jebel Prospect

James Lime Test Well

Timberstar-Mills 1H

IP: 12.1 MMcfd, 100%WI

* Entered area in 2000 with purchase of 10,800 acres at Overton for $6.1 million.

* Current acreage position of 24,400 gross acres at Overton and 80,000 gross acres at Angelina and Jebel.

* Drilled 354 wells at Overton from 2001 to September 30, 2007, with 100% success.

* Future development program at Angelina and Jebel Prospect, including 10-15 James Lime horizontal wells in 2008.

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 Fayetteville Shale Focus Area, Ranger Anticline, Midway and the area known as the Fairway are further noted. 

* 65+ years of experience in the basin, large acreage position of 460,000 net acres in the traditional fairway.
	* 2008 capital program includes drilling 100 - 110 wells in the traditional fairway, Ranger Anticline and Midway areas.
* SWN currently holds approximately 902,000 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 13)
Fayetteville Shale Focus Area

This slide contains a map of the Fayetteville Shale Focus Area in Arkansas.  Existing pilot areas and portions of the conventional fairway are indicated. 777,000 net acres and 125,000 net acres HBP are outlined on the map. Boxes denote Conventional Production (15 MMcf/d). The Scotland Field, Gravel Hill Field, Griffin Mountain Field, Cove Creek Field, New Quitman Field, Chattanooga Test, Ranger Anticline and Moorefield Test are also designated.  The Moorefield Prospective Area is outlined.  Lines trace the Ozark, Centerpoint, NGPL, MRT and TETCO transmission pipelines.

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

* As of September 30, 2007, SWN has drilled and completed 392 wells, of which 290 are horizontal slickwater or crosslinked gel fracture stimulated wells, in 35 separate pilot areas in 8 counties.

* We anticipate participating in 475 horizontal wells in 2008, approximately 75% operated.

* Assuming development of 50% of the acreage within the shaded areas at 80-acre spacing and average ultimate production of 1.5 Bcf gross per well, the potential exists for 8,000 horizontal wells and approximately 12 Tcf gross ultimate recovery.

Note: Data as of September 30, 2007.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 14)
Fayetteville Shale - Improving Well Performance

Time Frame	Wells Placed on Production	Average IP Rate (Mcf/d)	First 30-Day Avg Rate (# of wells)	First 60-Day Avg Rate (# of wells)	Average Lateral Length	Completion Method SW/XL/Hy/RHy	Est. Well Cost ($MM)
1st Qtr 2007	62	1,208	1,023 (62)	921 (62)	2,113	12/40/10	$2.6
2nd Qtr 2007	50	1,473	1,203 (50)	1,030 (50)	2,497	27/12/11	$2.9
3rd Qtr 2007	75	1,836	1,543 (72)	1,350 (72)	2,613	70/4/1	$3.0
SW wells with lateral length > 3000 feet	53	2,165	2,021 (39)	1,850 (25)	3,355	All SW	$3.3

* Focusing on longer laterals, slick-water completions and larger frac jobs.

* For 2008, the average lateral length of planned wells is projected to be approximately 3,300 feet and our average well cost is projected to be $3.05 million.

* Utilizing 3-D seismic to improve overall well performance.  Over 75% of our 2008 planned wells will have the benefit of 3-D seismic (versus 20% in 2007).

(Slide 15)
Fayetteville Project - Gross Production

This line graph shows gross production in MMcf/d for the Fayetteville Shale from January 2006 to December 31, 2007. Gross operated production of approx. 325 MMcf/d as of December 31, 2007.

(Slide 16)
Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through December 5, 2007, for the company's horizontal wells drilled.  This graph displays two composite curves, one showing the SW/XL normalized production from the company's horizontal wells excluding mechanical issues and another showing the SW normalized production from the company's horizontal wells with laterals greater than 3,000 feet excluding mechanical issues. The production data is compared to 2.5 Bcf, 2.0 Bcf and 1.5 Bcf typecurves from the company's reservoir simulation shale gas model.  Well counts and respective days of production are also displayed, as follows:

Days of Production	Total Well Count	SW Horizontal Wells with Laterals > 3,000 Feet
30	282	39
60	251	25
90	234	18
120	208	12
150	182	6
180	171	2
210	154	2
240	139	1
270	117	1
300	93	1
330	81	1
360	63	1
390	50	1
420	42	1
450	34	1
480	29	1
510	22	1
540	17	0
570	5	0
600	3	0
630	2	0
660	1	0
690	1	0
720	1	0
750	1	0
784	1	0

Notes: Data as of December 5, 2007.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 17)
Midstream - Capturing Additional Value Beyond the Wellhead

This slide contains a map of several counties in Arkansas where the company's Fayetteville Shale Focus Area is located.  Lines trace DeSoto Gathering Lines and the Ozark, Centerpoint, NGPL, MRT and TETCO transmission pipelines.  Compression facilities are also indicated on the map.

* Midstream assets provide rapidly growing revenue stream and potential future funding source.

* Currently gathering approximately 370 MMcf per day through 566 miles of gathering lines, up from approximately 100 MMcf per day the same time a year ago.

* Projected EBITDA⁽¹⁾ of $16.0 million in 2007 and $37.0 to $40.0 million in 2008.  Projected CapEx of $101.0 million for 2007 and $100.7 for 2008.

(1) EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of EBITDA on page 25.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 18)
Consistent Commodity Hedging Strategy

This slide contains a bar chart detailing gas hedges in place by quarter for year 2007, year 2008 and year 2009.  A summary of these outstanding gas hedges is as follows:

			Average Price per Mcf	Percent
	Type	Hedged Volumes	(or Floor/Ceiling)	Hedged
2007	Swaps	43.5 Bcf	$7.81	41%
	Collars	36.0 Bcf	$6.99 / $12.21	34%
2008	Swaps	54.0 Bcf	$8.26	38%
	Collars	48.0 Bcf	$7.92 / $11.60	33%
2009	Swaps	64.0 Bcf	$8.25	-
	Collars	23.0 Bcf	$8.09 / $10.91	-

SWN has historically hedged 70 - 80% of projected gas production volumes.

Historical Gas Hedge Percentages
2002	78%
2003	80%
2004	70%
2005	79%
2006	73%
2007	75%

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 19)
Outlook for 2008

* Production target of 148.0 - 152.0 Bcfe in 2008 (estimated growth of ~35%).

	2007	2008 Guidance
	Projected	NYMEX Price Assumptions
	$7.00 Gas	$6.00 Gas	$7.00 Gas	$8.00 Gas
	$70.00 Oil	$60.00 Oil	$70.00 Oil	$80.00 Oil
Net Income	$200 - $205 MM	$225 - $230 MM	$245 - $250 MM	$285 - $290 MM
EPS	$1.16 - $1.19	$1.30 - $1.33	$1.42 - $1.45	$1.65 - $1.68
Net Cash Flow (1)	$610 - $620 MM	$805 - $815 MM	$840 - $850 MM	$905 - $915 MM
EBITDA (1)	$630 - $640 MM	$860 - $870 MM	$895 - $905 MM	$960 - $970 MM
CapEx	$1,455 MM	$1,456 MM	$1,456 MM	$1,456 MM

Note:  Guidance updated as of January 3, 2008.  2007 oil and gas prices include actual last-day NYMEX closing prices.

(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 24 and 25.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 20)
Key Investment Considerations

* Large, diversified and growing reserve base.

* Consistent track record of organic production growth.

* Over 900,000 net acres in the low-risk Fayetteville Shale play.

* Operational efficiency.

* Strong balance sheet and financial discipline.

* Conservative and well-established risk management strategy.

* Experienced management and technical teams.

(Slide 21)
Appendix

(Slide 22)
Financial & Operational Summary

($ in millions except per unit metrics)
	Year Ended December 31,			Twelve Months Ended
	2004	2005	2006	September 30, 2007
Revenues	$477.1	$676.3	$763.1	$1,066.4
Growth (%)	46%	42%	13%
EBITDA (1)	$255.3	$345.9	$414.5	$564.3
Margin (%)	54%	51%	54%	53%
Net Income	$103.6	$147.8	$162.6	$183.3
Discretionary Cash Flow (1)	$237.7	$321.8	$413.5	$555.6
Capital Investments	$295.0	$483.1	$942.4	$1,451.0
Cash & Short-term Investments	$1.2	$223.7	$42.9	$0.6
Total Debt	$325.0	$100.0	$137.8	$731.5
Annual Production (Bcfe)	54.1	61.0	72.3	99.4
Avg. Gas Price ($/Mcf)	$5.21	$6.51	$6.55	$6.62
Avg. Oil Price ($/Bbl)	$31.47	$42.62	$58.36	$59.93
Debt / EBITDA	1.3x	0.3x	0.3x	1.3x
Debt / Book Cap	42%	8%	9%	31%
Debt / Market Cap (2)	15%	2%	2%	10%
EBITDA / Interest Expense	15.0x	23.0x	610.5x	40.6x

(1)    Discretionary cash flow is net cash flow before changes in operating assets and liabilities.  Discretionary cash flow and EBITDA are non-GAAP financial measures.  See explanation and reconciliation of non-GAAP financial measures on pages 24 and 25.

(2)    Market capitalization as of September 30, 2007 was approximately $7.2 billion.

(Slide 23)
Pro Forma Capitalization and Liquidity

Capitalization	As of September 30, 2007
($ in Millions)	Actual		Pro Forma
Cash	$0.6		$0.6
Short-Term Debt
7.15% Senior Notes due 2018 (current)	$1.2		$1.2
Long-Term Debt
Revolving Credit Facility	$594.3	(1)	$200.8	(2)
7.625% Senior Notes due 2027, putable at the holders' option in 2009	60.0		60.0
7.21% Senior Notes due 2017	40.0		40.0
7.15% Senior Notes due 2018	36.0		36.0
New Senior Notes due 2018	-		400.0
Total Long-Term Debt	$730.3		$736.8
Total Debt	$731.5		$738.0
Shareholders' Equity	1,610.5		1,610.5
Total Book Capitalization	$2,342.0		$2,348.5
Total Debt / Total Book Capitalization	31%		31%
Total Debt / Market Capitalization (3)	10%		10%
Liquidity
($ in Millions)
Revolving Credit Facility Availability (4)	$405.7		$799.2
Cash	0.6		0.6
Total Liquidity	$406.3		$799.8

(1)    As of December 31, 2007 we had $842.2 million outstanding under our Revolving Credit Facility.

(2)    Assumes $393.5 million of net proceeds from the Senior Notes Offering.

(3)    Market capitalization as of September 30, 2007 was approximately $7.2 billion.

(4)    Actual is pro forma for the upsize of the Revolving Credit Facility from $750 million to $1,000 million in October 2007.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 24)

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.

	12 Months Ended September 30,	Year Ended December 31,
	2007	2006	2005	2004
	($ in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$555,567	$413,508	$321,758	$237,706
Add back (deduct):
Change in operating assets and liabilities	(21,748)	16,429	(17,276)	191
Net cash provided by operating activities	$533,819	$429,937	$304,482	$237,897

	2007 Guidance	2008 Guidance
	NYMEX Commodity Price Assumptions
	$7.00 Gas	$6.00 Gas	$7.00 Gas	$8.00 Gas
	$70.00 Oil	$60.00 Oil	$70.00 Oil	$80.00 Oil
	($ in millions)
Net cash provided by operating activities	$610-$620	$805-$815	$840-$850	$905-$915
Add back (deduct):
Assumed change in operating assets and liabilities	--	--	--	--
Net cash provided by operating activities before changes in operating assets and liabilities	$610-$620	$805-$815	$840-$850	$905-$915

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 25)

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.

	12 Months Ended September 30,	12 Months Ended December 31,
	2007	2006	2005	2004	2003
	($ in thousands)
Net income	$183,302	$162,636	$147,760	$103,576	$48,897
Depreciation, depletion and amortization	254,984	151,795	96,641	74,919	56,833
Net interest expense	13,906	679	15,040	16,992	17,311
Provision for income taxes	112,065	99,399	86,431	59,778	28,372	(1)
EBITDA	$564,257	$414,509	$345,872	$255,265	$151,413

(1)    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 and 2008, assuming a NYMEX price scenario and the corresponding estimated impact on the company's results for 2007 and 2008, including current hedges in place, as of January 3, 2008:

	2007 Guidance		2008 Guidance
	NYMEX Commodity Price Assumptions
	Corporate	Midstream	Corporate			Midstream
	$7.00 Gas	Services	$6.00 Gas	$7.00 Gas	$8.00 Gas	Services
	$70.00 Oil	Segment	$60.00 Oil	$70.00 Oil	$80.00 Oil	Segment (1)
	($ in millions)
Net income	$200-$205	$5-$7	$225-$230	$245-$250	$285-$290	$15-$17
Add back:
Provision for income taxes - deferred	123-126	2-4	138-141	150-153	175-178	8-10
Interest expense	25-30	2-4	68-73	68-73	68-73	3-5
Depreciation, depletion, and amortization	285-295	3-5	435-445	435-445	435-445	10-12
EBITDA	$630-$640	$15-$17	$860-$870	$895-$905	$960-$970	$37-$40

(1)    Midstream Services segment 2008 results assumes NYMEX commodity prices of $7.00 per Mcf for natural gas and $70.00 per barrel for crude oil.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".