Southwestern Energy (SWN) 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 24, 2014	Jun. 28, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
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	'	352,930	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$12,840,843,498
Trading Symbol	'SWN	'	'

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating Revenues:	'		'		'
Gas sales	$2,381,478		$1,956,311		$2,078,151
Gas marketing	792,165		591,528		714,123
Oil sales	16,420		8,427		9,085
Gas gathering	181,082		173,727		149,973
Total Operating Revenues	3,371,145		2,729,993		2,951,332
Operating Costs and Expenses:	'		'		'
Gas purchases - midstream services	781,626		592,466		709,091
Operating expenses	328,503		244,735		240,944
General and administrative expenses	191,310		175,147		158,041
Depreciation, depletion and amortization	786,612		810,953		704,511
Impairment of natural gas and oil properties	'		1,939,734		'
Taxes, other than income taxes	79,471		67,584		65,518
Total operating costs and expenses	2,167,522		3,830,619		1,878,105
Operating Income (Loss)	1,203,623		-1,100,626	[1]	1,073,227
Interest Expense:	'		'		'
Interest on debt	100,051		93,296		65,421
Other interest charges	4,355		4,454		4,306
Interest capitalized	-62,812		-62,093		-45,652
Total Interest Expense	41,594	[2]	35,657	[2]	24,075	[2]
Other Income, Net	2,207		1,030		264
Gain (Loss) on Derivatives	26,141		-14,950		1,574
Income (Loss) Before Income Taxes	1,190,377		-1,150,203		1,050,990
Provision (Benefit) for Income Taxes:	'		'		'
Current	-11,071		18,689		4,198
Deferred	497,945		-461,828		409,023
Total provision for income taxes	486,874	[2]	-443,139	[2]	413,221	[2]
Net Income (Loss)	$703,503		($707,064)		$637,769
Earnings (Loss) Per Share:	'		'		'
Basic	$2.01		($2.03)		$1.84
Diluted	$2		($2.03)		$1.82
Weighted Average Common Shares Outstanding:	'		'		'
Basic	350,465,430		348,610,503		347,205,316
Effect Of:	'		'		'
Stock Options	377,626		'		2,475,053
Restricted Stock Awards	258,396		'		241,044
Diluted	351,101,452		348,610,503		349,921,413
[1]	The operating loss for the E&P segment for the twelve months ended December 31, 2012 includes a $1,939.7 million non-cash ceiling test impairment of our natural gas and oil properties.
[2]	Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	'		'		'
Net income (loss)	$703,503		($707,064)		$637,769
Change in derivatives:	'		'		'
Reclassification to earnings	-185,506	[1]	-382,156	[1]	-194,693	[1]
Ineffectiveness	991	[2]	-1,474	[2]	2,518	[2]
Change in fair value of derivative instruments	21,619	[3]	130,935	[3]	520,552	[3]
Total change in derivatives	-162,896		-252,695		328,377
Change in value of pension and other postretirement liabilities:	'		'		'
Current period net gain (loss)	11,673	[4]	-7,466	[4]	-4,129	[4]
Less: amortization of prior service cost included in net periodic pension cost	1,080		1,008		766
Total change in value of pension and other postretirement liabilities	12,753	[5]	-6,458	[5]	-3,363	[5]
Change in currency translation adjustment	-4,003		529		-561
Comprehensive income (loss)	$549,357		($965,688)		$962,222
[1]	Net of ($123.7), ($249.4), and ($126.6) million in taxes for the years ended December 31, 2013, 2012 and 2011, respectively.
[2]	Net of $0.7, ($1.0), and $1.6 million in taxes for the years ended December 31, 2013, 2012 and 2011, respectively.
[3]	Net of $16.3, $85.1, and $338.4 million in taxes for the years ended December 31, 2013, 2012 and 2011, respectively.
[4]	Net of $7.5, ($4.9), and ($2.7) million in taxes for the years ended December 31, 2013, 2012 and 2011, respectively.
[5]	Net of $0.7, $0.7, and $0.5 million in taxes for the years ended December 31, 2013, 2012, and 2011, respectively.

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	'	'	'
Reclassification to earnings tax	($123.70)	($249.40)	($126.60)
Ineffectiveness tax	0.7	-1	1.6
Change in fair value of derivative instruments tax	16.3	85.1	338.4
Current period net gain (loss) tax	7.5	-4.9	-2.7
Amortization of prior service cost included in net periodic pension cost tax	$0.70	$0.70	$0.50

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'		'
Cash and cash equivalents	$22,938		$53,583
Restricted cash	'		8,542
Accounts receivable	464,045		377,638
Inventories	37,745		28,141
Derivative asset	70,871		282,693
Other current assets	48,576		58,315
Total current assets	644,175		808,912
Property and Equipment:	'		'
Natural gas and oil properties, using the full cost method, including $956.5 million in 2013 and $1,023.9 million in 2012 excluded from amortization	13,293,841		11,283,114
Gathering systems	1,306,074		1,148,261
Other	702,544		597,064
Less: Accumulated depreciation, depletion and amortization	-8,005,836		-7,191,463
Total property and equipment, net	7,296,623		5,836,976
Other long-term assets	106,928		91,639
TOTAL ASSETS	8,047,726		6,737,527
Current liabilities:	'		'
Accounts payable	507,468		459,569
Taxes payable	68,019		62,980
Interest payable	33,485		34,431
Advances from partners	'		68,919
Current deferred income taxes	24,353		106,123
Other current liabilities	54,686		35,749
Total current liabilities	688,011		767,771
Long-term debt	1,950,096		1,668,273
Deferred income taxes	1,532,329		1,049,138
Pension and other postretirement liabilities	15,823		33,174
Other long-term liabilities	239,437		183,299
Total long-term liabilities	3,737,685		2,933,884
Commitments and contingencies	'		'
Equity:	'		'
Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 352,938,584 shares in 2013 and 351,100,391 in 2012	3,529		3,511
Additional paid-in capital	970,524		934,939
Retained earnings	2,652,653		1,949,150
Accumulated other comprehensive income	-4,342	[1]	149,804	[1]
Common stock in treasury, 9,924 shares in 2013 and 64,715 in 2012	-334		-1,532
Total equity	3,622,030		3,035,872
TOTAL LIABILITIES AND EQUITY	$8,047,726		$6,737,527
[1]	All amounts are net of tax.

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified
CONDENSED CONSOLIDATED BALANCE SHEETS	'	'
Natural gas and oil properties, using the full cost method, costs excluded from amortization	$956.50	$1,023.90
Common Stock, Par Value	$0.01	$0.01
Common Stock, Authorized, Shares	1,250,000,000	1,250,000,000
Common Stock, Issued, Shares	352,938,584	351,100,391
Common Stock in Treasury, Shares	9,924,000	64,715,000

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows From Operating Activities	'	'	'
Net income (loss)	$703,503	($707,064)	$637,769
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	790,553	814,710	707,966
Impairment of natural gas and oil properties	'	1,939,734	'
Deferred income taxes	497,945	-461,828	409,023
(Gain) loss on derivatives, net of settlement	-21,380	2,154	-5,600
Stock-based compensation	13,270	11,795	10,550
Other	-91	-619	6,310
Change in assets and liabilities:	'	'	'
Accounts receivable	-86,134	-35,717	9,659
Inventories	-5,851	18,111	-12,975
Accounts payable	74,229	41,275	11,490
Taxes payable	5,040	22,289	-9,360
Interest payable	-377	5,058	610
Advances from partners	-68,918	-15,163	2,377
Tax benefit for stock-based compensation	'	'	-14,626
Other assets and liabilities	6,739	19,207	-13,376
Net cash provided by operating activities	1,908,528	1,653,942	1,739,817
Cash Flows From Investing Activities	'	'	'
Capital investments	-2,252,647	-2,107,755	-2,184,474
Proceeds from sale of property and equipment	18,163	201,101	154,526
Transfers to restricted cash	8,542	-167,788	-85,055
Transfers from restricted cash	'	159,246	85,055
Other	10,166	8,519	5,158
Net cash used in investing activities	-2,215,776	-1,906,677	-2,024,790
Cash Flows From Financing Activities	'	'	'
Payments on current portion of long-term debt	-1,200	-1,200	-1,200
Payments on revolving long-term debt	-3,147,750	-2,263,900	-3,445,900
Borrowings under revolving long-term debt	3,430,650	1,592,400	3,696,200
Change in bank drafts outstanding	-7,174	-35,608	24,637
Proceeds from issuance of long-term debt	'	998,780	'
Debt issuance costs	'	-8,339	'
Credit Facility costs	-6,150	'	-10,211
Proceeds from exercise of common stock options	9,801	9,184	6,412
Tax benefit for stock-based compensation	'	'	14,626
Other	-978	-428	-261
Net cash provided by financing activities	277,199	290,889	284,303
Effect of exchange rate changes on cash	-596	-198	242
Increase (decrease) in cash and cash equivalents	-30,645	37,956	-428
Cash and cash equivalents at beginning of year	53,583	15,627	16,055
Cash and cash equivalents at end of year	$22,938	$53,583	$15,627

CONSOLIDATED_STATEMENT_OF_CHAN

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (USD $)	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Common Stock in Treasury	Total
In Thousands, unless otherwise specified
Balance at Dec. 31, 2010	$3,477	$862,423	$2,018,445	$83,975	($3,444)	$2,964,876
Balance, shares at Dec. 31, 2010	347,734	'	'	'	'	'
Comprehensive income (loss):	'	'	'	'	'	'
Net income (loss)	'	'	637,769	'	'	637,769
Other comprehensive income (loss)	'	'	'	324,453	'	324,453
Comprehensive income (loss)	'	'	'	'	'	962,222
Tax benefit for stock-based compensation	'	14,626	'	'	'	14,626
Stock-based compensation	'	19,036	'	'	'	19,036
Exercise of stock options	9	6,403	'	'	'	6,412
Issuance of restricted stock, shares	851	'	'	'	'	'
Issuance of restricted stock	5	-5	'	'	'	'
Cancellation of restricted stock, shares	532	'	'	'	'	'
Cancellation of restricted stock	'	1	'	'	'	1
Tax withholding - stock compensation, shares	-52	'	'	'	'	'
Tax withholding - stock compensation	'	-262	'	'	'	-262
Issuance of stock awards, shares	-7	'	'	'	'	'
Issuance of stock awards	-1	-42	'	'	'	-42
Treasury stock - non-qualified plan	'	1,135	'	'	1,216	2,351
Balance at Dec. 31, 2011	3,491	903,399	2,656,214	408,428	-2,228	3,969,304
Balance, shares at Dec. 31, 2011	349,059	'	'	'	'	'
Comprehensive income (loss):	'	'	'	'	'	'
Net income (loss)	'	'	-707,064	'	'	-707,064
Other comprehensive income (loss)	'	'	'	-258,624	'	-258,624
Comprehensive income (loss)	'	'	'	'	'	-965,688
Stock-based compensation	'	22,212	'	'	'	22,212
Exercise of stock options, shares	1,607	'	'	'	'	'
Exercise of stock options	16	9,168	'	'	'	9,184
Issuance of restricted stock, shares	539	'	'	'	'	'
Issuance of restricted stock	5	-5	'	'	'	'
Cancellation of restricted stock, shares	-95	'	'	'	'	'
Cancellation of restricted stock	-1	1	'	'	'	'
Tax withholding - stock compensation, shares	-11	'	'	'	'	'
Tax withholding - stock compensation	'	-393	'	'	'	-393
Issuance of stock awards, shares	1	'	'	'	'	'
Issuance of stock awards	'	44	'	'	'	44
Treasury stock - non-qualified plan	'	513	'	'	696	1,209
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 (loss)	'	'	703,503	'	'	703,503
Other comprehensive income (loss)	'	'	'	-154,146	'	-154,146	[1]
Comprehensive income (loss)	'	'	'	'	'	549,357
Stock-based compensation	'	25,502	'	'	'	25,502
Exercise of stock options, shares	834	'	'	'	'	'
Exercise of stock options	8	10,088	'	'	'	10,096
Issuance of restricted stock, shares	1,103	'	'	'	'	'
Issuance of restricted stock	11	-11	'	'	'	'
Cancellation of restricted stock, shares	-74	'	'	'	'	'
Cancellation of restricted stock	-1	1	'	'	'	'
Tax withholding - stock compensation, shares	-25	'	'	'	'	'
Tax withholding - stock compensation	'	-978	'	'	'	-978
Issuance of stock awards, shares	1	'	'	'	'	'
Issuance of stock awards	'	49	'	'	'	49
Treasury stock - non-qualified plan	'	934	'	'	1,198	2,132
Balance at Dec. 31, 2013	$3,529	$970,524	$2,652,653	($4,342)	($334)	$3,622,030
Balance, shares at Dec. 31, 2013	352,939	'	'	'	'	'
[1]	All amounts are net of tax.

Organization_and_Summary_of_Si

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Information [Abstract]	'
Organization and Summary of Significant Accounting Policies	'
	(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Nature of Operations
	Southwestern Energy Company (including its subsidiaries, collectively, “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 principally focused within the United States on development of an unconventional gas reservoir in Arkansas, 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, Arkansas, and Oklahoma in the Arkoma Basin. We have commenced exploration operations in Arkansas and Louisiana testing an unconventional oil play targeting the Lower Smackover Brown Dense. In 2010, we commenced an exploration program in New Brunswick, Canada, which represents our first operations outside of the United States.  Southwestern’s natural gas gathering and marketing (Midstream Services) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania and Texas.
	Basis of Presentation
	The consolidated financial statements included in this Annual Report on Form 10-K present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.  The Company evaluates subsequent events through the date the financial statements are issued.
	Certain reclassifications have been made to the prior year’s financial statements to conform to the 2013 presentation.  The effects of the reclassifications were not material to the Company’s consolidated financial statements.
	Principles of Consolidation
	The consolidated financial statements include the accounts of Southwestern and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
	Revenue Recognition
	Natural gas and oil sales. Natural gas sales and oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, natural gas sales and oil sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas sales and oil sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. As of December 31, 2013, the Company had overproduction of 11.2 Bcf valued at $37.9 million and underproduction of 12.5 Bcf valued at $38.5 million. At December 31, 2012, the Company had overproduction of 8.4 Bcf valued at $28.4 million and underproduction of 9.4 Bcf valued at $29.9 million.
	Gas marketing. The Company generally markets its natural gas, as well as some gas produced by third parties, to brokers, local distribution companies and end-users, pursuant to a variety of contracts. Gas marketing revenues are recognized when delivery of natural gas has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured.
	Gas gathering. In certain areas the Company gathers its natural gas, as well as some natural gas produced by third parties, pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured.
	Other. The Company maintains an underground gas storage facility and generally sells natural gas from its storage facility during the winter gas withdrawal season. Revenue is recognized on natural gas storage sales when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. Other revenues, a component of gas sales, include a gain of $1.0 million in 2013, and losses of $0.9 million in 2012 and 2011, respectively, primarily related to the sale of natural gas in underground storage.
	Cash and Cash Equivalents
	Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash.  Management considers cash and cash equivalents to have minimal credit and market risk.
	Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $4.9 million and $12.1 million as of December 31, 2013 and 2012, respectively.
	Restricted Cash
	Restricted cash represents proceeds deposited by the Company with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.
	Inventory
	Inventory recorded in current assets includes $3.7 million as of December 31, 2013 and $5.6 million at December 31, 2012, for natural gas in underground storage owned by the Company’s E&P segment, and $34.1 million as of December 31, 2013 and $22.5 million at December 31, 2012 for tubulars and other equipment used in the E&P segment.
	The Company has one natural gas storage facility. The current portion of the natural gas classified in inventory and carried at the lower of cost or market totaled $3.7 million as of December 31, 2013. The non-current portion of the natural gas classified in property and equipment and carried at cost totaled $16.0 million as of December 31, 2013. The carrying value of the non-current natural gas is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Withdrawals of current natural gas in underground storage are accounted for by a weighted average cost method whereby natural gas withdrawn from storage is relieved at the weighted average cost of current natural gas remaining in the facility.
	Other assets include $15.1 million as of December 31, 2013 and $13.8 million at December 31, 2012 for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems.
	Tubulars and other equipment are carried at the lower of cost or market and are accounted for by a moving weighted average cost method that is applied within specific classes of inventory items. Purchases of inventory are recorded at cost and inventory is relieved at the weighted average cost of items remaining within a specified class.
	Property, Depreciation, Depletion and Amortization
	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 properties. 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 discounted at 10% 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 $3.67 per MMBtu, West Texas Intermediate oil of $93.42 per barrel, and NGLs of $43.45 per barrel, 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 December 31, 2013. Cash flow hedges of natural gas production in place increased this ceiling amount by approximately $70.7 million, net of tax, as of December 31, 2013.  At December 31, 2012, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.76 per MMBtu for Henry Hub natural gas and West Texas Intermediate oil of $91.21 per barrel. At December 31, 2011, the ceiling value of the Company’s reserves was calculated based upon average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.12 per MMBtu for Henry Hub natural gas and for West Texas Intermediate oil of $92.71.  Using the first-day-of-the-month prices of natural gas for the first two months of 2014 and NYMEX strip prices for the remainder of 2014, as applicable, the prices required to be used to determine the ceiling limit is not expected to result in a ceiling test write-down in 2014.  Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments. During 2012, the net capitalized costs of our natural gas and oil properties exceeded the ceiling by approximately $1,192.4 million (net of tax) and resulted in a non-cash ceiling test impairment.
	All of our costs directly associated with the acquisition and evaluation of properties in Canada relating to our exploration program as of December 31, 2013 and as of December 31, 2012 were unproved and did not exceed the ceiling amount.  If our exploration program in Canada is unsuccessful on all or a portion of these properties, or if further extensions are not granted, if requested, a ceiling test impairment may result in the future.
	Gathering Systems. The Company’s investment in gathering systems is primarily related to its Fayetteville Shale assets in Arkansas and the Marcellus Shale assets in Pennsylvania.  These assets are being depreciated on a straight-line basis over 25 years.
	Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and actively being evaluated.
	Asset Retirement Obligations.  An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company owns natural gas and oil properties, which require expenditures to plug and abandon the wells and reclaim the associated pads when reserves in the wells are depleted.
	Income Taxes
	The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
	The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.
	Derivative Financial Instruments
	The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses commodity fixed price swaps and fixed price options contracts to hedge sales of natural gas. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas sales if designated for hedge accounting treatment or gain (loss) on derivative if not designated for hedge accounting treatment in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item.  In contrast, gains and losses from the ineffective portion of fixed price swaps designated for hedge accounting treatment are recognized currently in gas sales in the consolidated statement of operations. Gains and losses from the ineffective portion of fixed price swaps not designated for hedge accounting treatment, interest rate swaps, fixed price call options, and basis swaps that were not designated for hedge accounting treatment are recognized in gain (loss) on derivatives in the consolidated statement of operations. Changes in the fair value of derivative instruments designated as fair value hedges as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately.  See Note 5 and Note 7 for a discussion of the Company’s hedging activities.
	Earnings Per Share
	Basic earnings per common share is computed by dividing net income (loss) attributable to Southwestern by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding the incremental shares that would have been outstanding assuming the exercise of dilutive stock options and the vesting of unvested restricted shares of common stock.  Antidilutive is an increase in earnings per share or reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities, as defined by GAAP.
	For the year ended December 31, 2013, outstanding options for 1,569,665 shares with an average exercise price of $28.03 were included in the calculation of diluted shares. Options for 1,634,695 shares were excluded from the calculation because they would have had an antidilutive effect. As we recognized a net loss for the year ended December 31, 2012, the unvested stock options were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. Options for 1,716,109 shares were excluded from the calculation of diluted shares because they would have had an antidilutive effect.  For the year ended December 31, 2011, outstanding options for 3,577,104 shares with an average price of $11.78 were included in the calculation of diluted shares. Options for 881,254 shares were excluded from the calculation because they would have had an antidilutive effect.
	For the year ended December 31, 2013, 258,396 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 114,433 shares of restricted stock because they would have had an antidilutive effect. As we recognized a net loss for the year ended December 31, 2012, the unvested share-based payments were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. The calculation of diluted shares excluded 602,429 shares of restricted because they would have had an antidilutive effect. For the year ended December 31, 2011, 241,044 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 135,352 shares of restricted stock because they would have had an antidilutive effect.
	Supplemental Disclosures of Cash Flow Information
	Supplemental disclosures of cash flow information (in thousands):
		For the years ended December 31,
		2013		2012		2011
		(in thousands)
	Cash paid during the year for interest, net of amounts	$	36,267	$	17,311	$	19,159
	capitalized
	Cash paid during the year for income taxes		18,787		818		4,198
	Increase (decrease) in noncash property additions		-12,730		-26,240		30,389
	Stock-Based Compensation
	The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.
	Treasury Stock
	The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liability of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust and are presented as treasury stock and carried at cost. As of December 31, 2013, 9,924 shares were accounted for as treasury stock, compared to 64,715 shares at December 31, 2012.
	Foreign Currency Translation
	We have designated the Canadian dollar as the functional currency for our operations in Canada.  The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of stockholders' equity.
	New Accounting Standards Implemented in this Report
	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 about Offsetting Assets and Liabilities, issued in December 2011. Update 2013-01 clarifies that the scope of the disclosures under U.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and 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 requires an entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to provide the 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.
	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, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated 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 respective line 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 December 15, 2012, with early adoption permitted.  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.

Acquisitions_And_Divestitures

Acquisitions And Divestitures	12 Months Ended
	Dec. 31, 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 closed the acquisition during the second quarter of 2013 and accounted for it as an asset acquisition.
	In May 2012, we sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $164 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 our net proved reserves were approximately 143.0 Bcfe at December 31, 2011.

Prepaid_Expenses

Prepaid Expenses	12 Months Ended
	Dec. 31, 2013
Prepaid Expenses [Abstract]	'
Prepaid Expenses	'
	(3) PREPAID EXPENSES
	The components of prepaid expenses included in other current assets as of December 31, 2013 and 2012 consisted of the following:
		2013		2012
			(in thousands)
	Prepaid drilling costs	$	9,560	$	30,101
	Prepaid insurance		7,619		9,507
	Prepaid taxes		13,624		572
	Total	$	30,803	$	40,180

Natural_Gas_And_Oil_Properties

Natural Gas And Oil Properties (Unaudited)	12 Months Ended
	Dec. 31, 2013
Natural Gas And Oil Properties [Abstract]	'
Natural Gas And Oil Properties	'
	(4) NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
	The Company’s natural gas and oil properties are located in the United States and Canada.
	Net Capitalized Costs
	The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortization as of December 31, 2013 and 2012:
		2013					2012
		(in thousands)
	Proved properties	$	12,337,372				$	10,259,226
	Unproved properties		956,469	-1				1,023,888	-1
	Total capitalized costs		13,293,841					11,283,114
	Less:  Accumulated depreciation, depletion and amortization		7,481,335					6,774,174
	Net capitalized costs	$	5,812,506				$	4,508,940
	(1) Includes $72.3 and $40.4 million related to our exploration program in Canada as of December 31, 2013 and 2012, respectively.
	Oil and gas properties not subject to amortization represent investments in unproved properties and major development projects in which we own an interest. These unproved property costs include unevaluated costs associated with leasehold or drilling interests and unevaluated costs associated with wells in progress.  The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2013.
		2013			2012			2011			Prior			Total
		(in thousands)
	Property acquisition costs	$	147,791		$	81,889		$	221,451		$	109,994		$	561,125	-1
	Exploration and development costs		166,725			48,428			47,784			38,858			301,795	-1
	Capitalized interest		7,792			11,067			38,145			36,545			93,549	-1
		$	322,308		$	141,384		$	307,380		$	185,397		$	956,469
	(1)Property acquisition costs include $35.0 million, exploration costs include $31.8 million and capitalized interest includes $5.5 million related to our exploration program in Canada.
	Of the total net unevaluated costs excluded from amortization as of December 31, 2013,  approximately $23.1 million is related to unevaluated seismic costs in the Fayetteville Shale, approximately $39.0 million is related to acquisition of undeveloped properties in the Company’s Fayetteville Shale, approximately $195.7 million is related to acquisition of undeveloped properties in the Company’s Marcellus Shale and approximately $275.8 million is related to acquisition of undeveloped properties in the Company’s New Ventures, excluding our exploration program in Canada. The Company has $72.3 million of unevaluated costs related to its exploration program in Canada. Additionally, the Company has approximately $220.7 million of unevaluated costs related to costs of wells in progress. The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of drilling, and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.
	Costs Incurred in Natural Gas and Oil Exploration and Development
	The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities:
		2013				2012					2011
		(in thousands, except per Mcfe amounts)
	Proved property acquisition costs	$	572			$	–				$	17
	Unproved property acquisition costs		168,404	-1			220,822		-1			262,886		-1
	Exploration costs		192,164	-2			197,280		-2			63,419		-2
	Development costs		1,662,138				1,492,841					1,633,784
	Capitalized costs incurred		2,023,278				1,910,943					1,960,106
	Full cost pool amortization per Mcfe	$	1.08			$	1.31				$	1.30
		-1		Includes $17.1 million, $3.6 million and $0.2 million, in 2013, 2012 and 2011, respectively, related to our exploration program in Canada.
		-2		Includes $11.5 million, $2.5 million and $18.4 million in 2013, 2012 and 2011, respectively, related to our exploration program in Canada.
	Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $61.6 million, $62.1 million and $43.4 million during 2013, 2012 and 2011, respectively, based on the Company’s weighted average cost of borrowings used to finance expenditures.
	In addition to capitalized interest, the Company capitalized internal costs totaling $262.2 million, $236.5 million and $207.9 million during 2013, 2012 and 2011, respectively, that were directly related to the acquisition, exploration and development of the Company’s natural gas and oil and oil properties  Included in these amounts are internal costs from the Company’s subsidiaries involved with vertical integration of the Company’s exploration and development activities and totaled $104.3 million, $81.7 million and $51.3 million during 2013, 2012 and 2011, respectively.  All internal costs are included in the Company’s cost of natural gas and oil properties.
	Results of Operations from Natural Gas and Oil Producing Activities
	The table below sets forth the results of operations from natural gas and oil producing activities:
		2013			2012			2011
		(in thousands)
	Sales	$	2,404,165		$	1,963,172		$	2,098,914
	Production (lifting) costs		-628,817			-505,271			-469,153
	Depreciation, depletion and amortization		-735,215			-765,192			-666,107
	Impairment of natural gas and oil properties		–			-1,939,734			–
			1,040,133			-1,247,025			963,654
	Provision (benefit) for income taxes		416,042			-496,738			375,435
	Results of operations (1)	$	624,091		$	-750,287		$	588,219
	(1) Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments.  See Note 5 Derivatives and Risk Management.
	The results of operations shown above exclude general and administrative expenses, and interest expense and are not necessarily indicative of the contribution made by our natural gas and oil operations to the Company’s consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.
	Natural Gas and Oil Reserve Quantities
	The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates.  NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties and accounted for approximately 95%,  93% and 90% of the present worth of the Company’s total proved reserves as of December 31, 2013, 2012 and 2011, respectively. A reserve audit is not the same as a financial audit and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves. Reserve estimates are inherently imprecise and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available. For more information over reserves, refer to the table titled “Changes in Proved Undeveloped Reserves (Bcfe)” in “Business – Exploration and Production” in Item 1 of this Form 10-K.
	The following table summarizes the changes in the Company’s proved natural gas and oil reserves for 2013, 2012 and 2011 all of which were located in the United States:
		2013				2012				2011
		Natural				Natural				Natural
		Gas		Oil		Gas		Oil		Gas			Oil
		(MMcf)		(MBbls)		(MMcf)		(MBbls)		(MMcf)			(MBbls)
	Proved reserves, beginning of year	4,016,798		244		5,887,207		996		4,929,980			1,219
	Revisions of previous estimates	325,374		88		-2,087,985		-44		34,505			-125
	Extensions, discoveries and other additions	3,283,495		229		918,594		154		1,459,428			2
	Production	-655,704		-188		-564,484		-83		-499,433			-97
	Acquisition of reserves in place	4,114		–		–		–		13			–
	Disposition of reserves in place	–		–		-136,534		-779		-37,286			-3
	Proved reserves, end of year	6,974,077		373		4,016,798		244		5,887,207			996
	Proved developed reserves:
Beginning of year	3,195,662		243		3,254,018		983		2,687,238			1,173
End of year	4,237,495		372		3,195,662		243		3,254,018			983
Proved undeveloped reserves:
Beginning of year	821,136		1		2,633,189		13		2,242,742			46
End of year	2,736,582		1		821,136		1		2,633,189			13
The significant revision of previous estimates in 2012 was primarily due to price revision, as a result of lower average natural gas prices in 2012.  The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil.
Standardized Measure of Discounted Future Net Cash Flows
The following standardized measures of discounted future net cash flows relating to proved natural gas and oil reserves as of December 31, 2013, 2012 and 2011 are calculated after income taxes and discounted using a 10% annual discount rate and do not purport to present the fair market value the Company’s proved gas and oil reserves:
	2013			2012			2011
	(in thousands)
Future cash inflows	$	22,624,562		$	9,570,652		$	22,012,205
Future production costs		-8,895,956			-4,737,297			-8,080,207
Future development costs		-3,626,496			-711,050			-3,425,185
Future income tax expense		-3,223,271			-745,251			-3,366,175
Future net cash flows		6,878,839			3,377,054			7,140,638
10% annual discount for estimated timing of cash flows		-3,142,795			-1,326,389			-3,689,838
Standardized measure of discounted future net cash flows	$	3,736,044		$	2,050,665		$	3,450,800
Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves.  Prices used for the standardized measure above were $3.67 per MMBtu for natural gas and $93.42 per barrel for oil in 2013, $2.76 per MMBtu for natural gas and $91.21 per barrel for oil in 2012, and $4.12 per MMBtu for natural gas and $92.71 per barrel for oil in 2011. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits.
Following is an analysis of changes in the standardized measure during 2013, 2012 and 2011:
	2013			2012			2011
	(in thousands)
Standardized measure, beginning of year	$	2,050,665		$	3,450,800		$	3,013,750
Sales and transfers of natural gas and oil produced, net of production costs		-1,774,043			-1,443,606			-1,632,156
Net changes in prices and production costs		1,852,772			-2,604,591			-381,131
Extensions, discoveries, and other additions, net of future production and development costs		1,454,634			549,601			1,163,992
Acquisition of reserves in place		4,914			–			30
Sales of reserves in place		–			-157,108			-11,761
Revisions of previous quantity estimates		348,996			-1,109,409			34,221
Accretion of discount		232,385			480,315			426,245
Net change in income taxes		-1,119,798			1,079,158			-103,643
Changes in estimated future development costs		-196,394			2,475,470			70,492
Previously estimated development costs incurred during the year		222,982			61,949			564,894
Changes in production rates (timing) and other		658,931			-731,914			305,867
Standardized measure, end of year	$	3,736,044		$	2,050,665		$	3,450,800

Derivatives_and_Risk_Managemen

Derivatives and Risk Management	12 Months Ended
	Dec. 31, 2013
Derivatives And Risk Management [Abstract]	'
Derivatives and Risk Management	'
	(5) DERIVATIVES AND RISK MANAGEMENT
	The Company is exposed to volatility in market prices and basis differentials for natural gas and oil which impacts the predictability of its cash flows related to the sale of natural gas and oil. These risks are managed by the Company’s use of certain derivative financial instruments.  As of December 31, 2013 and 2012, the Company’s derivative financial instruments consisted of 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.
	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 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 gains (losses) on derivatives, net of settlement and gains (losses) on derivatives, settled. The Company calculates gains (losses) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.
	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 derivative financial instruments are summarized below as of December 31, 2013 and 2012:
			Derivative Assets
			31-Dec-13				31-Dec-12
			Balance Sheet Classification		Fair Value		Balance Sheet Classification		Fair Value
			(in thousands)
	Derivatives designated as hedging
	instruments:
	Fixed price swaps		Derivative asset		$	20,631	Derivative asset		$	279,443
	Fixed price swaps		Other long-term assets			–	Other long-term assets			8,550
	Total derivatives designated as hedging				$	20,631			$	287,993
	instruments
	Derivatives not designated as hedging
	instruments:
	Basis swaps		Derivative asset		$	12,858	Derivative asset		$	3,250
	Fixed price swaps		Derivative asset			37,382	Derivative asset			–
	Basis swaps		Other long-term assets			107	Other long-term assets			901
	Interest rate swaps		Other long-term assets			7,525	Other long-term assets			–
	Total derivatives not designated as				$	57,872			$	4,151
	hedging instruments
	Total derivative assets				$	78,503			$	292,144
			Derivative Liabilities
			31-Dec-13				31-Dec-12
			Balance Sheet Classification		Fair Value		Balance Sheet Classification		Fair Value
			(in thousands)
	Derivatives designated as hedging
	instruments:
	Fixed price swaps		Other current liabilities		$	3,884	Other current liabilities		$	–
	Total derivatives designated as hedging				$	3,884			$	–
	instruments
	Derivatives not designated as hedging
	instruments:
	Basis swaps		Other current liabilities		$	1,501	Other current liabilities		$	138
	Fixed price swaps		Other current liabilities			185	Other current liabilities			–
	Fixed price call options		Other long-term liabilities			30,388	Other long-term liabilities			4,128
	Interest rate swaps		Other current liabilities			1,520	Other current liabilities			–
	Interest rate swaps		Other long-term liabilities			3,012	Other long-term liabilities			–
	Total derivatives not designated as				$	36,606			$	4,266
	hedging instruments
	Total derivative liabilities				$	40,490			$	4,266
	As of December 31, 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
	2014	200.7	181.6	382.3
	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 recognized in earnings immediately.
	As of December 31, 2013, the Company recorded a gain in accumulated other comprehensive income related to its hedging activities of $9.3 million net of a deferred income tax liability of $6.2 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 December 31, 2013 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of approximately $9.3 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 natural gas sales in the consolidated statements of operations. Natural gas sales included a realized gain from settled contracts of $309.2 million for the year ended December 31, 2013 compared to a realized gain of $631.5 million for the year ended December 31, 2012. Volatility in net income, comprehensive income and accumulated 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 consolidated financial statements for the years ended December 31, 2013 and 2012.
						Gain Recognized in Other Comprehensive Income
						Comprehensive Income
						(Effective Portion)
					For the years ended
					December 31,
	Derivative Instrument				2013		2012
					(in thousands)
	Fixed price swaps				$	37,931	$	178,660
Costless-collars				$	–	$	39,247
		Classification of Gain		Gain Reclassified from Accumulated Other Comprehensive Income into Earnings
		Reclassified from Accumulated		(Effective Portion)
		Other Comprehensive Income		For the years ended
		into Earnings		December 31,
Derivative Instrument		(Effective Portion)		2013		2012
				(in thousands)
Fixed price swaps		Gas Sales		$	309,177	$	413,410
Costless-collars		Gas Sales		$	–	$	218,119
				Gain (Loss) Recognized in Earnings
				(Ineffective Portion)
		Classification of Gain (Loss)		For the years ended
		Recognized in Earnings		December 31,
Derivative Instrument		(Ineffective Portion)		2013		2012
				(in thousands)
Fixed price swaps		Gas Sales		$	-1,652	$	2,450
Costless-collars		Gas Sales		$	–	$	-24
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 are not designated for hedge accounting are recorded on the balance sheet at their fair values under derivative assets, other assets, other current liabilities, and other long-term liabilities, as applicable and all gains and losses related to these contracts are recognized immediately in the consolidated statements of operations as a component of gain (loss) on derivatives.
As of December 31, 2013, the Company had basis swaps on natural gas production that were not designated for hedge accounting of 21.3 Bcf for 2014 and 0.9 Bcf for 2015.
As of December 31, 2013, the Company had fixed price call options on 199.8 Bcf of 2015 natural gas production not designated 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 interest rate swaps with counterparty banks. The interest rate swaps were entered into in order to mitigate the Company’s exposure to volatility in interest rates related to construction of its new corporate office complex. The interest rate swaps build to a notional amount of $170.0 million and expire on June 20, 2020. The Company did not designate the interest rate swaps for hedge accounting. Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives in the consolidated statements of operations. The Company had no interest rate swaps in 2012.
The following tables summarizes the before tax effect of fair value hedges, fixed price call options and basis swaps that were not designated for hedge accounting, and fixed price swaps and interest rate swaps not designated for hedge accounting on the uncondensed consolidated statements of operations for the years ended December 31, 2013 and 2012.
				Gain (Loss) on Derivatives,
				net of settlement
				Recognized in Earnings
		Consolidated Statement of Operations		For the years ended
		Classification of Gain (Loss) on		December 31,
Derivative Instrument		Derivatives, net of settlement		2013		2012
				(in thousands)
Basis swaps		Gain (Loss) on Derivatives		$	7,450	$	766
Fixed price call options		Gain (Loss) on Derivatives			-26,259		-4,128
Fixed price swaps		Gain (Loss) on Derivatives			37,197		–
Fair value swaps		Gain (Loss) on Derivatives			–		1,208
Interest rate swaps		Gain (Loss) on Derivatives			2,992		–
				Gain (Loss)
				on Derivatives, Settled (1)
				Recognized in Earnings
		Consolidated Statement of Operations		For the years ended
		Classification of Gain (Loss)		December 31,
Derivative Instrument		on Derivatives, Settled (1)		2013		2012
				(in thousands)
Basis swaps		Gain (Loss) on Derivatives		$	4,772	$	2,162
Fair value swaps		Gain (Loss) on Derivatives			–		-14,958
Interest rate swaps		Gain (Loss) on Derivatives			-11		–
(1) The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.

Reclassification_From_Accumula

Reclassification From Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2013
Reclassification From Accumulated Other Comprehensive Income [Abstract]	'
Reclassification From Accumulated Other Comprehensive Income	'
	(6) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME
	The following tables detail the components of accumulated other comprehensive income, amounts reclassified from accumulated other comprehensive income into earnings and the related tax effects for the year ended December 31, 2013:
			For the year ended
			31-Dec-13
			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			21,619			–		-4,003		17,616
	Amounts reclassified (2)			-184,515			12,753		–		-171,762
	Net current-period other comprehensive income (loss)			-162,896			12,753		-4,003		-154,146
	Ending balance, December 31, 2013		$	9,270		$	-9,558	$	-4,054	$	-4,342
		-1		All amounts are net of tax.
		-2		See separate table below for details about these reclassifications.
	Details about Accumulated Other Comprehensive Income		Consolidated Statement of Operations Classification
					(in thousands)
	Gains (losses) on cash flow hedges
	Settlements		Gas sales	$	309,177
	Ineffectiveness		Gas sales		-1,652
			Income before income taxes		307,525
			Provision for income taxes		123,010
			Net income	$	184,515
	Pension and other postretirement
	Amortization of prior service cost included in		General and administrative expenses	$	-21,009
	net periodic pension cost (1)
			Loss before income taxes		-21,009
			Benefit for income taxes		-8,256
			Net loss	$	-12,753
	Total reclassifications for the period		Net income	$	171,762
		-1		Included in the computation of net periodic pension cost (see Note 12 for additional details).

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements [Abstract]	'
Fair Value Measurements	'
	(7) FAIR VALUE MEASUREMENTS
	The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2013 and 2012 were as follows:
		31-Dec-13									31-Dec-12
		Carrying					Fair				Carrying				Fair
		Amount					Value				Amount				Value
		(in thousands)
	Cash and cash equivalents	$		22,938			$		22,938			$	53,583	$		53,583
	Restricted cash	$		–			$		–			$	8,542	$		8,542
	Credit facility	$		282,900			$		282,900			$	–	$		–
	Senior notes	$		1,668,396			$		1,795,935			$	1,669,473	$		1,917,005
	Derivative instruments, net	$		38,013			$		38,013			$	287,878	$		287,878
	The carrying values of cash and cash equivalents, accounts receivable, accounts payable, other current assets and current liabilities on the 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 2.6% as of December 31, 2013 and 2.6% at December 31, 2012, and its 4.10% Senior Notes due 2022, which was 4.2% as of December 31, 2013. The carrying values of the borrowings under the Company’s unsecured Credit Facility 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.
	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 and floating-price swaps and are estimated using third-party discounted cash flow calculations using the NYMEX futures index. The Company’s Level 3 fair value measurements include costless-collars, basis swaps and fixed price call options. The Company’s costless-collars and 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 third party discounted cash flow calculations based upon forward commodity price curves.
	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 result in an increase (decrease) in fair value measurement, respectively.
	Assets and liabilities measured at fair value on a recurring basis are summarized below (in thousands):
			31-Dec-13
			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		$	–	$	65,538		$	12,965	$	78,503
	Derivative liabilities			–		-8,601			-31,889		-40,490
	Total		$	–	$	56,937		$	-18,924	$	38,013
			31-Dec-12
			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 years ended December 31, 2013 and 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 reasonable assumptions a marketplace participant would have used as of December 31, 2013 and at December 31, 2012.
	Total net gains and losses for Level 3 derivatives for the years ended December 31, 2013 and 2012 are provided below:
			For the years ended
			December 31,
			2013		2012
			(in thousands)
	Balance at beginning of period		$	-115	$	182,119
	Total gains or losses (realized/unrealized):
	Included in earnings			-14,037		216,857
	Included in other comprehensive income			–		-178,847
	Purchases, issuances, and settlements:
	Purchases			–		–
	Issuances			–		–
	Settlements			-4,772		-220,244
	Transfers into/out of Level 3			–		–
	Balance at end of period		$	-18,924	$	-115
	Change in unrealized gains included in earnings relating to derivatives still held as of December 31		$	-18,809	$	-3,362

Debt

Debt	12 Months Ended
	Dec. 31, 2013
Debt [Abstract]	'
Debt	'
	(8) DEBT
	The components of debt as of December 31, 2013 and 2012 consisted of the following:
			2013		2012
			(in thousands)
	Short-term debt:
	7.15% Senior Notes due 2018		$	1,200	$	1,200
	Total short-term debt (1)			1,200		1,200
	Long-term debt:
	Variable rate (1.64%  and 2.20% at December 31, 2013 and December 31, 2012,			282,900		–
	respectively) Credit Facility, expires December 2018
	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			28,200		29,400
	7.5% Senior Notes due 2018			600,000		600,000
	4.10% Senior Notes due 2022			1,000,000		1,000,000
	Unamortized discount			-1,004		-1,127
	Total long-term debt			1,950,096		1,668,273
	Total debt		$	1,951,296	$	1,669,473
	(1) Short-term debt is included in Other current liabilities.
	The following is a summary of scheduled long-term debt maturities by year as of December 31, 2013 (in thousands):
	2015		1,200
	2016		1,200
	2017		41,200
	2018		907,500
	Thereafter		1,000,000
		$	1,951,100
	Credit Facility
	On December 16, 2013, the Company entered into a Credit Agreement (“Credit Facility”), that exchanged our previous revolving credit facility.  Under the Credit Facility, we have a borrowing capacity of $2.0 billion. The Credit Facility has a maturity date of December 2018 and options for two one-year extensions with participating lender approval.  The amount available under the Credit Facility may be increased by $500.0 million upon the Company’s agreement with its participating lenders. The interest rate on the Credit Facility is calculated based upon our credit rating and is currently 150 basis points over the current London Interbank Offered Rate, or LIBOR. The borrowing rate on our previous revolving credit facility was 200 basis points over LIBOR as of December 31, 2012 and throughout 2013 until it was exchanged. The Credit Facility is unsecured and is not guaranteed by any subsidiaries of the Company.  Contemporaneously with the execution of the Credit Agreement, on December 16, 2013, the Company obtained subsidiary guarantee releases under the 7.15%, 7.5%, 7.35%, 7.125% and 4.10% Senior Notes and our former credit facility.  The Credit Facility contains covenants which impose certain restrictions on the Company, including a financial covenant whereby the Company may not issue total debt in excess of 60%  of its total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the noncontrolling interest in equity, the effects of non-cash entries that result from any full cost ceiling impairments (beginning in the year ended December 31, 2011), certain hedging activities and our pension and other postretirement liabilities. As of December 31, 2013, the Company was in compliance with the covenants of its Credit Facility and other debt agreements.  Although 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.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies [Abstract]	'
Commitments and Contingencies	'
	(9) COMMITMENTS AND CONTINGENCIES
	Operating Commitments and Contingencies
	The Company has commitments to third parties for demand transportation charges. As of December 31, 2013, future payments under non-cancelable firm transportation charges are approximately $362.8 million in 2014, $399.2 million in 2015, $413.2 million in 2016, $375.7 million in 2017, $363.3 million in 2018 and $1,594.7 million thereafter.
	The Company has 11 leases for pressure pumping equipment for its E&P operations under leases that expire between December 1, 2017 and January 1, 2018.  The Company’s current aggregate annual payment under the leases is approximately $7.5 million. The lease payments for the pressure pumping equipment, as well as other operating expenses for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings to third-party working interest owners for their share of fracture stage charges.
	The Company leases compressors, aircraft, vehicles, office space and equipment under non-cancelable operating leases expiring through 2027.  As of December 31, 2013, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $65.2 million in 2014, $55.9 million in 2015, $44.6 million in 2016, $27.8 million in 2017, $10.8 million in 2018 and $24.9 million thereafter. The Company also has commitments for compression services related to its Midstream Services and E&P segments. As of December 31, 2013, future minimum payments under these non-cancelable agreements are approximately $38.6 million in 2014, $24.5 million in 2015, $17.2 million in 2016, $9.2 million in 2017, $3.7 million in 2018 and $0.7 million thereafter.
	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. As of December 31, 2013, the Company’s obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $3.5 billion and the Company has guarantee obligations of up to $100.0 million of that amount.
	In 2013, we started construction on a corporate office complex located in Spring, Texas on 26 acres of commercial land that we purchased in 2012.  The Company financed the construction of this complex through a construction agreement and lease arrangement.  We are currently obligated for the construction costs incurred, which approximated $38 million at December 31, 2013.  Upon completion of construction, a lease term of approximately five years will commence.
	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 million Canadian dollars in the aggregate over the license periods. 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 December 31, 2013 has invested $39.2 million Canadian dollars, or $36.9 million USD, in New Brunswick towards the Company’s commitment. In December 2012, the Company received two one-year extensions to our exploration licenses which expire on March 2014 and March 2015, respectively. No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of December 31, 2013 and its future investment plans.
	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 results of operations of the Company.
	Litigation
	Tovah Energy
	In February 2009, SEPCO was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al., pending in the 273rd District Court in Shelby County, Texas.  By the time of trial in December 2010, Ms. Berry-Helfand  (the only remaining plaintiff) alleged that, in 2005, she 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, she alleged 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.  She also sought disgorgement of SEPCO’s profits.  A former associate of the plaintiff intervened in the matter claiming to have helped develop the prospect years earlier.
	The jury found in favor of the plaintiff and the intervenor with respect to all of the statutory and common law claims and awarded $11.4 million in compensatory damages but no special, punitive or other damages. Separately, the jury determined that SEPCO’s profits for purposes of disgorgement, if ordered as a remedy, were $381.5 million.  (Disgorgement of profits is an equitable remedy determined by the judge, and it is within the judge’s discretion to award none, some or all of unlawfully obtained profits.)   In August 2011, a judgment was entered pursuant to which the plaintiff and the intervenor were 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.
	Both sides appealed and in July 2013, the Tyler Court of Appeals ordered that (1) the judgment awarding the plaintiff and the 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 the plaintiff and the intervenor take nothing under those theories of recovery, (3) the award of $11.4 million to the plaintiff and the 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.  All parties petitioned for rehearing.  The Tyler Court of Appeals denied rehearing in November 2013.
	SEPCO filed a petition for review in the Supreme Court of Texas in February 2014.  The plaintiff and the intervenor have until March 2014 to file petitions for review.  Based on the Company’s understanding and judgment of the facts and merits of this case, including appellate matters, and after considering the advice of counsel, the Company has determined that, although reasonably possible, a materially adverse final outcome to this action is not probable.  As such, the Company has not accrued any amounts with respect to this action.  If the plaintiff and the intervenor were to prevail ultimately 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. If the Supreme Court declines to hear the case or affirms all aspects of the court of appeals’ judgment, then SEPCO would owe the $11.4 million in damages, plus interest and attorneys fees, offset by any award of attorneys’ fees for its prevailing on the theft count. The Company’s assessment may change in the future due to occurrence of certain events, such as the result of the petition or petitions for review at the Supreme Court of Texas, and such a 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 with representatives of the Bureau of Land Management and the U.S. Attorney, the Company believed the grand jury was investigating matters involving approximately 27 horizontal wells operated by SEECO in Arkansas, including whether appropriate leases or permits were obtained therefrom and whether royalties and other production attributable to federal lands were properly accounted for and paid.  In January 2014, the U.S. Attorney’s office informed SEECO’s outside counsel that no criminal charges will be brought.  Two wells were drilled, in part, through federal lands without having obtained leases at the time of drilling, and SEECO has paid full royalties as if those leases were in place from first production of the wells. The Government has made a formal demand for additional damages for trespass; however, because these actions were not deliberate and SEECO voluntarily reported this to the Bureau of Land Management at the time the error was discovered, the Company does not believe additional damages should be assessable or that such additional damages, if any, would be material.
	Other
	The Company is subject to various litigation, claims and proceedings that have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties and pollution, contamination or nuisance. Management believes that such litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows.  Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and all subject to inherent uncertainties; therefore, 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 the Company’s financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated.
	Indemnifications
	The Company provides certain indemnifications in relation to dispositions of assets.  These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. No liability has been recognized in connection with these indemnifications.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Taxes [Abstract]	'
Income Taxes	'
	(10) INCOME TAXES
	The provision (benefit) for income taxes included the following components:
			2013		2012		2011
		(in thousands)
	Current:
	Federal	$	-12,151	$	15,500	$	3,378
	State		1,080		3,189		820
			-11,071		18,689		4,198
	Deferred:
	Federal		409,359		-388,209		345,922
	State		87,823		-71,582		60,941
	Foreign		763		-2,037		2,160
			497,945		-461,828		409,023
	Provision (benefit) for income taxes	$	486,874	$	-443,139	$	413,221
	The provision for income taxes was an effective rate of 40.9% in 2013,  38.5% in 2012  and 39.3% 2011. The following reconciles the provision for income taxes included in the consolidated statements of operations with the provision which would result from application of the statutory federal tax rate to pre-tax financial income:
			2013		2012		2011
		(in thousands)
	Expected provision (benefit) at federal statutory rate	$	416,632	$	-402,571	$	367,854
	Increase (decrease) resulting from:
	State income taxes, net of federal income tax effect		53,130		-44,454		40,145
	Nondeductible expenses		3,404		2,100		1,244
	Other		13,708		1,786		3,978
	Provision (benefit) for income taxes	$	486,874	$	-443,139	$	413,221
	The components of the Company’s net deferred tax liability as of December 31, 2013 and 2012 were as follows:
			2013		2012
		(in thousands)
	Deferred tax liabilities:
	Differences between book and tax basis of property	$	2,114,685	$	1,441,149
	Cash flow hedges		13,171		112,625
	Other		10,715		4,460
			2,138,571		1,558,234
	Deferred tax assets:
	Accrued compensation		15,718		16,387
	Alternative minimum tax credit carryforward		76,864		89,016
	Stored natural gas		9,272		7,812
	Accrued pension costs		1,821		7,686
	Asset retirement obligations		53,419		39,249
	Net operating loss carryforward		411,994		217,276
	Differences between book and tax basis of property - state		11,045		16,872
	Other		7,405		12,354
			587,538		406,652
	Net deferred tax liability	$	1,551,033	$	1,151,582
	The net deferred tax liability as of December 31, 2013 was comprised of net long-term deferred income tax liabilities of $1,526.7 million in addition to a net current deferred income tax liability of $24.3 million. The net deferred tax liability at December 31, 2012 was comprised of net long-term deferred income tax liabilities of $1,045.5 million, in addition to a net current deferred income tax liability of $106.1 million.  In 2013, the Company paid $3.3 million in state income taxes and paid $15.5 million in federal income taxes.  In 2012, the Company paid $0.8 million in state income taxes and did not pay any alternative minimum taxes.  The Company’s net operating loss carryforward as of December 31, 2013 was $1,174.7 million and $878.0 million for federal and state reporting purposes, respectively, the majority of which will expire between 2028 and 2032.  In 2013 the Company recorded a $2.9 million valuation allowance against our deferred tax asset for various state net operating losses. The Company also had an alternative minimum tax credit carryforward of $76.9 million and a statutory depletion carryforward of $12.9 million as of December 31, 2013.
	Our effective tax rate increased in 2013 as compared with 2012. This was primarily due to a redetermination of the deferred state tax liability to reflect updated state apportionment factors in certain higher-rate states and the recording of a valuation allowance against a portion of our deferred tax asset for state net operating losses.
	Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises in 2012. Some exercises resulted in tax deductions in excess of previously recorded benefits based on the option value at the time of the grant (“windfalls”). Although these additional tax benefits or “windfalls” are reflected in net operating loss carryforwards, pursuant to GAAP, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable. Accordingly, since the tax benefit does not reduce our current taxes payable in 2013 due to net operating loss carryforwards, these “windfall” tax benefits are not reflected in our net operating losses in deferred tax assets for 2013. Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2013 were $131.3 million.
	As of December 31, 2013, the Company has no unrecognized tax benefits.  The income tax years 2010 to 2013 remain open to examination by the major taxing jurisdictions to which the Company is subject.
	The Company has an income tax net operating loss carryforward related to its Canadian operations of $22.3 million, and has expiration dates of 2030 through 2033. The Company assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to utilize the existing deferred tax asset associated with the Canadian net operating loss. Based on this assessment, the Company did not record a valuation allowance as of December 31, 2013.

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Asset Retirement Obligation	'
	(11) ASSET RETIREMENT OBLIGATIONS
	The following table summarizes the Company’s 2013 and 2012 activity related to asset retirement obligations:
		2013		2012
		(in thousands)
	Asset retirement obligation at January 1	$	100,637	$	37,693
	Accretion of discount		5,643		2,394
	Obligations incurred		22,241		23,327
	Obligations settled/removed		-2,341		-8,804
	Revisions of estimates		7,366		46,027
	Asset retirement obligation at December 31	$	133,546	$	100,637
	Current liability		5,549		4,091
	Long-term liability		127,997		96,546
	Asset retirement obligation at December 31	$	133,546	$	100,637
	In 2012, the Company recorded a correction to increase the asset retirement obligation by approximately $39 million, the effect of which was immaterial to the Company’s financial statements in all affected periods.

Retirement_and_Employee_Benefi

Retirement and Employee Benefit Plans	12 Months Ended
	Dec. 31, 2013
Retirement and Employee Benefit Plans [Abstract]	'
Retirement and Employee Benefits Plans	'
	(12) RETIREMENT AND EMPLOYEE BENEFIT PLANS
	401(k) Defined Contribution Plan
	The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $2.5 million, $2.2 million and $1.9 million of contribution expense in 2013, 2012 and 2011, respectively. Additionally, the Company capitalized $2.9 million, $2.8 million and $3.8 million of contributions in 2013, 2012 and 2011, respectively, directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.
	Defined Benefit Pension and Other Postretirement Plans
	Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service.  Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible.
	The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages.
	Substantially all employees are covered by the Company’s defined benefit pension and postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.
	The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets, and funded status as of December 31, 2013 and 2012:
								Other Postretirement
		Pension Benefits						Benefits
			2013			2012			2013			2012
		(in thousands)
	Change in benefit obligations:
	Benefit obligation at January 1	$	105,432		$	81,738		$	11,464		$	6,793
	Service cost		13,789			10,942			2,296			1,832
	Interest cost		4,104			4,050			441			398
	Participant contributions		–			–			24			21
	Actuarial loss		-11,107			14,981			-1,706			2,525
	Benefits paid		-8,492			-6,951			-139			-105
	Plan amendments		–			672			–			–
	Settlements		-520			–			–			–
	Benefit obligation at December 31	$	103,206		$	105,432		$	12,380		$	11,464
								Other Postretirement
		Pension Benefits						Benefits
			2013			2012			2013			2012
		(in thousands)
	Change in plan assets:
	Fair value of plan assets at January 1	$	83,347		$	68,023		$	–		$	–
	Actual return on plan assets		12,471			11,191			–			–
	Employer contributions		12,520			11,084			115			84
	Participant contributions		–			–			24			21
	Benefits paid		-8,492			-6,951			-139			-105
	Settlements		-507			–			–			–
	Fair value of plan assets at December 31	$	99,339		$	83,347		$	–		$	–
	Funded status of plans at December 31	$	-3,867		$	-22,085		$	-12,380		$	-11,464
	The Company uses a December 31 measurement date for all of its plans and had liabilities recorded for the underfunded status for each period as presented above.
	The change in accumulated other comprehensive income related to the pension plans was a gain of $19.2 million ($11.6 million after tax) for the year ended December 31, 2013 and a loss of $8.4 million ($5.0 million after tax) for the year ended December 31, 2012. The change in accumulated other comprehensive income related to the other postretirement benefit plan was a gain of  $1.8 million ($1.1 million after tax) for the year ended December 31, 2013 and was a loss of $2.4 million ($1.4 million after tax) for the year ended December 31, 2012. Included in accumulated other comprehensive income as of December 31, 2013 and 2012 was a $15.9 million loss ($9.6 million net of tax) and a $36.9 million loss ($22.3 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans.    For the year ended December 31, 2013, amortization of prior period service cost included in net periodic pension cost of $21.0 million was reclassified from accumulated other comprehensive income to general and administrative expenses.
	The amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2014 are $0.1 million for prior service costs and $0.2 million net loss.
	The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2013 and 2012 are as follows:
			2013			2012
			(in thousands)
	Projected benefit obligation	$	103,206		$	105,432
	Accumulated benefit obligation	$	100,208		$	100,379
	Fair value of plan assets	$	99,339		$	83,347
	Pension and other postretirement benefit costs include the following components for 2013, 2012 and 2011:
												Other Postretirement
			Pension Benefits									Benefits
			2013			2012			2011			2013			2012		2011
			(in thousands)
	Service cost	$	13,789		$	10,942		$	9,323		$	2,296		$	1,832	$	1,354
	Interest cost		4,104			4,050			3,671			441			398		252
	Expected return on plan assets		-6,136			-5,426			-4,398			–			–		–
	Amortization of transition		–			–			–			–			64		64
	obligation
	Amortization of prior service cost		103			286			344			14			14		14
	Amortization of net loss		1,541			1,220			856			120			93		11
	Net periodic benefit cost		13,401			11,072			9,796			2,871			2,401		1,695
	Settlements and curtailments		70			–			–			–			–		–
	Total benefit cost	$	13,471		$	11,072		$	9,796		$	2,871		$	2,401	$	1,695
	Amounts recognized in other comprehensive income for the year ended December 31, 2013 were as follows:
				Pension Benefits			Other Postretirement Benefits
				(in thousands)
	Net actuarial gain arising during the year		$	17,454		$	1,706
Amortization of prior service cost			104			14
Amortization of net loss			1,541			120
Settlements			70			–
Tax effect			-7,535			-721
		$	11,634		$	1,119
The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2013 and 2012 are as follows:
	Pension Benefits							Other Postretirement
								Benefits
	2013			2012				2013			2012
Discount rate	5.00	%		4.00		%		5.00	%		4.00		%
Rate of compensation increase	4.50	%		4.50		%		n/a			n/a
The assumptions used in the measurement of the Company’s net periodic benefit cost for 2013, 2012 and 2011 are as follows:
	Pension Benefits										Other Postretirement
											Benefits
	2013			2012				2011			2013			2012			2011
Discount rate	4.00	%		5.00		%		5.50	%		4.00	%		5.00	%		5.50	%
Expected return on plan assets	7.00	%		7.50		%		7.50	%		n/a			n/a			n/a
Rate of compensation increase	4.50	%		4.50		%		4.50	%		n/a			n/a			n/a
The expected return on plan assets for the various benefit plans is based upon a review of the historical returns experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of the Employee Retirement Income Security Act and with a prudent level of diversification.
For measurement purposes, the following trend rates were assumed for 2013 and 2012:
	2013			2012
Health care cost trend assumed for next year	8	%		8	%
Rate to which the cost trend is assumed to decline	5	%		5	%
Year that the rate reaches the ultimate trend rate	2032			2031
Assumed health care cost trend rates have a significant effect on the amounts for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
		1%			1%
		Increase			Decrease
	(in thousands)
Effect on the total service and interest cost components	$	457		$	-373
Effect on postretirement benefit obligations	$	1,693		$	-1,413
Pension Payments and Asset Management
In 2013, the Company contributed $12.5 million to its pension plans and $0.1 million to its other postretirement benefit plan. The Company expects to contribute $12.0 million to its pension plans and $0.4 million to its other postretirement benefit plan in 2014. No plan assets are expected to be returned to the Company during the next twelve months.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
	Pension Benefits				Other
					Postretirement
					Benefits
	(in thousands)
2014	$	6,384		$	404
2015	$	6,280		$	542
2016	$	8,075		$	730
2017	$	8,553		$	801
2018	$	9,517		$	994
Years 2019-2023	$	58,894		$	7,545
The Company’s overall investment strategy is to provide an adequate pool of assets to support both the long-term growth of plan assets and to ensure adequate liquidity exists for the near-term benefit payment of obligations to participants, retirees and beneficiaries. The Benefits Administration Committee of the Company administers the Company’s pension plan assets. The Benefits Administration Committee believes long-term investment performance is a function of asset-class mix and restricts the composition of pension plan assets to a combination of cash and cash equivalents, domestic equity markets, international equity markets or investment grade fixed income assets.
The table below presents the allocations targeted by the Benefits Administration Committee and the actual weighted-average asset allocation of the Company’s pension plan as of December 31, 2013, by asset category. The asset allocation targets are subject to change and the Benefits Administration Committee allows for its actual allocations to deviate from target as a result of current and anticipated market conditions.  Plan assets are periodically balanced whenever the allocation to any asset class falls outside of the specified range.
	Pension Plan Asset
	Allocations
Asset category:	Target			Actual
U.S. Equity(1)	35	%		36	%
Non-U.S. Developed Equity(2)	30	%		31	%
Emerging Markets Equity(3)	5	%		6	%
Opportunistic(4)	–	%		–	%
Fixed income(5)	29	%		26	%
Cash(6)	1	%		1	%
Total	100	%		100	%
(1) Asset category above includes the following equity securities in the table below: U.S large cap growth equity, U.S. large cap value equity, U.S. large
cap core equity, and U.S. small cap equity.
(2) Asset category above includes Non-U.S. equity securities in the table below.
(3) Asset category above includes Emerging markets equity securities below.
(4) Asset category above includes none of the securities in the table below.
(5) Asset category above includes Fixed income pension plan assets in the table below.
(6) Asset category above includes Cash and cash equivalents pension plan assets in the table below.
Utilizing GAAP’s fair value hierarchy, the Company’s fair value measurement of pension plan assets as of December 31, 2013 are as follows:
Asset category:	Total			Quoted Prices in Active Markets for Identical Assets			Significant Observable Inputs			Significant Unobservable Inputs
				(Level 1)			(Level 2)			(Level 3)
	(in thousands)
Equity securities:
U.S. large cap growth equity(1)	$	7,660		$	7,660		$	–		$	–
U.S. large cap value equity(2)		8,174			8,174			–			–
U.S. large cap core equity(3)		16,438			–			16,438			–
U.S. small cap equity(4)		3,245			3,245			–			–
Non-U.S. equity(5)		30,628			30,628			–			–
Emerging markets equity(6)		6,374			–			6,374			–
Fixed income (7)		25,523			–			25,523			–
Cash and cash equivalents		1,296			1,296			–			–
Total	$	99,338		$	51,003		$	48,335		$	–
(1)Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2)Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3)An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
(4)Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(5)Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
(6)An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
(7)Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.
Utilizing GAAP’s fair value hierarchy, the Company’s fair value measurement of pension plan assets at December 31, 2012 are as follows:
Asset category:	Total			Quoted Prices in Active Markets for Identical Assets			Significant Observable Inputs			Significant Unobservable Inputs
				(Level 1)			(Level 2)			(Level 3)
	(in thousands)
Equity securities:
U.S. large cap growth equity(1)	$	4,588		$	4,588		$	–		$	–
U.S. large cap value equity(2)		5,257			5,257			–			–
U.S. large cap core equity(3)		11,564			–			11,564			–
U.S. small cap equity(4)		2,792			2,792			–			–
Non-U.S. equity(5)		21,891			21,891			–			–
Emerging markets equity(6)		4,454			–			4,454			–
Fixed income (7)		31,021			–			31,021			–
Cash and cash equivalents		1,780			1,780			–			–
Total	$	83,347		$	36,308		$	47,039		$	–
(1)Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2)Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3)An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
(4)Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(5)Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
(6)An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
(7)An institutional fund that seeks to replicate the performance of the Barclays Capital Long-Term Corporate Bond Index before fees through a sampling process.
The Company’s pension plan assets that are classified as Level 1 are due to the pension plan’s investments comprising either cash or investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of observable activity to support classification of the fair value measurement as Level 1. The Company’s Level 2 pension plan assets represent investments in institutional funds.  These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.  No concentration of risk arising within or across categories of plan assets exists due to any significant investments in a single entity, industry, country or investment fund.

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2013
Stock-Based Compensation [Abstract]	'
Stock-Based Compensation	'
	(13) STOCK-BASED COMPENSATION
	The Southwestern Energy Company 2013 Incentive Plan (2013 Plan) was adopted in February 2013 and approved by stockholders in May 2013. The 2013 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries. The 2013 Plan replaced the Southwestern Energy Company 2004 Stock Incentive Plan, the Southwestern Energy Company 2000 Stock Incentive Plan (2000 Plan) and the Southwestern Energy Company 2002 Employee Stock Incentive Plan (2002 Plan) but did not affect prior awards under those plans which remained valid and some of which are still outstanding. The awards under the prior plans have been adjusted for stock splits as permitted under such plans.
	The 2013 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock units to employees, officers and directors that in the aggregate do not exceed 20,500,000 shares. The types of incentives that may be awarded are comprehensive and are intended to enable the Company’s board of directors to structure the most appropriate incentives and to address changes in income tax laws which may be enacted over the term of the 2013 Plan.
	As initially adopted, the 2004 Plan, the 2000 Plan and the 2002 Plan provided for grants of options, stock appreciation rights, shares of phantom stock and shares of restricted stock that in the aggregate did not exceed 16,800,000,  1,125,000 and 300,000 shares, respectively, to employees who are not officers or directors of the Company under provisions of Section 16 of the Securities Exchange Act of 1934, as amended.
	The Company may utilize treasury shares, if available, or authorized but unissued shares when a stock option is exercised or when restricted stock is granted.
	The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. All options are issued at fair market value at the date of grant and expire seven years from the date of grant for awards under both the 2013 Plan and the 2004 Plan and ten years from the date of grant for awards under all other plans. Generally, stock options granted to employees and directors vest ratably over three years from the grant date. The Company issues shares of restricted stock to employees and directors which generally vest over four years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the individual grants with the exception of awards granted to participants who have reached retirement age or will reach retirement age during the vesting period. Restricted stock and stock options granted to participants on or after December 6, 2013 immediately vest upon death, disability or retirement (subject to a minimum of three years of service).
	Stock Options
	The Company recorded the following compensation costs related to stock options for the years ended December 31, 2013, 2012 and 2011:
		2013				2012				2011
			(in thousands)
	Stock-based compensation cost related to stock options – general and administrative expense	$	5,494			$	5,427			$	4,959
	Stock-based compensation cost related to stock options – capitalized	$	4,812			$	4,468			$	3,365
	The Company also recorded a deferred tax benefit of $4.0 million related to stock options in 2013, compared to deferred tax benefits of $2.2 million in 2012 and $1.7 million in 2011. A total of $16.2 million of 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 2.1 years.
	The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table.  Expected volatility is based on historical volatility of the Company’s common stock and other factors.  The Company uses historical data on exercise of stock options, post vesting forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant.
	Assumptions	2013		2012		2011
	Risk-free interest rate	1.5%		0.6%		0.9%
	Expected dividend yield	–		–		–
	Expected volatility	38.6%		58.2%		58.1%
	Expected term	5 years		5 years		5 years
	The following tables summarize stock option activity for the years 2013, 2012 and 2011 and provide information for options outstanding at December 31 of each year:
			2013						2012					2011
							Weighted						Weighted				Weighted
							Average						Average				Average
			Number				Exercise		Number				Exercise	Number			Exercise
			of Shares				Price		of Shares				Price	of Shares			Price
	Options outstanding at January 1		3,649,520			$	29.84		4,741,732			$	21.24	4,769,122		$	16.13
	Granted		571,166				38.95		613,120				34.34	853,478			36.64
	Exercised		-833,132				12.12		-1,607,784				5.71	-850,659			7.54
	Forfeited or expired		-74,861				37.31		-97,548				37.76	-30,209			35.46
	Options outstanding at December 31		3,312,693			$	35.70		3,649,520			$	29.84	4,741,732		$	21.24
			Options Outstanding										Options Exercisable
								Weighted								Weighted
								Average								Average
			Options		Weighted			Remaining		Aggregate			Options	Weighted		Remaining		Aggregate
			Outstanding at		Average			Contractual		Intrinsic			Exercisable at	Average		Contractual		Intrinsic
	Range of		December 31,		Exercise			Life		Value			December 31,	Exercise		Life		Value
	Exercise Prices		2013		Price			(Years)		(thousands)			2013	Price		(Years)		(thousands)
	$20.34-$29.69		273,134			27.31		1.2					265,025		27.29	1.1
	$30.23-$35.91		1,087,218			33.09		4.3					677,387		32.32	3.4
	$36.22-$39.91		1,587,066			37.56		5.4					803,412		36.74	4.4
	$40.15-$51.47		365,275			41.64		3.0					358,004		41.62	2.9
			3,312,693		$	35.70		4.4		$	12,882		2,103,828	$	34.96	2.9		$	10,022
	The weighted-average grant-date fair value of options granted during the years 2013, 2012 and 2011 was $13.39, $16.91 and $18.17, respectively. The total intrinsic value of options exercised during 2013, 2012 and 2011 was $21.7 million, $44.1 million and $27.0 million, respectively.
	Restricted Stock
	The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2013, 2012 and 2011:
			2013			2012			2011
			(in thousands)
	Stock-based compensation cost related to restricted stock grants	$	7,432		$	6,368		$	5,591
	– general and administrative expense
	Stock-based compensation cost related to restricted stock grants	$	7,469		$	5,994		$	5,162
	– capitalized
	The Company also recorded a deferred tax liability of $14.8 million related to restricted stock for the year ended December 31, 2013, compared to deferred tax liabilities of $1.4 million for 2012 and $2.1 million for 2011. As of December 31, 2013, there was $62.5 million of total unrecognized compensation cost related to unvested shares of restricted stock that is expected to be recognized over a weighted-average period of 3.4 years.
	The following table summarizes the restricted stock activity for the years 2013, 2012 and 2011 and provides information for restricted stock outstanding at December 31 of each year:
			2013						2012					2011
							Weighted						Weighted				Weighted
							Average						Average				Average
			Number				Grant Date		Number				Grant Date	Number			Grant Date
			of Shares				Fair Value		of Shares				Fair Value	of Shares			Fair Value
	Unvested shares at January 1		1,117,515			$	35.64		1,019,737			$	36.71	834,058		$	36.24
	Granted		1,108,852				38.92		537,244				34.39	532,754			36.41
	Vested		-381,676				36.29		-344,164				36.50	-294,358			34.90
	Forfeited		-73,769				35.81		-95,302				36.97	-52,717			36.45
	Unvested shares at December 31		1,770,922			$	37.55		1,117,515			$	35.64	1,019,737		$	36.71
The fair values of the grants were $43.2 million for 2013, $18.5 million for 2012 and $19.4 million for 2011. The total fair value of shares vested were $13.9 million for 2013, $12.6 million for 2012 and $10.9 million for 2011.
Liability-Classified Performance Units
Certain employees were provided performance units vesting equally over three years.  The payout of these units is based on certain metrics, such as total shareholder return and reserve replacement efficiency, compared to a predetermined group of peer companies and Company goal. At the end of each performance period, the value of the vested performance units, if any, is paid in cash.  The Company paid $3.3 million related to the vested performance units in 2013,  $19.1 million in 2012, and $15.8 million in 2011.  As of December 31, 2013 and 2012, the Company’s liability under the performance unit agreements was $45.3 million and $41.3 million, respectively.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Information [Abstract]	'
Segment Information	'
	(14) 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 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. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs and expenses. 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 other income (loss), net. 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)
	2013
	Revenues from external customers	$	2,398,214		$	972,832	$	99	$	3,371,145
	Intersegment revenues		5,951			2,373,851		241		2,380,043
	Operating income (loss)		878,701			325,435		-513		1,203,623
	Other income (loss), net		2,741			-1		-533		2,207
	Gain (loss) on derivatives		25,670			480		-9		26,141
	Depreciation, depletion and amortization expense		735,215			50,940		457		786,612
	Interest expense(2)		30,244			10,619		731		41,594
	Provision (benefit) for income taxes(2)		368,320			119,223		-669		486,874
	Assets		6,356,799	-3		1,427,294		263,633		8,047,726
	Capital investments(4)		2,052,148			157,635		25,014		2,234,797
	2012
	Revenues from external customers	$	1,964,624		$	765,255	$	114	$	2,729,993
	Intersegment revenues		-1,452			1,598,225		2,751		1,599,524
	Operating income (loss) (1)		-1,396,261			294,302		1,333		-1,100,626
	Other income (loss), net		-1,156			132		2,054		1,030
	Loss on derivatives		-14,950			–		–		-14,950
	Depreciation, depletion and amortization expense		765,368			44,395		1,190		810,953
	Impairment of natural gas and oil properties		1,939,734			–		–		1,939,734
	Interest expense(2)		20,315			14,341		1,001		35,657
	Provision for income taxes(2)		-548,556			104,522		895		-443,139
	Assets		5,193,733	-3		1,273,228		270,566		6,737,527
	Capital investments(4)		1,860,681			164,978		54,860		2,080,519
	2011
	Revenues from external customers	$	2,087,189		$	864,096	$	47	$	2,951,332
	Intersegment revenues		11,725			1,995,423		3,221		2,010,369
	Operating income		823,564			247,952		1,711		1,073,227
	Other income (loss), net		328			-91		27		264
	Gain on derivatives		1,574			–		–		1,574
	Depreciation, depletion and amortization expense		666,125			37,261		1,125		704,511
	Interest expense(2)		9,026			15,049		–		24,075
	Provision for income taxes(2)		322,714			90,221		286		413,221
	Assets		6,547,117	-3		1,119,861		235,919		7,902,897
	Capital investments(4)		1,977,493			160,776		68,905		2,207,174
	(1)The operating loss for the E&P segment for the twelve months ended December 31, 2012 includes a $1,939.7 million non-cash ceiling test impairment of our natural gas and oil properties.
	(2)  Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.
	(3)Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities.
	(4)Capital investments include a decrease of $24.9 million for 2013, a decrease of $36.9 million for 2012 and an increase of $4.3 million for 2011 related to the change in accrued expenditures between years.
	Included in intersegment revenues of the Midstream Services segment are approximately  $2.0 billion, $1.3 billion and $1.7 billion for 2013, 2012 and 2011, 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 2013, 2012,  and 2011, capital investments within the E&P segment include $35.4 million,  $11.6 million, and $18.7 respectively, related to the Company’s activities in Canada. As of December 31, 2013,  2012, and 2011, E&P assets include $79.2 million, $44.4 million, $28.4 million related to the Company’s activities in Canada.

Quarterly_Results_Unaudited

Quarterly Results (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Quarterly Results (Unaudited)	'
	(15) QUARTERLY RESULTS (UNAUDITED)
	The following is a summary of the quarterly results of operations for the years ended December 31, 2013 and 2012:
		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
		(in thousands, except per share amounts)
		2013
	Operating revenues	$	733,649	$	862,041	$	868,366	$	907,089
	Operating income		251,960		325,317		309,229		317,117
	Net income		127,515		245,631		185,867		144,490
	Earnings per share - Basic		0.36		0.70		0.53		0.41
	Earnings per share - Diluted		0.36		0.70		0.53		0.41
		2012
	Operating revenues	$	654,835	$	606,076	$	691,727	$	777,355
	Operating income (1)		184,326		-646,046		-65,959		-572,947
	Net income		107,704		-405,132		-54,053		-355,583
	Earnings per share - Basic		0.31		-1.16		-0.16		-1.02
	Earnings per share - Diluted		0.31		-1.16		-0.16		-1.02
	(1) 2012 Operating income includes an impairment charge for the full year of $1,939.7 million.

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Information [Abstract]	'
Condensed Consolidating Financial Information	'
	(16) CONDENSED CONSOLIDATING FINANCIAL INFORMATION
	As of December 16, 2013, following the release of all guarantees under the 7.15%, 7.5%, 7.35%, 7.125% and 4.10% Senior Notes and our former credit facility, as described in Note 8, all of our 100%-owned subsidiaries have been released of their guarantees.
	Prior to that date, the Company’s obligations under registered public debt and outstanding senior notes as listed in Note 8 were fully and unconditionally guaranteed, jointly and severally, by all of our 100%-owned subsidiaries, other than minor subsidiaries, on a senior unsecured basis, and the Company, as a parent company, had no independent assets or operations.  The subsidiary guarantees (i) ranked equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) ranked senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) were 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) were structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors.  In the case of each series of notes, if no default or event of default had occurred and was continuing, these guarantees would 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 revolving credit facility; and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the notes.  In addition, there were no significant restrictions on the ability of the Company or any guarantor to obtain funds from its subsidiaries by dividend or loan, and none of the assets of the Company or a guarantor represented restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.
	The Company is providing condensed consolidating financial information for SEECO, SEPCO and SES, its subsidiaries that were guarantors of the Company’s registered public debt and outstanding senior notes, and for its other subsidiaries that are not guarantors of such debt as of and for the years December 31, 2012 and 2011.  The Company has not provided comparative financial statements for 2013 because all guarantees were released in 2013.  The Company has not presented separate financial and narrative information for each of the former 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 former guarantor and other subsidiaries.
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
		Parent		Former		Other		Eliminations		Consolidated
				Guarantors		Subsidiaries
		(in thousands)
	Year ended December 31, 2012:
	Operating revenues	$	–	$	2,556,634	$	476,997	$	-303,638	$	2,729,993
	Operating costs and expenses:
	Gas purchases		–		593,091		–		-625		592,466
	Operating expenses		–		423,147		121,953		-300,365		244,735
	General and administrative expenses		–		151,488		26,307		-2,648		175,147
	Depreciation, depletion and amortization		–		765,623		45,330		–		810,953
	Impairment of natural gas and oil		–		1,939,734		–		–		1,939,734
	properties
	Taxes, other than income taxes		–		56,262		11,321		1		67,584
	Total operating costs and expenses		–		3,929,345		204,911		-303,637		3,830,619
	Operating income (loss)		–		-1,372,711		272,086		-1		-1,100,626
	Other income (loss), net		–		-1,143		2,173		–		1,030
	Gain (loss) on derivatives		–		-14,950		–		–		-14,950
	Equity in earnings of subsidiaries		-707,064		–		–		707,064		–
	Interest expense		–		22,312		13,345		–		35,657
	Income (loss) before income taxes		-707,064		-1,411,116		260,914		707,063		-1,150,203
	Provision (benefit) for income taxes		–		-538,357		95,218		–		-443,139
	Net income (loss)		-707,064		-872,759		165,696		707,063		-707,064
	Comprehensive income (loss)	$	-965,688	$	-1,125,454	$	166,225	$	959,229	$	-965,688
	Year ended December 31, 2011:
	Operating revenues	$	–	$	2,801,811	$	411,998	$	-262,477	$	2,951,332
	Operating costs and expenses:
	Gas purchases		–		710,487		–		-1,396		709,091
	Operating expenses		–		380,154		118,713		-257,923		240,944
	General and administrative expenses		–		141,499		19,700		-3,158		158,041
	Depreciation, depletion and amortization		–		665,615		38,896		–		704,511
	Taxes, other than income taxes		–		53,950		11,568		–		65,518
	Total operating costs and expenses		–		1,951,705		188,877		-262,477		1,878,105
	Operating income		–		850,106		223,121		–		1,073,227
	Other income (loss), net		–		306		-42		–		264
	Gain (loss) on derivatives		–		1,574		–		–		1,574
	Equity in earnings of subsidiaries		637,769		–		–		-637,769		–
	Interest expense		–		11,277		12,798		–		24,075
	Income (loss) before income taxes		637,769		840,709		210,281		-637,769		1,050,990
	Provision for income taxes		–		332,795		80,426		–		413,221
	Net income (loss)		637,769		507,914		129,855		-637,769		637,769
	Comprehensive income (loss)	$	962,222	$	836,291	$	129,294	$	-965,585	$	962,222
	CONDENSED CONSOLIDATING BALANCE SHEETS
		Parent		Former		Other		Eliminations		Consolidated
				Guarantors		Subsidiaries
		(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 current 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		-82,178		-6,923,106		-186,179		–		-7,191,463
	amortization
			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
	Parent		Former		Other		Eliminations		Consolidated
			Guarantors		Subsidiaries
	(in thousands)
Year ended December 31, 2012:
Net cash provided by operating activities	$	-39,934	$	1,278,673	$	415,203	$	–	$	1,653,942
Investing activities:
Capital investments		-36,918		-1,868,487		-202,350		–		-2,107,755
Proceeds from sale of property and equipment		26,006		169,149		5,946		–		201,101
Transfers to restricted cash		-167,788		–		–		–		-167,788
Transfers from restricted cash		159,245		1		–		–		159,246
Other		-696		-35,792		45,007		–		8,519
Net cash used in investing activities		-20,151		-1,735,129		-151,397		–		-1,906,677
Financing activities:
Intercompany activities		-198,023		462,443		-264,420		–		–
Payments on current portion of long-term debt		-1,200		–		–		–		-1,200
Payments on revolving long-term debt		-2,263,900		–		–		–		-2,263,900
Borrowings under revolving long-term debt		1,592,400		–		–		–		1,592,400
Proceeds from issuance of long-term debt		998,780		–		–		–		998,780
Other		-35,192		1		–		–		-35,191
Net cash provided by (used in) financing activities		92,865		462,444		-264,420		–		290,889
Effect of exchange rate changes on cash		–		–		-198		–		-198
Increase (decrease) in cash and cash equivalents		32,780		5,988		-812		–		37,956
Cash and cash equivalents at beginning of year		14,711		–		916		–		15,627
Cash and cash equivalents at end of period	$	47,491	$	5,988	$	104	$	–	$	53,583
Year ended December 31, 2011:
Net cash provided by operating activities	$	14,688	$	1,482,853	$	242,276	$	–	$	1,739,817
Investing activities:
Capital investments		-66,647		-1,916,246		-201,581		–		-2,184,474
Proceeds from sale of property and equipment		–		154,261		265		–		154,526
Transfers to restricted cash		-85,055		–		–		–		-85,055
Transfers from restricted cash		85,055		–		–		–		85,055
Other		16,263		-43,961		32,856		–		5,158
Net cash used in investing activities		-50,384		-1,805,946		-168,460		–		-2,024,790
Financing activities:
Intercompany activities		-242,277		315,462		-73,185		–		–
Payments on current portion of long-term debt		-1,200		–		–		–		-1,200
Payments on revolving long-term debt		-3,445,900		–		–		–		-3,445,900
Borrowings under revolving long-term debt		3,696,200		–		–		–		3,696,200
Other		35,203		–		–		–		35,203
Net cash provided by financing activities		42,026		315,462		-73,185		–		284,303
Effect of exchange rate changes on cash		–		–		242		–		242
Increase (decrease) in cash and cash equivalents		6,330		-7,631		873		–		-428
Cash and cash equivalents at beginning of year		8,381		7,631		43		–		16,055
Cash and cash equivalents at end of period	$	14,711	$	–	$	916	$	–	$	15,627

Organization_and_Summary_of_Si1

Organization and Summary of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Information [Abstract]	'
Nature of Operations	'
	Southwestern Energy Company (including its subsidiaries, collectively, “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 principally focused within the United States on development of an unconventional gas reservoir in Arkansas, 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, Arkansas, and Oklahoma in the Arkoma Basin. We have commenced exploration operations in Arkansas and Louisiana testing an unconventional oil play targeting the Lower Smackover Brown Dense. In 2010, we commenced an exploration program in New Brunswick, Canada, which represents our first operations outside of the United States.  Southwestern’s natural gas gathering and marketing (Midstream Services) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania and Texas.
Basis of Presentation	'
	The consolidated financial statements included in this Annual Report on Form 10-K present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.  The Company evaluates subsequent events through the date the financial statements are issued.
	Certain reclassifications have been made to the prior year’s financial statements to conform to the 2013 presentation.  The effects of the reclassifications were not material to the Company’s consolidated financial statements.
Principles of Consolidation	'
	The consolidated financial statements include the accounts of Southwestern and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
Revenue Recognition	'
	Natural gas and oil sales. Natural gas sales and oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, natural gas sales and oil sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas sales and oil sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. As of December 31, 2013, the Company had overproduction of 11.2 Bcf valued at $37.9 million and underproduction of 12.5 Bcf valued at $38.5 million. At December 31, 2012, the Company had overproduction of 8.4 Bcf valued at $28.4 million and underproduction of 9.4 Bcf valued at $29.9 million.
	Gas marketing. The Company generally markets its natural gas, as well as some gas produced by third parties, to brokers, local distribution companies and end-users, pursuant to a variety of contracts. Gas marketing revenues are recognized when delivery of natural gas has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured.
	Gas gathering. In certain areas the Company gathers its natural gas, as well as some natural gas produced by third parties, pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured.
	Other. The Company maintains an underground gas storage facility and generally sells natural gas from its storage facility during the winter gas withdrawal season. Revenue is recognized on natural gas storage sales when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. Other revenues, a component of gas sales, include a gain of $1.0 million in 2013, and losses of $0.9 million in 2012 and 2011, respectively, primarily related to the sale of natural gas in underground storage.
Cash and Cash Equivalents	'
	Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash.  Management considers cash and cash equivalents to have minimal credit and market risk.
	Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $4.9 million and $12.1 million as of December 31, 2013 and 2012, respectively.
Restricted Cash	'
	Restricted cash represents proceeds deposited by the Company with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.
Inventory	'
	Inventory recorded in current assets includes $3.7 million as of December 31, 2013 and $5.6 million at December 31, 2012, for natural gas in underground storage owned by the Company’s E&P segment, and $34.1 million as of December 31, 2013 and $22.5 million at December 31, 2012 for tubulars and other equipment used in the E&P segment.
	The Company has one natural gas storage facility. The current portion of the natural gas classified in inventory and carried at the lower of cost or market totaled $3.7 million as of December 31, 2013. The non-current portion of the natural gas classified in property and equipment and carried at cost totaled $16.0 million as of December 31, 2013. The carrying value of the non-current natural gas is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Withdrawals of current natural gas in underground storage are accounted for by a weighted average cost method whereby natural gas withdrawn from storage is relieved at the weighted average cost of current natural gas remaining in the facility.
	Other assets include $15.1 million as of December 31, 2013 and $13.8 million at December 31, 2012 for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems.
	Tubulars and other equipment are carried at the lower of cost or market and are accounted for by a moving weighted average cost method that is applied within specific classes of inventory items. Purchases of inventory are recorded at cost and inventory is relieved at the weighted average cost of items remaining within a specified class.
Property, Depreciation, Depletion and Amortization	'
	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 properties. 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 discounted at 10% 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 $3.67 per MMBtu, West Texas Intermediate oil of $93.42 per barrel, and NGLs of $43.45 per barrel, 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 December 31, 2013. Cash flow hedges of natural gas production in place increased this ceiling amount by approximately $70.7 million, net of tax, as of December 31, 2013.  At December 31, 2012, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.76 per MMBtu for Henry Hub natural gas and West Texas Intermediate oil of $91.21 per barrel. At December 31, 2011, the ceiling value of the Company’s reserves was calculated based upon average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.12 per MMBtu for Henry Hub natural gas and for West Texas Intermediate oil of $92.71.  Using the first-day-of-the-month prices of natural gas for the first two months of 2014 and NYMEX strip prices for the remainder of 2014, as applicable, the prices required to be used to determine the ceiling limit is not expected to result in a ceiling test write-down in 2014.  Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments. During 2012, the net capitalized costs of our natural gas and oil properties exceeded the ceiling by approximately $1,192.4 million (net of tax) and resulted in a non-cash ceiling test impairment.
	All of our costs directly associated with the acquisition and evaluation of properties in Canada relating to our exploration program as of December 31, 2013 and as of December 31, 2012 were unproved and did not exceed the ceiling amount.  If our exploration program in Canada is unsuccessful on all or a portion of these properties, or if further extensions are not granted, if requested, a ceiling test impairment may result in the future.
	Gathering Systems. The Company’s investment in gathering systems is primarily related to its Fayetteville Shale assets in Arkansas and the Marcellus Shale assets in Pennsylvania.  These assets are being depreciated on a straight-line basis over 25 years.
	Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and actively being evaluated.
	Asset Retirement Obligations.  An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company owns natural gas and oil properties, which require expenditures to plug and abandon the wells and reclaim the associated pads when reserves in the wells are depleted.
Income Taxes	'
	The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
	The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.
Derivative Financial Instruments	'
	The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses commodity fixed price swaps and fixed price options contracts to hedge sales of natural gas. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas sales if designated for hedge accounting treatment or gain (loss) on derivative if not designated for hedge accounting treatment in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item.  In contrast, gains and losses from the ineffective portion of fixed price swaps designated for hedge accounting treatment are recognized currently in gas sales in the consolidated statement of operations. Gains and losses from the ineffective portion of fixed price swaps not designated for hedge accounting treatment, interest rate swaps, fixed price call options, and basis swaps that were not designated for hedge accounting treatment are recognized in gain (loss) on derivatives in the consolidated statement of operations. Changes in the fair value of derivative instruments designated as fair value hedges as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately.  See Note 5 and Note 7 for a discussion of the Company’s hedging activities.
Earnings Per Share	'
	Basic earnings per common share is computed by dividing net income (loss) attributable to Southwestern by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding the incremental shares that would have been outstanding assuming the exercise of dilutive stock options and the vesting of unvested restricted shares of common stock.  Antidilutive is an increase in earnings per share or reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities, as defined by GAAP.
	For the year ended December 31, 2013, outstanding options for 1,569,665 shares with an average exercise price of $28.03 were included in the calculation of diluted shares. Options for 1,634,695 shares were excluded from the calculation because they would have had an antidilutive effect. As we recognized a net loss for the year ended December 31, 2012, the unvested stock options were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. Options for 1,716,109 shares were excluded from the calculation of diluted shares because they would have had an antidilutive effect.  For the year ended December 31, 2011, outstanding options for 3,577,104 shares with an average price of $11.78 were included in the calculation of diluted shares. Options for 881,254 shares were excluded from the calculation because they would have had an antidilutive effect.
	For the year ended December 31, 2013, 258,396 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 114,433 shares of restricted stock because they would have had an antidilutive effect. As we recognized a net loss for the year ended December 31, 2012, the unvested share-based payments were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. The calculation of diluted shares excluded 602,429 shares of restricted because they would have had an antidilutive effect. For the year ended December 31, 2011, 241,044 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 135,352 shares of restricted stock because they would have had an antidilutive effect.
	Supplemental Disclosures of Cash Flow Information
	Supplemental disclosures of cash flow information (in thousands):
		For the years ended December 31,
		2013		2012		2011
		(in thousands)
	Cash paid during the year for interest, net of amounts	$	36,267	$	17,311	$	19,159
	capitalized
	Cash paid during the year for income taxes		18,787		818		4,198
	Increase (decrease) in noncash property additions		-12,730		-26,240		30,389
Stock-Based Compensation	'
	The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.
Treasury Stock	'
	The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liability of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust and are presented as treasury stock and carried at cost. As of December 31, 2013, 9,924 shares were accounted for as treasury stock, compared to 64,715 shares at December 31, 2012.
Foreign Currency Translation	'
	We have designated the Canadian dollar as the functional currency for our operations in Canada.  The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of stockholders' equity.
New Accounting Standards Implemented in this Report	'
	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 about Offsetting Assets and Liabilities, issued in December 2011. Update 2013-01 clarifies that the scope of the disclosures under U.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and 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 requires an entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to provide the 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.
	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, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated 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 respective line 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 December 15, 2012, with early adoption permitted.  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.

Organization_and_Summary_of_Si2

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Disclosures of Cash Flow Information [Abstract]	'
Schedule of Supplemental Disclosures of Cash Flow Information	'
		For the years ended December 31,
		2013		2012		2011
		(in thousands)
	Cash paid during the year for interest, net of amounts	$	36,267	$	17,311	$	19,159
	capitalized
	Cash paid during the year for income taxes		18,787		818		4,198
	Increase (decrease) in noncash property additions		-12,730		-26,240		30,389

Prepaid_Expenses_Tables

Prepaid Expenses (Tables)	12 Months Ended
	Dec. 31, 2013
Prepaid Expenses [Abstract]	'
Prepaid Expenses Table	'
		2013		2012
			(in thousands)
	Prepaid drilling costs	$	9,560	$	30,101
	Prepaid insurance		7,619		9,507
	Prepaid taxes		13,624		572
	Total	$	30,803	$	40,180

Natural_Gas_And_Oil_Producing_

Natural Gas And Oil Producing Acitivities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Natural Gas And Oil Properties [Abstract]	'
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	'
		2013					2012
		(in thousands)
	Proved properties	$	12,337,372				$	10,259,226
	Unproved properties		956,469	-1				1,023,888	-1
	Total capitalized costs		13,293,841					11,283,114
	Less:  Accumulated depreciation, depletion and amortization		7,481,335					6,774,174
	Net capitalized costs	$	5,812,506				$	4,508,940
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	'
		2013			2012			2011			Prior			Total
		(in thousands)
	Property acquisition costs	$	147,791		$	81,889		$	221,451		$	109,994		$	561,125	-1
	Exploration and development costs		166,725			48,428			47,784			38,858			301,795	-1
	Capitalized interest		7,792			11,067			38,145			36,545			93,549	-1
		$	322,308		$	141,384		$	307,380		$	185,397		$	956,469
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	'
		2013				2012					2011
		(in thousands, except per Mcfe amounts)
	Proved property acquisition costs	$	572			$	–				$	17
	Unproved property acquisition costs		168,404	-1			220,822		-1			262,886		-1
	Exploration costs		192,164	-2			197,280		-2			63,419		-2
	Development costs		1,662,138				1,492,841					1,633,784
	Capitalized costs incurred		2,023,278				1,910,943					1,960,106
	Full cost pool amortization per Mcfe	$	1.08			$	1.31				$	1.30
Results of Operations for Oil and Gas Producing Activities Disclosure	'
		2013			2012			2011
		(in thousands)
	Sales	$	2,404,165		$	1,963,172		$	2,098,914
	Production (lifting) costs		-628,817			-505,271			-469,153
	Depreciation, depletion and amortization		-735,215			-765,192			-666,107
	Impairment of natural gas and oil properties		–			-1,939,734			–
			1,040,133			-1,247,025			963,654
	Provision (benefit) for income taxes		416,042			-496,738			375,435
	Results of operations (1)	$	624,091		$	-750,287		$	588,219
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	'
		2013				2012				2011
		Natural				Natural				Natural
		Gas		Oil		Gas		Oil		Gas			Oil
		(MMcf)		(MBbls)		(MMcf)		(MBbls)		(MMcf)			(MBbls)
	Proved reserves, beginning of year	4,016,798		244		5,887,207		996		4,929,980			1,219
	Revisions of previous estimates	325,374		88		-2,087,985		-44		34,505			-125
	Extensions, discoveries and other additions	3,283,495		229		918,594		154		1,459,428			2
	Production	-655,704		-188		-564,484		-83		-499,433			-97
	Acquisition of reserves in place	4,114		–		–		–		13			–
	Disposition of reserves in place	–		–		-136,534		-779		-37,286			-3
	Proved reserves, end of year	6,974,077		373		4,016,798		244		5,887,207			996
	Proved developed reserves:
	Beginning of year	3,195,662		243		3,254,018		983		2,687,238			1,173
	End of year	4,237,495		372		3,195,662		243		3,254,018			983
	Proved undeveloped reserves:
	Beginning of year	821,136		1		2,633,189		13		2,242,742			46
	End of year	2,736,582		1		821,136		1		2,633,189			13
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	'
		2013			2012			2011
		(in thousands)
	Future cash inflows	$	22,624,562		$	9,570,652		$	22,012,205
	Future production costs		-8,895,956			-4,737,297			-8,080,207
	Future development costs		-3,626,496			-711,050			-3,425,185
	Future income tax expense		-3,223,271			-745,251			-3,366,175
	Future net cash flows		6,878,839			3,377,054			7,140,638
	10% annual discount for estimated timing of cash flows		-3,142,795			-1,326,389			-3,689,838
	Standardized measure of discounted future net cash flows	$	3,736,044		$	2,050,665		$	3,450,800
Schedule Of Analysis Of Changes In Standardized Measure	'
		2013			2012			2011
		(in thousands)
	Standardized measure, beginning of year	$	2,050,665		$	3,450,800		$	3,013,750
	Sales and transfers of natural gas and oil produced, net of production costs		-1,774,043			-1,443,606			-1,632,156
	Net changes in prices and production costs		1,852,772			-2,604,591			-381,131
	Extensions, discoveries, and other additions, net of future production and development costs		1,454,634			549,601			1,163,992
	Acquisition of reserves in place		4,914			–			30
	Sales of reserves in place		–			-157,108			-11,761
	Revisions of previous quantity estimates		348,996			-1,109,409			34,221
	Accretion of discount		232,385			480,315			426,245
	Net change in income taxes		-1,119,798			1,079,158			-103,643
	Changes in estimated future development costs		-196,394			2,475,470			70,492
	Previously estimated development costs incurred during the year		222,982			61,949			564,894
	Changes in production rates (timing) and other		658,931			-731,914			305,867
	Standardized measure, end of year	$	3,736,044		$	2,050,665		$	3,450,800

Derivatives_and_Risk_Managemen1

Derivatives and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2013
Derivatives And Risk Management [Abstract]	'
Balance Sheet Classification of Derivative Financial Instruments	'
			Derivative Assets
			31-Dec-13				31-Dec-12
			Balance Sheet Classification		Fair Value		Balance Sheet Classification		Fair Value
			(in thousands)
	Derivatives designated as hedging
	instruments:
	Fixed price swaps		Derivative asset		$	20,631	Derivative asset		$	279,443
	Fixed price swaps		Other long-term assets			–	Other long-term assets			8,550
	Total derivatives designated as hedging				$	20,631			$	287,993
	instruments
	Derivatives not designated as hedging
	instruments:
	Basis swaps		Derivative asset		$	12,858	Derivative asset		$	3,250
	Fixed price swaps		Derivative asset			37,382	Derivative asset			–
	Basis swaps		Other long-term assets			107	Other long-term assets			901
	Interest rate swaps		Other long-term assets			7,525	Other long-term assets			–
	Total derivatives not designated as				$	57,872			$	4,151
	hedging instruments
	Total derivative assets				$	78,503			$	292,144
			Derivative Liabilities
			31-Dec-13				31-Dec-12
			Balance Sheet Classification		Fair Value		Balance Sheet Classification		Fair Value
			(in thousands)
	Derivatives designated as hedging
	instruments:
	Fixed price swaps		Other current liabilities		$	3,884	Other current liabilities		$	–
	Total derivatives designated as hedging				$	3,884			$	–
	instruments
	Derivatives not designated as hedging
	instruments:
	Basis swaps		Other current liabilities		$	1,501	Other current liabilities		$	138
	Fixed price swaps		Other current liabilities			185	Other current liabilities			–
	Fixed price call options		Other long-term liabilities			30,388	Other long-term liabilities			4,128
	Interest rate swaps		Other current liabilities			1,520	Other current liabilities			–
	Interest rate swaps		Other long-term liabilities			3,012	Other long-term liabilities			–
	Total derivatives not designated as				$	36,606			$	4,266
	hedging instruments
	Total derivative liabilities				$	40,490			$	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
	2014	200.7	181.6	382.3
Before Tax Effect of Cash Flow Hedges on Consolidated Financial Statements	'
						Gain Recognized in Other Comprehensive Income
						Comprehensive Income
						(Effective Portion)
					For the years ended
					December 31,
	Derivative Instrument				2013		2012
					(in thousands)
	Fixed price swaps				$	37,931	$	178,660
	Costless-collars				$	–	$	39,247
			Classification of Gain		Gain Reclassified from Accumulated Other Comprehensive Income into Earnings
			Reclassified from Accumulated		(Effective Portion)
			Other Comprehensive Income		For the years ended
			into Earnings		December 31,
	Derivative Instrument		(Effective Portion)		2013		2012
					(in thousands)
	Fixed price swaps		Gas Sales		$	309,177	$	413,410
	Costless-collars		Gas Sales		$	–	$	218,119
					Gain (Loss) Recognized in Earnings
					(Ineffective Portion)
			Classification of Gain (Loss)		For the years ended
			Recognized in Earnings		December 31,
	Derivative Instrument		(Ineffective Portion)		2013		2012
					(in thousands)
	Fixed price swaps		Gas Sales		$	-1,652	$	2,450
	Costless-collars		Gas Sales		$	–	$	-24
Before Tax Effect of Basis Swaps Not Qualifying for Hedge Accounting	'
					Gain (Loss) on Derivatives,
					net of settlement
					Recognized in Earnings
			Consolidated Statement of Operations		For the years ended
			Classification of Gain (Loss) on		December 31,
	Derivative Instrument		Derivatives, net of settlement		2013		2012
					(in thousands)
	Basis swaps		Gain (Loss) on Derivatives		$	7,450	$	766
	Fixed price call options		Gain (Loss) on Derivatives			-26,259		-4,128
	Fixed price swaps		Gain (Loss) on Derivatives			37,197		–
	Fair value swaps		Gain (Loss) on Derivatives			–		1,208
	Interest rate swaps		Gain (Loss) on Derivatives			2,992		–
					Gain (Loss)
					on Derivatives, Settled (1)
					Recognized in Earnings
			Consolidated Statement of Operations		For the years ended
			Classification of Gain (Loss)		December 31,
	Derivative Instrument		on Derivatives, Settled (1)		2013		2012
					(in thousands)
	Basis swaps		Gain (Loss) on Derivatives		$	4,772	$	2,162
	Fair value swaps		Gain (Loss) on Derivatives			–		-14,958
	Interest rate swaps		Gain (Loss) on Derivatives			-11		–

Reclassification_From_Accumula1

Reclassification From Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2013
Reclassification From Accumulated Other Comprehensive Income [Abstract]	'
Components Of Accumulated Other Comprehensive Income	'
			For the year ended
			31-Dec-13
			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			21,619			–		-4,003		17,616
	Amounts reclassified (2)			-184,515			12,753		–		-171,762
	Net current-period other comprehensive income (loss)			-162,896			12,753		-4,003		-154,146
	Ending balance, December 31, 2013		$	9,270		$	-9,558	$	-4,054	$	-4,342
		-1		All amounts are net of tax.
		-2		See separate table below for details about these reclassifications.
Amounts Reclassified From Accumulated Other Comprehensive Income	'
	Details about Accumulated Other Comprehensive Income		Consolidated Statement of Operations Classification
					(in thousands)
	Gains (losses) on cash flow hedges
	Settlements		Gas sales	$	309,177
	Ineffectiveness		Gas sales		-1,652
			Income before income taxes		307,525
			Provision for income taxes		123,010
			Net income	$	184,515
	Pension and other postretirement
	Amortization of prior service cost included in		General and administrative expenses	$	-21,009
	net periodic pension cost (1)
			Loss before income taxes		-21,009
			Benefit for income taxes		-8,256
			Net loss	$	-12,753
	Total reclassifications for the period		Net income	$	171,762
		-1		Included in the computation of net periodic pension cost (see Note 12 for additional details).

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements [Abstract]	'
Carrying Amount and Estimated Fair Values of Financial Instruments	'
		31-Dec-13									31-Dec-12
		Carrying					Fair				Carrying				Fair
		Amount					Value				Amount				Value
		(in thousands)
	Cash and cash equivalents	$		22,938			$		22,938			$	53,583	$		53,583
	Restricted cash	$		–			$		–			$	8,542	$		8,542
	Credit facility	$		282,900			$		282,900			$	–	$		–
	Senior notes	$		1,668,396			$		1,795,935			$	1,669,473	$		1,917,005
	Derivative instruments, net	$		38,013			$		38,013			$	287,878	$		287,878
Summary Assets and Liabilities Measured at Fair Value on Recurring Basis	'
			31-Dec-13
			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		$	–	$	65,538		$	12,965	$	78,503
	Derivative liabilities			–		-8,601			-31,889		-40,490
	Total		$	–	$	56,937		$	-18,924	$	38,013
			31-Dec-12
			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 Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3), Reconciliation	'
			For the years ended
			December 31,
			2013		2012
			(in thousands)
	Balance at beginning of period		$	-115	$	182,119
	Total gains or losses (realized/unrealized):
	Included in earnings			-14,037		216,857
	Included in other comprehensive income			–		-178,847
	Purchases, issuances, and settlements:
	Purchases			–		–
	Issuances			–		–
	Settlements			-4,772		-220,244
	Transfers into/out of Level 3			–		–
	Balance at end of period		$	-18,924	$	-115
	Change in unrealized gains included in earnings relating to derivatives still held as of December 31		$	-18,809	$	-3,362

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt [Abstract]	'
Components Of Debt	'
			2013		2012
			(in thousands)
	Short-term debt:
	7.15% Senior Notes due 2018		$	1,200	$	1,200
	Total short-term debt (1)			1,200		1,200
	Long-term debt:
	Variable rate (1.64%  and 2.20% at December 31, 2013 and December 31, 2012,			282,900		–
	respectively) Credit Facility, expires December 2018
	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			28,200		29,400
	7.5% Senior Notes due 2018			600,000		600,000
	4.10% Senior Notes due 2022			1,000,000		1,000,000
	Unamortized discount			-1,004		-1,127
	Total long-term debt			1,950,096		1,668,273
	Total debt		$	1,951,296	$	1,669,473
	(1) Short-term debt is included in Other current liabilities.
Schedule of Long Term Debt Maturities	'
	2015		1,200
	2016		1,200
	2017		41,200
	2018		907,500
	Thereafter		1,000,000
		$	1,951,100

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Taxes [Abstract]	'
Provision (Benefit) For Income Taxes	'
			2013		2012		2011
		(in thousands)
	Current:
	Federal	$	-12,151	$	15,500	$	3,378
	State		1,080		3,189		820
			-11,071		18,689		4,198
	Deferred:
	Federal		409,359		-388,209		345,922
	State		87,823		-71,582		60,941
	Foreign		763		-2,037		2,160
			497,945		-461,828		409,023
	Provision (benefit) for income taxes	$	486,874	$	-443,139	$	413,221
Reconciliation Of Provision For Income Taxes	'
			2013		2012		2011
		(in thousands)
	Expected provision (benefit) at federal statutory rate	$	416,632	$	-402,571	$	367,854
	Increase (decrease) resulting from:
	State income taxes, net of federal income tax effect		53,130		-44,454		40,145
	Nondeductible expenses		3,404		2,100		1,244
	Other		13,708		1,786		3,978
	Provision (benefit) for income taxes	$	486,874	$	-443,139	$	413,221
Schedule of Deferred Tax Assets and Liabilities	'
			2013		2012
		(in thousands)
	Deferred tax liabilities:
	Differences between book and tax basis of property	$	2,114,685	$	1,441,149
	Cash flow hedges		13,171		112,625
	Other		10,715		4,460
			2,138,571		1,558,234
	Deferred tax assets:
	Accrued compensation		15,718		16,387
	Alternative minimum tax credit carryforward		76,864		89,016
	Stored natural gas		9,272		7,812
	Accrued pension costs		1,821		7,686
	Asset retirement obligations		53,419		39,249
	Net operating loss carryforward		411,994		217,276
	Differences between book and tax basis of property - state		11,045		16,872
	Other		7,405		12,354
			587,538		406,652
	Net deferred tax liability	$	1,551,033	$	1,151,582

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Schedule of Asset Retirement Obligations	'
		2013		2012
		(in thousands)
	Asset retirement obligation at January 1	$	100,637	$	37,693
	Accretion of discount		5,643		2,394
	Obligations incurred		22,241		23,327
	Obligations settled/removed		-2,341		-8,804
	Revisions of estimates		7,366		46,027
	Asset retirement obligation at December 31	$	133,546	$	100,637
	Current liability		5,549		4,091
	Long-term liability		127,997		96,546
	Asset retirement obligation at December 31	$	133,546	$	100,637

Retirement_and_Employee_Benefi1

Retirement and Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Retirement and Employee Benefit Plans [Abstract]	'
Changes In The Plans Benefit Obligations	'
								Other Postretirement
		Pension Benefits						Benefits
			2013			2012			2013			2012
		(in thousands)
	Change in benefit obligations:
	Benefit obligation at January 1	$	105,432		$	81,738		$	11,464		$	6,793
	Service cost		13,789			10,942			2,296			1,832
	Interest cost		4,104			4,050			441			398
	Participant contributions		–			–			24			21
	Actuarial loss		-11,107			14,981			-1,706			2,525
	Benefits paid		-8,492			-6,951			-139			-105
	Plan amendments		–			672			–			–
	Settlements		-520			–			–			–
	Benefit obligation at December 31	$	103,206		$	105,432		$	12,380		$	11,464
Changes In The Plans Benefit Assets And Funded Status	'
								Other Postretirement
		Pension Benefits						Benefits
			2013			2012			2013			2012
		(in thousands)
	Change in plan assets:
	Fair value of plan assets at January 1	$	83,347		$	68,023		$	–		$	–
	Actual return on plan assets		12,471			11,191			–			–
	Employer contributions		12,520			11,084			115			84
	Participant contributions		–			–			24			21
	Benefits paid		-8,492			-6,951			-139			-105
	Settlements		-507			–			–			–
	Fair value of plan assets at December 31	$	99,339		$	83,347		$	–		$	–
	Funded status of plans at December 31	$	-3,867		$	-22,085		$	-12,380		$	-11,464
Pension And Other Postretirement Benefit Costs	'
												Other Postretirement
			Pension Benefits									Benefits
			2013			2012			2011			2013			2012		2011
			(in thousands)
	Service cost	$	13,789		$	10,942		$	9,323		$	2,296		$	1,832	$	1,354
	Interest cost		4,104			4,050			3,671			441			398		252
	Expected return on plan assets		-6,136			-5,426			-4,398			–			–		–
	Amortization of transition		–			–			–			–			64		64
	obligation
	Amortization of prior service cost		103			286			344			14			14		14
	Amortization of net loss		1,541			1,220			856			120			93		11
	Net periodic benefit cost		13,401			11,072			9,796			2,871			2,401		1,695
	Settlements and curtailments		70			–			–			–			–		–
	Total benefit cost	$	13,471		$	11,072		$	9,796		$	2,871		$	2,401	$	1,695
Projected Benefit Obligation, Accumulated Benefit Obligation, And Fair Value Of Plan Assets	'
			2013			2012
			(in thousands)
	Projected benefit obligation	$	103,206		$	105,432
	Accumulated benefit obligation	$	100,208		$	100,379
	Fair value of plan assets	$	99,339		$	83,347
Amounts Recognized In Other Comprehensive Income	'
				Pension Benefits			Other Postretirement Benefits
				(in thousands)
	Net actuarial gain arising during the year		$	17,454		$	1,706
	Amortization of prior service cost			104			14
	Amortization of net loss			1,541			120
	Settlements			70			–
	Tax effect			-7,535			-721
			$	11,634		$	1,119
Assumptions Used In The Measurement Of Benefit Obligations	'
		Pension Benefits							Other Postretirement
									Benefits
		2013			2012				2013			2012
	Discount rate	5.00	%		4.00		%		5.00	%		4.00		%
	Rate of compensation increase	4.50	%		4.50		%		n/a			n/a
Assumptions Used In The Measurement Of Net Periodic Benefit Cost	'
		Pension Benefits										Other Postretirement
												Benefits
		2013			2012				2011			2013			2012			2011
	Discount rate	4.00	%		5.00		%		5.50	%		4.00	%		5.00	%		5.50	%
	Expected return on plan assets	7.00	%		7.50		%		7.50	%		n/a			n/a			n/a
	Rate of compensation increase	4.50	%		4.50		%		4.50	%		n/a			n/a			n/a
Measurement Purposes Following Trend Rates Were Assumed	'
		2013			2012
	Health care cost trend assumed for next year	8	%		8	%
	Rate to which the cost trend is assumed to decline	5	%		5	%
	Year that the rate reaches the ultimate trend rate	2032			2031
One Percentage Point Change In Assumed Health Care Cost Trend Rates	'
			1%			1%
			Increase			Decrease
		(in thousands)
	Effect on the total service and interest cost components	$	457		$	-373
	Effect on postretirement benefit obligations	$	1,693		$	-1,413
Benefit Payments Which Reflect Expected Future Service	'
		Pension Benefits				Other
						Postretirement
						Benefits
		(in thousands)
	2014	$	6,384		$	404
	2015	$	6,280		$	542
	2016	$	8,075		$	730
	2017	$	8,553		$	801
	2018	$	9,517		$	994
	Years 2019-2023	$	58,894		$	7,545
Plan Assets Allocation To Any Asset Class Falls Outside Of The Specified Range	'
		Pension Plan Asset
		Allocations
	Asset category:	Target			Actual
	U.S. Equity(1)	35	%		36	%
	Non-U.S. Developed Equity(2)	30	%		31	%
	Emerging Markets Equity(3)	5	%		6	%
	Opportunistic(4)	–	%		–	%
	Fixed income(5)	29	%		26	%
	Cash(6)	1	%		1	%
	Total	100	%		100	%
	(1) Asset category above includes the following equity securities in the table below: U.S large cap growth equity, U.S. large cap value equity, U.S. large
	cap core equity, and U.S. small cap equity.
	(2) Asset category above includes Non-U.S. equity securities in the table below.
	(3) Asset category above includes Emerging markets equity securities below.
	(4) Asset category above includes none of the securities in the table below.
	(5) Asset category above includes Fixed income pension plan assets in the table below.
	(6) Asset category above includes Cash and cash equivalents pension plan assets in the table below.
Fair Value Measurement Of Pension Plan Assets	'
	Asset category:	Total			Quoted Prices in Active Markets for Identical Assets			Significant Observable Inputs			Significant Unobservable Inputs
					(Level 1)			(Level 2)			(Level 3)
		(in thousands)
	Equity securities:
	U.S. large cap growth equity(1)	$	7,660		$	7,660		$	–		$	–
	U.S. large cap value equity(2)		8,174			8,174			–			–
	U.S. large cap core equity(3)		16,438			–			16,438			–
	U.S. small cap equity(4)		3,245			3,245			–			–
	Non-U.S. equity(5)		30,628			30,628			–			–
	Emerging markets equity(6)		6,374			–			6,374			–
	Fixed income (7)		25,523			–			25,523			–
	Cash and cash equivalents		1,296			1,296			–			–
	Total	$	99,338		$	51,003		$	48,335		$	–
	(1)Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
	(2)Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
	(3)An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
	(4)Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
	(5)Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
	(6)An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
	(7)Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.
	Utilizing GAAP’s fair value hierarchy, the Company’s fair value measurement of pension plan assets at December 31, 2012 are as follows:
	Asset category:	Total			Quoted Prices in Active Markets for Identical Assets			Significant Observable Inputs			Significant Unobservable Inputs
					(Level 1)			(Level 2)			(Level 3)
		(in thousands)
	Equity securities:
	U.S. large cap growth equity(1)	$	4,588		$	4,588		$	–		$	–
	U.S. large cap value equity(2)		5,257			5,257			–			–
	U.S. large cap core equity(3)		11,564			–			11,564			–
	U.S. small cap equity(4)		2,792			2,792			–			–
	Non-U.S. equity(5)		21,891			21,891			–			–
	Emerging markets equity(6)		4,454			–			4,454			–
	Fixed income (7)		31,021			–			31,021			–
	Cash and cash equivalents		1,780			1,780			–			–
	Total	$	83,347		$	36,308		$	47,039		$	–
	(1)Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
	(2)Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
	(3)An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
	(4)Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
	(5)Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
	(6)An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
	(7)An institutional fund that seeks to replicate the performance of the Barclays Capital Long-Term Corporate Bond Index before fees through a sampling process.

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule Of Risk Free Interest Rate	'
	Assumptions	2013		2012		2011
	Risk-free interest rate	1.5%		0.6%		0.9%
	Expected dividend yield	–		–		–
	Expected volatility	38.6%		58.2%		58.1%
	Expected term	5 years		5 years		5 years
Summary of Stock Option Activity, Options Outstanding	'
			2013						2012					2011
							Weighted						Weighted				Weighted
							Average						Average				Average
			Number				Exercise		Number				Exercise	Number			Exercise
			of Shares				Price		of Shares				Price	of Shares			Price
	Options outstanding at January 1		3,649,520			$	29.84		4,741,732			$	21.24	4,769,122		$	16.13
	Granted		571,166				38.95		613,120				34.34	853,478			36.64
	Exercised		-833,132				12.12		-1,607,784				5.71	-850,659			7.54
	Forfeited or expired		-74,861				37.31		-97,548				37.76	-30,209			35.46
	Options outstanding at December 31		3,312,693			$	35.70		3,649,520			$	29.84	4,741,732		$	21.24
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range [Table Text Block]	'
			Options Outstanding										Options Exercisable
								Weighted								Weighted
								Average								Average
			Options		Weighted			Remaining		Aggregate			Options	Weighted		Remaining		Aggregate
			Outstanding at		Average			Contractual		Intrinsic			Exercisable at	Average		Contractual		Intrinsic
	Range of		December 31,		Exercise			Life		Value			December 31,	Exercise		Life		Value
	Exercise Prices		2013		Price			(Years)		(thousands)			2013	Price		(Years)		(thousands)
	$20.34-$29.69		273,134			27.31		1.2					265,025		27.29	1.1
	$30.23-$35.91		1,087,218			33.09		4.3					677,387		32.32	3.4
	$36.22-$39.91		1,587,066			37.56		5.4					803,412		36.74	4.4
	$40.15-$51.47		365,275			41.64		3.0					358,004		41.62	2.9
			3,312,693		$	35.70		4.4		$	12,882		2,103,828	$	34.96	2.9		$	10,022
Summary of Restricted Stock Activity and Unvested Shares	'
			2013						2012					2011
							Weighted						Weighted				Weighted
							Average						Average				Average
			Number				Grant Date		Number				Grant Date	Number			Grant Date
			of Shares				Fair Value		of Shares				Fair Value	of Shares			Fair Value
	Unvested shares at January 1		1,117,515			$	35.64		1,019,737			$	36.71	834,058		$	36.24
	Granted		1,108,852				38.92		537,244				34.39	532,754			36.41
	Vested		-381,676				36.29		-344,164				36.50	-294,358			34.90
	Forfeited		-73,769				35.81		-95,302				36.97	-52,717			36.45
	Unvested shares at December 31		1,770,922			$	37.55		1,117,515			$	35.64	1,019,737		$	36.71
Stock Options [Member]	'
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Text Block]	'
		2013				2012				2011
			(in thousands)
	Stock-based compensation cost related to stock options – general and administrative expense	$	5,494			$	5,427			$	4,959
	Stock-based compensation cost related to stock options – capitalized	$	4,812			$	4,468			$	3,365
Restricted Stock [Member]	'
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Text Block]	'
			2013			2012			2011
			(in thousands)
	Stock-based compensation cost related to restricted stock grants	$	7,432		$	6,368		$	5,591
	– general and administrative expense
	Stock-based compensation cost related to restricted stock grants	$	7,469		$	5,994		$	5,162
	– capitalized

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Information [Abstract]	'
Summary Financial Information for Company's Reportable Segments Table	'
		Exploration
		and			Midstream
		Production			Services		Other		Total
		(in thousands)
	2013
	Revenues from external customers	$	2,398,214		$	972,832	$	99	$	3,371,145
	Intersegment revenues		5,951			2,373,851		241		2,380,043
	Operating income (loss)		878,701			325,435		-513		1,203,623
	Other income (loss), net		2,741			-1		-533		2,207
	Gain (loss) on derivatives		25,670			480		-9		26,141
	Depreciation, depletion and amortization expense		735,215			50,940		457		786,612
	Interest expense(2)		30,244			10,619		731		41,594
	Provision (benefit) for income taxes(2)		368,320			119,223		-669		486,874
	Assets		6,356,799	-3		1,427,294		263,633		8,047,726
	Capital investments(4)		2,052,148			157,635		25,014		2,234,797
	2012
	Revenues from external customers	$	1,964,624		$	765,255	$	114	$	2,729,993
	Intersegment revenues		-1,452			1,598,225		2,751		1,599,524
	Operating income (loss) (1)		-1,396,261			294,302		1,333		-1,100,626
	Other income (loss), net		-1,156			132		2,054		1,030
	Loss on derivatives		-14,950			–		–		-14,950
	Depreciation, depletion and amortization expense		765,368			44,395		1,190		810,953
	Impairment of natural gas and oil properties		1,939,734			–		–		1,939,734
	Interest expense(2)		20,315			14,341		1,001		35,657
	Provision for income taxes(2)		-548,556			104,522		895		-443,139
	Assets		5,193,733	-3		1,273,228		270,566		6,737,527
	Capital investments(4)		1,860,681			164,978		54,860		2,080,519
	2011
	Revenues from external customers	$	2,087,189		$	864,096	$	47	$	2,951,332
	Intersegment revenues		11,725			1,995,423		3,221		2,010,369
	Operating income		823,564			247,952		1,711		1,073,227
	Other income (loss), net		328			-91		27		264
	Gain on derivatives		1,574			–		–		1,574
	Depreciation, depletion and amortization expense		666,125			37,261		1,125		704,511
	Interest expense(2)		9,026			15,049		–		24,075
	Provision for income taxes(2)		322,714			90,221		286		413,221
	Assets		6,547,117	-3		1,119,861		235,919		7,902,897
	Capital investments(4)		1,977,493			160,776		68,905		2,207,174
	(1)The operating loss for the E&P segment for the twelve months ended December 31, 2012 includes a $1,939.7 million non-cash ceiling test impairment of our natural gas and oil properties.
	(2)  Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.
	(3)Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities.
	(4)Capital investments include a decrease of $24.9 million for 2013, a decrease of $36.9 million for 2012 and an increase of $4.3 million for 2011 related to the change in accrued expenditures between years.

Quarterly_Results_Unaudited_Ta

Quarterly Results (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Schedule of Quarterly Financial Information [Table Text Block]	'
		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
		(in thousands, except per share amounts)
		2013
	Operating revenues	$	733,649	$	862,041	$	868,366	$	907,089
	Operating income		251,960		325,317		309,229		317,117
	Net income		127,515		245,631		185,867		144,490
	Earnings per share - Basic		0.36		0.70		0.53		0.41
	Earnings per share - Diluted		0.36		0.70		0.53		0.41
		2012
	Operating revenues	$	654,835	$	606,076	$	691,727	$	777,355
	Operating income (1)		184,326		-646,046		-65,959		-572,947
	Net income		107,704		-405,132		-54,053		-355,583
	Earnings per share - Basic		0.31		-1.16		-0.16		-1.02
	Earnings per share - Diluted		0.31		-1.16		-0.16		-1.02
	(1) 2012 Operating income includes an impairment charge for the full year of $1,939.7 million.

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Information [Abstract]	'
Condensed Consolidating Statements of Operations	'
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
		Parent		Former		Other		Eliminations		Consolidated
				Guarantors		Subsidiaries
		(in thousands)
	Year ended December 31, 2012:
	Operating revenues	$	–	$	2,556,634	$	476,997	$	-303,638	$	2,729,993
	Operating costs and expenses:
	Gas purchases		–		593,091		–		-625		592,466
	Operating expenses		–		423,147		121,953		-300,365		244,735
	General and administrative expenses		–		151,488		26,307		-2,648		175,147
	Depreciation, depletion and amortization		–		765,623		45,330		–		810,953
	Impairment of natural gas and oil		–		1,939,734		–		–		1,939,734
	properties
	Taxes, other than income taxes		–		56,262		11,321		1		67,584
	Total operating costs and expenses		–		3,929,345		204,911		-303,637		3,830,619
	Operating income (loss)		–		-1,372,711		272,086		-1		-1,100,626
	Other income (loss), net		–		-1,143		2,173		–		1,030
	Gain (loss) on derivatives		–		-14,950		–		–		-14,950
	Equity in earnings of subsidiaries		-707,064		–		–		707,064		–
	Interest expense		–		22,312		13,345		–		35,657
	Income (loss) before income taxes		-707,064		-1,411,116		260,914		707,063		-1,150,203
	Provision (benefit) for income taxes		–		-538,357		95,218		–		-443,139
	Net income (loss)		-707,064		-872,759		165,696		707,063		-707,064
	Comprehensive income (loss)	$	-965,688	$	-1,125,454	$	166,225	$	959,229	$	-965,688
	Year ended December 31, 2011:
	Operating revenues	$	–	$	2,801,811	$	411,998	$	-262,477	$	2,951,332
	Operating costs and expenses:
	Gas purchases		–		710,487		–		-1,396		709,091
	Operating expenses		–		380,154		118,713		-257,923		240,944
	General and administrative expenses		–		141,499		19,700		-3,158		158,041
	Depreciation, depletion and amortization		–		665,615		38,896		–		704,511
	Taxes, other than income taxes		–		53,950		11,568		–		65,518
	Total operating costs and expenses		–		1,951,705		188,877		-262,477		1,878,105
	Operating income		–		850,106		223,121		–		1,073,227
	Other income (loss), net		–		306		-42		–		264
	Gain (loss) on derivatives		–		1,574		–		–		1,574
	Equity in earnings of subsidiaries		637,769		–		–		-637,769		–
	Interest expense		–		11,277		12,798		–		24,075
	Income (loss) before income taxes		637,769		840,709		210,281		-637,769		1,050,990
	Provision for income taxes		–		332,795		80,426		–		413,221
	Net income (loss)		637,769		507,914		129,855		-637,769		637,769
	Comprehensive income (loss)	$	962,222	$	836,291	$	129,294	$	-965,585	$	962,222
Condensed Consolidating Statements of Cash Flows	'
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
		Parent		Former		Other		Eliminations		Consolidated
				Guarantors		Subsidiaries
		(in thousands)
	Year ended December 31, 2012:
	Net cash provided by operating activities	$	-39,934	$	1,278,673	$	415,203	$	–	$	1,653,942
	Investing activities:
	Capital investments		-36,918		-1,868,487		-202,350		–		-2,107,755
	Proceeds from sale of property and equipment		26,006		169,149		5,946		–		201,101
	Transfers to restricted cash		-167,788		–		–		–		-167,788
	Transfers from restricted cash		159,245		1		–		–		159,246
	Other		-696		-35,792		45,007		–		8,519
	Net cash used in investing activities		-20,151		-1,735,129		-151,397		–		-1,906,677
	Financing activities:
	Intercompany activities		-198,023		462,443		-264,420		–		–
	Payments on current portion of long-term debt		-1,200		–		–		–		-1,200
	Payments on revolving long-term debt		-2,263,900		–		–		–		-2,263,900
	Borrowings under revolving long-term debt		1,592,400		–		–		–		1,592,400
	Proceeds from issuance of long-term debt		998,780		–		–		–		998,780
	Other		-35,192		1		–		–		-35,191
	Net cash provided by (used in) financing activities		92,865		462,444		-264,420		–		290,889
	Effect of exchange rate changes on cash		–		–		-198		–		-198
	Increase (decrease) in cash and cash equivalents		32,780		5,988		-812		–		37,956
	Cash and cash equivalents at beginning of year		14,711		–		916		–		15,627
	Cash and cash equivalents at end of period	$	47,491	$	5,988	$	104	$	–	$	53,583
	Year ended December 31, 2011:
	Net cash provided by operating activities	$	14,688	$	1,482,853	$	242,276	$	–	$	1,739,817
	Investing activities:
	Capital investments		-66,647		-1,916,246		-201,581		–		-2,184,474
	Proceeds from sale of property and equipment		–		154,261		265		–		154,526
	Transfers to restricted cash		-85,055		–		–		–		-85,055
	Transfers from restricted cash		85,055		–		–		–		85,055
	Other		16,263		-43,961		32,856		–		5,158
	Net cash used in investing activities		-50,384		-1,805,946		-168,460		–		-2,024,790
	Financing activities:
	Intercompany activities		-242,277		315,462		-73,185		–		–
	Payments on current portion of long-term debt		-1,200		–		–		–		-1,200
	Payments on revolving long-term debt		-3,445,900		–		–		–		-3,445,900
	Borrowings under revolving long-term debt		3,696,200		–		–		–		3,696,200
	Other		35,203		–		–		–		35,203
	Net cash provided by financing activities		42,026		315,462		-73,185		–		284,303
	Effect of exchange rate changes on cash		–		–		242		–		242
	Increase (decrease) in cash and cash equivalents		6,330		-7,631		873		–		-428
	Cash and cash equivalents at beginning of year		8,381		7,631		43		–		16,055
	Cash and cash equivalents at end of period	$	14,711	$	–	$	916	$	–	$	15,627

Organization_and_Summary_of_Si3

Organization and Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended			24 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012
Asset Retirement Obligation, Period Increase (Decrease)	'	$39,000,000	'	'
Gains related to the sale of natural gas in underground storage	1,000,000	'	'	-900,000
Outstanding checks included in accounts payable	4,900,000	12,100,000	'	12,100,000
Current assets inventory, tubulars & other equipment	3,700,000	'	'	'
Other Inventory, Noncurrent	16,000,000	'	'	'
Natural gas and oil reserves discount	10.00%	'	'	'
Cash flow hedges impact on ceiling value	70,700,000	'	'	'
Amount recognized is the largest amount of tax benefit, threshold	50.00%	'	'	'
Net capitalized costs exceeding ceiling	'	1,192,400,000	'	'
Cash paid during the year for interest, net of amounts capitalized	36,267,000	17,311,000	19,159,000	'
Cash paid during the year for income taxes	18,787,000	818,000	4,198,000	'
Increase (decrease) in noncash property additions	-12,730,000	-26,240,000	30,389,000	'
Common Stock in Treasury, Shares	9,924,000	64,715,000	'	64,715,000
NGL [Member]	'	'	'	'
Full cost ceiling test, Price	43.45	'	'	'
Over Production [Member]	'	'	'	'
Gas imbalance volume amount in Bcf	11.2	8.4	'	8.4
Gas imbalance asset (liability)	37,900,000	28,400,000	'	28,400,000
Under Production [Member]	'	'	'	'
Gas imbalance volume amount in Bcf	12.5	9.4	'	9.4
Gas imbalance asset (liability)	-38,500,000	-29,900,000	'	-29,900,000
Henry Hub Natural Gas [Member]	'	'	'	'
Full cost ceiling test, Price	3.67	2.76	4.12	'
West Texas Intermediate Oil [Member]	'	'	'	'
Full cost ceiling test, Price	93.42	91.21	92.71	'
Stock Options [Member]	'	'	'	'
Number of common shares, Issued upon assumed exercise of outstanding stock options	1,569,665	'	3,577,104	'
Outstanding options average exercise price	$28.03	'	$11.78	'
Antidilutive securities excluded from computation of earnings per share, shares	1,634,695	1,716,109	881,254	'
Restricted Stock [Member]	'	'	'	'
Number of common shares, Issued upon assumed exercise of outstanding stock options	258,396	'	241,044	'
Antidilutive securities excluded from computation of earnings per share, shares	114,433	602,429	135,352	'
Exploration and Production [Member]	'	'	'	'
Energy Related Inventory, Gas Stored Underground	3,700,000	5,600,000	'	5,600,000
Current assets inventory, tubulars & other equipment	34,100,000	22,500,000	'	22,500,000
Midstream Services [Member]	'	'	'	'
Other Inventory, Noncurrent	$15,100,000	$13,800,000	'	$13,800,000
Gathering Systems [Member]	'	'	'	'
Straight-line depreciation period	'25 years	'	'	'

Acquisitions_And_Divestitures_

Acquisitions And Divestitures (Details) (USD $)	1 Months Ended
In Millions, unless otherwise specified	Apr. 30, 2013	31-May-12	Dec. 31, 2011
		MMcf
Acquisitions And Divestitures [Abstract]	'	'	'
Cost to acquire natural gas properties through definitive purchase agreement	$93	'	'
Proceeds from sale of oil and gas property and equipment	'	$164	'
Divested assets, Production in MMcfe per day	'	24	'
Divested assets, Proved net reserves in Bcfe	'	'	143

Prepaid_Expenses_Details

Prepaid Expenses (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Prepaid Expenses [Abstract]	'	'
Prepaid drilling costs	$9,560	$30,101
Prepaid insurance	7,619	9,507
Prepaid taxes	13,624	572
Total	$30,803	$40,180

Natural_Gas_And_Oil_Producing_1

Natural Gas And Oil Producing Activities (Unaudited) (Narrative) (Details) (USD $)	12 Months Ended			84 Months Ended	120 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2013
Net unevaluated costs excluded from amortization	$322,308,000	$141,384,000	$307,380,000	$185,397,000	$956,469,000	[1]
Percentage of present worth of proved reserves evaluated in audit	95.00%	93.00%	90.00%	'	'
Capitalized interest based on weighted average cost of borrowings	61,600,000	62,100,000	43,400,000	'	'
Capitalized internal costs related to acquisition, exploration and development	262,200,000	236,500,000	207,900,000	'	'
Capitalized internal costs related to acquisition, exploration and development activities - subsidiaries	104,300,000	81,700,000	51,300,000	'	'
Discount Rate Of Natural Gas And Oil Reserves	10.00%	'	'	'	'
Seismic Costs Fayetteville Shale Play [Member]	'	'	'	'	'
Net unevaluated costs excluded from amortization	23,100,000	'	'	'	'
Undeveloped Properties Fayetteville Shale Play [Member]	'	'	'	'	'
Net unevaluated costs excluded from amortization	39,000,000	'	'	'	'
Undeveloped Properties Marcellus Shale Play [Member]	'	'	'	'	'
Net unevaluated costs excluded from amortization	195,700,000	'	'	'	'
Undeveloped Properties New Ventures - Excluding Canada [Member]	'	'	'	'	'
Net unevaluated costs excluded from amortization	275,800,000	'	'	'	'
Exploration Program in Canada [Member]	'	'	'	'	'
Net unevaluated costs excluded from amortization	72,300,000	'	'	'	'
Wells In Progress [Member]	'	'	'	'	'
Net unevaluated costs excluded from amortization	$220,700,000	'	'	'	'
West Texas Intermediate Oil [Member]	'	'	'	'	'
Full cost ceiling test, Price	93.42	91.21	92.71	'	'
Henry Hub Natural Gas [Member]	'	'	'	'	'
Full cost ceiling test, Price	3.67	2.76	4.12	'	'
[1]	Property acquisition costs include $35.0 million, exploration costs include $31.8 million and capitalized interest includes $5.5 million related to our exploration program in Canada.

Natural_Gas_And_Oil_Producing_2

Natural Gas And Oil Producing Activities (Unaudited) (Capitalized Costs of Gas and Oil Properties and the Related Accumulated Depreciation, Depletion, and Amortization) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Proved properties	$12,337,372		$10,259,226		'
Unproved properties	956,469	[1]	1,023,888	[1]	'
Total capitalized costs	13,293,841		11,283,114		'
Less: Accumulated depreciation, depletion and amortization	7,481,335		6,774,174		'
Net capitalized costs	5,812,506		4,508,940		'
Unproved property acquisition costs	168,404	[2]	220,822	[2]	262,886	[2]
Capitalized Costs [Member] | Exploration Program in Canada [Member]	'		'		'
Unproved property acquisition costs	$72,300		$40,400		'
[1]	Includes $72.3 and $40.4 million related to our exploration program in Canada as of December 31, 2013 and 2012, respectively.
[2]	Includes $17.1 million, $3.6 million and $0.2 million, in 2013, 2012 and 2011, respectively, related to our exploration program in Canada.

Natural_Gas_And_Oil_Producing_3

Natural Gas And Oil Producing Activities (Unaudited) (Composition of Net Unevaluated Costs Excluded from Amortization (Details) (USD $)	12 Months Ended			84 Months Ended	120 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2013
Property aquisition costs	$147,791	$81,889	$221,451	$109,994	$561,125
Exploration and Development Costs	166,725	48,428	47,784	38,858	301,795	[1]
Capitalized interest	7,792	11,067	38,145	36,545	93,549	[1]
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost, Total	322,308	141,384	307,380	185,397	956,469	[1]
Exploration Program in Canada [Member]	'	'	'	'	'
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost, Total	72,300	'	'	'	'
Composition of Net Unevaluated Costs [Member] | Exploration Program in Canada [Member]	'	'	'	'	'
Property aquisition costs	'	'	'	'	35,000
Exploration and Development Costs	'	'	'	'	31,800
Capitalized interest	'	'	'	'	$5,500
[1]	Property acquisition costs include $35.0 million, exploration costs include $31.8 million and capitalized interest includes $5.5 million related to our exploration program in Canada.

Natural_Gas_And_Oil_Producing_4

Natural Gas And Oil Producing Activities (Unaudited) (Capitalized Costs Incurred in Natural Gas and Oil Property Acquisition, Exploration and Development Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Proved property acquisition costs	$572		'		$17
Unproved property acquisition costs	168,404	[1]	220,822	[1]	262,886	[1]
Exploration costs	192,164	[2]	197,280	[2]	63,419	[2]
Development costs	1,662,138		1,492,841		1,633,784
Capitalized costs incurred	2,023,278		1,910,943		1,960,106
Full cost pool amortization per Mcfe	1.08		1.31		1.3
Costs Incurred in Natural Gas and Oil Exploration and Development [Member] | Exploration Program in Canada [Member]	'		'		'
Unproved property acquisition costs	17,100		3,600		200
Exploration costs	$11,500		$2,500		$18,400
[1]	Includes $17.1 million, $3.6 million and $0.2 million, in 2013, 2012 and 2011, respectively, related to our exploration program in Canada.
[2]	Includes $11.5 million, $2.5 million and $18.4 million in 2013, 2012 and 2011, respectively, related to our exploration program in Canada.

Natural_Gas_And_Oil_Producing_5

Natural Gas And Oil Producing Activities (Unaudited) (Results of Operations from Natural Gas and Oil Producing Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Natural Gas And Oil Properties [Abstract]	'	'	'
Sales	$2,404,165	$1,963,172	$2,098,914
Production (lifting) costs	-628,817	-505,271	-469,153
Depreciation, depletion and amortization	-735,215	-765,192	-666,107
Impairment of natural gas and oil properties	'	-1,939,734	'
Results of operations - income before income taxes	1,040,133	-1,247,025	963,654
Provision (benefit) for income taxes	416,042	-496,738	375,435
Results of operations	$624,091	($750,287)	$588,219

Natural_Gas_And_Oil_Producing_6

Natural Gas And Oil Producing Activities (Unaudited) (Changes in Proved Natural Gas and Oil Reserves) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMcf	MMcf	MMcf
Natural Gas [Member]	'	'	'
Proved reserves, beginning of year	4,016,798	5,887,207	4,929,980
Revisions of previous estimates	325,374	-2,087,985	34,505
Extensions, discoveries and other additions	3,283,495	918,594	1,459,428
Production	-655,704	-564,484	-499,433
Acquisition of reserves in place	4,114	'	13
Disposition of reserves in place	'	-136,534	-37,286
Proved reserves, end of year	6,974,077	4,016,798	5,887,207
Proved Developed Reserves [Abstract]	'	'	'
Beginning of year	3,195,662	3,254,018	2,687,238
End of year	4,237,495	3,195,662	3,254,018
Proved Undeveloped Reserves [Abstract]	'	'	'
Beginning of year	821,136	2,633,189	2,242,742
End of year	2,736,582	821,136	2,633,189
Oil [Member]	'	'	'
Proved reserves, beginning of year	244	996	1,219
Revisions of previous estimates	88	-44	-125
Extensions, discoveries and other additions	229	154	2
Production	-188	-83	-97
Disposition of reserves in place	'	-779	-3
Proved reserves, end of year	373	244	996
Proved Developed Reserves [Abstract]	'	'	'
Beginning of year	243	983	1,173
End of year	372	243	983
Proved Undeveloped Reserves [Abstract]	'	'	'
Beginning of year	1	13	46
End of year	1	1	13

Natural_Gas_And_Oil_Producing_7

Natural Gas And Oil Producing Activities (Unaudited) (Standardized Measures of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Natural Gas And Oil Properties [Abstract]	'	'	'
Future cash inflows	$22,624,562	$9,570,652	$22,012,205
Future production costs	-8,895,956	-4,737,297	-8,080,207
Future development costs	-3,626,496	-711,050	-3,425,185
Future income tax expense	-3,223,271	-745,251	-3,366,175
Future net cash flows	6,878,839	3,377,054	7,140,638
10% annual discount for estimated timing of cash flows	-3,142,795	-1,326,389	-3,689,838
Standardized measure of discounted future net cash flows	$3,736,044	$2,050,665	$3,450,800
Annual discount for estimated timing of cash flows percent	10.00%	10.00%	10.00%

Natural_Gas_And_Oil_Producing_8

Natural Gas And Oil Producing Activities (Unaudited) (Analysis of Changes in the Standardized Measure) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Natural Gas And Oil Properties [Abstract]	'	'	'
Standardized measure, beginning of year	$2,050,665	$3,450,800	$3,013,750
Sales and transfers of natural gas and oil produced, net of production costs	-1,774,043	-1,443,606	-1,632,156
Net changes in prices and production costs	1,852,772	-2,604,591	-381,131
Extensions, discoveries, and other additions, net of future production and development costs	1,454,634	549,601	1,163,992
Acquisition of reserves in place	4,914	'	30
Sales of reserves in place	'	-157,108	-11,761
Revisions of previous quantity estimates	348,996	-1,109,409	34,221
Accretion of Discount	232,385	480,315	426,245
Net change in income taxes	-1,119,798	1,079,158	-103,643
Changes in estimated future development costs	-196,394	2,475,470	70,492
Previously estimated development costs incurred during the year	222,982	61,949	564,894
Changes in production rates (timing) and other	658,931	-731,914	305,867
Standardized measure, end of year	$3,736,044	$2,050,665	$3,450,800

Recovered_Sheet1

Derivatives And Risk Management (Narratives) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Accumulated other comprehensive income, net gain related to hedging activities	$9.30	'
Deferred income tax liability, accumulated other comprehensive income	6.2	'
Cash flow hedge after-tax net gain to be transferred from accumulated other comprehensive income to earnings during the next twelve months	9.3	'
Realized Gain From Settled Contracts	309.2	631.5
Interest Rate Swap [Member]	'	'
Derivative [Line Items]	'	'
Notional amount of derivatives	$170	'
Year 2014 [Member]	'	'
Derivative [Line Items]	'	'
Volume of Natural Gas Production (in Bcf), Basis Swaps Not Qualifying for Hedge Accounting Treatment	21,300,000,000	'
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps Not Qualifying for Hedge Accounting Treatment	181,600,000,000	'
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	'

Recovered_Sheet2

Derivatives And Risk Management (Balance Sheet Classification) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative [Line Items]	'	'
Derivative assets	$78,503	$292,144
Derivative liabilities	40,490	4,266
Designated as Hedging Instrument [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	20,631	287,993
Derivative liabilities	3,884	'
Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Asset [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	20,631	279,443
Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Other Long-Term Assets [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	'	8,550
Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Other Current Liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	3,884	'
Not Designated as Hedging Instrument [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	57,872	4,151
Derivative liabilities	36,606	4,266
Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Asset [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	37,382	'
Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Other Current Liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	185	'
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Derivative Asset [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	12,858	3,250
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Other Long-Term Assets [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	107	901
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Other Current Liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	1,501	138
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Long-Term Assets [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	7,525	'
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Current Liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	1,520	'
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Long-Term Liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	3,012	'
Not Designated as Hedging Instrument [Member] | Fixed Price Call Options [Member] | Other Long-Term Liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	$30,388	$4,128

Derivatives_And_Risk_Managemen2

Derivatives And Risk Management (Fixed Price Swaps, Volumes of Natural Gas Production (in Bcf)) (Details) (Year 2014 [Member])	Dec. 31, 2013
	ft3
Derivative [Line Items]	'
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	382,300,000,000
Fixed and Floating Price Swaps [Member]	'
Derivative [Line Items]	'
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	200,700,000,000
Fixed and Floating Price Swaps [Member] | Not Designated as Hedging Instrument [Member]	'
Derivative [Line Items]	'
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps	181,600,000,000

Derivatives_And_Risk_Managemen3

Derivatives And Risk Management (Before Tax Effect of all Cash Flow Hedges on the Condensed Consolidated Financial Statements) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fixed Price Swaps [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income, Effective Portion	$37,931	$178,660
Costless Collar [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income, Effective Portion	'	39,247
Gas Sales [Member] | Fixed Price Swaps [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Gain Reclassified from Accumulated Other Comprehensive Income into Earnings, Effective Portion	309,177	413,410
Derivative Instruments, Gain (Loss) Recognized in Earnings, Ineffective Portion	-1,652	2,450
Gas Sales [Member] | Costless Collar [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Gain Reclassified from Accumulated Other Comprehensive Income into Earnings, Effective Portion	'	218,119
Derivative Instruments, Gain (Loss) Recognized in Earnings, Ineffective Portion	'	($24)

Derivatives_And_Risk_Managemen4

Derivatives And Risk Management (Before Tax Effect of Basis Swaps that do not Qualify for Hedge Accounting Consolidated Statements of Operations) (Details) (Gas Sales [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Basis Swaps [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Unrealized Loss Recognized in Earnings	$7,450	$766
Derivative Instruments, Realized Gain (Loss) Recognized in Earnings	4,772	2,162
Fixed Price Call Options [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Unrealized Loss Recognized in Earnings	-26,259	-4,128
Fixed and Floating Price Swaps [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Unrealized Loss Recognized in Earnings	37,197	'
Fair Value Swaps [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Unrealized Loss Recognized in Earnings	'	1,208
Derivative Instruments, Realized Gain (Loss) Recognized in Earnings	'	-14,958
Interest Rate Swap [Member]	'	'
Derivative [Line Items]	'	'
Derivative Instruments, Unrealized Loss Recognized in Earnings	2,992	'
Derivative Instruments, Realized Gain (Loss) Recognized in Earnings	($11)	'

Reclassification_From_Accumula2

Reclassification From Accumulated Other Comprehensive Income (Components Of Accumulated Other Comprehensive Income) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Line Items]	'		'		'
Beginning balance	$149,804	[1]	'		'
Other comprehensive income (loss) before reclassifications	17,616	[1]	'		'
Amounts reclassified	-171,762	[1],[2]	'		'
Net current-period other comprehensive income (loss)	-154,146	[1]	-258,624		324,453
Ending balance	-4,342	[1]	149,804	[1]	'
Gains And Losses On Cash Flow Hedges [Member]	'		'		'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'		'		'
Beginning balance	172,166	[1]	'		'
Other comprehensive income (loss) before reclassifications	21,619	[1]	'		'
Amounts reclassified	-184,515	[1],[2]	'		'
Net current-period other comprehensive income (loss)	-162,896	[1]	'		'
Ending balance	9,270	[1]	'		'
Pension And Other Postretirement [Member]	'		'		'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'		'		'
Beginning balance	-22,311	[1]	'		'
Amounts reclassified	12,753	[1],[2]	'		'
Net current-period other comprehensive income (loss)	12,753	[1]	'		'
Ending balance	-9,558	[1]	'		'
Foreign Currency [Member]	'		'		'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'		'		'
Beginning balance	-51	[1]	'		'
Other comprehensive income (loss) before reclassifications	-4,003	[1]	'		'
Net current-period other comprehensive income (loss)	-4,003	[1]	'		'
Ending balance	($4,054)	[1]	'		'
[1]	All amounts are net of tax.
[2]	See separate table below for details about these reclassifications.

Reclassification_From_Accumula3

Reclassification From Accumulated Other Comprehensive Income (Amounts Reclassified From Accumulated Other Comprehensive Income) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Gas sales	$2,381,478		$1,956,311		$2,078,151
General and administrative expenses	191,310		175,147		158,041
Income (loss) before income taxes	1,190,377		-1,150,203		1,050,990
Provision (benefit) for income taxes	486,874	[1]	-443,139	[1]	413,221	[1]
Reclassification Out Of Accumulated Other Comprehensive Income [Member]	'		'		'
Net income (loss)	171,762		'		'
Parent [Member]	'		'		'
Income (loss) before income taxes	'		-707,064		637,769
Gains And Losses On Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member]	'		'		'
Income (loss) before income taxes	307,525		'		'
Provision (benefit) for income taxes	123,010		'		'
Net income (loss)	184,515		'		'
Gains And Losses On Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | Settlements [Member]	'		'		'
Gas sales	309,177		'		'
Gains And Losses On Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | Ineffectiveness [Member]	'		'		'
Gas sales	-1,652		'		'
Pension And Other Postretirement [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member]	'		'		'
General and administrative expenses	-21,009	[2]	'		'
Income (loss) before income taxes	-21,009		'		'
Provision (benefit) for income taxes	-8,256		'		'
Net income (loss)	($12,753)		'		'
[1]	Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.
[2]	Included in the computation of net periodic pension cost (see Note 12 for additional details).

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details)	Dec. 31, 2013	Dec. 31, 2012
7.5% Senior Notes due 2018 [Member]	'	'
Debt instrument, interest rate, stated percentage	7.50%	7.50%
Yield, Publicly-traded debt market	2.60%	2.60%
4.10% Senior Notes Due 2022 [Member]	'	'
Debt instrument, interest rate, stated percentage	4.10%	4.10%
Yield, Publicly-traded debt market	4.20%	'

Fair_Value_Measurements_Carryi

Fair Value Measurements (Carrying Amount and Estimated Fair Values of Financial Instruments) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
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	22,938	53,583
Restricted cash	'	8,542
Credit facility	282,900	'
Senior notes	1,668,396	1,669,473
Derivative instruments, net	38,013	287,878
Fair Value [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Cash and cash equivalents	22,938	53,583
Restricted cash	'	8,542
Credit facility	282,900	'
Senior notes	1,795,935	1,917,005
Derivative instruments, net	$38,013	$287,878

Fair_Value_Measurements_Summar

Fair Value Measurements (Summary Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Significant Observable Inputs, Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative assets	$65,538	$287,993
Derivative liabilities	-8,601	'
Total	56,937	287,993
Significant Unobservable Inputs, Level 3 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative assets	12,965	4,151
Derivative liabilities	-31,889	-4,266
Total	-18,924	-115
Fair Value [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative assets	78,503	292,144
Derivative liabilities	-40,490	-4,266
Total	$38,013	$287,878

Fair_Value_Measurements_Assets

Fair Value Measurements (Assets Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3), Reconciliation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Measurements [Abstract]	'	'
Balance at beginning of period	($115)	$182,119
Total gains or losses (realized/unrealized): Included in earnings	-14,037	216,857
Total gains or losses (realized/unrealized): Included in other comprehensive income	'	-178,847
Purchases, issuances, and settlements:	'	'
Purchases	'	'
Issuances	'	'
Settlements	-4,772	-220,244
Transfers into/out of Level 3	'	'
Balance at end of period	-18,924	-115
Change in unrealized gains included in earnings relating to derivatives still held as of December 31	($18,809)	($3,362)

Debt_Narrative_Details

Debt (Narrative) (Details) (USD $)

0 Months Ended

Dec. 16, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 16, 2013

Dec. 31, 2012

7.5% Senior Notes due 2018 [Member]

7.5% Senior Notes due 2018 [Member]

4.10% Senior Notes Due 2022 [Member]

4.10% Senior Notes Due 2022 [Member]

7.15% Senior Notes due 2018 [Member]

7.15% Senior Notes due 2018 [Member]

7.35% Senior Notes due 2017 [Member]

7.35% Senior Notes due 2017 [Member]

7.125% Senior Notes due 2017 [Member]

7.125% Senior Notes due 2017 [Member]

Credit Facility [Member]

Credit Facility [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage

'

7.50%

7.50%

4.10%

4.10%

7.15%

7.15%

7.35%

7.35%

7.13%

7.13%

'

'

Senior notes redemption date

1-Dec-18

'

'

'

'

'

'

'

'

'

'

'

'

Basis Points

'

'

'

'

'

'

'

'

'

'

'

1.50%

2.00%

Unsecured revolving credit facility, borrowing capacity

$2,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Unsecured revolving credit facility, increase in current borrowing capacity potential

'

'

'

'

'

'

'

'

'

'

'

$500,000,000

'

Debt percentage of capital structure covenant

60.00%

'

'

'

'

'

'

'

'

'

'

'

'

Stated interest rate

'

7.50%

7.50%

4.10%

4.10%

7.15%

7.15%

7.35%

7.35%

7.13%

7.13%

'

'

Debt_Components_Of_Debt_Detail

Debt (Components Of Debt) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'
Short-term debt	$1,200	$1,200
Variable rate (1.644% and 2.200% at December 31, 2013 and December 31, 2012, respectively) Credit Facility, expires December 2018	282,900	'
Unamortized discount	-1,004	-1,127
Long-term debt	1,950,096	1,668,273
Total debt	1,951,296	1,669,473
Variable interest rate	1.64%	2.20%
7.15% Senior Notes due 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Short-term debt	1,200	1,200
Stated interest rate	7.15%	7.15%
7.35% Senior Notes due 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	15,000	15,000
Stated interest rate	7.35%	7.35%
7.125% Senior Notes due 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	25,000	25,000
Stated interest rate	7.13%	7.13%
7.15% Senior Notes due 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	28,200	29,400
Stated interest rate	7.15%	7.15%
7.5% Senior Notes due 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	600,000	600,000
Stated interest rate	7.50%	7.50%
4.10% Senior Notes Due 2022 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	$1,000,000	$1,000,000
Stated interest rate	4.10%	4.10%

Debt_Schedule_of_Long_Term_Deb

Debt (Schedule of Long Term Debt Maturities) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt [Abstract]	'
2015	$1,200
2016	1,200
2017	41,200
2018	907,500
Thereafter	1,000,000
Total long-term debt maturities	$1,951,100

Commitments_and_Contingencies_

Commitments and Contingencies (Details)

1 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Jul. 31, 2013

Aug. 31, 2011

Dec. 31, 2010

Mar. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2010

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

USD ($)

USD ($)

USD ($)

item

USD ($)

USD ($)

USD ($)

SES and SEPCO [Member]

Midstream Services and E&P [Member]

Exploration Program in Canada [Member]

Exploration Program in Canada [Member]

Exploration Program in Canada [Member]

Maximum [Member]

Maximum [Member]

Minimum [Member]

acre

USD ($)

USD ($)

USD ($)

CAD

CAD

SES and SEPCO [Member]

Midstream Services and E&P [Member]

Midstream Services and E&P [Member]

item

acre

USD ($)

Operating Leases, Future Minimum Payments, Due in Two Years

'

'

'

'

$55,900,000

'

'

'

$24,500,000

'

'

'

'

'

'

Future Demand Transportation Charges Due 2014

'

'

'

'

362,800,000

'

'

'

'

'

'

'

'

'

'

Future Demand Transportation Charges Due 2015

'

'

'

'

399,200,000

'

'

'

'

'

'

'

'

'

'

Future Demand Transportation Charges Due 2016

'

'

'

'

413,200,000

'

'

'

'

'

'

'

'

'

'

Future Demand Transportation Charges Due 2017

'

'

'

'

375,700,000

'

'

'

'

'

'

'

'

'

'

Future Demand Transportation Charges Due 2018

'

'

'

'

363,300,000

'

'

'

'

'

'

'

'

'

'

Future Demand Transportation Charges Due Thereafter (After 2018)

'

'

'

'

1,594,700,000

'

'

'

'

'

'

'

'

'

'

Number of leases

'

'

'

'

'

'

'

'

11

'

'

'

'

'

'

Aggregate annual lease payment for the 11 leases for pressure pumping equipment for E&P

'

'

'

'

'

'

'

'

7,500,000

'

'

'

'

'

'

Lease Expiration Date

'

'

'

'

31-Dec-27

'

'

'

'

'

'

'

'

1-Jan-18

1-Dec-17

Operating Leases, Future Minimum Payments Due in 2014

'

'

'

'

65,200,000

'

'

'

38,600,000

'

'

'

'

'

'

Operating Leases, Future Minimum Payments, Due in 2015

'

'

'

'

55,900,000

'

'

'

24,500,000

'

'

'

'

'

'

Operating Leases, Future Minimum Payments, Due in 2016

'

'

'

'

44,600,000

'

'

'

17,200,000

'

'

'

'

'

'

Operating Leases, Future Minimum Payments, Due in 2017

'

'

'

'

27,800,000

'

'

'

9,200,000

'

'

'

'

'

'

Operating Leases, Future Minimum Payments, Due in 2018

'

'

'

'

10,800,000

'

'

'

3,700,000

'

'

'

'

'

'

Obligations for demand and similar charges under transportation agreements

'

'

'

'

'

'

'

3,500,000,000

'

'

'

'

'

'

'

Contractual Obligation

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

Operating Leases, Future Minimum Payments, Due Thereafter

'

'

'

'

24,900,000

'

'

'

700,000

'

'

'

'

'

'

Unrecorded capital investments obligation, Exploration program acres coverage (acres)

'

'

'

'

'

'

'

'

'

'

'

2,500,000

'

'

'

Unrecorded capital investments obligation

'

'

'

'

'

'

'

'

'

'

'

47,000,000

'

'

'

Unrecorded promissory note payable

'

'

'

'

'

'

'

'

'

'

'

44,500,000

'

'

'

Capital investments related to E&P program in Canada

'

'

'

'

35,400,000

11,600,000

18,700,000

'

'

36,900,000

39,200,000

'

'

'

'

Area of land purchased

'

'

'

'

'

26

'

'

'

'

'

'

'

'

'

Current obligation for construction costs incurred

'

'

'

'

38,000,000

'

'

'

'

'

'

'

'

'

'

Lease period upon construction completion

'

'

'

'

'P5Y

'

'

'

'

'

'

'

'

'

'

Litigation settlement, gross

'

'

11,400,000

'

'

'

'

'

'

'

'

'

'

'

'

Litigation, portion of profits considered for disgorgement

'

'

381,500,000

'

'

'

'

'

'

'

'

'

'

'

'

Actual damages recoverable by plaintiff per August 2011 judgement

'

11,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Disgorgement recoverable by plaintiff per August 2011 judgement

'

23,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Prejudgement interest and attorney's fees recoverable by plaintiff per August 2011 judgement

'

8,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Disgorgement recoverable by plaintiff to be reversed

23,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Actual damages recoverable by plaintiff to be reversed

11,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Litigation settlement upheld

11,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Litigation, SEPCO's estimated gross liability including interest and attorney's fees.

'

'

'

'

$45,500,000

'

'

'

'

'

'

'

'

'

'

Number of horizontal wells operated by SEECO in Arkansas

'

'

'

27

'

'

'

'

'

'

'

'

'

'

'

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effective tax rate of provision for income taxes	40.90%	38.50%	39.30%
Net current deferred income tax liability	$24,353,000	$106,123,000	'
Income taxes paid	18,787,000	818,000	4,198,000
Operating Loss Carryforwards	411,994,000	217,276,000	'
Alternative minimum tax credit carryforward	76,864,000	89,016,000	'
Statutory depletion carryforward	12,900,000	'	'
Windfalls Included In Net Operating Loss Carryforwards But Not Reflected In Deferred Tax Assets	131,300,000	'	'
Deferred Tax Assets, Valuation Allowance	2,900,000	'	'
Net long-term deferred tax liabilities	1,526,700,000	1,045,500,000	'
Federal [Member]	'	'	'
Income taxes paid	15,500,000	'	'
Operating Loss Carryforwards	1,174,700,000	'	'
State [Member]	'	'	'
Income taxes paid	3,300,000	800,000	'
Operating Loss Carryforwards	878,000,000	'	'
Minimum [Member]	'	'	'
Net operating loss carryforwards expiration date	31-Dec-28	'	'
Maximum [Member]	'	'	'
Net operating loss carryforwards expiration date	31-Dec-32	'	'
Exploration Program in Canada [Member]	'	'	'
Net operating loss carryforward	$22,300,000	'	'
Exploration Program in Canada [Member] | Minimum [Member]	'	'	'
Net operating loss carryforwards expiration date	1-Jan-30	'	'
Exploration Program in Canada [Member] | Maximum [Member]	'	'	'
Net operating loss carryforwards expiration date	31-Dec-33	'	'

Income_Taxes_Provision_Benefit

Income Taxes (Provision (Benefit) for Income Taxes) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Current:	'		'		'
Federal Current	($12,151)		$15,500		$3,378
State Current	1,080		3,189		820
Total Current	-11,071		18,689		4,198
Deferred:	'		'		'
Federal Deferred	409,359		-388,209		345,922
State Deferred	87,823		-71,582		60,941
Foreign Deferred	763		-2,037		2,160
Total Deferred	497,945		-461,828		409,023
Total provision for income taxes	$486,874	[1]	($443,139)	[1]	$413,221	[1]
[1]	Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.

Income_Taxes_Reconciliation_of

Income Taxes (Reconciliation of Provision (Benefit) for Income Taxes) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Income Taxes [Abstract]	'		'		'
Expected provision (benefit) at federal statutory rate	$416,632		($402,571)		$367,854
Increase (decrease) resulting from:	'		'		'
State income taxes, net of federal income tax effect	53,130		-44,454		40,145
Nondeductible expenses	3,404		2,100		1,244
Other	13,708		1,786		3,978
Provision (benefit) for income taxes	$486,874	[1]	($443,139)	[1]	$413,221	[1]
[1]	Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.

Income_Taxes_Net_Deferred_Tax_

Income Taxes (Net Deferred Tax Liability) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax liabilities:	'	'
Differences between book and tax basis of property	$2,114,685	$1,441,149
Cash flow hedges	13,171	112,625
Other	10,715	4,460
Total deferred tax liabilities	2,138,571	1,558,234
Deferred tax assets	'	'
Accrued compensation	15,718	16,387
Alternative minimum tax credit carryforward	76,864	89,016
Stored natural gas	9,272	7,812
Accrued pension costs	1,821	7,686
Asset retirement obligations	53,419	39,249
Net operating loss carryforward	411,994	217,276
Differences between book and tax basis of property - state	11,045	16,872
Other	7,405	12,354
Total deferred tax assets	587,538	406,652
Net deferred tax liability	$1,551,033	$1,151,582

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation [Abstract]	'	'
Asset retirement obligation at January 1	$100,637,000	$37,693,000
Accretion of discount	5,643,000	2,394,000
Obligations incurred	22,241,000	23,327,000
Obligations settled/removed	-2,341,000	-8,804,000
Revisions of estimates	7,366,000	46,027,000
Current liability	5,549,000	4,091,000
Long-term liability	127,997,000	96,546,000
Asset retirement obligation at December 31	133,546,000	100,637,000
Asset retirement obligation period increase due to correction	'	$39,000,000

Retirement_and_Employee_Benefi2

Retirement and Employee Benefit Plans (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Contribution expense	$2,500,000	$2,200,000	$1,900,000
Contributions capitalized	2,900,000	2,800,000	3,800,000
Amount of amortization of prior period service costs reclassified from AOCI to general and administrative expenses	21,000,000	'	'
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Change in accumulated other comprehensive income (loss)	19,200,000	-8,400,000	'
Change in accumulated other comprehensive income (loss) after tax	11,600,000	-5,000,000	'
Prior service costs	100,000	'	'
Net loss	200,000	'	'
Company's expected contribution	12,000,000	'	'
Net periodic pension cost	13,471,000	11,072,000	9,796,000
Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Change in accumulated other comprehensive income (loss)	1,800,000	-2,400,000	'
Change in accumulated other comprehensive income (loss) after tax	1,100,000	-1,400,000	'
Company's expected contribution	400,000	'	'
Net periodic pension cost	2,871,000	2,401,000	1,695,000
United States Postretirement Benefit Plan of US Entity, Defined Benefit [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined benefit plan included in accumulated other comprehensive income (loss)	-15,900,000	-36,900,000	'
Defined benefit plan included in accumulated other comprehensive income (loss) after tax	-9,600,000	-22,300,000	'
Change In Plan Assets [Member] | Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Employer contributions	12,520,000	11,084,000	'
Change In Plan Assets [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Employer contributions	$115,000	$84,000	'

Retirement_and_Employee_Benefi3

Retirement and Employee Benefit Plans (Changes in the Plans Benefit Obligations, Fair Value of Assets, and Funded Status) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	$13,789	$10,942	$9,323
Interest cost	4,104	4,050	3,671
Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	2,296	1,832	1,354
Interest cost	441	398	252
Change In Benefit Obligation [Member] | Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Benefit obligation at January 1	105,432	81,738	'
Service cost	13,789	10,942	'
Interest cost	4,104	4,050	'
Actuarial loss	-11,107	14,981	'
Benefits paid	-8,492	-6,951	'
Plan amendments	'	672	'
Settlements	-520	'	'
Benefit obligation at December 31	103,206	105,432	'
Change In Benefit Obligation [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Benefit obligation at January 1	11,464	6,793	'
Service cost	2,296	1,832	'
Interest cost	441	398	'
Participant contributions	24	21	'
Actuarial loss	-1,706	2,525	'
Benefits paid	-139	-105	'
Benefit obligation at December 31	12,380	11,464	'
Change In Plan Assets [Member] | Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Employer contributions	12,520	11,084	'
Benefits paid	-8,492	-6,951	'
Settlements	-507	'	'
Fair value of plan assets at January 1	83,347	68,023	'
Fair value of plan assets at December 31	99,339	83,347	'
Actual return/(loss) on plan assets	12,471	11,191	'
Funded status of plans at December 31	-3,867	-22,085	'
Change In Plan Assets [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Employer contributions	115	84	'
Participant contributions	24	21	'
Benefits paid	-139	-105	'
Funded status of plans at December 31	($12,380)	($11,464)	'

Retirement_and_Employee_Benefi4

Retirement and Employee Benefit Plans (Projected Benefit Obligation, Accumulated Benefit Obligation and Fair Value of Plan Assets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Retirement and Employee Benefit Plans [Abstract]	'	'
Projected benefit obligation	$103,206	$105,432
Accumulated benefit obligation	100,208	100,379
Fair value of plan assets	$99,339	$83,347

Retirement_and_Employee_Benefi5

Retirement and Employee Benefit Plans (Pension and Other Postretirement Benefit Costs) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	$13,789	$10,942	$9,323
Interest cost	4,104	4,050	3,671
Expected return on plan assets	-6,136	-5,426	-4,398
Amortization of prior service cost	103	286	344
Amortization of net loss	1,541	1,220	856
Net periodic benefit cost	13,401	11,072	9,796
Settlements and curtailments	70	'	'
Total benefit cost	13,471	11,072	9,796
Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	2,296	1,832	1,354
Interest cost	441	398	252
Amortization of transition obligation	'	64	64
Amortization of prior service cost	14	14	14
Amortization of net loss	120	93	11
Net periodic benefit cost	2,871	2,401	1,695
Total benefit cost	$2,871	$2,401	$1,695

Retirement_and_Employee_Benefi6

Retirement and Employee Benefit Plans (Amounts Recognized in Other Comprehensive Income) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Pension Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial loss arising during the year	$17,454
Amortization of prior service cost	104
Amortization of net loss	1,541
Settlements	70
Tax effect	-7,535
Total	11,634
Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial loss arising during the year	1,706
Amortization of prior service cost	14
Amortization of net loss	120
Tax effect	-721
Total	$1,119

Retirement_and_Employee_Benefi7

Retirement and Employee Benefit Plans (Pension Weighted Average Assumptions Used in the Measurement of Benefit Obligations) (Details)	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Discount rate	5.00%	4.00%
Rate of compensation increase	4.50%	4.50%
Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Discount rate	5.00%	4.00%

Retirement_and_Employee_Benefi8

Retirement and Employee Benefit Plans (Weighted Average Assumptions Used in the Measurement of Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	4.00%	5.00%	5.50%
Expected return on plan assets	7.00%	7.50%	7.50%
Rate of compensation increase	4.50%	4.50%	4.50%
Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate	4.00%	5.00%	5.50%

Retirement_and_Employee_Benefi9

Retirement and Employee Benefit Plans (Measurement Purposes Following Trend Rates were Assumed) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Retirement and Employee Benefit Plans [Abstract]	'	'
Health care cost trend assumed for next year	8.00%	8.00%
Rate to which the cost trend is assumed to decline	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	'2032	'2031

Recovered_Sheet3

Retirement and Employee Benefit Plans (One Percentage Point Change in Assumed Health Care Cost Trend Rates) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Retirement and Employee Benefit Plans [Abstract]	'
Effect on total service and interest cost components increase	$457
Effect on total service and interest cost components decrease	-373
Effect on postretirement benefit obligations increase	1,693
Effect on postretirement benefit obligation decrease	($1,413)

Recovered_Sheet4

Retirement and Employee Benefit Plans (Benefit Payments which Reflect Expected Future Service) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Pension Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
2013	$6,384
2014	6,280
2015	8,075
2016	8,553
2017	9,517
2018-2022	58,894
Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
2013	404
2014	542
2015	730
2016	801
2017	994
2018-2022	$7,545

Recovered_Sheet5

Retirement and Employee Benefit Plans (Plan Assets Allocation to any Asset Class Falls Outside of the Specified Range) (Details)	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]	'
Target asset allocations	100.00%
Actual asset allocations	100.00%
U.S. Equity [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Target asset allocations	35.00%	[1]
Actual asset allocations	36.00%	[1]
International Equity [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Target asset allocations	30.00%	[2]
Actual asset allocations	31.00%	[2]
Emerging Market Equity [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Target asset allocations	5.00%	[3]
Actual asset allocations	6.00%	[3]
Fixed Income [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Target asset allocations	29.00%	[4]
Actual asset allocations	26.00%	[4]
Cash and Cash Equivalents [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Target asset allocations	1.00%	[5]
Actual asset allocations	1.00%	[5]
[1]	Asset category above includes the following equity securities in the table below: U.S large cap growth equity, U.S. large cap value equity, U.S. large cap core equity, and U.S. small cap equity.
[2]	Asset category above includes Non-U.S. equity securities in the table below.
[3]	Asset category above includes Emerging markets equity securities below.
[4]	Asset category above includes Fixed income pension plan assets in the table below.
[5]	Asset category above includes Cash and cash equivalents pension plan assets in the table below.

Recovered_Sheet6

Retirement and Employee Benefit Plans (Fair Value Measurement of Pension Plan Assets) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Large Cap Growth Equity [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	$7,660	[1]	$4,588	[1]
Large Cap Growth Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	7,660	[1]	4,588	[1]
Large Cap Value Equity [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	8,174	[2]	5,257	[2]
Large Cap Value Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	8,174	[2]	5,257	[2]
Large Cap Core Equity [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	16,438	[3]	11,564	[3]
Large Cap Core Equity [Member] | Significant Observable Inputs, Level 2 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	16,438	[3]	11,564	[3]
Small Cap Equity [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	3,245	[4]	2,792	[4]
Small Cap Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	3,245	[4]	2,792	[4]
International Equity [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	30,628	[5]	21,891	[5]
International Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	30,628	[5]	21,891	[5]
Emerging Market Equity [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	6,374	[6]	4,454	[6]
Emerging Market Equity [Member] | Significant Observable Inputs, Level 2 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	6,374	[6]	4,454	[6]
Fixed Income [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	25,523		31,021
Fixed Income [Member] | Significant Observable Inputs, Level 2 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	25,523		31,021
Cash and Cash Equivalents [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	1,296		1,780
Cash and Cash Equivalents [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	1,296		1,780
Equity Securities [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	99,338		83,347
Equity Securities [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	51,003		36,308
Equity Securities [Member] | Significant Observable Inputs, Level 2 [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Fair value of plan assets	$48,335		$47,039
[1]	Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
[2]	Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
[3]	An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
[4]	Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
[5]	Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
[6]	An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.

StockBased_Compensation_Narrat

Stock-Based Compensation (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Expiration period from date of grant	'10 years	'	'
Period of service for immediate vesting upon death, disability or retirement	'3 years	'	'
Unrecognized compensation cost related to unvested stock option and restricted stock grants	$16,200,000	'	'
Weighted average period over which cost is recognized, years	'2 years 1 month 6 days	'	'
2004 Plan [Member]	'	'	'
Maximum shares	16,800,000	'	'
Expiration period from date of grant	'7 years	'	'
2002 Plan [Member]	'	'	'
Maximum shares	300,000	'	'
2000 Plan [Member]	'	'	'
Maximum shares	1,125,000	'	'
Stock Options [Member]	'	'	'
Vesting period for stock awards from grant date	'3 years	'	'
Stock-based compensation costs - expensed	5,494,000	5,427,000	4,959,000
Stock-based compensation costs - capitalized	4,812,000	4,468,000	3,365,000
Deferred tax benefit (liability) recorded	4,000,000	2,200,000	1,700,000
Weighted-average grant-date fair value of options granted	$13.39	$16.91	$18.17
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value	21,700,000	44,100,000	27,000,000
Restricted Stock [Member]	'	'	'
Vesting period for stock awards from grant date	'4 years	'	'
Stock-based compensation costs - expensed	7,432,000	6,368,000	5,591,000
Stock-based compensation costs - capitalized	7,469,000	5,994,000	5,162,000
Deferred tax benefit (liability) recorded	-14,800,000	-1,400,000	-2,100,000
Weighted-average grant-date fair value of options granted	$38.92	$34.39	$36.41
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	62,500,000	'	'
Weighted average period over which cost is recognized, restricted stock (years)	'3 years 4 months 24 days	'	'
Total fair value of restricted stock grants	43,200,000	18,500,000	19,400,000
Total fair value of shares vested	13,900,000	12,600,000	10,900,000
Performance Shares [Member]	'	'	'
Vesting period for stock awards from grant date	'3 years	'	'
Stock-based compensation costs - expensed	3,300,000	19,100,000	15,800,000
Deferred tax benefit (liability) recorded	$45,300,000	$41,300,000	'
Maximum [Member] | 2004 Plan [Member]	'	'	'
Maximum shares	20,500,000	'	'

StockBased_Compensation_Compen

Stock-Based Compensation (Compensation Costs Related To Stock Options) (Details) (Stock Options [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock Options [Member]	'	'	'
Stock-based compensation cost related to stock options - general and administrative expense	$5,494	$5,427	$4,959
Stock-based compensation cost related to stock options - capitalized	$4,812	$4,468	$3,365

StockBased_Compensation_RiskFr

Stock-Based Compensation (Risk-Free Interest Rate) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock-Based Compensation [Abstract]	'	'	'
Risk-free interest rate	1.50%	0.60%	0.90%
Expected volatility	38.60%	58.20%	58.10%
Expected term	'5 years	'5 years	'5 years

StockBased_Compensation_Summar

Stock-Based Compensation (Summary of Options Outstanding and Options Exerciseable) (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock options, Outstanding at January 1, Number of options	3,649,520	4,741,732	4,769,122
Stock options, Granted, Number of options	571,166	613,120	853,478
Stock options, Exercised, Number of options	-833,132	-1,607,784	-850,659
Stock options, Forfeited or expired, Number of options	-74,861	-97,548	-30,209
Stock options, Outstanding at December 31, Number of options	3,312,693	3,649,520	4,741,732
Stock options, Outstanding at January 1, Weighted average exercise price	$29.84	$21.24	$16.13
Stock options, Granted, Weighted average exercise price	$38.95	$34.34	$36.64
Stock options, Exercised, Weighted average exercise price	$12.12	$5.71	$7.54
Stock options, Forfeited or expired, Weighted average exercise price	$37.31	$37.76	$35.46
Stock options, Outstanding at December 31, Weighted average exercise price	$35.70	$29.84	$21.24
Stock Options [Member]	'	'	'
Stock options, Outstanding at December 31, Number of options	3,312,693	'	'
Stock options, Outstanding at December 31, Weighted average exercise price	$35.70	'	'
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	'4 years 4 months 24 days	'	'
Options Outstanding - Aggregate Intrinsic Value (thousands)	$12,882	'	'
Stock options, Exercisable at December 31,	2,103,828	'	'
Stock options Exercisable at December 31, Weighted average exercise price	$34.96	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'2 years 10 months 24 days	'	'
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	'2 years 10 months 24 days	'	'
Options Exercisable - Aggregate Intrinsic Value (thousands)	$10,022	'	'
Range of Exercise Prices $20.34-$29.69 [Member] | Stock Options [Member]	'	'	'
Stock options, Outstanding at December 31, Number of options	273,134	'	'
Stock options, Outstanding at December 31, Weighted average exercise price	$27.31	'	'
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	'1 year 2 months 12 days	'	'
Stock options, Exercisable at December 31,	265,025	'	'
Stock options Exercisable at December 31, Weighted average exercise price	$27.29	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'1 year 1 month 6 days	'	'
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	'1 year 1 month 6 days	'	'
Range of Exercise Prices $30.23-$35.91 [Member] | Stock Options [Member]	'	'	'
Stock options, Outstanding at December 31, Number of options	1,087,218	'	'
Stock options, Outstanding at December 31, Weighted average exercise price	$33.09	'	'
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	'4 years 3 months 18 days	'	'
Stock options, Exercisable at December 31,	677,387	'	'
Stock options Exercisable at December 31, Weighted average exercise price	$32.32	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'3 years 4 months 24 days	'	'
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	'3 years 4 months 24 days	'	'
Range of Exercise Prices $36.22-$39.91 [Member] | Stock Options [Member]	'	'	'
Stock options, Outstanding at December 31, Number of options	1,587,066	'	'
Stock options, Outstanding at December 31, Weighted average exercise price	$37.56	'	'
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	'5 years 4 months 24 days	'	'
Stock options, Exercisable at December 31,	803,412	'	'
Stock options Exercisable at December 31, Weighted average exercise price	$36.74	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'4 years 4 months 24 days	'	'
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	'4 years 4 months 24 days	'	'
Range of Exercise Prices $40.15-$51.47 [Member] | Stock Options [Member]	'	'	'
Stock options, Outstanding at December 31, Number of options	365,275	'	'
Stock options, Outstanding at December 31, Weighted average exercise price	$41.64	'	'
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	'3 years	'	'
Stock options, Exercisable at December 31,	358,004	'	'
Stock options Exercisable at December 31, Weighted average exercise price	$41.62	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'2 years 10 months 24 days	'	'
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	'2 years 10 months 24 days	'	'

StockBased_Compensation_Compen1

Stock-Based Compensation (Compensation Costs Related To Restricted Stock Grants) (Details) (Restricted Stock [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock [Member]	'	'	'
Stock-based compensation cost related to stock options - general and administrative expense	$7,432	$6,368	$5,591
Stock-based compensation cost related to stock options - capitalized	$7,469	$5,994	$5,162

StockBased_Compensation_Summar1

Stock-Based Compensation (Summary of Restricted Stock Activity and Unvested Shares) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock Options [Member]	'	'	'
Restricted Stock, Granted, Weighted Average Grant Date Fair Value	$13.39	$16.91	$18.17
Restricted Stock [Member]	'	'	'
Restricted Stock, Unvested shares at January 1, Number of Shares	1,117,515	1,019,737	834,058
Restricted Stock, Granted, Number of Shares	1,108,852	537,244	532,754
Restricted Stock, Vested, Number of Shares	-381,676	-344,164	-294,358
Restricted Stock, Forfeited, Number of Shares	-73,769	-95,302	-52,717
Restricted Stock, Unvested shares at December 31, Number of Shares	1,770,922	1,117,515	1,019,737
Restricted Stock, Unvested shares at January 1, Weighted Average Grant Date Fair Value	$35.64	$36.71	$36.24
Restricted Stock, Granted, Weighted Average Grant Date Fair Value	$38.92	$34.39	$36.41
Restricted Stock, Vested, Weighted Average Grant Date Fair Value	$36.29	$36.50	$34.90
Restricted Stock, Forfeited, Weighted Average Grant Date Fair Value	$35.81	$36.97	$36.45
Restricted Stock, Unvested shares at December 31, Weighted Average Grant Date Fair Value	$37.55	$35.64	$36.71

Segment_Information_Details

Segment Information (Details) (USD $)

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Revenues from external customers

$907,089,000

$868,366,000

$862,041,000

$733,649,000

$777,355,000

$691,727,000

$606,076,000

$654,835,000

$3,371,145,000

$2,729,993,000

$2,951,332,000

Intersegment revenues

'

'

'

'

'

'

'

'

2,380,043,000

1,599,524,000

2,010,369,000

Operating income (loss)

317,117,000

309,229,000

325,317,000

251,960,000

-572,947,000

-65,959,000

-646,046,000

184,326,000

1,203,623,000

-1,100,626,000

[1]

1,073,227,000

Other income (loss), net

'

'

'

'

'

'

'

'

2,207,000

1,030,000

264,000

Gain (loss) on derivatives

'

'

'

'

'

'

'

'

26,141,000

-14,950,000

1,574,000

Depreciation, depletion and amortization expense

'

'

'

'

'

'

'

'

786,612,000

810,953,000

704,511,000

Impairment of natural gas and oil properties

'

'

'

'

'

'

'

'

'

1,939,734,000

'

Interest expense

'

'

'

'

'

'

'

'

41,594,000

[2]

35,657,000

[2]

24,075,000

[2]

Provision (benefit) for income taxes

'

'

'

'

'

'

'

'

486,874,000

[2]

-443,139,000

[2]

413,221,000

[2]

Assets

8,047,726,000

'

'

'

6,737,527,000

'

'

'

8,047,726,000

6,737,527,000

7,902,897,000

Capital investments

'

'

'

'

'

'

'

'

2,234,797,000

[3]

2,080,519,000

[3]

2,207,174,000

[3]

Change in accrued expenditures

'

'

'

'

'

'

'

'

-24,900,000

-36,900,000

-4,300,000

Intersegment revenues for marketing company's E&P sales

'

'

'

'

'

'

'

'

2,000,000,000

1,300,000,000

1,700,000,000

Capital investment related to companys E&P segment related to Canada for December 31, 2012 and 2011

'

'

'

'

'

'

'

'

35,400,000

11,600,000

18,700,000

Assets related to E&P program in Canada

79,200,000

'

'

'

44,400,000

'

'

'

79,200,000

44,400,000

28,400,000

Non-cash ceiling test impairment

'

'

'

'

'

'

'

'

1,939,700,000

'

'

Exploration and Production [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

2,398,214,000

1,964,624,000

2,087,189,000

Intersegment revenues

'

'

'

'

'

'

'

'

5,951,000

-1,452,000

11,725,000

Operating income (loss)

'

'

'

'

'

'

'

'

878,701,000

-1,396,261,000

[1]

823,564,000

Other income (loss), net

'

'

'

'

'

'

'

'

2,741,000

-1,156,000

328,000

Gain (loss) on derivatives

'

'

'

'

'

'

'

'

25,670,000

-14,950,000

1,574,000

Depreciation, depletion and amortization expense

'

'

'

'

'

'

'

'

735,215,000

765,368,000

666,125,000

Impairment of natural gas and oil properties

'

'

'

'

'

'

'

'

'

1,939,734,000

'

Interest expense

'

'

'

'

'

'

'

'

30,244,000

[2]

20,315,000

[2]

9,026,000

[2]

Provision (benefit) for income taxes

'

'

'

'

'

'

'

'

368,320,000

[2]

-548,556,000

[2]

322,714,000

[2]

Assets

6,356,799,000

[4]

'

'

'

5,193,733,000

[4]

'

'

'

6,356,799,000

[4]

5,193,733,000

[4]

6,547,117,000

[4]

Capital investments

'

'

'

'

'

'

'

'

2,052,148,000

[3]

1,860,681,000

[3]

1,977,493,000

[3]

Midstream Services [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

972,832,000

765,255,000

864,096,000

Intersegment revenues

'

'

'

'

'

'

'

'

2,373,851,000

1,598,225,000

1,995,423,000

Operating income (loss)

'

'

'

'

'

'

'

'

325,435,000

294,302,000

[1]

247,952,000

Other income (loss), net

'

'

'

'

'

'

'

'

-1,000

132,000

-91,000

Gain (loss) on derivatives

'

'

'

'

'

'

'

'

480,000

'

'

Depreciation, depletion and amortization expense

'

'

'

'

'

'

'

'

50,940,000

44,395,000

37,261,000

Interest expense

'

'

'

'

'

'

'

'

10,619,000

[2]

14,341,000

[2]

15,049,000

[2]

Provision (benefit) for income taxes

'

'

'

'

'

'

'

'

119,223,000

[2]

104,522,000

[2]

90,221,000

[2]

Assets

1,427,294,000

'

'

'

1,273,228,000

'

'

'

1,427,294,000

1,273,228,000

1,119,861,000

Capital investments

'

'

'

'

'

'

'

'

157,635,000

[3]

164,978,000

[3]

160,776,000

[3]

Other [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

99,000

114,000

47,000

Intersegment revenues

'

'

'

'

'

'

'

'

241,000

2,751,000

3,221,000

Operating income (loss)

'

'

'

'

'

'

'

'

-513,000

1,333,000

[1]

1,711,000

Other income (loss), net

'

'

'

'

'

'

'

'

-533,000

2,054,000

27,000

Gain (loss) on derivatives

'

'

'

'

'

'

'

'

-9,000

'

'

Depreciation, depletion and amortization expense

'

'

'

'

'

'

'

'

457,000

1,190,000

1,125,000

Interest expense

'

'

'

'

'

'

'

'

731,000

[2]

1,001,000

[2]

'

Provision (benefit) for income taxes

'

'

'

'

'

'

'

'

-669,000

[2]

895,000

[2]

286,000

[2]

Assets

263,633,000

'

'

'

270,566,000

'

'

'

263,633,000

270,566,000

235,919,000

Capital investments

'

'

'

'

'

'

'

'

$25,014,000

[3]

$54,860,000

[3]

$68,905,000

[3]

[1]

The operating loss for the E&P segment for the twelve months ended December 31, 2012 includes a $1,939.7 million non-cash ceiling test impairment of our natural gas and oil properties.

[2]

Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.

[3]

Capital investments include a decrease of $24.9 million for 2013, a decrease of $36.9 million for 2012 and an increase of $4.3 million for 2011 related to the change in accrued expenditures between years.

[4]

Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities.

Quarterly_Results_Unaudited_De

Quarterly Results (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Quarterly Financial Data [Abstract]	'	'	'	'	'	'	'	'	'	'		'
Operating Revenues	$907,089	$868,366	$862,041	$733,649	$777,355	$691,727	$606,076	$654,835	$3,371,145	$2,729,993		$2,951,332
Operating income (loss)	317,117	309,229	325,317	251,960	-572,947	-65,959	-646,046	184,326	1,203,623	-1,100,626	[1]	1,073,227
Net income (loss)	$144,490	$185,867	$245,631	$127,515	($355,583)	($54,053)	($405,132)	$107,704	$703,503	($707,064)		$637,769
Earnings per share attributable to Southwestern Energy stockholders - Basic	$0.41	$0.53	$0.70	$0.36	($1.02)	($0.16)	($1.16)	$0.31	$2.01	($2.03)		$1.84
Earnings per share attributable to Southwestern Energy stockholders - Diluted	$0.41	$0.53	$0.70	$0.36	($1.02)	($0.16)	($1.16)	$0.31	$2	($2.03)		$1.82
[1]	The operating loss for the E&P segment for the twelve months ended December 31, 2012 includes a $1,939.7 million non-cash ceiling test impairment of our natural gas and oil properties.

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information (Condensed Consolidating Statement of Operations) (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Operating Revenues

$907,089

$868,366

$862,041

$733,649

$777,355

$691,727

$606,076

$654,835

$3,371,145

$2,729,993

$2,951,332

Gas purchases

'

'

'

'

'

'

'

'

781,626

592,466

709,091

Operating expenses

'

'

'

'

'

'

'

'

328,503

244,735

240,944

General and administrative expenses

'

'

'

'

'

'

'

'

191,310

175,147

158,041

Depreciation, depletion and amortization

'

'

'

'

'

'

'

'

786,612

810,953

704,511

Impairment of natural gas and oil properties

'

'

'

'

'

'

'

'

'

1,939,734

'

Taxes, other than income taxes

'

'

'

'

'

'

'

'

79,471

67,584

65,518

Total operating costs and expenses

'

'

'

'

'

'

'

'

2,167,522

3,830,619

1,878,105

Operating Income (Loss)

317,117

309,229

325,317

251,960

-572,947

-65,959

-646,046

184,326

1,203,623

-1,100,626

[1]

1,073,227

Other income (loss), net

'

'

'

'

'

'

'

'

2,207

1,030

264

Gain (loss) on derivatives

'

'

'

'

'

'

'

'

26,141

-14,950

1,574

Interest expense

'

'

'

'

'

'

'

'

41,594

[2]

35,657

[2]

24,075

[2]

Income (Loss) Before Income Taxes

'

'

'

'

'

'

'

'

1,190,377

-1,150,203

1,050,990

Provision (benefit) for income taxes

'

'

'

'

'

'

'

'

486,874

[2]

-443,139

[2]

413,221

[2]

Net income (loss)

144,490

185,867

245,631

127,515

-355,583

-54,053

-405,132

107,704

703,503

-707,064

637,769

Comprehensive income (loss)

'

'

'

'

'

'

'

'

549,357

-965,688

962,222

Parent [Member]

'

'

'

'

'

'

'

'

'

'

'

Equity in earnings of subsidiaries

'

'

'

'

'

'

'

'

'

-707,064

637,769

Income (Loss) Before Income Taxes

'

'

'

'

'

'

'

'

'

-707,064

637,769

Net income (loss)

'

'

'

'

'

'

'

'

'

-707,064

637,769

Comprehensive income (loss)

'

'

'

'

'

'

'

'

'

-965,688

962,222

Guarantors [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating Revenues

'

'

'

'

'

'

'

'

'

2,556,634

2,801,811

Gas purchases

'

'

'

'

'

'

'

'

'

593,091

710,487

Operating expenses

'

'

'

'

'

'

'

'

'

423,147

380,154

General and administrative expenses

'

'

'

'

'

'

'

'

'

151,488

141,499

Depreciation, depletion and amortization

'

'

'

'

'

'

'

'

'

765,623

665,615

Impairment of natural gas and oil properties

'

'

'

'

'

'

'

'

'

1,939,734

'

Taxes, other than income taxes

'

'

'

'

'

'

'

'

'

56,262

53,950

Total operating costs and expenses

'

'

'

'

'

'

'

'

'

3,929,345

1,951,705

Operating Income (Loss)

'

'

'

'

'

'

'

'

'

-1,372,711

850,106

Other income (loss), net

'

'

'

'

'

'

'

'

'

-1,143

306

Gain (loss) on derivatives

'

'

'

'

'

'

'

'

'

-14,950

1,574

Interest expense

'

'

'

'

'

'

'

'

'

22,312

11,277

Income (Loss) Before Income Taxes

'

'

'

'

'

'

'

'

'

-1,411,116

840,709

Provision (benefit) for income taxes

'

'

'

'

'

'

'

'

'

-538,357

332,795

Net income (loss)

'

'

'

'

'

'

'

'

'

-872,759

507,914

Comprehensive income (loss)

'

'

'

'

'

'

'

'

'

-1,125,454

836,291

Non-Guarantors [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating Revenues

'

'

'

'

'

'

'

'

'

476,997

411,998

Operating expenses

'

'

'

'

'

'

'

'

'

121,953

118,713

General and administrative expenses

'

'

'

'

'

'

'

'

'

26,307

19,700

Depreciation, depletion and amortization

'

'

'

'

'

'

'

'

'

45,330

38,896

Taxes, other than income taxes

'

'

'

'

'

'

'

'

'

11,321

11,568

Total operating costs and expenses

'

'

'

'

'

'

'

'

'

204,911

188,877

Operating Income (Loss)

'

'

'

'

'

'

'

'

'

272,086

223,121

Other income (loss), net

'

'

'

'

'

'

'

'

'

2,173

-42

Interest expense

'

'

'

'

'

'

'

'

'

13,345

12,798

Income (Loss) Before Income Taxes

'

'

'

'

'

'

'

'

'

260,914

210,281

Provision (benefit) for income taxes

'

'

'

'

'

'

'

'

'

95,218

80,426

Net income (loss)

'

'

'

'

'

'

'

'

'

165,696

129,855

Comprehensive income (loss)

'

'

'

'

'

'

'

'

'

166,225

129,294

Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating Revenues

'

'

'

'

'

'

'

'

'

-303,638

-262,477

Gas purchases

'

'

'

'

'

'

'

'

'

-625

-1,396

Operating expenses

'

'

'

'

'

'

'

'

'

-300,365

-257,923

General and administrative expenses

'

'

'

'

'

'

'

'

'

-2,648

-3,158

Taxes, other than income taxes

'

'

'

'

'

'

'

'

'

1

'

Total operating costs and expenses

'

'

'

'

'

'

'

'

'

-303,637

-262,477

Operating Income (Loss)

'

'

'

'

'

'

'

'

'

-1

'

Equity in earnings of subsidiaries

'

'

'

'

'

'

'

'

'

707,064

-637,769

Income (Loss) Before Income Taxes

'

'

'

'

'

'

'

'

'

707,063

-637,769

Net income (loss)

'

'

'

'

'

'

'

'

'

707,063

-637,769

Comprehensive income (loss)

'

'

'

'

'

'

'

'

'

$959,229

($965,585)

7.5% Senior Notes due 2018 [Member]

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage

7.50%

'

'

'

7.50%

'

'

'

7.50%

7.50%

'

Stated interest rate

7.50%

'

'

'

7.50%

'

'

'

7.50%

7.50%

'

4.10% Senior Notes Due 2022 [Member]

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage

4.10%

'

'

'

4.10%

'

'

'

4.10%

4.10%

'

Stated interest rate

4.10%

'

'

'

4.10%

'

'

'

4.10%

4.10%

'

7.15% Senior Notes due 2018 [Member]

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage

7.15%

'

'

'

7.15%

'

'

'

7.15%

7.15%

'

Stated interest rate

7.15%

'

'

'

7.15%

'

'

'

7.15%

7.15%

'

7.35% Senior Notes due 2017 [Member]

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage

7.35%

'

'

'

7.35%

'

'

'

7.35%

7.35%

'

Stated interest rate

7.35%

'

'

'

7.35%

'

'

'

7.35%

7.35%

'

7.125% Senior Notes due 2017 [Member]

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage

7.13%

'

'

'

7.13%

'

'

'

7.13%

7.13%

'

Stated interest rate

7.13%

'

'

'

7.13%

'

'

'

7.13%

7.13%

'

[1]

The operating loss for the E&P segment for the twelve months ended December 31, 2012 includes a $1,939.7 million non-cash ceiling test impairment of our natural gas and oil properties.

[2]

Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.

Condensed_Consolidating_Financ3

Condensed Consolidating Financial Information (Condensed Consolidating Balance Sheets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Cash and cash equivalents	$22,938	$53,583	$15,627	$16,055
Restricted cash	'	8,542	'	'
Accounts receivable	464,045	377,638	'	'
Inventories	37,745	28,141	'	'
Other current assets	'	341,008	'	'
Total current assets	644,175	808,912	'	'
Property and equipment	'	13,028,439	'	'
Less: Accumulated depreciation, depletion and amortization	-8,005,836	-7,191,463	'	'
Total property and equipment, net	7,296,623	5,836,976	'	'
Other assets	106,928	91,639	'	'
TOTAL ASSETS	8,047,726	6,737,527	7,902,897	'
Accounts payable	'	556,980	'	'
Other current liabilities	'	210,791	'	'
Total current liabilities	688,011	767,771	'	'
Long-term debt	1,950,096	1,668,273	'	'
Deferred income taxes	1,532,329	1,049,138	'	'
Other liabilities	'	216,473	'	'
Total liabilities	'	3,701,655	'	'
Total Equity	3,622,030	3,035,872	3,969,304	2,964,876
TOTAL LIABILITIES AND EQUITY	8,047,726	6,737,527	'	'
Parent [Member]	'	'	'	'
Cash and cash equivalents	'	47,491	14,711	8,381
Accounts receivable	'	2,677	'	'
Inventories	'	2	'	'
Other current assets	'	7,461	'	'
Total current assets	'	66,173	'	'
Intercompany receivables	'	2,259,713	'	'
Property and equipment	'	220,837	'	'
Less: Accumulated depreciation, depletion and amortization	'	-82,178	'	'
Total property and equipment, net	'	138,659	'	'
Investments in subsidiaries (equity method)	'	2,309,947	'	'
Other assets	'	35,136	'	'
TOTAL ASSETS	'	4,809,628	'	'
Accounts payable	'	140,367	'	'
Other current liabilities	'	3,758	'	'
Total current liabilities	'	144,125	'	'
Long-term debt	'	1,668,273	'	'
Deferred income taxes	'	-116,207	'	'
Other liabilities	'	77,565	'	'
Total liabilities	'	1,773,756	'	'
Total Equity	'	3,035,872	'	'
TOTAL LIABILITIES AND EQUITY	'	4,809,628	'	'
Guarantors [Member]	'	'	'	'
Cash and cash equivalents	'	5,988	'	7,631
Accounts receivable	'	353,607	'	'
Inventories	'	26,975	'	'
Other current assets	'	321,396	'	'
Total current assets	'	707,966	'	'
Intercompany receivables	'	42	'	'
Property and equipment	'	11,491,222	'	'
Less: Accumulated depreciation, depletion and amortization	'	-6,923,106	'	'
Total property and equipment, net	'	4,568,116	'	'
Other assets	'	42,247	'	'
TOTAL ASSETS	'	5,318,371	'	'
Accounts payable	'	375,604	'	'
Other current liabilities	'	205,623	'	'
Total current liabilities	'	581,227	'	'
Intercompany payables	'	2,108,360	'	'
Deferred income taxes	'	820,279	'	'
Other liabilities	'	124,505	'	'
Total liabilities	'	3,634,371	'	'
Total Equity	'	1,684,000	'	'
TOTAL LIABILITIES AND EQUITY	'	5,318,371	'	'
Non-Guarantors [Member]	'	'	'	'
Cash and cash equivalents	'	104	916	43
Accounts receivable	'	21,354	'	'
Inventories	'	1,164	'	'
Other current assets	'	12,151	'	'
Total current assets	'	34,773	'	'
Intercompany receivables	'	27,077	'	'
Property and equipment	'	1,316,380	'	'
Less: Accumulated depreciation, depletion and amortization	'	-186,179	'	'
Total property and equipment, net	'	1,130,201	'	'
Other assets	'	14,256	'	'
TOTAL ASSETS	'	1,206,307	'	'
Accounts payable	'	41,009	'	'
Other current liabilities	'	1,410	'	'
Total current liabilities	'	42,419	'	'
Intercompany payables	'	178,472	'	'
Deferred income taxes	'	345,066	'	'
Other liabilities	'	14,403	'	'
Total liabilities	'	580,360	'	'
Total Equity	'	625,947	'	'
TOTAL LIABILITIES AND EQUITY	'	1,206,307	'	'
Eliminations [Member]	'	'	'	'
Intercompany receivables	'	-2,286,832	'	'
Investments in subsidiaries (equity method)	'	-2,309,947	'	'
TOTAL ASSETS	'	-4,596,779	'	'
Intercompany payables	'	-2,286,832	'	'
Total liabilities	'	-2,286,832	'	'
Total Equity	'	-2,309,947	'	'
TOTAL LIABILITIES AND EQUITY	'	($4,596,779)	'	'

Condensed_Consolidating_Financ4

Condensed Consolidating Financial Information (Condensed Consolidating Statements of Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net cash provided by (used in) operating activities	$1,908,528	$1,653,942	$1,739,817
Capital investments	-2,252,647	-2,107,755	-2,184,474
Proceeds from sale of property and equipment	'	201,101	154,526
Transfers to restricted cash	8,542	-167,788	-85,055
Transfers from Restricted Cash	'	159,246	85,055
Other	10,166	8,519	5,158
Net cash used in investing activities	-2,215,776	-1,906,677	-2,024,790
Payments on current portion of long-term debt	-1,200	-1,200	-1,200
Payments on revolving long-term debt	-3,147,750	-2,263,900	-3,445,900
Borrowings under revolving long-term debt	3,430,650	1,592,400	3,696,200
Proceeds from issuance of long-term debt	'	998,780	'
Other	'	-35,191	35,203
Net cash provided by (used in) financing activities	277,199	290,889	284,303
Effect of exchange rate changes on cash	-596	-198	242
Increase (decrease) in cash and cash equivalents	-30,645	37,956	-428
Cash and cash equivalents at beginning of year	53,583	15,627	16,055
Cash and cash equivalents at end of year	22,938	53,583	15,627
Parent [Member]	'	'	'
Net cash provided by (used in) operating activities	'	-39,934	14,688
Capital investments	'	-36,918	-66,647
Proceeds from sale of property and equipment	'	26,006	'
Transfers to restricted cash	'	-167,788	-85,055
Transfers from Restricted Cash	'	159,245	85,055
Other	'	-696	16,263
Net cash used in investing activities	'	-20,151	-50,384
Intercompany activities	'	-198,023	-242,277
Payments on current portion of long-term debt	'	-1,200	-1,200
Payments on revolving long-term debt	'	-2,263,900	-3,445,900
Borrowings under revolving long-term debt	'	1,592,400	3,696,200
Other	'	-35,192	35,203
Net cash provided by (used in) financing activities	'	92,865	42,026
Increase (decrease) in cash and cash equivalents	'	32,780	6,330
Cash and cash equivalents at beginning of year	'	14,711	8,381
Cash and cash equivalents at end of year	'	47,491	14,711
Guarantors [Member]	'	'	'
Net cash provided by (used in) operating activities	'	1,278,673	1,482,853
Capital investments	'	-1,868,487	-1,916,246
Proceeds from sale of property and equipment	'	169,149	154,261
Transfers from Restricted Cash	'	1	'
Other	'	-35,792	-43,961
Net cash used in investing activities	'	-1,735,129	-1,805,946
Intercompany activities	'	462,443	315,462
Other	'	1	'
Net cash provided by (used in) financing activities	'	462,444	315,462
Increase (decrease) in cash and cash equivalents	'	5,988	-7,631
Cash and cash equivalents at beginning of year	'	'	7,631
Cash and cash equivalents at end of year	'	5,988	'
Non-Guarantors [Member]	'	'	'
Net cash provided by (used in) operating activities	'	415,203	242,276
Capital investments	'	-202,350	-201,581
Proceeds from sale of property and equipment	'	5,946	265
Other	'	45,007	32,856
Net cash used in investing activities	'	-151,397	-168,460
Intercompany activities	'	-264,420	-73,185
Net cash provided by (used in) financing activities	'	-264,420	-73,185
Effect of exchange rate changes on cash	'	-198	242
Increase (decrease) in cash and cash equivalents	'	-812	873
Cash and cash equivalents at beginning of year	'	916	43
Cash and cash equivalents at end of year	'	$104	$916