NEWS RELEASE  

SOUTHWESTERN ENERGY ANNOUNCES CAPITAL PROGRAM

AND GUIDANCE FOR 2010

Production Projected to Grow Approximately 36% in 2010;

Low-Cost Operations Sets the Stage for A Record Year

Houston, Texas – December 17, 2009...Southwestern Energy Company (NYSE: SWN) today announced a planned capital investment program for 2010 of approximately $2.1 billion, including approximately $1.5 billion of planned investments in its Fayetteville Shale play in Arkansas. The company’s 2010 capital program includes approximately $1.7 billion for its exploration and production segment, $270 million for its midstream segment and $95 million for corporate and other purposes.

“While we are proud of the accomplishments we have made in the Fayetteville Shale play, which has resulted in another year of significant production growth and record cash flow, we are just beginning to unlock the true value of this play,” stated Steve Mueller, President and Chief Executive Officer of Southwestern Energy. “Our 2010 capital program will allow us to continue our progress in the Fayetteville Shale and East Texas programs, and begin drilling in the Marcellus Shale in Pennsylvania.”

“Our 2010 program in the Fayetteville will continue to focus on optimizing well spacing and completion techniques. We plan to operate 14 horizontal rigs in the Fayetteville Shale, two rigs in our East Texas operations and kick off our drilling activity in the Marcellus Shale in January with one operated rig. Our 2010 production is expected to grow over 100 Bcf and be in a range of 400 to 410 Bcfe, which is an increase of approximately 36% (using midpoints) compared to our expected 2009 levels. The capital program is flexible and will be adjusted to reflect market conditions. It is expected to be funded through our cash flow and our borrowings, while keeping our balance sheet in excellent shape. Gas prices are expected to remain volatile in 2010 but our low-cost operations, our position in a world-class play in the Fayetteville Shale and our financial flexibility will allow us to create significant value. We plan to accelerate the development of our Fayetteville Shale play if gas prices do rebound in 2010,” stated Mueller.

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The following tables provide annual forecast information for 2010, as compared to projected 2009 results, for capital investments and the gross and net well counts (including wells operated by others) for each of the company’s operating areas.

	Capital Investments
	Projected 2009	Forecast 2010
	(in millions)
Fayetteville Shale Play	$        1,260	$        1,200
East Texas	160	230
Appalachia	40	145
New Ventures	22	135
Arkoma Basin	40	25
Midstream Services	220	270
Corporate & Other	58	95
Total Capital Investments	$        1,800	$        2,100

	Gross Well Count		Net Well Count
	Projected 2009	Forecast 2010	Projected 2009	Forecast 2010
Fayetteville Shale Play	540	650-680	355	375-400
East Texas	50	50-60	28	25-30
Appalachia	--	35-40	--	25-29
Arkoma Basin	20	15-20	7	5-6
Total Well Count	610	750-800	390	430-465

Southwestern expects to participate in approximately 750 to 800 total gross wells (520 to 555 operated), compared to an estimated 610 total gross wells in 2009 (approximately 460 operated). The company’s 2010 net well count will be approximately 430 to 465 wells compared to approximately 390 net wells in 2009.

In 2010, Southwestern plans to participate in approximately 650 to 680 gross wells in the Fayetteville Shale play, 475 to 500 of which will be operated. The company expects its average drilled lateral length per operated horizontal well in the Fayetteville Shale play to increase to approximately 4,500 feet, up from an average of approximately 4,080 feet in 2009. However, due to lower proppant costs resulting from the operation of a company-owned sand mine and increased efficiencies, the company expects to more than offset the higher drilling and completion costs associated with longer laterals and is currently projecting average completed well costs of $2.75 million per well for 2010. Approximately 36% of the operated wells are planned to be the first well drilled in a section and approximately 200 wells are planned to further test appropriate downspacing for the play. The company is expected to average approximately 1.5 new wells drilled per section in 2010, compared to approximately 1.8 new wells per section in 2009. Over 98% of these operated wells will be drilled with the benefit of the company’s growing 3-D seismic database.

In East Texas, the company expects to participate in approximately 50 to 60 gross wells, 22

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to 27 of which will be operated. Of the wells planned in 2010, 21 to 26 wells will be targeting the Haynesville or Middle Bossier Shales and 29 to 34 wells will be targeting the James Lime, Pettet or Cotton Valley formations. In the Marcellus Shale play in Pennsylvania, the company plans to begin drilling in January 2010 with one operated rig and participate in a total of 35 to 40 wells, 21 to 24 of which will be operated. Southwestern also expects to invest approximately $135 million in various other unconventional, exploration and New Ventures projects in 2010.

Of the approximate $1.7 billion E&P capital budget for 2010, $1.3 billion (or 76%) will be invested in development and exploratory drilling, $25 million in seismic and other geological and geophysical (G&G) expenditures, $180 million in leasehold and $220 million in capitalized interest and expenses and other equipment, facilities and technology-related expenditures.

Southwestern Issues Guidance for 2010

Southwestern is targeting total gas and oil production of 400 to 410 Bcfe, up approximately 36% (using midpoints) over the company’s current forecasted 2009 production of 297 to 300 Bcfe. Approximately 344 to 352 Bcf of the 2010 targeted gas production is projected to come from the company’s activities in the Fayetteville Shale play, up from the 2009 projected production of approximately 243 to 245 Bcf.

As of December 17, 2009, the company had NYMEX fixed price hedges in place on notional volumes of 36.0 Bcf of its 2010 gas production at a weighted average price of $9.04 per MMBtu and collars in place on notional volumes of 14.0 Bcf of its 2010 gas production at an average floor and ceiling price of $8.29 and $10.57 per MMBtu, respectively. The company’s projected results for 2010 are as follows:

Estimated Production by Quarter in 2010

1^st Quarter

2^nd Quarter

3^rd Quarter

4^th Quarter

Full-Year 2010

Total Production (Bcfe) 91 - 93 99 - 101 103 - 106 107 - 110 400 - 410

Estimated E&P Pricing Deductions in 2010 ($ per Mcfe, except for fuel charges)

Average Basis Differential

$0.10 - $0.20

Average Transportation Charge

$0.25 - $0.32

Average Fuel Charge

0.25% - 1.00%

Estimated E&P Operating Expenses in 2010 (assumes $5.00 gas price)

Lease Operating Expenses

$0.87 - $0.92

General & Administrative Expense

$0.32 - $0.37

Taxes, Other Than Income Taxes

$0.20 - $0.25

Other Operating Income and Expenses in 2010 ($ in millions)

Midstream Operating Income

$145.0 - $155.0

Net Interest Expense

$19.0 - $20.0

Income Tax Rate (99% Deferred)

38.0%

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Assuming a NYMEX commodity price of $5.00 per Mcf of gas for 2010, the company is targeting net income of $640 - $650 million and net cash provided by operating activities before changes in operating assets and liabilities (a non-GAAP measure; see “Explanation and Reconciliation of Non-GAAP Financial Measures” below) of $1,680 - $1,690 million in 2010. The company expects its operating income to approximate $1,065 - $1,075 million and its net income plus interest, income tax expense, depreciation, depletion and amortization (also known as EBITDA, a non-GAAP measure; see “Explanation and Reconciliation of Non-GAAP Financial Measures” below) to be approximately $1,690 - $1,700 million in 2010. The company’s debt-to-total capitalization ratio is expected to range between 29% and 31% at year-end 2010.The company has also provided additional price scenarios and their corresponding estimated financial results for 2010 in the table below:

NYMEX Commodity Prices	Net Income	Operating Income	Net Cash Flow (1)	EBITDA (1)
$4.00 Gas	$435 - $445 Million	$735 - $745 Million	$1,355 - $1,365 Million	$1,365 - $1,375 Million
$5.00 Gas	$640 - $650 Million	$1,065 - $1,075 Million	$1,680 - $1,690 Million	$1,690 - $1,700 Million
$6.00 Gas	$845 - $855 Million	$1,390 - $1,400 Million	$1,990 - $2,000 Million	$2,010 - $2,020 Million

(1)

Net cash provided by operating activities before changes in operating assets and liabilities and EBITDA are non-GAAP measures; see Explanation and Reconciliation of Non-GAAP Financial Measures below.

Explanation and Reconciliation of Non-GAAP Financial Measures

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. The table below reconciles 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.

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	2010 Guidance
	NYMEX Commodity Price Assumption
	$4.00 Gas	$5.00 Gas	$6.00 Gas
	$70.00 Oil	$70.00 Oil	$70.00 Oil
		($ in millions)
Net cash provided by operating activities	$1,355-$1,365	$1,680-$1,690	$1,990-$2,000
Add back (deduct):
Assumed change in operating assets and liabilities	--	--	--
Net cash flow	$1,355-$1,365	$1,680-$1,690	$1,990-$2,000

EBITDA is defined as net income plus interest expense, 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 2010 forecasted EBITDA with 2010 forecasted net income.

	2010 Guidance
	NYMEX Commodity Price Assumption
	$4.00 Gas	$5.00 Gas	$6.00 Gas
	$70.00 Oil	$70.00 Oil	$70.00 Oil
		($ in millions)
Net income (loss) attributable to SWN	$435-$445	$640-$650	$845-$855
Add back:
Provision (benefit) for income taxes	271-277	395-401	518-524
Interest expense	21-22	19-20	16-17
Depreciation, depletion and amortization	625-630	625-630	625-630
EBITDA	$1,365-$1,375	$1,690-$1,700	$2,010-$2,020

Southwestern Energy Company is an integrated company whose wholly-owned subsidiaries are engaged in oil and gas exploration and production, natural gas gathering and marketing. Additional information on the company can be found on the Internet at http://www.swn.com.

Contacts:

Greg D. Kerley

Brad D. Sylvester, CFA

Executive Vice President

Vice President, Investor Relations

and Chief Financial Officer

            (281) 618-4897

(281) 618-4803

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

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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 company’s ability to transport its production to the most favorable markets or at all; 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 impact of federal, state and local government regulation, including any increase in severance taxes; the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services; the company’s future property acquisition or divestiture activities; increased competition; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of the company’s lenders to provide it with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by the company’s counterparties 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 the 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.

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