10-Q

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 endedSeptember 30, 2013
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 registrant as specified in its charter)
Delaware		71-0205415
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
2350 North Sam Houston Parkway East, 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 12 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.  Yesx     No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yesx  No o Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o     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 as of October 29, 2013
Common Stock, Par Value $0.01		351,752,517

SOUTHWESTERN ENERGY COMPANY
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 4.	Controls and Procedures	43
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults Upon Senior Securities	46
Item 4.	Mine Safety Disclosures	46
Item 5.	Other Information	46
Item 6.	Exhibits	46

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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, except as may be required by law.

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);

· our ability to fund our planned capital investments;

· our ability to transport our production to the most favorable markets or at all;

· the timing and extent of our success in discovering, developing, producing and estimating reserves;

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· 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;

· the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over the counter derivatives;

· the costs and availability of oilfield personnel, services and drilling supplies, raw materials, and equipment, including pressure pumping equipment and crews;

· our ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale play and Marcellus Shale play;

· our future property acquisition or divestiture activities;

· the impact of the adverse outcome of any material litigation against us;

· the effects of weather;

· increased competition and regulation;

· the financial impact of accounting regulations and critical accounting policies;

· the comparative cost of alternative fuels;

· conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed;

· credit risk relating to the risk of loss as a result of non-performance by our counterparties; 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 forward-looking statements contained in this Form 10-Q 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, 2012 (the “2012 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 this Form 10-Q 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.

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands, except share/per share amounts)
Operating Revenues:
Gas sales	$	617,427	$	497,219	$	1,736,101	$	1,394,745
Gas marketing		201,112		148,764		581,932		423,503
Oil sales		4,397		1,889		12,431		6,097
Gas gathering		45,430		43,855		133,592		128,293
		868,366		691,727		2,464,056		1,952,638
Operating Costs and Expenses:
Gas purchases – midstream services		195,271		149,651		575,337		423,941
Operating expenses		90,269		61,906		236,648		179,478
General and administrative expenses		50,969		36,121		135,754		129,879
Depreciation, depletion and amortization		204,934		203,935		571,268		605,392
Impairment of natural gas and oil properties		–		289,821		–		1,090,473
Taxes, other than income taxes		17,694		16,252		58,543		51,154
		559,137		757,686		1,577,550		2,480,317
Operating Income (Loss)		309,229		(65,959)		886,506		(527,679)
Interest Expense:
Interest on debt		25,435		25,463		74,581		69,154
Other interest charges		1,049		1,058		3,203		3,096
Interest capitalized		(15,466)		(15,915)		(48,467)		(45,945)
		11,018		10,606		29,317		26,305
Other Gain (Loss), Net		(319)		238		(498)		2,615
Gain (Loss) on Derivatives		12,124		(5,879)		75,779		(10,593)
Income (Loss) Before Income Taxes		310,016		(82,206)		932,470		(561,962)
Provision for Income Taxes:
Current		(16,068)		101		402		369
Deferred		140,217		(28,254)		373,055		(210,850)
		124,149		(28,153)		373,457		(210,481)
Net Income (Loss)	$	185,867	$	(54,053)	$	559,013	$	(351,481)
Earnings (Loss) Per Share:
Basic	$	0.53	$	(0.16)	$	1.60	$	(1.01)
Diluted	$	0.53	$	(0.16)	$	1.59	$	(1.01)
Weighted Average Common Shares Outstanding:
Basic		350,517,337		348,649,630		350,334,634		348,272,192
Diluted		351,222,830		348,649,630		351,014,974		348,272,192

See the accompanying notes which are an integral part of these

unaudited condensed consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
	For the three months ended					For the nine months ended
	September 30,					September 30,
	2013		2012			2013		2012
	(in thousands)
Net income (loss)	$	185,867	$	(54,053)	$	559,013	$	(351,481)
Change in derivatives:
Settlements (1)		(55,968)		(94,996)		(130,942)		(310,882)
Ineffectiveness (2)		872		322		1,310		(1,215)
Change in fair value of derivative instruments (3)		7,509		(36,468)		29,600		93,985
Total change in derivatives		(47,587)		(131,142)		(100,032)		(218,112)
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost included in net periodic pension cost (4)		266		254		800		762
Change in currency translation adjustment		633		997		(1,814)		962
Comprehensive income (loss)	$	139,179	$	(183,944)	$	457,967	$	(567,869)

(1) Net of ($37.3),($62.2),  ($87.3) and ($202.6)million in taxes for the three months ended September 30, 2013 and 2012, and nine months ended September 30, 2013 and 2012, respectively. 

(2) Net of $0.6,  $0.2,  $0.9and ($0.8) million in taxes for the three months ended September 30, 2013 and 2012, and nine months ended September 30, 2013 and 2012, respectively. 

(3) Net of $5.0,  ($22.1),  $19.7, and $62.7 million in taxes for the three months ended September 30, 2013 and 2012, and nine months ended September 30, 2013 and 2012, respectively.

(4) Net of $0.2,  $0.2,  $0.5, and $0.5 million in taxes for the three months ended September 30, 2013 and 2012, and nine months ended September 30, 2013 and 2012, respectively. 

See the accompanying notes which are an integral part of these

unaudited condensed consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2013		2012
ASSETS	(in thousands)
Current assets:
Cash and cash equivalents	$	18,950	$	53,583
Restricted cash		–		8,542
Accounts receivable		444,723		377,638
Inventories		43,225		28,141
Hedging asset		197,647		282,693
Other current assets		35,430		58,315
Total current assets		739,975		808,912
Natural gas and oil properties, using the full cost method, including $1,101.5 million in 2013 and $1,023.9 million in 2012 excluded from amortization		12,863,859		11,283,114
Gathering systems		1,282,652		1,148,261
Other		677,042		597,064
Less: Accumulated depreciation, depletion and amortization		(7,786,820)		(7,191,463)
Total property and equipment, net		7,036,733		5,836,976
Other long-term assets		117,680		91,639
TOTAL ASSETS	$	7,894,388	$	6,737,527
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	601,414	$	459,569
Taxes payable		48,263		62,980
Interest payable		14,049		34,431
Advances from partners		3,438		68,919
Current deferred income taxes		75,954		106,123
Other current liabilities		66,693		35,749
Total current liabilities		809,811		767,771
Long-term debt		1,911,165		1,668,273
Deferred income taxes		1,388,833		1,049,138
Pension and other postretirement liabilities		34,963		33,174
Other long-term liabilities		229,627		183,299
Total long-term liabilities		3,564,588		2,933,884
Commitments and contingencies (Note 11)
Equity:
Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 351,768,352 shares in 2013 and 351,100,391 in 2012		3,517		3,511
Additional paid-in capital		960,058		934,939
Retained earnings		2,508,163		1,949,150
Accumulated other comprehensive income		48,758		149,804
Common stock in treasury, 14,625 shares in 2013 and 64,715 in 2012		(507)		(1,532)
Total equity		3,519,989		3,035,872
TOTAL LIABILITIES AND EQUITY	$	7,894,388	$	6,737,527
See the accompanying notes which are an integral part of these
unaudited condensed consolidated financial statements.

5

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	For the nine months ended
	September 30,
	2013		2012
	(in thousands)
Cash Flows From Operating Activities
Net income (loss)	$	559,013	$	(351,481)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		574,221		608,167
Impairment of natural gas and oil properties		–		1,090,473
Deferred income taxes		373,055		(210,850)
Mark to market gain on derivatives		(72,664)		(892)
Stock-based compensation		8,883		8,226
Other		3,038		(1,686)
Change in assets and liabilities:
Accounts receivable		(67,070)		44,148
Inventories		(13,449)		16,608
Accounts payable		45,189		(11,050)
Taxes payable		(14,717)		(3,789)
Interest payable		(7,682)		(2,306)
Advances from partners		(65,481)		26,155
Other assets and liabilities		55,182		(19,246)
Net cash provided by operating activities		1,377,518		1,192,477
Cash Flows From Investing Activities
Capital investments		(1,727,543)		(1,623,751)
Proceeds from sale of property and equipment		3,081		201,161
Transfers to restricted cash		–		(167,774)
Transfers from restricted cash		8,542		40,700
Other		4,700		5,239
Net cash used in investing activities		(1,711,220)		(1,544,425)
Cash Flows From Financing Activities
Payments on current portion of long-term debt		(600)		(600)
Payments on revolving long-term debt		(2,134,550)		(1,774,000)
Borrowings under revolving long-term debt		2,377,950		1,129,000
Change in bank drafts outstanding		49,106		1,627
Proceeds from issuance of long-term debt		–		998,780
Debt issuance costs		–		(8,338)
Proceeds from exercise of common stock options		6,751		8,422
Net cash provided by financing activities		298,657		354,891
Effect of exchange rate changes on cash		412		(10)
Increase (decrease) in cash and cash equivalents		(34,633)		2,933
Cash and cash equivalents at beginning of year		53,583		15,627
Cash and cash equivalents at end of period	$	18,950	$	18,560

See the accompanying notes which are an integral part of

these unaudited condensed consolidated financial statements.

6

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

Accumulated

Common Stock

Additional

Other

Common

Shares

Paid-In

Retained

Comprehensive

Stock in

Issued

Amount

Capital

Earnings

Income (Loss)

Treasury

Total

(in thousands)

Balance at December 31, 2012

351,100

$

3,511

$

934,939

$

1,949,150

$

149,804

$

(1,532)

$

3,035,872

Comprehensive income (loss):

Net income

–

–

–

559,013

–

–

559,013

Other comprehensive loss

–

–

–

–

(101,046)

–

(101,046)

Total comprehensive income

–

–

–

–

–

–

457,967

Stock-based compensation

–

–

17,426

–

–

–

17,426

Exercise of stock options

706

7

6,768

–

–

–

6,775

Issuance of restricted stock

21

–

–

–

–

–

–

Cancellation of restricted stock

(59)

(1)

1

–

–

–

–

Treasury stock – non-qualified plan

–

–

924

–

–

1,025

1,949

Balance at September 30, 2013

351,768

$

3,517

$

960,058

$

2,508,163

$

48,758

$

(507)

$

3,519,989

See the accompanying notes which are an integral part of these

unaudited condensed consolidated financial statements.

7

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Southwestern Energy Company (including its subsidiaries, collectively, “we”, “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production. The Company engages in natural gas and oil exploration and production, natural gas gathering and natural gas marketing through its subsidiaries. Southwestern’s exploration, development and production (“E&P”) activities are focused within the United States.   The Company is actively engaged in exploration and production activities in Arkansas, where we are targeting the unconventional gas reservoir known as the Fayetteville Shale, in Pennsylvania, where we are targeting the unconventional gas reservoir known as the Marcellus Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma Basin.  The Company also actively seeks to find and develop new oil and natural gas plays with significant exploration and exploitation potential.  Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania and Texas.  

The accompanying unaudited condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report on Form 10-Q. The Company believes the disclosures made are adequate to make the information presented not misleading.

The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Annual Report on Form 10-K”).

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 in the Notes to the Consolidated Financial Statements included in the Company’s 2012 Annual Report on Form 10-K.

Certain reclassifications have been made to the prior year financial statements to conform to the 2013 presentation. The effects of the reclassifications were not material to the Company’s unaudited condensed consolidated financial statements.

(2) ACQUISITIONS AND DIVESTITURES

In April 2013, the Company entered into a definitive purchase agreement to acquire natural gas properties located in Pennsylvania prospective for the Marcellus Shale for approximately $93.0 million, subject to closing conditions.  The Company utilized its revolving credit facility to finance the acquisition.  The Company closed on the acquisition during the second quarter of 2013 and accounted for it as an asset acquisition.

In May 2012, the Company sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $166.0 million.  The assets included in the sale represented all of the Company’s interests and related assets in the Overton Field in Smith County. The net production from the sold assets was approximately 24.0 MMcfe per day as of the closing date and the associated net proved reserves were approximately 143.0 Bcfe at December 31, 2011. 

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(3) PREPAID EXPENSES

The components of prepaid expenses included in other current assets as of September 30, 2013 and December 31, 2012 consisted of the following:

	September 30,		December 31,
	2013		2012
		(in thousands)
Prepaid drilling costs	$	15,622	$	30,101
Prepaid insurance		9,536		9,507
Total	$	25,158	$	39,608

(4) INVENTORY

Inventory recorded in current assets includes $3.7 million at September  30, 2013 and $5.6 million at December 31, 2012 for natural gas in underground storage owned by the Company’s E&P segment, and $39.5 million at September  30, 2013 and $22.5 million at December 31, 2012 for tubular and other equipment used in the E&P segment.

Other long-term assets include $15.8 million at September  30, 2013 and $13.8 million at December 31, 2012, respectively, for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems for the Fayetteville Shale play.

(5) NATURAL 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 on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, 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, net of taxes, discounted at 10 percent 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 average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.60 per MMBtu and $91.56 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at September 30, 2013. Cash flow hedges of natural gas production in place increased the ceiling value by $79.2 million, net of tax, at September 30, 2013.  Decreases in average quoted prices from September 30, 2013 levels as well as changes in production rates, levels of reserves, capitalized costs, the evaluation of costs excluded from amortization, future development costs, service costs and taxes could result in future ceiling test impairments.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.83 per MMBtu and $91.48 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $185.7 million (net of tax) at September 30, 2012 and resulted in a non-cash ceiling test impairment.  Cash flow hedges of natural gas production in place increased the ceiling by $330.6 million at September 30, 2012. In the second quarter of 2012, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $496.4 million (net of tax) at June 30, 2012 and resulted in a non-cash ceiling test impairment.

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All of the Company’s costs directly associated with the acquisition and evaluation of properties in Canada relating to its exploration program at September 30, 2013 were unproved and did not exceed the ceiling amount.  If the exploration program in Canada is unsuccessful on all or a portion of these properties, a ceiling test impairment may result in the future.

(6) EARNINGS PER SHARE

The following table presents the computation of earnings per share for the three- and nine-month periods ended September  30, 2013 and 2012:

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
Net income (loss) (in thousands)	$	185,867	$	(54,053)	$	559,013	$	(351,481)
Number of common shares:
Weighted average outstanding		350,517,337		348,649,630		350,334,634		348,272,192
Issued upon assumed exercise of outstanding stock options		373,152		–		442,678		–
Effect of issuance of nonvested restricted common stock		332,341		–		237,662		–
Weighted average and potential dilutive outstanding(1)		351,222,830		348,649,630		351,014,974		348,272,192
Earnings (loss) per share:
Basic	$	0.53	$	(0.16)	$	1.60	$	(1.01)
Diluted	$	0.53	$	(0.16)	$	1.59	$	(1.01)

(1) Options for 1,550,838shares and 15,703 shares of restricted stock were excluded from the calculation for the three months ended September 30, 2013 because they would have had an antidilutive effect.  Due to the net loss for the three months ended September 30, 2012, options for 1,664,232 shares and 560,848 shares of restricted stock were antidilutive and excluded from the calculation.  Options for1,848,566 shares and 169,261 shares of restricted stock were excluded from the calculation for the nine months ended September 30, 2013 because they would have had an antidilutive effect.  Due to the net loss for the nine months ended September 30, 2012, options for 1,685,398 shares and 580,227 shares of restricted stock were antidilutive and excluded from the calculation.

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(7) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas and crude oil which impacts the predictability of its cash flows related to the sale of natural gas and oil, and is exposed to volatility in interest rates. These risks are managed by the Company’s use of certain derivative financial instruments.  At September  30, 2013 and December 31, 2012, the Company’s derivative financial instruments consisted of fixed price swaps, basis swaps, fixed price call options, and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:

Fixed price swaps	The Company receives a fixed price for the contract and pays a floating market price to the counterparty.
Floating price swaps	The Company receives a floating market price from the counterparty and pays a fixed price.
Costless-collars	Arrangements that contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
Basis swaps	Arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.
Fixed price call options	The Company sells fixed price call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty such excess on sold fixed price call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Interest rate swaps	Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest-rate changes.

GAAP requires that all derivatives be recognized in the balance sheet as either an asset or liability and be measured at fair value. Under GAAP, certain criteria must be satisfied in order for derivative financial instruments to be classified and accounted for as either a cash flow or a fair value hedge. Accounting for qualifying hedges requires a derivative’s gains and losses to be recorded either in earnings as a component of the sale of natural gas and oil or as a component of other comprehensive income. Gains and losses on derivatives that are not elected for hedge accounting treatment or that do not meet hedge accounting requirements are recorded in earnings as a component of gain (loss) on derivatives.  Within the gain (loss) on derivatives component of the statement of operations are mark to market gain (loss) on derivatives and mark to market gain (loss) on derivatives, settled.  The Company calculates mark to market gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period reported.

The Company utilizes counterparties for its derivative instruments that it believes are credit-worthy at the time the transactions are entered into and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.

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The balance sheet classification of the assets related to derivative financial instruments are summarized below at September  30, 2013 and December 31, 2012:

	Derivative Assets
	September 30, 2013			December 31, 2012
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Derivatives designated as hedging instruments:
Fixed price swaps	Hedging asset	$	115,039	Hedging asset	$	279,443
Fixed price swaps	Other long-term assets		5,951	Other long-term assets		8,550
Total derivatives designated as hedging instruments		$	120,990		$	287,993
Derivatives not designated as hedging instruments:
Basis swaps	Hedging asset	$	5,104	Hedging asset	$	3,250
Fixed price swaps	Hedging asset		77,504	Hedging asset		–
Basis swaps	Other long-term assets		679	Other long-term assets		901
Fixed price swaps	Other long-term assets		19,103	Other long-term assets		–
Interest rate swaps	Other long-term assets		5,797	Other long-term assets		–
Total derivatives not designated as hedging instruments		$	108,187		$	4,151
Total derivative assets		$	229,177		$	292,144
	Derivative Liabilities
	September 30, 2013			December 31, 2012
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Derivatives not designated as hedging instruments:
Basis swaps	Other current liabilities	$	164	Other current liabilities	$	138
Fixed price call options	Other long-term liabilities		30,980	Other long-term liabilities		4,128
Interest rate swaps	Other current liabilities		912	Other current liabilities		–
Interest rate swaps	Other long-term liabilities		3,582	Other long-term liabilities		–
Total derivatives not designated as hedging instruments		$	35,638		$	4,266
Total derivative liabilities		$	35,638		$	4,266

As of September  30, 2013, the Company had derivatives designated as cash flow hedges and derivatives not designated as hedges on the following volumes of natural gas production (in Bcf):

Year	Fixed price swaps	Fixed price swaps not designated for hedge accounting	Total
2013	84.4	-	84.4
2014	51.1	181.6	232.7

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Cash Flow Hedges

The reporting of gains and losses on cash flow derivative hedging instruments depends on whether the gains or losses are effective at offsetting changes in the cash flows of the hedged item. The effective portion of the gains and losses on the derivative hedging instruments are recorded in other comprehensive income until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of the gains and losses from the derivative hedging instrument is recognized in earnings immediately.

As of September  30, 2013, the Company recorded a net gain in accumulated other comprehensive income related to its hedging activities of $72.1 million. This amount is net of a deferred income tax liability recorded as of September  30, 2013 of $48.1 million. The amount recorded in accumulated other comprehensive income will be relieved over time and recognized in the statement of operations as the physical transactions being hedged occur. Assuming the market prices of natural gas futures as of September  30, 2013 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of $68.6 million from accumulated other comprehensive income to earnings during the next 12 months. Gains or losses from derivative instruments designated as cash flow hedges are reflected as adjustments to gas sales in the unaudited condensed consolidated statements of operations. Volatility in earnings and other comprehensive income may occur in the future as a result of the Company’s derivative activities.

The following tables summarize the before tax effect of all cash flow hedges on the unaudited condensed consolidated financial statements for the three- and nine-month periods ended September  30, 2013 and 2012:

		Gain (Loss) Recognized in Other Comprehensive Income
		(Effective Portion)
		For the three months ended				For the nine months ended
		September 30,				September 30,
Derivative Instrument		2013		2012		2013		2012
		(in thousands)
Fixed price swaps		$	12,515	$	(55,039)	$	51,234	$	116,089
Costless-collars		$	–	$	(3,497)	$	–	$	40,644
	Classification of Gain	Gain Reclassified from Accumulated Other
	Reclassified from	Comprehensive Income into Earnings
	Accumulated Other	(Effective Portion)
	Comprehensive Income	For the three months ended				For the nine months ended
	into Earnings	September 30,				September 30,
Derivative Instrument	(Effective Portion)	2013		2012		2013		2012
		(in thousands)
Fixed price swaps	Gas sales	$	93,280	$	102,789	$	218,236	$	337,994
Costless-collars	Gas sales	$	–	$	54,489	$	–	$	175,531
		Gain (Loss) Recognized in Earnings
		(Ineffective Portion)
	Classification of Gain (Loss)	For the three months ended				For the nine months ended
	Recognized in Earnings	September 30,				September 30,
Derivative Instrument	(Ineffective Portion)	2013		2012		2013		2012
		(in thousands)
Fixed price swaps	Gas sales	$	(1,452)	$	(165)	$	(2,183)	$	1,831
Costless-collars	Gas sales	$	–	$	(373)	$	–	$	167

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Fair Value Hedges and Other Derivative Contracts

For fair value hedges, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately.

Although the Company’s basis swaps meet the objective of managing commodity price exposure, these trades are typically not entered into concurrent with the Company’s derivative instruments that qualify as cash flow hedges and therefore do not generally qualify for hedge accounting. Basis swap derivative instruments that do not qualify as cash flow hedges are recorded on the balance sheet at their fair values under hedging assets, other long-term assets and other current liabilities, as applicable, and all gains and losses related to these contracts are recognized immediately in the unaudited condensed consolidated statements of operations as a component of gain (loss) on derivatives.  

As of September  30, 2013, the Company had basis swaps on natural gas production that did not qualify for hedge accounting treatment of 6.5 Bcf,16.7 Bcf, and 0.9 Bcf in 2013, 2014, and 2015, respectively.

As of September  30, 2013, the Company had fixed price call options on199.8 Bcf of 2015 natural gas production that did not qualify for hedge accounting treatment and fixed price swaps of 181.6 Bcf of 2014 natural gas production not designated for hedge accounting.

The Company is a party to an interest rate swap with counterparty banks. The interest rate swap was entered into in order to mitigate the Company’s exposure to volatility in interest rates related to its building lease. The interest rate swap has a notional amount of $170.0 million and expires on June 20, 2020. The Company did not designate the interest rate swap for hedge accounting.  Changes in the fair value of the interest rate swap are included in gain (loss) on derivatives in theunaudited condensed consolidated statements of operations.  The Company had no interest rate swaps in 2012. 

The following table summarizes the before tax effect of fair value hedges, fixed price call options that did not qualify for hedge accounting,fixed price swaps not designated for hedge accounting, basis swaps, and interest rate swaps not designated for hedge accounting on the unaudited condensed consolidated statements of operations for the three- and nine-month periods ended September  30, 2013 and 2012:

		Mark to Market Gain (Loss)
		on Derivatives
		Recognized in Earnings
	Income Statement	For the three months ended				For the nine months ended
	Classification of Mark to Market Gain (Loss)	September 30,				September 30,
Derivative Instrument	on Derivatives	2013		2012		2013		2012
		(in thousands)
Basis swaps	Gain (Loss) on Derivatives	$	(5,279)	$	(1,275)	$	1,606	$	(270)
Fixed price call options	Gain (Loss) on Derivatives	$	7,876	$	–	$	(26,852)	$	–
Fixed price swaps	Gain (Loss) on Derivatives	$	8,819	$	–	$	96,606	$	–
Interest rate swaps	Gain (Loss) on Derivatives	$	(1,312)	$	–	$	1,304	$	–
Fair value swaps	Gain (Loss) on Derivatives	$	–	$	136	$	–	$	1,162
		Mark to Market Gain (Loss)
		on Derivatives, Settled (1)
		Recognized in Earnings
	Income Statement	For the three months ended				For the nine months ended
	Classification of Mark to Market Gain (Loss)	September 30,				September 30,
Derivative Instrument	on Derivatives, Settled (1)	2013		2012		2013		2012
		(in thousands)
Basis swaps	Gain (Loss) on Derivatives	$	2,020	$	624	$	3,115	$	1,773
Fair value swaps	Gain (Loss) on Derivatives	$	–	$	(5,364)	$	–	$	(13,258)

(1)    The Company calculates mark to market gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period reported.

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(8) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME

The following tables detail the components of accumulated other comprehensive income and the related tax effects for the nine-months ended September 30, 2013:

	For the nine months ended
	September 30, 2013
	Gains and Losses on Cash Flow Hedges		Pension and Other Postretirement		Foreign Currency		Total
	(in thousands) (1)
Beginning balance, December 31, 2012	$	172,166	$	(22,311)	$	(51)	$	149,804
Other comprehensive income (loss) before reclassifications		29,600		–		(1,814)		27,786
Amounts reclassified from accumulated other comprehensive income (loss) (2)		(129,632)		800		–		(128,832)
Net current-period other comprehensive income (loss)		(100,032)		800		(1,814)		(101,046)
Ending balance, September 30, 2013	$	72,134	$	(21,511)	$	(1,865)	$	48,758

(1) All amounts are net-of-tax.

(2) See separate table below for details about these reclassifications.

The following table details the amounts reclassified from accumulated other comprehensive income into earnings for the nine-months ended September 30, 2013:

Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statement of Operations		Amount Reclassified from Accumulated Other Comprehensive Income
			For the nine months ended September 30, 2013
			(in thousands)
Gains (losses) on cash flow hedges
Settlements	Gas sales	$	218,236
Ineffectiveness	Gas sales		(2,183)
	Income before income taxes		216,053
	Provision for income taxes		86,421
	Net income	$	129,632
Pension and other postretirement
Amortization of prior service cost included in net periodic pension cost (1)	General and administrative expenses	$	(1,334)
	Loss before income taxes		(1,334)
	Benefit for income taxes		(534)
	Net loss	$	(800)
Total reclassifications for the period	Net income	$	128,832

(1) Included in the computation of net periodic pension cost (see footnote 13 for additional details.)  

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(9) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Company’s financial instruments as of September 30, 2013 and December 31, 2012 were as follows:

	September 30,				December 31,
	2013				2012
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in thousands)
Cash and cash equivalents	$	18,950	$	18,950	$	53,583	$	53,583
Restricted cash	$	–	$	–	$	8,542	$	8,542
Unsecured revolving credit facility	$	243,400	$	243,400	$	–	$	–
Senior notes	$	1,668,965	$	1,807,234	$	1,669,473	$	1,917,005
Derivative instruments	$	193,539	$	193,539	$	287,878	$	287,878

The carrying values of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, other current assets and current liabilities on the unaudited condensed consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

Debt: The fair values of the Company’s senior notes were based on the market for the Company’s publicly-traded debt as determined based on yield of the Company’s 7.5% Senior Notes due 2018, which was 2.8% at September  30, 2013 and 2.6% at December 31, 2012, and its 4.10% Senior Notes due 2022, which was 4.0% at September  30, 2013. The carrying value of the borrowings under the Company’s unsecured revolving credit facility at September  30, 2013, approximate fair value because the interest rate is variable and reflective of market rates.  The Company considers the fair value of its debt to be a Level 2 measurement on the fair value hierarchy. 

Derivative Instruments: The fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

Level 1 valuations - Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

Level 2 valuations - Consist of quoted market information for the calculation of fair market value.

Level 3 valuations - Consist of internal estimates and have the lowest priority.

Pursuant to GAAP, the Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s Level 2 fair value measurements include fixed-price swaps and are estimated using internal discounted cash flow calculations using the NYMEX futures index.The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of September 30, 2013 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate ("LIBOR") yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy. The Company’s Level 3 fair value measurements include fixed price call options and basis swaps. The Company’s fixed price call options are valued using the Black-Scholes model, an industry standard option valuation model, and takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness.  The Company’s basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves. 

The accounting group, reporting to the Vice President and Controller, is responsible for determining the Company’s Level 3 fair value measurements.  Inputs to the Black-Scholes model, including the volatility input, which is the

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significant unobservable input for Level 3 fair value measurements, are obtained from a third-party pricing source, with independent verification of most significant inputs on a monthly basis. An increase (decrease) in volatility would resultin an increase (decrease) in fair value measurement, respectively.

Assets and liabilities measured at fair value on a recurring basis are summarized below (in thousands):

	September 30, 2013
	Fair Value Measurements Using:
	Quoted Prices		Significant
	in Active		Other		Significant
	Markets		Observable Inputs		Unobservable Inputs		Assets (Liabilities)
	(Level 1)		(Level 2)		(Level 3)		at Fair Value
Derivative assets	$	–	$	223,394	$	5,783	$	229,177
Derivative liabilities		–		(4,494)		(31,144)		(35,638)
Total	$	–	$	218,900	$	(25,361)	$	193,539
	December 31, 2012
	Fair Value Measurements Using:
	Quoted Prices		Significant
	in Active		Other		Significant
	Markets		Observable Inputs		Unobservable Inputs		Assets (Liabilities)
	(Level 1)		(Level 2)		(Level 3)		at Fair Value
Derivative assets	$	–	$	287,993	$	4,151	$	292,144
Derivative liabilities		–		–		(4,266)		(4,266)
Total	$	–	$	287,993	$	(115)	$	287,878

The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three-and nine-month periods ended September  30, 2013 and September  30, 2012. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect the assumptions a reasonable marketplace participant would have used at September  30, 2013 and September  30, 2012.

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Balance at beginning of period	$	(27,958)	$	106,222	$	(115)	$	182,119
Total gains (losses):
Included in earnings		4,617		53,465		(22,131)		177,201
Included in other comprehensive income		–		(57,614)		–		(135,055)
Purchases, issuances, and settlements:
Purchases		–		–		–		–
Issuances		–		–		–		–
Settlements		(2,020)		(55,112)		(3,115)		(177,304)
Transfers into/out of Level 3		–		–		–		–
Balance at end of period	$	(25,361)	$	46,961	$	(25,361)	$	46,961
Change in gains (losses) included in earnings relating to derivatives still held as of September 30	$	2,597	$	(1,647)	$	(25,246)	$	(103)

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(10) DEBT

The components of debt as of September  30, 2013 and December 31, 2012 consisted of the following:

	September 30,		December 31,
	2013		2012
	(in thousands)
Short-term debt:
7.15% Senior Notes due 2018	$	1,200	$	1,200
Total short-term debt		1,200		1,200
Long-term debt:
Variable rate (2.14% at September 30, 2013) unsecured revolving credit facility		243,400		–
7.5% Senior Notes due 2018		600,000		600,000
7.35% Senior Notes due 2017		15,000		15,000
7.125% Senior Notes due 2017		25,000		25,000
7.15% Senior Notes due 2018		28,800		29,400
4.10% Senior Notes due 2022		1,000,000		1,000,000
Unamortized discount		(1,035)		(1,127)
Total long-term debt		1,911,165		1,668,273
Total debt	$	1,912,365	$	1,669,473

Issuance of Senior Notes and Subsidiary Guarantees 

The indentures governing the Company’s senior notes contain covenants that, among other things, restrict the ability of the Company and/or its subsidiaries’ ability to incur liens, to engage in sale and leaseback transactions and to merge, consolidate, or sell assets.  All of the Company’s senior notes are currently guaranteed by its subsidiaries, SEECO, Inc. (“SEECO”), Southwestern Energy Production Company (“SEPCO”) and Southwestern Energy Services Company (“SES”).  If no default or event of default has occurred and is continuing, these guarantees will be released (i) automatically upon any sale, exchange, or transfer of all of the Company’s equity interests in the guarantor; (ii) automatically upon the liquidation and dissolution of a guarantor; (iii) following delivery of notice to the trustee of the release of the guarantor of its obligations under the Company’s credit facility; and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the notes.

In December 2012, the Company completed its offer to exchange up to $1.0 billion aggregate principal amount of its 4.10% Senior Notes due 2022 (the “Exchange Notes”, which were registered under the Securities Act of 1933, as amended (the “Act”), for any and all of its outstanding 4.10% Senior Notes due 2022, which were issued in a private placement in March 2012 (the “PrivateNotes”). The Exchange Notes have substantially identical terms to the Private Notes, except that the offering of the Exchange Notes was registered under the Act, and the Exchange Notes are not subject to any transfer restrictions. The Company exchanged $999,500,000 of Private Notes for Exchange Notes, and has no further obligations under the relatedregistration rights agreement.

Please refer to Note 17, “Condensed Consolidating Financial Information” in this Form 10-Q for additional information.

Credit Facility 

In February 2011, the Company amended and restated its unsecured revolving credit facility, increasing the borrowing capacity to $1.5 billion and extending the maturity date to February 2016 (“Credit Facility”).  The amount available under the Credit Facility may be increased to $2.0 billion at any time upon the Company’s agreement with its existing or additional lenders. The interest rate on the Credit Facility is calculated based upon our debt rating and is currently 200 basis points over the current London Interbank Offered Rate (LIBOR) and was 200 basis points over LIBOR at September  30, 2013. The Credit Facility is guaranteed by the Company’s subsidiary, SEECO and requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied.  The facility contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in

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excess of 60% of its total capital and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of 3.5 or above. The terms of the Credit Facility also include covenants that restrict the ability of the Company and its material subsidiaries to merge, consolidate or sell all or substantially all of their assets, restrict the ability of the Company and its subsidiaries to incur liens and restrict the ability of the Company’s subsidiaries to incur indebtedness.  As of September  30, 2013, the Company was in compliance with the covenants of its debt agreements.  While the Company believes all of the lenders under the Credit Facility have the ability to provide funds, it cannot predict whether each will be able to meet its obligation under the facility.

(11) COMMITMENTS AND CONTINGENCIES

Commitments

In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses require the Company to make certain capital investments in New Brunswick of approximately $47.0 millionin the aggregate over a three year period. In order to obtain the licenses, the Company provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate principal amount of$44.5 million Canadian dollars. The promissory notes secure the Company's capital expenditure obligations under the licenses and are returnable to the Company to the extent the Company performs such obligations. If the Company fails to fully perform, the Minister of Finance may retain a portion of the applicable promissory notes in an amount equal to any deficiency. The Company commenced its Canada exploration program in 2010 and, as of September 30, 2013 has invested $35.4 million in New Brunswick towards the Company’s commitment.  In December 2012, the Company received twoone-year extensions to our exploration license agreements which expire on March 16, 2014 and March 16, 2015, respectively.  No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of September 30, 2013 and its future investment plans.  

In response to the Company’s well performance, SES and SEPCO entered into new and amended natural gas transportation and gathering arrangements with third party pipelines, during the second quarter of 2013, in support of the Company’s production in the Marcellus Shale Play.  As of September 30, 2013,  the Company’s obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $3.4 billion and the Company has guarantee obligations of up to $100.0million of that amount.

Environmental Risk

The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued 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 effect on the financial position or reported results of operations of the Company.

Litigation

Tovah Energy

In February 2009, SEPCO was added as a defendant in a Third Amended Petition in the matter of Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al.  In the Sixth Amended Petition, filed in July 2010, in the 273rd District Court in Shelby County, Texas (collectively, the “Sixth Petition”), plaintiff alleged that, in 2005, they provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom.  Among other things, the plaintiff’s allegations in the Sixth Petition included various statutory and common law claims, including, but not limited to claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 2005 and February 2006.  In the Sixth Petition, plaintiff sought actual damages of over $55.0 million as well as other remedies, including special damages and punitive damages of four times the amount of actual damages established at trial.

Immediately before the commencement of the trial in November 2010, plaintiff was permitted, over SEPCO’s objections, to file a Seventh Amended Petition claiming actual damages of $46.0 million and also seeking the equitable remedy of disgorgement of all profits for the misappropriation of trade secrets and the breach of fiduciary duty claims. In December 2010, the jury found in favor of the plaintiff with respect to all of the statutory and common law claims

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and awarded $11.4 million in compensatory damages. The jury did not, however, award the plaintiff any special, punitive or other damages. In addition, the jury separately determined that SEPCO’s profits for purposes of disgorgement were $381.5 million. This profit determination does not constitute a judgment or an award. The plaintiff’s entitlement to disgorgement of profits as an equitable remedy will be determined by the judge and it is within the judge’s discretion to award none, some or all the amount of profit to the plaintiff.  In December 2010, the plaintiff filed a motion to enter the judgment based on the jury’s verdict.  In February 2011, SEPCO filed a motion for a judgment notwithstanding the verdict and a motion to disregard certain findings.  In March 2011, the plaintiff filed an amended motion for judgment and intervenor filed its motion for judgment seeking not only the monetary damages and the profits determined by the jury but also seeking, as a new remedy, a constructive trust for profits from 143 wells as well as future drilling and sales of properties in the prospect areas.  At the suggestion of the judge, all parties voluntarily agreed to participate in non-binding mediation efforts.  The mediation occurred in April 2011 and was unsuccessful. In June 2011, SEPCO received by mail a letter dated June 2011 from the judge, in which he made certain rulings with respect to the post-verdict motions and responses filed by the parties. In his rulings, the judge denied SEPCO’s motion for judgment, judgment notwithstanding the verdict and to disregard certain findings. Plaintiff’s and intervenor’s claim for a constructive trust was denied but the judge ruled that plaintiff and intervenor shall recover from SEPCO $11.4 million and a reasonable attorney’s fee of 40% of the total damages awarded and are entitled to recover on their claim for disgorgement.  The judge instructed that SEPCO calculate the profit on the designated wells for each respective period.  SEPCO performed the calculation and provided it to the judge in June 2011.  In July 2011, plaintiff and intervenor filed a letter with the court raising objections to the accounting provided by SEPCO, to which SEPCO filed a response in July 2011.  In July 2011, the judge sent a letter to the parties in which he ruled that after reviewing the parties’ respective position letters, he was awarding $23.9 million in disgorgement damages in favor of the plaintiff and intervenor.  In the July 2011 letter, the judge instructed the plaintiff and intervenor to prepare a judgment for his approval prior to July 2011 consistent with his findings in his June 2011 letter and the disgorgement award.  In August 2011, a judgment was entered pursuant to which plaintiff and intervenor are entitled to recover approximately $11.4 million in actual damages and approximately $23.9 million in disgorgement as well as prejudgment interest and attorneys' fees which currently are estimated to be up to $8.9 million and all costs of court of the plaintiff and intervenor.  In September 2011, SEPCO filed a motion for a new trial and in November 2011 filed a notice of appeal.  In November 2011, the court approved SEPCO’s supersedeas bond in the amount of $14.1 million, which stays execution on the judgment pending appeal.  The bond covers the $11.4 million judgment for actual damages, plus $1.3 million in pre-judgment interest, $1.3 million in post-judgment interest (estimating two years for the duration of appeal), and court costs. 

In June 2012, SEPCO filed its appellate brief and, in June 2012, plaintiff and intervenor filed a cross-appellate brief seeking limited remand to reassess the disgorgement determination. The parties filed their responses to the appellate and cross appellate briefs in November 2012.  Oral argument was held before the Tyler Court of Appeals on March 8, 2013.  On July 10, 2013, the Tyler Court of Appeals ordered that (1) the judgment awarding plaintiff and intervenor $23.9 million as disgorgement of illicit gains be reversed and judgment rendered that they take nothing, (2) the award of $11.4 million for actual damages, insofar as it is based on the jury’s findings of breach of fiduciary duty, fraud, breach of contract, and theft of trade secret is reversed and judgment rendered that plaintiff and intervenor take nothing under those theories of recovery, (3) the award of $11.4 million to plaintiff and intervenor as damages for misappropriation of trade secret is affirmed, (4) the case be remanded to the trial court for a determination and award of attorney’s fees for SEPCO as the prevailing party under the Texas Theft Liability Act, and (5) in all other respects, the judgment is affirmed.  On July 25, 2013, SEPCO filed its motion for rehearing with the Tyler Court of Appeals, seeking reversal of every part of plaintiff and intervenor’s recovery, and plaintiff and intervenor filed a court-ordered response.  Plaintiff and intervenor filed their own motion for rehearing, and to date SEPCO has not been ordered to respond. 

Based on the Company's understanding and judgment of the facts and merits of this case, including appellate defenses, and after considering the advice of counsel, the Company has determined that, although reasonably possible after exhaustion of all appeals, an adverse final outcome to this lawsuit is not probable.  As such, the Company has not accrued any amounts with respect to this lawsuit.  If the plaintiff and intervenor were to ultimately prevail in the appellate process, the Company currently estimates, based on the judgments to date, that SEPCO’s potential liability would be up to $45.5 million, including interest and attorney’s fees. The Company’s assessment may change in the future due to occurrence of certain events, such as denied appeals, and such re-assessment could lead to the determination that the potential liability is probable and could be material to the Company's results of operations, financial position or cash flows.

20

Bureau of Land Management

In March 2010, the Company’s subsidiary, SEECO, was served with a subpoena from a federal grand jury in Little Rock, Arkansas.  Based on the documents requested under the subpoena and subsequent discussions described below, the Company believes the grand jury is investigating matters involving approximately 27 horizontal wells operated by SEECO in Arkansas, including whether appropriate leases or permits were obtained therefore and whether royalties and other production attributable to federal lands have been properly accounted for and paid.  The Company believes it has fully complied with all requests related to the federal subpoena and delivered its affidavit to that effect. The Company and representatives of the Bureau of Land Management and the U.S. Attorney have had discussions since the production of the documents pursuant to the subpoena.  In January 2011, the Company voluntarily produced additional materials informally requested by the government arising from these discussions.  In September 2013, the U.S. Attorney’s Office requested additional information regarding this matter.  Although, to the Company’s knowledge, no proceeding in this matter has been initiated against SEECO, the Company cannot predict whether or when one might be initiated. The Company intends to fully comply with any further requests and to cooperate with any related investigation. No assurance can be made as to the time or resources that will need to be devoted to this inquiry or the impact of the final outcome of the discussions or any related proceeding.

Other

We are subject to various litigation, claims and proceedings that have arisen in the ordinary course of business. Management believes, individually or in aggregate, such litigation, claims and proceedings will not have a material adverse impact on our financial position, results of operations or cash flows 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, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.

(12) SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Supplemental disclosures of cash flow information:

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Cash paid for interest	$	44,745	$	45,667	$	94,963	$	75,487
Cash paid for income taxes	$	1,330	$	400	$	18,636	$	468
Noncash property changes	$	(11,745)	$	(55,729)	$	34,437	$	(34,940)

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(13) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company has defined pension and postretirement benefit plans which cover substantially all of the Company’s employees. Net periodic pension and other postretirement benefit costs include the following components for the three-and nine-month periods ended September  30, 2013 and 2012:  

	Pension Benefits
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Service cost	$	3,447	$	2,736	$	10,342	$	8,207
Interest cost		1,026		1,013		3,078		3,038
Expected return on plan assets		(1,534)		(1,356)		(4,602)		(4,069)
Amortization of prior service cost		25		71		77		214
Amortization of net loss		386		305		1,156		915
Net periodic benefit cost	$	3,350	$	2,769	$	10,051	$	8,305
	Postretirement Benefits
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Service cost	$	574	$	458	$	1,722	$	1,374
Interest cost		111		100		331		299
Amortization of transition obligation		–		16		–		48
Amortization of prior service cost		4		4		11		11
Amortization of net loss		30		23		90		69
Net periodic benefit cost	$	719	$	601	$	2,154	$	1,801

As of September  30, 2013, the Company has contributed $9.0 million to the pension plan and $0.1 million to the postretirement benefit plan, and expects to contribute an additional $3.0 million to the pension plan in 2013.

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are presented as treasury stock and totaled 14,625 shares at September  30, 2013 compared to 64,715 shares at December 31, 2012.

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(14) STOCK-BASED COMPENSATION

The Company recognized the following amounts in employee stock-based compensation costs for the three-and nine-months ended September  30, 2013 and 2012:

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Stock-based compensation cost – expensed	$	2,921	$	2,677	$	8,883	$	8,226
Stock-based compensation cost – capitalized	$	2,809	$	2,482	$	8,543	$	7,788

As of September  30, 2013, there was $38.2 million of total unrecognized compensation cost related to the Company’s unvested stock option and restricted stock grants. This cost is expected to be recognized over a weighted-average period of 2.3 years.

The following table summarizes stock option activity for the nine months ended September  30, 2013 and provides information for options outstanding as of September  30, 2013:

		Weighted
		Average
	Number	Exercise
	of Options	Price
Outstanding at December 31, 2012	3,649,520	$	29.84
Granted	26,010		38.76
Exercised	(705,991)		9.60
Forfeited or expired	(55,756)		37.47
Outstanding at September 30, 2013	2,913,783		34.68
Exercisable at September 30, 2013	1,699,151	$	34.06

The following table summarizes restricted stock activity for the nine months ended September 30, 2013 and provides information for unvested shares as of September 30, 2013:  

		Weighted
		Average
	Number	Grant Date
	of Shares	Fair Value
Unvested shares at December 31, 2012	1,117,515	$	35.64
Granted	32,346		37.53
Vested	(30,884)		36.19
Forfeited	(58,560)		35.77
Unvested shares at September 30, 2013	1,060,417	$	35.67

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(15) SEGMENT INFORMATION

The Company’s reportable business segments 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 natural gas volumes and through gathering fees associated with the transportation of natural gas to market.

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 2012 Annual Report on Form 10-K. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense and interest and other income (loss). The “Other” column includes items not related to the Company’s reportable segments including real estate and corporate items.

	Exploration
	and		Midstream
	Production		Services		Other			Total
	(in thousands)
Three months ended September 30, 2013:
Revenues from external customers	$	621,833	$	246,501	$	32		$	868,366
Intersegment revenues		644		601,104		64			601,812
Operating income (loss)		222,692		86,658		(121)			309,229
Other income (loss), net		143		70		(532)			(319)
Gain on derivatives		10,885		1,232		7			12,124
Depreciation, depletion and amortization expense		191,860		12,970		104			204,934
Interest expense(2)		8,580		2,294		144			11,018
Provision (benefit) for income taxes(2)		87,779		36,671		(301)			124,149
Assets		6,264,845		1,387,765		241,778	(3)		7,894,388
Capital investments(4)		496,331		40,052		5,726			542,109
Three months ended September 30, 2012:
Revenues from external customers	$	499,083	$	192,619	$	25		$	691,727
Intersegment revenues		(982)		409,720		825			409,563
Operating income (loss)(1)		(141,865)		75,488		418			(65,959)
Other income (loss), net		213		27		(2)			238
Loss on derivatives		(5,879)		–		–			(5,879)
Depreciation, depletion and amortization expense		192,994		10,620		321			203,935
Impairment of natural gas and oil properties		289,821		–		–			289,821
Interest expense(2)		6,707		3,659		240			10,606
Provision (benefit) for income taxes(2)		(55,220)		27,006		61			(28,153)
Assets		5,854,055		1,158,638		343,869	(3)		7,356,562
Capital investments(4)		385,585		31,693		7,608			424,886

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	Exploration
	and		Midstream
	Production		Services		Other			Total
	(in thousands)
Nine months ended September 30, 2013:
Revenues from external customers	$	1,748,821	$	715,155	$	80		$	2,464,056
Intersegment revenues		3,817		1,740,132		177			1,744,126
Operating income (loss)		650,996		235,854		(344)			886,506
Other income (loss), net		61		(27)		(532)			(498)
Gain on derivatives		74,540		1,232		7			75,779
Depreciation, depletion and amortization expense		533,577		37,377		314			571,268
Interest expense(2)		21,101		7,682		534			29,317
Provision (benefit) for income taxes(2)		282,231		91,785		(559)			373,457
Assets		6,264,845		1,387,765		241,778	(3)		7,894,388
Capital investments(4)		1,602,885		135,425		16,748			1,755,058
Nine months ended September 30, 2012:
Revenues from external customers	$	1,400,749	$	551,796	$	93		$	1,952,638
Intersegment revenues		(1,716)		1,085,392		2,459			1,086,135
Operating income (loss)(1)		(745,533)		216,598		1,256			(527,679)
Other income (loss), net		(34)		4		2,645			2,615
Loss on derivatives		(10,593)		–		–			(10,593)
Depreciation, depletion and amortization expense		571,934		32,499		959			605,392
Impairment of natural gas and oil properties		1,090,473		–		–			1,090,473
Interest expense(2)		14,459		10,904		942			26,305
Provision (benefit) for income taxes(2)		(289,875)		78,268		1,126			(210,481)
Assets		5,854,055		1,158,638		343,869	(3)		7,356,562
Capital investments(4)		1,450,569		105,576		30,486			1,586,631

(1) The operating loss for the E&P segment for the three and nine months ended September 30, 2012 includes a $289.8 million and $1,090.5 million non-cash ceiling test impairment of our natural gas and oil properties respectively.

(2) Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

(3) Other assets represent corporate assets not allocated to segments and assets, including restricted cash and investments in cash equivalents, for non reportable segments.

(4) Capital investments includes decreases of $14.6 million and $56.2 million for the three-month periods ended September 30, 2013 and 2012, respectively, and increase of $25.8 million and decrease of $40.7 million for the nine-month periods ended September 30, 2013 and 2012, respectively, relating to the change in accrued expenditures between periods.

Included in intersegment revenues of the Midstream Services segment are $515.3 million and $332.1 million for the three months ended September  30, 2013 and 2012, respectively, and $1,493.8 million and $863.7 million for the nine months ended September 30, 2013 and 2012, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, restricted cash, furniture and fixtures, prepaid debt and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments. For the three months ended September  30, 2013 and 2012, capital investments within the E&P segment include$11.9million and $2.2 million, respectively, related to the Company’s activities in Canada.  For the nine months ended September 30, 2013 and 2012, capital investments within the E&P segment include $19.8 million and $6.9 million, respectively, relating to the Company’s activities in Canada. At September  30, 2013, E&P segment assets include $64.8 million and at September  30, 2012, assets include $36.4  million related to the Company’s activities in Canada.

25

(16) NEW ACCOUNTING PRONOUNCEMENTS ADOPTED

In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“Update 2013-02”), which finalizes  proposed ASU No. 2012-240, and seeks to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. Update 2013-02 replaces the presentation requirements in ASU No. 2011-05,Comprehensive Income (Topic 220): Presentation of Comprehensive Income, and ASU No. 2011-12, ComprehensiveIncome (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out ofAccumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. Update 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respectiveline items in net income if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income. For public entities, Update 2013-02 is effective prospectively for reporting periods beginning after December15, 2012, with early adoption permitted. The implementation of the disclosure requirement did not have amaterial impact on the Company’s consolidated results of operations, financial position or cash flows. 

In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”), which finalizes Proposed ASU No.2012-250 and clarifies the scope of transactions that are subject to disclosures concerning offsetting. Update 2013-01 addresses implementation issues regarding the scope of ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures aboutOffsetting Assets and Liabilities, issued in December 2011. Update 2013-01 clarifies that the scope of the disclosures underU.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowingand securities lending transactions that are offset either in accordance with FASB ASC Section 210-20-45, Balance Sheet—Offsetting—Other Presentation Matters, or FASB ASC Section 815-10-45, Derivatives and Hedging—Overall—Other Presentation Matters, or are subject to a master netting arrangement or similar agreement. Update 2013-01 requiresan entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to providethe required disclosures retrospectively for all comparative periods presented. The implementation of the disclosure requirement did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

(17) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Company is providing condensed consolidating financial information for SEECO, SEPCO and SES, its subsidiaries that are currently guarantors of the Company’s registered public debt, and for its other subsidiaries that are not guarantors of such debt. These wholly owned subsidiary guarantors have jointly and severally, fully and unconditionally guaranteed the Company’s 7.35% Senior Notes,7.125% Senior Notes, and 4.10% Senior Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated to any future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors.

The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees. The following condensed consolidating financial information summarizes the results of operations, financial position and cash flows for the Company’s guarantor and non-guarantor subsidiaries.

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Unaudited)
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
	(in thousands)
Three months ended September 30, 2013:
Operating revenues	$	–	$	823,112	$	130,998	$	(85,744)	$	868,366
Operating costs and expenses:
Gas purchases – midstream services		–		195,437		–		(166)		195,271
Operating expenses		–		140,400		35,425		(85,556)		90,269
General and administrative expenses		–		43,836		7,155		(22)		50,969
Depreciation, depletion and amortization		–		191,972		12,962		–		204,934
Taxes, other than income taxes		–		15,348		2,346		–		17,694
Total operating costs and expenses		–		586,993		57,888		(85,744)		559,137
Operating income		–		236,119		73,110		–		309,229
Other income (loss), net		–		145		(464)		–		(319)
Gain on derivatives		–		10,251		1,873		–		12,124
Equity in earnings of subsidiaries		185,867		–		–		(185,867)		–
Interest expense		–		9,359		1,659		–		11,018
Income before income taxes		185,867		237,156		72,860		(185,867)		310,016
Provision for income taxes		–		91,466		32,683		–		124,149
Net income		185,867		145,690		40,177		(185,867)		185,867
Comprehensive income	$	139,179	$	98,102	$	40,811	$	(138,913)	$	139,179
Three months ended September 30, 2012:
Operating revenues	$	–	$	647,961	$	121,343	$	(77,577)	$	691,727
Operating costs and expenses:
Gas purchases – midstream services		–		149,765		–		(114)		149,651
Operating expenses		–		106,293		32,277		(76,664)		61,906
General and administrative expenses		–		30,818		6,102		(799)		36,121
Depreciation, depletion and amortization		–		193,057		10,878		–		203,935
Impairment of natural gas and oil properties		–		289,821		–		–		289,821
Taxes, other than income taxes		–		13,513		2,739		–		16,252
Total operating costs and expenses		–		783,267		51,996		(77,577)		757,686
Operating income (loss)		–		(135,306)		69,347		–		(65,959)
Other income, net		–		216		22		–		238
Loss on derivatives		–		(5,879)		–		–		(5,879)
Equity in earnings of subsidiaries		(54,053)		–		–		54,053		–
Interest expense		–		7,200		3,406		–		10,606
Income (loss) before income taxes		(54,053)		(148,169)		65,963		54,053		(82,206)
Provision (benefit) for income taxes		–		(53,903)		25,750		–		(28,153)
Net income (loss)		(54,053)		(94,266)		40,213		54,053		(54,053)
Comprehensive income (loss)	$	(183,944)	$	(225,408)	$	41,210	$	184,198	$	(183,944)

27

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Unaudited)
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
	(in thousands)
Nine months ended September 30, 2013:
Operating revenues	$	–	$	2,331,343	$	379,212	$	(246,499)	$	2,464,056
Operating costs and expenses:
Gas purchases – midstream services		–		576,185		–		(848)		575,337
Operating expenses		–		375,721		106,520		(245,593)		236,648
General and administrative expenses		–		116,648		19,164		(58)		135,754
Depreciation, depletion and amortization		–		533,876		37,392		–		571,268
Taxes, other than income taxes		–		50,053		8,490		–		58,543
Total operating costs and expenses		–		1,652,483		171,566		(246,499)		1,577,550
Operating income		–		678,860		207,646		–		886,506
Other income (loss), net		–		67		(565)		–		(498)
Gain on derivatives		–		73,906		1,873		–		75,779
Equity in earnings of subsidiaries		559,013		–		–		(559,013)		–
Interest expense		–		23,884		5,433		–		29,317
Incomebefore income taxes		559,013		728,949		203,521		(559,013)		932,470
Provision for income taxes		–		291,795		81,662		–		373,457
Net income		559,013		437,154		121,859		(559,013)		559,013
Comprehensive income	$	457,967	$	337,122	$	120,045	$	(457,167)	$	457,967
Nine months ended September 30, 2012:
Operating revenues	$	–	$	1,824,594	$	350,064	$	(222,020)	$	1,952,638
Operating costs and expenses:
Gas purchases – midstream services		–		424,425		–		(484)		423,941
Operating expenses		–		311,165		87,461		(219,148)		179,478
General and administrative expenses		–		111,567		20,700		(2,388)		129,879
Depreciation, depletion and amortization		–		572,139		33,253		–		605,392
Impairment of natural gas and oil properties		–		1,090,473		–		–		1,090,473
Taxes, other than income taxes		–		42,159		8,995		–		51,154
Total operating costs and expenses		–		2,551,928		150,409		(222,020)		2,480,317
Operating income (loss)		–		(727,334)		199,655		–		(527,679)
Other income (loss), net		–		(23)		2,638		–		2,615
Loss on derivatives		–		(10,593)		–		–		(10,593)
Equity in earnings of subsidiaries		(351,481)		–		–		351,481		–
Interest expense		–		15,460		10,845		–		26,305
Income (loss) before income taxes		(351,481)		(753,410)		191,448		351,481		(561,962)
Provision (benefit) for income taxes		–		(285,231)		74,750		–		(210,481)
Net income (loss)		(351,481)		(468,179)		116,698		351,481		(351,481)
Comprehensive income (loss)	$	(567,869)	$	(686,291)	$	117,660	$	568,631	$	(567,869)

28

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
	Parent		Guarantors		Non- Guarantors		Eliminations		Consolidated
	(in thousands)
September 30, 2013:
ASSETS
Cash and cash equivalents	$	17,956	$	–	$	994	$	–	$	18,950
Accounts receivable		3,114		423,418		18,191		–		444,723
Inventories		–		40,906		2,319		–		43,225
Other assets		13,893		212,154		7,030		–		233,077
Total current assets		34,963		676,478		28,534		–		739,975
Intercompany receivables		2,548,900		57		54,531		(2,603,488)		–
Property and equipment		236,324		13,079,991		1,507,238		–		14,823,553
Less: Accumulated depreciation, depletion and amortization		(102,706)		(7,455,008)		(229,106)		–		(7,786,820)
		133,618		5,624,983		1,278,132		–		7,036,733
Investments in subsidiaries (equity method)		2,788,544		–		–		(2,788,544)		–
Other assets		32,103		69,697		15,880		–		117,680
Total assets	$	5,538,128	$	6,371,215	$	1,377,077	$	(5,392,032)	$	7,894,388
LIABILITIES AND EQUITY
Accounts payable	$	147,265	$	432,089	$	84,372	$	–	$	663,726
Other current liabilities		3,759		141,307		1,019		–		146,085
Total current liabilities		151,024		573,396		85,391		–		809,811
Intercompany payables		–		2,603,488		–		(2,603,488)		–
Long-term debt		1,911,165		–		–		–		1,911,165
Deferred income taxes		(115,675)		1,077,055		427,453		–		1,388,833
Other liabilities		71,625		178,703		14,262		–		264,590
Total liabilities		2,018,139		4,432,642		527,106		(2,603,488)		4,374,399
Commitments and contingencies
Total equity		3,519,989		1,938,573		849,971		(2,788,544)		3,519,989
Total liabilities and equity	$	5,538,128	$	6,371,215	$	1,377,077	$	(5,392,032)	$	7,894,388

29

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
	Parent		Guarantors		Non- Guarantors		Eliminations		Consolidated
	(in thousands)
December 31, 2012:
ASSETS
Cash and cash equivalents	$	47,491	$	5,988	$	104	$	–	$	53,583
Restricted cash		8,542		–		–		–		8,542
Accounts receivable		2,677		353,607		21,354		–		377,638
Inventories		2		26,975		1,164		–		28,141
Other assets		7,461		321,396		12,151		–		341,008
Total current assets		66,173		707,966		34,773		–		808,912
Intercompany receivables		2,259,713		42		27,077		(2,286,832)		–
Property and equipment		220,837		11,491,222		1,316,380		–		13,028,439
Less: Accumulated depreciation, depletion and amortization		(82,178)		(6,923,106)		(186,179)		–		(7,191,463)
		138,659		4,568,116		1,130,201		–		5,836,976
Investments in subsidiaries (equity method)		2,309,947		–		–		(2,309,947)		–
Other assets		35,136		42,247		14,256		–		91,639
Total assets	$	4,809,628	$	5,318,371	$	1,206,307	$	(4,596,779)	$	6,737,527
LIABILITIES AND EQUITY
Accounts payable	$	140,367	$	375,604	$	41,009	$	–	$	556,980
Other current liabilities		3,758		205,623		1,410		–		210,791
Total current liabilities		144,125		581,227		42,419		–		767,771
Intercompany payables		–		2,108,360		178,472		(2,286,832)		–
Long-term debt		1,668,273		–		–		–		1,668,273
Deferred income taxes		(116,207)		820,279		345,066		–		1,049,138
Other liabilities		77,565		124,505		14,403		–		216,473
Total liabilities		1,773,756		3,634,371		580,360		(2,286,832)		3,701,655
Commitments and contingencies
Total equity		3,035,872		1,684,000		625,947		(2,309,947)		3,035,872
Total liabilities and equity	$	4,809,628	$	5,318,371	$	1,206,307	$	(4,596,779)	$	6,737,527

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
	(in thousands)
Nine months ended September 30, 2013:
Net cash provided by (used in) operating activities	$	(32,502)	$	1,062,133	$	347,887	$	–	$	1,377,518
Investing activities:
Capital investments		(29,227)		(1,530,760)		(167,556)		–		(1,727,543)
Proceeds from sale of property and equipment		–		210		2,871		–		3,081
Transfers from restricted cash		8,542		–		–		–		8,542
Other		(74)		(1,685)		6,459		–		4,700
Net cash used in investing activities		(20,759)		(1,532,235)		(158,226)		–		(1,711,220)
Financing activities:
Intercompany activities		(274,931)		464,114		(189,183)		–		–
Payments on current portion of long-term debt		(600)		–		–		–		(600)
Payments on revolving long-term debt		(2,134,550)		–		–		–		(2,134,550)
Borrowing under revolving long-term debt		2,377,950		–		–		–		2,377,950
Other Items		55,857		–		–		–		55,857
Net cash provided by (used in) financing activities		23,726		464,114		(189,183)		–		298,657
Effect of exchange rate changes on cash		–		–		412		–		412
Increase (decrease) in cash and cash equivalents		(29,535)		(5,988)		890		–		(34,633)
Cash and cash equivalents at beginning of year		47,491		5,988		104		–		53,583
Cash and cash equivalents at end of period	$	17,956	$	–	$	994	$	–	$	18,950
Nine months ended September 30, 2012:
Net cash provided by (used in) operating activities	$	(55,324)	$	915,885	$	331,916	$	–	$	1,192,477
Investing activities:
Capital investments		(38,946)		(1,452,061)		(132,744)		–		(1,623,751)
Proceeds from sale of property and equipment		144		169,149		31,868		–		201,161
Transfers to restricted cash		(167,774)		–		–		–		(167,774)
Transfers from restricted cash		40,700		–		–		–		40,700
Other		16,575		(24,340)		13,004		–		5,239
Net cash used in investing activities		(149,301)		(1,307,252)		(87,872)		–		(1,544,425)
Financing activities:
Intercompany activities		(148,027)		392,732		(244,705)		–		–
Payments on current portion of long-term debt		(600)		–		–		–		(600)
Payments on revolving long-term debt		(1,774,000)		–		–		–		(1,774,000)
Borrowings under revolving long-term debt		1,129,000		–		–		–		1,129,000
Proceeds from issuance of long-term debt		998,780		–		–		–		998,780
Other items		1,722		–		(11)		–		1,711
Net cash provided by (used in) financing activities		206,875		392,732		(244,716)		–		354,891
Effect of exchange rate changes on cash		–		–		(10)		–		(10)
Increase (decrease) in cash and cash equivalents		2,250		1,365		(682)		–		2,933
Cash and cash equivalents at beginning of year		14,711		–		916		–		15,627
Cash and cash equivalents at end of period	$	16,961	$	1,365	$	234	$	–	$	18,560

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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 2012 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three- and nine-month periods ended September 30, 2013 and 2012. For definitions of commonly used natural gas and oil terms used in this Form 10-Q, please refer to the “Glossary of Certain Industry Terms” provided in our 2012 Annual Report on Form 10-K.

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in the “Cautionary Statement About Forward-Looking Statements” in the forepart of this Form 10-Q, in Item 1A, “Risk Factors” in Part I and elsewhere in our 2012 Annual Report on Form 10-K, and Item 1A, “Risk Factors” in Part II in this Form 10-Q and any other Form 10-Q filed during the fiscal year. You should read the following discussion with our unaudited condensed consolidated financial statements and the related notes included in this Form 10-Q.

OVERVIEW

Background

Southwestern Energy Company is an independent energy company engaged in natural gas andoilexploration, development and production, or E&P. We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as Midstream Services. We operate principally in two segments: E&P and Midstream Services.   

Our primary business is the exploration for and production of natural gas and oil, with our current operations being focused within the United States.  We are actively engaged in exploration and production activities in Arkansas, where we are targeting the unconventional gas reservoir known as the Fayetteville Shale, in Pennsylvania, where we are targeting the unconventional gas reservoir known as the Marcellus Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma Basin.  We have recently commenced exploration operations in Arkansas and Louisiana testing an unconventional oil play targeting the Lower Smackover Brown Dense, or LSBDformation, as well as in Colorado.  In 2010, we commenced an exploration program in New Brunswick, Canada, which representsour first operations outside of the United States.

We are focused on providing long-term growth in the net asset value of our business. We derive the 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 willdependprimarilyon natural gas prices and our ability to increase our natural gas production. We expect our natural gas production volumes will continue to increase due to our ongoing development of the Fayetteville Shale play and the Marcellus Shale play. The price we expect to receive for our natural gas is a critical factor in the capital investments we make in order to develop our properties and increase our production. In recent years, there has been volatility in natural gas prices as evidenced byNew York Mercantile Exchange, or NYMEX,natural gas prices ranging from a high of $13.58 per MMBtu in 2008 to a recent low of$1.91per MMBtu inApril2012. Natural gas prices fluctuate due to a variety of factors we cannot control or predict. These factors, which include increased supplies of natural gas due to greater exploration and development activities, weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas, which in turn determines the sale prices for our production. In addition to the factors identified above, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices.

Three Months Ended September 30, 2013 Compared with Three Months Ended September 30, 2012

We reported net income of $185.9 million for the three months ended September 30, 2013, or $0.53 per diluted share, compared to a  net loss of $54.1 million, or$0.16 per diluted share, for the comparable period in 2012.  

Our natural gas and oil production increased to 172.4 Bcfe for the three months ended September 30, 2013, up 19% from 144.3 Bcfe for the three months ended September 30, 2012.The 28.1 Bcfe increase in our third quarter 2013 production was primarily due to a 29.6 Bcf increase in net production from our Marcellus Shale properties and a 1.5 Bcf decrease in net production from our other properties.  The average price realized for our gas production, including the

32

effects of hedges, increased 6% to $3.60 per Mcf for the three months ended September 30, 2013 compared to $3.41 per Mcf for the same period in 2012.

Our E&P segment reported operating income of $222.7 million for the three months ended September 30, 2013, up from an operating loss of $141.9 million for the three months ended September 30, 2012.  The loss for the three months ended September 30, 2012 included a $289.8 million non-cash ceiling test impairment of our natural gas and oil properties.  Excluding the $289.8 non-cash ceiling test impairment, operating income for the three months ended September 30, 2013 increased $74.7 million as a result of an increase in revenue of $96.0 million from higher natural gas production volumes and an increase in revenue of $25.8 million from increased prices from the sale of our natural gas production, offset by an increase in operating costs and expenses of $49.6 million associated with the expansion of our E&P operations due to the continued development of our Fayetteville Shale play and Marcellus Shale play.

Operating income for our Midstream Services segment was $86.7 million for the three months ended September 30, 2013, up from $75.5 million for the three months ended September 30, 2012, primarily due to an increase of $10.4 million in gas gathering revenues and an increase of $8.2 million in the margin generated from our natural gas marketing activities, which was partially offset by a $7.4 million increase in operating costs and expenses associated with an increase in natural gas volumes gathered, exclusive of natural gas purchase costs.

Capital investments were $542.1 million for the three months ended September 30, 2013, of which $496.3 million was invested in our E&P segment, compared to $424.9 million for the same period of 2012, of which $385.6 million was invested in our E&P segment.

Nine Months Ended September 30, 2013 Compared with Nine Months Ended September 30, 2012

We reported net income of $559.0 million for the nine months ended September 30, 2013, or $1.59 per diluted share, compared to net loss of $351.5 million, or $1.01 per diluted share, for the comparable period in 2012.  

Our natural gas and oil production increased to 480.3 Bcfe for the nine months ended September 30, 2013, up 16% from 415.1 Bcfe for the nine months ended September 30, 2012.The 65.2 Bcfe increase in our 2013 production was primarily due to a 67.8 Bcf increase in net production from our Marcellus Shale properties,a 2.4 Bcf increase in net production from our Fayetteville Shale properties, and a 1.2 Bcfe increase from our New Ventures properties, which more than offset a 6.2 Bcfe decrease in net production from our Ark-La-Tex properties primarily due to the sale of certain East Texas oil and natural gas properties in 2012. The average price realized for our gas production, including the effects of hedges, increased 9% to $3.63 per Mcf for the nine months ended September 30, 2013 compared to $3.33 per Mcf for the same period in 2012.

Our E&P segment reported operating income of $651.0 million for the nine months ended September 30, 2013, up from an operating loss of $745.5 million for the nine months ended September 30, 2012.  The loss for the nine months ended September 30, 2012 included a $1,090.5 million non-cash ceiling test impairment of our natural gas and oil properties.  Excluding the $1,090.5 non-cash ceiling test impairment, operating income for the nine months ended September 30, 2013 increased $306.1 million as a result of an increase in revenue of $217.3 million from higher natural gas production volumes, an increase in revenue of $129.4 million from increased prices realized from the sale of our natural gas production and an increase in revenues of $6.3 million from higher oil and NGL volumes, offset by an increase in operating costs and expenses of $47.5 million associated with the expansion of our E&P operations due to the continued development of our Fayetteville Shale play and Marcellus Shale play.

Operating income for our Midstream Services segment was $235.9 million for the nine months ended September 30, 2013, up from $216.6 million for the nine months ended September 30, 2012, primarily due to an increase of $31.3 million in gas gathering revenues and an increase of $10.9 million in the margin generated from our gas marketing activities, which was partially offset bya $23.0 million increase in operating costs and expenses associated with an increase in gas volumes gathered, exclusive of gas purchase costs.

Net cash provided by operating activities increased 16% to $1,377.5 million for the nine months ended September 30, 2013, up from $1,192.5 million for the same period in 2012, due to an increase in net income adjusted for non-cash expenses primarily resulting from increased revenues due to higher natural gas production and gathering volumes, higher realized gas prices, offset slightly by a decrease in changes in working capital.Capital investments were $1,755.1 million for the nine months ended September 30, 2013, of which $1,602.9 million was invested in our E&P segment, compared to $1,586.6 million for the same period of 2012, of which $1,450.6 million was invested in our E&P segment.

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RESULTS OF OPERATIONS

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense, income tax expense and stock-based compensation are discussed on a consolidated basis.

Exploration and Production
	For the three months				For the nine months
	ended September 30,				ended September 30,
	2013		2012		2013		2012
Revenues (in thousands)	$	622,477	$	498,101	$	1,752,638	$	1,399,033
Impairment of natural gas and oil properties (in thousands)	$	–	$	289,821	$	–	$	1,090,473
Operating costs and expenses (in thousands)	$	399,785	$	350,145	$	1,101,642	$	1,054,093
Operating income (loss) (in thousands)	$	222,692	$	(141,865)	$	650,996	$	(745,533)
Gain (loss) on derivatives(1)	$	2,020	$	(4,740)	$	3,115	$	(11,485)
Gas production (Bcf)		172.1		144.2		479.4		414.7
Oil production (MBbls)		37		19		102		59
NGL production (MBbls)		12		–		40		–
Total production (Bcfe)		172.4		144.3		480.3		415.1
Average realized gas price per Mcf, including hedges (2)	$	3.60	$	3.41	$	3.63	$	3.33
Average realized gas price per Mcf, excluding hedges	$	3.06	$	2.35	$	3.18	$	2.12
Average oil price per Bbl	$	106.72	$	99.67	$	105.05	$	102.89
Average NGL price per Bbl	$	42.05	$	–	$	44.20	$	–
Average unit costs per Mcfe:
Lease operating expenses	$	0.87	$	0.79	$	0.85	$	0.80
General & administrative expenses	$	0.24	$	0.21	$	0.23	$	0.26
Taxes, other than income taxes	$	0.09	$	0.09	$	0.10	$	0.10
Full cost pool amortization	$	1.07	$	1.30	$	1.07	$	1.34

(1)Represents the commodity mark to market gain (loss) on derivatives, settled, associated with derivatives not designated or not qualifying for hedge accounting.

(2)Had we included the commodity mark to market gain (loss) on derivatives effects of commodity hedging contracts not designated or not qualifying for hedge accounting, our average price for total natural gas would have been $3.67, $3.40, $3.78, and $3.34 per Mcf for the three months ended September 30, 2013 and 2012, and the nine months ended September 30, 2013 and 2012, respectively.

Revenues

Revenues for our E&P segment were $622.5 million for the three months ended September 30, 2013, up $124.4 million, or 25%, compared to the same period in 2012. Higher natural gas production volumes and increased prices realized from the sale of our natural gas production increased revenues by $96.0 million and $25.8 million, respectively.  E&P revenues were $1.8 billion for the nine months ended September 30, 2013, up $353.6 million, or 25%. The increase in revenue was driven by a $217.3 million increase from higher natural gas production volumes, a $129.4 million increase from prices realized from the sale of our natural gas production, and a $6.3 million increase from higher oil and NGL volumes. We expect our natural gas production volumes to continue to increase due to our development and growth of our shale properties.  Natural gas prices are difficult to predict and subject to wide price fluctuations. As of September 30, 2013, we had hedged 84.4 Bcf of our remaining 2013 natural gas production and 232.7 Bcf of our 2014 natural gas production to limit our exposure to price fluctuations. We refer you to Note 7 to the unaudited condensed consolidated financial statements included in this Form 10-Q and to the discussion of “Commodity Prices” provided below for additional information.

34

Production

For the three months ended September 30, 2013, our natural gas and oil production increased 19% to 172.4 Bcfe, up from 144.3 Bcfe from the same period in 2012, and was produced entirely by our properties in the United States. The 28.1 Bcfe increase in our 2013 production was primarily due to a 29.6 Bcf increase in net production from our Marcellus Shale properties and a 1.5 Bcf decrease in net production from our other properties. Net production from our Fayetteville Shale and Marcellus Shale properties was 122.7 Bcf and 44.7 Bcf, respectively, for the three months ended September 30, 2013 compared to 123.6 Bcf and 15.1 Bcf, respectively, for the same period in 2012.For the nine months ended September 30, 2013, our natural gas and oil production increased 16% to 480.3 Bcfe, up from 415.1 Bcfe from the same period in 2012, and was produced entirely by our properties in the United States. The 65.2 Bcfe increase in our 2013 production was primarily due to a 67.8 Bcf increase in net natural gas production from our Marcellus Shale properties, a 2.4 Bcf increase in net production from our Fayetteville Shale play, and a 1.2 Bcfe increase in our New Ventures properties, which more than offset a 6.2 Bcfe decrease in net production from our Ark-La-Tex properties. Net production from our Fayetteville Shale and Marcellus Shale properties was 362.8 Bcf and 102.1 Bcf, respectively, for the nine months ended September 30, 2013 compared to 360.4 Bcf and 34.3 Bcf, respectively, for the same period in 2012.

Commodity Prices

The average realized price for our natural gas production, including the effects of hedges, increased to $3.60 per Mcf for the three months ended September 30, 2013, as compared to $3.41 for the same period in 2012.  The increase was the result of a $0.71 per Mcf increase in average natural gas prices, excluding hedges, partially offset by a $0.52per Mcf decrease in the impact of our price hedging activities.  The average price realized for our natural gas production, excluding the effects of hedges, increased 30% to $3.06 per Mcf for the three months ended September 30, 2013, as compared to the same period in 2012.  Our hedges increased the average realized natural gas price $0.54 per Mcf for the three months ended September 30, 2013 compared to an increase of $1.06 per Mcf for the same period in 2012.  The average price realized for our natural gas production, including the effects of hedges, increased 9% to $3.63 per Mcf for the nine months ended September 30, 2013, as compared to the same period in 2012. The increase in the average price realized for nine months ended September 30, 2013, as compared to the same period in 2012, primarily reflects the $1.06 Mcf increase in average gas prices, excluding hedges, which was partially offset by the $0.76 Mcf decreased effect of our price hedging activities. Our hedging activities increased the average natural gas price $0.45 per Mcf for the nine months ended September 30, 2013 compared to an increase of $1.21 per Mcf for the same period in 2012. 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 basis differentials (we refer you to Item 3 and Note 7 to the unaudited condensed consolidated financial statements included in this Form 10-Q for additional discussion).

Our E&P segment receives a sales price for our natural gas at a discount to average monthly NYMEX settlement prices due to locational basis differentials, while transportation charges and fuel charges also reduce the price received.  Excluding the impact of hedges, the average price received for our natural gas production for the nine months ended September 30, 2013 of $3.18 per Mcf was approximately $0.49 lower than the average monthly NYMEX settlement price, primarily due to locational basis differentials and transportation costs.  We protected approximately 51% of our natural gas production for the nine months ended September 30, 2013 from the impact of widening basis differentials through our hedging activities and sales arrangements. For the remainder of 2013, we expect our total natural gas sales discount to NYMEX to be approximately $0.50 to $0.55 per Mcf.  At September 30, 2013, we had basis protected on approximately 74 Bcf of our remaining 2013 expected natural gas production through financial hedging activities and physical sales arrangements at a differential to NYMEX natural gas prices of approximately ($0.06) per Mcf, excluding transportation and fuel charges.Additionally, at September 30, 2013, we had basis protected on approximately 141 Bcf and 29 Bcf of our 2014 and 2015 expected natural gas production, respectively, through financial hedging activities and physical sales arrangements.

In addition to the basis hedges discussed above, at September 30, 2013, we had NYMEX fixed price hedges in place on notional volumes of 84.4 Bcf of our remaining 2013 natural gas production at an average price of $4.68 per MMBtu and notional volumes of 232.7 Bcf of our 2014 natural gas production at an average price of $4.41per MMBtu.

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Operating Income

Our E&P segment reported operating income of $222.7 million for the three months ended September 30, 2013, up from an operating loss of $141.9 million for the three months ended September 30, 2012.  The loss for the three months ended September 30, 2012 included a $289.8 million non-cash ceiling test impairment of our natural gas and oil properties.  Excluding the $289.8 non-cash ceiling test impairment, operating income for the three months ended September 30, 2013 increased $74.7 million as a result of an increase in revenue of $96.0 million from higher natural gas production volumes and an increase in revenue of $25.8 million from increased prices from the sale of our natural gas production, offset slightly by an increase in operating costs and expenses of $49.6 million due to increased compression and gathering costs.Our E&P segment reported operating income of $651.0 million for the nine months ended September 30, 2013, up from an operating loss of $756.1 million for the nine months ended September 30, 2012.  The loss for the nine months ended September 30, 2012 included a $1,090.5 million non-cash ceiling test impairment of our natural gas and oil properties.  Excluding the $1,090.5 non-cash ceiling test impairment, operating income for the nine months ended September 30, 2013 increased $306.1 million as a result of an increase in revenue of $217.3 million from higher natural gas production volumes, an increase in revenue of $129.4 million from increased prices realized from the sale of our natural gas production, an increase in revenues of $6.3 million from higher oil and NGL volumes,  offset by an increase in operating costs and expenses of $47.5 million due primarily to increased compression and gathering costs,  reduced slightly by lower salt water disposal costs.

Operating Costs and Expenses

Lease operating expenses per Mcfe for our E&P segment were $0.87 for the three months ended September 30, 2013 compared to $0.79 for the same period in 2012.  Lease operating expenses per Mcfe for our E&P segment were $0.85 for thenine months ended September 30, 2013 compared to $0.80 for the same period in 2012.  The increase in lease operating expense per unit of production for the three-and nine-months ended September 30, 2013 as compared to the same period of 2012, was primarily due to increase in compression and gathering cost in our Marcellus Shale play, offset slightly by a decrease in salt water disposal cost in our Fayetteville Shale play. 

General and administrative expenses per Mcfe for our E&P segment were $0.24 for the three months ended September 30, 2013 compared to $0.21for the same period in 2012 primarily due to anincrease in personnel costs.  General and administrative expenses per Mcfe were $0.23 for the nine months ended September 30, 2013 compared to $0.26 for same period in 2012 primarily due to a decrease in personnel costs and increased production volumes.In total general and administrative expenses for our E&P segment were $42.0 million for the three months ended September 30, 2013 compared to $30.3 million for the same period in 2012, primarily due to increased personnel costs and professional fees associated with the expansion of our E&P operations due to the continued development of our Fayetteville Shale play and Marcellus Shale play.  In total general and administrative expenses for our E&P segments were $111.6 million for the nine months ended September 30, 2013 compared to $107.6 million for the same period in 2012. The increase in general and administrative expenses for the nine months ended September 30, 2013 as compared to the same period of 2012, was primarily a result of increased professional fees associated with the expansion of our E&P operations due to the continued development of our Fayetteville Shale play and Marcellus Shale play.

Taxes other than income taxes per Mcfe were $0.09 for the three months ended September 30, 2013 and 2012,and $0.10 for the nine months ended September 30, 2013 and 2012. Taxes other than income taxes per Mcfe vary from period to period due to changes in severance and ad valorem taxes that result from the mix of our production volumes and fluctuations in commodity prices.

Our full cost pool amortization rate averaged $1.07 per Mcfe for the three months ended September 30, 2013 compared to $1.30 for the same period in 2012. For the first nine months of 2013, our full cost pool amortization rate averaged $1.07 per Mcfe compared to $1.34 per Mcfe for the same period in 2012. 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, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to 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 other factors, including but not limited to the uncertainty of the amount of future reserves. 

Unevaluated costs excluded from amortization were $1,101.5 million at September 30, 2013 compared to $1,023.9 million at December 31, 2012. The increase in unevaluated costs since December 31, 2012 primarily resulted from our acquisition of Marcellus acreage in the second quarter 2013 and an increase in our wells in progress. Unevaluated costs excluded from amortization at September 30, 2013 included $58.7 million related to our properties in Canada, compared to $40.4 million at December 31, 2012.

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The timing and amount of production and reserve additions and revisions could have a material adverse impact on our per unit costs.

Midstream Services
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	($ in thousands, except volumes)
Revenues – marketing	$	716,703	$	481,845	$	2,076,590	$	1,289,818
Revenues – gathering	$	130,902	$	120,494	$	378,697	$	347,370
Gas purchases – marketing	$	701,304	$	474,628	$	2,042,948	$	1,267,117
Operating costs and expenses	$	59,643	$	52,223	$	176,485	$	153,473
Operating income	$	86,658	$	75,488	$	235,854	$	216,598
Gas volumes marketed (Bcf)		206.4		171.2		574.9		498.7
Gas volumes gathered (Bcf)		229.9		214.7		667.3		622.9

Revenues

Revenues from our marketing activities were up 49% to $716.7 million for the three months ended September 30, 2013 and were up 61% to $2,076.6 million for the nine months ended September 30, 2013 compared to the same period in 2012.  For the three months ended September 30, 2013, the volumes marketed increased 21% and the price received for volumes marketed increased 23% compared to the same period in 2012.For the nine months ended September 30, 2013, the volumes marketed increased 15% and the price received for volumes marketed increased 39% compared to the same period in 2012. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in gas purchase expenses. Of the total volumes marketed, production from our affiliated E&P operated wells accounted for 95% and 96% of the marketed volumes for the three months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013 and 2012, production from our affiliated E&P operated wells accounted for 96% and 95% of the marketed volumes, respectively.

Revenues from our gathering activities were up 9% to $130.9 million for the three months ended September 30, 2013 and up 9% to $378.7 million for the nine months ended September 30, 2013 compared to respective periods in 2012. The increase in gathering revenues resulted primarily from a 7% increase in gas volumes gathered for the three months ended September 30, 2013 and the nine months ended September 30, 2013, respectively, compared to the same period in 2012.  A majority of the increase in gathering revenues for the three- and nine-months ended September 30, 2013 resulted from increases in volumes gathered due to our development and growth of our shale properties. Gathering volumes, revenues and expenses for this segment are expected to continue to grow as reserves related to our shale properties are developed and production increases.

Operating Income

Operating income from our Midstream Services segment increased to $86.7 million for the three months ended September 30, 2013  compared to $75.5 million for the same period in 2012and increased to $235.9 million for the nine months ended September 30, 2013 compared to $216.6 million for the same period in 2012. Operating income was higher due to increases in gas volumes gathered which primarily resulted from our increase inE&P production volumes. The $11.2 million increase in operating income for the three months ended September 30, 2013 was primarily due to an increase of $10.4 million in gathering revenues and an increase of $8.2 million in the margin generated from our gas marketing activities, which was partially offset by a $7.4 million increase in operating costs and expenses associated with an increase in gas volumes gathered, exclusive of gas purchase costs. The $19.3 million increase in operating income for the nine  months ended September 30, 2013 was primarily due to an increase of $31.3 million in gathering revenues and an increase of $10.9 million in the margin generated from our gas marketing activities, which was partially offset by a $23.0 million increase in operating costs and expenses, exclusive of gas purchase costs, associated with the increase in gas volumes gathered.

The margin generated from gas marketing activities was $15.4 million for the three months ended September 30, 2013 compared to $7.2 million for the three months ended September 30, 2012. The margin generated from gas marketing activities was $33.6 million for the nine months ended September 30, 2013 compared to $22.7 million for the nine months ended September 30, 2012. Margins are primarily driven by volumes of natural gas marketed and may

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fluctuate depending on the prices paid for commodities and the ultimate disposition of those commodities. We enter into hedging activities from time to time with respect to our natural gas marketing activities to provide margin protection. We refer you to Item 3, “Quantitative and Qualitative Disclosures about Market Risks” included in this Form 10-Q for additional information.

Interest Expense

Interest expense, net of capitalization, increased to $11.0 million for the three months ended September 30, 2013, compared to $10.6 million for the same period in 2012 and increased to $29.3 million for the nine months ended September 30, 2013 compared to $26.3 million for the same period in 2012.The increase in interest expense, net of capitalization, for the three months ended September 30, 2013 was primarily due to a decrease in capitalized interest for the three monthsended September 30, 2013.  The increase in interest expense, net of capitalization, for the nine-month period ended September 30, 2013 was primarily due to our increased borrowing level, partially offset by an increase in capitalized interest for the nine months ended September 30, 2013. We capitalized interest of $15.5 and $15.9 million for the three months ended September 30, 2013 and 2012, respectively.  The decrease in capitalized interest for the three months ending September 30, 2013 compared to the same period in 2012 was primarily due to a decrease to the Company’s weighted average borrowing rate.  We capitalized interest of $48.5 and $45.9 million for and nine-month periods ended September 30, 2013 and 2012, respectively.  The increase in capitalized interest for the nine-month period ending September 30, 2013 compared to the same period in 2012 was primarily due to the increase in our unevaluated property balance during 2013.

Gain (Loss) on Derivatives

At September 30, 2013, our basis swaps did not qualify for hedge accounting treatment. Changes in the fair value of derivatives that do not qualify as cash flow hedges are recorded in gain (loss) on derivatives.  For the nine months ended September 30, 2013, we recorded  a mark to market loss on derivatives of $26.9 million related to fixed price call options that did not qualify for hedge accounting treatment, amark to market gain on derivatives of $96.6 million related to fixed price swaps not designated for hedge accounting, and a mark to market gain on derivatives of $1.6 million related to the basis swaps that did not qualify for hedge accounting treatment. In general and without consideration of volatility or duration, as 2014 natural gas prices increase from current levels, the Company will recognize losses in future periods and, likewise, as 2014 natural gas prices decline from current levels, the Company will recognize gains in future periods on its derivative contracts not accounted for under hedge accounting prior to settlement.

Income Taxes

Our effective tax rates were 40.0% and 37.5% for the nine months ended September 30, 2013 and 2012, respectively.  For the nine months ended September 30, 2013, we recorded an income tax expense of $373.5  million compared to an income tax benefit of $210.5 million for the same period in 2012.

Stock-Based Compensation Expense

We recognized expense of $2.9 million and capitalized $2.8 million for stock-based compensation during the three months ended September 30, 2013 compared to $2.7 million expense and $2.5 million capitalized for the comparable period in 2012. We recognized expense of $8.9 million and capitalized $8.5 million for stock-based compensation costs recognized during the nine-month period ended September 30, 2013 compared to $8.2 million expense and $7.8 million capitalized for the comparable period in 2012. We refer you to Note 14 in the unaudited condensed consolidated financial statements included in this Form 10-Q for additional discussion of our equity based compensation plans.

New Accounting Standards

In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“Update 2013-02”), which finalizes  proposed ASU No. 2012-240, and seeks to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. Update 2013-02 replaces the presentation requirements in ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, and ASU No. 2011-12, ComprehensiveIncome (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out ofAccumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. Update 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respectiveline items in net income if the amount being reclassified is required under U.S.

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GAAP to be reclassified in its entirety to net income. For public entities, Update 2013-02 is effective prospectively for reporting periods beginning after December15, 2012, with early adoption permitted. The implementation of the disclosure requirement did not have amaterial impact on the Company’s consolidated results of operations, financial position or cash flows. 

In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”), which finalizes Proposed ASU No.2012-250 and clarifies the scope of transactions that are subject to disclosures concerning offsetting. Update 2013-01 addresses implementation issues regarding the scope of ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures aboutOffsetting Assets and Liabilities, issued in December 2011. Update 2013-01 clarifies that the scope of the disclosures underU.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowingand securities lending transactions that are offset either in accordance with FASB ASC Section 210-20-45, Balance Sheet—Offsetting—Other Presentation Matters, or FASB ASC Section 815-10-45, Derivatives and Hedging—Overall—Other Presentation Matters, or are subject to a master netting arrangement or similar agreement. Update 2013-01 requiresan entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to providethe required disclosures retrospectively for all comparative periods presented. The implementation of the disclosure requirement did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on internally-generated funds, our Credit Facility and funds accessed through debt and equity markets as our primary sources of liquidity.

For the remainder of 2013, assuming natural gas prices remain at current levels, we intend to draw on a portion of the funds available under our Credit Facility to fund our planned capital investments (discussed below under “Capital Investments”).  We refer you to Note 10 to the unaudited condensed consolidated financial statements included in this Form 10-Q and the section below under “Financing Requirements” for additional discussion of our Credit Facility.

Net cash provided by operating activities  increased 16% to $1,377.5 million for the nine months ended September 30, 2013 compared to $1,192.5 million for the same period in 2012,  is primarily due to an increase in net income adjusted for non-cash expenses primarily resulting from increased revenues due to higher realized gas prices, higher natural gas production and gathering volumes, offset slightly by a decrease in changes in working capital.During the nine months ended September 30, 2013, requirements for our capital investments were funded primarily from our cash generated by operating activities, cash and cash equivalents, and net proceeds from borrowings under our Credit Facility. For the nine months ended September 30, 2013, cash generated from our operating activities funded 80% of our cash requirements for capital investments and 73% for the nine months ended September 30, 2012.

We believe that our operating cash flow, cash equivalents, and available funds under our Credit Facility will be adequate to meet our capital and operating requirements for 2013. The credit status of the financial institutions participating in our Credit Facility could adversely impact our ability to borrow funds under the Credit Facility. While we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet its obligation.

Our cash flow from operating activities is highly dependent upon the market prices that we receive for our natural gas and oil production,  including regional basis differentials. Natural gas and oil prices are subject to wide fluctuations and are driven by market supply and demand factors which are impacted by the overall state of the economy. 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 7 in the unaudited condensed consolidated financial statements included in this Form 10-Q. Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to complete the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities.

Additionally, our short-term cash flows are dependent on the timely collection of receivables from our customers and partners. We actively manage this risk through credit management activities and through the date of this filing have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers and partners could adversely impact our cash flows.

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Due to the above factors, we are unable to forecast with certainty our future level of cash flow from operations. Accordingly, we will adjust our discretionary uses of cash dependent upon available cash flow.

Capital Investments

Our capital investments were $1.8 billion for the nine months ended September 30, 2013 compared to $1.6 billion for the comparable period in 2012.  Our E&P segment investments were $1.6 billion and $1.5 billion for the nine months ended September 30, 2013 and 2012 respectively.  Our E&P segment capitalized internal costs of $136.9 million for the nine months ended September 30, 2013 compared to $113.1 million for the comparable period in 2012. These internal costs were directly related to acquisition, exploration and development activities and are included as part of the cost of natural gas and oil properties.

Our capital investments for 2013 are planned to be approximately $2.25 billion, consisting of $2.0 billion for E&P, $160 million for Midstream Services and $90 million for corporate and other purposes. Of the approximate $2.0 billion for E&P, we expect to allocate approximately $900 million to our Fayetteville Shale play and approximately $870 million to our Marcellus Shale play.  Our planned level of capital investments in 2013 is expected to allow us to continue our progress in the Fayetteville Shale and Marcellus Shale programs and explore and develop other existing natural gas and oil properties and generate new drilling prospects. Our remaining 2013 capital investment program is expected to be funded through cash flow from operations and borrowings under our revolving credit facility. The planned capital program for 2013 is flexible and can be modified.  We will reevaluate our proposed investments as needed to take into account prevailing market conditions and we could change our planned investments.

Financing Requirements

Our total debt outstanding was $1.9 billion at September 30, 2013 compared to $1.7billion at December 31, 2012. In February 2011, we amended and restated our unsecured revolving credit facility, increasing the borrowing capacity to $1.5 billion and extending the maturity date to February 2016.  The amount available under the revolving credit facility may be increased to $2.0 billion at any time upon the Company’s agreement with its existing or additional lenders. We had $243.4 million outstanding under our revolving credit facility at September 30, 2013 compared to no borrowings on our credit facility at December 31, 2012.  

The interest rate on our Credit Facility is calculated based upon our public debt rating and is currently 200 basis points over LIBOR. Our publicly traded notes are rated BBB- by Standard and Poor’s and we have a long term debt rating of Baa3 by Moody’s. Any downgrades in our public debt ratings could increase our cost of funds under the Credit Facility.

Our Credit Facility contains covenants which impose certain restrictions on us. Under the Credit Facility, we must keep our total debt at or below 60% of our total capital, and must maintain a ratio of EBITDA to interest expense of 3.5 or above. Our Credit Facility’s financial covenants with respect to capitalization percentages exclude hedging activities, pension and other postretirement liabilities as well as the effects of non-cash entries that result from any full cost ceiling impairments occurring after the date of the agreement. At September 30, 2013, our capital structure as determined under our Credit Facility was 30% debt and 70% equity, which excluded hedging activities, pension and other postretirement liabilities, and if applicable, the effect of the non-cash full cost ceiling impairment. We were in compliance with all of the covenants of our Credit Facility at September 30, 2013. 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 may have to decrease our capital investment plans.

In March 2012, we issued $1 billion of 4.10% Senior Notes due 2022 in a private placement. A portion of the net proceeds of the offering were used to repay the amounts outstanding under the Company’s revolving credit facility and the remaining proceeds were used for general corporate purposes.  

At September 30, 2013 and December 31, 2012, our capital structure consisted of 35% debt and 65% equity (exclusive of cash and cash equivalents and restricted cash)  and $18.9 and $62.1million in cash and cash equivalents and restricted cash, respectively.  Equity at September 30, 2013 included an accumulated other comprehensive gain of $72.1 million related to our hedging activities, partially offset by $21.5 million related to our pension and other postretirement liabilities. The amount recorded in equity for our hedging activities is based on current market values for our hedges at September 30, 2013 and does not necessarily reflect the value that we will receive or pay when the hedges are ultimately settled, nor does it take into account revenues to be received associated with the physical delivery of sales volumes hedged.

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Our hedges allow us to ensure a certain level of cash flow to fund our operations.  At September 30, 2013, we had NYMEX commodity price hedges in place on 84.4 Bcf of our remaining targeted 2013 natural gas production and 232.7 Bcf of our expected 2014 natural gas production.  The amount of long-term debt we incur will be largely dependent upon commodity prices and our capital investment plans.

Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. There have been no material changes to our contractual obligations from those disclosed in our 2012 Annual Report on Form 10-K.

Contingent Liabilities and Commitments

In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses requirethe Company to make certain capital investments in New Brunswick of approximately $47 million in the aggregate over athree year period. In order to obtain the licenses, the Company provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate principal amount of $44.5 million Canadian dollars. The promissory notes secure the Company's capital expenditure obligations under the licenses and are returnable tothe Company to the extent the Company performs such obligations. If the Company fails to fully perform, the Minister of Finance may retain a portion of the applicable promissory notes in an amount equal to any deficiency. The Companycommenced its Canada exploration program in 2010 and, as of September 30, 2013 had invested $35.4 million in New Brunswick towards the Company’s commitment. In December 2012, we received two one-year extensions to our exploration license agreements which expire on March 16, 2014 and March 16, 2015, respectively. No liability has beenrecognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of September 30, 2013 and its future investment plans.

Substantially all of our employees are covered by defined pension and postretirement benefit plans. As of September 30, 2013, the Company has contributed $9.0 million to the pension plan and $0.1 million to the postretirement benefit plan, and expects to contribute an additional $3.0 million to the pension plan in 2013.At September 30, 2013, we recognized a liability of $35.3 million as a result of the underfunded status of our pension and other postretirement benefit plans compared to a liability of $33.5 million at December 31, 2012.

We are subject to litigation, claims and proceedings (including with respect to environmental matters) that arise in the ordinary course of business. Management believes, individually or in aggregate, such litigation, claims and proceedings will not have a material adverse impact on our financial position, results of operations, or cash flows, 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, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.  For further information regarding commitments and contingencies, we refer you to Note 11 in the unaudited condensed consolidated financial statements included in this Form 10-Q.

Working Capital

We had negative working capital of $69.8 million at September 30, 2013 and positive working capital of $41.1 million at December 31, 2012. Current assets decreased by $68.9 million during the nine months ended September 30, 2013 primarily due to an $85.0 million decrease in current hedging asset, a $43.2 million decrease in cash, cash equivalents and restricted cash, and a $22.9 million decrease in other current assets. These decreases were partially offset by a $67.1 million increase in accounts receivable and a $15.1 million increase in inventory.  Current liabilities increased by $42.0 million during the nine months ended September 30, 2013 primarily as a result of a $141.8 million increase in accounts payable, and a $31.0 million increase in other current liabilities, offset slightly by a $65.5 million decrease in advances from partners, a $30.2 million decrease in current deferred income taxes, $20.4 million decrease in interest payable, and a $14.7 million decrease in taxes payable.  We maintain access to funds that may be needed to meet capital requirements through our Credit Facility described in “Financing Requirements” above.

Natural Gas in Underground Storage

We record our natural gas stored in inventory that is owned by the E&P segment at the lower of weighted average cost or market. The natural gas in inventory for the E&P segment is used primarily to supplement production in meeting

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the segment’s contractual commitments, especially during periods of colder weather. In determining the lower of cost or market for storage gas, we utilize the natural gas futures market in assessing the price we expect to be able to realize for our natural gas in inventory. A decline in the future market price of natural gas could result in write-downs of our natural gas in underground 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 risk. The Board of Directors has approved our use of financial products for the reduction of 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 our customers and their dispersion across geographic areas. No single customer accounted for greater than 10% of revenues for the nine months ended September 30, 2013.  See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

Interest Rate Risk

At September 30, 2013, we had approximately $1.9 billion of total debt with a weighted average interest rate of 5.03%. Our revolving credit facility has a floating interest rate (2.14% at September 30, 2013).  At September 30, 2013, we had borrowings outstanding of $243.4  million under our Credit Facility.

Interest rate swaps may be used to adjust interest rate exposures when deemed appropriate. At September 30, 2013, the Company had a net derivative asset position of $1.3 million related to interest-rate swaps. A 10% increase or decrease in interest rates would not result in a material increase or decrease in the aggregate fair value of outstanding interest-rate swap agreements. For a summary of the Company’s open interest-rate derivative positions, see Note 7-Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Commodities Risk

We use over-the-counter natural gas and crude oil swap agreements and options to hedge sales of our production and to hedge activity in our Midstream Services 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 funds equal to the amount by which the price of the commodity is below the contracted floor, and a “ceiling” price above which we pay to the counterparty the amount by which the price of the commodity is above the contracted ceiling.

The primary market risks relating 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 commercial banks, investment banks and integrated energy companies which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, given the recent volatility in the financial markets, we cannot be certain that we will not experience such losses in the future.

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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 natural gas production. The table presents the notional amount in Bcf, the weighted average contract prices and the fair value by expected maturity dates. At September 30, 2013, the net fair value of our financial instruments related to natural gas production was a $192.3 million asset.

	Volume (Bcf)	Weighted Average Price to be Swapped ($/MMBtu)		Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)		Weighted Average Basis Differential ($/MMBtu)		Fair value at September 30, 2013 ($ in millions)
Natural Gas (Bcf):
Fixed Price Swaps:
2013	84.4	$	4.68	$	–	$	–	$	–	$	91.5
2014	232.7	$	4.41	$	–	$	–	$	–	$	126.1
Basis Swaps:
2013	6.5	$	–	$	–	$	–	$	0.09	$	0.9
2014	16.7	$	–	$	–	$	–	$	0.05	$	4.7
2015	0.9	$	–	$	–	$	–	$	0.17	$	0.1
Fixed Price Call Options:
2015	199.8	$	–	$	5.09	$	–	$	–	$	(31.0)

At September 30, 2013, our basis swaps did not qualify for hedge accounting treatment. Changes in the fair value of derivatives that do not qualify as cash flow hedges are recorded in gain (loss) on derivatives.  For the nine months ended September 30, 2013, we recorded  a mark to market loss on derivatives of $26.9 million related to fixed price call options that did not qualify for hedge accounting treatment, a mark to market gain on derivatives of $96.6 million related to fixed price swaps not designated for hedge accounting, and a mark to market gain on derivatives of $1.6 million related to the basis swaps that did not qualify for hedge accounting treatment and aloss of $2.2 million related to the change in estimated ineffectiveness of our cash flow hedges. Typically, our hedge ineffectiveness results from changes at the end of a reporting period in the price differentials between the index price of the derivative contract, which is primarily a NYMEX price, and the index price for the point of sale for the cash flow that is being hedged.

Item 4. Controls and Procedures.

Evaluation of  Disclosure 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 Rules 13a-15(e) and 15d 15(e) under the Securities Exchange Act of 1934, as amended (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 level of 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 September 30, 2013 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

In August 2013, the Company implemented an accounting module in its Enterprise Resource Planning (ERP) system. Implementing an accounting module in an ERP system involves significant changes in business processes that management believes will provide several benefits including more standardized and efficient processes throughout the Company. This implementation has resulted in material changes to the Company’s internal controls over financial reporting, as that term is defined Rules 13(a)-15(f) and 15(d)-15(f) under the Exchange Act, for the three months ended

43

September 30, 2013. Therefore, the Company has modified the design, operation and documentation of certain internal control processes and procedures to address the new environment associated with implementation. The system changes were undertaken to integrate systems and consolidate information, and were not undertaken in response to any perceived or actual deficiency in the Company’s internal controls over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

The Company is subject to laws and regulations relating to the protection of the environment. Our 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 effect on our financial position, results of operations, and cash flows.

Tovah Energy

In February 2009, SEPCO was added as a defendant in a Third Amended Petition in the matter of Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al.  In the Sixth Amended Petition, filed in July 2010, in the 273rd District Court in Shelby County, Texas (collectively, the “Sixth Petition”), plaintiff alleged that, in 2005, they provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom.  Among other things, the plaintiff’s allegations in the Sixth Petition included various statutory and common law claims, including, but not limited to claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 2005 and February 2006.  In the Sixth Petition, plaintiff sought actual damages of over $55.0 million as well as other remedies, including special damages and punitive damages of four times the amount of actual damages established at trial.

Immediately before the commencement of the trial in November 2010, plaintiff was permitted, over SEPCO’s objections, to file a Seventh Amended Petition claiming actual damages of $46.0 million and also seeking the equitable remedy of disgorgement of all profits for the misappropriation of trade secrets and the breach of fiduciary duty claims. In December 2010, the jury found in favor of the plaintiff with respect to all of the statutory and common law claims and awarded $11.4 million in compensatory damages. The jury did not, however, award the plaintiff any special, punitive or other damages. In addition, the jury separately determined that SEPCO’s profits for purposes of disgorgement were $381.5 million. This profit determination does not constitute a judgment or an award. The plaintiff’s entitlement to disgorgement of profits as an equitable remedy will be determined by the judge and it is within the judge’s discretion to award none, some or all the amount of profit to the plaintiff.  In December 2010, the plaintiff filed a motion to enter the judgment based on the jury’s verdict.  In February 2011, SEPCO filed a motion for a judgment notwithstanding the verdict and a motion to disregard certain findings.  In March 2011, the plaintiff filed an amended motion for judgment and intervenor filed its motion for judgment seeking not only the monetary damages and the profits determined by the jury but also seeking, as a new remedy, a constructive trust for profits from 143 wells as well as future drilling and sales of properties in the prospect areas.  At the suggestion of the judge, all parties voluntarily agreed to participate in non-binding mediation efforts.  The mediation occurred in April 2011 and was unsuccessful. In June 2011, SEPCO received by mail a letter dated June 2011 from the judge, in which he made certain rulings with respect to the post-verdict motions and responses filed by the parties. In his rulings, the judge denied SEPCO’s motion for judgment, judgment notwithstanding the verdict and to disregard certain findings. Plaintiff’s and intervenor’s claim for a constructive trust was denied but the judge ruled that plaintiff and intervenor shall recover from SEPCO $11.4 million and a reasonable attorney’s fee of 40% of the total damages awarded and are entitled to recover on their claim for disgorgement.  The judge instructed that SEPCO calculate the profit on the designated wells for each respective period.  SEPCO performed the calculation and provided it to the judge in June 2011.  In July 2011, plaintiff and intervenor filed a letter with the court raising objections to the accounting provided by SEPCO, to which SEPCO filed a response in July 2011.  In July 2011, the judge sent a letter to the parties in which he ruled that after reviewing the parties’ respective position letters, he was awarding $23.9 million in disgorgement damages in favor of the plaintiff and intervenor.  In the July 2011 letter, the judge instructed the plaintiff and intervenor to prepare a judgment for his approval prior to July 2011 consistent with his findings in his June 2011 letter and the disgorgement award.  In August 2011, a judgment was entered pursuant to which plaintiff and intervenor are entitled to recover approximately $11.4 million in actual damages and approximately $23.9 million in disgorgement as well as prejudgment interest and attorneys' fees which currently are estimated to be up to $8.9 million and all costs of court of the plaintiff and intervenor.  In September 2011, SEPCO filed a motion for a new trial and in November 2011 filed a notice of appeal. 

44

In November 2011, the court approved SEPCO’s supersedeas bond in the amount of $14.1 million, which stays execution on the judgment pending appeal.  The bond covers the $11.4 million judgment for actual damages, plus $1.3 million in pre-judgment interest, $1.3 million in post-judgment interest (estimating two years for the duration of appeal), and court costs. 

In June 2012, SEPCO filed its appellate brief and, in June 2012, plaintiff and intervenor filed a cross-appellate brief seeking limited remand to reassess the disgorgement determination. The parties filed their responses to the appellate and cross appellate briefs in November 2012.  Oral argument was held before the Tyler Court of Appeals on March 8, 2013.  On July 10, 2013, the Tyler Court of Appeals ordered that (1) the judgment awarding plaintiff and intervenor $23.9 million as disgorgement of illicit gains be reversed and judgment rendered that they take nothing, (2) the award of $11.4 million for actual damages, insofar as it is based on the jury’s findings of breach of fiduciary duty, fraud, breach of contract, and theft of trade secret is reversed and judgment rendered that plaintiff and intervenor take nothing under those theories of recovery, (3) the award of $11.4 million to plaintiff and intervenor as damages for misappropriation of trade secret is affirmed, (4) the case be remanded to the trial court for a determination and award of attorney’s fees for SEPCO as the prevailing party under the Texas Theft Liability Act, and (5) in all other respects, the judgment is affirmed.  On July 25, 2013, SEPCO filed its motion for rehearing with the Tyler Court of Appeals, seeking reversal of every part of plaintiff and intervenor’s recovery, and plaintiff and intervenor filed a court-ordered response.  Plaintiff and intervenor filed their own motion for rehearing, and to date SEPCO has not been ordered to respond.

Based on the Company's understanding and judgment of the facts and merits of this case, including appellate defenses, and after considering the advice of counsel, the Company has determined that, although reasonably possible after exhaustion of all appeals, an adverse final outcome to this lawsuit is not probable.  As such, the Company has not accrued any amounts with respect to this lawsuit.  If the plaintiff and intervenor were to ultimately prevail in the appellate process, the Company currently estimates, based on the judgments to date, that SEPCO’s potential liability would be up to $45.5 million, including interest and attorney’s fees. The Company’s assessment may change in the future due to occurrence of certain events, such as denied appeals, and such re-assessment could lead to the determination that the potential liability is probable and could be material to the Company's results of operations, financial position or cash flows.

Bureau of Land Management

In March 2010, the Company’s subsidiary, SEECO, was served with a subpoena from a federal grand jury in Little Rock, Arkansas.  Based on the documents requested under the subpoena and subsequent discussions described below, the Company believes the grand jury is investigating matters involving approximately 27 horizontal wells operated by SEECO in Arkansas, including whether appropriate leases or permits were obtained therefore and whether royalties and other production attributable to federal lands have been properly accounted for and paid.  The Company believes it has fully complied with all requests related to the federal subpoena and delivered its affidavit to that effect. The Company and representatives of the Bureau of Land Management and the U.S. Attorney have had discussions since the production of the documents pursuant to the subpoena.  In January 2011, the Company voluntarily produced additional materials informally requested by the government arising from these discussions.  In September 2013, the U.S. Attorney’s Office requested additional information regarding this matter.  Although, to the Company’s knowledge, no proceeding in this matter has been initiated against SEECO, the Company cannot predict whether or when one might be initiated. The Company intends to fully comply with any further requests and to cooperate with any related investigation. No assurance can be made as to the time or resources that will need to be devoted to this inquiry or the impact of the final outcome of the discussions or any related proceeding.

45

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 2012 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. MINE SAFETY DISCLOSURES.

Our sand mining operations, in support of our E&P business, are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Form 10-Q.

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.

(95.1)Mine Safety Disclosure.

(101.INS)Interactive Data File Instance Document.

(101.SCH)Interactive Data File Schema Document.

(101.CAL)Interactive Data File Calculation Linkbase Document.

(101.LAB)Interactive Data File Label Linkbase Document.

(101.PRE)Interactive Data File Presentation Linkbase Document.

(101.DEF)Interactive Data File Definition Linkbase Document.

46

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:	October 31, 2013	/s/ R. CRAIG OWEN
		R. Craig Owen
		Senior Vice President
		and Chief Financial Officer

47

EX-31

Exhibit 31.1

CERTIFICATION

I, Steve Mueller, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Southwestern Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
		(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
	5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
		(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	October 31, 2013		/s/ STEVE MUELLER
				Steve Mueller
				President and Chief Executive Officer

EX-31

Exhibit 31.2

CERTIFICATION

I, R. Craig Owen, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Southwestern Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
		(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
	5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
		(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	October 31, 2013		/s/ R. CRAIG OWEN
				R. Craig Owen
				Senior Vice President and Chief Financial Officer

EX-32

Exhibit 32.1

CERTIFICATION
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

          Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), each of the undersigned officers of Southwestern Energy Company, a Delaware corporation (the "Company"), does hereby certify that:

          The Quarterly Report on Form 10-Q for the quarter ended September 30, 2013 (the "Form 10-Q") of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:      October 31, 2013	/s/ STEVE MUELLER
	Steve Mueller
	President and Chief Executive Officer
Dated:      October 31, 2013	/s/ R. CRAIG OWEN
	R. Craig Owen
	Senior Vice President and Chief Financial Officer

EX-95

EXHIBIT 95.1

Mine Safety Disclosure

Under the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), each operator of a mine is required to include certain mine safety results in its periodic reports filed with the U.S. Securities and Exchange Commission (“SEC”). Our mining operations are subject to regulation by the federal Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977 (“Mine Act”). Below, we present the following items regarding certain mining safety and health matters for the three months ended September 30, 2013:  

• total number of violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA;

• total number of orders issued under section 104(b) of the Mine Act, which covers violations that had previously been cited under section 104(a) that, upon follow-up inspection by MSHA, are found not to have been totally abated within the prescribed time period, which results in the issuance of an order requiring the mine operator to immediately withdraw all persons (except certain authorized persons) from the mine;

• total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of the Mine Act;

• total number of flagrant violations (i.e., reckless or repeated failure to make reasonable efforts to eliminate a known violation of a mandatory health or safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury) under section 110(b)(2) of the Mine Act;

• total number of imminent danger orders (i.e., the existence of any condition or practice in a mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated) issued under section 107(a) of the Mine Act;

• total dollar value of proposed assessments from MSHA under the Mine Act;

• total number of mining-related fatalities; and

• total number of pending legal actions before the Federal Mine Safety and Health Review Commission involving such mine.

Southwestern Energy Company
Mine Safety Disclosure
Three Months Ended September 30, 2013
(Unaudited)
(Whole dollars)

			Section 104(d) Citations and Orders					Received Notice of Potential to Have Pattern Under Section 104(e)
	Section 104 S&S Citations	Section 104(b) Orders		Section 110(b)(2) Violations	Section 107(a) Orders	Total Dollar Value of Proposed MSHA Assessments(2)	Total Number of Mining Related  Fatalities		Legal Actions Pending as of the Last Day of the Periods	Legal Actions Initiated During Period
Operation(1)											Legal Actions Resolved During Period
DeSoto Sand, LLC	0	0	0	0	0	$0	0	0	0	0	0
Total						$0

(1)

The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools, and preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine.

(2)

Amounts included are the total dollar value of proposed or outstanding assessments received from MSHA on or before September 30, 2013 regardless of whether the assessment has been challenged or appealed, for alleged violations occurring during the three month period ended September 30, 2013.

In addition, as required by the reporting requirements regarding mine safety included in §1503(a)(2) of the Dodd-Frank Act, the following is a list for the three months ended September 30, 2013, of each mine of which we or a subsidiary of ours is an operator, that has received written notice from MSHA of:

(a) a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under §104(e) of the Mine Act:           None

(b) the potential to have such a pattern:           None

Citations and orders can be contested and appealed, and as part of that process, are sometimes reduced in severity and amount, and are sometimes dismissed. The number of citations, orders, and proposed assessments vary by inspector and also vary depending on the size and type of the operation.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2013

Fair Value Measurements [Abstract]

Fair Value Measurements

(9) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Company’s financial instruments as of September 30, 2013 and December 31, 2012 were as follows:

	September 30,				December 31,
	2013				2012
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in thousands)
Cash and cash equivalents	$	18,950	$	18,950	$	53,583	$	53,583
Restricted cash	$	–	$	–	$	8,542	$	8,542
Unsecured revolving credit facility	$	243,400	$	243,400	$	–	$	–
Senior notes	$	1,668,965	$	1,807,234	$	1,669,473	$	1,917,005
Derivative instruments	$	193,539	$	193,539	$	287,878	$	287,878

The carrying values of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, other current assets and current liabilities on the unaudited condensed consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

Debt: The fair values of the Company’s senior notes were based on the market for the Company’s publicly-traded debt as determined based on yield of the Company’s 7.5% Senior Notes due 2018, which was 2.8% at September  30, 2013 and 2.6% at December 31, 2012, and its 4.10% Senior Notes due 2022, which was 4.0% at September  30, 2013. The carrying value of the borrowings under the Company’s unsecured revolving credit facility at September  30, 2013, approximate fair value because the interest rate is variable and reflective of market rates.  The Company considers the fair value of its debt to be a Level 2 measurement on the fair value hierarchy. 

Derivative Instruments: The fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

Level 1 valuations - Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

Level 2 valuations - Consist of quoted market information for the calculation of fair market value.

Level 3 valuations - Consist of internal estimates and have the lowest priority.

Pursuant to GAAP, the Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s Level 2 fair value measurements include fixed-price swaps and are estimated using internal discounted cash flow calculations using the NYMEX futures index.The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of September 30, 2013 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate ("LIBOR") yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy. The Company’s Level 3 fair value measurements include fixed price call options and basis swaps. The Company’s fixed price call options are valued using the Black-Scholes model, an industry standard option valuation model, and takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness.  The Company’s basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves. 

The accounting group, reporting to the Vice President and Controller, is responsible for determining the Company’s Level 3 fair value measurements.  Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, are obtained from a third-party pricing source, with independent verification of most significant inputs on a monthly basis. An increase (decrease) in volatility would resultin an increase (decrease) in fair value measurement, respectively.

Assets and liabilities measured at fair value on a recurring basis are summarized below (in thousands):

	September 30, 2013
	Fair Value Measurements Using:
	Quoted Prices		Significant
	in Active		Other		Significant
	Markets		Observable Inputs		Unobservable Inputs		Assets (Liabilities)
	(Level 1)		(Level 2)		(Level 3)		at Fair Value
Derivative assets	$	–	$	223,394	$	5,783	$	229,177
Derivative liabilities		–		(4,494)		(31,144)		(35,638)
Total	$	–	$	218,900	$	(25,361)	$	193,539
	December 31, 2012
	Fair Value Measurements Using:
	Quoted Prices		Significant
	in Active		Other		Significant
	Markets		Observable Inputs		Unobservable Inputs		Assets (Liabilities)
	(Level 1)		(Level 2)		(Level 3)		at Fair Value
Derivative assets	$	–	$	287,993	$	4,151	$	292,144
Derivative liabilities		–		–		(4,266)		(4,266)
Total	$	–	$	287,993	$	(115)	$	287,878

The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three-and nine-month periods ended September  30, 2013 and September  30, 2012. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect the assumptions a reasonable marketplace participant would have used at September  30, 2013 and September  30, 2012.

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Balance at beginning of period	$	(27,958)	$	106,222	$	(115)	$	182,119
Total gains (losses):
Included in earnings		4,617		53,465		(22,131)		177,201
Included in other comprehensive income		–		(57,614)		–		(135,055)
Purchases, issuances, and settlements:
Purchases		–		–		–		–
Issuances		–		–		–		–
Settlements		(2,020)		(55,112)		(3,115)		(177,304)
Transfers into/out of Level 3		–		–		–		–
Balance at end of period	$	(25,361)	$	46,961	$	(25,361)	$	46,961
Change in gains (losses) included in earnings relating to derivatives still held as of September 30	$	2,597	$	(1,647)	$	(25,246)	$	(103)

XML

Debt (Narrative) (Details) (USD $)	1 Months Ended			9 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Feb. 28, 2011	Sep. 30, 2013	Sep. 30, 2013 4.10% Senior Notes Due 2022 [Member]	Dec. 31, 2012 4.10% Senior Notes Due 2022 [Member]	Sep. 30, 2013 Credit Facility [Member]	Feb. 28, 2011 Credit Facility [Member]
Debt Instrument [Line Items]
Senior Notes					$ 1,000,000,000	$ 1,000,000,000
Debt instrument, interest rate, stated percentage					4.10%
Senior notes redemption date				Feb. 01, 2016
Duration of assumed year, days	360 days
Duration of assumed month, days		30 days
Company exhanged Private Notes for Exchange Notes				999,500,000
Basis Points							200
Unsecured revolving credit facility, borrowing capacity			$ 1,500,000,000					$ 2,000,000,000
Debt percentage of capital structure			60.00%
EBITDA to Interest Expense Ratio			3.5

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Settlements tax	$ (37.3)	$ (62.2)	$ (87.3)	$ (202.6)
Ineffectiveness tax	0.6	0.2	0.9	(0.8)
Change in fair value of derivative instruments tax	5.0	(22.1)	19.7	62.7
Amortization of prior service cost included in net periodic pension cost tax	$ 0.2	$ 0.2	$ 0.5	$ 0.5

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Acquisitions And Divestitures

9 Months Ended

Sep. 30, 2013

Acquisitions And Divestitures [Abstract]

Acquisitions And Divestitures

(2) ACQUISITIONS AND DIVESTITURES

In April 2013, the Company entered into a definitive purchase agreement to acquire natural gas properties located in Pennsylvania prospective for the Marcellus Shale for approximately $93.0 million, subject to closing conditions.  The Company utilized its revolving credit facility to finance the acquisition.  The Company closed on the acquisition during the second quarter of 2013 and accounted for it as an asset acquisition.

In May 2012, the Company sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $166.0 million.  The assets included in the sale represented all of the Company’s interests and related assets in the Overton Field in Smith County. The net production from the sold assets was approximately 24.0 MMcfe per day as of the closing date and the associated net proved reserves were approximately 143.0 Bcfe at December 31, 2011. 

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New Accounting Pronouncements Adopted

9 Months Ended

Sep. 30, 2013

New Accounting Pronouncements Adopted [Abstract]

New Accounting Pronouncements Adopted

(16) NEW ACCOUNTING PRONOUNCEMENTS ADOPTED

In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“Update 2013-02”), which finalizes  proposed ASU No. 2012-240, and seeks to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. Update 2013-02 replaces the presentation requirements in ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, and ASU No. 2011-12, ComprehensiveIncome (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out ofAccumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. Update 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respectiveline items in net income if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income. For public entities, Update 2013-02 is effective prospectively for reporting periods beginning after December15, 2012, with early adoption permitted. The implementation of the disclosure requirement did not have amaterial impact on the Company’s consolidated results of operations, financial position or cash flows. 

In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”), which finalizes Proposed ASU No.2012-250 and clarifies the scope of transactions that are subject to disclosures concerning offsetting. Update 2013-01 addresses implementation issues regarding the scope of ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures aboutOffsetting Assets and Liabilities, issued in December 2011. Update 2013-01 clarifies that the scope of the disclosures underU.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowingand securities lending transactions that are offset either in accordance with FASB ASC Section 210-20-45, Balance Sheet—Offsetting—Other Presentation Matters, or FASB ASC Section 815-10-45, Derivatives and Hedging—Overall—Other Presentation Matters, or are subject to a master netting arrangement or similar agreement. Update 2013-01 requiresan entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to providethe required disclosures retrospectively for all comparative periods presented. The implementation of the disclosure requirement did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

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Supplemental Disclosures of Cash Flow Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Supplemental Disclosures of Cash Flow Information [Abstract]
Cash paid for interest	$ 44,745	$ 45,667	$ 94,963	$ 75,487
Cash paid for income taxes	1,330	400	18,636	468
Noncash property changes	$ (11,745)	$ (55,729)	$ 34,437	$ (34,940)

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Debt

9 Months Ended

Sep. 30, 2013

Debt [Abstract]

Debt

(10) DEBT

The components of debt as of September  30, 2013 and December 31, 2012 consisted of the following:

	September 30,		December 31,
	2013		2012
	(in thousands)
Short-term debt:
7.15% Senior Notes due 2018	$	1,200	$	1,200
Total short-term debt		1,200		1,200
Long-term debt:
Variable rate (2.14% at September 30, 2013) unsecured revolving credit facility		243,400		–
7.5% Senior Notes due 2018		600,000		600,000
7.35% Senior Notes due 2017		15,000		15,000
7.125% Senior Notes due 2017		25,000		25,000
7.15% Senior Notes due 2018		28,800		29,400
4.10% Senior Notes due 2022		1,000,000		1,000,000
Unamortized discount		(1,035)		(1,127)
Total long-term debt		1,911,165		1,668,273
Total debt	$	1,912,365	$	1,669,473

Issuance of Senior Notes and Subsidiary Guarantees 

The indentures governing the Company’s senior notes contain covenants that, among other things, restrict the ability of the Company and/or its subsidiaries’ ability to incur liens, to engage in sale and leaseback transactions and to merge, consolidate, or sell assets.  All of the Company’s senior notes are currently guaranteed by its subsidiaries, SEECO, Inc. (“SEECO”), Southwestern Energy Production Company (“SEPCO”) and Southwestern Energy Services Company (“SES”).  If no default or event of default has occurred and is continuing, these guarantees will be released (i) automatically upon any sale, exchange, or transfer of all of the Company’s equity interests in the guarantor; (ii) automatically upon the liquidation and dissolution of a guarantor; (iii) following delivery of notice to the trustee of the release of the guarantor of its obligations under the Company’s credit facility; and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the notes.

In December 2012, the Company completed its offer to exchange up to $1.0 billion aggregate principal amount of its 4.10% Senior Notes due 2022 (the “Exchange Notes”, which were registered under the Securities Act of 1933, as amended (the “Act”), for any and all of its outstanding 4.10% Senior Notes due 2022, which were issued in a private placement in March 2012 (the “PrivateNotes”). The Exchange Notes have substantially identical terms to the Private Notes, except that the offering of the Exchange Notes was registered under the Act, and the Exchange Notes are not subject to any transfer restrictions. The Company exchanged $999,500,000 of Private Notes for Exchange Notes, and has no further obligations under the relatedregistration rights agreement.

Please refer to Note 17, “Condensed Consolidating Financial Information” in this Form 10-Q for additional information.

Credit Facility 

In February 2011, the Company amended and restated its unsecured revolving credit facility, increasing the borrowing capacity to $1.5 billion and extending the maturity date to February 2016 (“Credit Facility”).  The amount available under the Credit Facility may be increased to $2.0 billion at any time upon the Company’s agreement with its existing or additional lenders. The interest rate on the Credit Facility is calculated based upon our debt rating and is currently 200 basis points over the current London Interbank Offered Rate (LIBOR) and was 200 basis points over LIBOR at September  30, 2013. The Credit Facility is guaranteed by the Company’s subsidiary, SEECO and requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied.  The facility 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 and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of 3.5 or above. The terms of the Credit Facility also include covenants that restrict the ability of the Company and its material subsidiaries to merge, consolidate or sell all or substantially all of their assets, restrict the ability of the Company and its subsidiaries to incur liens and restrict the ability of the Company’s subsidiaries to incur indebtedness.  As of September  30, 2013, the Company was in compliance with the covenants of its debt agreements.  While the Company believes all of the lenders under the Credit Facility have the ability to provide funds, it cannot predict whether each will be able to meet its obligation under the facility.

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Reclassifications From Accumulated Other Comprehensive Income (Amounts Reclassified From AOCI Into Earnings) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Gas sales	$ 617,427		$ 497,219		$ 1,736,101		$ 1,394,745
General and administrative expenses	50,969		36,121		135,754		129,879
Income (loss) before income taxes	310,016		(82,206)		932,470		(561,962)
Provision (benefit) for income taxes	124,149	[1]	(28,153)	[1]	373,457	[1]	(210,481)	[1]
Net income (loss)	185,867		(54,053)		559,013		(351,481)
Parent [Member]
Income (loss) before income taxes	185,867		(54,053)		559,013		(351,481)
Net income (loss)	185,867		(54,053)		559,013		(351,481)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Net income (loss)					128,832
Reclassification out of Accumulated Other Comprehensive Income [Member] | Gains and Losses on Cash Flow Hedges [Member]
Income (loss) before income taxes					216,053
Provision (benefit) for income taxes					86,421
Net income (loss)					129,632
Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension and Other Postretirement [Member]
General and administrative expenses					(1,334)
Income (loss) before income taxes					(1,334)
Provision (benefit) for income taxes					(534)
Net income (loss)					(800)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Settlements [Member] | Gains and Losses on Cash Flow Hedges [Member]
Gas sales					218,236
Reclassification out of Accumulated Other Comprehensive Income [Member] | Ineffectiveness [Member] | Gains and Losses on Cash Flow Hedges [Member]
Gas sales					$ (2,183)

[1] Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

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Pension Plan and Other Postretirement Benefits (Details) (USD $)			3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Pension Benefits [Member]	Sep. 30, 2012 Pension Benefits [Member]	Sep. 30, 2013 Pension Benefits [Member]	Sep. 30, 2012 Pension Benefits [Member]	Sep. 30, 2013 Other Postretirement Benefits [Member]	Sep. 30, 2012 Other Postretirement Benefits [Member]	Sep. 30, 2013 Other Postretirement Benefits [Member]	Sep. 30, 2012 Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost			$ 3,447,000	$ 2,736,000	$ 10,342,000	$ 8,207,000	$ 574,000	$ 458,000	$ 1,722,000	$ 1,374,000
Interest cost			1,026,000	1,013,000	3,078,000	3,038,000	111,000	100,000	331,000	299,000
Expected return on plan assets			(1,534,000)	(1,356,000)	(4,602,000)	(4,069,000)
Amortization of transition obligation								16,000		48,000
Amortization of prior service cost			25,000	71,000	77,000	214,000	4,000	4,000	11,000	11,000
Amortization of net loss			386,000	305,000	1,156,000	915,000	30,000	23,000	90,000	69,000
Net periodic benefit cost			3,350,000	2,769,000	10,051,000	8,305,000	719,000	601,000	2,154,000	1,801,000
Defined benefit plan, Expected employer contributions			3,000,000		3,000,000
Employer contributions					$ 9,000,000				$ 100,000
Common stock purchased under non-qualified plan, Treasury stock, Shares	14,625	64,715

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Prepaid Expenses (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Prepaid Expenses [Abstract]
Prepaid drilling costs	$ 15,622	$ 30,101
Prepaid insurance	9,536	9,507
Total	$ 25,158	$ 39,608

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Share

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
Net income (loss) (in thousands)	$	185,867	$	(54,053)	$	559,013	$	(351,481)
Number of common shares:
Weighted average outstanding		350,517,337		348,649,630		350,334,634		348,272,192
Issued upon assumed exercise of outstanding stock options		373,152		–		442,678		–
Effect of issuance of nonvested restricted common stock		332,341		–		237,662		–
Weighted average and potential dilutive outstanding(1)		351,222,830		348,649,630		351,014,974		348,272,192
Earnings (loss) per share:
Basic	$	0.53	$	(0.16)	$	1.60	$	(1.01)
Diluted	$	0.53	$	(0.16)	$	1.59	$	(1.01)

(1) Options for 1,550,838shares and 15,703 shares of restricted stock were excluded from the calculation for the three months ended September 30, 2013 because they would have had an antidilutive effect.  Due to the net loss for the three months ended September 30, 2012, options for 1,664,232 shares and 560,848 shares of restricted stock were antidilutive and excluded from the calculation.  Options for1,848,566 shares and 169,261 shares of restricted stock were excluded from the calculation for the nine months ended September 30, 2013 because they would have had an antidilutive effect.  Due to the net loss for the nine months ended September 30, 2012, options for 1,685,398 shares and 580,227 shares of restricted stock were antidilutive and excluded from the calculation.

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Prepaid Expenses (Tables)

9 Months Ended

Sep. 30, 2013

Prepaid Expenses [Abstract]

Prepaid Expenses Table

	September 30,		December 31,
	2013		2012
		(in thousands)
Prepaid drilling costs	$	15,622	$	30,101
Prepaid insurance		9,536		9,507
Total	$	25,158	$	39,608

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Derivatives and Risk Management (Before Tax Effect of Basis Swaps that do not Qualify for Hedge Accounting Consolidated Statements of Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Basis Swaps [Member]
Derivative [Line Items]
Mark to Market Gain (Loss) on Derivatives Recognized in Earnings	$ (5,279)	$ (1,275)	$ 1,606	$ (270)
Mark to Market Gain (Loss) on Derivatives, Settled Recognized in Earnings	2,020	624	3,115	1,773
Fixed Price Call Options [Member]
Derivative [Line Items]
Mark to Market Gain (Loss) on Derivatives Recognized in Earnings	7,876		(26,852)
Fixed Price Swaps [Member]
Derivative [Line Items]
Mark to Market Gain (Loss) on Derivatives Recognized in Earnings	8,819		96,606
Interest Rate Swaps [Member]
Derivative [Line Items]
Mark to Market Gain (Loss) on Derivatives Recognized in Earnings	(1,312)		1,304
Fair Value Swaps [Member]
Derivative [Line Items]
Mark to Market Gain (Loss) on Derivatives Recognized in Earnings		136		1,162
Mark to Market Gain (Loss) on Derivatives, Settled Recognized in Earnings		$ (5,364)		$ (13,258)

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2013

Stock-Based Compensation [Abstract]

Employee Stock-Based Compensation Costs

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Stock-based compensation cost – expensed	$	2,921	$	2,677	$	8,883	$	8,226
Stock-based compensation cost – capitalized	$	2,809	$	2,482	$	8,543	$	7,788

Summary of Stock Option Activity, Options Outstanding

		Weighted
		Average
	Number	Exercise
	of Options	Price
Outstanding at December 31, 2012	3,649,520	$	29.84
Granted	26,010		38.76
Exercised	(705,991)		9.60
Forfeited or expired	(55,756)		37.47
Outstanding at September 30, 2013	2,913,783		34.68
Exercisable at September 30, 2013	1,699,151	$	34.06

Summary of Restricted Stock Activity and Unvested Shares

		Weighted
		Average
	Number	Grant Date
	of Shares	Fair Value
Unvested shares at December 31, 2012	1,117,515	$	35.64
Granted	32,346		37.53
Vested	(30,884)		36.19
Forfeited	(58,560)		35.77
Unvested shares at September 30, 2013	1,060,417	$	35.67

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Natural Gas and Oil Properties (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended			9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Jun. 30, 2012	Sep. 30, 2013 West Texas Intermediate Oil [Member]	Sep. 30, 2012 West Texas Intermediate Oil [Member]	Sep. 30, 2013 Henry Hub Natural Gas [Member]	Sep. 30, 2012 Henry Hub Natural Gas [Member]
Discount rate of natural gas and oil reserves	10.00%
Period of time needed to calculate ceiling value of reserves	12 months
Full cost ceiling test, Price				91.56	91.48	3.60	2.83
Cash flow hedges impact on ceiling value	$ 79.2	$ 330.6
Net capitalized costs of our natural gas and oil properties in excess of ceiling value		$ 185.7	$ 496.4

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Fair Value Measurements (Narrative) (Details)	Sep. 30, 2013	Dec. 31, 2012
7.5% Senior Notes due 2018 [Member]
Debt instrument , interest rate percentage	7.50%
Yield, Publicly-traded debt market	2.80%	2.60%
4.10% Senior Notes Due 2022 [Member]
Debt instrument , interest rate percentage	4.10%
Yield, Publicly-traded debt market	4.00%

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Debt (Tables)

9 Months Ended

Sep. 30, 2013

Debt [Abstract]

Components Of Debt

	September 30,		December 31,
	2013		2012
	(in thousands)
Short-term debt:
7.15% Senior Notes due 2018	$	1,200	$	1,200
Total short-term debt		1,200		1,200
Long-term debt:
Variable rate (2.14% at September 30, 2013) unsecured revolving credit facility		243,400		–
7.5% Senior Notes due 2018		600,000		600,000
7.35% Senior Notes due 2017		15,000		15,000
7.125% Senior Notes due 2017		25,000		25,000
7.15% Senior Notes due 2018		28,800		29,400
4.10% Senior Notes due 2022		1,000,000		1,000,000
Unamortized discount		(1,035)		(1,127)
Total long-term debt		1,911,165		1,668,273
Total debt	$	1,912,365	$	1,669,473

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Condensed Consolidating Financial Information (Condensed Consolidating Statements of Cash Flows) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Net cash provided by (used in) operating activities	$ 1,377,518	$ 1,192,477
Capital investments	(1,727,543)	(1,623,751)
Proceeds from sale of property and equipment	3,081	(201,161)
Transfers to restricted cash		(167,774)
Transfers from restricted cash	8,542	40,700
Other	4,700	5,239
Net cash used in investing activities	(1,711,220)	(1,544,425)
Payments on current portion of long-term debt	(600)	(600)
Payments on revolving long-term debt	(2,134,550)	(1,774,000)
Borrowing under revolving long-term debt	2,377,950	1,129,000
Proceeds from issuance of long-term debt		998,780
Other items	55,857	1,711
Net cash provided by (used in) financing activities	298,657	354,891
Effect of exchange rate changes on cash	412	(10)
Increase (decrease) in cash and cash equivalents	(34,633)	2,933
Cash and cash equivalents at beginning of year	53,583	15,627
Cash and cash equivalents at end of period	18,950	18,560
Parent [Member]
Net cash provided by (used in) operating activities	(32,502)	(55,324)
Capital investments	(29,227)	(38,946)
Proceeds from sale of property and equipment		(144)
Transfers to restricted cash		(167,774)
Transfers from restricted cash	8,542	40,700
Other	(74)	16,575
Net cash used in investing activities	(20,759)	(149,301)
Intercompany activities	(274,931)	(148,027)
Payments on current portion of long-term debt	(600)	(600)
Payments on revolving long-term debt	(2,134,550)	(1,774,000)
Borrowing under revolving long-term debt	2,377,950	1,129,000
Proceeds from issuance of long-term debt		998,780
Other items	55,857	1,722
Net cash provided by (used in) financing activities	23,726	206,875
Increase (decrease) in cash and cash equivalents	(29,535)	2,250
Cash and cash equivalents at beginning of year	47,491	14,711
Cash and cash equivalents at end of period	17,956	16,961
Guarantors [Member]
Net cash provided by (used in) operating activities	1,062,133	915,885
Capital investments	(1,530,760)	(1,452,061)
Proceeds from sale of property and equipment	210	(169,149)
Other	(1,685)	(24,340)
Net cash used in investing activities	(1,532,235)	(1,307,252)
Intercompany activities	464,114	392,732
Net cash provided by (used in) financing activities	464,114	392,732
Increase (decrease) in cash and cash equivalents	(5,988)	1,365
Cash and cash equivalents at beginning of year	5,988
Cash and cash equivalents at end of period		1,365
Non-Guarantors [Member]
Net cash provided by (used in) operating activities	347,887	331,916
Capital investments	(167,556)	(132,744)
Proceeds from sale of property and equipment	2,871	(31,868)
Other	6,459	13,004
Net cash used in investing activities	(158,226)	(87,872)
Intercompany activities	(189,183)	(244,705)
Other items		(11)
Net cash provided by (used in) financing activities	(189,183)	(244,716)
Effect of exchange rate changes on cash	412	(10)
Increase (decrease) in cash and cash equivalents	890	(682)
Cash and cash equivalents at beginning of year	104	916
Cash and cash equivalents at end of period	$ 994	$ 234

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Condensed Consolidating Financial Information (Condensed Consolidating Balance Sheets) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012	Sep. 30, 2012		Dec. 31, 2011
Cash and cash equivalents	$ 18,950		$ 53,583	$ 18,560		$ 15,627
Restricted cash			8,542
Accounts receivable	444,723		377,638
Inventories	43,225		28,141
Other current assets	233,077		341,008
Total current assets	739,975		808,912
Property and equipment	14,823,553		13,028,439
Less: Accumulated depreciation, depletion and amortization	(7,786,820)		(7,191,463)
Total property and equipment, net	7,036,733		5,836,976
Other assets	117,680		91,639
TOTAL ASSETS	7,894,388	[1]	6,737,527	7,356,562	[1],[2]
Accounts payable	663,726		556,980
Other current liabilities	146,085		210,791
Total current liabilities	809,811		767,771
Long-term debt	1,911,165		1,668,273
Deferred income taxes	1,388,833		1,049,138
Other liabilities	264,590		216,473
Total liabilities	4,374,399		3,701,655
Commitments and Contingencies
Total Equity	3,519,989		3,035,872
TOTAL LIABILITIES AND EQUITY	7,894,388		6,737,527
Parent [Member]
Cash and cash equivalents	17,956		47,491	16,961		14,711
Restricted cash			8,542
Accounts receivable	3,114		2,677
Inventories			2
Other current assets	13,893		7,461
Total current assets	34,963		66,173
Intercompany receivables	2,548,900		2,259,713
Property and equipment	236,324		220,837
Less: Accumulated depreciation, depletion and amortization	(102,706)		(82,178)
Total property and equipment, net	133,618		138,659
Investments in subsidiaries (equity method)	2,788,544		2,309,947
Other assets	32,103		35,136
TOTAL ASSETS	5,538,128		4,809,628
Accounts payable	147,265		140,367
Other current liabilities	3,759		3,758
Total current liabilities	151,024		144,125
Long-term debt	1,911,165		1,668,273
Deferred income taxes	(115,675)		(116,207)
Other liabilities	71,625		77,565
Total liabilities	2,018,139		1,773,756
Total Equity	3,519,989		3,035,872
TOTAL LIABILITIES AND EQUITY	5,538,128		4,809,628
Guarantors [Member]
Cash and cash equivalents			5,988	1,365
Accounts receivable	423,418		353,607
Inventories	40,906		26,975
Other current assets	212,154		321,396
Total current assets	676,478		707,966
Intercompany receivables	57		42
Property and equipment	13,079,991		11,491,222
Less: Accumulated depreciation, depletion and amortization	(7,455,008)		(6,923,106)
Total property and equipment, net	5,624,983		4,568,116
Other assets	69,697		42,247
TOTAL ASSETS	6,371,215		5,318,371
Accounts payable	432,089		375,604
Other current liabilities	141,307		205,623
Total current liabilities	573,396		581,227
Intercompany payables	2,603,488		2,108,360
Deferred income taxes	1,077,055		820,279
Other liabilities	178,703		124,505
Total liabilities	4,432,642		3,634,371
Total Equity	1,938,573		1,684,000
TOTAL LIABILITIES AND EQUITY	6,371,215		5,318,371
Non-Guarantors [Member]
Cash and cash equivalents	994		104	234		916
Accounts receivable	18,191		21,354
Inventories	2,319		1,164
Other current assets	7,030		12,151
Total current assets	28,534		34,773
Intercompany receivables	54,531		27,077
Property and equipment	1,507,238		1,316,380
Less: Accumulated depreciation, depletion and amortization	(229,106)		(186,179)
Total property and equipment, net	1,278,132		1,130,201
Other assets	15,880		14,256
TOTAL ASSETS	1,377,077		1,206,307
Accounts payable	84,372		41,009
Other current liabilities	1,019		1,410
Total current liabilities	85,391		42,419
Intercompany payables			178,472
Deferred income taxes	427,453		345,066
Other liabilities	14,262		14,403
Total liabilities	527,106		580,360
Total Equity	849,971		625,947
TOTAL LIABILITIES AND EQUITY	1,377,077		1,206,307
Eliminations [Member]
Intercompany receivables	(2,603,488)		(2,286,832)
Investments in subsidiaries (equity method)	(2,788,544)		(2,309,947)
TOTAL ASSETS	(5,392,032)		(4,596,779)
Intercompany payables	(2,603,488)		(2,286,832)
Total liabilities	(2,603,488)		(2,286,832)
Total Equity	(2,788,544)		(2,309,947)
TOTAL LIABILITIES AND EQUITY	$ (5,392,032)		$ (4,596,779)

[1] Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

[2] Capital investments includes decreases of $14.6 million and $56.2 million for the three-month periods ended September 30, 2013 and 2012, respectively, and increase of $25.8 million and decrease of $40.7 million for the nine-month periods ended September 30, 2013 and 2012, respectively, relating to the change in accrued expenditures between periods.

XML

Derivatives and Risk Management (Balance Sheet Classification) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative assets	$ 229,177	$ 292,144
Derivative liabilities	35,638	4,266
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative assets	120,990	287,993
Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Hedging Asset [Member]
Derivative [Line Items]
Derivative assets	115,039	279,443
Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Other Assets
Derivative [Line Items]
Derivative assets	5,951	8,550
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative assets	108,187	4,151
Derivative liabilities	35,638	4,266
Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Hedging Asset [Member]
Derivative [Line Items]
Derivative assets	77,504
Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Other Assets
Derivative [Line Items]
Derivative assets	19,103
Not Designated as Hedging Instrument [Member] | Fixed Price Call Options [Member] | Long-Term Hedging Liability [Member]
Derivative [Line Items]
Derivative liabilities	30,980	4,128
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Hedging Asset [Member]
Derivative [Line Items]
Derivative assets	5,104	3,250
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Other Assets
Derivative [Line Items]
Derivative assets	679	901
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Hedging Liability [Member]
Derivative [Line Items]
Derivative liabilities	164	138
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Other Assets
Derivative [Line Items]
Derivative assets	5,797
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Hedging Liability [Member]
Derivative [Line Items]
Derivative liabilities	912
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Long-Term Hedging Liability [Member]
Derivative [Line Items]
Derivative liabilities	$ 3,582

XML

Condensed Consolidating Financial Information

9 Months Ended

Sep. 30, 2013

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

(17) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Company is providing condensed consolidating financial information for SEECO, SEPCO and SES, its subsidiaries that are currently guarantors of the Company’s registered public debt, and for its other subsidiaries that are not guarantors of such debt. These wholly owned subsidiary guarantors have jointly and severally, fully and unconditionally guaranteed the Company’s 7.35% Senior Notes, 7.125% Senior Notes, and 4.10% Senior Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated to any future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors.

The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees. The following condensed consolidating financial information summarizes the results of operations, financial position and cash flows for the Company’s guarantor and non-guarantor subsidiaries.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Unaudited)
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
	(in thousands)
Three months ended September 30, 2013:
Operating revenues	$	–	$	823,112	$	130,998	$	(85,744)	$	868,366
Operating costs and expenses:
Gas purchases – midstream services		–		195,437		–		(166)		195,271
Operating expenses		–		140,400		35,425		(85,556)		90,269
General and administrative expenses		–		43,836		7,155		(22)		50,969
Depreciation, depletion and amortization		–		191,972		12,962		–		204,934
Taxes, other than income taxes		–		15,348		2,346		–		17,694
Total operating costs and expenses		–		586,993		57,888		(85,744)		559,137
Operating income		–		236,119		73,110		–		309,229
Other income (loss), net		–		145		(464)		–		(319)
Gain on derivatives		–		10,251		1,873		–		12,124
Equity in earnings of subsidiaries		185,867		–		–		(185,867)		–
Interest expense		–		9,359		1,659		–		11,018
Income before income taxes		185,867		237,156		72,860		(185,867)		310,016
Provision for income taxes		–		91,466		32,683		–		124,149
Net income		185,867		145,690		40,177		(185,867)		185,867
Comprehensive income	$	139,179	$	98,102	$	40,811	$	(138,913)	$	139,179
Three months ended September 30, 2012:
Operating revenues	$	–	$	647,961	$	121,343	$	(77,577)	$	691,727
Operating costs and expenses:
Gas purchases – midstream services		–		149,765		–		(114)		149,651
Operating expenses		–		106,293		32,277		(76,664)		61,906
General and administrative expenses		–		30,818		6,102		(799)		36,121
Depreciation, depletion and amortization		–		193,057		10,878		–		203,935
Impairment of natural gas and oil properties		–		289,821		–		–		289,821
Taxes, other than income taxes		–		13,513		2,739		–		16,252
Total operating costs and expenses		–		783,267		51,996		(77,577)		757,686
Operating income (loss)		–		(135,306)		69,347		–		(65,959)
Other income, net		–		216		22		–		238
Loss on derivatives		–		(5,879)		–		–		(5,879)
Equity in earnings of subsidiaries		(54,053)		–		–		54,053		–
Interest expense		–		7,200		3,406		–		10,606
Income (loss) before income taxes		(54,053)		(148,169)		65,963		54,053		(82,206)
Provision (benefit) for income taxes		–		(53,903)		25,750		–		(28,153)
Net income (loss)		(54,053)		(94,266)		40,213		54,053		(54,053)
Comprehensive income (loss)	$	(183,944)	$	(225,408)	$	41,210	$	184,198	$	(183,944)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Unaudited)
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
	(in thousands)
Nine months ended September 30, 2013:
Operating revenues	$	–	$	2,331,343	$	379,212	$	(246,499)	$	2,464,056
Operating costs and expenses:
Gas purchases – midstream services		–		576,185		–		(848)		575,337
Operating expenses		–		375,721		106,520		(245,593)		236,648
General and administrative expenses		–		116,648		19,164		(58)		135,754
Depreciation, depletion and amortization		–		533,876		37,392		–		571,268
Taxes, other than income taxes		–		50,053		8,490		–		58,543
Total operating costs and expenses		–		1,652,483		171,566		(246,499)		1,577,550
Operating income		–		678,860		207,646		–		886,506
Other income (loss), net		–		67		(565)		–		(498)
Gain on derivatives		–		73,906		1,873		–		75,779
Equity in earnings of subsidiaries		559,013		–		–		(559,013)		–
Interest expense		–		23,884		5,433		–		29,317
Income before income taxes		559,013		728,949		203,521		(559,013)		932,470
Provision for income taxes		–		291,795		81,662		–		373,457
Net income		559,013		437,154		121,859		(559,013)		559,013
Comprehensive income	$	457,967	$	337,122	$	120,045	$	(457,167)	$	457,967
Nine months ended September 30, 2012:
Operating revenues	$	–	$	1,824,594	$	350,064	$	(222,020)	$	1,952,638
Operating costs and expenses:
Gas purchases – midstream services		–		424,425		–		(484)		423,941
Operating expenses		–		311,165		87,461		(219,148)		179,478
General and administrative expenses		–		111,567		20,700		(2,388)		129,879
Depreciation, depletion and amortization		–		572,139		33,253		–		605,392
Impairment of natural gas and oil properties		–		1,090,473		–		–		1,090,473
Taxes, other than income taxes		–		42,159		8,995		–		51,154
Total operating costs and expenses		–		2,551,928		150,409		(222,020)		2,480,317
Operating income (loss)		–		(727,334)		199,655		–		(527,679)
Other income (loss), net		–		(23)		2,638		–		2,615
Loss on derivatives		–		(10,593)		–		–		(10,593)
Equity in earnings of subsidiaries		(351,481)		–		–		351,481		–
Interest expense		–		15,460		10,845		–		26,305
Income (loss) before income taxes		(351,481)		(753,410)		191,448		351,481		(561,962)
Provision (benefit) for income taxes		–		(285,231)		74,750		–		(210,481)
Net income (loss)		(351,481)		(468,179)		116,698		351,481		(351,481)
Comprehensive income (loss)	$	(567,869)	$	(686,291)	$	117,660	$	568,631	$	(567,869)

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
	Parent		Guarantors		Non- Guarantors		Eliminations		Consolidated
	(in thousands)
September 30, 2013:
ASSETS
Cash and cash equivalents	$	17,956	$	–	$	994	$	–	$	18,950
Accounts receivable		3,114		423,418		18,191		–		444,723
Inventories		–		40,906		2,319		–		43,225
Other assets		13,893		212,154		7,030		–		233,077
Total current assets		34,963		676,478		28,534		–		739,975
Intercompany receivables		2,548,900		57		54,531		(2,603,488)		–
Property and equipment		236,324		13,079,991		1,507,238		–		14,823,553
Less: Accumulated depreciation, depletion and amortization		(102,706)		(7,455,008)		(229,106)		–		(7,786,820)
		133,618		5,624,983		1,278,132		–		7,036,733
Investments in subsidiaries (equity method)		2,788,544		–		–		(2,788,544)		–
Other assets		32,103		69,697		15,880		–		117,680
Total assets	$	5,538,128	$	6,371,215	$	1,377,077	$	(5,392,032)	$	7,894,388
LIABILITIES AND EQUITY
Accounts payable	$	147,265	$	432,089	$	84,372	$	–	$	663,726
Other current liabilities		3,759		141,307		1,019		–		146,085
Total current liabilities		151,024		573,396		85,391		–		809,811
Intercompany payables		–		2,603,488		–		(2,603,488)		–
Long-term debt		1,911,165		–		–		–		1,911,165
Deferred income taxes		(115,675)		1,077,055		427,453		–		1,388,833
Other liabilities		71,625		178,703		14,262		–		264,590
Total liabilities		2,018,139		4,432,642		527,106		(2,603,488)		4,374,399
Commitments and contingencies
Total equity		3,519,989		1,938,573		849,971		(2,788,544)		3,519,989
Total liabilities and equity	$	5,538,128	$	6,371,215	$	1,377,077	$	(5,392,032)	$	7,894,388

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
	Parent		Guarantors		Non- Guarantors		Eliminations		Consolidated
	(in thousands)
December 31, 2012:
ASSETS
Cash and cash equivalents	$	47,491	$	5,988	$	104	$	–	$	53,583
Restricted cash		8,542		–		–		–		8,542
Accounts receivable		2,677		353,607		21,354		–		377,638
Inventories		2		26,975		1,164		–		28,141
Other assets		7,461		321,396		12,151		–		341,008
Total current assets		66,173		707,966		34,773		–		808,912
Intercompany receivables		2,259,713		42		27,077		(2,286,832)		–
Property and equipment		220,837		11,491,222		1,316,380		–		13,028,439
Less: Accumulated depreciation, depletion and amortization		(82,178)		(6,923,106)		(186,179)		–		(7,191,463)
		138,659		4,568,116		1,130,201		–		5,836,976
Investments in subsidiaries (equity method)		2,309,947		–		–		(2,309,947)		–
Other assets		35,136		42,247		14,256		–		91,639
Total assets	$	4,809,628	$	5,318,371	$	1,206,307	$	(4,596,779)	$	6,737,527
LIABILITIES AND EQUITY
Accounts payable	$	140,367	$	375,604	$	41,009	$	–	$	556,980
Other current liabilities		3,758		205,623		1,410		–		210,791
Total current liabilities		144,125		581,227		42,419		–		767,771
Intercompany payables		–		2,108,360		178,472		(2,286,832)		–
Long-term debt		1,668,273		–		–		–		1,668,273
Deferred income taxes		(116,207)		820,279		345,066		–		1,049,138
Other liabilities		77,565		124,505		14,403		–		216,473
Total liabilities		1,773,756		3,634,371		580,360		(2,286,832)		3,701,655
Commitments and contingencies
Total equity		3,035,872		1,684,000		625,947		(2,309,947)		3,035,872
Total liabilities and equity	$	4,809,628	$	5,318,371	$	1,206,307	$	(4,596,779)	$	6,737,527

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
	(in thousands)
Nine months ended September 30, 2013:
Net cash provided by (used in) operating activities	$	(32,502)	$	1,062,133	$	347,887	$	–	$	1,377,518
Investing activities:
Capital investments		(29,227)		(1,530,760)		(167,556)		–		(1,727,543)
Proceeds from sale of property and equipment		–		210		2,871		–		3,081
Transfers from restricted cash		8,542		–		–		–		8,542
Other		(74)		(1,685)		6,459		–		4,700
Net cash used in investing activities		(20,759)		(1,532,235)		(158,226)		–		(1,711,220)
Financing activities:
Intercompany activities		(274,931)		464,114		(189,183)		–		–
Payments on current portion of long-term debt		(600)		–		–		–		(600)
Payments on revolving long-term debt		(2,134,550)		–		–		–		(2,134,550)
Borrowing under revolving long-term debt		2,377,950		–		–		–		2,377,950
Other Items		55,857		–		–		–		55,857
Net cash provided by (used in) financing activities		23,726		464,114		(189,183)		–		298,657
Effect of exchange rate changes on cash		–		–		412		–		412
Increase (decrease) in cash and cash equivalents		(29,535)		(5,988)		890		–		(34,633)
Cash and cash equivalents at beginning of year		47,491		5,988		104		–		53,583
Cash and cash equivalents at end of period	$	17,956	$	–	$	994	$	–	$	18,950
Nine months ended September 30, 2012:
Net cash provided by (used in) operating activities	$	(55,324)	$	915,885	$	331,916	$	–	$	1,192,477
Investing activities:
Capital investments		(38,946)		(1,452,061)		(132,744)		–		(1,623,751)
Proceeds from sale of property and equipment		144		169,149		31,868		–		201,161
Transfers to restricted cash		(167,774)		–		–		–		(167,774)
Transfers from restricted cash		40,700		–		–		–		40,700
Other		16,575		(24,340)		13,004		–		5,239
Net cash used in investing activities		(149,301)		(1,307,252)		(87,872)		–		(1,544,425)
Financing activities:
Intercompany activities		(148,027)		392,732		(244,705)		–		–
Payments on current portion of long-term debt		(600)		–		–		–		(600)
Payments on revolving long-term debt		(1,774,000)		–		–		–		(1,774,000)
Borrowings under revolving long-term debt		1,129,000		–		–		–		1,129,000
Proceeds from issuance of long-term debt		998,780		–		–		–		998,780
Other items		1,722		–		(11)		–		1,711
Net cash provided by (used in) financing activities		206,875		392,732		(244,716)		–		354,891
Effect of exchange rate changes on cash		–		–		(10)		–		(10)
Increase (decrease) in cash and cash equivalents		2,250		1,365		(682)		–		2,933
Cash and cash equivalents at beginning of year		14,711		–		916		–		15,627
Cash and cash equivalents at end of period	$	16,961	$	1,365	$	234	$	–	$	18,560

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
CONDENSED CONSOLIDATED BALANCE SHEETS
Natural gas and oil properties, using the full cost method, costs excluded from amortization	$ 1,149.8	$ 1,023.9
Common Stock, Par Value	$ 0.01
Common Stock, Authorized, Shares	1,250,000,000
Common Stock, Issued, Shares	351,529,457	351,100,391
Common Stock in Treasury, Shares	14,442	64,715

XML

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income	Common Stock in Treasury	Total
Balance at Dec. 31, 2012	$ 3,511	$ 934,939	$ 1,949,150	$ 149,804	$ (1,532)	$ 3,035,872
Balance, shares at Dec. 31, 2012	351,100
Comprehensive income (loss):
Net income			559,013			559,013
Other comprehensive loss				(101,046)		(101,046)	[1]
Total comprehensive income						457,967
Stock-based compensation		17,426				17,426
Exercise of stock options, shares	706
Exercise of stock options	7	6,768				6,775
Issuance of restricted stock, shares	21
Cancellation of restricted stock, shares	(59)
Cancellation of restricted stock	(1)	1
Treasury stock - non-qualified plan		924			1,025	1,949
Balance at Sep. 30, 2013	$ 3,517	$ 960,058	$ 2,508,163	$ 48,758	$ (507)	$ 3,519,989
Balance, shares at Sep. 30, 2013	351,768

[1] For the nine months endedSeptember 30, 2013Gains and Losses on Cash Flow HedgesPension and Other PostretirementForeign CurrencyTotal(in thousands) (1)Beginning balance, December 31, 2012$ 172,166 $ (22,311)$ (51)$ 149,804 Other comprehensive income (loss) before reclassifications 29,600  -   (1,814) 27,786 Amounts reclassified from accumulated other comprehensive income (loss) (2) (129,632) 800  -   (128,832)Net current-period other comprehensive income (loss) (100,032) 800  (1,814) (101,046)Ending balance, September 30, 2013$ 72,134 $ (21,511)$ (1,865)$ 48,758 All amounts are net-of-tax.

XML

Prepaid Expenses

9 Months Ended

Sep. 30, 2013

Prepaid Expenses [Abstract]

Prepaid Expenses

(3) PREPAID EXPENSES

The components of prepaid expenses included in other current assets as of September 30, 2013 and December 31, 2012 consisted of the following:

	September 30,		December 31,
	2013		2012
		(in thousands)
Prepaid drilling costs	$	15,622	$	30,101
Prepaid insurance		9,536		9,507
Total	$	25,158	$	39,608

XML

Basis of Presentation

9 Months Ended

Sep. 30, 2013

Basis of Presentation [Abstract]

Basis of Presentation

(1) BASIS OF PRESENTATION

Southwestern Energy Company (including its subsidiaries, collectively, “we”, “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production. The Company engages in natural gas and oil exploration and production, natural gas gathering and natural gas marketing through its subsidiaries. Southwestern’s exploration, development and production (“E&P”) activities are focused within the United States.   The Company is actively engaged in exploration and production activities in Arkansas, where we are targeting the unconventional gas reservoir known as the Fayetteville Shale, in Pennsylvania, where we are targeting the unconventional gas reservoir known as the Marcellus Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma Basin.  The Company also actively seeks to find and develop new oil and natural gas plays with significant exploration and exploitation potential.  Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania and Texas.  

The accompanying unaudited condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report on Form 10-Q. The Company believes the disclosures made are adequate to make the information presented not misleading.

The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Annual Report on Form 10-K”).

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 in the Notes to the Consolidated Financial Statements included in the Company’s 2012 Annual Report on Form 10-K.

Certain reclassifications have been made to the prior year financial statements to conform to the 2013 presentation. The effects of the reclassifications were not material to the Company’s unaudited condensed consolidated financial statements.

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Earnings Per Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss)	$ 185,867		$ (54,053)		$ 559,013		$ (351,481)
Number of common shares, Weighted average outstanding	350,517,337		348,649,630		350,334,634		348,272,192
Number of common shares, Issued upon assumed exercise of outstanding stock options	373,152				442,678
Number of common shares, Effect of issuance of nonvested restricted common stock	332,341				237,662
Number of common shares, Weighted average and potential dilutive outstanding	351,222,830	[1]	348,649,630	[1]	351,014,974	[1]	348,272,192	[1]
Basic	$ 0.53		$ (0.16)		$ 1.60		$ (1.01)
Diluted	$ 0.53		$ (0.16)		$ 1.59		$ (1.01)
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	1,550,838		1,664,232		1,848,566		1,685,398
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	15,703		560,848		169,261		580,227
Parent [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss)	$ 185,867		$ (54,053)		$ 559,013		$ (351,481)

[1] Options for 1,550,838 shares and 15,703 shares of restricted stock were excluded from the calculation for the three months ended September 30, 2013 because they would have had an antidilutive effect. Due to the net loss for the three months ended September 30, 2012, options for 1,664,232 shares and 560,848 shares of restricted stock were antidilutive and excluded from the calculation. Options for 1,848,566 shares and 169,261 shares of restricted stock were excluded from the calculation for the nine months ended September 30, 2013 because they would have had an antidilutive effect. Due to the net loss for the nine months ended September 30, 2012, options for 1,685,398 shares and 580,227 shares of restricted stock were antidilutive and excluded from the calculation.

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Derivatives and Risk Management (Tables)

9 Months Ended

Sep. 30, 2013

Derivatives And Risk Management [Abstract]

Balance Sheet Classification of Derivative Financial Instruments

	Derivative Assets
	September 30, 2013			December 31, 2012
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Derivatives designated as hedging instruments:
Fixed price swaps	Hedging asset	$	115,039	Hedging asset	$	279,443
Fixed price swaps	Other long-term assets		5,951	Other long-term assets		8,550
Total derivatives designated as hedging instruments		$	120,990		$	287,993
Derivatives not designated as hedging instruments:
Basis swaps	Hedging asset	$	5,104	Hedging asset	$	3,250
Fixed price swaps	Hedging asset		77,504	Hedging asset		–
Basis swaps	Other long-term assets		679	Other long-term assets		901
Fixed price swaps	Other long-term assets		19,103	Other long-term assets		–
Interest rate swaps	Other long-term assets		5,797	Other long-term assets		–
Total derivatives not designated as hedging instruments		$	108,187		$	4,151
Total derivative assets		$	229,177		$	292,144
	Derivative Liabilities
	September 30, 2013			December 31, 2012
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Derivatives not designated as hedging instruments:
Basis swaps	Other current liabilities	$	164	Other current liabilities	$	138
Fixed price call options	Other long-term liabilities		30,980	Other long-term liabilities		4,128
Interest rate swaps	Other current liabilities		912	Other current liabilities		–
Interest rate swaps	Other long-term liabilities		3,582	Other long-term liabilities		–
Total derivatives not designated as hedging instruments		$	35,638		$	4,266
Total derivative liabilities		$	35,638		$	4,266

Fixed Price Swaps, Volumes of Natural Gas Production (in Bcf)

Year	Fixed price swaps	Fixed price swaps not designated for hedge accounting	Total
2013	84.4	-	84.4
2014	51.1	181.6	232.7

Before Tax Effect of Cash Flow Hedges on Consolidated Financial Statements

		Gain (Loss) Recognized in Other Comprehensive Income
		(Effective Portion)
		For the three months ended				For the nine months ended
		September 30,				September 30,
Derivative Instrument		2013		2012		2013		2012
		(in thousands)
Fixed price swaps		$	12,515	$	(55,039)	$	51,234	$	116,089
Costless-collars		$	–	$	(3,497)	$	–	$	40,644
	Classification of Gain	Gain Reclassified from Accumulated Other
	Reclassified from	Comprehensive Income into Earnings
	Accumulated Other	(Effective Portion)
	Comprehensive Income	For the three months ended				For the nine months ended
	into Earnings	September 30,				September 30,
Derivative Instrument	(Effective Portion)	2013		2012		2013		2012
		(in thousands)
Fixed price swaps	Gas sales	$	93,280	$	102,789	$	218,236	$	337,994
Costless-collars	Gas sales	$	–	$	54,489	$	–	$	175,531
		Gain (Loss) Recognized in Earnings
		(Ineffective Portion)
	Classification of Gain (Loss)	For the three months ended				For the nine months ended
	Recognized in Earnings	September 30,				September 30,
Derivative Instrument	(Ineffective Portion)	2013		2012		2013		2012
		(in thousands)
Fixed price swaps	Gas sales	$	(1,452)	$	(165)	$	(2,183)	$	1,831
Costless-collars	Gas sales	$	–	$	(373)	$	–	$	167

Before Tax Effect of Basis Swaps Not Qualifying for Hedge Accounting

		Mark to Market Gain (Loss)
		on Derivatives
		Recognized in Earnings
	Income Statement	For the three months ended				For the nine months ended
	Classification of Mark to Market Gain (Loss)	September 30,				September 30,
Derivative Instrument	on Derivatives	2013		2012		2013		2012
		(in thousands)
Basis swaps	Gain (Loss) on Derivatives	$	(5,279)	$	(1,275)	$	1,606	$	(270)
Fixed price call options	Gain (Loss) on Derivatives	$	7,876	$	–	$	(26,852)	$	–
Fixed price swaps	Gain (Loss) on Derivatives	$	8,819	$	–	$	96,606	$	–
Interest rate swaps	Gain (Loss) on Derivatives	$	(1,312)	$	–	$	1,304	$	–
Fair value swaps	Gain (Loss) on Derivatives	$	–	$	136	$	–	$	1,162
		Mark to Market Gain (Loss)
		on Derivatives, Settled (1)
		Recognized in Earnings
	Income Statement	For the three months ended				For the nine months ended
	Classification of Mark to Market Gain (Loss)	September 30,				September 30,
Derivative Instrument	on Derivatives, Settled (1)	2013		2012		2013		2012
		(in thousands)
Basis swaps	Gain (Loss) on Derivatives	$	2,020	$	624	$	3,115	$	1,773
Fair value swaps	Gain (Loss) on Derivatives	$	–	$	(5,364)	$	–	$	(13,258)

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Supplemental Disclosures of Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2013

Supplemental Disclosures of Cash Flow Information [Abstract]

Schedule of Supplemental Disclosures of Cash Flow Information

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Cash paid for interest	$	44,745	$	45,667	$	94,963	$	75,487
Cash paid for income taxes	$	1,330	$	400	$	18,636	$	468
Noncash property changes	$	(11,745)	$	(55,729)	$	34,437	$	(34,940)

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Acquisitions And Divestitures (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Apr. 30, 2013	May 31, 2012 MMcf	Dec. 31, 2011
Acquisitions And Divestitures [Abstract]
Cost to acquire natural gas properties through definitive purchase agreement	$ 93.0
Proceeds from sale of oil and gas property and equipment		$ 166.0
Divested assets, Production in MMcfe per day		24.0
Divested assets, Proved net reserves in Bcfe			143.0

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Commitments and Contingencies (Details)	1 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2010 USD ($)	Mar. 31, 2010 CAD item acre	Mar. 31, 2010 CAD acre	Sep. 30, 2013 USD ($)	Dec. 31, 2012 item	Dec. 31, 2010 USD ($)	Mar. 23, 2012	Nov. 30, 2011 USD ($)	Aug. 24, 2011 USD ($)	Jul. 12, 2011 USD ($)	Jun. 02, 2011 USD ($)	Mar. 11, 2011 item	Nov. 30, 2010 Seventh Amended Petition [Member] USD ($)	Feb. 28, 2009 Sixth Amended Petition [Member] USD ($)
Unrecorded capital investments obligation, Exploration program acres coverage (acres)		2,500,000	2,500,000
Unrecorded capital investments obligation		47,000,000	47,000,000
Recorded capital investments obligation				35,400,000
Period licenses require capital investments be made, years			3 years
Number of extensions to exploration license agreememnts					2
Extension of exploration license, period					1 year
Unrecorded promissory note payable		44,500,000	44,500,000
Duration of firm transportation agreement, years							15 years
Obligation under transportation agreements				3,400,000,000
Guarantee obligations relative to the firms transportation agreements and gathering project and services				100,000,000
Litigation, Allegations				plaintiff alleged that, in 2005, they provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom.  Among other things, the plaintiff's allegations in the Sixth Petition included various statutory and common law claims, including, but not limited to claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 2005 and February 2006.
Litigation, Monetary damages claimed by plaintiffs													46,000,000	55,000,000
Litigation settlement	11,400,000
Litigation, Interest and Attorney's Fees claimed by plaintiffs									8,900,000		11,400,000
Litigation, portion of profits considered for disgorgement						381,500,000
Disgorgement damages awarded in favor of the plantiff and intervenor										23,900,000
Percentage of attorney fees recoverable by plantiff											40
Number of wells for constructive trust profits												143
Number of horizontal wells operated by SEECO in Arkansas		27
Value of SEPCO's supersedeas bond								14,100,000
Pre-judgement interest covered by SEPCO's supersedeas bond								1,300,000
Post-judgement interest covered by SEPCO's supersedeas bond								1,300,000
Litigation, SEPCO's estimated gross liability including interest and attorney's fees.				$ 45,500,000

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Fair Value Measurements (Carrying Amount and Estimated Fair Values of Financial Instruments) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash		$ 8,542
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	18,950	53,583
Restricted cash		8,542
Unsecured revolving credit facility	243,400
Senior notes	1,668,965	1,669,473
Derivative instruments	193,539	287,878
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	18,950	53,583
Restricted cash		8,542
Unsecured revolving credit facility	243,400
Senior notes	1,807,234	1,917,005
Derivative instruments	$ 193,539	$ 287,878

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Derivatives and Risk Management (Before Tax Effect of all Cash Flow Hedges on the Condensed Consolidated Financial Statements) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Fixed Price Swaps [Member]
Derivative [Line Items]
Gain (Loss) Recognized in Other Comprehensive Income (Effective Portion)	$ 12,515	$ (55,039)	$ 51,234	$ 116,089
Costless Collar [Member]
Derivative [Line Items]
Gain (Loss) Recognized in Other Comprehensive Income (Effective Portion)		(3,497)		40,644
Gas Sales [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Gain Reclassified from Accumulated Other Comprehensive Income into Earnings (Effective Portion)	93,280	102,789	218,236	337,994
Gain (Loss) Recognized in Earnings (Ineffective Portion)	(1,452)	(165)	(2,183)	1,831
Gas Sales [Member] | Costless Collar [Member]
Derivative [Line Items]
Gain Reclassified from Accumulated Other Comprehensive Income into Earnings (Effective Portion)		54,489		175,531
Gain (Loss) Recognized in Earnings (Ineffective Portion)		$ (373)		$ 167

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss)	$ 185,867		$ (54,053)		$ 559,013		$ (351,481)
Change in derivatives:
Settlements	(55,968)	[1]	(94,996)	[1]	(130,942)	[1]	(310,882)	[1]
Ineffectiveness	872	[2]	322	[2]	1,310	[2]	(1,215)	[2]
Change in fair value of derivative instruments	7,509	[3]	(36,468)	[3]	29,600	[3]	93,985	[3]
Total change in derivatives	(47,587)		(131,142)		(100,032)		(218,112)
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost included in net periodic pension cost	266	[4]	254	[4]	800	[4]	762	[4]
Change in currency translation adjustment	633		997		(1,814)		962
Comprehensive income (loss)	$ 139,179		$ (183,944)		$ 457,967		$ (567,869)

[1] Net of ($37.3), ($62.2), ($87.3) and ($202.6) million in taxes for the three months ended September 30, 2013 and 2012, and nine months ended September 30, 2013 and 2012, respectively.

[2] Net of $0.6, $0.2, $0.9 and ($0.8) million in taxes for the three months ended September 30, 2013 and 2012, and nine months ended September 30, 2013 and 2012, respectively.

[3] Net of $5.0, ($22.1), $19.7, and $62.7 million in taxes for the three months ended September 30, 2013 and 2012, and nine months ended September 30, 2013 and 2012, respectively.

[4] Net of $0.2, $0.2, $0.5, and $0.5 million in taxes for the three months ended September 30, 2013 and 2012, and nine months ended September 30, 2013 and 2012, respectively.

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Earnings Per Share

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Share

(6) EARNINGS PER SHARE

The following table presents the computation of earnings per share for the three- and nine-month periods ended September  30, 2013 and 2012:

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
Net income (loss) (in thousands)	$	185,867	$	(54,053)	$	559,013	$	(351,481)
Number of common shares:
Weighted average outstanding		350,517,337		348,649,630		350,334,634		348,272,192
Issued upon assumed exercise of outstanding stock options		373,152		–		442,678		–
Effect of issuance of nonvested restricted common stock		332,341		–		237,662		–
Weighted average and potential dilutive outstanding(1)		351,222,830		348,649,630		351,014,974		348,272,192
Earnings (loss) per share:
Basic	$	0.53	$	(0.16)	$	1.60	$	(1.01)
Diluted	$	0.53	$	(0.16)	$	1.59	$	(1.01)

(1) Options for 1,550,838shares and 15,703 shares of restricted stock were excluded from the calculation for the three months ended September 30, 2013 because they would have had an antidilutive effect.  Due to the net loss for the three months ended September 30, 2012, options for 1,664,232 shares and 560,848 shares of restricted stock were antidilutive and excluded from the calculation.  Options for1,848,566 shares and 169,261 shares of restricted stock were excluded from the calculation for the nine months ended September 30, 2013 because they would have had an antidilutive effect.  Due to the net loss for the nine months ended September 30, 2012, options for 1,685,398 shares and 580,227 shares of restricted stock were antidilutive and excluded from the calculation.

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 18,950		$ 53,583
Restricted cash			8,542
Accounts receivable	444,723		377,638
Inventories	43,225		28,141
Hedging asset	197,647		282,693
Other current assets	35,430		58,315
Total current assets	739,975		808,912
Property and Equipment:
Natural gas and oil properties, using the full cost method, including $1,101.5 million in 2013 and $1,023.9 million in 2012 excluded from amortization	12,863,859		11,283,114
Gathering systems	1,282,652		1,148,261
Other	677,042		597,064
Less: Accumulated depreciation, depletion and amortization	(7,786,820)		(7,191,463)
Total property and equipment, net	7,036,733		5,836,976
Other long-term assets	117,680		91,639
TOTAL ASSETS	7,894,388	[1]	6,737,527
Current liabilities:
Accounts payable	601,414		459,569
Taxes payable	48,263		62,980
Interest payable	14,049		34,431
Advances from partners	3,438		68,919
Current deferred income taxes	75,954		106,123
Other current liabilities	66,693		35,749
Total current liabilities	809,811		767,771
Long-term debt	1,911,165		1,668,273
Other Liabilities:
Deferred income taxes	1,388,833		1,049,138
Pension and other postretirement liabilities	34,963		33,174
Other long-term liabilities	229,627		183,299
Total long-term liabilities	3,564,588		2,933,884
Commitments and contingencies (Note 11)
Equity:
Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 351,768,852 shares in 2013 and 351,100,391 in 2012	3,517		3,511
Additional paid-in capital	960,058		934,939
Retained earnings	2,508,163		1,949,150
Accumulated other comprehensive income	48,758	[2]	149,804	[2]
Common stock in treasury, 14,625 shares in 2013 and 64,715 in 2012	(507)		(1,532)
Total equity	3,519,989		3,035,872
TOTAL LIABILITIES AND EQUITY	$ 7,894,388		$ 6,737,527

[1] Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

[2] For the nine months endedSeptember 30, 2013Gains and Losses on Cash Flow HedgesPension and Other PostretirementForeign CurrencyTotal(in thousands) (1)Beginning balance, December 31, 2012$ 172,166 $ (22,311)$ (51)$ 149,804 Other comprehensive income (loss) before reclassifications 29,600  -   (1,814) 27,786 Amounts reclassified from accumulated other comprehensive income (loss) (2) (129,632) 800  -   (128,832)Net current-period other comprehensive income (loss) (100,032) 800  (1,814) (101,046)Ending balance, September 30, 2013$ 72,134 $ (21,511)$ (1,865)$ 48,758 All amounts are net-of-tax.

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Stock-Based Compensation (Employee Stock-Based Compensation Costs) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Stock-Based Compensation [Abstract]
Stock-based compensation costs - expensed	$ 2,921,000	$ 2,677,000	$ 8,883,000	$ 8,226,000
Stock-based compensation costs - capitalized	2,809,000	2,482,000	8,543,000	7,788,000
Unrecognized compensation cost related to unvested stock option and restricted stock grants	$ 38,200,000		$ 38,200,000
Weighted average period over which cost is recognized, years			2 years 3 months 18 days

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Operating Revenues:
Gas sales	$ 617,427		$ 497,219		$ 1,736,101		$ 1,394,745
Gas marketing	201,112		148,764		581,932		423,503
Oil sales	4,397		1,889		12,431		6,097
Gas gathering	45,430		43,855		133,592		128,293
Total Operating Revenues	868,366		691,727		2,464,056		1,952,638
Operating Costs and Expenses:
Gas purchases - midstream services	195,271		149,651		575,337		423,941
Operating expenses	90,269		61,906		236,648		179,478
General and administrative expenses	50,969		36,121		135,754		129,879
Depreciation, depletion and amortization	204,934		203,935		571,268		605,392
Impairment of natural gas and oil properties			289,821				1,090,473	[1]
Taxes, other than income taxes	17,694		16,252		58,543		51,154
Total operating costs and expenses	559,137		757,686		1,577,550		2,480,317
Operating Income (loss)	309,229		(65,959)		886,506		(527,679)	[2]
Interest Expense:
Interest on debt	25,435		25,463		74,581		69,154
Other interest charges	1,049		1,058		3,203		3,096
Interest capitalized	(15,466)		(15,915)		(48,467)		(45,945)
Total Interest Expense	11,018		10,606		29,317	[1]	26,305	[1]
Other Gain (Loss), Net	(319)		238	[2]	(498)	[1]	2,615	[1]
Gain (Loss) on Derivatives	12,124	[1]	(5,879)	[1]	75,779		(10,593)
Income (Loss) before income taxes	310,016		(82,206)		932,470		(561,962)
Provision for Income Taxes:
Current	(16,068)		101		402		369
Deferred	140,217		(28,254)		373,055		(210,850)
Total provision for income taxes	124,149	[1]	(28,153)	[1]	373,457	[1]	(210,481)	[1]
Net Income (Loss)	$ 185,867		$ (54,053)		$ 559,013		$ (351,481)
Earnings (Loss) Per Share:
Basic	$ 0.53		$ (0.16)		$ 1.60		$ (1.01)
Diluted	$ 0.53		$ (0.16)		$ 1.59		$ (1.01)
Weighted Average Common Shares Outstanding:
Basic	350,517,337		348,649,630		350,334,634		348,272,192
Diluted	351,222,830	[3]	348,649,630	[3]	351,014,974	[3]	348,272,192	[3]

[1] Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

[2] The operating loss for the E&P segment for the three and nine months ended September 30, 2012 includes a $289.8 million and $1,090.5 million non-cash ceiling test impairment of our natural gas and oil properties respectively.

[3] Options for 1,550,838 shares and 15,703 shares of restricted stock were excluded from the calculation for the three months ended September 30, 2013 because they would have had an antidilutive effect. Due to the net loss for the three months ended September 30, 2012, options for 1,664,232 shares and 560,848 shares of restricted stock were antidilutive and excluded from the calculation. Options for 1,848,566 shares and 169,261 shares of restricted stock were excluded from the calculation for the nine months ended September 30, 2013 because they would have had an antidilutive effect. Due to the net loss for the nine months ended September 30, 2012, options for 1,685,398 shares and 580,227 shares of restricted stock were antidilutive and excluded from the calculation.

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Fair Value Measurements (Summary Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets
Derivative liabilities
Total
Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	223,394	287,993
Derivative liabilities	(4,494)
Total	218,900	287,993
Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5,783	4,151
Derivative liabilities	(31,144)	(4,266)
Total	(25,361)	(115)
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	229,177	292,144
Derivative liabilities	(35,638)	(4,266)
Total	$ 193,539	$ 287,878

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Reclassifications From Accumulated Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2013

Reclassifications From Accumulated Other Comprehensive Income [Abstract]

Components of AOCI and Related Tax Effects

	For the nine months ended
	September 30, 2013
	Gains and Losses on Cash Flow Hedges		Pension and Other Postretirement		Foreign Currency		Total
	(in thousands) (1)
Beginning balance, December 31, 2012	$	172,166	$	(22,311)	$	(51)	$	149,804
Other comprehensive income (loss) before reclassifications		29,600		–		(1,814)		27,786
Amounts reclassified from accumulated other comprehensive income (loss) (2)		(129,632)		800		–		(128,832)
Net current-period other comprehensive income (loss)		(100,032)		800		(1,814)		(101,046)
Ending balance, September 30, 2013	$	72,134	$	(21,511)	$	(1,865)	$	48,758

(1) All amounts are net-of-tax.

See separate table below for details about these reclassifications.

Amounts Reclassified from AOCI into Earnings

Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statement of Operations		Amount Reclassified from Accumulated Other Comprehensive Income
			For the nine months ended September 30, 2013
			(in thousands)
Gains (losses) on cash flow hedges
Settlements	Gas sales	$	218,236
Ineffectiveness	Gas sales		(2,183)
	Income before income taxes		216,053
	Provision for income taxes		86,421
	Net income	$	129,632
Pension and other postretirement
Amortization of prior service cost included in net periodic pension cost (1)	General and administrative expenses	$	(1,334)
	Loss before income taxes		(1,334)
	Benefit for income taxes		(534)
	Net loss	$	(800)
Total reclassifications for the period	Net income	$	128,832

Included in the computation of net periodic pension cost (see footnote 13 for additional details.)

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Segment Information

9 Months Ended

Sep. 30, 2013

Segment Information [Abstract]

Segment Information

(15) SEGMENT INFORMATION

The Company’s reportable business segments 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 natural gas volumes and through gathering fees associated with the transportation of natural gas to market.

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 2012 Annual Report on Form 10-K. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense and interest and other income (loss). The “Other” column includes items not related to the Company’s reportable segments including real estate and corporate items.

	Exploration
	and		Midstream
	Production		Services		Other			Total
	(in thousands)
Three months ended September 30, 2013:
Revenues from external customers	$	621,833	$	246,501	$	32		$	868,366
Intersegment revenues		644		601,104		64			601,812
Operating income (loss)		222,692		86,658		(121)			309,229
Other income (loss), net		143		70		(532)			(319)
Gain on derivatives		10,885		1,232		7			12,124
Depreciation, depletion and amortization expense		191,860		12,970		104			204,934
Interest expense(2)		8,580		2,294		144			11,018
Provision (benefit) for income taxes(2)		87,779		36,671		(301)			124,149
Assets		6,264,845		1,387,765		241,778	(3)		7,894,388
Capital investments(4)		496,331		40,052		5,726			542,109
Three months ended September 30, 2012:
Revenues from external customers	$	499,083	$	192,619	$	25		$	691,727
Intersegment revenues		(982)		409,720		825			409,563
Operating income (loss)(1)		(141,865)		75,488		418			(65,959)
Other income (loss), net		213		27		(2)			238
Loss on derivatives		(5,879)		–		–			(5,879)
Depreciation, depletion and amortization expense		192,994		10,620		321			203,935
Impairment of natural gas and oil properties		289,821		–		–			289,821
Interest expense(2)		6,707		3,659		240			10,606
Provision (benefit) for income taxes(2)		(55,220)		27,006		61			(28,153)
Assets		5,854,055		1,158,638		343,869	(3)		7,356,562
Capital investments(4)		385,585		31,693		7,608			424,886

	Exploration
	and		Midstream
	Production		Services		Other			Total
	(in thousands)
Nine months ended September 30, 2013:
Revenues from external customers	$	1,748,821	$	715,155	$	80		$	2,464,056
Intersegment revenues		3,817		1,740,132		177			1,744,126
Operating income (loss)		650,996		235,854		(344)			886,506
Other income (loss), net		61		(27)		(532)			(498)
Gain on derivatives		74,540		1,232		7			75,779
Depreciation, depletion and amortization expense		533,577		37,377		314			571,268
Interest expense(2)		21,101		7,682		534			29,317
Provision (benefit) for income taxes(2)		282,231		91,785		(559)			373,457
Assets		6,264,845		1,387,765		241,778	(3)		7,894,388
Capital investments(4)		1,602,885		135,425		16,748			1,755,058
Nine months ended September 30, 2012:
Revenues from external customers	$	1,400,749	$	551,796	$	93		$	1,952,638
Intersegment revenues		(1,716)		1,085,392		2,459			1,086,135
Operating income (loss)(1)		(745,533)		216,598		1,256			(527,679)
Other income (loss), net		(34)		4		2,645			2,615
Loss on derivatives		(10,593)		–		–			(10,593)
Depreciation, depletion and amortization expense		571,934		32,499		959			605,392
Impairment of natural gas and oil properties		1,090,473		–		–			1,090,473
Interest expense(2)		14,459		10,904		942			26,305
Provision (benefit) for income taxes(2)		(289,875)		78,268		1,126			(210,481)
Assets		5,854,055		1,158,638		343,869	(3)		7,356,562
Capital investments(4)		1,450,569		105,576		30,486			1,586,631

(1) The operating loss for the E&P segment for the three and nine months ended September 30, 2012 includes a $289.8 million and $1,090.5 million non-cash ceiling test impairment of our natural gas and oil properties respectively.

(2) Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

(3) Other assets represent corporate assets not allocated to segments and assets, including restricted cash and investments in cash equivalents, for non reportable segments.

(4) Capital investments includes decreases of $14.6 million and $56.2 million for the three-month periods ended September 30, 2013 and 2012, respectively, and increase of $25.8 million and decrease of $40.7 million for the nine-month periods ended September 30, 2013 and 2012, respectively, relating to the change in accrued expenditures between periods.

Included in intersegment revenues of the Midstream Services segment are $515.3 million and $332.1 million for the three months ended September  30, 2013 and 2012, respectively, and $1,493.8 million and $863.7 million for the nine months ended September 30, 2013 and 2012, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, restricted cash, furniture and fixtures, prepaid debt and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments. For the three months ended September  30, 2013 and 2012, capital investments within the E&P segment include$11.9million and $2.2 million, respectively, related to the Company’s activities in Canada.  For the nine months ended September 30, 2013 and 2012, capital investments within the E&P segment include $19.8 million and $6.9 million, respectively, relating to the Company’s activities in Canada. At September  30, 2013, E&P segment assets include $64.8 million and at September  30, 2012, assets include $36.4  million related to the Company’s activities in Canada.

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Derivatives and Risk Management (Cash Flow Hedges on Volumes of Natural Gas Production) (Details)	Sep. 30, 2013 ft3
Year 2013 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	84,400,000,000
Year 2014 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	232,700,000,000
Not Designated as Hedging Instrument [Member] | Year 2014 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	181,600,000,000
Designated as Hedging Instrument [Member] | Year 2013 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	84,400,000,000
Designated as Hedging Instrument [Member] | Year 2014 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	51,100,000,000

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Debt (Components Of Debt) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Total short-term debt	$ 1,200	$ 1,200
Unamortized discount	(1,035)	(1,127)
Total long-term debt	1,911,165	1,668,273
Total debt	1,912,365	1,669,473
2.14% unsecured revolving credit facility
Debt Instrument [Line Items]
Variable rate (2.14% at September 30, 2013) unsecured revolving credit facility	243,400
Debt instrument, interest rate, stated percentage	2.14%
7.5% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	600,000	600,000
Debt instrument, interest rate, stated percentage	7.50%
7.35% Senior Notes due 2017 [Member]
Debt Instrument [Line Items]
Senior Notes	15,000	15,000
Debt instrument, interest rate, stated percentage	7.35%
7.125% Senior Notes due 2017 [Member]
Debt Instrument [Line Items]
Senior Notes	25,000	25,000
Debt instrument, interest rate, stated percentage	7.125%
7.15% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Total short-term debt	1,200	1,200
Senior Notes	28,800	29,400
Debt instrument, interest rate, stated percentage	7.15%
4.10% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	1,000,000	1,000,000
Debt instrument, interest rate, stated percentage	4.10%
Parent [Member]
Debt Instrument [Line Items]
Total long-term debt	$ 1,911,165	$ 1,668,273

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Inventory (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Inventory [Abstract]
Current assets inventory, underground storage	$ 3.7	$ 5.6
Current assets inventory, tubulars & other equipment	39.5	22.5
Other assets non-current inventory, gathering systems pipe	$ 15.8	$ 13.8

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Information [Abstract]

Summary Financial Information for Company's Reportable Segments Table

	Exploration
	and		Midstream
	Production		Services		Other			Total
	(in thousands)
Three months ended September 30, 2013:
Revenues from external customers	$	621,833	$	246,501	$	32		$	868,366
Intersegment revenues		644		601,104		64			601,812
Operating income (loss)		222,692		86,658		(121)			309,229
Other income (loss), net		143		70		(532)			(319)
Gain on derivatives		10,885		1,232		7			12,124
Depreciation, depletion and amortization expense		191,860		12,970		104			204,934
Interest expense(2)		8,580		2,294		144			11,018
Provision (benefit) for income taxes(2)		87,779		36,671		(301)			124,149
Assets		6,264,845		1,387,765		241,778	(3)		7,894,388
Capital investments(4)		496,331		40,052		5,726			542,109
Three months ended September 30, 2012:
Revenues from external customers	$	499,083	$	192,619	$	25		$	691,727
Intersegment revenues		(982)		409,720		825			409,563
Operating income (loss)(1)		(141,865)		75,488		418			(65,959)
Other income (loss), net		213		27		(2)			238
Loss on derivatives		(5,879)		–		–			(5,879)
Depreciation, depletion and amortization expense		192,994		10,620		321			203,935
Impairment of natural gas and oil properties		289,821		–		–			289,821
Interest expense(2)		6,707		3,659		240			10,606
Provision (benefit) for income taxes(2)		(55,220)		27,006		61			(28,153)
Assets		5,854,055		1,158,638		343,869	(3)		7,356,562
Capital investments(4)		385,585		31,693		7,608			424,886

	Exploration
	and		Midstream
	Production		Services		Other			Total
	(in thousands)
Nine months ended September 30, 2013:
Revenues from external customers	$	1,748,821	$	715,155	$	80		$	2,464,056
Intersegment revenues		3,817		1,740,132		177			1,744,126
Operating income (loss)		650,996		235,854		(344)			886,506
Other income (loss), net		61		(27)		(532)			(498)
Gain on derivatives		74,540		1,232		7			75,779
Depreciation, depletion and amortization expense		533,577		37,377		314			571,268
Interest expense(2)		21,101		7,682		534			29,317
Provision (benefit) for income taxes(2)		282,231		91,785		(559)			373,457
Assets		6,264,845		1,387,765		241,778	(3)		7,894,388
Capital investments(4)		1,602,885		135,425		16,748			1,755,058
Nine months ended September 30, 2012:
Revenues from external customers	$	1,400,749	$	551,796	$	93		$	1,952,638
Intersegment revenues		(1,716)		1,085,392		2,459			1,086,135
Operating income (loss)(1)		(745,533)		216,598		1,256			(527,679)
Other income (loss), net		(34)		4		2,645			2,615
Loss on derivatives		(10,593)		–		–			(10,593)
Depreciation, depletion and amortization expense		571,934		32,499		959			605,392
Impairment of natural gas and oil properties		1,090,473		–		–			1,090,473
Interest expense(2)		14,459		10,904		942			26,305
Provision (benefit) for income taxes(2)		(289,875)		78,268		1,126			(210,481)
Assets		5,854,055		1,158,638		343,869	(3)		7,356,562
Capital investments(4)		1,450,569		105,576		30,486			1,586,631

(1) The operating loss for the E&P segment for the three and nine months ended September 30, 2012 includes a $289.8 million and $1,090.5 million non-cash ceiling test impairment of our natural gas and oil properties respectively.

(2) Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

(3) Other assets represent corporate assets not allocated to segments and assets, including restricted cash and investments in cash equivalents, for non reportable segments.

(4) Capital investments includes decreases of $14.6 million and $56.2 million for the three-month periods ended September 30, 2013 and 2012, respectively, and increase of $25.8 million and decrease of $40.7 million for the nine-month periods ended September 30, 2013 and 2012, respectively, relating to the change in accrued expenditures between periods.

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Condensed Consolidating Financial Information (Tables)

9 Months Ended

Sep. 30, 2013

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Statements of Operations

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Unaudited)
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
	(in thousands)
Three months ended September 30, 2013:
Operating revenues	$	–	$	823,112	$	130,998	$	(85,744)	$	868,366
Operating costs and expenses:
Gas purchases – midstream services		–		195,437		–		(166)		195,271
Operating expenses		–		140,400		35,425		(85,556)		90,269
General and administrative expenses		–		43,836		7,155		(22)		50,969
Depreciation, depletion and amortization		–		191,972		12,962		–		204,934
Taxes, other than income taxes		–		15,348		2,346		–		17,694
Total operating costs and expenses		–		586,993		57,888		(85,744)		559,137
Operating income		–		236,119		73,110		–		309,229
Other income (loss), net		–		145		(464)		–		(319)
Gain on derivatives		–		10,251		1,873		–		12,124
Equity in earnings of subsidiaries		185,867		–		–		(185,867)		–
Interest expense		–		9,359		1,659		–		11,018
Income before income taxes		185,867		237,156		72,860		(185,867)		310,016
Provision for income taxes		–		91,466		32,683		–		124,149
Net income		185,867		145,690		40,177		(185,867)		185,867
Comprehensive income	$	139,179	$	98,102	$	40,811	$	(138,913)	$	139,179
Three months ended September 30, 2012:
Operating revenues	$	–	$	647,961	$	121,343	$	(77,577)	$	691,727
Operating costs and expenses:
Gas purchases – midstream services		–		149,765		–		(114)		149,651
Operating expenses		–		106,293		32,277		(76,664)		61,906
General and administrative expenses		–		30,818		6,102		(799)		36,121
Depreciation, depletion and amortization		–		193,057		10,878		–		203,935
Impairment of natural gas and oil properties		–		289,821		–		–		289,821
Taxes, other than income taxes		–		13,513		2,739		–		16,252
Total operating costs and expenses		–		783,267		51,996		(77,577)		757,686
Operating income (loss)		–		(135,306)		69,347		–		(65,959)
Other income, net		–		216		22		–		238
Loss on derivatives		–		(5,879)		–		–		(5,879)
Equity in earnings of subsidiaries		(54,053)		–		–		54,053		–
Interest expense		–		7,200		3,406		–		10,606
Income (loss) before income taxes		(54,053)		(148,169)		65,963		54,053		(82,206)
Provision (benefit) for income taxes		–		(53,903)		25,750		–		(28,153)
Net income (loss)		(54,053)		(94,266)		40,213		54,053		(54,053)
Comprehensive income (loss)	$	(183,944)	$	(225,408)	$	41,210	$	184,198	$	(183,944)

Condensed Consolidating Balance Sheets

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
	Parent		Guarantors		Non- Guarantors		Eliminations		Consolidated
	(in thousands)
September 30, 2013:
ASSETS
Cash and cash equivalents	$	17,956	$	–	$	994	$	–	$	18,950
Accounts receivable		3,114		423,418		18,191		–		444,723
Inventories		–		40,906		2,319		–		43,225
Other assets		13,893		212,154		7,030		–		233,077
Total current assets		34,963		676,478		28,534		–		739,975
Intercompany receivables		2,548,900		57		54,531		(2,603,488)		–
Property and equipment		236,324		13,079,991		1,507,238		–		14,823,553
Less: Accumulated depreciation, depletion and amortization		(102,706)		(7,455,008)		(229,106)		–		(7,786,820)
		133,618		5,624,983		1,278,132		–		7,036,733
Investments in subsidiaries (equity method)		2,788,544		–		–		(2,788,544)		–
Other assets		32,103		69,697		15,880		–		117,680
Total assets	$	5,538,128	$	6,371,215	$	1,377,077	$	(5,392,032)	$	7,894,388
LIABILITIES AND EQUITY
Accounts payable	$	147,265	$	432,089	$	84,372	$	–	$	663,726
Other current liabilities		3,759		141,307		1,019		–		146,085
Total current liabilities		151,024		573,396		85,391		–		809,811
Intercompany payables		–		2,603,488		–		(2,603,488)		–
Long-term debt		1,911,165		–		–		–		1,911,165
Deferred income taxes		(115,675)		1,077,055		427,453		–		1,388,833
Other liabilities		71,625		178,703		14,262		–		264,590
Total liabilities		2,018,139		4,432,642		527,106		(2,603,488)		4,374,399
Commitments and contingencies
Total equity		3,519,989		1,938,573		849,971		(2,788,544)		3,519,989
Total liabilities and equity	$	5,538,128	$	6,371,215	$	1,377,077	$	(5,392,032)	$	7,894,388

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
	Parent		Guarantors		Non- Guarantors		Eliminations		Consolidated
	(in thousands)
December 31, 2012:
ASSETS
Cash and cash equivalents	$	47,491	$	5,988	$	104	$	–	$	53,583
Restricted cash		8,542		–		–		–		8,542
Accounts receivable		2,677		353,607		21,354		–		377,638
Inventories		2		26,975		1,164		–		28,141
Other assets		7,461		321,396		12,151		–		341,008
Total current assets		66,173		707,966		34,773		–		808,912
Intercompany receivables		2,259,713		42		27,077		(2,286,832)		–
Property and equipment		220,837		11,491,222		1,316,380		–		13,028,439
Less: Accumulated depreciation, depletion and amortization		(82,178)		(6,923,106)		(186,179)		–		(7,191,463)
		138,659		4,568,116		1,130,201		–		5,836,976
Investments in subsidiaries (equity method)		2,309,947		–		–		(2,309,947)		–
Other assets		35,136		42,247		14,256		–		91,639
Total assets	$	4,809,628	$	5,318,371	$	1,206,307	$	(4,596,779)	$	6,737,527
LIABILITIES AND EQUITY
Accounts payable	$	140,367	$	375,604	$	41,009	$	–	$	556,980
Other current liabilities		3,758		205,623		1,410		–		210,791
Total current liabilities		144,125		581,227		42,419		–		767,771
Intercompany payables		–		2,108,360		178,472		(2,286,832)		–
Long-term debt		1,668,273		–		–		–		1,668,273
Deferred income taxes		(116,207)		820,279		345,066		–		1,049,138
Other liabilities		77,565		124,505		14,403		–		216,473
Total liabilities		1,773,756		3,634,371		580,360		(2,286,832)		3,701,655
Commitments and contingencies
Total equity		3,035,872		1,684,000		625,947		(2,309,947)		3,035,872
Total liabilities and equity	$	4,809,628	$	5,318,371	$	1,206,307	$	(4,596,779)	$	6,737,527

Condensed Consolidating Statements of Cash Flows

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
	(in thousands)
Nine months ended September 30, 2013:
Net cash provided by (used in) operating activities	$	(32,502)	$	1,062,133	$	347,887	$	–	$	1,377,518
Investing activities:
Capital investments		(29,227)		(1,530,760)		(167,556)		–		(1,727,543)
Proceeds from sale of property and equipment		–		210		2,871		–		3,081
Transfers from restricted cash		8,542		–		–		–		8,542
Other		(74)		(1,685)		6,459		–		4,700
Net cash used in investing activities		(20,759)		(1,532,235)		(158,226)		–		(1,711,220)
Financing activities:
Intercompany activities		(274,931)		464,114		(189,183)		–		–
Payments on current portion of long-term debt		(600)		–		–		–		(600)
Payments on revolving long-term debt		(2,134,550)		–		–		–		(2,134,550)
Borrowing under revolving long-term debt		2,377,950		–		–		–		2,377,950
Other Items		55,857		–		–		–		55,857
Net cash provided by (used in) financing activities		23,726		464,114		(189,183)		–		298,657
Effect of exchange rate changes on cash		–		–		412		–		412
Increase (decrease) in cash and cash equivalents		(29,535)		(5,988)		890		–		(34,633)
Cash and cash equivalents at beginning of year		47,491		5,988		104		–		53,583
Cash and cash equivalents at end of period	$	17,956	$	–	$	994	$	–	$	18,950
Nine months ended September 30, 2012:
Net cash provided by (used in) operating activities	$	(55,324)	$	915,885	$	331,916	$	–	$	1,192,477
Investing activities:
Capital investments		(38,946)		(1,452,061)		(132,744)		–		(1,623,751)
Proceeds from sale of property and equipment		144		169,149		31,868		–		201,161
Transfers to restricted cash		(167,774)		–		–		–		(167,774)
Transfers from restricted cash		40,700		–		–		–		40,700
Other		16,575		(24,340)		13,004		–		5,239
Net cash used in investing activities		(149,301)		(1,307,252)		(87,872)		–		(1,544,425)
Financing activities:
Intercompany activities		(148,027)		392,732		(244,705)		–		–
Payments on current portion of long-term debt		(600)		–		–		–		(600)
Payments on revolving long-term debt		(1,774,000)		–		–		–		(1,774,000)
Borrowings under revolving long-term debt		1,129,000		–		–		–		1,129,000
Proceeds from issuance of long-term debt		998,780		–		–		–		998,780
Other items		1,722		–		(11)		–		1,711
Net cash provided by (used in) financing activities		206,875		392,732		(244,716)		–		354,891
Effect of exchange rate changes on cash		–		–		(10)		–		(10)
Increase (decrease) in cash and cash equivalents		2,250		1,365		(682)		–		2,933
Cash and cash equivalents at beginning of year		14,711		–		916		–		15,627
Cash and cash equivalents at end of period	$	16,961	$	1,365	$	234	$	–	$	18,560

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Natural Gas and Oil Properties

9 Months Ended

Sep. 30, 2013

Natural Gas And Oil Properties [Abstract]

Natural Gas and Oil Properties

(5) NATURAL 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 on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, 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, net of taxes, discounted at 10 percent 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 average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.60 per MMBtu and $91.56 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at September 30, 2013. Cash flow hedges of natural gas production in place increased the ceiling value by $79.2 million, net of tax, at September 30, 2013.  Decreases in average quoted prices from September 30, 2013 levels as well as changes in production rates, levels of reserves, capitalized costs, the evaluation of costs excluded from amortization, future development costs, service costs and taxes could result in future ceiling test impairments.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.83 per MMBtu and $91.48 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $185.7 million (net of tax) at September 30, 2012 and resulted in a non-cash ceiling test impairment.  Cash flow hedges of natural gas production in place increased the ceiling by $330.6 million at September 30, 2012.  In the second quarter of 2012, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $496.4 million (net of tax) at June 30, 2012 and resulted in a non-cash ceiling test impairment.

All of the Company’s costs directly associated with the acquisition and evaluation of properties in Canada relating to its exploration program at September 30, 2013 were unproved and did not exceed the ceiling amount.  If the exploration program in Canada is unsuccessful on all or a portion of these properties, a ceiling test impairment may result in the future.

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Condensed Consolidating Financial Information (Condensed Consolidating Statement of Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Operating revenues	$ 868,366		$ 691,727		$ 2,464,056		$ 1,952,638
Gas purchases - midstream services	195,271		149,651		575,337		423,941
Operating expenses	90,269		61,906		236,648		179,478
General and administrative expenses	50,969		36,121		135,754		129,879
Depreciation, depletion and amortization	204,934		203,935		571,268		605,392
Impairment of natural gas and oil properties			289,821				1,090,473	[1]
Taxes, other than income taxes	17,694		16,252		58,543		51,154
Total operating costs and expenses	559,137		757,686		1,577,550		2,480,317
Operating Income (loss)	309,229		(65,959)		886,506		(527,679)	[2]
Other income (loss), net	(319)		238	[2]	(498)	[1]	2,615	[1]
Gain (Loss) on Derivatives	12,124	[1]	(5,879)	[1]	75,779		(10,593)
Interest expense	11,018		10,606		29,317	[1]	26,305	[1]
Income (Loss) before income taxes	310,016		(82,206)		932,470		(561,962)
Provision (benefit) for income taxes	124,149	[1]	(28,153)	[1]	373,457	[1]	(210,481)	[1]
Net income (loss)	185,867		(54,053)		559,013		(351,481)
Comprehensive income (loss)	139,179		(183,944)		457,967		(567,869)
Parent [Member]
Equity in earnings of subsidiaries	185,867		(54,053)		559,013		(351,481)
Income (Loss) before income taxes	185,867		(54,053)		559,013		(351,481)
Net income (loss)	185,867		(54,053)		559,013		(351,481)
Comprehensive income (loss)	139,179		(183,944)		457,967		(567,869)
Guarantors [Member]
Operating revenues	823,112		647,961		2,331,343		1,824,594
Gas purchases - midstream services	195,437		149,765		576,185		424,425
Operating expenses	140,400		106,293		375,721		311,165
General and administrative expenses	43,836		30,818		116,648		111,567
Depreciation, depletion and amortization	191,972		193,057		533,876		572,139
Impairment of natural gas and oil properties			289,821				1,090,473
Taxes, other than income taxes	15,348		13,513		50,053		42,159
Total operating costs and expenses	586,993		783,267		1,652,483		2,551,928
Operating Income (loss)	236,119		(135,306)		678,860		(727,334)
Other income (loss), net	145		216		67		(23)
Gain (Loss) on Derivatives	10,251		(5,879)		73,906		(10,593)
Interest expense	9,359		7,200		23,884		15,460
Income (Loss) before income taxes	237,156		(148,169)		728,949		(753,410)
Provision (benefit) for income taxes	91,466		(53,903)		291,795		(285,231)
Net income (loss)	145,690		(94,266)		437,154		(468,179)
Comprehensive income (loss)	98,102		(225,408)		337,122		(686,291)
Non-Guarantors [Member]
Operating revenues	130,998		121,343		379,212		350,064
Operating expenses	35,425		32,277		106,520		87,461
General and administrative expenses	7,155		6,102		19,164		20,700
Depreciation, depletion and amortization	12,962		10,878		37,392		33,253
Taxes, other than income taxes	2,346		2,739		8,490		8,995
Total operating costs and expenses	57,888		51,996		171,566		150,409
Operating Income (loss)	73,110		69,347		207,646		199,655
Other income (loss), net	(464)		22		(565)		2,638
Gain (Loss) on Derivatives	1,873				1,873
Interest expense	1,659		3,406		5,433		10,845
Income (Loss) before income taxes	72,860		65,963		203,521		191,448
Provision (benefit) for income taxes	32,683		25,750		81,662		74,750
Net income (loss)	40,177		40,213		121,859		116,698
Comprehensive income (loss)	40,811		41,210		120,045		117,660
Eliminations [Member]
Operating revenues	(85,744)		(77,577)		(246,499)		(222,020)
Gas purchases - midstream services	(166)		(114)		(848)		(484)
Operating expenses	(85,556)		(76,664)		(245,593)		(219,148)
General and administrative expenses	(22)		(799)		(58)		(2,388)
Total operating costs and expenses	(85,744)		(77,577)		(246,499)		(222,020)
Equity in earnings of subsidiaries	(185,867)		54,053		(559,013)		351,481
Income (Loss) before income taxes	(185,867)		54,053		(559,013)		351,481
Net income (loss)	(185,867)		54,053		(559,013)		351,481
Comprehensive income (loss)	$ (138,913)		$ 184,198		$ (457,167)		$ 568,631

[1] Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

[2] The operating loss for the E&P segment for the three and nine months ended September 30, 2012 includes a $289.8 million and $1,090.5 million non-cash ceiling test impairment of our natural gas and oil properties respectively.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Measurements [Abstract]

Carrying Amount and Estimated Fair Values of Financial Instruments

	September 30,				December 31,
	2013				2012
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in thousands)
Cash and cash equivalents	$	18,950	$	18,950	$	53,583	$	53,583
Restricted cash	$	–	$	–	$	8,542	$	8,542
Unsecured revolving credit facility	$	243,400	$	243,400	$	–	$	–
Senior notes	$	1,668,965	$	1,807,234	$	1,669,473	$	1,917,005
Derivative instruments	$	193,539	$	193,539	$	287,878	$	287,878

Summary Assets and Liabilities Measured at Fair Value on Recurring Basis

	September 30, 2013
	Fair Value Measurements Using:
	Quoted Prices		Significant
	in Active		Other		Significant
	Markets		Observable Inputs		Unobservable Inputs		Assets (Liabilities)
	(Level 1)		(Level 2)		(Level 3)		at Fair Value
Derivative assets	$	–	$	223,394	$	5,783	$	229,177
Derivative liabilities		–		(4,494)		(31,144)		(35,638)
Total	$	–	$	218,900	$	(25,361)	$	193,539
	December 31, 2012
	Fair Value Measurements Using:
	Quoted Prices		Significant
	in Active		Other		Significant
	Markets		Observable Inputs		Unobservable Inputs		Assets (Liabilities)
	(Level 1)		(Level 2)		(Level 3)		at Fair Value
Derivative assets	$	–	$	287,993	$	4,151	$	292,144
Derivative liabilities		–		–		(4,266)		(4,266)
Total	$	–	$	287,993	$	(115)	$	287,878

Assets and Liabilities Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3), Reconciliation

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Balance at beginning of period	$	(27,958)	$	106,222	$	(115)	$	182,119
Total gains (losses):
Included in earnings		4,617		53,465		(22,131)		177,201
Included in other comprehensive income		–		(57,614)		–		(135,055)
Purchases, issuances, and settlements:
Purchases		–		–		–		–
Issuances		–		–		–		–
Settlements		(2,020)		(55,112)		(3,115)		(177,304)
Transfers into/out of Level 3		–		–		–		–
Balance at end of period	$	(25,361)	$	46,961	$	(25,361)	$	46,961
Change in gains (losses) included in earnings relating to derivatives still held as of September 30	$	2,597	$	(1,647)	$	(25,246)	$	(103)

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Derivatives and Risk Management (Narratives) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Derivative [Line Items]
Accumulated other comprehensive income, net gain related to hedging activities	$ 72.1
Deferred income tax liability, accumulated other comprehensive income	48.1
Cash flow hedge after-tax net gain to be transferred from accumulated other comprehensive income to earnings during the next twelve months	68.6
Period of time needed to transfers net gain from accumulated other comprehensive income to earnings, months	12 months
Year 2013 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Basis Swaps Not Qualifying for Hedge Accounting Treatment	6,500,000,000
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	84,400,000,000
Year 2014 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Basis Swaps Not Qualifying for Hedge Accounting Treatment	16,700,000,000
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	232,700,000,000
Year 2015 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Basis Swaps Not Qualifying for Hedge Accounting Treatment	900,000,000
Volume of Natural Gas Production (in Bcf), Call Options Not Qualifying for Hedge Accounting Treatment	199,800,000,000
Not Designated as Hedging Instrument [Member] | Year 2014 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	181,600,000,000
Interest Rate Swaps [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Notional amount	$ 170

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Reclassifications From Accumulated Other Comprehensive Income

9 Months Ended

Sep. 30, 2013

Reclassifications From Accumulated Other Comprehensive Income [Abstract]

Reclassifications From Accumulated Other Comprehensive Income

(8) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME

The following tables detail the components of accumulated other comprehensive income and the related tax effects for the nine-months ended September 30, 2013:

	For the nine months ended
	September 30, 2013
	Gains and Losses on Cash Flow Hedges		Pension and Other Postretirement		Foreign Currency		Total
	(in thousands) (1)
Beginning balance, December 31, 2012	$	172,166	$	(22,311)	$	(51)	$	149,804
Other comprehensive income (loss) before reclassifications		29,600		–		(1,814)		27,786
Amounts reclassified from accumulated other comprehensive income (loss) (2)		(129,632)		800		–		(128,832)
Net current-period other comprehensive income (loss)		(100,032)		800		(1,814)		(101,046)
Ending balance, September 30, 2013	$	72,134	$	(21,511)	$	(1,865)	$	48,758

(1) All amounts are net-of-tax.

(2) See separate table below for details about these reclassifications.

The following table details the amounts reclassified from accumulated other comprehensive income into earnings for the nine-months ended September 30, 2013:

Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statement of Operations		Amount Reclassified from Accumulated Other Comprehensive Income
			For the nine months ended September 30, 2013
			(in thousands)
Gains (losses) on cash flow hedges
Settlements	Gas sales	$	218,236
Ineffectiveness	Gas sales		(2,183)
	Income before income taxes		216,053
	Provision for income taxes		86,421
	Net income	$	129,632
Pension and other postretirement
Amortization of prior service cost included in net periodic pension cost (1)	General and administrative expenses	$	(1,334)
	Loss before income taxes		(1,334)
	Benefit for income taxes		(534)
	Net loss	$	(800)
Total reclassifications for the period	Net income	$	128,832

(1) Included in the computation of net periodic pension cost (see footnote 13 for additional details.)  

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Inventory

9 Months Ended

Sep. 30, 2013

Inventory [Abstract]

Inventory

(4) INVENTORY

Inventory recorded in current assets includes $3.7 million at September  30, 2013 and $5.6 million at December 31, 2012 for natural gas in underground storage owned by the Company’s E&P segment, and $39.5 million at September  30, 2013 and $22.5 million at December 31, 2012 for tubular and other equipment used in the E&P segment.

Other long-term assets include $15.8 million at September  30, 2013 and $13.8 million at December 31, 2012, respectively, for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems for the Fayetteville Shale play.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash Flows From Operating Activities
Net income (loss)	$ 559,013	$ (351,481)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	574,221	608,167
Impairment of natural gas and oil properties		1,090,473	[1]
Deferred income taxes	373,055	(210,850)
Mark to market gain on derivatives	(72,664)	(892)
Stock-based compensation	8,883	8,226
Other	3,038	(1,686)
Change in assets and liabilities:
Accounts receivable	(67,070)	44,148
Inventories	(13,449)	16,608
Accounts payable	45,189	(11,050)
Taxes payable	(14,717)	(3,789)
Interest payable	(7,682)	(2,306)
Advances from partners	(65,481)	26,155
Other assets and liabilities	55,182	(19,246)
Net cash provided by operating activities	1,377,518	1,192,477
Cash Flows From Investing Activities
Capital investments	(1,727,543)	(1,623,751)
Proceeds from sale of property and equipment	3,081	201,161
Transfers to restricted cash		(167,774)
Transfers from restricted cash	8,542	40,700
Other	4,700	5,239
Net cash used in investing activities	(1,711,220)	(1,544,425)
Cash Flows From Financing Activities
Payments on current portion of long-term debt	(600)	(600)
Payments on revolving long-term debt	(2,134,550)	(1,774,000)
Borrowing under revolving long-term debt	2,377,950	1,129,000
Change in bank drafts outstanding	49,106	1,627
Proceeds from issuance of long-term debt		998,780
Debt issuance costs		(8,338)
Proceeds from exercise of common stock options	6,751	8,422
Net cash provided by financing activities	298,657	354,891
Effect of exchange rate changes on cash	412	(10)
Increase (decrease) in cash and cash equivalents	(34,633)	2,933
Cash and cash equivalents at beginning of year	53,583	15,627
Cash and cash equivalents at end of period	$ 18,950	$ 18,560

[1] Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

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Fair Value Measurements (Assets and Liabilities Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3), Reconciliation) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Fair Value Measurements [Abstract]
Balance at beginning of period	$ (27,958)	$ 106,222	$ (115)	$ 182,119
Total gains (losses): Included in earnings	4,617	53,465	(22,131)	177,201
Total gains or losses (realized/unrealized): Included in other comprehensive income		(57,614)		(135,055)
Purchases, issuances, and settlements:
Purchases
Issuances
Settlements	(2,020)	(55,112)	(3,115)	(177,304)
Balance at end of period	(25,361)	46,961	(25,361)	46,961
Change in gains (losses) included in earnings relating to derivatives still held as of September 30	$ 2,597	$ (1,647)	$ (25,246)	$ (103)

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Reclassifications From Accumulated Other Comprehensive Income (Components of AOCI And Related Tax Effects) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Beginning balance	$ 149,804	[1]
Other comprehensive income (loss) before reclassifications	27,786	[1]
Amounts reclassified from accumulated other comprehensive income (loss)	(128,832)	[1],[2]
Net current-period other comprehensive income (loss)	(101,046)	[1]
Ending balance	48,758	[1]
Gains and Losses on Cash Flow Hedges [Member]
Beginning balance	172,166	[1]
Other comprehensive income (loss) before reclassifications	29,600	[1]
Amounts reclassified from accumulated other comprehensive income (loss)	(129,632)	[1],[2]
Net current-period other comprehensive income (loss)	(100,032)	[1]
Ending balance	72,134	[1]
Pension and Other Postretirement [Member]
Beginning balance	(22,311)	[1]
Amounts reclassified from accumulated other comprehensive income (loss)	800	[1],[2]
Net current-period other comprehensive income (loss)	800	[1]
Ending balance	(21,511)	[1]
Foreign Currency [Member]
Beginning balance	(51)	[1]
Other comprehensive income (loss) before reclassifications	(1,814)	[1]
Net current-period other comprehensive income (loss)	(1,814)	[1]
Ending balance	$ (1,865)	[1]

[1] For the nine months endedSeptember 30, 2013Gains and Losses on Cash Flow HedgesPension and Other PostretirementForeign CurrencyTotal(in thousands) (1)Beginning balance, December 31, 2012$ 172,166 $ (22,311)$ (51)$ 149,804 Other comprehensive income (loss) before reclassifications 29,600  -   (1,814) 27,786 Amounts reclassified from accumulated other comprehensive income (loss) (2) (129,632) 800  -   (128,832)Net current-period other comprehensive income (loss) (100,032) 800  (1,814) (101,046)Ending balance, September 30, 2013$ 72,134 $ (21,511)$ (1,865)$ 48,758 All amounts are net-of-tax.

[2] See separate table below for details about these reclassifications.

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Pension Plan and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2013

Pension Plan And Other Postretirement Benefits [Abstract]

Net Periodic Pension and Other Postretirement Benefit Costs

	Pension Benefits
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Service cost	$	3,447	$	2,736	$	10,342	$	8,207
Interest cost		1,026		1,013		3,078		3,038
Expected return on plan assets		(1,534)		(1,356)		(4,602)		(4,069)
Amortization of prior service cost		25		71		77		214
Amortization of net loss		386		305		1,156		915
Net periodic benefit cost	$	3,350	$	2,769	$	10,051	$	8,305
	Postretirement Benefits
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Service cost	$	574	$	458	$	1,722	$	1,374
Interest cost		111		100		331		299
Amortization of transition obligation		–		16		–		48
Amortization of prior service cost		4		4		11		11
Amortization of net loss		30		23		90		69
Net periodic benefit cost	$	719	$	601	$	2,154	$	1,801

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Stock-Based Compensation (Summary of Stock Option Activity, Options Outstanding) (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Stock-Based Compensation [Abstract]
Stock options, Outstanding at December 31, 2012 Number of options	3,649,520
Stock options, Granted, Number of options	26,010
Stock options, Exercised, Number of options	(705,991)
Stock options, Forfeited or expired, Number of options	(55,756)
Stock options, Outstanding at September 30, 2013, Number of options	2,913,783
Stock options, Exercisable at September 30, 2013	1,699,151
Stock options, Outstanding at December 31, 2012 Weighted average exercise price	$ 29.84
Stock options, Granted, Weighted average exercise price	$ 38.76
Stock options, Exercised, Weighted average exercise price	$ 9.60
Stock options, Forfeited or expired, Weighted average exercise price	$ 37.47
Stock options, Outstanding at September 30, 2013, Weighted average exercise price	$ 34.68
Stock options Exercisable at September 30, 2013, Weighted average exercise price	$ 34.06

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies [Abstract]

Commitments and Contingencies

(11) COMMITMENTS AND CONTINGENCIES

Commitments

In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses require the Company to make certain capital investments in New Brunswick of approximately $47.0 millionin the aggregate over a three year period. In order to obtain the licenses, the Company provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate principal amount of$44.5 million Canadian dollars. The promissory notes secure the Company's capital expenditure obligations under the licenses and are returnable to the Company to the extent the Company performs such obligations. If the Company fails to fully perform, the Minister of Finance may retain a portion of the applicable promissory notes in an amount equal to any deficiency. The Company commenced its Canada exploration program in 2010 and, as of September 30, 2013 has invested $35.4 million in New Brunswick towards the Company’s commitment.  In December 2012, the Company received twoone-year extensions to our exploration license agreements which expire on March 16, 2014 and March 16, 2015, respectively.  No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of September 30, 2013 and its future investment plans.  

In response to the Company’s well performance, SES and SEPCO entered into new and amended natural gas transportation and gathering arrangements with third party pipelines, during the second quarter of 2013, in support of the Company’s production in the Marcellus Shale Play.  As of September 30, 2013,  the Company’s obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $3.4 billion and the Company has guarantee obligations of up to $100.0million of that amount.

Environmental Risk

The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued 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 effect on the financial position or reported results of operations of the Company.

Litigation

Tovah Energy

In February 2009, SEPCO was added as a defendant in a Third Amended Petition in the matter of Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al.  In the Sixth Amended Petition, filed in July 2010, in the 273rd District Court in Shelby County, Texas (collectively, the “Sixth Petition”), plaintiff alleged that, in 2005, they provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom.  Among other things, the plaintiff’s allegations in the Sixth Petition included various statutory and common law claims, including, but not limited to claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 2005 and February 2006.  In the Sixth Petition, plaintiff sought actual damages of over $55.0 million as well as other remedies, including special damages and punitive damages of four times the amount of actual damages established at trial.

Immediately before the commencement of the trial in November 2010, plaintiff was permitted, over SEPCO’s objections, to file a Seventh Amended Petition claiming actual damages of $46.0 million and also seeking the equitable remedy of disgorgement of all profits for the misappropriation of trade secrets and the breach of fiduciary duty claims. In December 2010, the jury found in favor of the plaintiff with respect to all of the statutory and common law claims and awarded $11.4 million in compensatory damages. The jury did not, however, award the plaintiff any special, punitive or other damages. In addition, the jury separately determined that SEPCO’s profits for purposes of disgorgement were $381.5 million. This profit determination does not constitute a judgment or an award. The plaintiff’s entitlement to disgorgement of profits as an equitable remedy will be determined by the judge and it is within the judge’s discretion to award none, some or all the amount of profit to the plaintiff.  In December 2010, the plaintiff filed a motion to enter the judgment based on the jury’s verdict.  In February 2011, SEPCO filed a motion for a judgment notwithstanding the verdict and a motion to disregard certain findings.  In March 2011, the plaintiff filed an amended motion for judgment and intervenor filed its motion for judgment seeking not only the monetary damages and the profits determined by the jury but also seeking, as a new remedy, a constructive trust for profits from 143 wells as well as future drilling and sales of properties in the prospect areas.  At the suggestion of the judge, all parties voluntarily agreed to participate in non-binding mediation efforts.  The mediation occurred in April 2011 and was unsuccessful. In June 2011, SEPCO received by mail a letter dated June 2011 from the judge, in which he made certain rulings with respect to the post-verdict motions and responses filed by the parties. In his rulings, the judge denied SEPCO’s motion for judgment, judgment notwithstanding the verdict and to disregard certain findings. Plaintiff’s and intervenor’s claim for a constructive trust was denied but the judge ruled that plaintiff and intervenor shall recover from SEPCO $11.4 million and a reasonable attorney’s fee of 40% of the total damages awarded and are entitled to recover on their claim for disgorgement.  The judge instructed that SEPCO calculate the profit on the designated wells for each respective period.  SEPCO performed the calculation and provided it to the judge in June 2011.  In July 2011, plaintiff and intervenor filed a letter with the court raising objections to the accounting provided by SEPCO, to which SEPCO filed a response in July 2011.  In July 2011, the judge sent a letter to the parties in which he ruled that after reviewing the parties’ respective position letters, he was awarding $23.9 million in disgorgement damages in favor of the plaintiff and intervenor.  In the July 2011 letter, the judge instructed the plaintiff and intervenor to prepare a judgment for his approval prior to July 2011 consistent with his findings in his June 2011 letter and the disgorgement award.  In August 2011, a judgment was entered pursuant to which plaintiff and intervenor are entitled to recover approximately $11.4 million in actual damages and approximately $23.9 million in disgorgement as well as prejudgment interest and attorneys' fees which currently are estimated to be up to $8.9 million and all costs of court of the plaintiff and intervenor.  In September 2011, SEPCO filed a motion for a new trial and in November 2011 filed a notice of appeal.  In November 2011, the court approved SEPCO’s supersedeas bond in the amount of $14.1 million, which stays execution on the judgment pending appeal.  The bond covers the $11.4 million judgment for actual damages, plus $1.3 million in pre-judgment interest, $1.3 million in post-judgment interest (estimating two years for the duration of appeal), and court costs. 

In June 2012, SEPCO filed its appellate brief and, in June 2012, plaintiff and intervenor filed a cross-appellate brief seeking limited remand to reassess the disgorgement determination. The parties filed their responses to the appellate and cross appellate briefs in November 2012.  Oral argument was held before the Tyler Court of Appeals on March 8, 2013.  On July 10, 2013, the Tyler Court of Appeals ordered that (1) the judgment awarding plaintiff and intervenor $23.9 million as disgorgement of illicit gains be reversed and judgment rendered that they take nothing, (2) the award of $11.4 million for actual damages, insofar as it is based on the jury’s findings of breach of fiduciary duty, fraud, breach of contract, and theft of trade secret is reversed and judgment rendered that plaintiff and intervenor take nothing under those theories of recovery, (3) the award of $11.4 million to plaintiff and intervenor as damages for misappropriation of trade secret is affirmed, (4) the case be remanded to the trial court for a determination and award of attorney’s fees for SEPCO as the prevailing party under the Texas Theft Liability Act, and (5) in all other respects, the judgment is affirmed.  On July 25, 2013, SEPCO filed its motion for rehearing with the Tyler Court of Appeals, seeking reversal of every part of plaintiff and intervenor’s recovery, and plaintiff and intervenor filed a court-ordered response.  Plaintiff and intervenor filed their own motion for rehearing, and to date SEPCO has not been ordered to respond. 

Based on the Company's understanding and judgment of the facts and merits of this case, including appellate defenses, and after considering the advice of counsel, the Company has determined that, although reasonably possible after exhaustion of all appeals, an adverse final outcome to this lawsuit is not probable.  As such, the Company has not accrued any amounts with respect to this lawsuit.  If the plaintiff and intervenor were to ultimately prevail in the appellate process, the Company currently estimates, based on the judgments to date, that SEPCO’s potential liability would be up to $45.5 million, including interest and attorney’s fees. The Company’s assessment may change in the future due to occurrence of certain events, such as denied appeals, and such re-assessment could lead to the determination that the potential liability is probable and could be material to the Company's results of operations, financial position or cash flows.

Bureau of Land Management

In March 2010, the Company’s subsidiary, SEECO, was served with a subpoena from a federal grand jury in Little Rock, Arkansas.  Based on the documents requested under the subpoena and subsequent discussions described below, the Company believes the grand jury is investigating matters involving approximately 27 horizontal wells operated by SEECO in Arkansas, including whether appropriate leases or permits were obtained therefore and whether royalties and other production attributable to federal lands have been properly accounted for and paid.  The Company believes it has fully complied with all requests related to the federal subpoena and delivered its affidavit to that effect. The Company and representatives of the Bureau of Land Management and the U.S. Attorney have had discussions since the production of the documents pursuant to the subpoena.  In January 2011, the Company voluntarily produced additional materials informally requested by the government arising from these discussions.  In September 2013, the U.S. Attorney’s Office requested additional information regarding this matter.  Although, to the Company’s knowledge, no proceeding in this matter has been initiated against SEECO, the Company cannot predict whether or when one might be initiated. The Company intends to fully comply with any further requests and to cooperate with any related investigation. No assurance can be made as to the time or resources that will need to be devoted to this inquiry or the impact of the final outcome of the discussions or any related proceeding.

Other

We are subject to various litigation, claims and proceedings that have arisen in the ordinary course of business. Management believes, individually or in aggregate, such litigation, claims and proceedings will not have a material adverse impact on our financial position, results of operations or cash flows 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, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.

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Derivatives and Risk Management

9 Months Ended

Sep. 30, 2013

Derivatives And Risk Management [Abstract]

Derivatives and Risk Management

(7) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas and crude oil which impacts the predictability of its cash flows related to the sale of natural gas and oil, and is exposed to volatility in interest rates. These risks are managed by the Company’s use of certain derivative financial instruments.  At September  30, 2013 and December 31, 2012, the Company’s derivative financial instruments consisted of fixed price swaps, basis swaps, fixed price call options, and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:

Fixed price swaps	The Company receives a fixed price for the contract and pays a floating market price to the counterparty.
Floating price swaps	The Company receives a floating market price from the counterparty and pays a fixed price.
Costless-collars	Arrangements that contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
Basis swaps	Arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.
Fixed price call options	The Company sells fixed price call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty such excess on sold fixed price call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Interest rate swaps	Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest-rate changes.

GAAP requires that all derivatives be recognized in the balance sheet as either an asset or liability and be measured at fair value. Under GAAP, certain criteria must be satisfied in order for derivative financial instruments to be classified and accounted for as either a cash flow or a fair value hedge. Accounting for qualifying hedges requires a derivative’s gains and losses to be recorded either in earnings as a component of the sale of natural gas and oil or as a component of other comprehensive income. Gains and losses on derivatives that are not elected for hedge accounting treatment or that do not meet hedge accounting requirements are recorded in earnings as a component of gain (loss) on derivatives.  Within the gain (loss) on derivatives component of the statement of operations are mark to market gain (loss) on derivatives and mark to market gain (loss) on derivatives, settled.  The Company calculates mark to market gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period reported.

The Company utilizes counterparties for its derivative instruments that it believes are credit-worthy at the time the transactions are entered into and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.

The balance sheet classification of the assets related to derivative financial instruments are summarized below at September  30, 2013 and December 31, 2012:

	Derivative Assets
	September 30, 2013			December 31, 2012
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Derivatives designated as hedging instruments:
Fixed price swaps	Hedging asset	$	115,039	Hedging asset	$	279,443
Fixed price swaps	Other long-term assets		5,951	Other long-term assets		8,550
Total derivatives designated as hedging instruments		$	120,990		$	287,993
Derivatives not designated as hedging instruments:
Basis swaps	Hedging asset	$	5,104	Hedging asset	$	3,250
Fixed price swaps	Hedging asset		77,504	Hedging asset		–
Basis swaps	Other long-term assets		679	Other long-term assets		901
Fixed price swaps	Other long-term assets		19,103	Other long-term assets		–
Interest rate swaps	Other long-term assets		5,797	Other long-term assets		–
Total derivatives not designated as hedging instruments		$	108,187		$	4,151
Total derivative assets		$	229,177		$	292,144
	Derivative Liabilities
	September 30, 2013			December 31, 2012
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Derivatives not designated as hedging instruments:
Basis swaps	Other current liabilities	$	164	Other current liabilities	$	138
Fixed price call options	Other long-term liabilities		30,980	Other long-term liabilities		4,128
Interest rate swaps	Other current liabilities		912	Other current liabilities		–
Interest rate swaps	Other long-term liabilities		3,582	Other long-term liabilities		–
Total derivatives not designated as hedging instruments		$	35,638		$	4,266
Total derivative liabilities		$	35,638		$	4,266

As of September  30, 2013, the Company had derivatives designated as cash flow hedges and derivatives not designated as hedges on the following volumes of natural gas production (in Bcf):

Year	Fixed price swaps	Fixed price swaps not designated for hedge accounting	Total
2013	84.4	-	84.4
2014	51.1	181.6	232.7

Cash Flow Hedges

The reporting of gains and losses on cash flow derivative hedging instruments depends on whether the gains or losses are effective at offsetting changes in the cash flows of the hedged item. The effective portion of the gains and losses on the derivative hedging instruments are recorded in other comprehensive income until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of the gains and losses from the derivative hedging instrument is recognized in earnings immediately.

As of September  30, 2013, the Company recorded a net gain in accumulated other comprehensive income related to its hedging activities of $72.1 million. This amount is net of a deferred income tax liability recorded as of September  30, 2013 of $48.1 million. The amount recorded in accumulated other comprehensive income will be relieved over time and recognized in the statement of operations as the physical transactions being hedged occur. Assuming the market prices of natural gas futures as of September  30, 2013 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of $68.6 million from accumulated other comprehensive income to earnings during the next 12 months. Gains or losses from derivative instruments designated as cash flow hedges are reflected as adjustments to gas sales in the unaudited condensed consolidated statements of operations. Volatility in earnings and other comprehensive income may occur in the future as a result of the Company’s derivative activities.

The following tables summarize the before tax effect of all cash flow hedges on the unaudited condensed consolidated financial statements for the three- and nine-month periods ended September  30, 2013 and 2012:

		Gain (Loss) Recognized in Other Comprehensive Income
		(Effective Portion)
		For the three months ended				For the nine months ended
		September 30,				September 30,
Derivative Instrument		2013		2012		2013		2012
		(in thousands)
Fixed price swaps		$	12,515	$	(55,039)	$	51,234	$	116,089
Costless-collars		$	–	$	(3,497)	$	–	$	40,644
	Classification of Gain	Gain Reclassified from Accumulated Other
	Reclassified from	Comprehensive Income into Earnings
	Accumulated Other	(Effective Portion)
	Comprehensive Income	For the three months ended				For the nine months ended
	into Earnings	September 30,				September 30,
Derivative Instrument	(Effective Portion)	2013		2012		2013		2012
		(in thousands)
Fixed price swaps	Gas sales	$	93,280	$	102,789	$	218,236	$	337,994
Costless-collars	Gas sales	$	–	$	54,489	$	–	$	175,531
		Gain (Loss) Recognized in Earnings
		(Ineffective Portion)
	Classification of Gain (Loss)	For the three months ended				For the nine months ended
	Recognized in Earnings	September 30,				September 30,
Derivative Instrument	(Ineffective Portion)	2013		2012		2013		2012
		(in thousands)
Fixed price swaps	Gas sales	$	(1,452)	$	(165)	$	(2,183)	$	1,831
Costless-collars	Gas sales	$	–	$	(373)	$	–	$	167

Fair Value Hedges and Other Derivative Contracts

For fair value hedges, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately.

Although the Company’s basis swaps meet the objective of managing commodity price exposure, these trades are typically not entered into concurrent with the Company’s derivative instruments that qualify as cash flow hedges and therefore do not generally qualify for hedge accounting. Basis swap derivative instruments that do not qualify as cash flow hedges are recorded on the balance sheet at their fair values under hedging assets, other long-term assets and other current liabilities, as applicable, and all gains and losses related to these contracts are recognized immediately in the unaudited condensed consolidated statements of operations as a component of gain (loss) on derivatives.  

As of September  30, 2013, the Company had basis swaps on natural gas production that did not qualify for hedge accounting treatment of 6.5 Bcf,16.7 Bcf, and 0.9 Bcf in 2013, 2014, and 2015, respectively.

As of September  30, 2013, the Company had fixed price call options on199.8 Bcf of 2015 natural gas production that did not qualify for hedge accounting treatment and fixed price swaps of 181.6 Bcf of 2014 natural gas production not designated for hedge accounting.

The Company is a party to an interest rate swap with counterparty banks. The interest rate swap was entered into in order to mitigate the Company’s exposure to volatility in interest rates related to its building lease. The interest rate swap has a notional amount of $170.0 million and expires on June 20, 2020. The Company did not designate the interest rate swap for hedge accounting.  Changes in the fair value of the interest rate swap are included in gain (loss) on derivatives in theunaudited condensed consolidated statements of operations.  The Company had no interest rate swaps in 2012. 

The following table summarizes the before tax effect of fair value hedges, fixed price call options that did not qualify for hedge accounting,fixed price swaps not designated for hedge accounting, basis swaps, and interest rate swaps not designated for hedge accounting on the unaudited condensed consolidated statements of operations for the three- and nine-month periods ended September  30, 2013 and 2012:

		Mark to Market Gain (Loss)
		on Derivatives
		Recognized in Earnings
	Income Statement	For the three months ended				For the nine months ended
	Classification of Mark to Market Gain (Loss)	September 30,				September 30,
Derivative Instrument	on Derivatives	2013		2012		2013		2012
		(in thousands)
Basis swaps	Gain (Loss) on Derivatives	$	(5,279)	$	(1,275)	$	1,606	$	(270)
Fixed price call options	Gain (Loss) on Derivatives	$	7,876	$	–	$	(26,852)	$	–
Fixed price swaps	Gain (Loss) on Derivatives	$	8,819	$	–	$	96,606	$	–
Interest rate swaps	Gain (Loss) on Derivatives	$	(1,312)	$	–	$	1,304	$	–
Fair value swaps	Gain (Loss) on Derivatives	$	–	$	136	$	–	$	1,162
		Mark to Market Gain (Loss)
		on Derivatives, Settled (1)
		Recognized in Earnings
	Income Statement	For the three months ended				For the nine months ended
	Classification of Mark to Market Gain (Loss)	September 30,				September 30,
Derivative Instrument	on Derivatives, Settled (1)	2013		2012		2013		2012
		(in thousands)
Basis swaps	Gain (Loss) on Derivatives	$	2,020	$	624	$	3,115	$	1,773
Fair value swaps	Gain (Loss) on Derivatives	$	–	$	(5,364)	$	–	$	(13,258)

(1)    The Company calculates mark to market gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period reported.  

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2013

Stock-Based Compensation [Abstract]

Stock-Based Compensation

(14) STOCK-BASED COMPENSATION

The Company recognized the following amounts in employee stock-based compensation costs for the three-and nine-months ended September  30, 2013 and 2012:

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Stock-based compensation cost – expensed	$	2,921	$	2,677	$	8,883	$	8,226
Stock-based compensation cost – capitalized	$	2,809	$	2,482	$	8,543	$	7,788

As of September  30, 2013, there was $38.2 million of total unrecognized compensation cost related to the Company’s unvested stock option and restricted stock grants. This cost is expected to be recognized over a weighted-average period of 2.3 years.

The following table summarizes stock option activity for the nine months ended September  30, 2013 and provides information for options outstanding as of September  30, 2013:

		Weighted
		Average
	Number	Exercise
	of Options	Price
Outstanding at December 31, 2012	3,649,520	$	29.84
Granted	26,010		38.76
Exercised	(705,991)		9.60
Forfeited or expired	(55,756)		37.47
Outstanding at September 30, 2013	2,913,783		34.68
Exercisable at September 30, 2013	1,699,151	$	34.06

The following table summarizes restricted stock activity for the nine months ended September 30, 2013 and provides information for unvested shares as of September 30, 2013:  

		Weighted
		Average
	Number	Grant Date
	of Shares	Fair Value
Unvested shares at December 31, 2012	1,117,515	$	35.64
Granted	32,346		37.53
Vested	(30,884)		36.19
Forfeited	(58,560)		35.77
Unvested shares at September 30, 2013	1,060,417	$	35.67

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Supplemental Disclosures of Cash Flow Information

9 Months Ended

Sep. 30, 2013

Supplemental Disclosures of Cash Flow Information [Abstract]

Supplemental Disclosures of Cash Flow Information

(12) SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Supplemental disclosures of cash flow information:

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Cash paid for interest	$	44,745	$	45,667	$	94,963	$	75,487
Cash paid for income taxes	$	1,330	$	400	$	18,636	$	468
Noncash property changes	$	(11,745)	$	(55,729)	$	34,437	$	(34,940)

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 29, 2013
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Entity Registrant Name	Southwestern Energy Co
Entity Central Index Key	0000007332
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		351,752,517
Trading Symbol	SWN
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes

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Pension Plan And Other Postretirement Benefits

9 Months Ended

Sep. 30, 2013

Pension Plan And Other Postretirement Benefits [Abstract]

Pension Plan and Other Postretirement Benefits

(13) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company has defined pension and postretirement benefit plans which cover substantially all of the Company’s employees. Net periodic pension and other postretirement benefit costs include the following components for the three-and nine-month periods ended September  30, 2013 and 2012:  

	Pension Benefits
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Service cost	$	3,447	$	2,736	$	10,342	$	8,207
Interest cost		1,026		1,013		3,078		3,038
Expected return on plan assets		(1,534)		(1,356)		(4,602)		(4,069)
Amortization of prior service cost		25		71		77		214
Amortization of net loss		386		305		1,156		915
Net periodic benefit cost	$	3,350	$	2,769	$	10,051	$	8,305
	Postretirement Benefits
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)
Service cost	$	574	$	458	$	1,722	$	1,374
Interest cost		111		100		331		299
Amortization of transition obligation		–		16		–		48
Amortization of prior service cost		4		4		11		11
Amortization of net loss		30		23		90		69
Net periodic benefit cost	$	719	$	601	$	2,154	$	1,801

As of September  30, 2013, the Company has contributed $9.0 million to the pension plan and $0.1 million to the postretirement benefit plan, and expects to contribute an additional $3.0 million to the pension plan in 2013.

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are presented as treasury stock and totaled 14,625 shares at September  30, 2013 compared to 64,715 shares at December 31, 2012.

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Segment Information (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012		Dec. 31, 2012
Revenues from external customers	$ 868,366,000		$ 691,727,000		$ 2,464,056,000		$ 1,952,638,000
Intersegment revenues	601,812,000		409,563,000		1,744,126,000		1,086,135,000
Operating income (loss)	309,229,000		(65,959,000)		886,506,000		(527,679,000)	[1]
Other income (loss), net	(319,000)		238,000	[1]	(498,000)	[2]	2,615,000	[2]
Gain (loss) on Derivatives	12,124,000	[2]	(5,879,000)	[2]	75,779,000		(10,593,000)
Depreciation, depletion and amortization expense	204,934,000		203,935,000		571,268,000		605,392,000
Impairment of natural gas and oil properties			289,821,000				1,090,473,000	[2]
Interest expense	11,018,000		10,606,000		29,317,000	[2]	26,305,000	[2]
Provision (benefit) for income taxes	124,149,000	[2]	(28,153,000)	[2]	373,457,000	[2]	(210,481,000)	[2]
Assets	7,894,388,000	[2]	7,356,562,000	[2],[3]	7,894,388,000	[2]	7,356,562,000	[2],[3]	6,737,527,000
Capital investments	542,109,000		424,886,000		1,755,058,000	[3]	1,586,631,000	[3]
Change in accrued expenditures	14,600,000		56,200,000		25,800,000		40,700,000
Intersegment revenues for marketing company's E&P sales	515,300,000		332,100,000		1,493,800,000		863,700,000
Capital investment related to companys E&P segment related to Canada for September 30, 2012 and 2011	11,900,000		2,200,000		19,800,000		6,900,000
Assets related to E&P program in Canada	64,800,000		36,400,000		64,800,000		36,400,000
Exploration and Production [Member]
Revenues from external customers	621,833,000		499,083,000		1,748,821,000		1,400,749,000
Intersegment revenues	644,000		(982,000)		3,817,000		(1,716,000)
Operating income (loss)	222,692,000		(141,865,000)		650,996,000		(745,533,000)	[1]
Other income (loss), net	143,000		213,000	[1]	61,000	[2]	(34,000)	[2]
Gain (loss) on Derivatives	10,885,000	[2]	(5,879,000)	[2]	74,540,000		(10,593,000)
Depreciation, depletion and amortization expense	191,860,000		192,994,000		533,577,000		571,934,000
Impairment of natural gas and oil properties			289,821,000				1,090,473,000	[2]
Interest expense	8,580,000		6,707,000		21,101,000	[2]	14,459,000	[2]
Provision (benefit) for income taxes	87,779,000	[2]	(55,220,000)	[2]	282,231,000	[2]	(289,875,000)	[2]
Assets	6,264,845,000	[2]	5,854,055,000	[2],[3]	6,264,845,000	[2]	5,854,055,000	[2],[3]
Capital investments	496,331,000		385,585,000		1,602,885,000	[3]	1,450,569,000	[3]
Midstream Services [Member]
Revenues from external customers	246,501,000		192,619,000		715,155,000		551,796,000
Intersegment revenues	601,104,000		409,720,000		1,740,132,000		1,085,392,000
Operating income (loss)	86,658,000		75,488,000		235,854,000		216,598,000	[1]
Other income (loss), net	70,000		27,000	[1]	(27,000)	[2]	4,000	[2]
Gain (loss) on Derivatives	1,232,000	[2]			1,232,000
Depreciation, depletion and amortization expense	12,970,000		10,620,000		37,377,000		32,499,000
Interest expense	2,294,000		3,659,000		7,682,000	[2]	10,904,000	[2]
Provision (benefit) for income taxes	36,671,000	[2]	27,006,000	[2]	91,785,000	[2]	78,268,000	[2]
Assets	1,387,765,000	[2]	1,158,638,000	[2],[3]	1,387,765,000	[2]	1,158,638,000	[2],[3]
Capital investments	40,052,000		31,693,000		135,425,000	[3]	105,576,000	[3]
Other [Member]
Revenues from external customers	32,000		25,000		80,000		93,000
Intersegment revenues	64,000		825,000		177,000		2,459,000
Operating income (loss)	(121,000)		418,000		(344,000)		1,256,000	[1]
Other income (loss), net	(532,000)		(2,000)	[1]	(532,000)	[2]	2,645,000	[2]
Gain (loss) on Derivatives	7,000	[2]			7,000
Depreciation, depletion and amortization expense	104,000		321,000		314,000		959,000
Interest expense	144,000		240,000		534,000	[2]	942,000	[2],[4]
Provision (benefit) for income taxes	(301,000)	[2]	61,000	[2]	(559,000)	[2]	1,126,000	[2],[4]
Assets	241,778,000	[2],[4]	343,869,000	[2],[3]	241,778,000	[2],[4]	343,869,000	[2],[3]
Capital investments	5,726,000		7,608,000		16,748,000	[3]	30,486,000	[3]
Parent [Member]
Assets	$ 5,538,128,000				$ 5,538,128,000				$ 4,809,628,000

[1] The operating loss for the E&P segment for the three and nine months ended September 30, 2012 includes a $289.8 million and $1,090.5 million non-cash ceiling test impairment of our natural gas and oil properties respectively.

[2] Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

[3] Capital investments includes decreases of $14.6 million and $56.2 million for the three-month periods ended September 30, 2013 and 2012, respectively, and increase of $25.8 million and decrease of $40.7 million for the nine-month periods ended September 30, 2013 and 2012, respectively, relating to the change in accrued expenditures between periods.

[4] Other assets represent corporate assets not allocated to segments and assets, including restricted cash and investments in cash equivalents, for non reportable segments.

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Stock-Based Compensation (Summary of Restricted Stock Activity and Unvested Shares) (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Stock-Based Compensation [Abstract]
Restricted Stock, Unvested shares at December 31, 2012 Number of Shares	1,117,515
Restricted Stock, Granted, Number of Shares	32,346
Restricted Stock, Vested, Number of Shares	(30,884)
Restricted Stock, Forfeited, Number of Shares	(58,560)
Restricted Stock, Unvested shares at September 30, 2013, Number of Shares	1,060,417
Restricted Stock, Unvested shares at December 31, 2012 Weighted Average Grant Date Fair Value	$ 35.64
Restricted Stock, Granted, Weighted Average Grant Date Fair Value	$ 37.53
Restricted Stock, Vested, Weighted Average Grant Date Fair Value	$ 36.19
Restricted Stock, Forfeited, Weighted Average Grant Date Fair Value	$ 35.77
Restricted Stock, Unvested shares at September 30, 2013, Weighted Average Grant Date Fair Value	$ 35.67