Southwestern Energy (SWN) 10-K 26 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 24, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Registrant Name	SOUTHWESTERN ENERGY CO
Entity Central Index Key	7332
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		384,480,028
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$15,884,399,197
Trading Symbol	SWN

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Revenues:
Gas sales	$2,827	$2,381	$1,956
Oil sales	22	16	8
Marketing	996	792	592
Gas gathering	193	182	174
Total Operating Revenues	4,038	3,371	2,730
Operating Costs and Expenses:
Marketing purchases	980	782	592
Operating expenses	427	328	245
General and administrative expenses	221	191	175
Depreciation, depletion and amortization	942	787	811
Impairment of natural gas and oil properties			1,940
Taxes, other than income taxes	95	79	68
Total Operating Costs and Expenses	2,665	2,167	3,831
Operating Income (Loss)	1,373	1,204	-1,101
Interest Expense:
Interest on debt	101	100	93
Other interest charges	13	4	4
Interest capitalized	-55	-62	-62
Total Interest Expense	59	42	35
Other Income (Loss), Net	-4	2	1
Gain (Loss) on Derivatives	139	26	-15
Income (Loss) Before Income Taxes	1,449	1,190	-1,150
Provision (Benefit) for Income Taxes:
Current	21	-11	19
Deferred	504	497	-462
Provision (benefit) for income taxes	525	486	-443
Net Income (Loss)	$924	$704	($707)
Earnings (Loss) Per Share:
Basic	$2.63	$2.01	($2.03)
Diluted	$2.62	$2	($2.03)
Weighted Average Common Shares Outstanding:
Basic	351,446,747	350,465,430	348,610,503
Diluted	352,410,683	351,101,452	348,610,503

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Net income (loss)	$924		$704		($707)
Change in derivatives:
Settlements	-16	[1]	185	[1]	382	[1]
Ineffectiveness			-1	[2]	1	[2]
Change in fair value of derivative instruments	73	[3]	22	[3]	131	[3]
Total change in derivatives	89		-162		-252
Change in value of pension and other postretirement liabilities:
Current period net gain (loss)	-15	[4]	11	[4]	-7	[4]
Amortization of prior service cost included in net periodic pension cost			1	[5]	1	[5]
Total change in value of pension and other postretirement liabilities	-15		12		-6
Change in currency translation adjustment	-8		-4
Comprehensive income (loss)	$990		$550		($965)
[1]	Net of $10, $(124), and $(249) million in taxes for the years ended December 31, 2014, 2013 and 2012, respectively.
[2]	Net of $0, $1, and $(1) million in taxes for the years ended December 31, 2014, 2013 and 2012, respectively.
[3]	Net of $49, $16, and $85 million in taxes for the years ended December 31, 2014, 2013 and 2012, respectively.
[4]	Net of $(10), $8, and $(5) million in taxes for the years ended December 31, 2014, 2013 and 2012, respectively.
[5]	Net of $0, $1, and $1 million in taxes for the years ended December 31, 2014, 2013, and 2012, respectively.

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Settlements tax	$10	($124)	($249)
Ineffectiveness tax	0	1	-1
Change in fair value of derivative instruments tax	49	16	85
Current period net gain (loss) tax	-10	8	-5
Amortization of prior service cost included in net periodic pension cost tax	$0	$1	$1

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents	$53	$23
Accounts receivable	530	464
Inventories	37	38
Derivative assets	337	71
Other current assets	158	48
Total current assets	1,115	644
Natural gas and oil properties, using the full cost method, including $4,646 million in 2014 and $957 million in 2013 excluded from amortization	20,506	13,294
Gathering systems	1,439	1,306
Other	612	703
Less: Accumulated depreciation, depletion and amortization	-8,845	-8,006
Total property and equipment, net	13,712	7,297
Other long-term assets	98	107
TOTAL ASSETS	14,925	8,048
Current liabilities:
Short-term debt	4,501	1
Accounts payable	653	507
Taxes payable	92	68
Interest payable	34	33
Current deferred income taxes	109	24
Derivative liabilities	9	7
Other current liabilities	30	48
Total current liabilities	5,428	688
Long-term debt	2,466	1,950
Deferred income taxes	1,951	1,532
Pension and other postretirement liabilities	44	16
Other long-term liabilities	374	240
Total long-term liabilities	4,835	3,738
Commitments and contingencies (see Note 9)
Equity:
Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 354,488,992 shares in 2014 and 352,938,584 in 2013	4	4
Additional paid-in capital	1,019	969
Retained earnings	3,577	2,653
Accumulated other comprehensive income (loss)	62	-4
Common stock in treasury, 11,055 shares in 2014 and 9,924 in 2013
Total equity	4,662	3,622
TOTAL LIABILITIES AND EQUITY	$14,925	$8,048

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
CONSOLIDATED BALANCE SHEETS [Abstract]
Natural gas and oil properties, using the full cost method, costs excluded from amortization	$4,646	$957
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	1,250,000,000	1,250,000,000
Common stock, shares issued	354,488,992	352,938,584
Treasury stock, shares	11,055	9,924

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows From Operating Activities
Net income (loss)	$924	$704	($707)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	942	787	811
Amortization of debt issuance cost	10	4	4
Impairment of natural gas and oil properties			1,940
Deferred income taxes	504	497	-462
(Gain) loss on derivatives, net of settlement	-130	-21	2
Stock-based compensation	18	13	12
Other	2	1
Change in assets and liabilities:
Accounts receivable	-66	-86	-36
Inventories	1	-6	18
Accounts payable	84	74	41
Taxes payable	24	5	22
Interest payable		-1	5
Advances from partners		-69	-15
Other assets and liabilities	22	7	19
Net cash provided by operating activities	2,335	1,909	1,654
Cash Flows From Investing Activities
Capital investments	-2,043	-2,157	-2,108
Acquisition of oil and gas properties	-5,298	-96
Proceeds from sale of property and equipment	43	18	201
Transfers to restricted cash		9	-168
Transfers from restricted cash			159
Other	10	10	9
Net cash used in investing activities	-7,288	-2,216	-1,907
Cash Flows From Financing Activities
Payments on current portion of long-term debt	-1	-1	-1
Payments on revolving long-term debt	-5,179	-3,148	-2,264
Borrowings under revolving long-term debt	5,196	3,430	1,592
Change in bank drafts outstanding	11	-7	-36
Proceeds from issuance of long-term debt	500		999
Proceeds from issuance of short-term debt	4,500
Debt issuance costs	-56		-8
Proceeds from exercise of common stock options	12	10	9
Other		-7
Net cash provided by financing activities	4,983	277	291
Effect of exchange rate changes on cash		-1
Increase (decrease) in cash and cash equivalents	30	-31	38
Cash and cash equivalents at beginning of year	23	54	16
Cash and cash equivalents at end of period	$53	$23	$54

CONSOLIDATED_STATEMENTS_OF_CHA

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $)	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Comprehensive Income (Loss) [Member]	Common Stock In Treasury [Member]	Total
In Millions, except Share data, unless otherwise specified
Balance at Dec. 31, 2011	$4	$903	$2,656	$408	($2)	$3,969
Balance, shares at Dec. 31, 2011	349,058,501
Comprehensive income:
Net income (loss)			-707			-707
Other comprehensive income (loss)				-258		-258
Comprehensive income (loss)						-965
Stock-based compensation		22				22
Exercise of stock options		9				9
Exercise of stock options, shares	1,607,784					1,608,000
Issuance of restricted stock, shares	539,542
Cancellation of restricted stock, shares	-95,302
Tax withholding - stock compensation, shares	-11,357
Issuance of stock awards, shares	1,223
Treasury stock - non-qualified plan					1	1
Balance at Dec. 31, 2012	4	934	1,949	150	-1	3,036
Balance, shares at Dec. 31, 2012	351,100,391
Comprehensive income:
Net income (loss)			704			704
Other comprehensive income (loss)				-154		-154
Comprehensive income (loss)						550
Stock-based compensation		25				25
Exercise of stock options		10				10
Exercise of stock options, shares	833,132					833,000
Issuance of restricted stock, shares	1,102,926
Cancellation of restricted stock, shares	-74,083
Tax withholding - stock compensation, shares	-25,131
Tax withholding - stock compensation		-1				-1
Issuance of stock awards, shares	1,349
Treasury stock - non-qualified plan		1			1	2
Balance at Dec. 31, 2013	4	969	2,653	-4		3,622
Balance, shares at Dec. 31, 2013	352,938,584
Comprehensive income:
Net income (loss)			924			924
Other comprehensive income (loss)				66		66
Comprehensive income (loss)						990
Stock-based compensation		38				38
Exercise of stock options		12				12
Exercise of stock options, shares	402,190					402,000
Issuance of restricted stock, shares	1,299,367
Cancellation of restricted stock, shares	-140,703
Tax withholding - stock compensation, shares	-12,133
Issuance of stock awards, shares	1,687
Balance at Dec. 31, 2014	$4	$1,019	$3,577	$62		$4,662
Balance, shares at Dec. 31, 2014	354,488,992

Organization_And_Summary_Of_Si

Organization And Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Organization And Summary Of Significant Accounting Policies [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 (“E&P”).  Our current operations are principally focused within the United States on development of two unconventional natural gas reservoirs located in Arkansas and Pennsylvania. The Company’s operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale, and its operations in northeast Pennsylvania are focused on an unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”). Recently, the Company acquired a significant stake in properties located in West Virginia and southwest Pennsylvania which it also intends to develop. These operations in West Virginia are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs (herein referred to as “Southwest Appalachia”). Collectively, the Company’s properties located in West Virginia and Pennsylvania are herein referred to as the “Appalachian Basin.”  To a lesser extent, the Company has exploration and production activities ongoing in Colorado, Louisiana, Texas and in the Arkoma Basin in Arkansas and Oklahoma. The Company also actively seeks to find and develop new natural gas and oil plays with significant exploration and exploitation potential, which it refers to as “New Ventures,” and through acquisitions. The Company also operates drilling rigs in Arkansas and Pennsylvania, as well as in other operating areas, and provide oilfield products and services, principally serving its exploration and production operations. Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Texas, Louisiana, Pennsylvania, and West Virginia.
	Basis of Presentation
	The consolidated financial statements included in this Annual Report 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 financial statements to conform to the 2014 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 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 and oil sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas 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. The Company had no significant production imbalances at December 31, 2014 or 2013.
	Marketing. The Company generally markets its natural gas and oil, as well as some products produced by third parties, to brokers, local distribution companies and end-users, pursuant to a variety of contracts. Marketing revenues are recognized when delivery 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.
	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 $17 million and $5 million as of December 31, 2014 and 2013, respectively.
	Inventory
	Inventory is comprised of natural gas in underground storage and tubular and other equipment. Natural gas in underground storage is carried at the lower of cost or market and accounted for by a weighted average cost method. 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.
	The components of inventory as of December 31, 2014 and December 31, 2013 consisted of the following:
			For year ended December 31,
			2014		2013
			(in millions)
	Inventory:
	Natural gas in underground storage	$	4	$	4
	Tubulars and other equipment		33		34
	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 reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves 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. Companies utilizing the full cost method 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 $4.35 per MMBtu, West Texas Intermediate oil of $91.48 per barrel and NGLs of $23.79 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, 2014. Cash flow hedges of natural gas production in place increased this ceiling amount by approximately $4 million, net of tax, as of December 31, 2014.  At December 31, 2013, 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 $3.67 per MMBtu, West Texas Intermediate oil of $93.42 per barrel, and NGLs of $43.45 per barrel. 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 and for West Texas Intermediate oil of $91.21. 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 the Company’s natural gas and oil properties exceeded the ceiling by approximately $1,192 million (net of tax) and resulted in a non-cash ceiling test impairment.
	All of the Company’s costs directly associated with the acquisition and evaluation of properties in Canada relating to its exploration program as of December 31, 2014 and as of December 31, 2013 were unproved and did not exceed the ceiling amount.  If the exploration program in Canada is unsuccessful on all or a portion of these properties, including the effects of changes in laws or regulations due to the new government in New Brunswick or otherwise or the Company’s exploration licenses in New Brunswick are not renewed in the first quarter of 2015, 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 Northeast Appalachia 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.  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. 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.
	Impairment of long-lived assets. The carrying values of long-lived assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable.
	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. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying Consolidated Statements of Operations. Additional information regarding uncertain tax positions can be found in Note 10 – Income Taxes.
	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 option 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 derivatives 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 and have an inconsequential impact in the consolidated statement of operations. Gains and losses from the unsettled 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.  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.
	For the year ended December 31, 2014, outstanding options for 241,603 shares with an average exercise price of $34.03 were included in the calculation of diluted shares. Options for 1,446,004 shares were excluded from the calculation because they would have had an antidilutive effect. For the year ended December 31, 2013, outstanding options for 377,626 shares with an 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 the Company recognized a net loss for the year ended December 31, 2012, the unvested stock options were not recognized in diluted earnings per share 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, 2014, 448,415 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 29,879 shares of restricted stock 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 the Company recognized a net loss for the year ended December 31, 2012, the unvested share-based payments were not recognized in diluted earnings per share 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, 2014, 273,918 shares of performance units were included in the calculation of diluted shares. There were no performance units issued in 2013.
	Supplemental Disclosures of Cash Flow Information
	The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2014, 2013, and 2012.
		For the years ended December 31,
		2014			2013		2012
		(in millions)
	Cash paid during the year for interest, net of amounts capitalized	$	50		$	36	$	17
	Cash paid during the year for income taxes		28			19		1
	Increase (decrease) in noncash property additions		174			-13		-26
	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, 2014,  11,055 shares were accounted for as treasury stock, compared to 9,924 shares at December 31, 2013.
	Foreign Currency Translation
	The Company has 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 Not Yet Implemented in this Report
	In April 2014, the FASB issued Accounting Standards Update No. 2014-08 (“Update 2014-08”), which amends FASB Accounting Standards Codification Topic 205, “Presentation of Financial Statements” and Topic 360, “Property, Plant, and Equipment.” Update 2014-08 alters the definition of a discontinued operation to cover only asset disposals that are a strategic shift with a major effect on an entity’s operations and finances, and calls for more extensive disclosures about a discontinued operation’s assets, liabilities, income and expenses. The guidance is effective for all disposals or classifications as held-for sale of components of an entity that occur within annual periods beginning on or after December 15, 2014. The Company has evaluated the provisions of Update 2014-08 and does not expect it to have an impact on its consolidated results of operations, financial position or cash flows.
	In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue. Topic 606 Revenue from Contracts with Customers will supersede the revenue recognition requirement as in Topic 605 Revenue Recognition. Update 2014-09 requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to those goods or services. Entities may apply the amendments in Update 2014-09 either (a) retrospectively to each reporting period presented, and the entity may elect a practical expedient per the update, or (b) retrospectively with the cumulative effect of initially applying Update 2014-09 recognized at the date of initial application – if an entity elects this transition method it also should provide the additional disclosures in reporting periods. For public entities, Update 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of Update 2014-09 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.
	In June 2014, the FASB issued Accounting Standards Update No. 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period (“Update 2014-12”), which clarifies the accounting treatment of such awards in practice. Update 2014-12 requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. Update 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015, and early adoption is permitted. The Company is currently evaluating the provisions of Update 2014-12 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2014
Acquisitions [Abstract]
Acquisitions	(2) ACQUISITIONS
	On December 22, 2014, the Company completed the acquisition of certain oil and gas assets from a subsidiary of Chesapeake Energy Corporation covering approximately 413,000 net acres in West Virginia and southwest Pennsylvania targeting natural gas, NGLs and crude oil contained in the Upper Devonian, Marcellus and Utica Shales for approximately $5.0 billion, subject to customary closing adjustments (the “Chesapeake Property Acquisition”). The transaction was temporarily financed using a $4.5 billion 364-day senior unsecured bridge term loan credit facility and a $500 million two-year unsecured term loan.  The Company repaid all principal and interest outstanding on the $4.5 billion bridge term loan credit facility on January 23, 2015 after permanent financing was finalized. See Note 16 – Subsequent Events for further details.
	The following table summarizes the consideration paid for the Chesapeake Property Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date.  The purchase price allocation is preliminary and subject to adjustment. These amounts will be finalized as soon as possible, but no later than one year from the acquisition date.
			For the year ended
			31-Dec-14
	Consideration:		(in millions)
	Cash	$	4,978
	Recognized amounts of identifiable assets acquired and liabilities assumed:
	Assets acquired:
	Proved natural gas and oil properties		1,424
	Unproved natural gas and oil properties		3,605
	Other property and equipment		19
	Inventory		2
	Other receivables		27
	Total assets acquired		5,077
	Liabilities assumed:
	Asset retirement obligations		-42
	Other long term liabilities		-57
	Total liabilities assumed		-99
		$	4,978
	The Chesapeake Property Acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the December 22, 2014 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 7 – Fair Value.
	The Company recorded the assets acquired and liabilities assumed in the Chesapeake Property Acquisition at their estimated fair value of approximately $5.0 billion, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized.  In addition, the Company included $1 million in general and administrative expenses and $5 million in interest expense for fees related to the Chesapeake Property Acquisition on its Consolidated Statement of Operations for the year ended December 31, 2014. The Company included $47 million in other current assets and $1 million in other assets for unamortized fees related to the bridge facility and term loan facility, respectively, for the Chesapeake Property Acquisition on its Consolidated Balance Sheet as of December 31, 2014. In January 2015, the Company repaid in full amounts outstanding on its bridge facility. Therefore, the Company will expense the $47 million of short-term unamortized debt issuance costs associated with the bridge facility in January 2015.
	The results of operations of the Chesapeake Property Acquisition have been included in the Company’s consolidated financial statements since the December 22, 2014 closing date, including approximately $10 million of total revenue and $2 million of operating income. Summarized below are the consolidated results of operations for the years ended December 31, 2014 and 2013, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2013. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Chesapeake Property Acquisition properties. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.
		For the year ended
		December 31,
		2014		2013
		(in millions) (unaudited)
	Revenues	$	4,440	$	3,713
	Net Income		927		684
	In December 2014, a subsidiary of the Company and a subsidiary of Statoil ASA entered into a purchase and sale agreement in which the Company’s subsidiary will acquire certain oil and gas assets covering approximately 30,000 acres in West Virginia and southwest Pennsylvania comprising approximately 20% of Statoil’s interests in that acreage for approximately $365 million, subject to other customary adjustments (the “Statoil Property Acquisition”). All of these assets are also assets in which the Company has acquired interests under the Chesapeake Property Acquisition. This transaction closed in January 2015 and was funded with the revolving credit facility. See Note 16 – Subsequent Events for details regarding the closing of this transaction.
	In December 2014, the Company announced that it had signed an agreement to purchase oil and gas assets including approximately 46,700 net acres in northeast Pennsylvania from WPX Energy, Inc. for approximately $300 million, subject to customary closing conditions (the “WPX Property Acquisition”). This acreage was producing approximately 50 million net cubic feet of gas per day from 63 operated horizontal wells as of December 2014. As part of this transaction, the Company will assume firm transportation capacity of 260 million cubic feet of gas per day predominantly on the Millennium pipeline effective upon closing. This transaction closed in January 2015 and was funded with the revolving credit facility. See Note 16 – Subsequent Events for details regarding the closing of this transaction.
	In March 2014 and July 2014, the Company entered into several agreements to purchase approximately 380,000 net acres in northwest Colorado principally in the Niobrara formation for approximately $215 million. The Company utilized its revolving credit facility to finance these acquisitions. The Company closed the acquisitions in the second and third quarters and accounted for them as asset acquisitions.
	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 $82 million, subject to closing conditions.  The Company utilized its revolving credit facility to finance the acquisition.  The Company closed the acquisition during the second quarter of 2013 and accounted for it as an asset acquisition.

Prepaid_Expenses

Prepaid Expenses	12 Months Ended
	Dec. 31, 2014
Prepaid Expenses [Abstract]
Prepaid Expenses	(3)  PREPAID EXPENSES
	The components of prepaid expenses included in other current assets as of December 31, 2014 and December 31, 2013 consisted of the following:
		2014		2013
			(in millions)
	Deposits (1)	$	65	$	–
	Prepaid taxes		18		14
	Prepaid insurance		8		8
	Prepaid drilling costs		1		9
	Total	$	92	$	31
	Deposits consist of a $50 million and $15 million pre-payment related to the Statoil Property Acquisition and WPX Property Acquisition, respectively.

Natural_Gas_And_Oil_Producing_

Natural Gas And Oil Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2014
Natural Gas And Oil Producing Activities (Unaudited) [Abstract]
Natural Gas And Oil Producing Activities (Unaudited)	(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, 2014 and 2013:
		2014				2013
		(in millions)
	Proved properties	$	15,860			$	12,337
	Unproved properties		4,646	-1			957	-1
	Total capitalized costs		20,506	-2			13,294
	Less:  Accumulated depreciation, depletion and amortization		8,327				7,481
	Net capitalized costs	$	12,179			$	5,813
		-1		Includes $76 million and $72 million related to the Company’s exploration program in Canada as of December 31, 2014 and 2013, respectively.
		-2		Includes approximately $5.0 billion related to the Chesapeake Property Acquisition.
	Natural gas and oil properties not subject to amortization represent investments in unproved properties and major development projects in which the Company owns 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, 2014.
		2014			2013			2012			Prior		Total
		(in millions)
	Property acquisition costs	$	3,892		$	87		$	75		$	142	$	4,196	-1
	Exploration and development costs		239			40			26			61		366	-1
	Capitalized interest		13			10			14			47		84	-1
		$	4,144		$	137		$	115		$	250	$	4,646
		-1		Property acquisition costs include $36 million, exploration costs include $31 million and capitalized interest includes $9 million related to the Company’s exploration program in Canada.
	Of the total net unevaluated costs excluded from amortization as of December 31, 2014,  approximately $3.6  billion is related to the Chesapeake Property Acquistion, approximately $12 million is related to unevaluated seismic costs in the Fayetteville Shale, approximately $34  million is related to the acquisition of undeveloped properties in the Company’s Fayetteville Shale, approximately $138 million is related to the acquisition of undeveloped properties in the Company’s Marcellus Shale and approximately $367 million is related to the acquisition of undeveloped properties in the Company’s New Ventures, excluding its exploration program in Canada. The Company has $76 million of unevaluated costs related to its exploration program in Canada. Additionally, the Company has approximately $267 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:
		2014				2013				2012
		(in millions, except per Mcfe amounts)
	Proved property acquisition costs	$	1,455			$	1			$	–
	Unproved property acquisition costs (1)		3,934				168				221
	Exploration costs(2)		232				192				197
	Development costs		1,600				1,662				1,493
	Capitalized costs incurred		7,221				2,023				1,911
	Full cost pool amortization per Mcfe	$	1.10			$	1.08			$	1.31
		-1		Includes $1 million, $17 million and $4 million, in 2014, 2013 and 2012, respectively, related to the Company’s exploration program in Canada.
		-2		Includes $3 million, $12 million and $3 million in 2014, 2013 and 2012, respectively, related to the Company’s exploration program in Canada.
	Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $55 million, $62 million and $62 million during 2014, 2013 and 2012, 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 $320 million, $264 million and $237 million during 2014, 2013 and 2012, respectively, that were directly related to the acquisition, exploration and development of the Company’s natural gas 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 $123 million, $103 million and $82 million during 2014, 2013 and 2012, 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:
		2014			2013			2012
		(in millions)
	Sales	$	2,862		$	2,404		$	1,963
	Production (lifting) costs		-776			-629			-505
	Depreciation, depletion and amortization		-884			-735			-765
	Impairment of natural gas and oil properties		–			–			-1,940
			1,202			1,040			-1,247
	Provision (benefit) for income taxes		457			416			-497
	Results of operations (1)	$	745		$	624		$	-750
		-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 the Company’s natural gas and oil operations to its 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 97%,  95% and 93% of the present worth of the Company’s total proved reserves as of December 31, 2014, 2013 and 2012, 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, historical prices of natural gas and crude oil and 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 Annual Report.
	The following table summarizes the changes in the Company’s proved natural gas, NGLs and oil reserves for 2014, 2013 and 2012 all of which were located in the United States:
		2014						2013					2012
		Natural						Natural					Natural
		Gas		Oil		NGL		Gas		Oil		NGL	Gas		Oil	NGL
		(Bcf)		(MBbls)		(MBbls)		(Bcf)		(MBbls)		(MBbls)	(Bcf)		(MBbls)	(MBbls)
	Proved reserves, beginning of year	6,974		373		–		4,017		244		–	5,887		996	–
	Revisions of previous estimates	542		-14		66		325		38		50	-2,088		-44	–
	Extensions, discoveries and other additions	1,691		250		48		3,283		229		–	918		154	–
	Production	-765		-235		-231		-655		-138		-50	-564		-83	–
	Acquisition of reserves in place	1,367		37,246		118,816		4		–		–	–		–	–
	Disposition of reserves in place	–		-5		–		–		–		–	-136		-779	–
	Proved reserves, end of year	9,809		37,615		118,699		6,974		373		–	4,017		244	–
	Proved developed reserves:
Beginning of year	4,237		372		–		3,196		243		–	3,254		983	–
End of year	5,675		7,445		38,632		4,237		372		–	3,196		243	–
Proved undeveloped reserves:
Beginning of year	2,737		1		–		821		1		–	2,633		13	–
End of year	4,134		30,170		80,067		2,737		1		–	821		1	–
The Company’s estimated proved natural gas and oil reserves were 10,747 Bcfe at year-end 2014, compared to 6,976 Bcfe at year-end 2013. The significant increase in the Company’s reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia, successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and upward performance revisions in Northeast Appalachia. In 2014, the Company’s production was 768 Bcfe, up from 657 Bcfe in 2013. The increase in production in 2014 resulted primarily from a 103 Bcf increase in net production from the Company’s Northeast Appalachia properties, a 3 Bcfe increase in net production from its Southwest Appalachia properties, and an 8 Bcf increase in net production from its Fayetteville Shale properties, which more than offset a combined 3 Bcfe decrease in net production from its East Texas and Arkoma Basin properties. The Company replaced 591% of its production volumes with 1,693 Bcfe of proved reserve additions, net upward revisions of 543 Bcfe, and 2,304 Bcfe of proved reserve additions as a result of acquisitions primarily associated with acreage in Southwest Appalachia.  Of the reserve additions, 283 Bcfe, 246 Bcfe and 2 Bcfe from the Company’s Fayetteville Shale, Northeast Appalachia, and Brown Dense divisions, respectively, were proved developed and 573 Bcfe and 589 Bcfe from its Fayetteville Shale and Northeast Appalachia divisions, respectively, were proved undeveloped. In 2014, upward reserve revisions resulting from higher gas prices totaled 38 Bcf, 10 Bcf and 6 Bcf in the Company’s Fayetteville Shale, Northeast Appalachia and Ark-La-Tex divisions, respectively.  The Company also had performance revisions in 2014 of (126) Bcf, 636 Bcf and (21) Bcf in its Fayetteville Shale, Northeast Appalachia and Ark-La-Tex divisions, respectively. The Company’s December 31, 2014 proved reserves include 181 Bcfe of proved undeveloped reserves from 60 locations that have a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%. These properties have a negative present value of $28 million when discounted at 10%. The Company has made a final investment decision and is committed to developing these reserves.
The Company’s estimated proved natural gas and oil reserves were 6,976 Bcfe at year-end 2013, compared to 4,018 Bcfe at year-end 2012. The significant increase in the Company’s reserves in 2013 was primarily due to its successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and the higher natural gas price environment compared to 2012. In 2013, the Company’s production was 657 Bcfe, up from 565 Bcfe in 2012. The increase in production in 2013 resulted primarily from a 97 Bcf increase in net production from the Company’s Northeast Appalachia properties, a 1 Bcfe increase in net production from its New Ventures properties, and a 1 Bcf increase in net production from its Fayetteville Shale properties, which more than offset a combined 7 Bcfe decrease in net production from its East Texas and Arkoma Basin properties. The Company replaced 550% of its production volumes with 3,285 Bcfe of proved reserve additions, net upward revisions of 326 Bcfe, and 4 Bcfe of proved reserve additions as a result of acquisitions.  Of the reserve additions, 557 Bcfe, 386 Bcfe and 2 Bcfe from the Company’s Fayetteville Shale, Northeast Appalachia and Brown Dense divisions, respectively, were proved developed and  1,530 Bcfe and 810  Bcfe from its Fayetteville Shale and Northeast Appalachia divisions, respectively, were proved undeveloped.  In 2013, upward reserve revisions resulting from higher gas prices totaled 191 Bcf, 35 Bcf and 21 Bcf in the Fayetteville Shale, Northeast Appalachia, and the Company’s Ark-La-Tex division, respectively.  The Company also had upward performance revisions in 2013 of 16 Bcf, 62 Bcf and 1 Bcf in the Fayetteville Shale, Northeast Appalachia, and the Company’s New Ventures division, respectively.  Additionally, the Company’s reserves increased by 4 Bcf in 2013 as a result of the acquisition of natural gas leases and wells in Northeast Appalachia. The Company’s December 31, 2013 proved reserves include 662 Bcfe of proved undeveloped reserves from 268 locations that have a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%. These properties have a negative present value of $97 million when discounted when at 10%.
The Company’s estimated proved natural gas and oil reserves were 4,018 Bcfe at year-end 2012, compared to 5,893 Bcfe at year-end 2011. The overall decrease in total estimated proved reserves in 2012 was primarily due to the low natural gas price environment.  In 2012, the Company’s production was 565 Bcfe, up from 500 Bcfe in 2011. The increase in production in 2012 resulted primarily from a 49 Bcf increase in production from the Fayetteville Shale and a 30 Bcf increase in the Company’s Northeast Appalachia production, which more than offset a combined 14 Bcfe decrease in net production from the Company’s East Texas and Arkoma Basin properties. The Company replaced its production volumes with 920 Bcfe of proved reserve additions as a result of its drilling and acquisition program but also incurred net downward revisions of 2,088 Bcfe principally due to a decrease in the price of natural gas and to a lesser extent due to downward performance revisions of 336 Bcfe.   Of the reserve additions, 383 Bcfe, 195 Bcfe, 3 Bcfe and 2 Bcfe from the Company’s Fayetteville Shale, Northeast Appalachia, Ark-La-Tex, and New Ventures divisions, respectively, were proved developed and 32 Bcfe and 305 Bcfe from its Fayetteville Shale and Northeast Appalachia divisions, respectively, were proved undeveloped. The total downward reserve revisions were primarily impacted by the low commodity price environment in 2012 and to a lesser extent by downward performance revisions.  In 2012, downward reserve revisions resulting from lower gas prices totaled 1,684 Bcf, 9 Bcf and 59 Bcf in the Fayetteville Shale, Northeast Appalachia, and the Company’s Ark-La-Tex division, respectively.  The Company also had a net downward performance revision in 2012 of 362 Bcf and 10 Bcf in the Fayetteville Shale and its Ark-La-Tex division, respectively.  The Company had a net positive performance revision in 2012 of 36 Bcf in Northeast Appalachia.  Additionally, the Company’s reserves decreased by 141 Bcf in 2012 as a result of its disposition of natural gas leases and wells in the Overton Field in East Texas. The Company’s December 31, 2012 proved reserves include 355 Bcfe of proved undeveloped reserves from 198 locations that have a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%. These properties have a negative present value of $71 million when discounted when at 10%.
The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. The Company used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors.
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, 2014, 2013 and 2012 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:
	2014			2013			2012
	(in millions)
Future cash inflows	$	41,812		$	22,624		$	9,570
Future production costs		-16,477			-8,896			-4,737
Future development costs		-5,750			-3,626			-711
Future income tax expense		-4,743			-3,223			-745
Future net cash flows		14,842			6,879			3,377
10% annual discount for estimated timing of cash flows		-7,299			-3,143			-1,326
Standardized measure of discounted future net cash flows	$	7,543		$	3,736		$	2,051
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 $4.35 per MMBtu for natural gas, $91.48 per barrel for oil and $23.79 per barrel for NGLs in 2014, $3.67 per MMBtu for natural gas,  $93.42 per barrel for oil and $43.45 per barrel for NGLs in 2013, and $2.76 per MMBtu for natural gas and $91.21 per barrel for oil in 2012. 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 2014, 2013 and 2012:
	2014			2013			2012
	(in millions)
Standardized measure, beginning of year	$	3,736		$	2,051		$	3,451
Sales and transfers of natural gas and oil produced, net of production costs		-2,084			-1,774			-1,444
Net changes in prices and production costs		1,192			1,853			-2,605
Extensions, discoveries, and other additions, net of future production and development costs		1,049			1,454			550
Acquisition of reserves in place		1,897			5			–
Sales of reserves in place		–			–			-157
Revisions of previous quantity estimates		622			349			-1,109
Accretion of discount		513			232			480
Net change in income taxes		-522			-1,120			1,079
Changes in estimated future development costs		110			-196			2,476
Previously estimated development costs incurred during the year		815			223			62
Changes in production rates (timing) and other		215			659			-732
Standardized measure, end of year	$	7,543		$	3,736		$	2,051

Derivatives_And_Risk_Managemen

Derivatives And Risk Management	12 Months Ended
	Dec. 31, 2014
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, NGLs and oil. These risks are managed by the Company’s use of certain derivative financial instruments.  As of December 31, 2014 and 2013, the Company’s derivative financial instruments consisted of fixed price swaps, basis swaps, fixed price call options, and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:
	Fixed price swaps	The Company receives a fixed price for the contract and pays a floating market price to the counterparty.
	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.
	All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value other than transactions for which normal purchase/normal sale is applied. 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 designated 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 excluding derivatives, settled and gains (losses) on derivatives, settled. The Company calculates gains (losses) on derivatives, settled, as the summation of gains and losses on positions which 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 assets related to derivative financial instruments are summarized below as of December 31, 2014 and 2013:
			Derivative Assets
			31-Dec-14						31-Dec-13
			Balance Sheet Classification		Fair Value				Balance Sheet Classification	Fair Value
			(in millions)
	Derivatives designated as hedging instruments:
	Fixed price swaps		Derivative assets			$	165		Derivative assets	$	21
	Total derivatives designated as hedging instruments					$	165			$	21
	Derivatives not designated as hedging instruments:
	Basis swaps		Derivative assets			$	9		Derivative assets	$	13
	Fixed price swaps		Derivative assets				163		Derivative assets		37
	Basis swaps		Other long-term assets				1		Other long-term assets		–
	Interest rate swaps		Other long-term assets				1		Other long-term assets		8
	Total derivatives not designated as hedging instruments					$	174			$	58
	Total derivative assets					$	339			$	79
			Derivative Liabilities
			31-Dec-14						31-Dec-13
			Balance Sheet Classification			Fair Value			Balance Sheet Classification	Fair Value
			(in millions)
	Derivatives designated as hedging instruments:
	Fixed price swaps		Derivative liabilities			$	–		Derivative liabilities	$	4
	Total derivatives designated as hedging instruments					$	–			$	4
	Derivatives not designated as hedging instruments:
	Basis swaps		Derivative liabilities			$	4		Derivative liabilities	$	1
	Fixed price call options		Derivative liabilities				2		Derivative liabilities		–
	Interest rate swaps		Derivative liabilities				3		Derivative liabilities		2
	Fixed price call options		Other long-term liabilities				10		Other long-term liabilities		31
	Basis swaps		Other long-term liabilities				2		Other long-term liabilities		–
	Interest rate swaps		Other long-term liabilities				2		Other long-term liabilities		3
	Total derivatives not designated as hedging instruments					$	23			$	37
	Total derivative liabilities					$	23			$	41
	As of December 31, 2014, the Company had fixed price swap derivatives designated for hedge accounting and not designated for hedge accounting on the following volumes of natural gas production (in Bcf):
	Year	Fixed price swaps designated for	Fixed price swaps not designated for	Total	Weighted Average Price to be Swapped ($/MMBtu) (1)
		hedge accounting	hedge accounting
	2015	120	120	240	$4.40
	(1)    The weighted average price to be swapped is $4.40 for each category and in total.
	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 are recognized in earnings immediately and had an inconsequential impact to the consolidated statement of operations as of December 31, 2014 and 2013.
	As of December 31, 2014, the Company recorded a net gain in accumulated other comprehensive income related to its hedging activities of $98 million net of a deferred income tax liability of $65 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, 2014 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of approximately $98 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. 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, 2014 and 2013.
						Gain Recognized in Other Comprehensive Income
						(Effective Portion)
					For the years ended
					December 31,
	Derivative Instrument				2014			2013
					(in millions)
	Fixed price swaps				$	122		$	38
			Classification of Gain  (Loss)		Gain (Loss) 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)		2014			2013
					(in millions)
	Fixed price swaps		Gas Sales		$	-26		$	309
	Other Derivative Contracts
	For other derivative contracts, 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 through gain (loss) on derivatives. 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 long-term 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, 2014, the Company had basis swaps on natural gas production that were not designated for hedge accounting of 22 Bcf for 2015 and 4 Bcf for 2016.
As of December 31, 2014, the Company had fixed price call options on 200 Bcf and 120 Bcf of natural gas production in 2015 and 2016, respectively, not designated for hedge accounting and fixed price swaps of 120 Bcf of natural gas production in 2015 not designated for hedge accounting.
The Company is a party to interest rate swaps that were entered into in order to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps build to a notional amount of $170 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 following tables summarize the before tax effect of fixed price swaps, basis swaps, fixed price call options and interest rate swaps not designated for hedge accounting on the condensed consolidated statements of operations for the years ended December 31, 2014 and 2013.
				Gain (Loss) on Derivatives,
				Excluding Derivatives, Settled
				Recognized in Earnings
		Consolidated Statement of Operations		For the years ended
		Classification of Gain (Loss) on		December 31,
Derivative Instrument		Derivatives, Net of Settlement		2014			2013
				(in millions)
Basis swaps		Gain (Loss) on Derivatives		$	-7		$	7
Fixed price call options		Gain (Loss) on Derivatives			18			-26
Fixed price swaps		Gain (Loss) on Derivatives			126			37
Interest rate swaps		Gain (Loss) on Derivatives			-7			3
				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)		2014			2013
				(in millions)
Basis swaps		Gain (Loss) on Derivatives		$	12		$	5
Fixed price swaps		Gain (Loss) on Derivatives			-2			–
Interest rate swaps		Gain (Loss) on Derivatives			-1			–
	-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, 2014
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 (loss) and the related tax effects for the year ended December 31, 2014:
			For the year ended
			31-Dec-14
			Gains (Losses) on Cash Flow Hedges			Pension and Other Postretirement		Foreign Currency		Total
			(in millions) (1)
	Beginning balance, December 31, 2013		$	9		$	-9	$	-4	$	-4
	Other comprehensive income (loss) before reclassifications			73			–		-8		65
	Amounts reclassified from/to other comprehensive income (2)			16			-15		–		1
	Net current-period other comprehensive income (loss)			89			-15		-8		66
	Ending balance, December 31, 2014		$	98		$	-24	$	-12	$	62
		-1		All amounts are net of tax.
		-2		See separate table below for details about these reclassifications.
	Details about Accumulated Other Comprehensive Income		Affected Line Item in the Consolidated Statement of Operations		Amount Reclassified from/to Accumulated Other Comprehensive Income
					For the year ended December 31, 2014
					(in millions)
	Gains (losses) to Other Comprehensive Income on cash flow hedges
	Settlements		Gas sales	$	26
	Ineffectiveness		Gas sales		–
			Gain before income taxes		26
			Less: Provision for income taxes		10
			Net Gain	$	16
	Pension and other postretirement (1)
	Net actuarial loss(2)			$	-25
			Loss before income taxes		-25
			Less: Benefit for income taxes		-10
			Net Loss	$	-15
	Total reclassifications for the period		Net Gain	$	1
		-1		See Note 12 for additional details regarding the Company’s retirement and employee benefit plans.
		-2		Net actuarial loss had no impact on the consolidated statement of operations.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013 were as follows:
		31-Dec-14						31-Dec-13
		Carrying			Fair			Carrying			Fair
		Amount			Value			Amount			Value
		(in millions)
	Cash and cash equivalents	$	53		$	53		$	23		$	23
	Credit facility	$	300		$	300		$	283		$	283
	Term loan facility	$	500		$	500		$	–		$	–
	Bridge facility	$	4,500		$	4,500		$	–		$	–
	Senior notes	$	1,667		$	1,751		$	1,668		$	1,796
	Derivative instruments, net	$	316		$	316		$	38		$	38
	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 3.2%  as of December 31, 2014 and 2.6% at December 31, 2013, and its 4.10% Senior Notes due 2022, which was 4.3% as of December 31, 2014 and 4.2% at December 31, 2013. The carrying values of the borrowings under the Company’s unsecured revolving credit facility, bridge facility, and term loan 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.
	The fair value hierarchy 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 swaps and are estimated using internal discounted cash flow calculations using the NYMEX futures index. The Company utilized discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2014 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative asset and liability measurement represent Level 2 inputs in the hierarchy. The Company’s Level 3 fair value measurements include fixed price call options and basis swaps. The Company’s fixed price call options are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness. The Company’s basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves.
	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. However, such changes would not have a significant impact.
	Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):
			31-Dec-14
			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		$	–		$	329		$	10		$	339
	Derivative liabilities			–			-5			-18			-23
	Total		$	–		$	324		$	-8		$	316
			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		$	–		$	66		$	13		$	79
	Derivative liabilities			–			-9			-32			-41
	Total		$	–		$	57		$	-19		$	38
	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, 2014 and 2013. 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, 2014 and December 31, 2013.
			For the years ended
			December 31,
			2014			2013
			(in millions)
	Balance at beginning of period		$	-19		$	–
	Total gains (losses):
	Included in earnings			23			-14
	Included in other comprehensive income			–			–
	Purchases, issuances, and settlements:
	Purchases			–			–
	Issuances			–			–
	Settlements			-12			-5
	Transfers into/out of Level 3			–			–
	Balance at end of period		$	-8		$	-19
	Change in gains (losses) included in earnings relating to derivatives still held as of December 31		$	11		$	-19

Debt

Debt	12 Months Ended
	Dec. 31, 2014
Debt [Abstract]
Debt	(8) DEBT
	The components of debt as of December 31, 2014 and 2013 consisted of the following:
			2014		2013
			(in millions)
	Short-term debt:
	7.15% Senior Notes due 2018		$	1	$	1
	Variable rate (1.515% at December 31, 2014) bridge facility, due December 2015			4,500		–
	Total short-term debt			4,501		1
	Long-term debt:
	Variable rate (1.515%  and 1.640% at December 31, 2014 and December 31, 2013, respectively) credit facility, expires December 2018			300		283
	Variable rate (1.545% at December 31, 2014) term loan facility, due December 2016			500		–
	7.35% Senior Notes due 2017			15		15
	7.125% Senior Notes due 2017			25		25
	7.15% Senior Notes due 2018			27		28
	7.5% Senior Notes due 2018			600		600
	4.10% Senior Notes due 2022			1,000		1,000
	Unamortized discount			-1		-1
	Total long-term debt			2,466		1,950
	Total debt		$	6,967	$	1,951
	The following is a summary of scheduled long-term debt maturities by year as of December 31, 2014 (in millions):
	2016		501
	2017		41
	2018		925
	Thereafter		1,000
		$	2,467
	Chesapeake Property Acquisition Financing
	On December 19, 2014, the Company entered into a $4.5 billion unsecured 364-day bridge term loan credit agreement with various lenders. The bridge facility requires prepayments under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business or for specified uses. The Company repaid the $4.5 billion outstanding and terminated the bridge facility in January 2015 with net proceeds of $669 million and $1.7 billion from common stock and depositary share offerings, respectively, and $2.2 billion from senior note offerings with the difference utilized to pay down amounts under the revolving credit facility.
	On December 19, 2014, the Company also entered into a $500 million unsecured two-year term loan credit agreement with various lenders. The term loan facility requires prepayment under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business.
	Credit, Bridge and Term Facilities
	The Company’s revolving credit facility provides a borrowing capacity of up to  $2.0 billion and matures on December 2018, with options for two one-year extensions with participating lender approval. The amount available under the revolving credit facility may be increased by $500 million upon the Company’s agreement with its participating lenders. The interest rates on the revolving credit facility, bridge facility and term loan facility are calculated based upon the Company’s credit rating and were 137.5 basis points over the current London Interbank Offered Rate, or LIBOR as of December 31, 2014, and is currently at 150 basis points over the current LIBOR. The interest rate on the revolving credit facility at December 31, 2013 was 150 basis points over LIBOR.  The revolving credit facility, bridge facility and term loan facility are unsecured and are not guaranteed by any subsidiaries of the Company.  The revolving credit facility, bridge facility and term loan facility contain covenants which impose certain restrictions on us, including a financial covenant under which 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 effects of any full cost ceiling impairments (after December 31, 2011), certain hedging activities and the Company’s pension and other postretirement liabilities. As of December 31, 2014, the Company was in compliance with the covenants of its revolving credit facility, bridge facility, term loan facility and other debt agreements.

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2014
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, 2014, future payments under non-cancelable firm transportation charges are approximately $478 million in 2015, $515 million in 2016, $543 million in 2017, $549 million in 2018, $502 million in 2019 and $2,802 million thereafter.
	The Company has 11 leases for pressure pumping equipment for its E&P operations under leases that expire between December 2017 and January 2018.  The Company’s current aggregate annual payment under the leases is approximately $8 million.  The Company has 7 leases for drilling rigs for its E&P operations that expire in 2020. The Company’s current aggregate payment under the leases is approximately $13 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, 2014, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $73 million in 2015, $62 million in 2016, $45 million in 2017, $25 million in 2018, $21 million in 2019 and $45 million thereafter. The Company also has commitments for compression services related to its Midstream Services and E&P segments. As of December 31, 2014, future minimum payments under these non-cancelable agreements are approximately $41 million in 2015, $28 million in 2016, $19 million in 2017, $10 million in 2018, and $4 million in 2019.
	In response to its well performance, the Company entered into new and amended natural gas transportation and gathering arrangements with third party pipelines during the second quarter of 2013 in support of its production in Northeast Appalachia. As of December 31, 2014, the Company’s obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $5.4 billion and it has guarantee obligations of up to $173 million of that amount.
	In 2013, the Company started construction on a corporate office complex located in Spring, Texas on 26 acres of commercial land that it purchased in 2012.  The Company financed the construction of this complex through a construction agreement and lease arrangement.  As of December 31, 2014, the Company was obligated for the construction costs incurred, which approximated $137 million. In January 2015, construction on the corporate campus was completed and the Company commenced a lease with a term of approximately five years.
	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 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 $45 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, 2014 has invested $45 million Canadian dollars, or $44 million USD, in New Brunswick towards the Company’s commitment, fully covering the promissory notes held by the Province of New Brunswick. No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of December 31, 2014 and its future investment plans. Our licenses are scheduled to expire in March 2015. The newly elected provincial government in New Brunswick has announced an intent to impose a moratorium on hydraulic fracturing until a list of conditions is met and has introduced authorizing legislation in the provincial legislature. The Company has applied for an extension of its licenses past the end of the moratorium, but as of this time that extension has not been granted. The list of conditions that the provincial government has announced is subjective, and the Company cannot predict the duration of the moratorium or whether it will be granted the extension requested or any other extension. Unless and until the moratorium is lifted and the Company’s licenses are extended, it will not be able to continue with its program in New Brunswick. If this extension is not granted, the Company  may be required to write off its investment.
	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, one of the Company’s subsidiaries 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 the Company’s subsidiary with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that the Company’s subsidiary 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 the Company’s subsidiary between February 2005 and February 2006.  She also sought disgorgement of the Company’s subsidiary’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 million in compensatory damages but no special, punitive or other damages. Separately, the jury determined that the Company’s subsidiary’s profits for purposes of disgorgement, if ordered as a remedy, were $382 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 million in actual damages and approximately $24 million in disgorgement as well as prejudgment interest and attorneys’ fees, which currently are estimated to be up to $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 $24 million as disgorgement of illicit gains be reversed and judgment rendered that they take nothing, (2) the award of $11 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 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 the Company’s subsidiary 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.
	The Company’s subsidiary filed a petition for review in the Supreme Court of Texas in February 2014.  The plaintiff and the intervenor filed cross petition for review in April 2014, but conditioned their filing on the courts granting the Company’s subsidiary petition for review; i.e., if the court denies the Company’s subsidiary’s petition for review, then the plantiff and the intervenor are not seeking further review of the court of appeals’ judgment. On October 24, 2014, the Supreme Court requested full briefing on the merits of the case. 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 Supreme Court declines to rule on the case or affirms all aspects of the court of appeals’ judgment then the Company’s subsidiary would owe the $11 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 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.
	Arkansas Royalty Litigation
	The Company is a defendant in three cases, two filed in Arkansas state court in 2010 and 2013 and one in federal court in 2014, on behalf of putative classes of royalty owners on some of its leases located in Arkansas. The chief complaint in all three cases is that the Company underpaid the royalty owners by, among other things, deducting from royalty payments costs for gathering, transportation, and compression of natural gas in excess of what is permitted by the relevant leases. The Company removed the two cases filed in state court to federal court, but both were remanded to state court during the third quarter of 2014; the appeal of those remand orders is ongoing. Despite the ongoing appeal of the remand, in September and October 2014 the judges in the two Arkansas state actions entered orders certifying classes of royalty owners who are citizens of Arkansas. The Company is appealing those orders. Discovery regarding the plantiffs’ theories of liability and amount of claimed damages is in the very early stages. Management believes that the deductions from royalty payments as calculated are permitted and intends to defend the cases vigorously. The Company’s assessment may change in the future due to the occurrence of certain events, such as adverse judgments, 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.
	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 the Company’s 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, 2014
Income Taxes [Abstract]
Income Taxes	(10) INCOME TAXES
	The provision (benefit) for income taxes included the following components:
			2014		2013		2012
		(in millions)
	Current:
	Federal	$	11	$	-12	$	16
	State		10		1		3
			21		-11		19
	Deferred:
	Federal		501		408		-388
	State		2		88		-72
	Foreign		1		1		-2
			504		497		-462
	Provision (benefit) for income taxes	$	525	$	486	$	-443
	The provision for income taxes was an effective rate of 36% in 2014, 41% in 2013 and 39% in 2012. 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:
			2014		2013		2012
		(in millions)
	Expected provision (benefit) at federal statutory rate	$	507	$	417	$	-403
	Increase (decrease) resulting from:
	State income taxes, net of federal income tax effect		58		53		-44
	Nondeductible expenses		3		3		2
	State rate redetermination		-48		4		2
	Other		5		9		–
	Provision (benefit) for income taxes	$	525	$	486	$	-443
	The components of the Company’s net deferred tax liability as of December 31, 2014 and 2013 were as follows:
			2014		2013
		(in millions)
	Deferred tax liabilities:
	Differences between book and tax basis of property	$	2,504	$	2,115
	Derivative activity		122		13
	Other		21		11
			2,647		2,139
	Deferred tax assets:
	Accrued compensation		23		16
	Alternative minimum tax credit carryforward		131		77
	Stored natural gas		5		9
	Accrued pension costs		17		2
	Asset retirement obligations		79		54
	Net operating loss carryforward		318		412
	Differences between book and tax basis of property - state		6		11
	Other		8		7
			587		588
	Net deferred tax liability	$	2,060	$	1,551
	The net deferred tax liability as of December 31, 2014 was comprised of net long-term deferred income tax liabilities of $1,951 million, in addition to a net current deferred income tax liability of $109 million. The net deferred tax liability at December 31, 2013 was comprised of net long-term deferred income tax liabilities of $1,527 million, in addition to a net current deferred income tax liability of $24 million.  In 2014, the Company paid $14 million in state income taxes and paid $14 million in federal income taxes.  In 2013, the Company paid $3 million in state income taxes and paid $16 million in federal income taxes.  The Company’s net operating loss carryforward as of December 31, 2014 was $988 million and $556 million for federal and state reporting purposes, respectively, the majority of which will expire between 2028 and 2034.  As of December 31, 2014, the Company has recorded a $5 million valuation allowance against its deferred tax asset for various state net operating losses. The Company also had an alternative minimum tax credit carryforward of $131 million and a statutory depletion carryforward of $13 million as of December 31, 2014.
	Our effective tax rate decreased in 2014 as compared with 2013. This was primarily due to a redetermination of the deferred state tax liability to reflect updated state apportionment factors in certain states.
	Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises in 2014. 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, 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 the Company’s current taxes payable in 2014 due to net operating loss carryforwards, these “windfall” tax benefits are not reflected in its net operating losses in deferred tax assets for 2014. Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2014 were $152 million.
	The Company has an income tax net operating loss carryforward related to its Canadian operations of $26 million, and has expiration dates of 2030 through 2034. 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, 2014.
	A tax position must meet certain thresholds for any of the benefit of the uncertain tax position to be recognized in the financial statements. As of December 31, 2014, the amount of unrecognized tax benefits related to alternative minimum tax was $44 million.  The uncertain tax position identified would not have a material effect on the effective tax rate.  No material changes to the current uncertain tax position are expected within the next 12 months. As of December 31, 2014, the Company had accrued a liability of $1 million of interest related to this uncertain tax position. The Company recognizes penalties and interest related to uncertain tax positions in income tax expense.
	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
			2014
			(in millions)
	Unrecognized tax benefits at beginning of period	$	-
	Additions based on tax positions related to the current year		15
	Additions to tax positions of prior years		29
	Settlements		-
	Unrecognized tax benefits at end of period	$	44
	The income tax years 2011 to 2014 remain open to examination by the major taxing jurisdictions to which the Company is subject.

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation	(11) ASSET RETIREMENT OBLIGATIONS
	The following table summarizes the Company’s 2014 and 2013 activity related to asset retirement obligations:
			2014			2013
			(in millions)
	Asset retirement obligation at January 1		$	134		$	101
	Accretion of discount			7			6
	Obligations incurred			64	-1		22
	Obligations settled/removed			-4			-2
	Revisions of estimates			6			7
	Asset retirement obligation at December 31		$	207		$	134
	Current liability			9			6
	Long-term liability			198			128
	Asset retirement obligation at December 31		$	207		$	134
		-1		Obligations incurred include $42 million related to the Chesapeake Property Acquisition.

Retirement_And_Employee_Benefi

Retirement And Employee Benefit Plans	12 Months Ended
	Dec. 31, 2014
Retirement And Employee Benefit Plans [Abstract]
Retirement And Employee Benefit 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 $3 million, $3 million and $2 million of contribution expense in 2014, 2013 and 2012, respectively. Additionally, the Company capitalized $3 million, $3 million and $3 million of contributions in 2014, 2013 and 2012, 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, 2014 and 2013:
								Other Postretirement
		Pension Benefits						Benefits
			2014			2013			2014		2013
		(in millions)
	Change in benefit obligations:
	Benefit obligation at January 1	$	103		$	105		$	12	$	12
	Service cost		13			14			2		2
	Interest cost		5			4			1		–
	Participant contributions		–			–			–		–
	Actuarial loss		21			-11			3		-2
	Benefits paid		-8			-8			–		–
	Plan amendments		–			–			–		–
	Settlements		–			-1			–		–
	Benefit obligation at December 31	$	134		$	103		$	18	$	12
								Other Postretirement
		Pension Benefits						Benefits
			2014			2013			2014		2013
		(in millions)
	Change in plan assets:
	Fair value of plan assets at January 1	$	99		$	83		$	–	$	–
	Actual return on plan assets		5			12			–		–
	Employer contributions		12			13			–		–
	Participant contributions		–			–			–		–
	Benefits paid		-8			-8			–		–
	Settlements		–			-1			–		–
	Fair value of plan assets at December 31	$	108		$	99		$	–	$	–
	Funded status of plans at December 31	$	-26		$	-4		$	-18	$	-12
	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 loss of $23 million ($14 million after tax) for the year ended December 31, 2014 and a gain of $19 million ($12 million after tax) for the year ended December 31, 2013. The change in accumulated other comprehensive income related to the other postretirement benefit plan was a loss of  $2 million ($1 million after tax) for the year ended December 31, 2014 and was a gain of $2 million ($1 million after tax) for the year ended December 31, 2013. Included in accumulated other comprehensive income as of December 31, 2014 and 2013 was a $41 million loss ($24 million net of tax) and a $16 million loss ($10 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans.    For the year ended December 31, 2014,  $25 million was classified to accumulated other comprehensive income primarily driven by actuarial loss adjustments. Amortization of prior period service cost reclassified from accumulated other comprehensive income to general and administrative expenses for the year was immaterial.
	The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2015 is a  $2 million net loss.
	The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2014 and 2013 are as follows:
			2014			2013
			(in millions)
	Projected benefit obligation	$	134		$	103
	Accumulated benefit obligation	$	129		$	100
	Fair value of plan assets	$	108		$	99
	Pension and other postretirement benefit costs include the following components for 2014, 2013 and 2012:
											Other Postretirement
			Pension Benefits								Benefits
			2014			2013			2012		2014		2013		2012
			(in millions)
	Service cost	$	13		$	14		$	11	$	2	$	2	$	2
	Interest cost		5			4			4		1		1		–
	Expected return on plan assets		-7			-6			-5		–		–		–
	Amortization of transition obligation		–			–			–		–		–		–
	Amortization of prior service cost		–			–			–		–		–		–
	Amortization of net loss		1			2			1		–		–		–
	Net periodic benefit cost		12			14			11		3		3		2
	Settlements and curtailments		–			0			–		–		–		–
	Total benefit cost	$	12		$	14		$	11	$	3	$	3	$	2
	Amounts recognized in other comprehensive income for the year ended December 31, 2014 were as follows:
				Pension Benefits			Other Postretirement Benefits
				(in millions)
	Net actuarial loss arising during the year		$	-23		$	-2
	Amortization of prior service cost			–			–
	Amortization of net loss			–			–
Settlements			–			–
Tax effect			9			1
		$	-14		$	-1
The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2014 and 2013 are as follows:
	Pension Benefits						Other Postretirement
							Benefits
	2014			2013			2014		2013
Discount rate	4.25	%		5.00	%		4.25	%	5.00	%
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 2014, 2013 and 2012 are as follows:
	Pension Benefits								Other Postretirement
									Benefits
	2014			2013			2012		2014		2013		2012
Discount rate	5.00	%		4.00	%		5.00	%	5.00	%	4.00	%	5.00	%
Expected return on plan assets	7.00	%		7.00	%		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 2014 and 2013:
	2014			2013
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	2033			2032
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 millions)
Effect on the total service and interest cost components	$	–		$	–
Effect on postretirement benefit obligations	$	3		$	-2
Pension Payments and Asset Management
In 2014, the Company contributed $12 million to its pension plans and $0.1 million to its other postretirement benefit plan. The Company expects to contribute $12 million to its pension plans and $1 million to its other postretirement benefit plan in 2015. 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 millions)
2015	$	6		2015	$	1
2016	$	8		2016	$	1
2017	$	8		2017	$	1
2018	$	10		2018	$	1
2019	$	11		Years 2019-2023	$	9
Years 2020-2024	$	65
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, 2014, 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
Equity securities:
U.S. Equity(1)	35	%		36	%
Non-U.S. Developed Equity(2)	30	%		27	%
Emerging Markets Equity(3)	5	%		5	%
Opportunistic(4)	–	%		–	%
Fixed income(5)	29	%		29	%
Cash(6)	1	%		3	%
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 the fair value hierarchy described in Note 7 – Fair Value Measurements, the Company’s fair value measurement of pension plan assets as of December 31, 2014 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 millions)
Equity securities:
U.S. large cap growth equity(1)	$	8		$	8		$	–	$	–
U.S. large cap value equity(2)		9			9			–		–
U.S. large cap core equity(3)		19			–			19		–
U.S. small cap equity(4)		3			3			–		–
Non-U.S. equity(5)		29			29			–		–
Emerging markets equity(6)		5			5			–		–
Fixed income (7)		31			–			31		–
Cash and cash equivalents		4			4			–		–
Total	$	108		$	58		$	50	$	–
(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 the fair value hierarchy described in Note 7 – Fair Value Measurements, the Company’s fair value measurement of pension plan assets at 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 millions)
Equity securities:
U.S. large cap growth equity(1)	$	8		$	8		$	–	$	–
U.S. large cap value equity(2)		8			8			–		–
U.S. large cap core equity(3)		16			–			16		–
U.S. small cap equity(4)		3			3			–		–
Non-U.S. equity(5)		31			31			–		–
Emerging markets equity(6)		6			–			6		–
Fixed income (7)		26			–			26		–
Cash and cash equivalents		1			1			–		–
Total	$	99		$	51		$	48	$	–
(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, 2014
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,  1,250,000, 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, 2014, 2013 and 2012:
		2014			2013			2012
			(in millions)
	Stock-based compensation cost related to stock options – general and administrative expense	$	5		$	5		$	5
	Stock-based compensation cost related to stock options – capitalized	$	4		$	5		$	4
	The Company also recorded a deferred tax asset of $3 million related to stock options in 2014, compared to deferred tax benefits of $4 million in 2013 and $2 million in 2012. A total of $13 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 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	2014		2013		2012
	Risk-free interest rate	1.6%		1.5%		0.6%
	Expected dividend yield	–		–		–
	Expected volatility	32.5%		38.6%		58.2%
	Expected term	5 years		5 years		5 years
	The following tables summarize stock option activity for the years 2014, 2013 and 2012 and provide information for options outstanding at December 31 of each year:
			2014					2013						2012
						Weighted						Weighted				Weighted
						Average						Average				Average
			Number			Exercise		Number				Exercise		Number		Exercise
			of Shares			Price		of Shares				Price		of Shares		Price
			(in thousands)					(in thousands)						(in thousands)
	Options outstanding at January 1		3,313		$	35.70		3,650			$	29.84		4,743	$	21.24
	Granted		835			32.31		571				38.95		613		34.34
	Exercised		-402			30.60		-833				12.12		-1,608		5.71
	Forfeited or expired		-124			37.80		-75				37.31		-98		37.76
	Options outstanding at December 31		3,622		$	35.41		3,313			$	35.70		3,650	$	29.84
			Options Outstanding								Options Exercisable
								Weighted							Weighted
								Average							Average
			Options			Weighted		Remaining			Options			Weighted	Remaining
			Outstanding at			Average		Contractual			Exercisable at			Average	Contractual
	Range of		December 31,			Exercise		Life			December 31,			Exercise	Life
	Exercise Prices		2014			Price		(Years)			2014			Price	(Years)
			(in thousands)								(in thousands)
	$27.09-$29.69		21			28.42		2.9			17			28.53	2.5
	$30.23-$35.91		1,744			32.04		4.9			819			32.83	3.1
	$36.22-$39.91		1,443			37.52		4.3			1,117			37.10	3.9
	$40.15-$51.47		414			42.64		2.9			324			41.56	1.9
			3,622		$	35.41		4.4		$	2,277		$	36.13	3.3
	The weighted-average grant-date fair value of options granted during the years 2014, 2013 and 2012 was $10.16, $13.39, and $16.91, respectively. The total intrinsic value of options exercised during 2014, 2013 and 2012 was $4 million, $22 million and $44 million, respectively.
	Restricted Stock
	The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2014, 2013 and 2012:
			2014			2013			2012
			(in millions)
	Stock-based compensation cost related to restricted stock grants	$	10		$	7		$	6
	– general and administrative expense
	Stock-based compensation cost related to restricted stock grants	$	12		$	7		$	6
	– capitalized
	The Company also recorded a deferred tax liability of $10 million related to restricted stock for the year ended December 31, 2014, compared to deferred tax liabilities of $15 million for 2013 and $1 million for 2012. As of December 31, 2014, there was $75 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 3.1 years.
	The following table summarizes the restricted stock activity for the years 2014, 2013 and 2012 and provides information for restricted stock outstanding at December 31 of each year:
			2014					2013							2012
						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
			(in thousands)					(in thousands)								(in thousands)
	Unvested shares at January 1		1,771		$	37.55		1,118			$		35.64			1,020	$	36.71
	Granted		1,295			30.89		1,109					38.92			537		34.39
	Vested		-548			37.12		-382					36.29			-344		36.50
	Forfeited		-142			37.91		-74					35.81			-95		36.97
Unvested shares at December 31		2,376		$	34.00		1,771			$		37.55			1,118	$	35.64
The fair values of the grants were $40 million for 2014, $43 million for 2013 and $19 million for 2012. The total fair value of shares vested were $20 million for 2014, $14 million for 2013 and $13 million for 2012.
Equity-Classified Performance Units
The Company recorded the following compensation costs related to equity-classified performance units for the years ended December 31, 2014.  The performance units include a market condition based on Relative Total Shareholder Return (“TSR”) and a performance condition based on the Company’s Present Value Index (“PVI”).  The fair value of the TSR market condition of the performance units is based on a Monte Carlo model and is amortized to compensation expense on a straight-line basis over the vesting period of the award.  The fair value of the PVI performance condition of the performance units is based on the closing price of the Company’s common stock at the grant date and amortized to compensation expense on a straight line basis over the vesting period of the award.
		2014
		(millions)
Stock-based compensation cost related to performance units - general and administrative expense	$	3
Stock-based compensation cost related to performance units - capitalized	$	2
The Company also recorded a deferred tax asset of $2 million related to equity-based performance units for the year ended December 31, 2014, compared to no deferred tax recorded in 2013 and 2012. As of December 31, 2014, there was $24 million of total unrecognized compensation cost related to unvested equity-based performance units that is expected to be recognized over a weighted-average period of 3 years.
The following table summarizes performance unit activity to be paid out in Company stock for the twelve months ended December 31, 2014 and provides information for unvested units as of December 31, 2014:
		2014
						Weighted
						Average
		Number				Grant Date
		of Units (1)				Fair Value
Unvested shares at January 1		-			$	-
Granted		359				40.44
Vested		-111				40.44
Forfeited		-25				40.44
Unvested shares at December 31		223			$	40.44
(1)      These amounts reflect the number of performance units granted in thousands. The actual payout of shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures.
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 $25 million related to the vested performance units in 2014,  $3 million in 2013, and $19 million in 2012.  As of December 31, 2014 and 2013, the Company’s liability under the performance unit agreements was $51 million and $45 million, respectively.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2014
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 crude oil. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced natural gas volumes and through gathering fees associated with the transportation of natural gas to market.
	Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, and other income (loss). The “Other” column includes items not related to the Company’s reportable segments including real estate and corporate items.
			Exploration
			and			Midstream
			Production			Services		Other		Total
			(in millions)
	2014
	Revenues from external customers		$	2,850		$	1,188	$	–	$	4,038
	Intersegment revenues			12			3,170		–		3,182
	Operating income (loss)			1,013			361		-1		1,373
	Other loss, net			-3			-1		–		-4
	Gain (loss) on derivatives			142			-1		-2		139
	Depreciation, depletion and amortization expense			884			58		–		942
	Interest expense(1)			47			12		–		59
	Provision for income taxes(1)			402			123		–		525
	Assets			13,018	-3		1,554		353		14,925
	Capital investments(4)			7,254			144		49		7,447
	2013
	Revenues from external customers		$	2,398		$	973	$	–	$	3,371
	Intersegment revenues			6			2,374		–		2,380
	Operating income			879			325		–		1,204
	Other income (loss), net			3			–		-1		2
	Gain on derivatives			26			–		–		26
	Depreciation, depletion and amortization expense			735			51		1		787
	Interest expense(1)			30			11		1		42
	Provision (benefit) for income taxes(1)			368			119		-1		486
	Assets			6,357	-3		1,427		264		8,048
	Capital investments(4)			2,052			158		25		2,235
	2012
	Revenues from external customers		$	1,965		$	765	$	–	$	2,730
	Intersegment revenues			-1			1,598		3		1,600
	Operating income (loss)			-1,396	(2)		294		1		-1,101
	Other income (loss), net			-1			–		2		1
	Loss on derivatives			-15			–		–		-15
	Depreciation, depletion and amortization expense			766			44		1		811
	Impairment of natural gas and oil properties			1,940			–		–		1,940
	Interest expense(1)			20			14		1		35
	Provision (benefit) for income taxes(1)			-549			105		1		-443
	Assets			5,194	-3		1,273		271		6,738
	Capital investments(4)			1,861			165		55		2,081
		-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		Includes a $1,940 million non-cash ceiling test impairment of the Company’s natural gas and oil properties.
		-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 an increase of $155 million for 2014 and a decrease of $25 million and $37 million for 2013 and 2012, respectively, related to the change in accrued expenditures between years.
	Included in intersegment revenues of the Midstream Services segment are approximately $2.8 billion, $2.0 billion and $1.3 billion for 2014, 2013 and 2012, respectively, for marketing of the Company’s E&P sales.  Corporate assets include cash and cash equivalents, 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 2014, 2013,  and 2012, capital investments within the E&P segment include $11 million,  $35 million, and $12 respectively, related to the Company’s activities in Canada. As of December 31, 2014,  2013, and 2012, E&P assets include $77 million,  $79 million, $44 million related to the Company’s activities in Canada.

Quarterly_Results_Unaudited

Quarterly Results (Unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Results (Unaudited) [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, 2014 and 2013:
		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
		(in millions, except per share amounts)
		2014
	Operating revenues	$	1,113	$	1,035	$	928	$	962
	Operating income		435		367		286		285
	Net income		194		207		211		312
	Earnings per share - Basic		0.55		0.59		0.60		0.89
	Earnings per share - Diluted		0.55		0.59		0.60		0.88
		2013
	Operating revenues	$	734	$	862	$	868	$	907
	Operating income		252		325		309		317
	Net income		128		246		186		144
	Earnings per share - Basic		0.36		0.70		0.53		0.41
	Earnings per share - Diluted		0.36		0.70		0.53		0.41

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	(16) SUBSEQUENT EVENTS
	On January 21, 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares). Net proceeds from the offerings totaled approximately $2.3 billion after underwriting discounts and offering expenses. The common stock offering was priced at $23.00 per share. Net proceeds, after underwriting discount and expenses, from the common stock offering were approximately $669 million. Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1.7 billion. Each depositary share represents a 1/20th interest in a share of the Company's 6.25% Series B Mandatory Convertible Preferred Stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share). The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364-day bridge term loan facility.
	On January 23, 2015, the Company completed a public offering of $350 million aggregate principal amount of its 3.300% senior notes due 2018 (the “2018 Notes”), $850 million aggregate principal amount of its 4.050% senior notes due 2020 (the “2020 Notes”) and $1 billion aggregate principal amount of its 4.950% senior notes due 2025 (the “2025 Notes” and together with the 2018 Notes and the 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses. The Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and 99.782% of their face value for the 2025 Notes. The proceeds from the offering were used to repay all principal and interest remaining outstanding under the Company’s $4.5 billion 364-day bridge term loan facility and were used to repay a portion of amounts outstanding under the Company’s revolving credit facility.
	On January 27, 2015, the Company closed the Statoil Property Acquisition to purchase certain oil and natural gas assets covering approximately 30,000 acres in West Virginia and southwest Pennsylvania comprising approximately 20% of Statoil’s interests in that acreage for $365 million, after environmental and title adjustments, and subject to customary post-closing adjustments.
	On January 30, 2015, the Company closed the WPX Property Acquisition to purchase approximately 46,700 net acres in northeast Pennsylvania for an adjusted purchase price of $288 million, subject to customary post-closing adjustments.

Organization_And_Summary_Of_Si1

Organization And Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2014
Organization And Summary Of Significant Accounting Policies [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 (“E&P”).  Our current operations are principally focused within the United States on development of two unconventional natural gas reservoirs located in Arkansas and Pennsylvania. The Company’s operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale, and its operations in northeast Pennsylvania are focused on an unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”). Recently, the Company acquired a significant stake in properties located in West Virginia and southwest Pennsylvania which it also intends to develop. These operations in West Virginia are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs (herein referred to as “Southwest Appalachia”). Collectively, the Company’s properties located in West Virginia and Pennsylvania are herein referred to as the “Appalachian Basin.”  To a lesser extent, the Company has exploration and production activities ongoing in Colorado, Louisiana, Texas and in the Arkoma Basin in Arkansas and Oklahoma. The Company also actively seeks to find and develop new natural gas and oil plays with significant exploration and exploitation potential, which it refers to as “New Ventures,” and through acquisitions. The Company also operates drilling rigs in Arkansas and Pennsylvania, as well as in other operating areas, and provide oilfield products and services, principally serving its exploration and production operations. Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Texas, Louisiana, Pennsylvania, and West Virginia.
Basis Of Presentation	The consolidated financial statements included in this Annual Report 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 financial statements to conform to the 2014 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 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 and oil sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas 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. The Company had no significant production imbalances at December 31, 2014 or 2013.
	Marketing. The Company generally markets its natural gas and oil, as well as some products produced by third parties, to brokers, local distribution companies and end-users, pursuant to a variety of contracts. Marketing revenues are recognized when delivery 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.
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 $17 million and $5 million as of December 31, 2014 and 2013, respectively.
Inventory	Inventory is comprised of natural gas in underground storage and tubular and other equipment. Natural gas in underground storage is carried at the lower of cost or market and accounted for by a weighted average cost method. 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.
	The components of inventory as of December 31, 2014 and December 31, 2013 consisted of the following:
			For year ended December 31,
			2014		2013
			(in millions)
	Inventory:
	Natural gas in underground storage	$	4	$	4
	Tubulars and other equipment		33		34
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 reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves 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. Companies utilizing the full cost method 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 $4.35 per MMBtu, West Texas Intermediate oil of $91.48 per barrel and NGLs of $23.79 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, 2014. Cash flow hedges of natural gas production in place increased this ceiling amount by approximately $4 million, net of tax, as of December 31, 2014.  At December 31, 2013, 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 $3.67 per MMBtu, West Texas Intermediate oil of $93.42 per barrel, and NGLs of $43.45 per barrel. 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 and for West Texas Intermediate oil of $91.21. 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 the Company’s natural gas and oil properties exceeded the ceiling by approximately $1,192 million (net of tax) and resulted in a non-cash ceiling test impairment.
	All of the Company’s costs directly associated with the acquisition and evaluation of properties in Canada relating to its exploration program as of December 31, 2014 and as of December 31, 2013 were unproved and did not exceed the ceiling amount.  If the exploration program in Canada is unsuccessful on all or a portion of these properties, including the effects of changes in laws or regulations due to the new government in New Brunswick or otherwise or the Company’s exploration licenses in New Brunswick are not renewed in the first quarter of 2015, 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 Northeast Appalachia 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.  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. 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.
	Impairment of long-lived assets. The carrying values of long-lived assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable.
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. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying Consolidated Statements of Operations. Additional information regarding uncertain tax positions can be found in Note 10 – Income Taxes.
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 option 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 derivatives 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 and have an inconsequential impact in the consolidated statement of operations. Gains and losses from the unsettled 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.  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.
	For the year ended December 31, 2014, outstanding options for 241,603 shares with an average exercise price of $34.03 were included in the calculation of diluted shares. Options for 1,446,004 shares were excluded from the calculation because they would have had an antidilutive effect. For the year ended December 31, 2013, outstanding options for 377,626 shares with an 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 the Company recognized a net loss for the year ended December 31, 2012, the unvested stock options were not recognized in diluted earnings per share 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, 2014, 448,415 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 29,879 shares of restricted stock 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 the Company recognized a net loss for the year ended December 31, 2012, the unvested share-based payments were not recognized in diluted earnings per share 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, 2014, 273,918 shares of performance units were included in the calculation of diluted shares. There were no performance units issued in 2013.
	Supplemental Disclosures of Cash Flow Information
	The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2014, 2013, and 2012.
		For the years ended December 31,
		2014			2013		2012
		(in millions)
	Cash paid during the year for interest, net of amounts capitalized	$	50		$	36	$	17
	Cash paid during the year for income taxes		28			19		1
	Increase (decrease) in noncash property additions		174			-13		-26
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, 2014,  11,055 shares were accounted for as treasury stock, compared to 9,924 shares at December 31, 2013.
Foreign Currency Translation	The Company has 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 Not Yet Implemented in this Report	In April 2014, the FASB issued Accounting Standards Update No. 2014-08 (“Update 2014-08”), which amends FASB Accounting Standards Codification Topic 205, “Presentation of Financial Statements” and Topic 360, “Property, Plant, and Equipment.” Update 2014-08 alters the definition of a discontinued operation to cover only asset disposals that are a strategic shift with a major effect on an entity’s operations and finances, and calls for more extensive disclosures about a discontinued operation’s assets, liabilities, income and expenses. The guidance is effective for all disposals or classifications as held-for sale of components of an entity that occur within annual periods beginning on or after December 15, 2014. The Company has evaluated the provisions of Update 2014-08 and does not expect it to have an impact on its consolidated results of operations, financial position or cash flows.
	In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue. Topic 606 Revenue from Contracts with Customers will supersede the revenue recognition requirement as in Topic 605 Revenue Recognition. Update 2014-09 requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to those goods or services. Entities may apply the amendments in Update 2014-09 either (a) retrospectively to each reporting period presented, and the entity may elect a practical expedient per the update, or (b) retrospectively with the cumulative effect of initially applying Update 2014-09 recognized at the date of initial application – if an entity elects this transition method it also should provide the additional disclosures in reporting periods. For public entities, Update 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of Update 2014-09 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.
	In June 2014, the FASB issued Accounting Standards Update No. 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period (“Update 2014-12”), which clarifies the accounting treatment of such awards in practice. Update 2014-12 requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. Update 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015, and early adoption is permitted. The Company is currently evaluating the provisions of Update 2014-12 and assessing the impact, if any, it may have on its 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, 2014
Organization And Summary Of Significant Accounting Policies [Abstract]
Components Of Inventory
			For year ended December 31,
			2014		2013
			(in millions)
	Inventory:
	Natural gas in underground storage	$	4	$	4
	Tubulars and other equipment		33		34
Schedule Of Supplemental Disclosures Of Cash Flow Information
		For the years ended December 31,
		2014			2013		2012
		(in millions)
	Cash paid during the year for interest, net of amounts capitalized	$	50		$	36	$	17
	Cash paid during the year for income taxes		28			19		1
	Increase (decrease) in noncash property additions		174			-13		-26

Acquisitions_Tables

Acquisitions (Tables) (Chesapeake Property Acquisition [Member])	12 Months Ended
	Dec. 31, 2014
Chesapeake Property Acquisition [Member]
Business Acquisition [Line Items]
Summary Of Consideration Paid And Fair Value Of Assets Acquired And Liabilities Assumed
			For the year ended
			31-Dec-14
	Consideration:		(in millions)
	Cash	$	4,978
	Recognized amounts of identifiable assets acquired and liabilities assumed:
	Assets acquired:
	Proved natural gas and oil properties		1,424
	Unproved natural gas and oil properties		3,605
	Other property and equipment		19
	Inventory		2
	Other receivables		27
	Total assets acquired		5,077
	Liabilities assumed:
	Asset retirement obligations		-42
	Other long term liabilities		-57
	Total liabilities assumed		-99
		$	4,978
Summary Of Consolidated Results Of Operations On Pro Forma Basis
		For the year ended
		December 31,
		2014		2013
		(in millions) (unaudited)
	Revenues	$	4,440	$	3,713
	Net Income		927		684

Prepaid_Expenses_Tables

Prepaid Expenses (Tables)	12 Months Ended
	Dec. 31, 2014
Prepaid Expenses [Abstract]
Components Of Prepaid Expenses
		2014		2013
			(in millions)
	Deposits (1)	$	65	$	–
	Prepaid taxes		18		14
	Prepaid insurance		8		8
	Prepaid drilling costs		1		9
	Total	$	92	$	31
	Deposits consist of a $50 million and $15 million pre-payment related to the Statoil Property Acquisition and WPX Property Acquisition, respectively.

Natural_Gas_And_Oil_Producing_1

Natural Gas And Oil Producing Acitivities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Natural Gas And Oil Producing Activities (Unaudited) [Abstract]
Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure
		2014				2013
		(in millions)
	Proved properties	$	15,860			$	12,337
	Unproved properties		4,646	-1			957	-1
	Total capitalized costs		20,506	-2			13,294
	Less:  Accumulated depreciation, depletion and amortization		8,327				7,481
	Net capitalized costs	$	12,179			$	5,813
		-1		Includes $76 million and $72 million related to the Company’s exploration program in Canada as of December 31, 2014 and 2013, respectively.
		-2		Includes approximately $5.0 billion related to the Chesapeake Property Acquisition.
Schedule Of Capitalized Costs Of Unproved Properties Excluded From Amortization		2014			2013			2012			Prior		Total
		(in millions)
	Property acquisition costs	$	3,892		$	87		$	75		$	142	$	4,196	-1
	Exploration and development costs		239			40			26			61		366	-1
	Capitalized interest		13			10			14			47		84	-1
		$	4,144		$	137		$	115		$	250	$	4,646
		-1		Property acquisition costs include $36 million, exploration costs include $31 million and capitalized interest includes $9 million related to the Company’s exploration program in Canada.
Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities Disclosure		2014				2013				2012
		(in millions, except per Mcfe amounts)
	Proved property acquisition costs	$	1,455			$	1			$	–
	Unproved property acquisition costs (1)		3,934				168				221
	Exploration costs(2)		232				192				197
	Development costs		1,600				1,662				1,493
	Capitalized costs incurred		7,221				2,023				1,911
	Full cost pool amortization per Mcfe	$	1.10			$	1.08			$	1.31
		-1		Includes $1 million, $17 million and $4 million, in 2014, 2013 and 2012, respectively, related to the Company’s exploration program in Canada.
		-2		Includes $3 million, $12 million and $3 million in 2014, 2013 and 2012, respectively, related to the Company’s exploration program in Canada.
Results Of Operations For Oil And Gas Producing Activities Disclosure
		2014			2013			2012
		(in millions)
	Sales	$	2,862		$	2,404		$	1,963
	Production (lifting) costs		-776			-629			-505
	Depreciation, depletion and amortization		-884			-735			-765
	Impairment of natural gas and oil properties		–			–			-1,940
			1,202			1,040			-1,247
	Provision (benefit) for income taxes		457			416			-497
	Results of operations (1)	$	745		$	624		$	-750
		-1		Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments.  See Note 5 Derivatives and Risk Management.
Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities
		2014						2013					2012
		Natural						Natural					Natural
		Gas		Oil		NGL		Gas		Oil		NGL	Gas		Oil	NGL
		(Bcf)		(MBbls)		(MBbls)		(Bcf)		(MBbls)		(MBbls)	(Bcf)		(MBbls)	(MBbls)
	Proved reserves, beginning of year	6,974		373		–		4,017		244		–	5,887		996	–
	Revisions of previous estimates	542		-14		66		325		38		50	-2,088		-44	–
	Extensions, discoveries and other additions	1,691		250		48		3,283		229		–	918		154	–
	Production	-765		-235		-231		-655		-138		-50	-564		-83	–
	Acquisition of reserves in place	1,367		37,246		118,816		4		–		–	–		–	–
	Disposition of reserves in place	–		-5		–		–		–		–	-136		-779	–
	Proved reserves, end of year	9,809		37,615		118,699		6,974		373		–	4,017		244	–
	Proved developed reserves:
	Beginning of year	4,237		372		–		3,196		243		–	3,254		983	–
	End of year	5,675		7,445		38,632		4,237		372		–	3,196		243	–
	Proved undeveloped reserves:
	Beginning of year	2,737		1		–		821		1		–	2,633		13	–
	End of year	4,134		30,170		80,067		2,737		1		–	821		1	–
Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure
		2014			2013			2012
		(in millions)
	Future cash inflows	$	41,812		$	22,624		$	9,570
	Future production costs		-16,477			-8,896			-4,737
	Future development costs		-5,750			-3,626			-711
	Future income tax expense		-4,743			-3,223			-745
	Future net cash flows		14,842			6,879			3,377
	10% annual discount for estimated timing of cash flows		-7,299			-3,143			-1,326
	Standardized measure of discounted future net cash flows	$	7,543		$	3,736		$	2,051
Schedule Of Analysis Of Changes In Standardized Measure
		2014			2013			2012
		(in millions)
	Standardized measure, beginning of year	$	3,736		$	2,051		$	3,451
	Sales and transfers of natural gas and oil produced, net of production costs		-2,084			-1,774			-1,444
	Net changes in prices and production costs		1,192			1,853			-2,605
	Extensions, discoveries, and other additions, net of future production and development costs		1,049			1,454			550
	Acquisition of reserves in place		1,897			5			–
	Sales of reserves in place		–			–			-157
	Revisions of previous quantity estimates		622			349			-1,109
	Accretion of discount		513			232			480
	Net change in income taxes		-522			-1,120			1,079
	Changes in estimated future development costs		110			-196			2,476
	Previously estimated development costs incurred during the year		815			223			62
	Changes in production rates (timing) and other		215			659			-732
	Standardized measure, end of year	$	7,543		$	3,736		$	2,051

Derivatives_And_Risk_Managemen1

Derivatives And Risk Management (Tables)	12 Months Ended
	Dec. 31, 2014
Derivatives And Risk Management [Abstract]
Balance Sheet Classification Of Derivative Financial Instruments
			Derivative Assets
			31-Dec-14						31-Dec-13
			Balance Sheet Classification		Fair Value				Balance Sheet Classification	Fair Value
			(in millions)
	Derivatives designated as hedging instruments:
	Fixed price swaps		Derivative assets			$	165		Derivative assets	$	21
	Total derivatives designated as hedging instruments					$	165			$	21
	Derivatives not designated as hedging instruments:
	Basis swaps		Derivative assets			$	9		Derivative assets	$	13
	Fixed price swaps		Derivative assets				163		Derivative assets		37
	Basis swaps		Other long-term assets				1		Other long-term assets		–
	Interest rate swaps		Other long-term assets				1		Other long-term assets		8
	Total derivatives not designated as hedging instruments					$	174			$	58
	Total derivative assets					$	339			$	79
			Derivative Liabilities
			31-Dec-14						31-Dec-13
			Balance Sheet Classification			Fair Value			Balance Sheet Classification	Fair Value
			(in millions)
	Derivatives designated as hedging instruments:
	Fixed price swaps		Derivative liabilities			$	–		Derivative liabilities	$	4
	Total derivatives designated as hedging instruments					$	–			$	4
	Derivatives not designated as hedging instruments:
	Basis swaps		Derivative liabilities			$	4		Derivative liabilities	$	1
	Fixed price call options		Derivative liabilities				2		Derivative liabilities		–
	Interest rate swaps		Derivative liabilities				3		Derivative liabilities		2
	Fixed price call options		Other long-term liabilities				10		Other long-term liabilities		31
	Basis swaps		Other long-term liabilities				2		Other long-term liabilities		–
	Interest rate swaps		Other long-term liabilities				2		Other long-term liabilities		3
	Total derivatives not designated as hedging instruments					$	23			$	37
	Total derivative liabilities					$	23			$	41
Schedule Of Derivative Instruments, Volumes Of Natural Gas Production
	Year	Fixed price swaps designated for	Fixed price swaps not designated for	Total	Weighted Average Price to be Swapped ($/MMBtu) (1)
		hedge accounting	hedge accounting
	2015	120	120	240	$4.40
	(1)    The weighted average price to be swapped is $4.40 for each category and in total.
Summary Of Before Tax Effect Of Cash Flow Hedges On Consolidated Financial Statements
						Gain Recognized in Other Comprehensive Income
						(Effective Portion)
					For the years ended
					December 31,
	Derivative Instrument				2014			2013
					(in millions)
	Fixed price swaps				$	122		$	38
			Classification of Gain  (Loss)		Gain (Loss) 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)		2014			2013
					(in millions)
	Fixed price swaps		Gas Sales		$	-26		$	309
Summary Of Before Tax Effect Of Fair Value Hedges Not Designated For Hedge Accounting
					Gain (Loss) on Derivatives,
					Excluding Derivatives, Settled
					Recognized in Earnings
			Consolidated Statement of Operations		For the years ended
			Classification of Gain (Loss) on		December 31,
	Derivative Instrument		Derivatives, Net of Settlement		2014			2013
					(in millions)
	Basis swaps		Gain (Loss) on Derivatives		$	-7		$	7
	Fixed price call options		Gain (Loss) on Derivatives			18			-26
	Fixed price swaps		Gain (Loss) on Derivatives			126			37
	Interest rate swaps		Gain (Loss) on Derivatives			-7			3
					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)		2014			2013
					(in millions)
	Basis swaps		Gain (Loss) on Derivatives		$	12		$	5
	Fixed price swaps		Gain (Loss) on Derivatives			-2			–
	Interest rate swaps		Gain (Loss) on Derivatives			-1			–
		-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_Accumula1

Reclassification From Accumulated Other Comprehensiv Income (Tables)	12 Months Ended
	Dec. 31, 2014
Reclassification From Accumulated Other Comprehensive Income [Abstract]
Components Of Accumulated Other Comprehensive Income (Loss)
			For the year ended
			31-Dec-14
			Gains (Losses) on Cash Flow Hedges			Pension and Other Postretirement		Foreign Currency		Total
			(in millions) (1)
	Beginning balance, December 31, 2013		$	9		$	-9	$	-4	$	-4
	Other comprehensive income (loss) before reclassifications			73			–		-8		65
	Amounts reclassified from/to other comprehensive income (2)			16			-15		–		1
	Net current-period other comprehensive income (loss)			89			-15		-8		66
	Ending balance, December 31, 2014		$	98		$	-24	$	-12	$	62
		-1		All amounts are net of tax.
		-2		See separate table below for details about these reclassifications.
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)
	Details about Accumulated Other Comprehensive Income		Affected Line Item in the Consolidated Statement of Operations		Amount Reclassified from/to Accumulated Other Comprehensive Income
					For the year ended December 31, 2014
					(in millions)
	Gains (losses) to Other Comprehensive Income on cash flow hedges
	Settlements		Gas sales	$	26
	Ineffectiveness		Gas sales		–
			Gain before income taxes		26
			Less: Provision for income taxes		10
			Net Gain	$	16
	Pension and other postretirement (1)
	Net actuarial loss(2)			$	-25
			Loss before income taxes		-25
			Less: Benefit for income taxes		-10
			Net Loss	$	-15
	Total reclassifications for the period		Net Gain	$	1
		-1		See Note 12 for additional details regarding the Company’s retirement and employee benefit plans.
		-2		Net actuarial loss had no impact on the consolidated statement of operations.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements [Abstract]
Carrying Amount And Estimated Fair Values Of Financial Instruments
		31-Dec-14						31-Dec-13
		Carrying			Fair			Carrying			Fair
		Amount			Value			Amount			Value
		(in millions)
	Cash and cash equivalents	$	53		$	53		$	23		$	23
	Credit facility	$	300		$	300		$	283		$	283
	Term loan facility	$	500		$	500		$	–		$	–
	Bridge facility	$	4,500		$	4,500		$	–		$	–
	Senior notes	$	1,667		$	1,751		$	1,668		$	1,796
	Derivative instruments, net	$	316		$	316		$	38		$	38
Summary Assets And Liabilities Measured At Fair Value On Recurring Basis
			31-Dec-14
			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		$	–		$	329		$	10		$	339
	Derivative liabilities			–			-5			-18			-23
	Total		$	–		$	324		$	-8		$	316
			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		$	–		$	66		$	13		$	79
	Derivative liabilities			–			-9			-32			-41
	Total		$	–		$	57		$	-19		$	38
Reconciliations For 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,
			2014			2013
			(in millions)
	Balance at beginning of period		$	-19		$	–
	Total gains (losses):
	Included in earnings			23			-14
	Included in other comprehensive income			–			–
	Purchases, issuances, and settlements:
	Purchases			–			–
	Issuances			–			–
	Settlements			-12			-5
	Transfers into/out of Level 3			–			–
	Balance at end of period		$	-8		$	-19
	Change in gains (losses) included in earnings relating to derivatives still held as of December 31		$	11		$	-19

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt [Abstract]
Components Of Debt
			2014		2013
			(in millions)
	Short-term debt:
	7.15% Senior Notes due 2018		$	1	$	1
	Variable rate (1.515% at December 31, 2014) bridge facility, due December 2015			4,500		–
	Total short-term debt			4,501		1
	Long-term debt:
	Variable rate (1.515%  and 1.640% at December 31, 2014 and December 31, 2013, respectively) credit facility, expires December 2018			300		283
	Variable rate (1.545% at December 31, 2014) term loan facility, due December 2016			500		–
	7.35% Senior Notes due 2017			15		15
	7.125% Senior Notes due 2017			25		25
	7.15% Senior Notes due 2018			27		28
	7.5% Senior Notes due 2018			600		600
	4.10% Senior Notes due 2022			1,000		1,000
	Unamortized discount			-1		-1
	Total long-term debt			2,466		1,950
	Total debt		$	6,967	$	1,951
Schedule Of Long Term Debt Maturities
	2016		501
	2017		41
	2018		925
	Thereafter		1,000
		$	2,467

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes [Abstract]
Provision (Benefit) For Income Taxes
			2014		2013		2012
		(in millions)
	Current:
	Federal	$	11	$	-12	$	16
	State		10		1		3
			21		-11		19
	Deferred:
	Federal		501		408		-388
	State		2		88		-72
	Foreign		1		1		-2
			504		497		-462
	Provision (benefit) for income taxes	$	525	$	486	$	-443
Reconciliation Of Provision For Income Taxes
			2014		2013		2012
		(in millions)
	Expected provision (benefit) at federal statutory rate	$	507	$	417	$	-403
	Increase (decrease) resulting from:
	State income taxes, net of federal income tax effect		58		53		-44
	Nondeductible expenses		3		3		2
	State rate redetermination		-48		4		2
	Other		5		9		–
	Provision (benefit) for income taxes	$	525	$	486	$	-443
Schedule Of Deferred Tax Assets And Liabilities
			2014		2013
		(in millions)
	Deferred tax liabilities:
	Differences between book and tax basis of property	$	2,504	$	2,115
	Derivative activity		122		13
	Other		21		11
			2,647		2,139
	Deferred tax assets:
	Accrued compensation		23		16
	Alternative minimum tax credit carryforward		131		77
	Stored natural gas		5		9
	Accrued pension costs		17		2
	Asset retirement obligations		79		54
	Net operating loss carryforward		318		412
	Differences between book and tax basis of property - state		6		11
	Other		8		7
			587		588
	Net deferred tax liability	$	2,060	$	1,551
Reconciliation Of Beginning And Ending Balances Of Unrecognized Tax Benefits
			2014
			(in millions)
	Unrecognized tax benefits at beginning of period	$	-
	Additions based on tax positions related to the current year		15
	Additions to tax positions of prior years		29
	Settlements		-
	Unrecognized tax benefits at end of period	$	44

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Schedule Of Asset Retirement Obligations
			2014			2013
			(in millions)
	Asset retirement obligation at January 1		$	134		$	101
	Accretion of discount			7			6
	Obligations incurred			64	-1		22
	Obligations settled/removed			-4			-2
	Revisions of estimates			6			7
	Asset retirement obligation at December 31		$	207		$	134
	Current liability			9			6
	Long-term liability			198			128
	Asset retirement obligation at December 31		$	207		$	134
		-1		Obligations incurred include $42 million related to the Chesapeake Property Acquisition.

Retirement_And_Employee_Benefi1

Retirement And Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Retirement And Employee Benefit Plans [Abstract]
Changes In Plans Benefit Obligations, Fair Value Of Assets, And Funded Status
								Other Postretirement
		Pension Benefits						Benefits
			2014			2013			2014		2013
		(in millions)
	Change in benefit obligations:
	Benefit obligation at January 1	$	103		$	105		$	12	$	12
	Service cost		13			14			2		2
	Interest cost		5			4			1		–
	Participant contributions		–			–			–		–
	Actuarial loss		21			-11			3		-2
	Benefits paid		-8			-8			–		–
	Plan amendments		–			–			–		–
	Settlements		–			-1			–		–
	Benefit obligation at December 31	$	134		$	103		$	18	$	12
								Other Postretirement
		Pension Benefits						Benefits
			2014			2013			2014		2013
		(in millions)
	Change in plan assets:
	Fair value of plan assets at January 1	$	99		$	83		$	–	$	–
	Actual return on plan assets		5			12			–		–
	Employer contributions		12			13			–		–
	Participant contributions		–			–			–		–
	Benefits paid		-8			-8			–		–
	Settlements		–			-1			–		–
	Fair value of plan assets at December 31	$	108		$	99		$	–	$	–
	Funded status of plans at December 31	$	-26		$	-4		$	-18	$	-12
Projected Benefit Obligation, Accumulated Benefit Obligation, And Fair Value Of Plan Assets
			2014			2013
			(in millions)
	Projected benefit obligation	$	134		$	103
	Accumulated benefit obligation	$	129		$	100
	Fair value of plan assets	$	108		$	99
Pension And Other Postretirement Benefit Costs
											Other Postretirement
			Pension Benefits								Benefits
			2014			2013			2012		2014		2013		2012
			(in millions)
	Service cost	$	13		$	14		$	11	$	2	$	2	$	2
	Interest cost		5			4			4		1		1		–
	Expected return on plan assets		-7			-6			-5		–		–		–
	Amortization of transition obligation		–			–			–		–		–		–
	Amortization of prior service cost		–			–			–		–		–		–
	Amortization of net loss		1			2			1		–		–		–
	Net periodic benefit cost		12			14			11		3		3		2
	Settlements and curtailments		–			0			–		–		–		–
	Total benefit cost	$	12		$	14		$	11	$	3	$	3	$	2
Amounts Recognized In Other Comprehensive Income
				Pension Benefits			Other Postretirement Benefits
				(in millions)
	Net actuarial loss arising during the year		$	-23		$	-2
	Amortization of prior service cost			–			–
	Amortization of net loss			–			–
	Settlements			–			–
	Tax effect			9			1
			$	-14		$	-1
Schedule Of Assumptions Used	The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2014 and 2013 are as follows:
		Pension Benefits						Other Postretirement
								Benefits
		2014			2013			2014		2013
	Discount rate	4.25	%		5.00	%		4.25	%	5.00	%
	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 2014, 2013 and 2012 are as follows:
		Pension Benefits								Other Postretirement
										Benefits
		2014			2013			2012		2014		2013		2012
	Discount rate	5.00	%		4.00	%		5.00	%	5.00	%	4.00	%	5.00	%
	Expected return on plan assets	7.00	%		7.00	%		7.50	%	n/a		n/a		n/a
	Rate of compensation increase	4.50	%		4.50	%		4.50	%	n/a		n/a		n/a
Schedule Of Health Care Cost Trend Rates
		2014			2013
	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	2033			2032
One Percentage Point Change In Assumed Health Care Cost Trend Rates
			1%			1%
			Increase			Decrease
		(in millions)
	Effect on the total service and interest cost components	$	–		$	–
	Effect on postretirement benefit obligations	$	3		$	-2
Schedule Of Expected Benefit Payments
	Pension Benefits				Other Postretirement Benefits
	(in millions)
	2015	$	6		2015	$	1
	2016	$	8		2016	$	1
	2017	$	8		2017	$	1
	2018	$	10		2018	$	1
	2019	$	11		Years 2019-2023	$	9
	Years 2020-2024	$	65
Schedule Of Allocation Of Plan Assets
		Pension Plan Asset
		Allocations
	Asset category:	Target			Actual
	Equity securities:
	U.S. Equity(1)	35	%		36	%
	Non-U.S. Developed Equity(2)	30	%		27	%
	Emerging Markets Equity(3)	5	%		5	%
	Opportunistic(4)	–	%		–	%
	Fixed income(5)	29	%		29	%
	Cash(6)	1	%		3	%
	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 millions)
	Equity securities:
	U.S. large cap growth equity(1)	$	8		$	8		$	–	$	–
	U.S. large cap value equity(2)		9			9			–		–
	U.S. large cap core equity(3)		19			–			19		–
	U.S. small cap equity(4)		3			3			–		–
	Non-U.S. equity(5)		29			29			–		–
	Emerging markets equity(6)		5			5			–		–
	Fixed income (7)		31			–			31		–
	Cash and cash equivalents		4			4			–		–
	Total	$	108		$	58		$	50	$	–
	(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 the fair value hierarchy described in Note 7 – Fair Value Measurements, the Company’s fair value measurement of pension plan assets at 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 millions)
	Equity securities:
	U.S. large cap growth equity(1)	$	8		$	8		$	–	$	–
	U.S. large cap value equity(2)		8			8			–		–
	U.S. large cap core equity(3)		16			–			16		–
	U.S. small cap equity(4)		3			3			–		–
	Non-U.S. equity(5)		31			31			–		–
	Emerging markets equity(6)		6			–			6		–
	Fixed income (7)		26			–			26		–
	Cash and cash equivalents		1			1			–		–
	Total	$	99		$	51		$	48	$	–
	(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, 2014
Schedule Of Valuation Assumptions
	Assumptions	2014		2013		2012
	Risk-free interest rate	1.6%		1.5%		0.6%
	Expected dividend yield	–		–		–
	Expected volatility	32.5%		38.6%		58.2%
	Expected term	5 years		5 years		5 years
Summary Of Stock Option Activity
			2014					2013						2012
						Weighted						Weighted				Weighted
						Average						Average				Average
			Number			Exercise		Number				Exercise		Number		Exercise
			of Shares			Price		of Shares				Price		of Shares		Price
			(in thousands)					(in thousands)						(in thousands)
	Options outstanding at January 1		3,313		$	35.70		3,650			$	29.84		4,743	$	21.24
	Granted		835			32.31		571				38.95		613		34.34
	Exercised		-402			30.60		-833				12.12		-1,608		5.71
	Forfeited or expired		-124			37.80		-75				37.31		-98		37.76
	Options outstanding at December 31		3,622		$	35.41		3,313			$	35.70		3,650	$	29.84
Summary Of Stock Options Outstanding
			Options Outstanding								Options Exercisable
								Weighted							Weighted
								Average							Average
			Options			Weighted		Remaining			Options			Weighted	Remaining
			Outstanding at			Average		Contractual			Exercisable at			Average	Contractual
	Range of		December 31,			Exercise		Life			December 31,			Exercise	Life
	Exercise Prices		2014			Price		(Years)			2014			Price	(Years)
			(in thousands)								(in thousands)
	$27.09-$29.69		21			28.42		2.9			17			28.53	2.5
	$30.23-$35.91		1,744			32.04		4.9			819			32.83	3.1
	$36.22-$39.91		1,443			37.52		4.3			1,117			37.10	3.9
	$40.15-$51.47		414			42.64		2.9			324			41.56	1.9
			3,622		$	35.41		4.4		$	2,277		$	36.13	3.3
Summary Of Restricted Stock Activity
			2014					2013							2012
						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
			(in thousands)					(in thousands)								(in thousands)
	Unvested shares at January 1		1,771		$	37.55		1,118			$		35.64			1,020	$	36.71
	Granted		1,295			30.89		1,109					38.92			537		34.39
	Vested		-548			37.12		-382					36.29			-344		36.50
	Forfeited		-142			37.91		-74					35.81			-95		36.97
	Unvested shares at December 31		2,376		$	34.00		1,771			$		37.55			1,118	$	35.64
Stock Options [Member]
Schedule Of Stock-Based Compensation Costs
		2014			2013			2012
			(in millions)
	Stock-based compensation cost related to stock options – general and administrative expense	$	5		$	5		$	5
	Stock-based compensation cost related to stock options – capitalized	$	4		$	5		$	4
Restricted Stock [Member]
Schedule Of Stock-Based Compensation Costs
			2014			2013			2012
			(in millions)
	Stock-based compensation cost related to restricted stock grants	$	10		$	7		$	6
	– general and administrative expense
	Stock-based compensation cost related to restricted stock grants	$	12		$	7		$	6
	– capitalized
Equity-Classified Performance Units [Member]
Schedule Of Stock-Based Compensation Costs
			2014
			(millions)
	Stock-based compensation cost related to performance units - general and administrative expense	$	3
	Stock-based compensation cost related to performance units - capitalized	$	2
Summary Of Equity-Classified Performance Units Activity
			2014
							Weighted
							Average
			Number				Grant Date
			of Units (1)				Fair Value
	Unvested shares at January 1		-			$	-
	Granted		359				40.44
	Vested		-111				40.44
	Forfeited		-25				40.44
	Unvested shares at December 31		223			$	40.44
	(1)      These amounts reflect the number of performance units granted in thousands. The actual payout of shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures.

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Information [Abstract]
Summary Financial Information For Company's Reportable Segments
			Exploration
			and			Midstream
			Production			Services		Other		Total
			(in millions)
	2014
	Revenues from external customers		$	2,850		$	1,188	$	–	$	4,038
	Intersegment revenues			12			3,170		–		3,182
	Operating income (loss)			1,013			361		-1		1,373
	Other loss, net			-3			-1		–		-4
	Gain (loss) on derivatives			142			-1		-2		139
	Depreciation, depletion and amortization expense			884			58		–		942
	Interest expense(1)			47			12		–		59
	Provision for income taxes(1)			402			123		–		525
	Assets			13,018	-3		1,554		353		14,925
	Capital investments(4)			7,254			144		49		7,447
	2013
	Revenues from external customers		$	2,398		$	973	$	–	$	3,371
	Intersegment revenues			6			2,374		–		2,380
	Operating income			879			325		–		1,204
	Other income (loss), net			3			–		-1		2
	Gain on derivatives			26			–		–		26
	Depreciation, depletion and amortization expense			735			51		1		787
	Interest expense(1)			30			11		1		42
	Provision (benefit) for income taxes(1)			368			119		-1		486
	Assets			6,357	-3		1,427		264		8,048
	Capital investments(4)			2,052			158		25		2,235
	2012
	Revenues from external customers		$	1,965		$	765	$	–	$	2,730
	Intersegment revenues			-1			1,598		3		1,600
	Operating income (loss)			-1,396	(2)		294		1		-1,101
	Other income (loss), net			-1			–		2		1
	Loss on derivatives			-15			–		–		-15
	Depreciation, depletion and amortization expense			766			44		1		811
	Impairment of natural gas and oil properties			1,940			–		–		1,940
	Interest expense(1)			20			14		1		35
	Provision (benefit) for income taxes(1)			-549			105		1		-443
	Assets			5,194	-3		1,273		271		6,738
	Capital investments(4)			1,861			165		55		2,081
		-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		Includes a $1,940 million non-cash ceiling test impairment of the Company’s natural gas and oil properties.
		-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 an increase of $155 million for 2014 and a decrease of $25 million and $37 million for 2013 and 2012, respectively, related to the change in accrued expenditures between years.

Quarterly_Results_Unaudited_Ta

Quarterly Results (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Results (Unaudited) [Abstract]
Schedule Of Quarterly Financial Information
		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
		(in millions, except per share amounts)
		2014
	Operating revenues	$	1,113	$	1,035	$	928	$	962
	Operating income		435		367		286		285
	Net income		194		207		211		312
	Earnings per share - Basic		0.55		0.59		0.60		0.89
	Earnings per share - Diluted		0.55		0.59		0.60		0.88
		2013
	Operating revenues	$	734	$	862	$	868	$	907
	Operating income		252		325		309		317
	Net income		128		246		186		144
	Earnings per share - Basic		0.36		0.70		0.53		0.41
	Earnings per share - Diluted		0.36		0.70		0.53		0.41

Organization_And_Summary_Of_Si3

Organization And Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Outstanding checks included in accounts payable	$17	$5
Natural gas and oil reserves discount	10.00%
Period of time needed to calculate ceiling value of reserves	12 months	12 months	12 months
Cash flow hedges impact on ceiling value, net of tax	4
Net capitalized costs exceeding ceiling			$1,192
Amount recognized is the largest amount of tax benefit, threshold	50.00%
Treasury stock, shares	11,055	9,924
NGL [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Full cost ceiling test, price	23.79	43.45
Henry Hub Natural Gas [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Full cost ceiling test, price	4.35	3.67	2.76
West Texas Intermediate Oil [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Full cost ceiling test, price	91.48	93.42	91.21
Stock Options [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of common shares, Issued upon assumed exercise of outstanding stock options	241,603	377,626
Outstanding options average exercise price	$34.03	$28.03
Antidilutive securities excluded from computation of earnings per share, shares	1,446,004	1,634,695	1,716,109
Restricted Stock [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of common shares, Issued upon assumed exercise of outstanding stock options	448,415	258,396
Antidilutive securities excluded from computation of earnings per share, shares	29,879	114,433	602,429
Performance Units [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of common shares, Effect of issuance of nonvested shares	273,918	0
Gathering Systems [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Straight-line depreciation period	25 years

Organization_And_Summary_Of_Si4

Organization And Summary Of Significant Accounting Policies (Components Of Inventory) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Organization And Summary Of Significant Accounting Policies [Abstract]
Natural gas in underground storage	$4	$4
Tubulars and other equipment	$33	$34

Organization_And_Summary_Of_Si5

Organization And Summary Of Significant Accounting Policies (Schedule Of Supplemental Disclosures Of Cash Flow Information) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Organization And Summary Of Significant Accounting Policies [Abstract]
Cash paid during the year for interest, net of amounts capitalized	$50	$36	$17
Cash paid during the year for income taxes	28	19	1
Increase (decrease) in noncash property additions	$174	($13)	($26)

Acquisitions_Narrative_Details

Acquisitions (Narrative) (Details) (USD $)	3 Months Ended								12 Months Ended			1 Months Ended			0 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Apr. 30, 2013	Jan. 31, 2015	Jan. 23, 2015	Dec. 19, 2014
					acre					acre		acre
Business Acquisition [Line Items]
Area of land purchased					26					26
General and administrative expenses									$221,000,000	$191,000,000	$175,000,000
Interest expense									59,000,000	42,000,000	35,000,000
Other current assets	158,000,000				48,000,000				158,000,000	48,000,000		158,000,000
Revenues	962,000,000	928,000,000	1,035,000,000	1,113,000,000	907,000,000	868,000,000	862,000,000	734,000,000	4,038,000,000	3,371,000,000	2,730,000,000
Operating income (loss)	285,000,000	286,000,000	367,000,000	435,000,000	317,000,000	309,000,000	325,000,000	252,000,000	1,373,000,000	1,204,000,000	-1,101,000,000
Cost to acquire property									5,298,000,000	96,000,000
Bridge Loan [Member]
Business Acquisition [Line Items]
Bridge loan	4,500,000,000								4,500,000,000			4,500,000,000				4,500,000,000
Debt instrument, term									364 days
Unsecured Debt [Member] | Term Loan [Member]
Business Acquisition [Line Items]
Loans payable	500,000,000								500,000,000			500,000,000				500,000,000
Debt instrument, term									2 years
Chesapeake Property Acquisition [Member]
Business Acquisition [Line Items]
Date of acquisition									22-Dec-14
Area of land purchased	413,000								413,000			413,000
Cash consideration									4,978,000,000
Assets acquired and liabilities assumed estimated fair value	4,978,000,000								4,978,000,000			4,978,000,000
General and administrative expenses									1,000,000
Interest expense									5,000,000
Other current assets	47,000,000								47,000,000			47,000,000
Unamortized fees	1,000,000								1,000,000			1,000,000
Revenues									10,000,000
Operating income (loss)									2,000,000
Statoil Property Acquisition [Member]
Business Acquisition [Line Items]
Area of land purchased	30,000								30,000			30,000
Percentage of interest acquired	20.00%								20.00%			20.00%
Cost to acquire property												365,000,000
WPX Property Acquisition [Member]
Business Acquisition [Line Items]
Area of land purchased	46,700								46,700			46,700
Cost to acquire property									300,000,000
Net production per day of acreage sold in MMcf	50								50			50
Number of horizontal wells operated by SEECO in Arkansas									63
Firm transportation capacity acquired	260								260			260
Niobrara Formation In Colorado [Member]
Business Acquisition [Line Items]
Area of land purchased	380,000								380,000			380,000
Cost to acquire natural gas properties through definitive purchase agreement									215,000,000
Marcellus Shale In Pennsylvania [Member]
Business Acquisition [Line Items]
Cost to acquire natural gas properties through definitive purchase agreement													82,000,000
Subsequent Event [Member]
Business Acquisition [Line Items]
Debt issuance expense														47,000,000
Subsequent Event [Member] | Bridge Loan [Member]
Business Acquisition [Line Items]
Repayment of debt														$4,500,000,000	$4,500,000,000

Acquisitions_Summary_Of_Consid

Acquisitions (Summary Of Consideration Paid And Fair Value Of Assets Acquired And Liabilities Assumed) (Details) (Chesapeake Property Acquisition [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Chesapeake Property Acquisition [Member]
Business Acquisition [Line Items]
Cash	$4,978
Proved natural gas and oil properties	1,424
Unproved natural gas and oil properties	3,605
Other property and equipment	19
Inventory	2
Other receivables	27
Total assets acquired	5,077
Asset retirement obligations	-42
Other long-term liabilities	-57
Total liabilities assumed	-99
Total assets acquired and liabilities assumed	$4,978

Acquisitions_Summary_Of_Consol

Acquisitions (Summary Of Consolidated Results Of Operations On Pro Forma Basis) (Details) (Chesapeake Property Acquisition [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Chesapeake Property Acquisition [Member]
Business Acquisition [Line Items]
Revenues	$4,440	$3,713
Net Income	$927	$684

Prepaid_Expenses_Details

Prepaid Expenses (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Prepaid Expenses [Line Items]
Deposits	$65
Prepaid taxes	18	14
Prepaid insurance	8	8
Prepaid drilling costs	1	9
Total	92	31
Statoil Property Acquisition [Member]
Prepaid Expenses [Line Items]
Deposits	50
WPX Property Acquisition [Member]
Prepaid Expenses [Line Items]
Deposits	$15

Natural_Gas_And_Oil_Producing_2

Natural Gas And Oil Producing Activities (Unaudited) (Narrative) (Details) (USD $)	12 Months Ended				96 Months Ended	132 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2014
	ft3	ft3	ft3	ft3
	acre	acre
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Discount rate of natural gas and oil reserves	10.00%
Net unevaluated costs excluded from amortization	$4,144	$137	$115		$250	$4,646
Percentage of present worth of proved reserves evaluated in audit	97.00%	95.00%	93.00%
Capitalized interest based on weighted average cost of borrowings	55	62	62
Capitalized internal costs related to acquisition, exploration and development	320	264	237
Capitalized internal costs related to acquisition, exploration and development activities - subsidiaries	123	103	82
Area of land purchased		26
Production	768,000,000,000	657,000,000,000	565,000,000,000	500,000,000,000
Production volumes replaced with proved reserve additions, percentage	591.00%	550.00%				591.00%
Additions	1,693,000,000,000	3,285,000,000,000	920,000,000,000
Revisions		326,000,000,000
Period of time needed to calculate ceiling value of reserves	12 months	12 months	12 months
Performance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions			-336,000,000,000
Decrease Natural Gas Price [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions			-2,088,000,000,000
Seismic Costs Fayetteville Shale Play [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net unevaluated costs excluded from amortization	12
Undeveloped Properties Fayetteville Shale [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net unevaluated costs excluded from amortization	34
Additions	573,000,000,000	1,530,000,000,000	32,000,000,000
Undeveloped Properties Marcellus Shale [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net unevaluated costs excluded from amortization	138
Undeveloped Properties New Ventures - Excluding Canada [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net unevaluated costs excluded from amortization	367
Exploration Program in Canada [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net unevaluated costs excluded from amortization	76
Wells In Progress [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net unevaluated costs excluded from amortization	267
Northeast Appalachia [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net increase (decrease) in production	103,000,000,000	97,000,000,000	30,000,000,000			103,000,000,000
Additions		4,000,000,000
Northeast Appalachia [Member] | Higher Gas Prices [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions	10,000,000,000	35,000,000,000
Northeast Appalachia [Member] | Performance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions	636,000,000,000	62,000,000,000	36,000,000,000
Northeast Appalachia [Member] | Lower Gas Prices [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions			-9,000,000,000
Southwest Appalachia [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net increase (decrease) in production	3,000,000,000					3,000,000,000
Additions	2,304,000,000,000
Revisions	543,000,000,000
Fayetteville Shale [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net increase (decrease) in production	8,000,000,000	1,000,000,000	49,000,000,000			8,000,000,000
Fayetteville Shale [Member] | Higher Gas Prices [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions	38,000,000,000	191,000,000,000
Fayetteville Shale [Member] | Performance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions	-126,000,000,000	16,000,000,000	-362,000,000,000
Fayetteville Shale [Member] | Lower Gas Prices [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions			-1,684,000,000,000
East Texas and Arkoma Basin [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net increase (decrease) in production	-3,000,000,000	-7,000,000,000	-14,000,000,000			-3,000,000,000
Developed Properties Fayetteville Shale [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Additions	283,000,000,000	557,000,000,000	383,000,000,000
Developed Properties Northeast Appalachia [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Additions	246,000,000,000	386,000,000,000	195,000,000,000
Developed Properties Brown Dense [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Additions	2,000,000,000	2,000,000,000
Undeveloped Properties Northeast Appalachia [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Additions	589,000,000,000	810,000,000,000	305,000,000,000
Ark-La-Tex [Member] | Higher Gas Prices [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions	6,000,000,000	21,000,000,000
Ark-La-Tex [Member] | Performance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions	-21,000,000,000		-10,000,000,000
Ark-La-Tex [Member] | Lower Gas Prices [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions			-59,000,000,000
Undeveloped Properties, Various Locations [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Discount rate of natural gas and oil reserves	10.00%	10.00%	10.00%
Proved undeveloped reserves	181,000,000,000	662,000,000,000	355,000,000,000			181,000,000,000
Number of locations	60	268	198			60
Present value of proved reserves, discounted basis	-28	-97	-71			-28
New Ventures [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net increase (decrease) in production		1,000,000,000
New Ventures [Member] | Performance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Revisions		1,000,000,000
Developed Properties Ark-La-Tex [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Additions			3,000,000,000
Developed Properties New Ventures [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Additions			2,000,000,000
Overton Field in East Texas [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Proved developed and undeveloped reserves			-141,000,000,000
Chesapeake Property Acquisition [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net unevaluated costs excluded from amortization	$3,600
Area of land purchased	413,000					413,000
Natural Gas [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Proved developed and undeveloped reserves	9,809,000,000,000	6,974,000,000,000	4,017,000,000,000	5,887,000,000,000	5,887,000,000,000	9,809,000,000,000
Production	-765,000,000,000	-655,000,000,000	-564,000,000,000
Additions	1,691,000,000,000	3,283,000,000,000	918,000,000,000
Revisions	542,000,000,000	325,000,000,000	-2,088,000,000,000
Proved undeveloped reserves	4,134,000,000,000	2,737,000,000,000	821,000,000,000	2,633,000,000,000	2,633,000,000,000	4,134,000,000,000
Average market prices used in reserves	4.35	3.67	2.76
Oil [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Proved developed and undeveloped reserves	37,615	373	244	996	996	37,615
Production	-235	-138	-83
Additions	250	229	154
Revisions	-14	38	-44
Proved undeveloped reserves	30,170	1	1	13	13	30,170
Average market prices used in reserves	91.48	93.42	91.21
NGL [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Full cost ceiling test, price	23.79	43.45
Proved developed and undeveloped reserves	118,699					118,699
Production	-231	-50
Additions	48
Revisions	66	50
Proved undeveloped reserves	80,067					80,067
Average market prices used in reserves	23.79	43.45
Natural Gas and Oil [Member] | Estimated [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Proved developed and undeveloped reserves	10,747,000,000,000	6,976,000,000,000	4,018,000,000,000	5,893,000,000,000	5,893,000,000,000	10,747,000,000,000
Synthetic Gas, Synthetic Oil or Nonrenewable Natural Resources [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Proved developed and undeveloped reserves	0					0

Natural_Gas_And_Oil_Producing_3

Natural Gas And Oil Producing Activities (Unaudited) (Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Proved properties	$15,860	$12,337
Unproved properties	4,646	957
Total capitalized costs	20,506	13,294
Less: Accumulated depreciation, depletion and amortization	8,327	7,481
Net capitalized costs	12,179	5,813
Unproved property acquisition costs	3,934	168	221
Capitalized costs incurred	7,221	2,023	1,911
Capitalized Costs [Member] | Exploration Program in Canada [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unproved property acquisition costs	76	72
Chesapeake Property Acquisition [Member] | Capitalized Costs [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Capitalized costs incurred	$5,000

Natural_Gas_And_Oil_Producing_4

Natural Gas And Oil Producing Activities (Unaudited) (Schedule Of Capitalized Costs Of Unproved Properties Excluded From Amortization) (Details) (USD $)	12 Months Ended			96 Months Ended	132 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2014
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property aquisition costs	$3,892	$87	$75	$142	$4,196
Exploration and Development Costs	239	40	26	61	366
Capitalized interest	13	10	14	47	84
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost, Total	4,144	137	115	250	4,646
Exploration Program in Canada [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost, Total	76
Composition of Net Unevaluated Costs [Member] | Exploration Program in Canada [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property aquisition costs					36
Exploration and Development Costs					31
Capitalized interest					$9

Natural_Gas_And_Oil_Producing_5

Natural Gas And Oil Producing Activities (Unaudited) (Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities Disclosure) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved property acquisition costs	$1,455	$1
Unproved property acquisition costs	3,934	168	221
Exploration costs	232	192	197
Development costs	1,600	1,662	1,493
Capitalized costs incurred	7,221	2,023	1,911
Full cost pool amortization per Mcfe	1.1	1.08	1.31
Costs Incurred in Natural Gas and Oil Exploration and Development [Member] | Exploration Program in Canada [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved property acquisition costs	1	17	4
Exploration costs	$3	$12	$3

Natural_Gas_And_Oil_Producing_6

Natural Gas And Oil Producing Activities (Unaudited) (Results Of Operations For Oil And Gas Producing Activities Disclosure) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Natural Gas And Oil Producing Activities (Unaudited) [Abstract]
Sales	$2,862	$2,404	$1,963
Production (lifting) costs	-776	-629	-505
Depreciation, depletion and amortization	-884	-735	-765
Impairment of natural gas and oil properties			-1,940
Results of operations - income before income taxes	1,202	1,040	-1,247
Provision (benefit) for income taxes	457	416	-497
Results of operations	$745	$624	($750)

Natural_Gas_And_Oil_Producing_7

Natural Gas And Oil Producing Activities (Unaudited) (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	ft3	ft3	ft3	ft3
Reserve Quantities [Line Items]
Revisions of previous estimates		326,000,000,000
Extensions, discoveries and other additions	1,693,000,000,000	3,285,000,000,000	920,000,000,000
Production	768,000,000,000	657,000,000,000	565,000,000,000	500,000,000,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	6,974,000,000,000	4,017,000,000,000	5,887,000,000,000
Revisions of previous estimates	542,000,000,000	325,000,000,000	-2,088,000,000,000
Extensions, discoveries and other additions	1,691,000,000,000	3,283,000,000,000	918,000,000,000
Production	-765,000,000,000	-655,000,000,000	-564,000,000,000
Acquisition of reserves in place	1,367,000,000,000	4,000,000,000
Disposition of reserves in place			-136,000,000,000
Proved reserves, end of year	9,809,000,000,000	6,974,000,000,000	4,017,000,000,000
Proved Developed Reserves [Abstract]
Beginning of year	4,237,000,000,000	3,196,000,000,000	3,254,000,000,000
End of year	5,675,000,000,000	4,237,000,000,000	3,196,000,000,000
Proved Undeveloped Reserves [Abstract]
Beginning of year	2,737,000,000,000	821,000,000,000	2,633,000,000,000
End of year	4,134,000,000,000	2,737,000,000,000	821,000,000,000
Oil [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	373	244	996
Revisions of previous estimates	-14	38	-44
Extensions, discoveries and other additions	250	229	154
Production	-235	-138	-83
Acquisition of reserves in place	37,246
Disposition of reserves in place	-5		-779
Proved reserves, end of year	37,615	373	244
Proved Developed Reserves [Abstract]
Beginning of year	372	243	983
End of year	7,445	372	243
Proved Undeveloped Reserves [Abstract]
Beginning of year	1	1	13
End of year	30,170	1	1
NGL [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year
Revisions of previous estimates	66	50
Extensions, discoveries and other additions	48
Production	-231	-50
Acquisition of reserves in place	118,816
Disposition of reserves in place
Proved reserves, end of year	118,699
Proved Developed Reserves [Abstract]
Beginning of year
End of year	38,632
Proved Undeveloped Reserves [Abstract]
Beginning of year
End of year	80,067

Natural_Gas_And_Oil_Producing_8

Natural Gas And Oil Producing Activities (Unaudited) (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Natural Gas And Oil Producing Activities (Unaudited) [Abstract]
Future cash inflows	$41,812	$22,624	$9,570
Future production costs	-16,477	-8,896	-4,737
Future development costs	-5,750	-3,626	-711
Future income tax expense	-4,743	-3,223	-745
Future net cash flows	14,842	6,879	3,377
10% annual discount for estimated timing of cash flows	-7,299	-3,143	-1,326
Standardized measure of discounted future net cash flows	$7,543	$3,736	$2,051
Annual discount for estimated timing of cash flows percent	10.00%	10.00%	10.00%

Natural_Gas_And_Oil_Producing_9

Natural Gas And Oil Producing Activities (Unaudited) (Schedule Of Analysis Of Changes In Standardized Measure) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Natural Gas And Oil Producing Activities (Unaudited) [Abstract]
Standardized measure, beginning of year	$3,736	$2,051	$3,451
Sales and transfers of natural gas and oil produced, net of production costs	-2,084	-1,774	-1,444
Net changes in prices and production costs	1,192	1,853	-2,605
Extensions, discoveries, and other additions, net of future production and development costs	1,049	1,454	550
Acquisition of reserves in place	1,897	5
Sales of reserves in place			-157
Revisions of previous quantity estimates	622	349	-1,109
Accretion of discount	513	232	480
Net change in income taxes	-522	-1,120	1,079
Changes in estimated future development costs	110	-196	2,476
Previously estimated development costs incurred during the year	815	223	62
Changes in production rates (timing) and other	215	659	-732
Standardized measure, end of year	$7,543	$3,736	$2,051

Derivatives_And_Risk_Managemen2

Derivatives And Risk Management (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Derivative [Line Items]
Accumulated other comprehensive income, net gain related to hedging activities	$98
Deferred income tax liability, accumulated other comprehensive income	65
Cash flow hedge after-tax net gain to be transferred from accumulated other comprehensive income to earnings during the next twelve months	98
Interest Rate Swaps [Member]
Derivative [Line Items]
Notional amount of derivatives	$170
Year 2015 [Member]
Derivative [Line Items]
Volume of natural gas production	240,000,000,000
Volume of Natural Gas Production (in Bcf), Basis Swaps Not Qualifying for Hedge Accounting Treatment	22,000,000,000
Year 2015 [Member] | Fixed Price Call Options [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Call Options Not Qualifying for Hedge Accounting Treatment	200,000,000,000
Year 2015 [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Volume of natural gas production	120,000,000,000
Volume of Natural Gas Production (in Bcf), Basis Swaps Not Qualifying for Hedge Accounting Treatment	120,000,000,000
Year 2016 [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Basis Swaps Not Qualifying for Hedge Accounting Treatment	4,000,000,000
Year 2016 [Member] | Fixed Price Call Options [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps Not Qualifying for Hedge Accounting Treatment	120,000,000,000
Not Designated as Hedging Instrument [Member] | Year 2015 [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Volume of natural gas production	120,000,000,000

Derivatives_And_Risk_Managemen3

Derivatives And Risk Management (Balance Sheet Classification Of Derivative Financial Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]
Derivative assets	$339	$79
Derivative liabilities	23	41
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	165	21
Derivative liabilities		4
Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	165	21
Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		4
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	174	58
Derivative liabilities	23	37
Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	163	37
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	9	13
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	1
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	1
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	2
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	1	8
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	3	2
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	2	3
Not Designated as Hedging Instrument [Member] | Fixed Price Call Options [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	2
Not Designated as Hedging Instrument [Member] | Fixed Price Call Options [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$10	$31

Derivatives_And_Risk_Managemen4

Derivatives And Risk Management (Schedule Of Derivative Instruments, Volumes Of Natural Gas Production) (Details) (Year 2015 [Member])	12 Months Ended
	Dec. 31, 2014
	ft3
Derivative [Line Items]
Volume of natural gas production	240,000,000,000
Weighted average price to be swapped	4.4
Fixed Price Swaps [Member]
Derivative [Line Items]
Volume of natural gas production	120,000,000,000
Fixed Price Swaps [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume of natural gas production	120,000,000,000

Derivatives_And_Risk_Managemen5

Derivatives And Risk Management (Summary Of Before Tax Effect Of Cash Flow Hedges On Consolidated Financial Statements) (Details) (Fixed Price Swaps [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income, Effective Portion	$122	$38
Gas Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Earnings, Effective Portion	($26)	$309

Derivatives_And_Risk_Managemen6

Derivatives And Risk Management (Summary Of Before Tax Effect Of Fair Value Hedges Not Designated For Hedge Accounting) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Basis Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) on Derivatives, Excluding Derivatives, Settled	($7)	$7
Derivative Instruments, Gain (Loss) on Derivatives, Settled	12	5
Fixed Price Call Options [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) on Derivatives, Excluding Derivatives, Settled	18	-26
Fixed Price Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) on Derivatives, Excluding Derivatives, Settled	126	37
Derivative Instruments, Gain (Loss) on Derivatives, Settled	-2
Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) on Derivatives, Excluding Derivatives, Settled	-7	3
Derivative Instruments, Gain (Loss) on Derivatives, Settled	($1)

Reclassification_From_Accumula2

Reclassification From Accumulated Other Comprehensive Income (Components Of Accumulated Other Comprehensive Income (Loss)) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2013	($4)
Other comprehensive income (loss) before reclassifications	65
Amounts reclassified from other comprehensive income	1
Net current-period other comprehensive income (loss)	66	-154	-258
Ending balance, December 31, 2014	62	-4
Gains (Losses) To Other Comprehensive Income On Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2013	9
Other comprehensive income (loss) before reclassifications	73
Amounts reclassified from other comprehensive income	16
Net current-period other comprehensive income (loss)	89
Ending balance, December 31, 2014	98
Pension And Other Postretirement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2013	-9
Amounts reclassified from other comprehensive income	-15
Net current-period other comprehensive income (loss)	-15
Ending balance, December 31, 2014	-24
Foreign Currency [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2013	-4
Other comprehensive income (loss) before reclassifications	-8
Net current-period other comprehensive income (loss)	-8
Ending balance, December 31, 2014	($12)

Reclassification_From_Accumula3

Reclassification From Accumulated Other Comprehensive Income (Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Gas sales									$2,827	$2,381	$1,956
Net actuarial loss									25
Gain (loss) before income taxes									1,449	1,190	-1,150
Provision (benefit) for income taxes									525	486	-443
Net Income (Loss)	312	211	207	194	144	186	246	128	924	704	-707
Reclassification Out Of Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income (Loss)									1
Gains (Losses) To Other Comprehensive Income On Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Gain (loss) before income taxes									26
Provision (benefit) for income taxes									10
Net Income (Loss)									16
Gains (Losses) To Other Comprehensive Income On Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Loss [Member] | Settlements [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Gas sales									26
Pension And Other Postretirement [Member] | Reclassification Out Of Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net actuarial loss									-25
Gain (loss) before income taxes									-25
Provision (benefit) for income taxes									-10
Net Income (Loss)									($15)

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
7.5% Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	7.50%
Yield, Publicly-traded debt market	3.20%	2.60%
Debt Instrument, Maturity Year	2018
4.10% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.10%
Yield, Publicly-traded debt market	4.30%	4.20%
Debt Instrument, Maturity Year	2022

Fair_Value_Measurements_Carryi

Fair Value Measurements (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	$53	$23
Credit facility	300	283
Senior notes	1,667	1,668
Derivative instruments	316	38
Carrying Amount [Member] | Unsecured Debt [Member] | Term Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	500
Carrying Amount [Member] | Bridge Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	4,500
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	53	23
Credit facility	300	283
Senior notes	1,751	1,796
Derivative instruments	316	38
Fair Value [Member] | Unsecured Debt [Member] | Term Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	500
Fair Value [Member] | Bridge Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	$4,500

Fair_Value_Measurements_Summar

Fair Value Measurements (Summary Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$329	$66
Derivative liabilities	-5	-9
Total	324	57
Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	10	13
Derivative liabilities	-18	-32
Total	-8	-19
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	339	79
Derivative liabilities	-23	-41
Total	$316	$38

Fair_Value_Measurements_Reconc

Fair Value Measurements (Reconciliations For Change In Net Fair Value Of Derivative Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value Measurements [Abstract]
Balance at beginning of period	($19)
Included in earnings	23	-14
Purchases, issuances, and settlements:
Purchases
Issuances
Settlements	-12	-5
Transfers into/out of Level 3
Balance at end of period	-8	-19
Change in gains (losses) included in earnings relating to derivatives still held as of December 31	$11	($19)

Debt_Narrative_Details

Debt (Narrative) (Details) (USD $)	0 Months Ended	2 Months Ended	12 Months Ended		0 Months Ended	1 Months Ended
	Jan. 21, 2015	Feb. 26, 2015	Dec. 31, 2014	Dec. 31, 2013	Jan. 23, 2015	Jan. 31, 2015	Dec. 16, 2013	Dec. 19, 2014
Debt Instrument [Line Items]
Senior notes			2,200,000,000
Debt percentage of adjusted book capital structure covenant			60.00%
Subsequent Event [Member]
Debt Instrument [Line Items]
Proceeds from issuance of shares	2,300,000,000
Over LIBOR [Member]
Debt Instrument [Line Items]
Basis points		1.50%	1.38%	1.50%
Credit Facility [Member]
Debt Instrument [Line Items]
Unsecured revolving credit facility, borrowing capacity			2,000,000,000
Unsecured revolving credit facility, maturity date			1-Dec-18
Number of extension options			2
Extension term			1 year
Unsecured revolving credit facility, increase in current borrowing capacity potential							500,000,000
Bridge Loan [Member]
Debt Instrument [Line Items]
Bridge loan			4,500,000,000					4,500,000,000
Debt instrument, term			364 days
Bridge Loan [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Repayment of debt					4,500,000,000	4,500,000,000
Term Loan [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt instrument, term			2 years
Loans payable			500,000,000					500,000,000
Common Stock [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Proceeds from issuance of shares	669,000,000
Depositary Shares [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Proceeds from issuance of shares	$1,700,000,000

Debt_Components_Of_Debt_Detail

Debt (Components Of Debt) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 19, 2014
Debt Instrument [Line Items]
Total short-term debt	$4,501,000,000	$1,000,000
Senior notes	2,200,000,000
Unamortized discount	-1,000,000	-1,000,000
Long-term debt	2,466,000,000	1,950,000,000
Total debt	6,967,000,000	1,951,000,000
Credit Facility [Member]
Debt Instrument [Line Items]
Variable rate (1.50% and 1.64% at September 30, 2014 and December 31, 2013, respectively) Credit Facility, expires December 2018	300,000,000	283,000,000
Credit facility, variable interest rate	1.52%	1.64%
Credit facility, maturity date	1-Dec-18
7.35% Senior Notes due 2017 [Member]
Debt Instrument [Line Items]
Stated interest rate	7.35%
Maturity date	2017
7.125% Senior Notes due 2017 [Member]
Debt Instrument [Line Items]
Stated interest rate	7.13%
Maturity date	2017
7.5% Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Stated interest rate	7.50%
Maturity date	2018
4.10% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
Maturity date	2022
Senior Notes [Member] | 7.15% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Senior notes	1,000,000	1,000,000
Stated interest rate	7.15%
Maturity date	2018
Bridge Loan [Member]
Debt Instrument [Line Items]
Variable rate (1.515% at December 31, 2014) bridge facility, due December 2015	4,500,000,000		4,500,000,000
Term loan, maturity date	2015-12
Term loan, variable interest rate	1.52%
Senior Notes [Member] | 7.15% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Senior notes	27,000,000	28,000,000
Stated interest rate	7.15%
Maturity date	2018
Senior Notes [Member] | 7.35% Senior Notes due 2017 [Member]
Debt Instrument [Line Items]
Senior notes	15,000,000	15,000,000
Senior Notes [Member] | 7.125% Senior Notes due 2017 [Member]
Debt Instrument [Line Items]
Senior notes	25,000,000	25,000,000
Senior Notes [Member] | 7.5% Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Senior notes	600,000,000	600,000,000
Senior Notes [Member] | 4.10% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,000,000,000	1,000,000,000
Unsecured Debt [Member] | Term Loan [Member]
Debt Instrument [Line Items]
Variable rate (1.545% at December 31, 2014) term loan facility, due December 2016	$500,000,000		$500,000,000
Term loan, maturity date	2016-12
Term loan, variable interest rate	1.55%

Debt_Schedule_Of_Long_Term_Deb

Debt (Schedule Of Long Term Debt Maturities) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Debt [Abstract]
2016	$501
2017	41
2018	925
Thereafter	1,000
Total long-term debt maturities	$2,467

Commitments_And_Contingencies_

Commitments And Contingencies (Details)

1 Months Ended

12 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Jul. 31, 2013

Aug. 31, 2011

Dec. 31, 2010

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Mar. 31, 2010

USD ($)

USD ($)

USD ($)

USD ($)

acre

Exploration and Production [Member]

Exploration and Production [Member]

Exploration and Production [Member]

Exploration and Production [Member]

Midstream Services and E&P [Member]

Exploration Program in Canada [Member]

Exploration Program in Canada [Member]

Exploration Program in Canada [Member]

Pressure Pumping Equipment [Member]

Drilling Rigs [Member]

Maximum [Member]

Minimum [Member]

USD ($)

USD ($)

CAD

CAD

USD ($)

USD ($)

Pressure Pumping Equipment [Member]

Pressure Pumping Equipment [Member]

acre

item

item

Commitments And Contingencies [Line Items]

Future demand transportation charges, 2015

$478

Future demand transportation charges, 2016

515

Future demand transportation charges, 2017

543

Future demand transportation charges, 2018

549

Future Demand Transportation Charges Due 2019

502

Future demand transportation charges, thereafter

2,802

Number of leases

11

7

Lease expiration date

31-Dec-27

31-Dec-20

1-Jan-18

1-Dec-17

Aggregate annual lease payment

8

13

Operating leases, future minimum payments, 2015

73

41

Operating leases, future minimum payments, 2016

62

28

Operating leases, future minimum payments, 2017

45

19

Operating leases, future minimum payments, 2018

25

10

Operating leases, future minimum payments, 2019

21

4

Operating leases, future minimum payments, thereafter

45

Obligations for demand and similar charges under transportation agreements

5,400

44

45

Guarantee obligations relative to the firms transportation agreements and gathering project and services

173

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

2,500,000

Unrecorded capital investments obligation

47

Unrecorded promissory note payable

45

Area of land being constructed

26

Current obligation for construction costs incurred

137

Litigation settlement, gross

11

Litigation, portion of profits considered for disgorgement

382

Actual damages recoverable by plaintiff per August 2011 judgement

11

Disgorgement recoverable by plaintiff per August 2011 judgement

24

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

9

Disgorgement recoverable by plaintiff to be reversed

24

Actual damages recoverable by plaintiff to be reversed

11

Litigation settlement upheld

$11

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Effective tax rate of provision for income taxes	36.00%	41.00%	39.00%
Cash paid for income taxes	$28	$19	$1
Operating Loss Carryforwards	318	412
Alternative minimum tax credit carryforward	131	77
Statutory depletion carryforward	13
Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets	152
Deferred tax assests, valuation allowance	5
Net long-term deferred tax liabilities	1,951	1,527
Net current deferred tax liabilities	109	24
Accrued liability of interest related to uncertain tax position	1
Unrecognized tax benefits related to alternative minimum tax	44
Exploration Program in Canada [Member]
Income Taxes [Line Items]
Net operating loss carryforward	26
Federal [Member]
Income Taxes [Line Items]
Cash paid for income taxes	14	16
Operating Loss Carryforwards	988
State [Member]
Income Taxes [Line Items]
Cash paid for income taxes	14	3
Operating Loss Carryforwards	$556
Minimum [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date	1-Jan-28
Minimum [Member] | Exploration Program in Canada [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date	1-Jan-30
Maximum [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date	31-Dec-34
Maximum [Member] | Exploration Program in Canada [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date	31-Dec-34

Income_Taxes_Provision_Benefit

Income Taxes (Provision (Benefit) For Income Taxes) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal Current	$11	($12)	$16
State Current	10	1	3
Total Current	21	-11	19
Deferred:
Federal Deferred	501	408	-388
State Deferred	2	88	-72
Foreign Deferred	1	1	-2
Total Deferred	504	497	-462
Provision (benefit) for income taxes	$525	$486	($443)

Income_Taxes_Reconciliation_Of

Income Taxes (Reconciliation Of Provision (Benefit) For Income Taxes) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Abstract]
Expected provision (benefit) at federal statutory rate	$507	$417	($403)
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect	58	53	-44
Nondeductible expenses	3	3	2
State rate redetermination	-48	4	2
Other	5	9
Provision (benefit) for income taxes	$525	$486	($443)

Income_Taxes_Schedule_Of_Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Deferred tax liabilities:
Differences between book and tax basis of property	$2,504	$2,115
Derivative activity	122	13
Other	21	11
Total deferred tax liabilities	2,647	2,139
Deferred tax assets
Accrued compensation	23	16
Alternative minimum tax credit carryforward	131	77
Stored natural gas	5	9
Accrued pension costs	17	2
Asset retirement obligations	79	54
Net operating loss carryforward	318	412
Differences between book and tax basis of property - state	6	11
Other	8	7
Total deferred tax assets	587	588
Net deferred tax liability	$2,060	$1,551

Income_Taxes_Reconciliation_Of1

Income Taxes (Reconciliation Of Beginning And Ending Balances Of Unrecognized Tax Benefits) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Income Taxes [Abstract]
Unrecognized tax benefits at beginning of period
Additions based on tax positions related to the current year	15
Additions to tax positions of prior years	29
Settlements
Unrecognized tax benefits at end of period	$44

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations [Line Items]
Asset retirement obligation at January 1	$134	$101
Accretion of discount	7	6
Obligations incurred	64	22
Obligations settled/removed	-4	-2
Revisions of estimates	6	7
Current liability	9	6
Long-term liability	198	128
Asset retirement obligation at December 31	207	134
Chesapeake Property Acquisition [Member]
Asset Retirement Obligations [Line Items]
Obligations incurred	$42

Retirement_And_Employee_Benefi2

Retirement And Employee Benefit Plans (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Contribution expense	$3	$3	$2
Contributions capitalized	3	3	3
Net actuarial loss arising during the year	25
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	12	14	11
Change in accumulated other comprehensive income (loss)	-23	19
Change in accumulated other comprehensive income (loss) after tax	-14	12
Net actuarial loss arising during the year	-23
Net loss	-2
Employer contributions	12
Company's expected additional annual contribution	12
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	3	3	2
Change in accumulated other comprehensive income (loss)	-2	2
Change in accumulated other comprehensive income (loss) after tax	-1	1
Net actuarial loss arising during the year	-2
Employer contributions	0.1
Company's expected additional annual contribution	1
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)	-41	16
Defined benefit plan included in accumulated other comprehensive income (loss) after tax	($24)	$10

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 Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$13	$14	$11
Interest cost	5	4	4
Employer contributions	12
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2	2	2
Interest cost	1	1
Employer contributions	0.1
Change In Benefit Obligation [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at January 1	103	105
Service cost	13	14
Interest cost	5	4
Actuarial loss	21	-11
Benefits paid	-8	-8
Settlements		-1
Benefit obligation at December 31	134	103
Change In Benefit Obligation [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at January 1	12	12
Service cost	2	2
Interest cost	1
Actuarial loss	3	-2
Benefit obligation at December 31	18	12
Change In Plan Assets [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	12	13
Benefits paid	-8	-8
Settlements		-1
Fair value of plan assets at January 1	99	83
Fair value of plan assets at December 31	108	99
Actual return/(loss) on plan assets	5	12
Funded status of plans at December 31	-26	-4
Change In Plan Assets [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Funded status of plans at December 31	($18)	($12)

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, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Retirement And Employee Benefit Plans [Abstract]
Projected benefit obligation	$134	$103
Accumulated benefit obligation	129	100
Fair value of plan assets	$108	$99

Retirement_And_Employee_Benefi5

Retirement And Employee Benefit Plans (Pension And Other Postretirement Benefit Costs) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$13	$14	$11
Interest cost	5	4	4
Expected return on plan assets	-7	-6	-5
Amortization of transition obligation
Amortization of prior service cost
Amortization of net loss	1	2	1
Net periodic benefit cost	12	14	11
Settlements and curtailments		0
Total benefit cost	12	14	11
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2	2	2
Interest cost	1	1
Amortization of transition obligation
Amortization of prior service cost
Net periodic benefit cost	3	3	2
Total benefit cost	$3	$3	$2

Retirement_And_Employee_Benefi6

Retirement And Employee Benefit Plans (Amounts Recognized In Other Comprehensive Income) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss arising during the year	$25
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss arising during the year	-23
Amortization of prior service cost
Amortization of net loss
Settlements
Tax effect	9
Total	-14
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss arising during the year	-2
Amortization of prior service cost
Amortization of net loss
Settlements
Tax effect	1
Total	($1)

Retirement_And_Employee_Benefi7

Retirement And Employee Benefit Plans (Schedule Of Assumptions Used - Benefit Obligations) (Details)	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.25%	5.00%
Rate of compensation increase	4.50%	4.50%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.25%	5.00%

Retirement_And_Employee_Benefi8

Retirement And Employee Benefit Plans (Schedule Of Assumptions Used - Benefit Obligations - Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.00%	4.00%	5.00%
Expected return on plan assets	7.00%	7.00%	7.50%
Rate of compensation increase	4.50%	4.50%	4.50%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.00%	4.00%	5.00%

Retirement_And_Employee_Benefi9

Retirement And Employee Benefit Plans (Schedule Of Health Care Cost Trend Rates) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
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	2033	2032

Recovered_Sheet1

Retirement And Employee Benefit Plans (One Percentage Point Change In Assumed Health Care Cost Trend Rates) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Retirement And Employee Benefit Plans [Abstract]
Effect on total service and interest cost components increase
Effect on total service and interest cost components decrease
Effect on postretirement benefit obligations increase	3
Effect on postretirement benefit obligation decrease	($2)

Recovered_Sheet2

Retirement And Employee Benefit Plans (Schedule Of Expected Benefit Payments) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	$6
2016	8
2017	8
2018	10
2019	11
2020-2024	65
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	1
2016	1
2017	1
2018	1
2019-2023	$9

Recovered_Sheet3

Retirement And Employee Benefit Plans (Schedule Of Allocation Of Plan Assets) (Details) (Pension Benefits [Member])	12 Months Ended
	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	100.00%
Actual asset allocations	100.00%
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	29.00%
Actual asset allocations	29.00%
Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	1.00%
Actual asset allocations	3.00%
U.S. Equity [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	35.00%
Actual asset allocations	36.00%
International Equity [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	30.00%
Actual asset allocations	27.00%
Emerging Market Equity [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	5.00%
Actual asset allocations	5.00%

Recovered_Sheet4

Retirement And Employee Benefit Plans (Fair Value Measurement Of Pension Plan Assets) (Details) (Pension Benefits [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$108	$99
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	58	51
Equity Securities [Member] | Significant Observable Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50	48
Equity Securities [Member] | Large Cap Growth Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8	8
Equity Securities [Member] | 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	8	8
Equity Securities [Member] | Large Cap Value Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	8
Equity Securities [Member] | 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	9	8
Equity Securities [Member] | Large Cap Core Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19	16
Equity Securities [Member] | Large Cap Core Equity [Member] | Significant Observable Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19	16
Equity Securities [Member] | Small Cap Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	3
Equity Securities [Member] | 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	3
Equity Securities [Member] | International Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	29	31
Equity Securities [Member] | 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	29	31
Equity Securities [Member] | Emerging Market Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5	6
Equity Securities [Member] | Emerging Market Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5
Equity Securities [Member] | Emerging Market Equity [Member] | Significant Observable Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		6
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31	26
Fixed Income [Member] | Significant Observable Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31	26
Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	1
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	$4	$1

StockBased_Compensation_Narrat

Stock-Based Compensation (Narrative) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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	$13
Weighted average period over which cost is recognized, years	2 years
2004 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares	16,800,000
Expiration period from date of grant	7 years
2002 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares	300,000
2000 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares	1,250,000
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	3 years
Deferred tax benefit (liability) recorded	3	4	2
Weighted-average grant-date fair value of options granted	$10.16	$13.39	$16.91
Intrinsic value	4	22	44
Stock-based compensation costs - expensed	5	5	5
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	4 years
Deferred tax benefit (liability) recorded	-10	-15	-1
Unrecognized compensation cost related to the Company's unvested stock option grants, restricted stock grants, and performance units	75
Weighted-average grant-date fair value of options granted	$30.89	$38.92	$34.39
Weighted average period over which cost is recognized, restricted stock (years)	3 years 1 month 6 days
Total fair value of restricted stock grants	40	43	19
Total fair value of shares vested	20	14	13
Stock-based compensation costs - expensed	10	7	6
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	3 years
Deferred tax benefit (liability) recorded	51	45
Stock-based compensation costs - expensed	25	3	19
Equity-Classified Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred tax benefit (liability) recorded	2
Unrecognized compensation cost related to the Company's unvested stock option grants, restricted stock grants, and performance units	24
Weighted average period over which cost is recognized, years	3 years
Weighted-average grant-date fair value of options granted	$40.44
Stock-based compensation costs - expensed	$3
Maximum [Member] | 2004 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares	20,500,000

StockBased_Compensation_Schedu

Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs - Stock Options) (Details) (Stock Options [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Options [Member]
Stock-based compensation costs - expensed	$5	$5	$5
Stock-based compensation costs - capitalized	$4	$5	$4

StockBased_Compensation_Schedu1

Stock-Based Compensation (Schedule Of Valuation Assumptions) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock-Based Compensation [Abstract]
Risk-free interest rate	1.60%	1.50%	0.60%
Expected volatility	32.50%	38.60%	58.20%
Expected term	5 years	5 years	5 years

StockBased_Compensation_Summar

Stock-Based Compensation (Summary Of Stock Option Activity) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock options, Outstanding at December 31, Number of options	3,313,000	3,650,000	4,743,000
Stock options, Granted, Number of options	835,000	571,000	613,000
Stock options, Exercised, Number of options	-402,000	-833,000	-1,608,000
Stock options, Forfeited or expired, Number of options	-124,000	-75,000	-98,000
Stock options, Outstanding at December 31, Number of options	3,622,000	3,313,000	3,650,000
Stock options, Outstanding at December 31, Weighted average exercise price	$35.70	$29.84	$21.24
Stock options, Granted, Weighted average exercise price	$32.31	$38.95	$34.34
Stock options, Exercised, Weighted average exercise price	$30.60	$12.12	$5.71
Stock options, Forfeited or expired, Weighted average exercise price	$37.80	$37.31	$37.76
Stock options, Outstanding at December 31, Weighted average exercise price	$35.41	$35.70	$29.84
Stock Options [Member]
Stock options, Outstanding at December 31, Number of options	3,622,000
Stock options, Outstanding at December 31, Weighted average exercise price	$35.41
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	4 years 4 months 24 days
Stock options, Exercisable at December 31, 2014	2,277,000
Stock options, Exercisable at December 31, 2014, Weighted average exercise price	$36.13
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	3 years 3 months 18 days
Range of Exercise Prices $27.09-$29.69 [Member] | Stock Options [Member]
Stock options, Outstanding at December 31, Number of options	21,000
Stock options, Outstanding at December 31, Weighted average exercise price	$28.42
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	2 years 10 months 24 days
Stock options, Exercisable at December 31, 2014	17,000
Stock options, Exercisable at December 31, 2014, Weighted average exercise price	$28.53
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	2 years 6 months
Range of Exercise Prices $30.23-$35.91 [Member] | Stock Options [Member]
Stock options, Outstanding at December 31, Number of options	1,744,000
Stock options, Outstanding at December 31, Weighted average exercise price	$32.04
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	4 years 10 months 24 days
Stock options, Exercisable at December 31, 2014	819,000
Stock options, Exercisable at December 31, 2014, Weighted average exercise price	$32.83
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	3 years 1 month 6 days
Range of Exercise Prices $36.22-$39.91 [Member] | Stock Options [Member]
Stock options, Outstanding at December 31, Number of options	1,443,000
Stock options, Outstanding at December 31, Weighted average exercise price	$37.52
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	4 years 3 months 18 days
Stock options, Exercisable at December 31, 2014	1,117,000
Stock options, Exercisable at December 31, 2014, Weighted average exercise price	$37.10
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	3 years 10 months 24 days
Range of Exercise Prices $40.15-$51.47 [Member] | Stock Options [Member]
Stock options, Outstanding at December 31, Number of options	414,000
Stock options, Outstanding at December 31, Weighted average exercise price	$42.64
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	2 years 10 months 24 days
Stock options, Exercisable at December 31, 2014	324,000
Stock options, Exercisable at December 31, 2014, Weighted average exercise price	$41.56
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	1 year 10 months 24 days

StockBased_Compensation_Schedu2

Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs - Restricted Stock) (Details) (Restricted Stock [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Stock-based compensation costs - expensed	$10	$7	$6
Stock-based compensation costs - capitalized	$12	$7	$6

StockBased_Compensation_Summar1

Stock-Based Compensation (Summary Of Restricted Stock Activity) (Details) (Restricted Stock [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares/units at January 1, 2014, Number of Shares	1,771	1,118	1,020
Granted, Number of Shares/Units	1,295	1,109	537
Vested, Number of Shares/Units	-548	-382	-344
Forfeited, Number of Shares/Units	-142	-74	-95
Unvested shares/units at December 31, 2014, Number of Shares	2,376	1,771	1,118
Unvested shares/units at January 1, 2014, Weighted Average Grant Date Fair Value	$37.55	$35.64	$36.71
Granted, Weighted Average Grant Date Fair Value	$30.89	$38.92	$34.39
Vested, Weighted Average Grant Date Fair Value	$37.12	$36.29	$36.50
Forfeited, Weighted Average Grant Date Fair Value	$37.91	$35.81	$36.97
Unvested shares at December 31, 2014, Weighted Average Grant Date Fair Value	$34	$37.55	$35.64

StockBased_Compensation_Summar2

Stock-Based Compensation (Summary Of Equity-Classified Performance Units) (Details) (Equity-Classified Performance Units [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014
Equity-Classified Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares/units at January 1, 2014, Number of Shares
Granted, Number of Shares/Units	359
Vested, Number of Shares/Units	-111
Forfeited, Number of Shares/Units	-25
Unvested shares/units at December 31, 2014, Number of Shares	223
Unvested shares/units at January 1, 2014, Weighted Average Grant Date Fair Value
Granted, Weighted Average Grant Date Fair Value	$40.44
Vested, Weighted Average Grant Date Fair Value	$40.44
Forfeited, Weighted Average Grant Date Fair Value	$40.44
Unvested shares at December 31, 2014, Weighted Average Grant Date Fair Value	$40.44

StockBased_Compensation_Schedu3

Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs - Equity-Classified Performance Units) (Details) (Equity-Classified Performance Units [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Equity-Classified Performance Units [Member]
Stock-based compensation costs - expensed	$3
Stock-based compensation costs - capitalized	$2

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Revenues	$962	$928	$1,035	$1,113	$907	$868	$862	$734	$4,038	$3,371	$2,730
Operating income (loss)	285	286	367	435	317	309	325	252	1,373	1,204	-1,101
Other Income (Loss), Net									-4	2	1
Gain (loss) on derivatives									139	26	-15
Depreciation, depletion and amortization									942	787	811
Impairment of natural gas and oil properties											1,940
Interest expense									59	42	35
Provision (benefit) for income taxes									525	486	-443
Assets	14,925				8,048				14,925	8,048	6,738
Capital investments									7,447	2,235	2,081
Impairment of natural gas and oil properties											1,940
Change in accrued expenditures									155	-25	-37
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									-3,182	-2,380	-1,600
Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenues									2,850	2,398	1,965
Operating income (loss)									1,013	879	-1,396
Other Income (Loss), Net									-3	3	-1
Gain (loss) on derivatives									142	26	-15
Depreciation, depletion and amortization									884	735	766
Impairment of natural gas and oil properties											1,940
Interest expense									47	30	20
Provision (benefit) for income taxes									402	368	-549
Assets	13,018				6,357				13,018	6,357	5,194
Capital investments									7,254	2,052	1,861
Exploration and Production [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									-12	-6	1
Exploration and Production [Member] | Canada [Member]
Segment Reporting Information [Line Items]
Assets	77				79				77	79	44
Capital investments									11	35	12
Midstream Services [Member]
Segment Reporting Information [Line Items]
Revenues									1,188	973	765
Operating income (loss)									361	325	294
Other Income (Loss), Net									-1
Gain (loss) on derivatives									-1
Depreciation, depletion and amortization									58	51	44
Interest expense									12	11	14
Provision (benefit) for income taxes									123	119	105
Assets	1,554				1,427				1,554	1,427	1,273
Capital investments									144	158	165
Midstream Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									-3,170	-2,374	-1,598
Other [Member]
Segment Reporting Information [Line Items]
Operating income (loss)									-1		1
Other Income (Loss), Net										-1	2
Gain (loss) on derivatives									-2
Depreciation, depletion and amortization										1	1
Interest expense										1	1
Provision (benefit) for income taxes										-1	1
Assets	353				264				353	264	271
Capital investments									49	25	55
Other [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues											-3
Marketing [Member] | Midstream Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									($2,800)	($2,000)	($1,300)

Quarterly_Results_Unaudited_De

Quarterly Results (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Results (Unaudited) [Abstract]
Operating revenues	$962	$928	$1,035	$1,113	$907	$868	$862	$734	$4,038	$3,371	$2,730
Operating income (loss)	285	286	367	435	317	309	325	252	1,373	1,204	-1,101
Net income (loss)	$312	$211	$207	$194	$144	$186	$246	$128	$924	$704	($707)
Earnings per share attributable to Southwestern Energy stockholders - Basic	$0.89	$0.60	$0.59	$0.55	$0.41	$0.53	$0.70	$0.36	$2.63	$2.01	($2.03)
Earnings per share attributable to Southwestern Energy stockholders - Diluted	$0.88	$0.60	$0.59	$0.55	$0.41	$0.53	$0.70	$0.36	$2.62	$2	($2.03)

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 23, 2015	Jan. 21, 2015	Jan. 27, 2015	Jan. 30, 2015	Dec. 19, 2014
Subsequent Event [Line Items]
Capitalized costs incurred	$7,221,000,000	$2,023,000,000	$1,911,000,000
Bridge Loan [Member]
Subsequent Event [Line Items]
Bridge loan	4,500,000,000							4,500,000,000
Debt instrument, term	364 days
Subsequent Event [Member]
Subsequent Event [Line Items]
Proceeds from issuance of shares					2,300,000,000
Share price					$23
Depositary shares conversion rate					0.05
Proceeds from issuance of senior notes				2,200,000,000
Subsequent Event [Member] | 3.300% Senior Notes Due 2018 [Member]
Subsequent Event [Line Items]
Senior notes				350,000,000
Stated interest rate				3.30%
Discount on senior notes				99.95%
Subsequent Event [Member] | 4.050% Senior Notes Due 2020 [Member]
Subsequent Event [Line Items]
Senior notes				850,000,000
Stated interest rate				4.05%
Discount on senior notes				99.90%
Subsequent Event [Member] | 4.950% Senior Notes Due 2025 [Member]
Subsequent Event [Line Items]
Senior notes				1,000,000,000
Stated interest rate				4.95%
Discount on senior notes				99.78%
Subsequent Event [Member] | Statoil Property [Member]
Subsequent Event [Line Items]
Area of property						30,000
Interest in property						20.00%
Acquisition price						365,000,000
Subsequent Event [Member] | WPX Property [Member]
Subsequent Event [Line Items]
Area of property							46,700
Acquisition price							288,000,000
Subsequent Event [Member] | Common Stock [Member]
Subsequent Event [Line Items]
Shares issued					30,000,000
Proceeds from issuance of shares					669,000,000
Subsequent Event [Member] | Depositary Shares [Member]
Subsequent Event [Line Items]
Shares issued					34,500,000
Proceeds from issuance of shares					$1,700,000,000
Preferred stock, liquidation preference per share					$50
Subsequent Event [Member] | Preferred Stock [Member]
Subsequent Event [Line Items]
Preferred stock dividend rate					6.25%
Preferred stock, liquidation preference per share					$1,000