UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark one)
[ X ] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended June 30, 2007
or
[    ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from___________ to ___________
Commission file number   1-08246
SOUTHWESTERN ENERGY COMPANY
(Exact name of the registrant as specified in its charter)
Delaware	71-0205415
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2350 N. Sam Houston Pkwy. E., Suite 125, Houston, Texas	77032
(Address of principal executive offices)	(Zip Code)
(281) 618-4700
(Registrant's telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year; if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes:   X	No:
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer   X                                      Accelerated filer                                       Non-accelerated filer
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes:	No:   X
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Class	Outstanding at July 27, 2007
Common Stock, Par Value $0.01	170,229,759

FORWARD-LOOKING INFORMATION

All statements, other than historical fact or present 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 our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-Q identified by words such as "anticipate," "project," "intend," "estimate," "expect," "believe," "predict," "budget," "projection," "goal," "plan," "forecast," "target" or similar expressions.

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 our operations, markets, products, services and prices and cause our 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 our 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 our success in discovering, developing, producing and estimating reserves;

*

the economic viability of, and our success in drilling, our large acreage position in the Fayetteville Shale play, overall as well as relative to other productive shale gas plays;

*

our 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;

*

our ability to fund our planned capital investments;

*

our future property acquisition or divestiture activities;

1

*

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 we have filed and may file with the Securities and Exchange Commission (“SEC”).

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, third-party interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved natural gas and oil reserves and in projecting future rates of production and timing of development expenditures and the other risks described in our Annual Report on Form 10-K for the year ended December 31, 2006 (the “2006 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto, including this Form 10-Q (“Form 10-Qs”).

Should one or more of the risks or uncertainties described above or elsewhere in our 2006 Annual Report on Form 10-K or the Form 10-Qs occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

2

PART I

FINANCIAL INFORMATION

3

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
STATEMENTS OF OPERATIONS
(Unaudited)
		For the three months ended				For the six months ended
		June 30,				June 30,
		2007		2006		2007		2006
		(in thousands, except share/per share amounts)
Operating Revenues:
	Gas sales	$	184,059	$	107,570	$	395,703	$	288,368
	Gas marketing		72,238		34,051		127,555		65,016
	Oil sales		10,216		10,409		19,453		20,444
	Gas transportation and other		3,569		1,969		12,023		6,873
			270,082		153,999		554,734		380,701
Operating Costs and Expenses:
	Gas purchases - midstream services		69,488		31,733		122,705		60,160
	Gas purchases - gas distribution		7,427		3,464		55,408		48,820
	Operating expenses		20,485		16,077		40,522		30,468
	General and administrative expenses		17,935		15,238		34,683		29,791
	Depreciation, depletion and amortization		66,435		31,950		122,220		60,053
	Taxes, other than income taxes		6,306		7,243		13,431		13,311
			188,076		105,705		388,969		242,603
Operating Income			82,006		48,294		165,765		138,098
Interest Expense:
	Interest on long-term debt		7,384		2,642		11,509		4,819
	Other interest charges		545		317		926		643
	Interest capitalized		(2,923)		(2,823)		(5,971)		(5,181)
			5,006		136		6,464		281
Other Income (Loss)			(125)		13,281		(104)		16,457
Income Before Income Taxes and Minority Interest			76,875		61,439		159,197		154,274
Minority Interest in Partnership			(111)		(114)		(194)		(405)
Income Before Income Taxes			76,764		61,325		159,003		153,869
Provision for Income Taxes - Deferred			29,170		24,321		60,421		58,470
Net Income		$	47,594	$	37,004	$	98,582	$	95,399
Earnings Per Share:
	Basic	$	0.28	$	0.22	$	0.58	$	0.57
	Diluted	$	0.28	$	0.22	$	0.57	$	0.56
Weighted Average Common Shares Outstanding:
	Basic	169,466,912		167,044,589		169,036,525		166,911,812
	Diluted	172,500,541		170,888,839		172,268,902		170,918,407
The accompanying notes are an integral part of these consolidated financial statements.
4

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
BALANCE SHEETS
(Unaudited)
ASSETS
			June 30,		December 31,
			2007		2006
			(in thousands)
Current Assets
	Cash and cash equivalents		$	311	$	42,927
	Accounts receivable			153,156		131,370
	Inventories, at average cost			61,678		62,488
	Hedging asset - FAS 133			50,048		64,082
	Other			18,981		22,969
		Total current assets		284,174		323,836
Property, Plant and Equipment, at cost
	Gas and oil properties, using the full cost method,       including $221.8 million in 2007 and $166.8 million       in 2006 excluded from amortization			3,313,573		2,651,427
	Gas distribution systems			231,491		226,067
	Gathering systems			96,694		51,836
	Gas in underground storage			32,254		32,254
	Other			86,280		77,702
				3,760,292		3,039,286
	Less: Accumulated depreciation, depletion and amortization			1,144,838		1,022,786
				2,615,454		2,016,500
Other Assets				29,366		38,733
Total Assets			$	2,928,994	$	2,379,069
The accompanying notes are an integral part of these consolidated financial statements.
5

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
BALANCE SHEETS
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
			June 30,		December 31,
			2007		2006
			(in thousands)
Current Liabilities
	Current portion of long-term debt		$	1,200	$	1,200
	Accounts payable			319,163		266,023
	Taxes payable			11,212		16,088
	Advances from partners and customer deposits			30,781		31,941
	Hedging liability - FAS 133			13,816		23,864
	Over-recovered purchased gas costs			14,681		10,580
	Current deferred income taxes			7,886		19,162
	Other			10,847		10,002
		Total current liabilities		409,586		378,860
Long-Term Debt				496,100		136,600
Other Liabilities
	Deferred income taxes			413,282		370,522
	Long-term hedging liability			15,965		4,902
	Pension liability			12,492		11,697
	Other			31,740		30,811
				473,479		417,932
Commitments and Contingencies
Minority Interest in Partnership				11,093		11,034
Stockholders' Equity
	Common stock, $0.01 par value; authorized 540,000,000     shares, issued 170,201,992 shares in 2007     and 168,953,893 in 2006			1,702		1,690
	Additional paid-in capital			766,054		740,609
	Retained earnings			759,439		660,857
	Accumulated other comprehensive income			11,541		31,487
				1,538,736		1,434,643
Total Liabilities and Stockholders' Equity			$	2,928,994	$	2,379,069
The accompanying notes are an integral part of these consolidated financial statements.
6

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
STATEMENTS OF CASH FLOWS
(Unaudited)
			For the six months ended
			June 30,
			2007		2006
			(in thousands)
Cash Flows From Operating Activities
	Net income		$	98,582	$	95,399
	Adjustments to reconcile net income to
	net cash provided by operating activities:
		Depreciation, depletion and amortization		122,887		60,657
		Deferred income taxes		60,421		58,470
		Unrealized loss on derivatives		4,589		4,919
		Stock-based compensation expense		2,648		2,018
		Gain on sale of investment in partnership and other property		-		(10,863)
		Equity in income of NOARK partnership		-		(925)
		Minority interest in partnership		59		(10)
	Change in assets and liabilities:
		Accounts receivable		(21,786)		47,958
		Inventories		811		2,265
		Under/over-recovered purchased gas costs		4,101		371
		Accounts payable		14,403		(24,080)
		Advances from partners and customer deposits		(1,161)		4,134
		Deferred tax benefit - stock options		(17,764)		(6,397)
		Other assets and liabilities		(9,572)		(4,865)
	Net cash provided by operating activities			258,218		229,051
Cash Flows From Investing Activities
	Capital investments			(704,583)		(357,195)
	Proceeds from sale of investment in partnership and other property			2,712		69,065
	Other items			158		(43)
	Net cash used in investing activities			(701,713)		(288,173)
Cash Flows From Financing Activities
	Debt retirement			(600)		(600)
	Payments on revolving long-term debt			(355,200)		-
	Borrowings under revolving long-term debt			715,300		-
	Revolving credit facility amendment costs			(1,275)		-
	Excess tax benefit for stock-based compensation			17,764		6,397
	Change in bank drafts outstanding			21,056		3,222
	Proceeds from exercise of common stock options			3,834		2,390
	Net cash provided by financing activities			400,879		11,409
Decrease in cash and cash equivalents				(42,616)		(47,713)
Cash and cash equivalents at beginning of year				42,927		223,705
Cash and cash equivalents at end of period			$	311	$	175,992
The accompanying notes are an integral part of these consolidated financial statements.
7

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
									Accumulated
	Common Stock				Additional				Other
	Shares				Paid-In		Retained		Comprehensive
	Issued		Amount		Capital		Earnings		Income (Loss)		Total
	(in thousands)
Balance at December 31, 2006	168,954	$	1,690	$	740,609	$	660,857	$	31,487	$	1,434,643
Comprehensive income:
Net income	-		-		-		98,582		-		98,582
Change in value of derivatives	-		-		-		-		(19,946)		(19,946)
Total comprehensive income (loss)	-		-		-		-		-		78,636
Tax benefit for stock-based compensation	-		-		17,764		-		-		17,764
Stock-based compensation - FAS 123(R)	-		-		3,859		-		-		3,859
Exercise of stock options	1,242		12		3,822		-		-		3,834
Issuance of restricted stock	22		-		-		-		-		-
Cancellation of restricted stock	(16)		-		-		-		-		-
Balance at June 30, 2007	170,202	$	1,702	$	766,054	$	759,439	$	11,541	$	1,538,736

STATEMENT OF COMPREHENSIVE INCOME (LOSS)
		For the three months ended				For the six months ended
		June 30,				June 30,
			2007		2006		2007		2006
		(in thousands)				(in thousands)
Net Income		$	47,594	$	37,004	$	98,582	$	95,399
Change in value of derivatives
	Current period reclassification to earnings		(1,798)		928		(14,054)		(115)
	Current period ineffectiveness		(114)		(2,760)		4,809		(4,466)
	Current period change in derivative instruments		40,130		23,529		(10,701)		88,692
	Total Change in value of derivatives		38,218		21,697		(19,946)		84,111
Comprehensive Income, end of period		$	85,812	$	58,701	$	78,636	$	179,510
The accompanying notes are an integral part of these consolidated financial statements.
8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southwestern Energy Company and Subsidiaries

June 30, 2007

(1)

BASIS OF PRESENTATION

The financial statements included herein are unaudited; however, such information reflects all adjustments (consisting solely of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the results for the interim periods. The Company's significant accounting policies, which have been reviewed and approved by the audit committee of the Company’s Board of Directors, are summarized in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2006 (the "2006 Annual Report on Form 10-K").

(2)

GAS AND OIL PROPERTIES

The Company utilizes the full cost method of accounting for costs related to the exploration, development, and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive) including salaries, benefits and other internal costs directly attributable to these activities are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves discounted at 10 percent (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense.  The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Full cost companies must use the prices in effect at the end of each accounting quarter, including the impact of derivatives qualifying as hedges, to calculate the ceiling value of their reserves. However, commodity price increases subsequent to the end of a reporting period but prior to the release of periodic reports may be utilized to calculate the ceiling value of reserves. At June 30, 2007 and 2006, the Company’s unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At June 30, 2007, the ceiling value of the Company’s reserves was calculated based upon quoted market prices of $6.80 per Mcf for Henry Hub gas and $67.25 per barrel for West Texas Intermediate oil, adjusted for market differentials, and included approximately $129.0 million related to the positive effects of future cash flow hedges of natural gas production. The Company had approximately 176.0 Bcf of future production hedged at June 30, 2007. A decline in natural gas and oil prices from June 30, 2007 levels or other factors, without other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings.

9

(3)

EARNINGS PER SHARE

The following table presents the computation of earnings per share for the three and six months ended June 30, 2007 and 2006, respectively:

	For the three months ended		For the six months ended
	June 30,		June 30,
	2007	2006	2007	2006
Net Income (in thousands)	$        47,594	$        37,004	$        98,582	$        95,399
Number of Common Shares:
Weighted average outstanding	169,466,912	167,044,589	169,036,525	166,911,812
Issued upon assumed exercise of outstanding stock options	2,789,110	3,308,304	3,017,657	3,464,833
Effect of issuance of nonvested restricted common shares	244,519	535,946	214,720	541,762
Weighted average and potential dilutive outstanding (1)	172,500,541	170,888,839	172,268,902	170,918,407
Net Income per Common Share:
Basic	$            0.28	$           0.22	$            0.58	$           0.57
Diluted	$            0.28	$           0.22	$            0.57	$           0.56

(1)   Options for 209,730 shares for the six months ended June 30, 2007, and for 223,780 shares for the comparable period of 2006, were excluded from the calculations because they would have had an antidilutive effect.  Additionally, 200 shares of restricted stock for the six months ended June 30, 2007, and 124,990 shares of restricted stock for the comparable period of 2006, were excluded from the calculations because they would have had an antidilutive effect.

(4)

DEBT

Debt balances as of June 30, 2007 and December 31, 2006 consisted of the following:

	June 30,	December 31,
	2007	2006
	(in thousands)
Short-term:
7.15% Senior Notes due 2018 (current portion)	$     1,200	$     1,200
Long-term:
Variable rate (6.20% at June 30, 2007) unsecured revolving       credit arrangements	360,100	-
7.625% Senior Notes due 2027, putable at the holders' option       in 2009	60,000	60,000
7.21% Senior Notes due 2017	40,000	40,000
7.15% Senior Notes due 2018	36,000	36,600
Total long-term debt	496,100	136,600
Total debt	$  497,300	$  137,800

10

In February 2007, the Company amended its unsecured revolving credit facility increasing the borrowing capacity to $750 million, lowering the borrowing cost and extending the maturity date to 2012. The amount available under the revolving credit facility may be increased to $1 billion at any time upon the Company’s agreement with its existing or additional lenders.  There was $360.1 million outstanding under the revolving credit facility at June 30, 2007, compared to no amount outstanding at December 31, 2006. The interest rate on the amended credit facility is calculated based upon the Company’s debt rating and is currently 87.5 basis points over the current London Interbank Offered Rate (LIBOR). The revolving credit facility is currently guaranteed by the Company’s subsidiaries, Southwestern Energy Production Company, SEECO, Inc. and Southwestern Energy Services Company and requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied. The revolving credit facility also contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in excess of 60% of its total capital, must maintain a certain level of stockholders' equity, and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of 3.5 or above. There are also restrictions on the ability of the Company’s subsidiaries to incur debt.  At June 30, 2007, the Company’s capital structure consisted of 24% debt and 76% equity and it was in compliance with the covenants of its debt agreements.

(5)

DERIVATIVES AND RISK MANAGEMENT

Management enters into various types of derivative instruments for a portion of the Company’s projected gas and oil sales to reduce its exposure to market price volatility for natural gas and oil.  At June 30, 2007, our gas derivative instruments consisted of price swaps, costless collars and basis swaps. Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133), as amended by FAS 137, FAS 138 and FAS 149, requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at its fair value. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement or as a component of other comprehensive income. The Company’s hedging practices are summarized in Note 8 of the Notes to Consolidated Financial Statements of the 2006 Annual Report on Form 10-K.

At June 30, 2007, the Company's net asset recorded on the balance sheet related to its hedging activities was $30.9 million. Additionally, at June 30, 2007, the Company had recorded a gain to other comprehensive income (loss) of $21.5 million related to its hedging activities. The amount recorded in other comprehensive income (loss) will be relieved over time and taken to the income statement as the physical transactions being hedged occur. Assuming the market prices of gas and oil futures as of June 30, 2007 remain unchanged, the Company would expect to transfer an aggregate after-tax gain of approximately $22.3 million from accumulated other comprehensive income to earnings during the next 12 months. The change in accumulated other comprehensive income (loss) related to derivatives was a gain of $61.6 million ($38.2 million after tax) compared to a gain of $34.4 million ($21.7 million after tax) for the three months ended June 30, 2007 and 2006, respectively, and a loss of $32.2 million ($19.9 million after tax) compared to a gain of $133.5 million ($84.1 million after tax) for the six months ended June 30, 2007 and 2006, respectively.  Additional volatility in earnings and other comprehensive income (loss) may occur in the future as a result of the application of FAS 133.

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(6)

SEGMENT INFORMATION

The Company's three reportable business segments, Exploration and Production (E&P),  Midstream Services and Natural Gas Distribution, have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and crude oil. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced gas volumes and through gathering fees associated with the transportation of natural gas to market. Gathering revenues have been insignificant to-date, but are expected to increase in the future depending upon the level of production from our Fayetteville Shale properties. Revenues for the Natural Gas Distribution segment arise from the transportation and sale of natural gas at retail.

Summarized financial information for the Company's reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the 2006 Annual Report on Form 10-K. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs and expenses. Income before income taxes is the sum of operating income, interest expense, other income (expense) and minority interest in partnership. The "Other" column includes items not related to the Company's reportable segments including real estate, corporate items and the Company’s former investment in the Ozark Gas Transmission system.

	Exploration And Production	Midstream Services	Natural Gas Distribution	Other		Total
	(in thousands)
Three months ended June 30, 2007:
Revenues from external customers	$    168,434	$     74,079	$     27,569	$              -		$    270,082
Intersegment revenues	13,364	159,588	36	112		173,100
Operating income (loss)	81,352	2,310	(1,706)	50		82,006
Interest and other income (loss) (1)	21	-	(153)	7		(125)
Depreciation, depletion and amortization expense	64,039	744	1,615	37		66,435
Interest expense (1)	3,546	381	1,079	-		5,006
Provision (benefit) for income taxes (1)	29,533	733	(1,117)	21		29,170
Assets	2,501,659	187,779	175,296	64,260	(2)	2,928,994	(2)
Capital investments (3)	369,125	23,660	3,339	717		396,841
Three months ended June 30, 2006:
Revenues from external customers	$     97,243	$     34,282	$     22,474	$              -		$    153,999
Intersegment revenues	9,066	69,178	36	112		78,392
Operating income (loss)	49,501	799	(2,092)	86		48,294
Interest and other income (loss) (1)	2,563	-	(146)	10,864		13,281
Depreciation, depletion and amortization expense	30,186	172	1,569	23		31,950
Interest expense (1)	104	-	32	-		136
Provision (benefit) for income taxes (1)	20,611	315	(776)	4,171		24,321
Assets	1,580,458	68,828	177,296	217,835	(2)	2,044,417	(2)
Capital investments (3)	189,309	11,144	2,836	3,842		207,131

12

Six months ended June 30, 2007:
Revenues from external customers	$    319,889	$    130,398	$    104,447	$              -		$    554,734
Intersegment revenues	23,170	281,858	152	224		305,404
Operating income	155,662	2,321	7,675	107		165,765
Interest and other income (loss) (1)	93	-	(204)	7		(104)
Depreciation, depletion and amortization expense	117,113	1,786	3,249	72		122,220
Interest expense (1)	3,639	381	2,444	-		6,464
Provision for income taxes (1)	57,730	737	1,910	44		60,421
Assets	2,501,659	187,779	175,296	64,260	(2)	2,928,994	(2)
Capital investments (3)	670,323	45,280	5,943	2,548		724,094
Six months ended June 30, 2006:
Revenues from external customers	$    214,680	$     65,336	$    100,685	$              -		$    380,701
Intersegment revenues	20,793	146,798	160	225		167,976
Operating income	130,280	1,869	5,815	134		138,098
Interest and other income (loss) (1)	4,854	1	(195)	11,797		16,457
Depreciation, depletion and amortization expense	56,433	406	3,166	48		60,053
Interest expense (1)	204	-	77	-		281
Provision for income taxes (1)	51,119	710	2,107	4,534		58,470
Assets	1,580,458	68,828	177,296	217,835	(2)	2,044,417	(2)
Capital investments (3)	344,217	15,912	6,331	7,217		373,677

(1)

Interest income, interest expense and the provision (benefit) for income taxes by segment are allocations as they are incurred at the corporate level.

(2)

Other assets include corporate assets not allocated to segments, assets for non-reportable segments and the Company's investment in cash equivalents.

(3)

Capital investments include $64.0 million and $17.7 million for the three- and six-month periods ended June 30, 2007, respectively, and $5.7 million and $15.3 million for the three- and six-month periods ended June 30, 2006, respectively, relating to the change in accrued expenditures between periods.

Included in intersegment revenues of the Midstream Services segment are $142.1 million and $59.1 million for the second quarters of 2007 and 2006, respectively, and $249.1 million and $122.6 million for the six months ended June 30, 2007 and 2006, respectively, for marketing of the Company's E&P sales. Intersegment sales by the E&P segment and Midstream Services segment to the Natural Gas Distribution segment are priced in accordance with terms of existing contracts and current market conditions. Parent company assets include furniture and fixtures and prepaid debt costs. Parent company general and administrative costs, depreciation expense and taxes other than income are allocated to segments. All of the Company's operations are located within the United States.

13

(7)

INTEREST AND INCOME TAXES PAID

The following table provides interest and income taxes paid during each period presented:

	For the six months ended
	June 30,
	2007		2006
	(in thousands)
Interest payments	$	11,080	$	5,138
Income tax payments	$	-	$	6

(8)

CONTINGENCIES AND COMMITMENTS

Operating Commitments

The Company has various operating commitments in the normal course of its operations. The Company has not made any new material operating commitments or modified its disclosed material commitments other than as disclosed in the 2006 Annual Report on Form 10-K and the Form 10-Q for the period ended March 31, 2007.

Environmental

The Company is subject to laws and regulations relating to the protection of the environment. The Company's policy is to accrue environmental and cleanup related costs of a non-capital nature when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material adverse effect on the financial position or results of operations of the Company.

Litigation

The Company is subject to litigation and claims that arise in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of litigation and claims currently pending will not have a material adverse effect on the financial position or results of operations of the Company.

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(9)

STOCK-BASED COMPENSATION

The Company has incentive plans that provide for the issuance of equity awards, including stock options and restricted stock. These plans are discussed more fully in Note 9 of the Notes to Consolidated Financial Statements included in Item 8 of the 2006 Annual Report on Form 10-K. The Company has issued options and restricted stock under these plans. All options are issued at fair market value at the date of grant and expire seven years from the date of grant for awards under the 2004 Plan and ten years from the date of grant for awards under all other plans. Generally, stock options granted to employees and directors vest ratably over three to four years from the grant date. There were no stock options granted during the first six months of 2007. The Company issues shares of restricted stock to employees and directors which generally vest over four years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the individual grants with the exception of awards granted to participants who have reached retirement age and have met the minimum service requirements in order to become fully vested prior to the requisite service period.

For the second quarter and first six months of 2007, the Company recorded compensation cost of $0.5 and $1.3 million, respectively, in general and administrative expense related to stock options.  Additional amounts of $0.1 million and $0.3 million for the same respective periods were directly related to the acquisition, exploration and development activities for the Company’s gas and oil properties and were capitalized into the full cost pool. The Company also recorded a deferred tax benefit of $0.5 million related to stock options for the six months ended June 30, 2007. A total of $4.6 million of unrecognized compensation costs related to stock options not yet vested is expected to be recognized over future periods. For the second quarter and first six months of 2006, the Company recorded compensation cost of $0.6 and $1.0 million, respectively, in general and administrative expense related to stock options.  Additional amounts of $0.1 million and $0.3 million for the same respective periods were directly related to the acquisition, exploration and development activities for the Company’s gas and oil properties and were capitalized into the full cost pool.

For the second quarter 2007, restricted stock expense recorded in general and administrative expenses was $0.6 million. For the six months ended June 30, 2007, $1.3 million of general and administrative expense related to restricted stock was recognized.  Additional amounts of $0.4 million and $0.9 million for the same respective periods were capitalized into the full cost pool. As of June 30, 2007, there was $10.3 million of total unrecognized compensation cost related to nonvested shares of restricted stock. For the second quarter 2006, restricted stock expense recorded in general and administrative expenses was $0.5 million. For the six months ended June 30, 2006, $0.9 million of general and administrative expense related to restricted stock was recognized.  Additional amounts of $0.3 million and $0.6 million for the same respective periods were capitalized into the full cost pool.

15

The following tables summarize stock option activity for the first half of 2007 and provide information for options outstanding at June 30, 2007:

	Number  of Options	Weighted Average Exercise  Price
Outstanding at December 31, 2006	5,792,240	$     6.19
Granted	-	-
Exercised	(1,241,622)	3.09
Forfeited or expired	(12,000)	20.91
Outstanding at June 30, 2007	4,538,618	$     7.01
Exercisable at June 30, 2007	3,990,314	$     3.95

During the first six months of 2007 and 2006 there were no options granted. The total intrinsic value of options exercised during the first six months of 2007 and 2006 was $48.6 million and $23.1 million, respectively. Associated with the exercise of stock options, the Company received a tax benefit of $17.8 million and $6.4 million in the first six months of 2007 and 2006, respectively. The tax benefit is recorded as an increase in additional paid-in capital.

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Options Outstanding at June 30, 2007	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (in thousands)	Options Exercisable at June 30, 2007	Weighted Average Exercise Price	Aggregate Intrinsic Value (in thousands)
$1.50 - $1.86	1,728,945	$       1.75	3.0		1,728,945	$      1.75
$1.87 - $2.85	472,108	2.52	4.0		472,108	2.52
$2.86 - $5.00	761,806	2.90	5.1		761,806	2.90
$5.01 - $12.00	759,462	5.48	6.5		719,462	5.45
$12.01 - $42.00	816,297	25.98	5.2		307,993	17.55
	4,538,618	$       7.01	4.5	$  170,175	3,990,314	$       3.95	$  161,822

The following table summarizes restricted stock activity for the first half of 2007:

	Number of  Shares	Weighted Average Grant Date  Fair Value
Unvested shares at December 31, 2006	478,732	$   25.30
Granted	22,250	40.39
Vested	(10,716)	14.50
Forfeited	(15,772)	28.81
Unvested shares at June 30, 2007	474,494	$   26.13

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(10) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company applies Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans." Substantially all employees are covered by the Company's defined benefit pension and postretirement benefit plans. Net periodic pension and other postretirement benefit costs include the following components for the three- and six-month periods ended June 30, 2007 and 2006:

	Pension Benefits
	For the three months ended June 30,		For the six months ended June 30,
	2007	2006	2007	2006
	(in thousands)
Service cost	$       996	$      753	$    1,992	$    1,505
Interest cost	1,061	970	2,121	1,940
Expected return on plan assets	(1,139)	(1,144)	(2,279)	(2,288)
Amortization of prior service cost	118	109	237	218
Amortization of net loss	115	190	230	380
Net periodic benefit cost	$    1,151	$      878	$    2,301	$    1,755

	Postretirement Benefits
	For the three months ended June 30,		For the six months ended June 30,
	2007	2006	2007	2006
	(in thousands)
Service cost	$      105	$        67	$      209	$      135
Interest cost	54	47	108	94
Expected return on plan assets	(20)	(17)	(40)	(34)
Amortization of net loss	5	9	10	17
Amortization of transition obligation	21	21	43	43
Net periodic benefit cost	$      165	$      127	$      330	$      255

The Company currently expects to contribute $6.5 million to the pension plans and $0.4 million to the postretirement benefit plans in 2007. As of June 30, 2007, $1.5 million has been contributed to our pension plans, and $0.2 million has been contributed to the postretirement benefit plans.

(11) ASSET RETIREMENT OBLIGATIONS

Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," (FAS 143) requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Company owns natural gas and oil properties which require expenditures to plug and abandon the wells

17

when reserves in the wells are depleted. These expenditures under FAS 143 are recorded in the period the liability is incurred (at the time the wells are drilled or acquired). The following table summarizes the Company's activity related to asset retirement obligations (in thousands) for the six-month period ended June 30, 2007 and for the year ended December 31, 2006:

Asset retirement obligation at January 1	$  10,545	$    9,229
Accretion of discount	224	401
Obligations incurred	894	1,152
Obligations settled/removed	(272)	(645)
Revisions of estimates	(1)	408
Asset retirement obligation at June 30, 2007 and December 31, 2006	$  11,390	$  10,545
Current liability	702	593
Long-term liability	10,688	9,952
Asset retirement obligation at June 30, 2007 and December 31, 2006	$  11,390	$  10,545

(12) NEW ACCOUNTING PRONOUNCEMENTS

During the first quarter of fiscal 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48).  FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a threshold condition that a tax position must meet to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions.  FIN 48 was effective for fiscal years beginning after December 15, 2006.  The adoption of FIN 48 had no material impact on the Company’s results of operations and financial condition.  The income tax years 2003-2006 remain open to examination by the major taxing jurisdictions to which the Company is subject.

In September 2006, the Financial Accounting Standards Board issued SFAS No. 157, “Fair Value Measurements” (FAS 157).  FAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Prior to this statement, there were different definitions of fair value and limited guidance for applying those definitions in GAAP.  In developing FAS 157, FASB considered the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. This statement applies to other accounting pronouncements that require or permit fair value measurements. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company has not yet determined the impact FAS 157 may have on its results of operations or financial condition.  

In February 2007, the Financial Accounting Standards Board issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (FAS 159). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value.  Most of the provisions of this statement apply only to entities that elect the fair value option. This statement applies to other accounting pronouncements that require or permit fair value measurements. FAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company has not yet determined the impact FAS 159 may have on its results of operations or financial condition.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following updates information as to Southwestern Energy Company's financial condition provided in our 2006 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three- and six-month periods ended June 30, 2007 and 2006. For definitions of commonly used gas and oil terms used in this Form 10-Q, please refer to the "Glossary of Certain Industry Terms" provided in our 2006 Annual Report on Form 10-K.

This Form 10-Q contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in our forward-looking statements for many reasons, including the risks described in Item 1A, "Risk Factors" in Part I and elsewhere in our 2006 Annual Report on Form 10-K and Item 1A, “Risk Factors” in Part II in this Form 10-Q. You should read the following discussion with our financial statements and related notes included in this Form 10-Q.  

OVERVIEW

Southwestern Energy Company is an independent energy company primarily focused on natural gas. Our primary business is the exploration, development and production of natural gas and crude oil within the United States, with operations principally located in Arkansas, Oklahoma, Texas and New Mexico. We are also focused on creating and capturing additional value at and beyond the wellhead through our established natural gas distribution and marketing businesses and our expanding gathering activities. Our marketing and our gas gathering businesses are collectively referred to as our Midstream Services.  We operate principally in three segments: Exploration and Production (E&P), Midstream Services and Natural Gas Distribution.

Our business strategy is focused on providing long-term growth in the net asset value of our business, which we achieve in our E&P business through the drillbit. In our E&P business, we prepare economic analyses for each of our drilling and acquisition opportunities and rank them based upon the expected present value added for each dollar invested, which we refer to as PVI. The PVI of the future expected cash flows for each project is determined using a 10% discount rate. Our actual PVI results are utilized to help determine the allocation of our future capital investments.  

We derive the vast majority of our operating income and cash flow from the natural gas production of our E&P business and expect this to continue in the future.  We expect that growth in our operating income and revenues will primarily depend on natural gas prices and our ability to increase our natural gas production.  In recent years, there has been significant price volatility in natural gas and crude oil prices due to a variety of factors we cannot control or predict.  These factors, which include weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas, which determines the pricing.  In addition, the price we realize for our gas production is affected by our hedging activities as well as locational differences in market prices.  Our ability to increase our natural gas production is dependent upon our ability to economically find and produce natural gas, our ability to control costs and our ability to market natural gas on economically attractive terms to our customers.

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Three Months Ended June 30, 2007, Compared with Three Months Ended June 30, 2006

In the second quarter of 2007, our gas and oil production increased to 25.8 Bcfe, up 57% from the second quarter of 2006.  The increase in 2007 production primarily resulted from a significant increase in production from our Fayetteville Shale play as a result of our ongoing development program.

We reported net income of $47.6 million in the second quarter of 2007, or $0.28 per share on a fully diluted basis, up 29% from the prior year, due to increased production volumes in our E&P segment and higher realized natural gas prices, which were up 11% from the second quarter of 2006.  This increase was partially offset by increased operating costs and expenses. Our cash flow from operating activities was $129.8 million in the second quarter of 2007, up from $85.7 million due primarily to the increase in net income and adjustments for non-cash expenses. Operating income for our E&P segment was $81.4 million for the second quarter of 2007, up 64% from the comparable period of 2006 as a result of the increased production volumes and higher realized prices for our gas production, partially offset by increased operating costs and expenses. Operating income for our Midstream Services segment was $2.3 million for the second quarter of 2007, compared to $0.8 million in the second quarter of 2006, due primarily to an increase in gathering revenues. Our Natural Gas Distribution segment’s seasonal operating loss decreased 18% to $1.7 million for the three months ended June 30, 2007, primarily due to increased deliveries as a result of colder weather.

Our capital investments increased approximately 92% to $396.8 million for the second quarter of 2007, of which $369.1 million was invested in our E&P segment.

Six Months Ended June 30, 2007, Compared with Six Months Ended June 30, 2006

For the six months ended June 30, 2007, our gas and oil production increased to 48.7 Bcfe, up 51% compared to the same period in 2006.  The increase in 2007 production primarily resulted from the increase in production from our Fayetteville Shale play.  

We reported net income of $98.6 million for the first six months of 2007, or $0.57 per share on a fully diluted basis, up 3% from the prior year, as increased production volumes in our E&P segment were largely offset by increased operating costs and expenses and lower realized natural gas prices, which were down 3% from the same period in 2006.  Our cash flow from operating activities was $258.2 million for the first six months of 2007, up from $229.1 million, due primarily to an increase in net income and adjustments to net income for non-cash expenses. Operating income for our E&P segment was $155.7 million for the six months ended June 30, 2007, up from $130.3 million in the comparable period of 2006, as a result of increased production volumes which were partially offset by increased operating costs and expenses and lower realized prices for our gas production. Operating income for our Midstream Services segment was $2.3 million for the first six months of 2007, up from $1.9 million for the same period of 2006, due to an increase in gas gathering revenues from the Fayetteville Shale play. Operating income for our Natural Gas Distribution segment increased to $7.7 million for the six months ended June 30, 2007, up from $5.8 million in the comparable period of 2006, primarily due to colder weather in the first part of the year.

Our capital investments increased approximately 94% to $724.1 million for the six months ended June 30, 2007, of which $670.3 million was invested in our E&P segment.

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RESULTS OF OPERATIONS

Exploration and Production

	For the three months ended		For the six months ended
	June 30,		June 30,
	2007	2006	2007	2006
Revenues (in thousands)	$181,798	$106,309	$343,059	$235,473
Operating income (in thousands)	$81,352	$49,501	$155,662	$130,280
Gas production (MMcf)	24,848	15,404	46,734	30,240
Oil production (MBbls)	166	170	333	347
Total production (MMcfe)	25,841	16,426	48,732	32,322
Average gas price per Mcf, including hedges	$6.90	$6.23	$6.81	$7.03
Average gas price per Mcf, excluding hedges	$6.83	$6.16	$6.53	$6.87
Average oil price per Bbl, including hedges	$61.72	$61.11	$58.42	$58.91
Average oil price per Bbl, excluding hedges	$61.72	$66.99	$58.42	$63.75
Average unit costs per Mcfe
Lease operating expenses	$0.73	$0.64	$0.73	$0.58
General & administrative expenses	$0.48	$0.60	$0.47	$0.57
Taxes, other than income taxes	$0.21	$0.39	$0.23	$0.36
Full cost pool amortization	$2.41	$1.79	$2.33	$1.69

Revenues, Operating Income and Production

Revenues. Revenues for our E&P segment were up 71% for the three months ended June 30, 2007, compared to the same period in 2006, primarily due to increased production volumes and higher gas prices realized for our production. Revenues were up 46% for the six months ended June 30, 2007, compared to the first half of 2006, primarily due to increased production volumes. Revenues for the first six months of 2007 and 2006 also include pre-tax gains of $5.1 million and $1.9 million, respectively, related to the sale of gas in storage inventory. We expect our production volumes to continue to increase due to the continued development of our Fayetteville Shale play in Arkansas. Gas and oil prices are difficult to predict and subject to wide price fluctuations. As of July 27, 2007, we have hedged 43.0 Bcf of our remaining 2007 gas production, 85.0 Bcf of 2008 gas production and 48.0 Bcf of 2009 gas production to limit our exposure to price fluctuations.

Operating Income.Operating income for the E&P segment was up 64% to $81.4 million for the second quarter of 2007 from $49.5 million for the same period in 2006.  For the six months ended June 30, 2007, operating income increased 19% to $155.7 from $130.3 for the same period in 2006.  The increases in operating income were a result of the increases in revenues, partially offset by increases in operating costs and expenses.

Production. Gas and oil production during the second quarter of 2007 was up approximately 57% to 25.8 Bcfe and was up approximately 51% to 48.7 Bcfe for the first six months of 2007 as compared to

21

prior periods due to an increase in production from our Fayetteville Shale play as a result of our ongoing development program. Our total gas production was up approximately 61% to 24.8 Bcf for the second quarter of 2007 which represented approximately 96% of our total equivalent production and up approximately 55% to 46.7 Bcf for the first six months of 2007. Net production from the Fayetteville Shale was 10.7 Bcf in the second quarter of 2007, compared to 1.8 Bcf in the second quarter of 2006. For the first six months of 2007, production from the Fayetteville Shale was 18.9 Bcf compared to 2.5 Bcf for the first six months of 2006. As of July 28, 2007, our gross production rate from our Fayetteville Shale properties approximated 200.0 MMcf per day.

Commodity Prices

We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and crude oil production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials (we refer you to Item 3 and Note 5 of the Notes to Consolidating Financial Statements in this Form 10-Q for additional discussion). The average price realized for our gas production, including the effect of hedges, increased approximately 11% to $6.90 per Mcf for the three months ended June 30, 2007, and decreased 3% to $6.81 for the first six months of 2007 as compared to the same periods last year. The change in the average price realized primarily reflects changes in average spot market prices and the effects of our price hedging activities. Our hedging activities increased our average gas price $0.07 per Mcf during the second quarters of both 2007 and 2006. Our hedging activities increased our average gas price $0.28 per Mcf for the first six months of 2007, compared to an increase of $0.16 per Mcf during the same period of 2006. Locational differences in market prices for natural gas have continued to be wider than historically experienced.  We had financially protected approximately 84% of our production in the second quarter of 2007 from the impact of widening basis differentials.  For the remainder of 2007, we have protected approximately 74% of our anticipated gas production from the impact of widening basis differentials through our hedging activities and sales arrangements.  Disregarding the impact of hedges, the average price received for our gas production during the first six months of 2007 was approximately $0.63 lower than average NYMEX spot prices, which represented the average locational basis differential.

As of July 27, 2007, we have NYMEX commodity price hedges in place for 43.0 Bcf of our 2007 gas production. For our 2008 and 2009 future gas production, we have hedges in place on 85.0 Bcf and 48.0 Bcf, respectively. Additionally, we have basis swaps on 34.2 Bcf for the remainder of 2007, and for 2008 we have basis swaps on 53.2 Bcf in order to reduce the effects of changes in market differentials on prices we receive.

Operating Costs and Expenses

Lease operating expenses per Mcfe for our E&P segment increased 14% to $0.73 for the second quarter of 2007, and 26% to $0.73 for the first six months of 2007, primarily as a result of increases in our gathering and compression costs related to our operations in the Fayetteville Shale play. Based on our projected production, we expect our per unit operating costs for 2007 to range between $0.82 and $0.87 per Mcfe.

General and administrative expenses per Mcfe decreased 20% to $0.48 for the second quarter of 2007 and 18% to $0.47 for the first six months of 2007, due primarily to the effects of our increased

22

production volumes.  Total general and administrative expenses for our E&P segment were $12.3 million in the second quarter of 2007, compared to $9.8 million in the second quarter of 2006 and were $23.1 million for the first six months of 2007, compared to $18.3 million for the first six months of 2006. The increases in general and administrative costs were due primarily to increased payroll and related costs associated with the expansion of our E&P operations due to the Fayetteville Shale play.  We expect our per unit G&A expense to continue to decline for the remainder of 2007 and to range between $0.41 and $0.46 per Mcfe for the year due to increased production volumes from our Fayetteville Shale play.

Our full cost pool amortization rate averaged $2.41 per Mcfe for the second quarter of 2007 and $2.33 for the first six months of 2007, up 35% and 38%, respectively, compared to the same periods in 2006. Our full cost pool amortization rate increased due to increased capital investments and future development costs relative to reserve additions, including revisions. We currently expect our full cost pool amortization rate to range between $2.20 and $2.40 per Mcfe for the year. The amortization rate is impacted by the timing and amount of reserve additions and the costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from full cost ceiling tests, and the level of unevaluated costs excluded from amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as the uncertainty of the amount of future reserves attributed to our Fayetteville Shale play. Unevaluated costs excluded from amortization were $221.8 million at June 30, 2007, compared to $152.4 million at June 30, 2006. The increase in unevaluated costs since June 30, 2006 resulted primarily from an increase in our undeveloped leasehold acreage and seismic costs related to our Fayetteville Shale play and our increased drilling activity.

We utilize the full cost method of accounting for costs related to the exploration, development, and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive) including salaries, benefits and other internal costs directly attributable to these activities are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves discounted at 10 percent (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense.  The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Full cost companies must use the prices in effect at the end of each accounting quarter, including the impact of derivatives qualifying as hedges, to calculate the ceiling value of their reserves. However, commodity price increases subsequent to the end of a reporting period but prior to the release of periodic reports may be utilized to calculate the ceiling value of reserves. At June 30, 2007 and 2006, the Company’s unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At June 30, 2007, the ceiling value of our reserves was calculated based upon quoted market prices of $6.80 per Mcf for Henry Hub gas and $67.25 per barrel for West Texas Intermediate oil, adjusted for market differentials, and included approximately $129.0 million related to the positive effects of future cash flow hedges of natural gas production. We had approximately 176.0 Bcf of future production hedged at June 30, 2007 (see Item 3 of this Form 10-Q for additional discussion of our hedging activities). A decline in natural gas and oil prices from June 30, 2007 levels or other factors, without other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings.

23

Taxes other than income taxes per Mcfe decreased 46% to $0.21 for the second quarter of 2007, compared to the same period in 2006 and decreased 36% to $0.23 for the six months ended June 30, 2007, compared to the first half of 2006, primarily due to the effects of the changing mix of production.

The timing and amount of production and reserve additions attributed to our Fayetteville Shale play could have a material impact on per unit costs; if production or reserves additions are lower than projected, our per unit costs would increase.

Midstream Services

	For the three months ended		For the six months ended
	June 30,		June 30,
	2007	2006	2007	2006
	($ in thousands)
Revenues	$233,667	$103,460	$412,256	$212,134
Gas purchases	$224,221	$99,853	$395,900	$205,386
Operating costs and expenses	$7,136	$2,808	$14,035	$4,879
Operating income	$2,310	$799	$2,321	$1,869
Gas volumes marketed (Bcf)	32.3	16.6	59.4	30.4

Revenues from our Midstream Services segment were up 126% in the second quarter of 2007 and up 94% for the first six months of 2007, as compared to prior year periods. The increases in revenues primarily resulted from an increase in volumes marketed and increased gathering revenues. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in gas purchase expense. Midstream Services had gathering revenues of $7.5 million in the second quarter of 2007 and $12.4 million for the first six months of 2007, compared to $1.3 million and $1.9 million for the comparable periods of 2006. Gathering revenues and expenses for this segment are expected to continue to grow in the future as reserves related to our Fayetteville Shale play are developed and production increases. Operating income from our Midstream Services segment increased 189% in the second quarter of 2007 and 24% for the first six months of 2007, as compared to the same periods of 2006 as a result of the increases in gathering revenues from the Fayetteville Shale play. The margin generated from natural gas marketing activities was down 15% for the second quarter of 2007 and down 19% for the first six months of 2007 as compared to the same periods of 2006.  Margins fluctuate depending on the prices paid for commodities and the ultimate disposition of those commodities. The increase in volumes marketed in the second quarter of 2007, as compared to the same period in 2006, resulted from increased production volumes in the Fayetteville Shale play. Approximately 70% of our volumes marketed for the second quarters and first six months of 2006 and 2007 related to affiliated gas production volumes. We enter into hedging activities from time to time with respect to our gas marketing activities to provide margin protection. We refer you to Item 3, "Qualitative and Quantitative Disclosure about Market Risks" in this Form 10-Q for additional information.

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Natural Gas Distribution

	For the three months ended		For the six months ended
	June 30,		June 30,
	2007	2006	2007	2006
Revenues (in thousands)	$27,605	$22,510	$104,599	$100,845
Gas purchases (in thousands)	$16,186	$11,624	$70,403	$68,129
Operating costs and expenses (in thousands)	$13,125	$12,978	$26,521	$26,901
Operating income (loss) (in thousands)	($1,706)	($2,092)	$7,675	$5,815
Sales and end-use transportation deliveries (Bcf)	4.2	3.6	13.7	12.0
Sales customers at period-end	149,389	146,489	149,389	146,489
Average sales rate per Mcf	$11.34	$12.34	$10.85	$12.93
Heating weather - degree days	359	163	2,300	1,950
Percent of normal	111%	50%	92%	78%

Revenues and Operating Income

Revenues for the second quarter of 2007 increased 23% from the comparable period of 2006 and increased 4% for the six months ended June 30, 2007 from the comparable period of 2006 due to increases in volumes delivered that resulted from colder weather.  Weather during the first six months of 2007 was 8% warmer than normal and 14% colder than the same period in 2006.

Operating income for our Natural Gas Distribution segment increased 18% in the second quarter of 2007 and increased 32% for the first six months of 2007, as compared to the same periods of 2006, due to the increases in volumes delivered.

Deliveries and Rates

Deliveries increased 17% and 14% in the three- and six-month periods ended June 30, 2007, respectively, as compared to the same periods of 2006, due to the colder weather. The average sales rate per Mcf decreased during the second quarter and the first six months as an increase in incremental volumes delivered had more impact on the average rates than did changes in natural gas prices.

Our utility segment hedged 3.1 Bcf of derivative gas purchases in the first half of 2007, which had the effect of increasing its total gas supply cost by $6.6 million.  In the first six months of 2006, our utility hedged 1.8 Bcf of its gas supply, which increased its total gas supply cost by $6.8 million. Additionally, our utility segment currently has hedges in place on 2.1 Bcf of gas purchases at an average purchase price of $8.71 per Mcf for the 2007-2008 winter season. See Note 5 of the Notes to Consolidated Financial Statements and Item 3 of this Form 10-Q for additional information regarding our commodity price risk hedging activities.

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In July 2007, in response to our utility segment’s request for a $13.1 million rate increase, the APSC approved a rate increase totaling $5.8 million annually, exclusive of costs to be recovered through the utility’s purchase gas adjustment clause. The rate increase will be effective for billings rendered on or after August 1, 2007. The original request relating to the August 2007 increase assumed a rate of return of 11.5% and a capital structure of 50% debt and 50% equity. The APSC order provided for an allowed return on equity of 9.5% and an assumed capital structure of 55% debt and 45% equity.

Operating Costs and Expenses

For the first half of 2007, operating costs and expenses (exclusive of purchased gas costs) for this segment were lower than the comparable period of the prior year due primarily to lower general and administrative expenses. The decrease in general and administrative expenses primarily resulted from a decrease in corporate expenses allocated to the natural gas distribution segment.

Transportation

In the second quarter of 2006, we sold our 25% partnership interest in NOARK to Atlas Pipeline Partners, L.P. for $69.0 million and recognized a pre-tax gain of approximately $10.9 million ($6.7 million after tax) relating to the transaction.  Pre-tax income from operations of $0.9 million for the first six months of 2006 and the gain on the sale in the second quarter were recorded in other income in our statements of operations.

Other Revenues

Other revenues for the first six months of 2007 and 2006 included pre-tax gains of $5.1 million and $1.9 million, respectively, related to the sale of gas-in-storage inventory.

Interest Expense and Interest Income

Interest costs, net of capitalization, increased to $5.0 million and $6.5 million for the second quarter and the first six months of 2007, respectively, due to increased debt levels resulting from our increased level of capital investments. We capitalized $6.0 million of interest in the first six months of 2007 compared to $5.2 million for the same period in 2006, as our costs excluded from amortization in the E&P segment increased to $221.8 million at June 30, 2007, compared to $152.4 million at June 30, 2006.

During the first six months of 2007, we earned interest income of $0.1 million related to our cash equivalents, compared to $4.8 million for the same period in 2006. These amounts are recorded in other income.  We had no cash investments as of June 30, 2007.

Income Taxes

Our provision for deferred income taxes was an effective rate of 38.0% for both the first six months of 2007 and 2006. Any changes in the provision for deferred income taxes recorded each period result primarily from the level of income before income taxes, adjusted for permanent differences.

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Pension Expense

We incurred pension costs of $1.3 million and $2.6 million in the second quarter and first six months of 2007, respectively, for our pension and other postretirement benefit plans, compared to $1.0 million and $2.0 million for the same periods of 2006. The increases were primarily the result of an increase in our number of employees. The amount of pension expense recorded is determined by actuarial calculations and is also impacted by the funded status of our plans. We currently expect to contribute $6.9 million to our pension and other postretirement plans in 2007. As of June 30, 2007, $1.5 million has been contributed to our pension plans and $0.2 million has been contributed to our other postretirement plans. For further information regarding our pension plans, we refer you to Note 10 of the Notes to Consolidating Financial Statements in this Form 10-Q.

Stock-Based Compensation

     We recognized expense of $2.6 million and capitalized $1.2 million to the full cost pool for stock-based compensation in the first six months of 2007, compared to $2.0 million expensed and $0.9 million capitalized to the full cost pool for the comparable period of 2006. We refer you to Note 9 of the Notes to Consolidating Financial Statements in this Form 10-Q for additional discussion of our equity based compensation plans.

Adoption of Accounting Principles

During the first quarter of 2007, we adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48).  FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in FAS 109. FIN 48 prescribes a threshold condition that a tax position must meet to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions.  FIN 48 was effective for fiscal years beginning after December 15, 2006.  The adoption of FIN 48 had no material impact on our results of operations and financial condition.

LIQUIDITY AND CAPITAL RESOURCES

We depend on internally-generated funds, our unsecured revolving credit facility (discussed below under "Financing Requirements") and funds accessed through public debt and equity markets as our primary sources of liquidity. We may borrow up to $750 million under our revolving credit facility from time to time. The amount available under our revolving credit facility may be increased up to $1 billion at any time upon our agreement with our existing or additional lenders. As of June 30, 2007, we had $360.1 million outstanding under our revolving credit facility. At December 31, 2006, we had no indebtedness outstanding under our revolving credit facility.

Net cash provided by operating activities increased 13% to $258.2 million in the first six months of 2007, compared to the same period in 2006, due primarily to an increase in net income and adjustments for non-cash expenses. For the first six months of 2007, requirements for our capital investments were met primarily by our revolving credit facility, cash provided by operating activities, and cash equivalents from the sale and operating leaseback of our drilling rigs on December 29, 2006.  

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At June 30, 2007, our capital structure consisted of 24% debt and 76% equity.  We believe that our operating cash flow and borrowings under our credit facility will be adequate to meet our capital and operating requirements for the remainder of 2007, however, we may also raise funds in the public debt and equity markets to meet a portion of our cash requirements.

Our cash flow from operating activities is highly dependent upon market prices that we receive for our gas and oil production. The price received for our production is also influenced by our commodity hedging activities, as more fully discussed in Item 3, "Quantitative and Qualitative Disclosures about Market Risks" and Note 5 to the Notes to Consolidating Financial Statements in this Form 10-Q. Natural gas and oil prices are subject to wide fluctuations. As a result, we are unable to forecast with certainty our future level of cash flow from operations. We adjust our discretionary uses of cash dependent upon cash flow available.

Capital Investments

Our capital investments increased 94% to $724.1 million (including $17.7 million for the change in accrued expenditures from December 31, 2006 to June 30, 2007) for the first half of 2007 as compared to the same period last year, of which $670.3 million was invested in our E&P segment. E&P segment investments during the first half of 2006 were $344.2 million, including $45.2 million for drilling rigs that were subsequently sold and leased back in December 2006. Our projected capital investments for 2007 of $1,341 million include approximately $1,237 million related to our E&P segment, of which we expect to allocate approximately $875 million to our Fayetteville Shale play. Our capital investment program for the remainder of 2007 is expected to be funded through cash flow from operations and borrowings under our revolving credit facility. We may also raise funds in the public debt and equity markets to fund a portion of our capital investment program. We may also adjust our level of 2007 capital investments dependent upon our level of cash flow generated from operations, our ability to borrow under our credit facility or access the capital markets.

Financing Requirements

Our total debt outstanding was $497.3 million at June 30, 2007, compared to $137.8 million at December 31, 2006. Our revolving credit facility was amended in February 2007, increasing our borrowing capacity to $750 million (with an accordion feature for an additional $250 million) lowering our borrowing cost and extending the maturity date to February 2012. At June 30, 2007, we had $360.1 million debt under our revolving credit facility. The interest rate on the facility is calculated based upon our public debt rating and is currently 87.5 basis points over LIBOR. The revolving credit facility is currently guaranteed by our subsidiaries, Southwestern Energy Production Company, SEECO, Inc. and Southwestern Energy Services Company and requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied. Our publicly traded notes were downgraded on August 1, 2006 by Standard and Poor’s to BB+ with a stable outlook from BBB- with a negative outlook. We have a Corporate Family Rating of Ba2 by Moody’s, and our publicly traded notes were rated Ba3 by Moody’s under Moody’s Loss Given Default Assessment on September 19, 2006. Any future downgrades in our public debt ratings could increase our cost of funds under the credit facility. We do not expect our current ratings to impact our ability to obtain acceptable financing terms if we elect to access the public debt market in the future.

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Our revolving credit facility contains covenants which impose certain restrictions on us. Under the credit agreement, we may not issue total debt in excess of 60% of our total capital, must maintain a certain level of stockholders’ equity and must maintain a ratio of EBITDA to interest expense of 3.5 or above. Additionally, there are certain limitations on the amount of indebtedness that may be incurred by our subsidiaries. We were in compliance with all of the covenants of our credit agreement at June 30, 2007. Although we do not anticipate any violations of our financial covenants, our ability to comply with those covenants is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas and oil. If we are unable to borrow under our credit facility, we would have to decrease our capital investment plans.

At June 30, 2007, our capital structure consisted of 24% debt and 76% equity. Stockholders’ equity in the June 30, 2007 balance sheet includes an accumulated other comprehensive gain of $21.5 million related to our hedging activities that is required to be recorded under the provisions of Statement on Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133), and a loss of $9.9 million related to changes in our pension liability and the adoption of FAS 158. The amount recorded for FAS 133 is based on current market values of our hedges at June 30, 2007, and does not necessarily reflect the value that we will receive or pay when the hedges ultimately are settled, nor does it take into account revenues to be received associated with the physical delivery of sales volumes hedged. Our credit facility’s financial covenants with respect to capitalization percentages exclude the effects of non-cash entries that result from FAS 133 and FAS 158 and the non-cash impact of any full cost ceiling write-downs. Our capital structure at June 30, 2007 would be 25% debt and 75% equity without consideration of the accumulated other comprehensive gain and loss related to FAS 133 and FAS 158.

As part of our strategy to ensure a certain level of cash flow to fund our operations, we have hedged approximately 74% of our expected 2007 gas production. The amount of long-term debt we incur will be dependent upon commodity prices and our capital investment plans. If commodity prices remain at or near their current levels throughout the remainder of 2007, our capital investment plans do not change and we do not issue equity, we will increase our long-term debt in 2007 by approximately $700 to $750 million. If commodity prices significantly decrease, we may decrease and/or reallocate our planned capital investments.

Off-Balance Sheet Arrangements

On May 2, 2006, we sold our 25% partnership interest in NOARK to Atlas Pipeline Partners, L.P., for $69.0 million. As part of the transaction, we assumed and recorded $39.0 million of debt obligations of NOARK Pipeline Finance, L.L.C., which we had previously guaranteed as part of the financing of NOARK.

On December 29, 2006, we entered into a sale/leaseback transaction pursuant to which we sold 13 operating drilling rigs, two rigs yet to be delivered and related equipment and then leased such drilling rigs and equipment from the buyer for an initial term of eight years commencing January 1, 2007 for aggregate rental payments of approximately $19.6 million annually. Subject to certain conditions, we have options to purchase the rigs and related equipment from the lessors at the end of the 84th month of the lease term at an agreed upon price or at the end of the lease term for the then fair market value. Additionally, we have the option to renew each lease for a negotiated renewal term at a periodic rental

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equal to the fair market rental value of the rigs as determined at the time of renewal.

Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Other than the agreements mentioned below, there have been no material changes to our contractual obligations as disclosed in our 2006 Annual Report on Form 10-K.

During the first quarter of 2007, one of our E&P subsidiaries renegotiated a previous agreement with a rig operating company, resulting in the net reduction of our future commitments for rig operating fees by approximately $20.6 million over the next three years.

Contingent Liabilities and Commitments

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. As a result of actuarial data, we expect to record expenses of $5.3 million in 2007 for these plans, of which $2.6 million has been recorded in the first six months of 2007. At June 30, 2007, we had an accrued pension benefit liability recorded of $12.5 million. For further information regarding our pension and other postretirement benefit plans, we refer you to Note 10 of the Notes to Consolidating Financial Statements in this Form 10-Q.

We are subject to litigation and claims (including with respect to environmental matters) that arise in the ordinary course of business. Management believes, individually or in aggregate, such litigation and claims will not have a material adverse impact on our financial position or our results of operations, but these matters are subject to inherent uncertainties and management's view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable.

Working Capital

We maintain access to funds that may be needed to meet capital requirements through our credit facility described above. We had negative working capital of $125.4 million at June 30, 2007, and $55.0 million at December 31, 2006. Current assets decreased at June 30, 2007 primarily due to a decrease of $42.0 million in cash equivalents. Current liabilities increased $30.7 million primarily due to an increase in our accounts payable at June 30, 2007. Both changes reflect our increased level of capital investments as discussed in “Capital Investments” above.

Gas in Underground Storage

We record our gas stored in inventory that is owned by the E&P segment at the lower of weighted average cost or market. Gas expected to be cycled within the next 12 months is recorded in current assets with the remaining stored gas reflected as a long-term asset. The quantity and average cost of gas in storage was 9.1 Bcf at $3.89 per Mcf at June 30, 2007, and 9.6 Bcf at $3.89 per Mcf at December 31, 2006.

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The gas in inventory for the E&P segment is used primarily to supplement field production in meeting the segment's contractual commitments, including delivery to customers of our natural gas distribution business, particularly during periods of colder weather. As a result, demand fees paid by the Natural Gas Distribution segment to the E&P segment, which are passed through to the utility's customers, are a part of the realized price of the gas in storage. In determining the lower of cost or market for storage gas, we utilize the gas futures market in assessing the price we expect to be able to realize for our gas in inventory. A significant decline in the future market price of natural gas could result in a write-down of our gas in storage carrying cost.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as credit risk concentrations. We use natural gas and crude oil swap agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price and interest rate risks. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of customers and their dispersion across geographic areas. No single customer accounts for greater than 5% of accounts receivable at June 30, 2007. In addition, please see the discussion of credit risk associated with commodities trading below.

Interest Rate Risk

At June 30, 2007, we had $497.3 million of total debt with an average interest rate of 6.52%.  Our revolving credit facility has a floating interest rate (6.20% at June 30, 2007). At June 30, 2007, we had $360.1 million of borrowings outstanding under the facility.  Our policy is to manage interest rates through use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposures when appropriate.  We do not have any interest rate swaps in effect currently.

Commodities Risk

We use over-the-counter natural gas and crude oil swap agreements and options to hedge sales of our production, to hedge activity in our midstream services segment, and to hedge the purchase of gas in our natural gas distribution segment against the inherent price risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps), and (3) the purchase and sale of index-related puts and calls (collars) that provide a "floor" price below which the counterparty pays (production hedge) or receives (gas purchase hedge) funds equal to the amount by which the price of the commodity is below the

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contracted floor, and a "ceiling" price above which we pay to (production hedge) or receive from (gas purchase hedge) the counterparty the amount by which the price of the commodity is above the contracted ceiling.

The primary market risks related to our derivative contracts are the volatility in market prices and basis differentials for natural gas and crude oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major investment and commercial banks that management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are periodically reviewed to limit our credit risk exposure.

Exploration and Production

The following table provides information about our financial instruments that are sensitive to changes in commodity prices and that are used to hedge prices for our future gas production. The table presents the notional amount in Bcf (billion cubic feet), the weighted average contract prices, and the fair value by expected maturity dates. At June 30, 2007, the fair value of our financial instruments related to natural gas production and underground storage sales was a $30.8 million asset.

	Volume	Weighted Average Price to be Swapped ($)	Weighted Average Floor Price ($)	Weighted Average Ceiling Price ($)	Weighted Average Basis Differential ($)	Fair Value at June 30, 2007 ($ in millions)
Natural Gas (Bcf):
Fixed Price Swaps:
2007 (1)	26.2	7.91	-	-	-	16.2
2008 (2)	37.6	8.35	-	-	-	5.8
2009	26.0	8.05	-	-	-	(3.5)
Costless Collars:
2007	17.0	-	6.85	10.64	-	4.8
2008	48.0	-	7.92	11.60	-	12.5
2009	22.0	-	7.83	11.18	-	(2.4)
Basis Swaps:
2007	19.1	-	-	-	(0.55)	(1.8)
2008	44.1	-	-	-	(0.47)	(1.8)
Matched-Basis Swaps:
2007	15.1	-	-	-	(0.42)	1.7
2008	8.0	-	-	-	(0.73)	(0.7)

(1)

Includes fixed-price swaps for 0.2 Bcf relating to future sales from our underground storage facility that have a fair value asset of $0.2 million.

(2)

Includes fixed-price swaps for 0.6 Bcf relating to future sales from our underground storage facility that have a fair value asset of $0.5 million.

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At June 30, 2007, we had outstanding fixed-price basis differential swaps on 19.1 Bcf of 2007 and 44.1 Bcf of 2008 gas production that did not qualify for hedge accounting treatment, as shown in the table above. The fair value of these differential swaps was a liability of $3.6 million at June 30, 2007.  As of July 27, 2007, we have basis-protected an additional 1.1 Bcf of future gas production subsequent to the end of the quarter.

At December 31, 2006, the Company had outstanding natural gas price swaps on total notional volumes of 32.5 Bcf in 2007 and 13.0 Bcf in 2008 for which the Company will receive fixed prices ranging from $6.20 to $12.06 per MMBtu. At December 31, 2006, the Company had outstanding fixed price basis differential swaps on 62.0 Bcf of 2007 and 2008 gas production that did not qualify for hedge treatment.  

At December 31, 2006, the Company had collars in place on notional volumes of 34.0 Bcf in 2007 and 22.0 Bcf in 2008. The 34.0 Bcf in 2007 had an average floor and ceiling price of $6.93 and $12.34 per MMBtu, respectively. The 22.0 Bcf in 2008 had an average floor and ceiling price of $7.92 and $13.15 per MMBtu, respectively.

Midstream Services

At June 30, 2007, our Midstream Services segment had outstanding hedges in place on 1.0 Bcf of gas.  These hedges are a mixture of fixed-price swap purchases and sales relating to our gas marketing activities. These hedges have contract months from July 2007 through March 2008 and have fair value asset of $0.9 million as of June 30, 2007.  An additional liability of $0.8 million was recognized as an offset to these hedges for physical gas purchases and sales commitments relating specifically to the hedged deals.

Natural Gas Distribution

At June 30, 2007, our Natural Gas Distribution segment had outstanding hedges in place on 0.8 Bcf of gas.  These hedges are fixed-price swap purchases that relate to the utility’s planned hedging program for the winter heating season. These hedges have contract months from November 2007 through March 2008, and have a fair value liability of $0.4 million as of June 30, 2007.  As of July 27, 2007, we have entered into additional hedges of 1.3 Bcf for total outstanding hedges of 2.1 Bcf related to the utility’s future gas purchases.

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ITEM 4. CONTROLS AND PROCEDURES

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act).  Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of June 30, 2007, and provided a level of reasonable assurance with respect to financial statement preparation and presentation. There were no changes in our internal control over financial reporting during the three months ended June 30, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

The Company is subject to litigation and claims that arise in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such litigation and claims will not have a material effect on the results of operations or the financial position of the Company.

ITEM 1A. RISK FACTORS.

There were no additions or material changes to the Company’s risk factors as disclosed in Item 1A of Part I in the Company’s 2006 Annual Report on Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

Not applicable.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

The Company held its Annual Meeting of Shareholders on May 10, 2007, for the purpose of electing Directors of the Company for the ensuing year and to ratify the appointment of PricewaterhouseCoopers LLP to serve as the Company’s independent registered public accounting firm for 2007. Holders of 157,626,046 shares (93.26% of total outstanding shares) voted in total.

The Directors were elected with the number of shares voted as follows:

	Voted For	Withheld
Lewis E. Epley, Jr.	157,356,268	269,778
Robert L. Howard	156,298,723	1,327,323
Harold M. Korell	156,387,546	1,238,500
Vello A. Kuuskraa	157,352,653	273,393
Kenneth R. Mourton	156,295,339	1,330,707
Charles E. Scharlau	147,777,869	9,848,177

Holders of 157,310,677 shares voted for the proposal to ratify the appointment of PricewaterhouseCoopers LLP to serve as the Company’s independent registered public accounting firm for 2007, 68,382 shares voted against and 246,987 shares abstained.

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ITEM 5. OTHER INFORMATION.

Not applicable.

ITEM 6. EXHIBITS.

(31.1)

Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31.2)

Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32.1)

Certification of CEO and CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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
Dated:	July 31, 2007	/s/ GREG D. KERLEY
		Greg D. Kerley
		Executive Vice President
		and Chief Financial Officer

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