Southwestern Energy (SWN) 10-K 28 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 26, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Registrant Name	SOUTHWESTERN ENERGY CO
Entity Central Index Key	7,332
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Trading Symbol	SWN
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 3,096,452,639
Entity Common Stock, Shares Outstanding		541,319,293

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Operating Revenues:
Operating Revenues	$ 3,862	$ 3,203		$ 2,436
Operating Costs and Expenses:
Operating expenses	785	671		592
General and administrative expenses	209	233		247
Restructuring charges	39			73
Depreciation, depletion and amortization	560	504		436
Impairments	171			2,321
Gain on sale of assets, net	(17)	(6)
Taxes, other than income taxes	89	94		93
Total Operating Costs and Expenses	3,065	2,472		4,626
Operating Income (Loss)	797	731		(2,190)
Interest Expense:
Interest on debt	231	239		226
Other interest charges	8	9		14
Interest capitalized	(115)	(113)		(152)
Total Interest Expense	124	135		88
Gain (Loss) on Derivatives	(118)	422		(339)
Loss on Early Extinguishment of Debt	(17)	(70)		(51)
Other Income (Loss), Net		5		(4)
Income (Loss) Before Income Taxes	538	953		(2,672)
Provision (Benefit) for Income Taxes:
Current	1	(22)		(7)
Deferred		(71)		(22)
Provision (Benefit) for Income Taxes	1	(93)		(29)
Net Income (Loss)	537	1,046	[1]	(2,643)
Mandatory convertible preferred stock dividend		108		108
Participating securities - mandatory convertible preferred stock	2	123
Net Income (Loss) Attributable to Common Stock	$ 535	$ 815		$ (2,751)
Earnings (Loss) Per Common Share:
Basic	$ 0.93	$ 1.64		$ (6.32)
Diluted	$ 0.93	$ 1.63		$ (6.32)
Weighted Average Common Shares Outstanding:
Basic	574,631,756	498,264,321		435,337,402
Diluted	576,642,808	500,804,297		435,337,402
Gas Sales [Member]
Operating Revenues:
Operating Revenues	$ 1,998	$ 1,793		$ 1,273
Oil Sales [Member]
Operating Revenues:
Operating Revenues	196	102		69
NGL Sales [Member]
Operating Revenues:
Operating Revenues	352	206		92
Marketing [Member]
Operating Revenues:
Operating Revenues	1,222	972		864
Gas Gathering [Member]
Operating Revenues:
Operating Revenues	89	126		138
Other [Member]
Operating Revenues:
Operating Revenues	5	4
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Operating Costs and Expenses:
Marketing purchases	$ 1,229	$ 976		$ 864
[1]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	[1]	Dec. 31, 2016
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Net income (loss)		$ 537	$ 1,046		$ (2,643)
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost	[2]	10	2		13
Net loss incurred in period	[3]	(2)	(13)		(7)
Total change in value of pension and postretirement liabilities		8	(11)		6
Change in currency translation adjustment			6		3
Comprehensive income (loss)		$ 545	$ 1,041		$ (2,634)
[1]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.
[2]	Net of $8 million in taxes for the year ended December 31, 2016.
[3]	Net of ($4) million in taxes for the year ended December 31, 2016.

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Amortization of prior service cost and net loss included in net periodic pension cost, tax	$ 8
Net gain (loss) incurred in period, tax	$ (4)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 201	$ 916
Accounts receivable, net	581	428
Derivative assets	130	130
Other current assets	44	35
Total current assets	956	1,509
Natural gas and oil properties, using the full cost method, including $1,755 million as of December 31, 2018 and $1,817 million as of December 31, 2017 excluded from amortization	24,180	23,890
Gathering systems	38	1,315
Other	487	564
Less: Accumulated depreciation, depletion and amortization	(20,049)	(19,997)
Total property and equipment, net	4,656	5,772
Other long-term assets	185	240
TOTAL ASSETS	5,797	7,521
Current liabilities:
Accounts payable	609	533
Taxes payable	58	62
Interest payable	52	70
Dividends payable		27
Derivative liabilities	79	64
Other current liabilities	48	24
Total current liabilities	846	780
Long-term debt	2,318	4,391
Pension and other postretirement liabilities	46	58
Other long-term liabilities	225	313
Total long-term liabilities	2,589	4,762
Commitments and contingencies (Note 9)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 585,407,107 shares as of December 31, 2018 and 512,134,311 as of December 31, 2017	6	5
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding as of December 31, 2017, converted to common stock on January 12, 2018
Additional paid-in capital	4,715	4,698
Accumulated deficit	(2,142)	(2,679)
Accumulated other comprehensive loss	(36)	(44)
Common stock in treasury, 39,092,537 shares as of December 31, 2018 and 31,269 shares as of December 31, 2017	(181)	(1)
Total equity	2,362	1,979
TOTAL LIABILITIES AND EQUITY	$ 5,797	$ 7,521

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
CONSOLIDATED BALANCE SHEETS [Abstract]
Natural gas and oil properties, using the full cost method, costs excluded from amortization	$ 1,755	$ 1,817
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1,250,000,000	1,250,000,000
Common stock, shares issued	585,407,107	512,134,311
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, dividend rate	6.25%	6.25%
Liquidation preference per share	$ 1,000	$ 1,000
Preferred stock, shares issued		1,725,000
Preferred stock, shares outstanding		1,725,000
Treasury stock, shares	39,092,537	31,269

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Cash Flows From Operating Activities:
Net income (loss)	$ 537	$ 1,046	[1]	$ (2,643)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	560	504		436
Amortization of debt issuance costs	8	9		14
Impairments	171			2,321
Deferred income taxes		(71)		(22)
(Gain) loss on derivatives, unsettled	24	(451)		373
Stock-based compensation	14	24		29
Gain on sale of assets, net	(17)	(6)
Restructuring charges				30
Loss on early extinguishment of debt	17	70		51
Other	(1)	13		8
Change in assets and liabilities:
Accounts receivable	(153)	(65)		(30)
Accounts payable	65	48		(69)
Taxes payable	2	4		(5)
Interest payable	(10)	(2)
Other assets and liabilities	6	(26)		5
Net cash provided by operating activities	1,223	1,097		498
Cash Flows From Investing Activities:
Capital investments	(1,290)	(1,268)		(593)
Proceeds from sale of property and equipment	1,643	10		430
Other	6	6		1
Net cash provided by (used in) investing activities	359	(1,252)		(162)
Cash Flows From Financing Activities:
Payments on current portion of long-term debt		(328)		(1)
Payments on long-term debt	(2,095)	(1,139)		(1,175)
Payments on revolving credit facility	(1,983)			(3,268)
Borrowings under revolving credit facility	1,983			3,152
Payments on commercial paper				(242)
Borrowings under commercial paper				242
Change in bank drafts outstanding	17	9		(20)
Proceeds from issuance of long-term debt		1,150		1,191
Debt issuance costs	(9)	(24)		(17)
Proceeds from issuance of common stock				1,247
Purchase of treasury stock	(180)
Preferred stock dividend	(27)	(16)		(27)
Cash paid for tax withholding	(3)	(2)		(9)
Other		(2)		(1)
Net cash (used in) provided by financing activities	(2,297)	(352)		1,072
Increase (decrease) in cash and cash equivalents	(715)	(507)		1,408
Cash and cash equivalents at beginning of year	916	1,423		15
Cash and cash equivalents at end of year	$ 201	$ 916		$ 1,423
[1]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Millions		Common Stock Outstanding [Member]	Preferred Stock [Member]	Additional Paid-in Capital	Retained Earnings		Accumulated Other Comprehensive Income (Loss)	Common Stock in Treasury	Total
Balance, shares at Dec. 31, 2015		390,138,549	1,725,000					47,149
Balance at Dec. 31, 2015		$ 4		$ 3,409	$ (1,082)		$ (48)	$ (1)	$ 2,282
Comprehensive income:
Net income (loss)					(1,132)				(1,132)
Other comprehensive income (loss)							4		4
Comprehensive income (loss)									(1,128)
Stock-based compensation				26					26
Preferred stock dividend				(27)					(27)
Issuance of restricted stock, shares		84,165
Cancellation of restricted stock, shares		(24,333)
Treasury stock, shares								(15,880)
Tax withholding - stock compensation, shares		(524,703)
Tax withholding - stock compensation				(5)					(5)
Balance, shares at Mar. 31, 2016		389,673,678	1,725,000					31,269
Balance at Mar. 31, 2016		$ 4		3,403	(2,214)		(44)	$ (1)	1,148
Balance, shares at Dec. 31, 2015		390,138,549	1,725,000					47,149
Balance at Dec. 31, 2015		$ 4		3,409	(1,082)		(48)	$ (1)	2,282
Comprehensive income:
Net income (loss)									(2,643)
Other comprehensive income (loss)									9
Comprehensive income (loss)									$ (2,634)
Preferred stock dividend, shares									9,917,799
Balance, shares at Dec. 31, 2016		495,248,369	1,725,000					31,269
Balance at Dec. 31, 2016		$ 5		4,677	(3,725)	[1]	(39)	$ (1)	$ 917
Balance, shares at Mar. 31, 2016		389,673,678	1,725,000					31,269
Balance at Mar. 31, 2016		$ 4		3,403	(2,214)		(44)	$ (1)	1,148
Comprehensive income:
Net income (loss)					(593)				(593)
Other comprehensive income (loss)							3		3
Comprehensive income (loss)									(590)
Stock-based compensation				16					16
Preferred stock dividend, shares		3,024,737
Cancellation of restricted stock, shares		(64,762)
Tax withholding - stock compensation, shares		(136,828)
Tax withholding - stock compensation				(1)					(1)
Balance, shares at Jun. 30, 2016		392,496,825	1,725,000					31,269
Balance at Jun. 30, 2016		$ 4		3,418	(2,807)		(41)	$ (1)	573
Comprehensive income:
Net income (loss)					(708)				(708)
Other comprehensive income (loss)							2		2
Comprehensive income (loss)									(706)
Stock-based compensation				8					8
Issuance of common stock, shares		98,900,000
Issuance of common stock		$ 1		1,246					1,247
Preferred stock dividend, shares		2,100,119
Issuance of restricted stock, shares		1,140
Cancellation of restricted stock, shares		(48,534)
Tax withholding - stock compensation				1					1
Tax withholding - stock compensation, shares		(3,179)
Balance, shares at Sep. 30, 2016		493,446,371	1,725,000					31,269
Balance at Sep. 30, 2016		$ 5		4,673	(3,515)		(39)	$ (1)	1,123
Comprehensive income:
Net income (loss)					(210)				(210)
Comprehensive income (loss)									(210)
Stock-based compensation				8					8
Exercise of stock options, shares		44,880
Preferred stock dividend, shares		2,041,533
Issuance of restricted stock, shares		2,167
Cancellation of restricted stock, shares		(27,854)
Tax withholding - stock compensation, shares		(264,542)
Tax withholding - stock compensation				(4)					(4)
Issuance of stock awards, shares		5,814
Balance, shares at Dec. 31, 2016		495,248,369	1,725,000					31,269
Balance at Dec. 31, 2016		$ 5		4,677	(3,725)	[1]	(39)	$ (1)	917
Comprehensive income:
Net income (loss)					351	[1]			351
Comprehensive income (loss)									351
Stock-based compensation				10					10
Preferred stock dividend, shares		2,751,410
Issuance of restricted stock, shares		4,549,122
Cancellation of restricted stock, shares		(113,185)
Performance units vested, shares		121,208
Tax withholding - stock compensation, shares		(59,455)
Balance, shares at Mar. 31, 2017		502,497,469	1,725,000					31,269
Balance at Mar. 31, 2017		$ 5		4,687	(3,374)	[1]	(39)	$ (1)	1,278
Balance, shares at Dec. 31, 2016		495,248,369	1,725,000					31,269
Balance at Dec. 31, 2016		$ 5		4,677	(3,725)	[1]	(39)	$ (1)	$ 917
Comprehensive income:
Preferred stock dividend, shares									10,040,306
Balance, shares at Sep. 30, 2017		509,142,659	1,725,000					31,269
Balance at Sep. 30, 2017		$ 5		4,698	(3,013)	[1]	(37)	$ (1)	$ 1,652
Balance, shares at Dec. 31, 2016		495,248,369	1,725,000					31,269
Balance at Dec. 31, 2016		$ 5		4,677	(3,725)	[1]	(39)	$ (1)	917
Comprehensive income:
Net income (loss)	[2]								1,046
Other comprehensive income (loss)									(5)
Comprehensive income (loss)	[2]								1,041
Balance, shares at Dec. 31, 2017		512,134,311	1,725,000					31,269
Balance at Dec. 31, 2017		$ 5		4,698	(2,679)	[1]	(44)	$ (1)	1,979
Balance, shares at Mar. 31, 2017		502,497,469	1,725,000					31,269
Balance at Mar. 31, 2017		$ 5		4,687	(3,374)	[1]	(39)	$ (1)	1,278
Comprehensive income:
Net income (loss)					284	[1]			284
Other comprehensive income (loss)							1		1
Comprehensive income (loss)									285
Stock-based compensation				10					10
Preferred stock dividend, shares		3,346,865
Issuance of restricted stock, shares		353,803
Cancellation of restricted stock, shares		(303,135)
Tax withholding - stock compensation, shares		(1,729)
Issuance of stock awards, shares		72
Balance, shares at Jun. 30, 2017		505,893,345	1,725,000					31,269
Balance at Jun. 30, 2017		$ 5		4,697	(3,090)	[1]	(38)	$ (1)	1,573
Comprehensive income:
Net income (loss)					77	[1]			77
Other comprehensive income (loss)							1		1
Comprehensive income (loss)									78
Stock-based compensation				9					9
Preferred stock dividend, shares		3,346,738
Preferred stock dividend				(8)					(8)
Issuance of restricted stock, shares		133,197
Cancellation of restricted stock, shares		(192,810)
Tax withholding - stock compensation, shares		(37,811)
Balance, shares at Sep. 30, 2017		509,142,659	1,725,000					31,269
Balance at Sep. 30, 2017		$ 5		4,698	(3,013)	[1]	(37)	$ (1)	1,652
Comprehensive income:
Net income (loss)					334	[1]			334
Other comprehensive income (loss)							(7)		(7)
Comprehensive income (loss)									327
Stock-based compensation				9					9
Preferred stock dividend, shares		3,346,703
Preferred stock dividend				(8)					(8)
Issuance of restricted stock, shares		19,086
Cancellation of restricted stock, shares		(132,898)
Tax withholding - stock compensation, shares		(241,239)
Tax withholding - stock compensation				(1)					(1)
Balance, shares at Dec. 31, 2017		512,134,311	1,725,000					31,269
Balance at Dec. 31, 2017		$ 5		4,698	(2,679)	[1]	(44)	$ (1)	1,979
Comprehensive income:
Net income (loss)					208				208
Other comprehensive income (loss)
Comprehensive income (loss)									208
Stock-based compensation				7					7
Conversion of preferred stock, shares		74,998,614	(1,725,000)
Conversion of preferred stock		$ 1		(1)
Issuance of restricted stock, shares		5,076
Cancellation of restricted stock, shares		(160,168)
Performance units vested, shares		214,866
Tax withholding - stock compensation, shares		(338,808)
Tax withholding - stock compensation				(1)					(1)
Balance, shares at Mar. 31, 2018		586,853,891						31,269
Balance at Mar. 31, 2018		$ 6		4,703	(2,471)		(44)	$ (1)	2,193
Balance, shares at Dec. 31, 2017		512,134,311	1,725,000					31,269
Balance at Dec. 31, 2017		$ 5		4,698	(2,679)	[1]	(44)	$ (1)	1,979
Comprehensive income:
Net income (loss)									537
Other comprehensive income (loss)									8
Comprehensive income (loss)									$ 545
Treasury stock, shares									39,061,269
Treasury stock									$ (180)
Balance, shares at Dec. 31, 2018		585,407,107						39,092,537
Balance at Dec. 31, 2018		$ 6		4,715	(2,142)		(36)	$ (181)	2,362
Balance, shares at Mar. 31, 2018		586,853,891						31,269
Balance at Mar. 31, 2018		$ 6		4,703	(2,471)		(44)	$ (1)	2,193
Comprehensive income:
Net income (loss)					51				51
Other comprehensive income (loss)
Comprehensive income (loss)									51
Stock-based compensation				6					6
Issuance of restricted stock, shares		307,743
Cancellation of restricted stock, shares		(722,465)
Tax withholding - stock compensation, shares		(9,068)
Balance, shares at Jun. 30, 2018		586,430,101						31,269
Balance at Jun. 30, 2018		$ 6		4,709	(2,420)		(44)	$ (1)	2,250
Comprehensive income:
Net income (loss)					(29)				(29)
Other comprehensive income (loss)							4		4
Comprehensive income (loss)									(25)
Stock-based compensation				5					5
Issuance of restricted stock, shares		30,924
Cancellation of restricted stock, shares		(248,342)
Treasury stock, shares								4,829,011
Treasury stock								$ (25)	(25)
Tax withholding - stock compensation, shares		(17,521)
Balance, shares at Sep. 30, 2018		586,195,162						4,860,280
Balance at Sep. 30, 2018		$ 6		4,714	(2,449)		(40)	$ (26)	2,205
Comprehensive income:
Net income (loss)					307				307
Other comprehensive income (loss)							4		4
Comprehensive income (loss)									311
Stock-based compensation				3					3
Issuance of restricted stock, shares		5,819
Cancellation of restricted stock, shares		(673,147)
Treasury stock, shares								34,232,257
Treasury stock								$ (155)	(155)
Tax withholding - stock compensation, shares		(120,727)
Tax withholding - stock compensation				(2)					(2)
Balance, shares at Dec. 31, 2018		585,407,107						39,092,537
Balance at Dec. 31, 2018		$ 6		$ 4,715	$ (2,142)		$ (36)	$ (181)	$ 2,362
[1]	Includes a net cumulative-effect adjustment of $59 million related to the recognition of previously unrecognized windfall tax benefits resulting from the adoption of ASU 2016-09 as of the beginning of 2017. This adjustment increased net deferred tax assets and the related income tax valuation allowance by the same amount.
[2]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Accounting Standards Update 2016-09 [Member]
Net cumulative-effect adjustment	$ 59

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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, oil and NGL exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business and, until the Fayetteville Shale sale, its gathering business in Arkansas (“Midstream”). Southwestern conducts most of its business through subsidiaries and operates principally in two segments: E&P and Midstream. The Company also has drilling rigs located in Pennsylvania and West Virginia and provides oilfield products and services, principally serving its E&P operations.  E&P. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania and West Virginia. The Company’s operations in northeast Pennsylvania, herein referred to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern refers to its properties located in Pennsylvania and West Virginia as the “Appalachian Basin.”  Midstream. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs produced in its E&P operations.  In September 2018, the Company announced that it had signed an agreement to sell 100% of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets for $1,865 million in cash, subject to customary closing adjustments (“Fayetteville Shale sale”). The sale closed December 3, 2018 resulting in net proceeds of approximately $1,650 million, following adjustments of $215 million primarily related to the net cash flows from the economic effective date to the closing date and certain other working capital adjustments, and is discussed in further detail in Note 3 . The historical financial and operating results of the assets sold are included in these financial statements for the period of time during which we owned the assets.  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 accordance 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 2018 presentation. In the first quarter of 2018, the Company adopted ASU 2017-07 which required that all non-service costs related to the Company’s pension plan be reclassified from general and administrative expenses to other income (loss), net for all periods presented. The adoption of ASU 2017-07 resulted in a reclassification of $5 million of curtailment and settlement costs from restructuring charges to other income (loss), net on the Company’s consolidated statements of operations for the year ended December 31, 2016.  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.  In 2015, the Company purchased an 86% ownership in a limited partnership which owns and operates a gathering system in Northeast Appalachia. Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The investor’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the years ended December 31, 2018, 2017 and 2016 was insignificant.  Major Customers  The Company sells the vast majority of its E&P natural gas, oil and NGL production to third-party customers through its marketing subsidiary. For the years ended December 31, 2018 and 2017, two subsidiaries of Royal Dutch Shell Plc in aggregate accounted for approximately 10.4% and 10.3% , respectively, of total natural gas, oil and NGL sales. In 2016, no single customer accounted for 10% or greater of our total sales. The Company believes that the loss of a major customer would not have a material adverse effect on its ability to sell its natural gas, oil and NGL production because alternative purchasers are available.  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 as the Company monitors the credit status of the financial institutions holding its cash and marketable securities. The following table presents a summary of cash and cash equivalents as of December 31, 2018 and December 31, 2017:    For the years ended December 31,  (in millions) 2018 2017  Cash $ 32 $ 261  Marketable securities (1) 169 605  Other cash equivalents – 50 (2)  Total $ 201 $ 916  (1) Consists of government stable value money market funds.  (2) Consists of time deposits.  Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. 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 $34 million and $17 million as of December 31, 2018 and 2017, respectively.  Property, Depreciation, Depletion and Amortization  Natural Gas and Oil Properties . The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). 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, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. 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.  Costs associated with unevaluated properties are excluded from the amortization base until the properties are evaluated or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from the amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. The Company’s decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on several factors, including drilling plans, availability of capital, project economics and drilling results from adjacent acreage. At December 31, 2018, the Company had a t otal of $1,755 m illion of costs excluded from the amortization base, all of which related to its properties in the United States. Inclusion of some or all of these costs in the Company’s United States properties in the future, without adding any associated reserves, could result in additional ceiling test impairments.  At December 31, 2018, using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.10 per MMBtu, West Texas Intermediate oil of $65.56 per barrel and NGLs of $17.64 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, 2018. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2018.  Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.98 per MMBtu, West Texas Intermediate oil of $47.79 per barrel and NGLs of $14.41 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, 2017. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2017.  The net book value of the Company’s United States and Canada natural gas and oil properties exceeded the ceiling by approximately $641 million (net of tax) at March 31, 2016, $297 million (net of tax) at June 30, 2016 and $506 million (net of tax) at September 30, 2016 and resulted in non-cash ceiling test impairments for the quarters ended those dates. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.48 per MMBtu, West Texas Intermediate oil of $39.25 per barrel and NGLs of $6.74 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 results in a ceiling test impairment at December 31, 2016. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2016.  Gathering Systems . The Company’s investment in gathering systems was primarily in a system serving its Fayetteville Shale operations in Arkansas. These assets were included in the Fayetteville Shale sale that closed in December 2018.  Capitalized Interest . Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization.  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 the wells are no longer producing. 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 value of non-full cost pool long-lived assets is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of carrying value or fair value less costs to sell. This accounting guidance does not apply to the Company’s full cost pool assets, which are governed under SEC Regulation S-X 4-10, and thus were not classified as held for sale. Because the assets excluding the full cost pool met the criteria for held for sale accounting in the third quarter of 2018 due to their inclusion in the Fayetteville Shale sale, the Company determined the carrying value of certain non-full cost pool assets exceeded the fair value less costs to sell. As a result, an impairment charge of $160 million was recorded for the year ended December 31, 2018, of which $145 million related to midstream gathering assets held for sale and $15 million related to E&P assets held for sale. Separately, the Company recorded an $11 million impairment of other non-core assets that were not included in the Fayetteville Shale sale, for the year ended December 31, 2018.  Intangible Assets . The carrying value of intangible assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their useful life. The Company amortized $9 million of its marketing-related intangible asset in each of the years ended December 31, 2018, 2017 and 2016.  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 expected to be 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 along with the impact of recent tax reform legislation can be found in Note 10 .  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 derivative instruments to financially protect sales of natural gas, oil and NGLs. In addition, the Company uses interest rate swaps to manage exposure to unfavorable interest rate changes. Since the Company does not designate its derivatives for hedge accounting treatment, gains and losses resulting from the settlement of derivative contracts have been recognized in gain (loss) on derivatives in the consolidated statements of operations when the contracts expire and the related physical transactions of the underlying commodity are settled. Additionally, changes in the fair value of the unsettled portion of derivative contracts are also recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 5 – “Derivatives and Risk Management” and Note 7 – “Fair Value Measurements” f or 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 common stock by the weighted average number of common shares outstanding during the reportable period. 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, the vesting of unvested restricted shares of common stock, performance units and the assumed conversion of mandatory convertible preferred stock. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.  In July 2016, the Company completed an underwritten public offering of 98,900,000 shares of its common stock, with an offering price to the public of $13.00 per share. Net proceeds from the common stock offering were approximately $1,247 million, after underwriting discount and offering expenses. The proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in 2018. The remaining proceeds of the offering were used for general corporate purposes.  In January 2015, the Company issued 34,500,000 depositary shares that entitled the holder to a proportional fractional interest in the rights and preferences of the mandatory convertible preferred stock, including conversion, dividend, liquidation and voting rights. The mandatory convertible preferred stock had the non-forfeitable right to participate on an as-converted basis at the conversion rate then in effect in any common stock dividends declared and, therefore, was considered a participating security. Accordingly, it has been included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the calculation of basic earnings per share attributable to common shareholders, earnings are allocated to participating securities based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. On January 12, 2018, all outstanding shares of mandatory convertible preferred stock were converted to 74,998,614 shares of the Company’s common stock.  The Company declared dividends on its mandatory convertible preferred stock in the first, second and third quarters of 2017 that were settled partially in common stock for a total of 10,040,306 shares as well as each quarter in 2016 that were settled in common stock for a total of 9,917,799 shares.  In 2018, the Company repurchased 39,061,269 of its outstanding common stock for approximately $180 million at an average price of $4.63 per share.  The following table presents the computation of earnings per share for the years ended December 31, 2018, 2017 and 2016:    For the years ended December 31,  (in millions, except share/per share amounts) 2018 2017 2016  Net income (loss) $ 537 $ 1,046 $ (2,643)  Mandatory convertible preferred stock dividend – 108 108  Participating securities – mandatory convertible preferred stock 2 123 –  Net income (loss) attributable to common stock $ 535 $ 815 $ (2,751)   Number of common shares:  Weighted average outstanding 574,631,756 498,264,321 435,337,402  Issued upon assumed exercise of outstanding stock options – – –  Effect of issuance of non-vested restricted common stock 698,103 1,061,056 –  Effect of issuance of non-vested performance units 1,312,949 1,478,920 –  Weighted average and potential dilutive outstanding 576,642,808 500,804,297 435,337,402   Earnings (loss) per common share:  Basic $ 0.93 $ 1.64 $ (6.32)  Diluted $ 0.93 $ 1.63 $ (6.32)  The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2018, 2017 and 2016, as they would have had an antidilutive effect:    For the years ended December 31,  2018 2017 2016  Unexercised stock options 5,909,082 116,717 3,692,697  Unvested share-based payment 3,692,794 5,361,849 959,233  Performance units 642,568 765,689 884,644  Mandatory convertible preferred stock 2,465,708 74,999,895 74,999,895  Total 12,710,152 81,244,150 80,536,469  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, 2018, 2017 and 2016:    For the years ended December 31,  (in millions) 2018 2017 2016  Cash paid during the year for interest, net of amounts capitalized $ 135 $ 130 $ 75  Cash paid (received) during the year for income taxes 6 (5) (15)  Increase (decrease) in noncash property additions (42) 25 55  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. See Note 13 for a discussion of the Company’s stock-based compensation.  Liability-Classified Awards  The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense or capitalized expense over the vesting period of the award. The Company’s liability-classified performance unit awards include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute total shareholder return and the other on relative total shareholder return as compared to a group of the Company’s peers. The fair values of the two market conditions are calculated by Monte Carlo models on a quarterly basis.  Treasury Stock  In the third quarter of 2018, the Company announced its intention to repurchase up to $200 million of its outstanding common stock using a portion of the net proceeds from the Fayetteville Shale sale. As of December 31, 2018, approximately $180 million has been spent to repurchase 39,061,269 shares at an average price of $4.63 per share.  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 liabilities 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, are presented as treasury stock and are carried at cost. As of December 31, 2018 and 2017, 10,653 shares and 31,269 shares, respectively, were held in the Rabbi Trust and were accounted for as treasury stock. In 2018, 20,616 shares were released from the Rabbi Trust due to a reduction in our workforce. These shares are still held as treasury stock.  Foreign Currency Translation  The Company has designated the Canadian dollar as the functional currency for its activities 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 other comprehensive income within stockholders’ equity.  New Accounting Standards Implemented in this Report  In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606, as subsequently amended). ASC 606 supersedes the revenue recognition requirements in topic 605, Revenue Recognition, and requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which an entity expects to be entitled to in exchange for those goods or services. The Company adopted ASC 606 with an effective date of January 2018 using the modified retrospective approach. For public entities, ASC 606 became effective for fiscal years beginning after December 15, 2017. The adoption of this standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows. Additional disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flow from contracts with customers are available in Note 4 – “Revenue Recognition” .  In March 2017, the FASB issued Accounting Standards Update No. 2017-07, Compensation - Retirement Benefits (Topic 715) (“Update 2017-07”), which provides additional guidance on the presentation of net benefit cost in the statement of operations and on the components eligible for capitalization in assets, and requires retrospective adoption. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of the net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The Company adopted Update 2017-07 during the first quarter of 2018 resulting in no material impact to its consolidated statement of operations, financial position or cash flows. The non-service cost components of net periodic benefit cost are no longer presented as a component of general and administrative expense, but are now presented as a component of Other Income, Net for the years ended December 31, 2018, 2017 and 2016, and are disclosed in Note 12 – “Retirement and Employment Benefit Plans” . The Company ceased capitalizing the non-service components of net periodic benefit costs prospectively as of the beginning of the first quarter of 2018.  In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (Topic 230) (“Update 2016-15”), which seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The Company adopted this update during the first quarter of 2018 resulting in no impact on its consolidated statement of cash flows.  In February 2018, the FASB issued Accounting Standards Update No. 2018-02 that will amend the FASB Accounting Standards relating to tax effects in accumulated other comprehensive income (Topic 220) (“Updated 2018-02”). Update 2018-02 permits a company to reclassify the stranded income tax effects of the Tax Reform Act on items within accumulated comprehensive income to retained earnings. Although the amendments in Update 2018-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, the Company elected to early adopt the amendments of Update 2018-02 in the third quarter of 2018. The implementation did not have a material impact on the Company’s consolidated statement of operations, financial position or cash flows due to the tax valuation allowance currently in place. Any adjustments required under this update were fully offset by valuation allowance adjustments for both continuing operations and accumulated other comprehensive income.  New Accounting Standards Not Yet Implemented in this Report  In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“Update 2016-02”), which seeks to increase transparency and comparability among organizations by, among other things, recognizing lease assets and lease liabilities on the balance sheet for leases classified as operating leases under previous GAAP and disclosing key information about leasing arrangements. The codification was amended through additional ASUs. Through the year ended December 31, 2018 , the Company finalized its contract reviews for leases in effect at year-end, drafted its accounting policies, evaluated the new disclosure requirements and implemented a software solution. Upon adoption, the Company expects to recognize a discounted right-of-use asset and corresponding lease liability between $95 million and $115 million. The Company continues to review new contracts commenced during 2019 to determine the appropriate lease accounting treatment where applicable.  ASC 842 allows issuers to elect the date of initial application as either the beginning of the period of adoption or the beginning of the earliest comparative period presented in the financial statements. The Company plans to elect the period of adoption, January 1, 2019, as its initial application date which would not result in restating prior comparative periods. The adoption of this standard is not expected to materially change the Company’s consolidated statement of operations or its consolidated statement of cash flows. The Form 10-Q filing for the quarter ended March 31, 2019 will include the full impact of ASC 842, along with the presentation of the discounted right-of-use asset and lease liability on the consolidated balance sheet.

Restructuring Charges

Restructuring Charges	12 Months Ended
	Dec. 31, 2018
Restructuring Charges [Abstract]
Restructuring Charges	(2) RESTRUCTURING CHARGES  The following table presents a summary of the restructuring charges included in Operating Income (Loss) for the years ended December 31, 2018, 2017 and 2016:     For the years ended December 31,  (in millions) 2018 (1) 2017 2016 (2)  Reduction in workforce $ 23 $ – $ 73  Fayetteville Shale sale-related 16 – –  Total restructuring charges $ 39 $ – $ 73  (1) Does not include a $4 million gain for the year ended December 31, 2018 related to curtailment of the other postretirement benefit plan presented in other income (loss), net on the consolidated statements of operations.  (2) Does not include a $5 million net loss for the year ended December 31, 2016 related to the curtailment and settlement of the pension and other postretirement benefit plans presented in other income (loss), net on the consolidated statements of operations.  The following table presents a summary of liabilities associated with the Company’s restructuring activities at December 31, 2018, which are reflected in accounts payable on the consolidated balance sheet:     (in millions)  Liability at December 31, 2017 $ –  Additions 39  Distributions 34  Liability at December 31, 2018 $ 5  Reduction in Workforce  In June 2018, the Company notified affected employees of a workforce reduction plan, which resulted primarily from a previously announced study of structural, process and organizational changes to enhance shareholder value and continues with respect to other aspects of the Company’s business activities. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were forfeited. Although the plan was substantially implemented by the end of 2018, certain employees were retained into 2019. As of December 31, 2018, a liability of $1 million for severance payments has been accrued related to the reduction in workforce.  In January 2016, the Company announced a 40% workforce reduction as a result of lower anticipated drilling activity. This reduction was substantially completed in the first quarter of 2016. In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016. Severance payments and other separation costs related to restructuring were substantially completed by the end of 2016.  The following table presents a summary of the restructuring charges related to workforce reduction plans included in Operating Income (Loss) for the years ended December 31, 2018, 2017 and 2016:    For the years ended December 31,  (in millions) 2018 2017 2016 (1)  Severance (including payroll taxes) $ 21 $ – $ 44  Stock-based compensation – – 24  Other benefits – – 3  Outplacement services, other 2 – 2  Total reduction in workforce-related restructuring charges (2) $ 23 $ – $ 73  (1) Does not include $5 million non-cash charges related to the curtailment and settlement of the pension and other postretirement benefit plans for the year ended December 31, 2016 presented in other income (loss), net in the consolidated statements of operations. See Note 12 for additional details regarding the Company’s retirement and employee benefit plans.  (2) Total restructuring charges were $21 million and $2 million for the Company’s E&P and Midstream segments, respectively, for the year ended December 31, 2018 and $70 million and $3 million for the Company’s E&P and Midstream segments, respectively, for the year ended December 31, 2016.  Fayetteville Shale Sale-Related  In December 2018, the Company closed on the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, most employees associated with those assets became employees of the buyer although the employment of some was, or will be, terminated. All affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were forfeited. Additionally, a small number of employees have been retained to provide assistance through the divestiture transition period and will receive a similar severance package upon the deferred termination of their employment. As of December 31, 2018, a liability of $4 million for severance payments has been accrued related to remaining Fayetteville Shale sale-related employment terminations.  As a result of the Fayetteville Shale sale, the Company relocated certain employees and infrastructure to other areas. In addition to personnel-related costs, the Company has also incurred charges related to office consolidation and has recognized these costs as restructuring charges. The following table presents a summary of the restructuring charges related to Fayetteville Shale sale included in Operating Income (Loss) for the year ended December 31, 2018:     For the year ended  (in millions) December 31, 2018  Severance (including payroll taxes) $ 12  Office consolidation 4  Total Fayetteville Shale sale-related charges (1) (2) $ 16  (1) Total restructuring charges were $16 million for the Company’s E&P segment for the year ended December 31, 2018.  (2) Does not include a $4 million gain for the year ended December 31, 2018 related to the curtailment of the other postretirement benefit plan presented in other income (loss), net on the consolidated statements of operations. 

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2018
Divestitures [Abstract]
Divestitures	(3) DIVESTITURES  O n August 30, 2018, the Company entered into a n agreement with Flywheel Energy Operating, LLC to sell 100% of the equity in the Company’s subsidiaries that own ed and operate d its Fayetteville Shale E&P and related midstream gathering assets for $1,865 m illion in cash, subject to customary closing adjustments, with an economic effective date of July 1, 2018. During the third quarter of 2018, the Company classified the non-full cost pool portion of these assets as held for sale and recorded an impairment charge o f $160 m illion, of which $145 million related to midstream gathering assets held for sale and $15 million related to E&P assets held for sale.  On December 3, 2018, the Company closed on the Fayetteville Shale sale and received approximatel y $1,650 m illion, which include d preliminary purchase price adjustments of approximately $215 million primarily related to the net cash flows from the economic effective date to the closing date. The Company allocated the sale proceeds to gain on sale for the non-full cost pool assets and to capitalized costs for the full cost pool assets based on the proportion of the estimated fair values of the underlying assets. The fair values of these assets was estimated primarily using an income approach. Consequently, the Company recognized a gain on the sale of non-full cost pool assets of $17 million and a reduction of $887 million to its full cost pool assets. A s the sale did not involve a significant change in proved reserves or significantly alter the relationship between capitalized costs and proved reserves, the Company recognized no gain or loss related to the full cost pool assets sold.  As part of the Fayetteville Shale sale agreement, the Company entered into c ertain natural gas derivative positions which were subsequently novated to the buyer in conjunction with finalization of the sale. The unrealized fair value of these derivatives at the closing of the sale in December 2018 was a net liability of $151 million which was transferred to the buyer. The unrealized loss associated with the novated position s was offset by the gain that the Company recognized when the liability was transferred to the buyer. These offsetting amounts were recognized on the consolidated statements of operations in G ain on sale of assets , net . In addition, t h e Company paid $22 million in premiums for these novated derivatives which was recorded as a loss in Gain on sale of assets, net in 2018.  T he Company retained certain contractual commitments related to firm transportation, with the buyer obligated to pay the transportation provider directly for these charges. As of December 31, 2018, approximately $221 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $102 million through 2020 depending on the buyer’s actual use , and has recorded an $88 million liability for the estimated future payments. The buyer will also assume future asset retirement obligations related to the operations sold.  From the proceeds received, $914 million was used to repurchase $900 million of the Company’s outstanding senior notes, including premiums and $9 million in accrued interest paid, and $ 180 million was used to repurchase approximately 39 million shares of the Company’s outstanding common stock as of December 31, 2018. The Company intends to use the remaining net proceeds from the sale to supplement Appalachian Basin development, return capital to shareholders and for general corporate purposes.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2018
Revenue Recognition [Abstract]
Revenue Recognition	(4 ) REV ENUE RECOGNITION  Effective January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606, “Revenue from Contracts with Customers,” using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Under the modified retrospective method, The Company recognizes the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no material adjustment was required as a result of adopting ASC 606. Results for reporting periods beginning on January 1, 2018 are presented under the new revenue standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The Company performed an analysis of the impact of adopting ASC 606 across all revenue streams and did not identify any changes to its revenue recognition policies that would result in a material impact to its consolidated financial statements.  Revenues from Contracts with Customers  Natural gas and liquids . Natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions in the geographic areas in which the Company operates. Under the Company’s sales contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. There is no significant financing component to the Company’s revenues as payment terms are typically within 30 to 60 days of control transfer. Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognizes revenue in the amount to which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.  The Company records revenue from its natural gas and liquids production in the amount of its net revenue interest in sales from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under-delivered volumes. Production imbalances are generally recorded as receivables and payables and not contract assets or contract liabilities as the imbalances are between the Company and other working interest owners, not the end customer.  Marketing . The Company, through its marketing affiliate, generally markets natural gas, oil and NGLs for its affiliated E&P companies as well as other joint owners who choose to market with Southwestern. In addition, the Company markets some products purchased from third parties. Marketing revenues for natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions. Under the Company’s marketing contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. Customers are invoiced and revenues are recorded each month as natural gas, oil and NGLs are delivered, and payment terms are typically within 30 to 60 days of control transfer. Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognizes revenue in the amount to which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.  Gas gathering . Prior to the Fayetteville Shale sale, the Company, through a subsidiary included in the Fayetteville Shale sale, gathered natural gas in Arkansas pursuant to a variety of contracts with customers, including an affiliated E&P company. The performance obligations for gas gathering services included delivery of each unit of natural gas to the designated delivery point, which may include treating of certain natural gas units to meet interstate pipeline specifications. Revenue was recognized at the point in time when performance obligations were fulfilled. Under the Company’s gathering contracts, customers were invoiced and revenue was recognized each month based on the volume of natural gas transported and treated at a contractually agreed upon price per unit. Payment terms were typically within 30 to 60 days of completion of the performance obligations. Furthermore, consideration from a customer corresponded directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognized revenue in the amount to which the Company had a right to invoice and therefore had not disclosed information regarding its remaining performance obligations. Any imbalances were settled on a monthly basis by cashing-out with the respective shipper. Accordingly, there were no contract assets or contract liabilities related to the Company’s gas gathering revenues. The natural gas gathering operations in Arkansas were included in the Fayetteville Shale sale that closed in December 2018.  Disaggregation of Revenues  The Company presents a disaggregation of E&P revenues by product in the consolidated statements of operations net of intersegment revenues. The following table reconciles operating revenues as presented on the consolidated statements of operations to the operating revenues by segment:    Intersegment  (in millions) E&P Midstream Revenues Total  Year ended December 31, 2018  Gas sales $ 1,974 $ – $ 24 $ 1,998  Oil sales 193 – 3 196  NGL sales 353 – (1) 352  Marketing – 3,497 (2,275) 1,222  Gas gathering (1) – 248 (159) 89  Other (2) 5 – – 5  Total $ 2,525 $ 3,745 $ (2,408) $ 3,862   Year ended December 31, 2017  Gas sales $ 1,775 $ – $ 18 $ 1,793  Oil sales 101 – 1 102  NGL sales 206 – – 206  Marketing – 2,867 (1,895) 972  Gas gathering – 331 (205) 126 Other (2) 4 – – 4  Total $ 2,086 $ 3,198 $ (2,081) $ 3,203   Year ended December 31, 2016  Gas sales $ 1,252 $ – $ 21 $ 1,273  Oil sales 69 – – 69  NGL sales 92 – – 92  Marketing – 2,191 (1,327) 864  Gas gathering – 378 (240) 138  Total $ 1,413 $ 2,569 $ (1,546) $ 2,436  (1) The Company’s gas gathering assets were divested in December 2018 as part of the Fayetteville Shale sale. (2) Other E&P revenues consists primarily of water sales to third-party operators.  Associated E&P revenues are also disaggregated for analysis on a geographic basis by the core areas in which the Company operates, which are in Pennsylvania and West Virginia. Operations in northeast Pennsylvania are referred to as “Northeast Appalachia,” operations in West Virginia and southwest Pennsylvania are referred to as “Southwest Appalachia.” In December 2018, the Company sold 100% of its Fayetteville Shale assets. See Note 3 for more details.     For the year ended December 31,  (in millions) 2018 2017 2016  North ea st Appalachia $ 1,165 $ 837 $ 470  Southwest Appalachia 817 498 259  Fayetteville Shale 537 743 675  Other 6 8 9  Total $ 2,525 $ 2,086 $ 1,413  Receivables from Contracts with Customers  The following table reconciles the Company’s receivables from contracts with customers to consolidated accounts receivable as presented on the consolidated balance sheet:     (in millions) December 31, 2018 December 31, 2017  Receivables from contracts with customers $ 494 $ 322  Other accounts receivable 87 106  Total accounts receivable $ 581 $ 428  Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the years ended December 31, 2018 and 2017. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.  

Derivatives and Risk Management

Derivatives and Risk Management	12 Months Ended
	Dec. 31, 2018
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, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of December 31, 2018, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, call options and interest rate swaps. During 2016, the Company settled all of its purchased put options. A description of the Company’s derivative financial instruments is provided below:   Fixed price swaps If the Company sells a fixed price swap, the Company receives a fixed price for the contract and pays a floating market to the counterparty. If the Company purchases a fixed price swap, the Company receives a floating market price for the contract and pays a fixed price to the counterparty. Two-way costless collars Arrangements that contain a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price. Three-way costless collars Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price. Basis swaps Arrangements that guarantee a price differential for natural gas from a specified delivery point. If the Company sells a basis swap, 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. If the Company purchases a basis swap, the Company pays the counterparty if the price differential is greater than the state terms of the contract and receives a payment from the counterparty if the price differential is less than the stated terms of the contract. Call options The Company purchases and sells call options in exchange for a premium. If the Company purchases a call option, the Company receives from the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company sells a call option, the Company pays the counterparty the excess (if any) of the market price over the strike price at the time of settlement, but if the market price is below the call’s strike price, 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.  The Company chooses counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company actively monitors the credit ratings and credit default swap rates of these counterparties where applicable. However, there can be no assurance that a counterparty will be able to meet its obligations to the Company. The Company presents its derivative positions on a gross basis and does not net the asset and liability positions where counterparty netting arrangements contain provisions for net settlement.  As part of the Fayetteville Shale sale agreement, the Company entered into c ertain natural gas derivative positions which were subsequently novated to the buyer in conjunction with finalization of the sale. The unrealized fair value of these derivatives at the closing of the sale in December 2018 was a net liability of $151 million which was transferred to the buyer. The unrealized loss associated with the novated position s was offset by the gain that the Company recognized when the liability was transferred to the buyer. These offsetting amounts were recognized on the consolidated statements of operations in G ain on sale of assets , net . In addition, t h e Company paid $22 million in premiums for these novated derivatives which was recorded as a loss in Gain on sale of assets, net in 2018. The derivatives that were novated to the buyer are not included in the tables below.  The following table provides information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The table presents the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of December 31, 2018:  Financial Protection on Production    Weighted Average Price per MMBtu  Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Fair value at December 31, 2018 ($ in millions)  Natural Gas  2019  Fixed price swaps 220 $ 2.93 $ – $ – $ – $ – $ 23  Two-way costless collars 53 – – 2.80 2.98 – 4  Three-way costless collars 170 – 2.48 2.90 3.28 – 8  Total 443 $ 35  2020  Fixed price swaps 24 $ 2.88 $ – $ – $ – $ – $ 5  Three-way costless collars 84 – 2.40 2.73 3.03 – –  Total 108 $ 5  2021  Three-way costless collars 37 $ – $ 2.35 $ 2.60 $ 2.93 $ – $ (1)   Basis swaps  2019 107 $ – $ – $ – $ – $ (0.29) $ (10)  2020 59 – – – – (0.44) (1)  Total 166 $ (11)    Weighted Average Price per Bbl  Volume (MBbls) Swaps Purchased Puts Sold Calls Fair value at December 31, 2018 ($ in millions)  Oil  2019  Fixed price swaps (1) 346 $ 68.74 $ – $ – $ 7  Two-way costless collars 329 – 65.00 72.30 6  Total 675 $ 13  2020  Fixed price swaps 366 $ 65.68 $ – $ – $ 6  Two-way costless collars 366 – 60.00 69.80 4  Total 732 $ 10   Propane  2019  Fixed price swaps 1,689 $ 33.12 $ – $ – $ 11   Ethane  2019  Fixed price swaps 3,687 $ 13.90 $ – $ – $ 4  2020  Fixed price swaps 732 $ 13.49 $ – $ – $ 1  (1) Includes 274 MBbls of purchased fixed price oil swaps hedged at $69.10 per barrel with a fair value of ( $6 ) million and 620 MBbls of sold fixed price oil swaps hedged at $68.90 with a fair value of $13 million.    Other Derivative Contracts  Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2018 ($ in millions)  Purchased Call Options – Natural Gas  2020 68 $ 3.63 $ 4  2021 57 3.52 2  Total 125 $ 6   Sold Call Options – Natural Gas  2019 52 $ 3.50 $ (3)  2020 137 3.39 (12)  2021 114 3.33 (7)  Total 303 $ (22)   Volume (MBbls) Weighted Average Strike Price per Bbl Fair Value at December 31, 2018 ($ in millions)  Sold Call Options – Oil  2019 270 $ 65.00 $ –    Volume (Bcf) Weighted Average Strike Price per MMBtu Basis Differential Fair Value at December 31, 2018 ($ in millions)  Storage (1)  2019  Fixed price swaps 0.8 $ 3.03 $ – $ –  Basis swaps 0.8 – (0.44) –  Total $ –  (1) The Company has entered into certain derivatives to protect the value of volumes of natural gas injected into a storage facility that will be withdrawn at a later date.  At December 31, 2018, the net fair value of the Company’s financial instruments related to commodities was a $51 million asset. The net fair value of the Company’s interest rate swaps was a $1 milli on asset as of December 31, 2018.  As of December 31, 2018, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled derivatives. The Company calculates gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period. Only the settled gains and losses are included in the Company’s realized commodity price calculations.  The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps have a notional amount of $170 million and expire in June 2020 . The Company did not designate the interest rate swaps for hedge accounting treatment. Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives on the consolidated statements of operations.  The balance sheet classification of the assets and liabilities related to derivative financial instruments (none of which are designated for hedge accounting treatment) are summarized below as of December 31, 2018 and 2017:    Derivative Assets  Balance Sheet Classification Fair Value  (in millions) December 31, 2018 December 31, 2017  Derivatives not designated as hedging instruments:  Fixed price swap – natural gas Derivative assets $ 32 $ 38  Fixed price swap – oil Derivative assets 13 –  Fixed price swap – propane Derivative assets 11 –  Fixed price swap – ethane Derivative assets 7 –  Two-way costless collar – natural gas Derivative assets 11 5  Two-way costless collar – oil Derivative assets 6 –  Three-way costless collar – natural gas Derivative assets 41 82  Basis swap – natural gas Derivative assets 8 2  Purchased call option – natural gas Derivative assets – 3 (1)  Interest rate swap Derivative assets 1 –  Fixed price swap – natural gas Other long-term assets 6 18  Fixed price swap – oil Other long-term assets 6 –  Fixed price swap – ethane Other long-term assets 1 –  Two-way costless collar – oil Other long-term assets 5 –  Three-way costless collar – natural gas Other long-term assets 34 39  Basis swap – natural gas Other long-term assets 3 –  Purchased call options – natural gas Other long-term assets 6 –  Total derivative assets $ 191 $ 187    Derivative Liabilities  Balance Sheet Classification Fair Value  (in millions) December 31, 2018 December 31, 2017  Derivatives not designated as hedging instruments:  Purchased fixed price swap – oil Derivative liabilities $ 6 $ –  Fixed price swap – natural gas Derivative liabilities 9 –  Fixed price swap – ethane Derivative liabilities 3 –  Two-way costless collar – natural gas Derivative liabilities 7 1  Three-way costless collar – natural gas Derivative liabilities 33 36  Basis swap – natural gas Derivative liabilities 18 23  Sold call option – natural gas Derivative liabilities 3 3  Interest rate swap Derivative liabilities – 1  Fixed price swap – natural gas Other long-term liabilities 1 1  Two-way costless collar – oil Other long-term liabilities 1 –  Three-way costless collar – natural gas Other long-term liabilities 35 30  Basis swap – natural gas Other long-term liabilities 4 –  Sold call option – natural gas Other long-term liabilities 19 15  Total derivative liabilities $ 139 $ 110  (1) Includes $1 million in premiums paid related to certain natural gas call options recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2017. As certain natural gas call options settled, the premium was amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations. The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the years ended December 31, 2018 and 2017:    Unsettled Gain (Loss) on Derivatives Recognized in Earnings  Consolidated Statement of Operations For the years ended  Classification of Gain (Loss) December 31,  Derivative Instrument on Derivatives, Unsettled 2018 2017  (in millions)  Purchased fixed price swap – oil Gain (Loss) on Derivatives $ (6) $ –  Fixed price swap – natural gas Gain (Loss) on Derivatives (27) 232  Fixed price swap – oil Gain (Loss) on Derivatives 19 –  Fixed price swap – propane Gain (Loss) on Derivatives 11 –  Fixed price swap – ethane Gain (Loss) on Derivatives 5 –  Two-way costless collar – natural gas Gain (Loss) on Derivatives – 52  Two-way costless collar – oil Gain (Loss) on Derivatives 10 –  Three-way costless collar – natural gas Gain (Loss) on Derivatives (48) 136  Basis swap – natural gas Gain (Loss) on Derivatives 10 (36)  Purchased call option – natural gas Gain (Loss) on Derivatives 4 2  Sold call option – natural gas Gain (Loss) on Derivatives (4) 63  Interest rate swap Gain (Loss) on Derivatives 2 2  Total gain (loss) on unsettled derivatives $ (24) $ 451   Settled Gain (Loss) on Derivatives Recognized in Earnings (1)  Consolidated Statement of Operations For the years ended  Classification of Gain (Loss) December 31,  Derivative Instrument on Derivatives, Settled 2018 2017  (in millions)  Fixed price swap – natural gas Gain (Loss) on Derivatives $ (32) $ (9)  Fixed price swap – propane Gain (Loss) on Derivatives (6) –  Fixed price swap – ethane Gain (Loss) on Derivatives (8) –  Two-way costless collar – natural gas Gain (Loss) on Derivatives (1) –  Three-way costless collar – natural gas Gain (Loss) on Derivatives (9) (1)  Basis swap – natural gas Gain (Loss) on Derivatives (31) (6)  Purchased call option – natural gas Gain (Loss) on Derivatives 2 (2) –  Sold call option – natural gas Gain (Loss) on Derivatives (7) (11) (3)  Sold call option – oil Gain (Loss) on Derivatives (2) –  Interest rate swap Gain (Loss) on Derivatives – (2)  Total loss on settled derivatives $ (94) $ (29)   Total gain (loss) on derivatives $ (118) $ 422  (1) The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.  (2) Includes $1 million amortization of premiums paid related to certain natural gas call options for the year ended December 31, 2018, which is included in gain (loss) on derivatives on the consolidated statement of operations.  (3) Includes $5 million amortization of premiums paid related to certain call options for the year ended December 31, 2017.

Reclassifications from Accumula

Reclassifications from Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2018
Reclassifications from Accumulated Other Comprehensive Income (Loss) [Abstract]
Reclassifications from Accumulated Other Comprehensive Income (Loss)	(6) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)  The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects, for the year ended December 31, 2018:   For the year ended December 31, 2018  (in millions) Pension and Other Postretirement Foreign Currency Total  Beginning balance, December 31, 2017 $ (30) $ (14) $ (44)  Other comprehensive (loss) before reclassifications (2) − (2)  Amounts reclassified from other comprehensive income (1) (2) 10 – 10  Net current-period other comprehensive income 8 − 8  Ending balance, December 31, 2018 $ (22) $ (14) $ (36)  (1) Deferred tax activity related to pension and other postretirement benefits was offset by a valuation allowance, resulting in no tax expense recorded for the period.  (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, 2018  (in millions)  Pension and other postretirement:  Amortization of prior service cost and net loss (1) Other Income (Loss), Net $ 10  Provision (benefit) for income taxes (2) −  Net income $ 10   Total reclassifications for the period Net income $ 10  (1) See Note 12 for additional details regarding the Company’s pension and other postretirement benefit plans.  (2) Deferred tax activity related to pension and other postretirement benefits was offset by a valuation allowance, resulting in no tax expense recorded for the period.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Measurements [Abstract]
Fair Value Measurements	(7) FAIR VALUE MEASUREMENTS  Assets and liabilities measured at fair value on a recurring basis  The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2018 and 2017 were as follows:     December 31, 2018 December 31, 2017  Carrying Fair Carrying Fair  (in millions) Amount Value Amount Value  Cash and cash equivalents $ 201 $ 201 $ 916 $ 916  2018 revolving credit facility due April 2023 – – – –  2016 term loan facility due December 2020 (1) (2) – – 1,191 1,191  Senior notes (1) (3) 2,342 2,190 3,242 3,358  Derivative instruments, net 52 52 77 (4) 77 (4)  (1) Excludes unamortized debt issuance costs and debt discounts.  (2) In April 2018, the Company replaced its 2016 credit facility with a new 2018 credit facility and repaid the $1,191 million secured term loan balance in full.  (3) In December 2018, the Company repurchased $900 million of certain of its outstanding senior notes with a portion of the net proceeds from the Fayetteville Shale sale.  (4) Includes $1 million in premiums paid related to certain natural gas call options recognized as a component of derivative assets within current assets on the consolidated balance sheet.  The carrying values of cash and cash equivalents, including marketable securities, accounts receivable, other current assets, accounts payable and other 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 value of the Company’s publicly traded debt as determined based on the market prices of the Company’s senior notes. These instruments were previously classified as a Level 2 measurement but substantially all senior notes were updated to a Level 1 in the second quarter of 2018 as the market activity of the Company’s debt has resulted in timely quoted prices. The 4.05% Senior Notes due January 2020 remain a Level 2 measurement due to relative market inactivity.  The carrying values of the borrowings under the Company’s revolving credit facility (to the extent utilized) and previous 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 revolving credit facility to be a Level 1 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 fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the NYMEX futures index for natural gas and oil derivatives and Oil Price Information Services (“OPIS”) for ethane and propane derivatives. The Company utilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2018 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 call options, two-way costless collars and three-way costless collars (Level 2) 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 and OPIS futures index, interest rates, volatility and credit worthiness. The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves. These instruments were previously classified as a Level 3 measurement in the fair value hierarchy but were updated to a Level 2 measurement in the second quarter of 2018 as a result of the Company’s ability to derive volatility inputs and forward commodity price curves from directly observable sources.  Inputs to the Black-Scholes model, including the volatility input are obtained from a third-party pricing source, with independent verification of the most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively.  Assets and liabilities measured at fair value on a recurring basis are summarized below:     December 31, 2018  Fair Value Measurements Using:  (in millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets (Liabilities) at Fair Value  Assets  Fixed price swap – natural gas $ – $ 38 $ – $ 38  Fixed price swap – oil – 19 – 19  Fixed price swap – propane – 11 – 11  Fixed price swap – ethane – 8 – 8  Two-way costless collar – natural gas – 11 – 11  Two-way costless collar – oil – 11 – 11  Three-way costless collar – natural gas – 75 – 75  Basis swap – natural gas – 11 – 11  Purchased call option – natural gas – 6 – 6  Interest rate swap – 1 – 1  Liabilities  Purchased fixed price swap – oil – (6) – (6)  Fixed price swap – natural gas – (10) – (10)  Fixed price swap – ethane – (3) – (3)  Two-way costless collar – natural gas – (7) – (7)  Two-way costless collar – oil – (1) – (1)  Three-way costless collar – natural gas – (68) – (68)  Basis swap – natural gas – (22) – (22)  Sold call option – natural gas – (22) – (22)  Total $ – $ 52 $ – $ 52     December 31, 2017  Fair Value Measurements Using:  (in millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets (Liabilities) at Fair Value  Assets  Fixed price swap – natural gas $ – $ 56 $ – $ 56  Two-way costless collar – natural gas – – 5 5  Three-way costless collar – natural gas – – 121 121  Purchased call option – natural gas (1) – – 3 3  Basis swap – natural gas – – 2 2  Liabilities  Fixed price swap – natural gas – (1) – (1)  Two-way costless collar – natural gas – – (1) (1)  Three-way costless collar – natural gas – – (66) (66)  Basis swap – natural gas – – (23) (23)  Sold call option – natural gas – – (18) (18)  Interest rate swap – (1) – (1)  Total $ – $ 54 $ 23 $ 77  (1) Includes $1 million in premiums paid related to certain natural gas call options recognized as a component of derivative assets within current assets on the consolidated balance sheets at December 31, 2017.  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, 2018 and 2017. 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 consisted of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflected reasonable assumptions a marketplace participant would have used as of December 31, 2018 and 2017.       For the years ended  December 31,  (in millions) 2018 2017  Balance at beginning of year $ 22 $ (195)  Total gains (losses):  Included in earnings (17) 199  Settlements (1) 1 18  Transfers into/out of Level 3 (2) (6) –  Balance at end of period $ – $ 22  Change in gains (losses) included in earnings relating to derivatives still held as of December 31 $ – $ 217  (1) Includes $1 million and $5 million amortization of premiums paid related to certain natural gas call options for the years ended December 31, 2018 and 2017, respectively.  (2) Commodity derivatives previously presented as Level 3 were transferred to Level 2 in the second quarter of 2018 as the Company moved from using proprietary volatility inputs and forward curves to more widely available published information, increasing market observability.  See Note 12 for a discussion of the fair value measurement of the Company’s pension plan assets.  Assets and liabilities measured at fair value on a nonrecurring basis  As further discussed in Note 3 , the Company’s announcement of the Fayetteville Shale sale resulted in the reclassification of certain related assets and liabilities to held for sale on its balance sheet in the third quarter of 2018. Because the non-full cost pool assets met the criteria for held for sale accounting in the third quarter of 2018 due to their inclusion in the Fayetteville Shale sale, the Company determined the carrying value of certain non-full cost pool assets exceeded the carrying value less costs to sell. As a result, an impairment charge of $160 million was recorded for the year ended December 31, 2018, of which $145 million related to midstream gathering assets held for sale and $15 million related to E&P assets held for sale. Separately, the Company recorded an $11 million impairment of other non-core assets that were not included in the Fayetteville Shale sale, for the year ended December 31, 2018. The estimated fair value of the gathering assets was based on an estimated discounted cash flow model and market assumptions. The significant Level 3 assumptions used in the calculation of estimated discounted cash flows included in future rates of production, inflation factors and risk adjusted discount rates. These impairments are included in Net Income (Loss) from Operations in the accompanying consolidated statements of operations. On December 3, 2018, the Company closed on the Fayetteville Shale sale. Consequently, the Company recognized a net gain on the sale of non-full cost pool assets of $17 million, which consisted of a gain on the Midstream segment of $35 million and a loss on the E&P segment of $18 million.

Debt

Debt	12 Months Ended
	Dec. 31, 2018
Debt [Abstract]
Debt	(8) DEBT  The components of debt as of December 31, 2018 and 2017 consisted of the following:    December 31, 2018  (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total  Variable rate ( 3.920% at December 31, 2018) 2018 revolving credit facility, due April 2023 $ – $ – (1) $ – $ –  4.05% Senior Notes due January 2020 (2) (3) 52 – – 52  4.10% Senior Notes due March 2022 (3) 213 (1) – 212  4.95% Senior Notes due January 2025 (2) (3) 927 (7) (1) 919  7.50 % Senior Notes due April 2026 650 (8) – 642  7.75 % Senior Notes due October 2027 500 (7) – 493  Total debt $ 2,342 $ (23) $ (1) $ 2,318     December 31, 2017  (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total  Variable rate ( 3.980% at December 31, 2017) 2016 term loan facility, due December 2020 (4) $ 1,191 $ (8) $ – $ 1,183  4.05% Senior Notes due January 2020 (2) (3) 92 – – 92  4.10% Senior Notes due March 2022 (3) 1,000 (7) – 993  4.95% Senior Notes due January 2025 (2) (3) 1,000 (8) (2) 990  7.50% Senior Notes due April 2026 650 (10) – 640  7.75% Senior Notes due October 2027 500 (7) – 493  Total debt $ 4,433 $ (40) $ (2) $ 4,391  (1) Unamortized issuance expense of $11 million associated with the 2018 revolving credit facility is classified as other long-term assets on the consolidated balance sheets and includes approximately $4 million in unamortized issuance expense associated with the Company’s previous 2016 term loan facility.  (2) In February and June 2016, Moody’s and S&P downgraded certain senior notes, which increased the interest rates by 175 basis points effective July 2016. As a result of the downgrades, interest rates increased to 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. In April and May 2018, S&P and Moody’s upgraded certain senior notes. As a result of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to the bondholders at the lower interest rate was paid in January 2019.  (3) In December 2018, the Company repurchased $40 million of its 4.05% senior notes due January 2020, $787 million of its 4.10% senior notes due March 2022 and $73 million of its 4.95% senior notes due January 2025.  (4) In April 2018, the Company repaid the $1,191 million secured term loan balance with cash on hand and borrowings under the 2018 credit facility.  The following is a summary of scheduled debt maturities by year as of December 31, 2018:    (in millions)  2019 $ –  2020 52  2021 –  2022 213  2023 –  Thereafter 2,077  $ 2,342  Credit Facilities  2013 Credit Facility  In December 2013, the Company entered into a credit agreement that exchanged its previous revolving credit facility. Under the revolving credit facility, the Company had a borrowing capacity of $2.0 billion. The revolving credit facility was unsecured and was not guaranteed by any subsidiaries. In June 2016, this credit facility was substantially exchanged for a new credit facility comprised of a $1,191 million secured term loan and a new $743 million revolving credit facility. The borrowing capacity of the original 2013 credit agreement was reduced from $2.0 billion to $66 million, remained unsecured and the maturity remained December 2018 . On April 26, 2018 the Company replaced its 2016 credit facility with the 2018 credit facility and terminated the 2013 credit facility.  2016 Credit Facility  In June 2016, the Company reduced its existing $2.0 billion unsecured revolving credit facility, entered into in December 2013, to $66 million and entered into a new credit agreement for $1,934 million, consisting of a $1,191 million secured term loan and a new $743 million unsecured revolving credit facility, maturing in December 2020 .  Concurrent with the closing of the new 2018 credit facility agreement on April 26, 2018, the Company repaid the $1,191 million secured term loan balance and recognized a loss on early debt extinguishment of $8 million on the consolidated income statement related to the unamortized issuance expense. In addition, approximately $4 million of unamortized issuance expense associated with the closed $743 million revolving credit facility was carried forward into the unamortized issuance expenses of the 2018 credit facility. At December 31, 2017, the $1,191 million secured term loan was fully drawn, there were no borrowings under the revolving credit facility, but $323 million in letters of credit was outstanding under the 2016 revolving credit facility.  2018 Revolving Credit Facility  In April 2018, as part of the Company’s strategic effort to simplify the capital structure, increase financial flexibility and reduce costs, the Company replaced its 2016 credit facility (which consisted of a $1,191 million secured term loan and an unsecured $743 million revolving credit facility) with a new revolving credit facility (the “2018 credit facility”). The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion, and at December 31, 2018, had a current borrowing base of $2.1 billion with a current aggregate commitment of $2.0 billion. The borrowing base is subject to redetermination twice a year in April and October. The 2018 credit facility matures in April 2023 and is secured by substantially all of the assets owned by the Company and its subsidiaries.  Loans under the 2018 credit facility are subject to varying rates of interest based on whether the loan is a Eurodollar loan or an alternate base rate loan. Eurodollar loans bear interest at the Eurodollar rate, which is adjusted LIBOR for such interest period plus the applicable margin (as those terms are defined in the 2018 credit facility documentation). The applicable margin for Eurodollar loans under the 2018 credit facility ranges from 1.50% to 2.50% based on the Company’s utilization of the borrowing base under the 2018 credit facility. Alternate base rate loans bear interest at the alternate base rate plus the applicable margin. The applicable margin for alternate base rate loans under the 2018 credit facility ranges from 0.50% to 1.50% based on the Company’s utilization of the borrowing base under the 2018 credit facility.  The 2018 credit facility contains customary representations and warranties and contains covenants including, among others, the following: · a prohibition against incurring debt, subject to permitted exceptions; · a restriction on creating liens on assets, subject to permitted exceptions; · restrictions on mergers and asset dispositions; · restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business; and · maintenance of the following financial covenants, commencing with the fiscal quarter ended June 30, 2018:  1. Minimum current ratio of no less than 1.00 to 1.00, whereby current ratio is defined as the Company’s consolidated current assets (including unused commitments under the credit agreement, but excluding non-cash derivative assets) to consolidated current liabilities (excluding non-cash derivative obligations and current maturities of long-term debt). 2. Maximum total net leverage ratio of no less than (i) with respect to each fiscal quarter ending during the period from June 30, 2018 through March 31, 2019, 4.50 to 1.00, (ii) with respect to each fiscal quarter ending during the period from June 30, 2019 through March 31, 2020, 4.25 to 1.00, and (iii) with respect to each fiscal quarter ending on or after June 30, 2020, 4.00 to 1.00. Total net leverage ratio is defined as total debt less cash on hand (up to the lesser of 10% of credit limit or $150 million) divided by consolidated EBITDAX for the last four consecutive quarters. EBITDAX, as defined in the Company’s 2018 credit agreement, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs. The 2018 credit facility contains customary events of default that include, among other things, the failure to comply with the financial covenants described above, non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations and warranties, bankruptcy and insolvency events, material judgments and cross-defaults to material indebtedness. If an event of default occurs and is continuing, all amounts outstanding under the 2018 credit facility may become immediately due and payable. In the fourth quarter of 2018, the Company entered into hedges that, when added to existing hedges including hedges put in place as part of the Fayetteville Shale sale that the buyer was obligated to assume at closing of that sale, exceeded a cap on hedges for the month of December 2018 under a covenant under the Company’s credit agreement. In conjunction with the closing, the buyer paid for the settlement of the December 2018 hedges it was to assume. The lenders have subsequently waived all matters associated with this default. Otherwise , as of December 31, 2018, the Company was in compliance with all of the remaining covenants of this credit agreement in all material respects.  Each United States domestic subsidiary of the Company for which the Company owns 100% of its equity guarantees the 2018 credit facility. Pursuant to requirements under the indentures governing the Company’s senior notes, each subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s senior notes. See Note 15 for the Company’s Condensed Consolidated Financial Information, presented in accordance with Rule 3-10 of Regulation S-X. At the closing of the Fayetteville Shale sale, its subsidiaries being sold were released from these guarantees.  As of December 31, 2018, the Company had $112 million in letters of credit and no borrowings outstanding under the 2018 revolving credit facility.  Senior Notes  In January 2015, the Company completed a public offering of $850 million aggregate principal amount of its 4.05% Senior Notes due 2020 (the “2020 Notes”) and $1.0 billion aggregate principal amount of its 4.95% Senior Notes due 2025 (the “2025 Notes” together with the 2020 Notes, the “Notes”). The interest rates on the Notes are determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment. In February and June 2016, Moody’s and S&P downgraded the Notes, which increased the interest rates by 175 basis points effective July 2016. As a result of these downgrades, interest rates increased to 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. In the event of future downgrades, the coupons for this series of notes are capped at 6.05% and 6.95% , respectively. The first coupon payment to the bondholders at the higher interest rates was paid in January 2017. S&P and Moody’s upgraded the Notes in April and May 2018, respectively. As a result of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to bondholders at the lower interest rates will be paid in January 2019.  During the first half of 2017, the Company redeemed or repurchased (i) the remaining $38 million principal amount of its outstanding 3.30% Senior Notes due 2018 , (ii) the remaining $212 million principal amount of its outstanding 7.50% Senior Notes due February 2018 and (iii) the remaining $26 million principal amount of its outstanding 7.15% Senior Notes due June 2018 , and recognized an $11 million loss on the extinguishment of debt. In September 2017, the Company completed a public offering of $650 million aggregate principal amount of its 7.50% Senior Notes due 2026 (the “2026 Notes”) and $500 million aggregate principal amount of its 7.75% Senior Notes due 2027 (the “2027 Notes”), with net proceeds from the offering totaling approximately $1.1 billion after underwriting discounts and offering expenses. Both series of senior notes were sold to the public at face value. The proceeds from this offering were used to purchase $758 million of the 2020 Notes in a tender offer and to repay the outstanding balance of $327 million on the 2015 term loan. The Company recognized a loss on extinguishment of debt of $59 million, which included $53 million of premiums paid.  As discussed in Note 3 above, i n December 2018, the Company closed on the Fayetteville Shale sale and used a portion of the proceeds to repurchase $40 million of its 4.05% Senior Notes due January 2020, $787 million of its 4.10% Senior Notes due March 2022 and $73 million of its 4.95% Senior Notes due January 2025. The Company recognized a loss on extinguishment of debt of $9 million, which included $2 million of premiums paid.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies [Abstract]
Commitments and Contingencies	(9) COMMITMENTS AND CONTINGENCIES  Operating Commitments and Contingencies  As of December 31, 2018, the Company’s contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately $8.8 billion , $3.1 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. The Company also had guarantee obligations of up to $463 million of that amount. As of December 31, 2018, future payments under non-cancelable firm transportation and gathering agreements are as follows:    Payments Due by Period  (in millions) Total Less than 1 Year 1 to 3 Years 3 to 5 Years 5 to 8 Years More than 8 Years  Infrastructure currently in service $ 5,715 $ 637 $ 1,060 $ 876 $ 1,123 $ 2,019  Pending regulatory approval and/or construction (1) 3,079 136 348 392 621 1,582  Total transportation charges $ 8,794 $ 773 $ 1,408 $ 1,268 $ 1,744 $ 3,601  (1) Based on the estimated in-service dates as of December 31, 2018.  In December 2018, the Company closed on the Fayetteville Shale sale. T he Company retained certain contractual commitments related to firm transportation, with the buyer obligated to pay the transportation provider directly for these charges. As of December 31, 2018, approximately $221 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $102 million through 2020 depending on the buyer’s actual use , and has recorded an $88 million liability for the estimated future payments. The buyer will also assume future asset retirement obligations related to the operations sold.  The Company leases pressure pumping equipment for its E&P operations under a single lease that expires in 2021 . The current aggregate annual payment under this lease i s approximately $7 million. The Company has seven leases for drilling rigs for its E&P operations that expire through 2024 with a current aggregate annual payment of 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.  The Company leases compressors, aircraft, vehicles, office space and equipment under non-cancelable operating leases expiring through 202 8 . As of December 31, 2018, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $38 million in 2019, $28 million in 2020, $14 million in 2021, $6 million in 2022, $5 million in 2023 and $4 million thereafter.  The Company also has commitments for compression services and rentals related to its E&P segment. As of December 31, 2018, future minimum payments under these non-cancelable agreements are approximately $3 million in 2019 and $1 million in each of 2020 and 2021 .  Subsequent to December 31, 2018, the Company agreed to purchase firm transportation with pipelines in the Appalachian Basin starting in 2021 and running through 2032 totaling $357 million in total contractual commitments of which the seller has agreed to reimburse $133 million of this commitment.  Env ironmental 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, results of operations or cash flows of the Company.  Lit igation  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, employment matters, traffic accidents, pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. It is not possible at this time to estimate the amount of any additional loss, or range of loss that is reasonably possible, but based on the nature of the claims, management believes that current 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, for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.  Arkansas Royalty Litigation  The Company has been a defendant in three certified class actions alleging that the Company underpaid lessors of lands in Arkansas by deducting from royalty payments costs for gathering, transportation and compression of natural gas in excess of what is permitted by the relevant leases. Two of these class actions were filed in Arkansas state courts and the third in the United States District court for the Eastern District of Arkansas. The Company denied liability in all three cases. Under the agreement for the sale of the Company’s properties in the Fayetteville Shale, the Company retained responsibility for these class actions.  In June 2017, the jury returned a verdict in favor of the Company on all counts in Smith v. SEECO, Inc. et al., the class action in the federal court, whose plaintiff class comprises the vast majority of the lessors in these cases. The plaintiff had asserted claims for, among other things, breach of contract, fraud, civil conspiracy, unjust enrichment and violation of certain Arkansas statutes. Following the verdict, the court entered judgment in favor of the Company on all claims. The trial court denied the plaintiff’s motion for a new trial, and the plaintiff appealed to the United States Court of Appeals for the Eighth Circuit. Independent of the plaintiff’s appeal, several different parties sought to intervene in the Smith case prior to or shortly after trial, and have appealed the trial court’s order denying their request to intervene. Oral argument occurred in January 2019. The Court of Appeals has not yet issued its decision.  In the second quarter of 2018, the company entered into an agreement to settle another of the class actions, which has been pending in the Circuit Court of Conway County, Arkansas under the caption Snow, et al v. SEECO, Inc., et al . The settlement received final approval by the court during the third quarter, and the deadline to appeal the order approving the settlement passed without any appeals filed. The amount of the settlement is reflected in the Company’s consolidated statement of operations for 2018 and has been paid. The third class action was dismissed in the second quarter of 2018.  The Smith and the Snow cases cover all affected lessors, except a small percentage who opted out. Most of these have filed separate actions. The Company does not expect those cases to have a material adverse effect on the results of operations, financial position or cash flows of the Company. Additionally, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible.  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. The Company likewise obtains indemnification for future matters when it sells assets, although there is no assurance the buyer will be capable of performing those obligations. No material liabilities have been recognized in connection with these indemnifications.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Taxes [Abstract]
Income Taxes	(10) INCOME TAXES  The provision (benefit) for income taxes included the following components:    (in millions) 2018 2017 2016  Current:  Federal $ (5) $ (22) $ (6)  State 6 – (1)  1 (22) (7)  Deferred:  Federal – (71) (22)  State – – –  – (71) (22)  Provision (benefit) for income taxes $ 1 $ (93) $ (29)  The provision for income taxes was an effective rate of 0% in 2018, ( 10% ) in 2017 and 1% in 2016. The Company’s effective tax rate increased in 2018, as compared with 2017, primarily due to state income taxes resulting from the Fayetteville Shale sale and the impact of the Tax Cuts and Jobs Act (“Tax Reform Act”) on the tax rate and alternative minimum taxes, as well as changes to the overall valuation allowance activity during 2018. 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:    (in millions) 2018 2017 2016  Expected provision (benefit) at federal statutory rate $ 113 $ 333 $ (935)  Increase (decrease) resulting from:  State income taxes, net of federal income tax effect 13 16 (79)  Rate impacts due to tax reform – 370 –  Changes to valuation allowance due to tax reform – (370) –  AMT tax reform impact – valuation allowance release – (68) –  Changes in uncertain tax positions – (5) (19)  Change in valuation allowance (121) (364) 1,002 Removal of sequestration fee on AMT receivables (5) – –  Other 1 (5) 2  Provision (benefit) for income taxes $ 1 $ (93) $ (29)  The 2018 tax accrual calculated under the estimated annual effective tax rate method reflects the Tax Reform Act changes that took effect January 1, 2018. The components of the Company’s deferred tax balances as of December 31, 2018 and 2017 were as follows:    (in millions) 2018 2017  Deferred tax liabilities:  Differences between book and tax basis of property $ 226 $ 395  Derivative activity 12 19  Other 2 1  240 415  Deferred tax assets:  Accrued compensation 33 29  Accrued pension costs 10 14  Asset retirement obligations 15 41  Net operating loss carryforward 777 1,043  Other 14 20  849 1,147  Valuation allowance (609) (732)  Net deferred tax liability $ – $ –  On December 22, 2017, the United States enacted the Tax Reform Act, which made significant changes to the U.S. federal income tax law affecting the Company. Major changes in this legislation applicable to the Company relate to the reduction in the corporate tax rate to 21% , repeal of the alternative minimum tax, interest deductibility and net operating loss carryforward limitations, changes to certain executive compensation and full expensing provisions related to business assets. Due to the tax valuation allowance currently in place, any adjustments required to deferred taxes as a result of the Tax Reform Act were fully offset by valuation allowance adjustments , and the Company continues to examine the impact of this legislation and future regulations.  As the Tax Reform Act repealed the corporate alternative minimum tax for tax years beginning on or after January 1, 2018 and provided for existing alternative minimum tax credit carryovers to be refunded beginning in 2018, the Company has approximately $68 million in refundable credits that are expected to be fully refunded between 2019 and 2021 . Accordingly, in 2017 the valuation allowance in place prior to the Tax Reform Act related to these credits was released, and any credits remaining were reclassed to a receivable.  In February 2018, the FASB issued Accounting Standards Update No. 2018-02 (“Update 2018-02”) amending the FASB Accounting Standards relating to tax effects in accumulated other comprehensive income. In the first quarter of 2018, the Company elected to early adopt the amendments of Update 2018-02. The implementation did not have a material impact on the Company’s consolidated statements of operations, financial position or cash flows due to the tax valuation allowance currently in place. See Note 1 for more information regarding this update.  In 2018, the Company made state income tax payments o f $6.3 million. In 2017, the Company received less than $1 million in state income tax refunds and received $4.2 million in federal income tax refunds. The Company’s net operating loss carryforward as of December 31, 2018 was $3.0 billion and $2.1 billion for federal and state reporting purposes, respectively, the majority of which will expire between 2035 and 2037 . Additionally, the Company has an income tax net operating loss carryforward related to its Canadian operations of $29 million, with expiration dates of 2030 through 2038 . The Company also had a statutory depletion carryforward of $13 m illion as of December 31, 2018.  A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess the likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as current and forecasted business economics of the oil and gas industry.  The Company maintained its net deferred tax asset position at December 31, 2018 primarily due to the prior write-downs of the carrying value of natural gas and oil properties. The Company believes it is more likely than not that these deferred tax assets will not be realized and accordingly maintained our full valuation allowance to adjust the remaining deferred tax asset to zero for the year ended December 31, 2018. During 2018, the valuation allowance was reduced $123 million, $121 million as a component of income tax expense and $2 million as a reduction of equity. Management assesses available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. In management’s view, the cumulative loss incurred over the three -year period ending December 31, 2018, outweighs any positive factors, such as the possibility of future growth. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth. It is reasonably possible that a release of the valuation allowance could occur as early as the first quarter of 2019 if the C ompany moves into a three-year pre-tax income position combined with other positive evidence of future taxable income.  A reconciliation of the changes to the valuation allowance is as follows:    (in millions)  Valuation allowance as of December 31, 2017 $ 732  Changes based on 2018 activity (121)  Equity – pension benefits in OCI (2)  Valuation allowance as of December 31, 2018 $ 609  On March 30, 2016, the FASB modified its accounting policy on share‐based payments (ASU 2016-09). Updates included tax impacts related to the treatment of excess tax benefits (“windfalls”) and deficiencies (“shortfalls”) were made and became effective on January 1, 2017. The Company had previously unrecognized tax “windfall” benefits of $149 million as of December 31, 2016, which were released in the first quarter of 2017. The recognition of previously unrecognized windfall tax benefits resulted in a net cumulative-effect adjustment of $59 million, which increased net deferred tax assets and the related income tax valuation allowance by the same amount as of the beginning of 2017. As of December 31, 2018, no unrecognized tax benefits exist related to share-based payments.  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, 2018, the amount of unrecognized tax benefits related to alternative minimum tax was $7 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, 2018, the Company had accrued a liabilit y of less than $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:    (in millions) 2018 2017  Unrecognized tax benefits at beginning of period $ 12 $ 17  Additions based on tax positions related to the current year – –  Additions to tax positions of prior years – –  Reductions to tax positions of prior years (5) (5)  Unrecognized tax benefits at end of period $ 7 $ 12  The Internal Revenue Service is currently auditing the Company’s federal income tax return for 2014. The income tax years 2014 to 2018 remain open to examination by the major taxing jurisdictions to which the Company is subject.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations	(11) ASSET RETIREMENT OBLIGATIONS  The following table summarizes the Company’s 2018 and 2017 activity related to asset retirement obligations:    (in millions) 2018 2017  Asset retirement obligation at January 1 $ 165 $ 141  Accretion of discount 9 8  Obligations incurred 1 3  Obligations settled/removed (1) (116) (10)  Revisions of estimates 2 23  Asset retirement obligation at December 31 $ 61 $ 165   Current liability 6 12  Long-term liability 55 153  Asset retirement obligation at December 31 $ 61 $ 165  (1) Obligations settled/removed include $111 million related to asset divestitures in 2018, of which $107 million related to the Fayetteville Shale sale.

Retirement and Employee Benefit

Retirement and Employee Benefit Plans	12 Months Ended
	Dec. 31, 2018
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 $4 million of contribution expense in 2018, 2017 and 2016, respectively. Additionally, the Company capitalized $2 million of contributions in each of 2018, 2017 and 2016, directly related to the acquisiti on, 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 of the Company’s employees are covered by the 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.  In June 2018, the Company notified affected employees of a workforce reduction plan, which resulted primarily from a previously announced study of structural, process and organizational changes to enhance shareholder value and continues with respect to other aspects of the Company’s business activities. In December 2018, the Company closed on the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, many employees associated with those assets were either transferred to the buyer or their employment was terminated. As a result of the restructurings, the Company recognized a curtailment on its pension and other postretirement benefit plans and recognized a non-cash gain of $4 million on its consolidated statements of operations. During the first half of 2019, the Company will recognize settlements related to these restructuring events, and the amounts may be material.  In January 2016, the Company initiated a reduction in workforce that was effectively completed by the end of the first quarter. As a result of the workforce reduction, the Company recognized a $1 million non-cash curtailment loss related to its pension plan for both the curtailment-related decrease to the benefit obligation and the recognition of the proportionate share of unrecognized prior service cost and net loss from other comprehensive income (loss) in the second quarter of 2016. For the year ended December 31, 2016, the Company recognized a non-cash settlement loss of $11 million related to a total of $37 million of lump sum payments from the pension plan. Additionally, the Company recognized a non-cash curtailment gain of $6 million related to its other postretirement benefit plan in the first quarter of 2016.  The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status as of December 31, 2018 and 2017:    Other Postretirement  Pension Benefits Benefits  (in millions) 2018 2017 2018 2017  Change in benefit obligations:  Benefit obligation at January 1 $ 143 $ 117 $ 17 $ 13  Service cost 10 9 2 2  Interest cost 5 5 1 –  Participant contributions – – – –  Actuarial loss (gain) (14) 21 − 3  Benefits paid (14) (9) (1) (1)  Plan amendments – – – –  Curtailments (5) – (6) –  Benefit obligation at December 31 $ 125 $ 143 $ 13 $ 17     Other Postretirement  Pension Benefits Benefits  (in millions) 2018 2017 2018 2017  Change in plan assets:  Fair value of plan assets at January 1 $ 101 $ 81 $ – $ –  Actual return on plan assets (8) 15 – –  Employer contributions 12 14 1 1  Participant contributions – – – –  Benefits paid (14) (9) (1) (1)  Fair value of plan assets at December 31 $ 91 $ 101 $ – $ –   Funded status of plans at December 31 $ (34) $ (42) $ (13) $ (17)  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 pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2018 and 2017 are as follows:    (in millions) 2018 2017  Projected benefit obligation $ 125 $ 143  Accumulated benefit obligation 122 137  Fair value of plan assets 91 101  Pension and other postretirement benefit costs include the following components for 2018, 2017 and 2016:    Pension Benefits Other Postretirement Benefits  (in millions) 2018 2017 2016 2018 2017 2016  Service cost $ 10 $ 9 $ 11 $ 2 $ 2 $ 2  Interest cost 5 5 5 1 – 1  Expected return on plan assets (7) (6) (6) – – –  Amortization of transition obligation – – – – – –  Amortization of prior service cost – – – – – –  Amortization of net loss 2 2 2 – – –  Net periodic benefit cost 10 10 12 3 2 3  Curtailment (gain) loss – – 1 (4) – (6)  Settlement loss – – 11 – – –  Total benefit cost (benefit) $ 10 $ 10 $ 24 $ (1) $ 2 $ (3)  Service cost is classified as general and administrative expenses on the consolidated statements of operations. All other components of total benefit cost (benefit) are classified as other income (loss), net on the consolidated statements of operations.  Amounts recognized in other comprehensive income for the years ended December 31, 2018 and 2017 were as follows:    Pension Benefits Other Postretirement Benefits  (in millions) 2018 2017 2018 2017  Net actuarial (loss) gain arising during the year $ (2) $ (11) $ – $ (2)  Amortization of prior service cost – – – –  Amortization of net loss 2 2 – –  Settlements – – – – Curtailments 5 − 3 −  Tax effect (1) (1) 3 (1) 1  $ 4 $ (6) $ 2 $ (1)  (1) Deferred tax activity related to pension and other postretirement benefits was offset by a valuation allowance, resulting in no tax expense for all periods presented on the consolidated statements of operations.  Included in accumulated other comprehensive income as of December 31, 2018 and 2017 was a $34 million loss ( $20 million net of tax) and a $42 million loss ( $26 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2018, $6 million was classified to accumulated other comprehensive income, pr imarily driven by actuarial gain 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 2019 is a $2 m illion net loss.  The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2018 and 2017 are as follows:    Pension Benefits Other Postretirement Benefits  2018 2017 2018 2017  Discount rate 4.35 % 3.75 % 4.35 % 3.75 %  Rate of compensation increase 3.50 % 3.50 % n/a n/a  The assumptions used in the measurement of the Company’s net periodic benefit cost for 2018, 2017 and 2016 are as follows:    Pension Benefits Other Postretirement Benefits  2018 2017 2016 2018 2017 2016  Discount rate 4.35 % 4.20 % 4.20 % 4.35 % 4.20 % 4.20 %  Expected return on plan assets 7.00 % 7.00 % 7.00 % n/a n/a n/a  Rate of compensation increase 3.50 % 3.50 % 3.50 % 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 2018 and 2017:    2018 2017  Health care cost trend assumed for next year 7% 7%  Rate to which the cost trend is assumed to decline 5% 5%  Year that the rate reaches the ultimate trend rate 2036 2035  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:    (in millions) 1% Increase 1% Decrease  Effect on the total service and interest cost components $ – $ –  Effect on postretirement benefit obligations $ 2 $ (1)  Pension Payments and Asset Management  In 2018, the Company contribute d $12 million to its pension plans and $1 million to its other postretirement benefit plan. The Company expects to contribute $13 million to its pension and other pos tretirement benefit plans in 2019.  The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:    Pension Benefits Other Postretirement Benefits  (in millions)  2019 $ 22 2019 $ 1  2020 6 2020 1  2021 6 2021 1  2022 6 2022 1  2023 7 2023 1  Years 2024-2028 39 Years 2024-2028 5  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 payment of benefit obligations to participants, retirees and beneficiaries. The Benefits Administration Committee of the Company, appointed by the Compensation Committee of the Board of Directors, 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, 2018, 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 % 26 %  Non-U.S. developed equity (2) 30 % 22 %  Emerging markets equity (3) 5 % 4 %  Fixed income (4) 28 % 23 %  Cash (5) 2 % 25 %  Total 100 % 100 %  (1) 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) Includes Non-U.S. equity securities in the table below.  (3) Includes emerging markets equity securities below.  (4) Includes fixed income pension plan assets in the table below.  (5) Includes Cash and cash equivalent pension plan assets in the table below.  Utilizing the fair value hierarchy described in Note 7 , the Company’s fair value measurement of pension plan assets as of December 31, 2018 is as follows:    (in millions) Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)  Measured within fair value hierarchy  Equity securities:  U.S. large cap growth equity (1) $ 5 $ 5 $ – $ –  U.S. large cap value equity (2) 5 5 – –  U.S. small cap equity (3) 2 2 – –  Non-U.S. equity (4) 20 20 – –  Emerging markets equity (5) 3 3 – –  Fixed income (6) 14 14 – –  Cash and cash equivalents (7) 23 23 – –  Total measured within fair value hierarchy $ 72 $ 72 $ – $ –  Measured at net asset value ( 8 )  Equity securities:  U.S. large cap core equity ( 9 ) 12  Fixed income (6) 7  Total measured at net asset value $ 19   Total plan assets at fair value $ 91  Note: Footnotes are located after the prior year comparative table below. Utilizing the fair value hierarchy described in Note 7 , the Company’s fair value measurement of pension plan assets at December 31, 2017 was as follows:    (in millions) Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)  Measured within fair value hierarchy  Equity securities:  U.S. large cap growth equity (1) $ 7 $ 7 $ – $ –  U.S. large cap value equity (2) 8 8 – –  U.S. small cap equity (3) 3 3 – –  Non-U.S. equity (4) 30 30 – –  Emerging markets equity (5) 5 5 – –  Fixed income (6) 27 27 – –  Cash and cash equivalents 3 3 – –  Total measured within fair value hierarchy $ 83 $ 83 $ – $ –  Measured at net asset value (8)  Equity securities:  U.S. large cap core equity (9) 18  Total measured at net asset value $ 18   Total plan assets at fair value $ 101  (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) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.  (4) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.  (5) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.  (6) 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.  (7) Includes approximately $21 million for anticipated lump sum distributions resulting from the Fayetteville Shale sale in December 2018.  (8) Plan assets for which fair value was measured using net asset value as a practical expedient.  (9) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.  The Company’s pension plan assets that are classified as Level 1 are the investments comprised of 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. Due to the Company’s implementation of Accounting Standards Update No. 2015-07, assets measured using net asset value as a practical expedient have not been classified in the fair value hierarchy. 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.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2018
Stock-Based Compensation [Abstract]
Stock-Based Compensation	(13) STOCK-BASED COMPENSATION  The Southwestern Energy Company 2013 Incentive Plan was adopted in February 2013, approved by stockholders in May 2013 and amended and restated per stockholders’ approval in May 2016 and further amended in May 2017 (the “2013 Plan”). 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 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 52,700,000 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.  The Company’s stock-based compensation is classified as either equity or liability awards in accordance with generally accepted accounting principles. The fair value of an equity-classified award is determined at the grant date and is amortized to general and administrative expense on a straight-line basis over the vesting period of the award. The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense over the vesting period of the award. A portion of this general and administrative expense is capitalized into natural gas and oil properties, included in property and equipment. Generally, stock options granted to employees and directors vest ratably over three years from the grant date and expire seven years from the date of grant. The Company issues shares of restricted stock or restricted stock units to employees and directors which generally vest over four years. Restricted stock, restricted stock units and stock options granted to participants under the 2013 Plan immediately vest upon death, disability or retirement (subject to a minimum of three years of service).  In June 2018, the Company announced a workforce reduction. Unvested stock-based awards of the affected employees were subsequently cancelled and the approximate fair value of a portion of those cancelled awards was included in a cash severance payment that was paid in the third quarter of 2018. Stock-based compensation costs recognized prior to the cancellation as either general and administrative expense or capitalized expense were reversed and the severance payments were subsequently recognized as restructuring charges for the year ended December 31, 2018 on the consolidated statements of operations.  In December 2018, the Company closed on the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, most employees associated with those assets became employees of the buyer although the employment of some was or will be terminated. All affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were forfeited. Stock-based compensation costs recognized prior to the cancellation as either general and administrative expense or capitalized expense were reversed and the severance payments were subsequently recognized as restructuring charges for the year ended December 31, 2018 on the consolidated statements of operations.  In January 2016, the Company announced a 40% workforce reduction that was substantially concluded by the end of March 2016. In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016. Affected employees were offered a severance package that included, if applicable, amendments to certain outstanding equity awards that modified forfeiture provisions upon separation from the Company. As a result, certain unvested stock-based equity awards became fully vested at the time of separation. These shares were revalued and recognized immediately as a component of restructuring charges on the Company’s consolidated statement of operations. The unvested portion of equity-based performance units was cancelled upon separation from the Company.  Equity-Classified Awards  Equity-Classified Stock Options  The Company recorded the following compensation costs related to stock options for the years ended December 31, 2018, 2017 and 2016:    (in millions) 2018 2017 2016  Stock options – general and administrative expense (1) $ 2 $ 3 $ 6  Stock options – general and administrative expense capitalized $ – $ 1 $ 1  (1) Includes less than $1 million related to the reduction in workforce and $1 million related to executive management restructuring for the year ended December 31, 2016.  The Company also recorded a deferred tax asset of less than $1 million, $1 million and $2 million related to stock options in 2018, 2017 and 2016, respectively. Unrecognized compensation cost related to the Company’s unvested stock options totaled $1 million at December 31, 2018. This cost is expected to be recognized over a weighted-average period of one year.  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 the 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. The Company did not issue equity-classified stock options in 2018.    Assumptions 2018 2017 2016  Risk-free interest rate – 1.9% 1.4%  Expected dividend yield – – –  Expected volatility – 50.5% 41.0%  Expected term – 5 years 5 years  The following tables summarize stock option activity for the years 2018, 2017 and 2016, and provide information for options outstanding at December 31 of each year:    2018 2017 2016  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 6,020 $ 19.43 5,416 $ 23.46 5,623 $ 24.57  Granted (1) – $ – 1,604 $ 8.00 155 $ 8.60  Exercised – $ – – $ – (45) $ 7.74  Forfeited or expired (842) $ 33.99 (1,000) $ 22.93 (317) $ 38.01  Options outstanding at December 31 5,178 $ 17.06 6,020 $ 19.43 5,416 $ 23.46  (1) Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual stock option awards from December to the following February. The Company did not issue equity-classified stock options in 2018.    Options Outstanding Options Exercisable  Weighted Weighted  Options Weighted Average Options Weighted Average  Outstanding at Average Remaining Exercisable at Average Remaining  Range of December 31, Exercise Contractual December 31, Exercise Contractual  Exercise Prices 2018 Price Life 2018 Price Life  (in thousands) (years) (in thousands) (years)  $5.22 - $29.42 3,517 $ 8.68 4.4 2,605 $ 8.96 4.1  $30.59 - $35.64 1,135 $ 32.26 2.1 1,135 $ 32.26 2.1  $36.69 - $39.48 436 $ 38.97 1.9 436 $ 38.97 1.9  $40.15 - $49.00 90 $ 46.55 2.4 90 $ 46.55 2.4  5,178 $ 17.06 3.6 4,266 $ 19.02 3.3  There were no options granted in 2018. The weighted-average grant date fair value of options granted during the years 2017 and 2016 were $3.47 and $3.22 , respectively. There were no options exercised in 2018 or 2017. The total intrinsic value of options exercised during 2016 was less than $1 million.  Equity-Classified Restricted Stock  The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2018, 2017 and 2016:    (in millions) 2018 2017 2016  Restricted stock grants – general and administrative expense (1) $ 9 $ 16 $ 33  Restricted stock grants – general and administrative expense capitalized $ 5 $ 11 $ 8  (1) Includes $16 million related to the reduction in workforce and $1 million related to executive management restructuring for the year ended December 31, 2016.  The Company also recorded a deferred tax asset of $2 million related to restricted stock for the year ended December 31, 2018, compared to a deferred tax assets of $9 million and $12 million for 2017 and 2016, respectively. As of December 31, 2018, there was $15 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 two years.  The following table summarizes the restricted stock activity for the years 2018, 2017 and 2016, and provides information for restricted stock outstanding at December 31 of each year:    2018 2017 2016  Weighted Weighted Weighted  Number of Average Fair Number of Average Fair Number of Average Fair  Shares Value Shares Value Shares Value  (in thousands) (in thousands) (in thousands)  Unvested shares at January 1 6,254 $ 8.85 3,321 $ 11.85 7,222 $ 13.24  Granted 350 $ 4.72 5,055 $ 8.38 81 (2) $ 8.56  Vested (2,058) (1) $ 9.24 (1,380) $ 13.28 (3,817) (3) $ 11.34  Forfeited (1,829) $ 9.01 (742) $ 10.04 (165) $ 12.05  Unvested shares at December 31 2,717 $ 7.91 6,254 $ 8.85 3,321 $ 11.85  (1) Includes 1,287,636 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2018. (2) Shares granted in 2016 were considerably lower than historical norms. In 2016, the Company changed the grant date of its annual restricted stock awards from December to the following February.  (3) Includes 2,059,626 shares and 151,575 shares related to reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.  The fair values o f the grants were $2 million for 2018, $42 million for 2017 and $1 million for 2016. The total fair value of shares vested were $19 million for 2018, $18 million for 2017 and $43 million for 2016.  Equity-Classified Performance Units  The Company recorded compensation costs related to equity-classified performance units for the years ended December 31, 2018, 2017 and 2016. The performance units awarded in 2018, 2017 and 2016 included a market condition based on relative Total Shareholder Return (“TSR”). The grant date fair value is calculated using the closing price of the Company’s common stock at the grant date and a Monte Carlo model to estimate the TSR market condition. The estimated fair value is amortized to compensation expense on a straight-line basis over the vesting period of the award.    (in millions) 2018 2017 2016  Performance units – general and administrative expense (1) $ 3 $ 5 $ 9  Performance units – general and administrative expense capitalized $ 1 $ 2 $ 1  (1) Includes less than $1 million related to reduction in workforce and $1 million related to executive management restructuring for the year ended December 31, 2016.  The Company also recorded a deferred tax asset of $1 million related to equity-classified performance units for the year end ed December 31, 2018, compared to deferred tax assets of $3 million and $4 million in 2017 and 2016, respectively. As of December 31, 2018, there was $3 million of total unrecognized compensation cost related to unvested equity-classified performance units that is expected to be recognized over a weighted-average period of one year.  The following table summarizes equity-classified performance unit activity to be paid out in Company stock for the years ended December 31, 2018, 2017 and 2016, and provides information for unvested units as of December 31, 2018, 2017 and 2016:    2018 2017 2016  Weighted Weighted Weighted  Number of Average Fair Number of Average Fair Number of Average Fair  Units (1) Value Units (1) Value Units (1) Value  (in thousands) (in thousands) (in thousands)  Unvested shares at January 1 1,084 $ 10.12 719 $ 11.46 407 $ 36.65  Granted – $ – 1,197 $ 10.47 1,503 $ 8.60  Vested (290) $ 10.47 (325) $ 12.21 (889) (3) $ 12.78  Forfeited (196) (2) $ 9.94 (507) $ 9.53 (302) (4) $ 11.26  Unvested shares at December 31 598 $ 10.01 1,084 $ 10.12 719 $ 11.46  (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 per unit contingent upon TSR. The performance units have a three -year vesting term and the actual disbursement of shares, if any, is determined during the first quarter following the end of the three-year vesting period.  (2) Includes 144,927 units related to the reduction in workforce for the year ended December 31, 2018.  (3) Includes 22,918 units and 37,590 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.  (4) Includes 87,595 units and 195,834 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.  Liability-Classified Awards  Liability-Classified Restricted Stock Units  In the first quarter of 2018, the Company granted restricted stock units that vest over a period of four years and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award.     (in millions) 2018  Restricted stock units – general and administrative expense $ 4  Restricted stock units – general and administrative expense capitalized $ 3  The Company also recorded a deferred tax asset of $2 million related to liability-classified restricted stock units for the year ended December 31, 2018. As of December 31, 2018, there was $22 million of total unrecognized compensation cost related to liability-classified restricted stock units that is expected to be recognized over a weighted-average period of three years .  The following table summarizes restricted stock unit activity to be paid out in cash for the year ended December 31, 2018 and provides information for unvested units as of December 31, 2018:     Number Weighted Average  of Units Fair Value  (in thousands)  Unvested shares at January 1, 2018 – $ –  Granted 12,216 $ 3.69  Vested (232) $ 5.14  Forfeited (1) (3,782) $ 4.86  Unvested units at December 31, 2018 8,202 $ 3.41  (1) Includes 2,766,610 units related to the reduction in workforce for the year ended December 31, 2018.  Liability-Classified Performance Units  In the first quarter of 2018, the Company granted performance units that vest over a three -year period and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The liability-classified performance unit awards include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers, collectively the “Performance Measures.” The fair values of the two market conditions are calculated by Monte Carlo models on a quarterly basis.     (in millions) 2018  Liability-classified performance units – general and administrative expense $ 2  Liability-classified performance units – general and administrative expense capitalized $ –  The Company also recorded a deferred tax asset of $1 million related to liability-classified performance units for the year ended December 31, 2 018. As of December 31, 2018, there was $9 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of two years. The final value of the performance unit awards is contingent upon the Company’s actual performance against the Performance Measures.  The following table summarizes liability-classified performance unit activity to be paid out in cash for the year ended December 31, 2018 and provides information for unvested units as of December 31, 2018:     Number Weighted Average  of Shares Fair Value  (in thousands)  Unvested shares at January 1, 2018 – $ –  Granted 3,200 $ 3.70  Vested – $ –  Forfeited (1) (397) $ 4.55  Unvested units at December 31, 2018 2,803 $ 3.41 (1) Includes 295,160 units related to the reduction in workforce for the year ended December 31, 2018. 

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2018
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 liquids. The Midstream segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes.  Prior to December 2018, the Midstream segment included the Company’s natural gas gathering business associated with its Fayetteville Shale assets. With the closing of the Fayetteville Shale sale in December 2018, the Midstream segment consists almost entirely of the Company’s marketing business.  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, gain (loss) on derivatives, loss on early extinguishment of debt 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  (in millions) Production Midstream Other Total  2018 (1)  Revenues from external customers $ 2,551 $ 1,311 $ – $ 3,862  Intersegment revenues (26) 2,434 – 2,408  Depreciation, depletion and amortization expense 514 46 – 560  Impairments 15 155 1 171  Operating income (loss) 794 ( 2 ) 4 ( 3 ) (1) 797  Interest expense (4) 124 – – 124  Loss on derivatives (118) – – (118)  Loss on early extinguishment of debt – – (17) (17)  Other loss, net 2 (2) – –  Provision for income taxes (4) 1 – – 1  Assets 4,872 ( 5 ) 539 386 ( 6 ) 5,797  Capital investments (7) 1,231 9 8 1,248   2017  Revenues from external customers $ 2,105 $ 1,098 $ – $ 3,203  Intersegment revenues (19) 2,100 – 2,081  Depreciation, depletion and amortization expense 440 64 – 504  Operating income (loss) 549 183 (1) 731  Interest expense ( 4) 135 – – 135  Gain on derivatives 421 1 – 422  Loss on early extinguishment of debt – – (70) (70)  Other income, net 4 1 – 5  Benefit for income taxes (4) (93) – – (93)  Assets 5,109 (5) 1,288 1,124 (6) 7,521  Capital investments (7) 1,248 32 13 1,293   2016  Revenues from external customers $ 1,435 $ 1,001 $ – $ 2,436  Intersegment revenues (22) 1,568 – 1,546  Depreciation, depletion and amortization expense 371 65 – 436  Impairment of natural gas and oil properties 2,321 – – 2,321  Operating income (loss) (2,399) (8) 209 (9) – (2,190)  Interest expense (4) 87 1 – 88  Loss on derivatives (338) (1) – (339)  Loss on early extinguishment of debt – – (51) (51)  Other income (loss), net – (2) (2) (4)  Benefit for income taxes (4) (29) – – (29)  Assets 4,178 (5) 1,331 1,567 (6) 7,076  Capital investments (7) 623 21 4 648  (1) Includes the impact of approximately eleven months of Fayetteville Shale-related E&P and Midstream operations which were divested on December 3, 2018.  (2) Operating income for the E&P segment includes $37 million related to restructuring charges for the year ended December 31, 2018.  (3) Operating income for the Midstream segment includes $2 million related to restructuring charges for the year ended December 31, 2018.  (4) 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.  (5) Includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities.  (6) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At December 31, 2018, other assets includes approximately $201 million in cash and cash equivalents.  (7) Capital investments include a decrease of $53 million for 2018 and an increase of $43 million for 2016 related to the change in accrued expenditures between years. There was no impact to 2017.  (8) Operating loss for the E&P segment includes $81 million related to restructuring and other one-time charges for the year ended December 31, 2016.  (9) Operating income for the Midstream segment includes $3 million related to restructuring charges for the year ended December 31, 2016.  Included in intersegment revenues of the Midstream segment are $2.3 billion, $1.9 billion and $1.3 billion for 2018, 2017 and 2016, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2018
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Information	(15) CONDENSED CONSOLIDATING FINANCIAL INFORMATION  In April 2018, the Company entered into the 2018 credit facility. Pursuant to requirements under the indentures governing the Company’s senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s senior notes (the “Guarantor Subsidiaries”). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 2018 credit facility but not of the senior notes. These guarantees are full and unconditional and joint and several among the Guarantor Subsidiaries. Certain of the Company’s subsidiaries which are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes (“Non-Guarantor Subsidiaries”). See Note 8 for additional information on the Company’s 2018 revolving credit facility and senior notes. At the closing of the Fayetteville Shale sale in December 2018, the Company’s subsidiaries being sold were released from these guarantees. See Note 3 for additional information on the divestiture of the Company’s Fayetteville Shale-related subsidiaries.  The following financial information reflects consolidating financial information of Southwestern Energy Company (the parent and issuer company), its Guarantor Subsidiaries on a combined basis and the Non-Guarantor Subsidiaries on a combined basis, prepared on the equity basis of accounting. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.     CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS    (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated  Year ended December 31, 2018:  Operating Revenues:  Gas sales $ – $ 1,998 $ – $ – $ 1,998  Oil sales – 196 – – 196  NGL sales – 352 – – 352  Marketing – 1,222 – – 1,222  Gas gathering – 89 – – 89  Other – 5 – – 5  – 3,862 – – 3,862  Operating Costs and Expenses:  Marketing purchases – 1,229 – – 1,229  Operating expenses – 785 – – 785  General and administrative expenses – 209 – – 209  Restructuring charges – 39 – – 39  Depreciation, depletion and amortization – 560 – – 560  Impairments – 171 – – 171  Gain on sale of assets, net – (17) – – (17)  Taxes, other than income taxes – 89 – – 89  – 3,065 – – 3,065  Operating Income – 797 – – 797  Interest Expense, Net 124 – – – 124  Loss on Derivatives – (118) – – (118)  Loss on Early Extinguishment of Debt (17) – – – (17)  Equity in Earnings of Subsidiaries 678 – – (678) –   Income (Loss) Before Income Taxes 537 679 – (678) 538  Provision for Income Taxes – 1 – – 1  Net Income (Loss) $ 537 $ 678 $ – $ (678) $ 537  Mandatory convertible preferred stock dividend – – – – –  Participating securities – mandatory convertible preferred stock 2 – – – 2  Net Income (Loss) Attributable to Common Stock $ 535 $ 678 $ – $ (678) $ 535   Net Income (Loss) $ 537 $ 678 $ – $ (678) $ 537  Other comprehensive income 8 – – – 8  Comprehensive Income (Loss) $ 545 $ 678 $ – $ (678) $ 545     CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS   (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated Year ended December 31, 2017: Operating Revenues:  Gas sales $ – $ 1,793 $ – $ – $ 1,793  Oil sales – 102 – – 102  NGL sales – 206 – – 206  Marketing – 972 – – 972  Gas gathering – 126 – – 126  Other – 4 – – 4  – 3,203 – – 3,203 Operating Costs and Expenses:  Marketing purchases – 976 – – 976  Operating expenses – 671 – – 671  General and administrative expenses – 233 – – 233  Depreciation, depletion and amortization – 504 – – 504  Gain on sale of assets, net – (6) – – (6)  Taxes, other than income taxes – 94 – – 94  – 2,472 – – 2,472  Operating Income – 731 – – 731  Interest Expense, Net 135 – – – 135  Gain on Derivatives – 422 – – 422  Loss on Early Extinguishment of Debt (70) – – – (70)  Other Income, Net – 5 – – 5  Equity in Earnings of Subsidiaries 1,251 – – (1,251) –   Income (Loss) Before Income Taxes 1,046 1,158 – (1,251) 953  Benefit from Income Taxes – (93) – – (93)  Net Income (Loss) $ 1,046 $ 1,251 $ – $ (1,251) $ 1,046  Mandatory convertible preferred stock dividend 108 – – – 108  Participating securities – mandatory convertible preferred stock 123 – – – 123  Net Income (Loss) Attributable to Common Stock $ 815 $ 1,251 $ – $ (1,251) $ 815   Net Income (Loss) $ 1,046 $ 1,251 $ – $ (1,251) $ 1,046  Other comprehensive income (5) 6 6 (12) (5)  Comprehensive Income (Loss) $ 1,041 $ 1,257 $ 6 $ (1,263) $ 1,041        CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS   (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated Year ended December 31, 2016: Operating Revenues:  Gas sales $ – $ 1,273 $ – $ – $ 1,273  Oil sales – 69 – – 69  NGL sales – 92 – – 92  Marketing – 864 – – 864  Gas gathering – 138 – – 138  – 2,436 – – 2,436 Operating Costs and Expenses:  Marketing purchases – 864 – – 864  Operating expenses – 592 – – 592  General and administrative expenses – 247 – – 247  Restructuring charges – 73 – – 73  Depreciation, depletion and amortization – 436 – – 436  Impairments – 2,266 55 – 2,321  Taxes, other than income taxes – 93 – – 93  – 4,571 55 – 4,626  Operating Income – (2,135) (55) – (2,190)  Interest Expense, Net 88 – – – 88  Loss on Derivatives – (339) – – (339)  Loss on Early Extinguishment of Debt (51) – – – (51)  Other Loss, Net – (4) – – (4)  Equity in Earnings of Subsidiaries (2,504) (55) – 2,559 –   Income (Loss) Before Income Taxes (2,643) (2,533) (55) 2,559 (2,672)  Benefit from Income Taxes – (29) – – (29)  Net Income (Loss) $ (2,643) $ (2,504) $ (55) $ 2,559 $ (2,643)  Mandatory convertible preferred stock dividend 108 – – – 108  Participating securities – mandatory convertible preferred stock – – – – –  Net Income (Loss) Attributable to Common Stock $ (2,751) $ (2,504) $ (55) $ 2,559 $ (2,751)   Net Income (Loss) $ (2,643) $ (2,504) $ (55) $ 2,559 $ (2,643)  Other comprehensive income 9 3 3 (6) 9  Comprehensive Income (Loss) $ (2,634) $ (2,501) $ (52) $ 2,553 $ (2,634)     CONDENSED CONSOLIDATED BALANCE SHEETS    (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated  December 31, 2018:  ASSETS  Cash and cash equivalents $ 201 $ – $ – $ – $ 201  Accounts receivable, net 4 577 – – 581  Other current assets 8 166 – – 174  Total current assets 213 743 – – 956   Intercompany receivables 7,932 – – (7,932) –   Natural gas and oil properties, using the full cost method – 24,128 52 – 24,180  Gathering systems – 11 27 – 38  Other 197 290 – – 487  Less: Accumulated depreciation, depletion and amortization (154) (19,840) (55) – (20,049)  Total property and equipment, net 43 4,589 24 – 4,656   Investments in subsidiaries (equity method) – 24 – (24) –  Other long-term assets 19 166 – – 185  TOTAL ASSETS $ 8,207 $ 5,522 $ 24 $ (7,956) $ 5,797   LIABILITIES AND EQUITY  Accounts payable $ 113 $ 496 $ – $ – $ 609  Other current liabilities 115 122 – – 237  Total current liabilities 228 618 – – 846   Intercompany payables – 7,932 – (7,932) –   Long-term debt 2,318 – – – 2,318  Pension and other postretirement liabilities 46 – – – 46  Other long-term liabilities 54 171 – – 225  Negative carrying amount of subsidiaries, net 3,199 – – (3,199) –  Total long-term liabilities 5,617 171 – (3,199) 2,589  Commitments and contingencies  Total equity (accumulated deficit) 2,362 (3,199) 24 3,175 2,362  TOTAL LIABILITIES AND EQUITY $ 8,207 $ 5,522 $ 24 $ (7,956) $ 5,797     CONDENSED CONSOLIDATED BALANCE SHEETS    (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated  December 31, 2017:  ASSETS  Cash and cash equivalents $ 914 $ 2 $ – $ – $ 916  Accounts receivable, net – 428 – – 428  Other current assets 10 155 – – 165  Total current assets 924 585 – – 1,509   Intercompany receivables 7,978 – – (7,978) –   Natural gas and oil properties, using the full cost method – 23,834 56 – 23,890  Gathering systems – 1,288 27 – 1,315  Other 207 357 – – 564  Less: Accumulated depreciation, depletion and amortization (134) (19,804) (59) – (19,997)  Total property and equipment, net 73 5,675 24 – 5,772   Investments in subsidiaries (equity method) – 24 – (24) –  Other long-term assets 16 224 – – 240  TOTAL ASSETS $ 8,991 $ 6,508 $ 24 $ (8,002) $ 7,521   LIABILITIES AND EQUITY  Accounts payable $ 73 $ 460 $ – $ – $ 533  Other current liabilities 110 137 – – 247  Total current liabilities 183 597 – – 780   Intercompany payables – 7,978 – (7,978) –   Long-term debt 4,391 – – – 4,391  Pension and other postretirement liabilities 58 – – – 58  Other long-term liabilities 13 300 – – 313  Negative carrying amount of subsidiaries, net 2,367 – – (2,367) –  Total long-term liabilities 6,829 300 – (2,367) 4,762  Commitments and contingencies  Total equity (accumulated deficit) 1,979 (2,367) 24 2,343 1,979  TOTAL LIABILITIES AND EQUITY $ 8,991 $ 6,508 $ 24 $ (8,002) $ 7,521      CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS    (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated  Year ended December 31, 2018:  Net cash provided by (used in) operating activities $ 304 $ 1,595 $ – $ (676) $ 1,223  Investing activities:  Capital investments (20) (1,270) – – (1,290)  Proceeds from the sale of property and equipment – 1,643 – – 1,643  Other – 6 – – 6  Net cash used in investing activities (20) 379 – – 359  Financing activities  Intercompany activities 1,300 (1,976) – 676 –  Payments on long-term debt (2,095) – – – (2,095)  Payments on revolving credit facility (1,983) – – – (1,983)  Borrowings under revolving credit facility 1,983 – – – 1,983  Purchase of treasury stock (180) – – – (180)  Preferred stock dividend (27) – – – (27)  Other 5 – – – 5  Net cash provided by (used in) financing activities (997) (1,976) – 676 (2,297)  Increase (decrease) in cash and cash equivalents (713) (2) – – (715)  Cash and cash equivalents at beginning of year 914 2 – – 916  Cash and cash equivalents at end of year $ 201 $ – $ – $ – $ 201   Year ended December 31, 2017:  Net cash provided by (used in) operating activities $ 1,019 $ 1,327 $ – $ (1,249) $ 1,097  Investing activities:  Capital investments (13) (1,250) (5) – (1,268)  Proceeds from the sale of property and equipment 1 9 – – 10  Other 1 5 – – 6  Net cash used in investing activities (11) (1,236) (5) – (1,252)  Financing activities  Intercompany activities (1,158) (96) 5 1,249 –  Payments on short-term debt (328) – – – (328)  Payments on long-term debt (1,139) – – – (1,139)  Proceeds from issuance of long-term debt 1,150 – – – 1,150  Preferred stock dividend (16) – – – (16)  Other (19) – – – (19)  Net cash provided by (used in) financing activities (1,510) (96) 5 1,249 (352)  Increase (decrease) in cash and cash equivalents (502) (5) – – (507)  Cash and cash equivalents at beginning of year 1,416 7 – – 1,423  Cash and cash equivalents at end of year $ 914 $ 2 $ – $ – $ 916  Year ended December 31, 2016:  Net cash provided by (used in) operating activities $ (2,610) $ 550 $ – $ 2,558 $ 498 Investing activities:  Capital investments (3) (590) – – (593)  Proceeds from the sale of property and equipment 2 428 – – 430  Other 1 – – – 1  Net cash used in investing activities – (162) – – (162) Financing activities  Intercompany activities 2,950 (392) – (2,558) –  Payments on long-term debt (1,175) – – – (1,175)  Payments on revolving credit facility (3,268) – – – (3,268)  Borrowings on revolving credit facility 3,152 – – – 3,152  Payments on commercial paper (242) – – – (242)  Borrowings under commercial paper 242 – – – 242  Proceeds from issuance of long-term debt 1,191 – – – 1,191  Proceeds from issuance of common stock 1,247 – – – 1,247  Preferred stock dividend (27) – – – (27)  Other (48) – – – (48)  Net cash provided by (used in) financing activities 4,022 (392) – (2,558) 1,072  Increase (decrease) in cash and cash equivalents 1,412 (4) – – 1,408  Cash and cash equivalents at beginning of year 4 11 – – 15  Cash and cash equivalents at end of year $ 1,416 $ 7 $ – $ – $ 1,423

Supplemental Quarterly Results

Supplemental Quarterly Results	12 Months Ended
	Dec. 31, 2018
Supplemental Quarterly Results [Abstract]
Supplemental Quarterly Results	SUP PLEMENTAL QUARTERLY RESULTS (UNAUDITED)  The following is a summary of the quarterly results of operations for the years ended December 31, 2018 and 2017:     (in millions, except share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter  2018  Operating revenues $ 920 $ 816 $ 951 $ 1,175  Operating income 255 124 66 352  Net income (loss) attributable to common stock 205 51 (29) 307  Earnings (loss) per share – Basic 0.36 0.09 (0.05) 0.54  Earnings (loss) per share – Diluted 0.36 0.09 (0.05) 0.54   2017  Operating revenues $ 846 $ 811 $ 737 $ 809  Operating income 266 188 110 167  Net income attributable to common stock 281 224 43 267  Earnings per share – Basic 0.57 0.45 0.09 0.53  Earnings per share – Diluted 0.57 0.45 0.09 0.53 

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures	12 Months Ended
	Dec. 31, 2018
Supplemental Oil and Gas Disclosures [Abstract]
Supplemental Oil and Gas Disclosures	SUP PLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)  The Company’s operating natural gas and oil properties are located solely in the United States. The Company also has licenses to properties in Canada, the development of which is subject to an indefinite moratorium. See “Our Operations – Other – New Brunswick, Canada” in Item 1 of Part 1 of this Annual Report.  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, 2018 and 2017:    (in millions) 2018 2017  Proved properties $ 22,425 $ 22,073  Unproved properties 1,755 1,817  Total capitalized costs 24,180 23,890  Less: Accumulated depreciation, depletion and amortization (19,761) (19,287)  Net capitalized costs $ 4,419 $ 4,603  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, 2018:     (in millions) 2018 2017 2016 Prior Total  Property acquisition costs $ 49 $ 70 $ 12 $ 1,346 $ 1,477  Exploration and development costs 42 23 6 23 94  Capitalized interest 77 45 28 34 184  $ 168 $ 138 $ 46 $ 1,403 $ 1,755  Of the total net unevaluated costs excluded from amortization as of December 31, 2018, approximately $1.5 billion is related to undeveloped properties in Southwest Appalachia (acquired in 2014), approximately $23 million is related to the acquisition of the Company’s undeveloped properties in Northeast Appalachia and approximately $11 million is related to the acquisition of undeveloped properties outside the Appalachian Basin. Additionally, the Company has approximately $184 million of unevaluated capitalized interest and $77 million of unevaluated costs related to 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:     (in millions, except per Mcfe amounts) 2018 2017 2016  Unproved property acquisition costs $ 164 $ 194 $ 171  Exploration costs 5 22 17  Development costs 1,014 1,024 433  Capitalized costs incurred 1,183 1,240 621  Full cost pool amortization per Mcfe $ 0.51 $ 0.45 $ 0.38  Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $115 m illion, $113 million and $152 million during 2018, 2017 and 2016, 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 $90 million, $99 million and $87 million during 2018, 2017 and 2016, respectively, which were directly related to the acquisition, exploration and development of the Company’s 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:     (in millions) 2018 2017 2016  Sales $ 2,525 $ 2,086 $ 1,413  Production (lifting) costs (974) (891) (839)  Depreciation, depletion and amortization (514) (440) (371)  Impairment of natural gas and oil properties – – (2,321)  1,037 755 (2,118)  Provision (benefit) for income taxes (1) – – –  Results of operations (2) $ 1,037 $ 755 $ (2,118)  (1) Prior to the recognition of a valuation allowance, in 2018, 2017 and 2016 the Company recognized income tax provisions of $254 million, $287 million and $805 million, respectively.  (2) Results of operations exclude the gain (loss) on unsettled 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 99% of the present worth of the Company’s total proved reserves as of December 31 of 2018, 2017 and 2016. 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, oil and NGL reserves for 2018, 2017 and 2016, all of which were located in the United States:     Natural  Gas Oil NGL Total  (Bcf) (MBbls) (MBbls) (Bcfe)  December 31, 2015 5,917 8,753 40,947 6,215  Revisions of previous estimates due to price (983) (582) (8,337) (1,037)  Revisions of previous estimates other than price 537 2,146 22,131 683  Extensions, discoveries and other additions 198 2,417 11,576 282  Production (788) (2,192) (12,372) (875)  Acquisition of reserves in place – – – –  Disposition of reserves in place (15) (19) (14) (15)  December 31, 2016 4,866 10,523 53,931 5,253  Revisions of previous estimates due to price 1,327 3,197 57,447 1,691  Revisions of previous estimates other than price 571 (1,529) 13,102 641  Extensions, discoveries and other additions (1) 5,159 55,772 432,220 8,087  Production (797) (2,327) (14,245) (897)  Acquisition of reserves in place – – – –  Disposition of reserves in place – – – –  December 31, 2017 11,126 65,636 542,455 14,775  Revisions of previous estimates due to price 96 788 8,912 154  Revisions of previous estimates other than price 316 410 8,855 372  Extensions, discoveries and other additions 753 5,830 36,823 1,009  Production (807) (3,407) (19,706) (946)  Acquisition of reserves in place – – – –  Disposition of reserves in place (2) (3,440) (250) (276) (3,443)  December 31, 2018 8,044 69,007 577,063 11,921  (1) The 2017 PUD additions are primarily associated with the increase in commodity prices.  (2) The 2018 disposition is primarily associated with the Fayetteville Shale sale.     Natural  Gas Oil NGL Total  (Bcf) (MBbls) (MBbls) (Bcfe)  Proved developed reserves as of:  December 31, 2016 4,789 10,523 53,931 5,176  December 31, 2017 6,979 14,513 142,213 7,920  December 31, 2018 4,395 18,037 175,480 5,557  Proved undeveloped reserves as of:  December 31, 2016 77 – – 77  December 31, 2017 4,147 51,123 400,242 6,855  December 31, 2018 3,649 50,970 401,583 6,364  The Company’s estimated proved natural gas, oil and NGL reserves w ere 11,921 B cfe at December 31, 2018, compared to 14,775 Bcfe at December 31, 2017. The Company’s reserves decreased in 2018, compared to 2017, as the disposition of the reserves related to the Fayetteville Shale was only partially offset by positive extensions, discoveries, other additions and revisions in the Appalachian Basin. The increase in the Company's reserves in 2017 primarily resulted through extensions, discoveries and other additions in the Appalachian Basin along with increases in both price and performance revisions across the portfolio. The decrease in the Company's reserves in 2016 was primarily due to the decrease in commodity prices.  The following table summarizes the changes in reserves for 2016, 2017 and 2018:     Appalachia Fayetteville  (in Bcfe) Northeast Southwest Shale (1) Other (2) Total  December 31, 2015 2,319 611 3,281 4 6,215  Net revisions  Price revisions (794) (127) (116) – (1,037)  Performance and production revisions 318 199 163 3 683  Total net revisions (476) 72 47 3 (354)  Extensions, discoveries and other additions  Proved developed 81 157 19 – 257  Proved undeveloped – – 25 – 25  Total reserve additions 81 157 44 – 282  Production (350) (148) (375) (2) (875)  Acquisition of reserves in place – – – – –  Disposition of reserves in place – (15) – – (15)  December 31, 2016 1,574 677 2,997 5 5,253  Net revisions  Price revisions 903 738 49 1 1,691  Performance and production revisions 154 125 358 4 641  Total net revisions 1,057 863 407 5 2,332  Extensions, discoveries and other additions  Proved developed 790 419 48 1 1,258  Proved undeveloped 1,100 5,186 543 – 6,829  Total reserve additions 1,890 5,605 591 1 8,087  Production (395) (183) (316) (3) (897)  Acquisition of reserves in place – – – – –  Disposition of reserves in place – – – – –  December 31, 2017 4,126 6,962 3,679 8 14,775  Net revisions  Price revisions 41 106 6 1 154  Performance and production revisions 107 272 (6) (1) 372  Total net revisions 148 378 – – 526  Extensions, discoveries and other additions  Proved developed 154 22 1 – 177  Proved undeveloped 397 435 – – 832  Total reserve additions 551 457 1 – 1,009  Production (459) (243) (243) (1) (946)  Acquisition of reserves in place – – – – –  Disposition of reserves in place – – (3,437) (6) (3,443)  December 31, 2018 4,366 7,554 – 1 11,921  (1) The Fayetteville Shale E&P assets and associated reserves were divested December 3, 2018.  (2) Other includes properties outside of the Appalachian Basin and Fayetteville Shale.  The Company's December 31, 2018 proved reserves included 190 Bcfe of proved undeveloped reserves from 30 locations that had 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 had a negative present value of $24 million when discounted at 10%. The Company made a final investment decision and is committed to developing these reserves within the next five years from the date of initial booking.  The Company's December 31, 2017 proved reserves included 1,375 Bcfe of proved undeveloped reserves from 330 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $124 million present value when discounted at 10% . The Company's December 31, 2016 proved reserves included 77 Bcfe of proved undeveloped reserves from 15 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $11 million present value when discounted 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, oil and NGL reserves as of December 31, 2018, 2017 and 2016 are calculated after income taxes, discounted using a 10% annual discount rate and do not purport to present the fair market value of the Company’s proved gas, oil and NGL reserves:     (in millions) 2018 2017 2016  Future cash inflows $ 34,523 $ 36,576 $ 9,064  Future production costs (15,347) (18,390) (5,880)  Future development costs (1) (4,095) (4,676) (485)  Future income tax expense (2) (2,079) (1,342) –  Future net cash flows 13,002 12,168 2,699  10% annual discount for estimated timing of cash flows (7,003) (6,606) (1,034)  Standardized measure of discounted future net cash flows $ 5,999 $ 5,562 $ 1,665  (1) Includes abandonment costs.  (2) The December 31, 2016 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis.  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 as follows:     (in millions) 2018 2017 2016  Natural gas (per MMBtu) $ 3.10 $ 2.98 $ 2.48  Oil (per Bbl) 65.56 47.79 39.25  NGLs (per Bbl) 17.64 14.41 6.74  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 2018, 2017 and 2016:     (in millions) 2018 2017 2016  Standardized measure, beginning of year $ 5,562 $ 1,665 $ 2,417  Sales and transfers of natural gas and oil produced, net of production costs (1,564) (1,191) (574)  Net changes in prices and production costs 2,162 1,963 (415)  Extensions, discoveries, and other additions, net of future production and development costs 335 1,715 45  Acquisition of reserves in place – – –  Sales of reserves in place (2,022) – (10)  Revisions of previous quantity estimates 361 1,721 (140)  Net change in income taxes (304) (222) –  Changes in estimated future development costs (166) (6) 71  Previously estimated development costs incurred during the year 536 55 114  Changes in production rates (timing) and other 521 (304) (85)  Accretion of discount 578 166 242  Standardized measure, end of year $ 5,999 $ 5,562 $ 1,665

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2018
Organization and Summary of Significant Accounting Policies [Abstract]
Nature of Operations	Nature of Operations  Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and NGL exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business and, until the Fayetteville Shale sale, its gathering business in Arkansas (“Midstream”). Southwestern conducts most of its business through subsidiaries and operates principally in two segments: E&P and Midstream. The Company also has drilling rigs located in Pennsylvania and West Virginia and provides oilfield products and services, principally serving its E&P operations.  E&P. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania and West Virginia. The Company’s operations in northeast Pennsylvania, herein referred to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern refers to its properties located in Pennsylvania and West Virginia as the “Appalachian Basin.”  Midstream. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs produced in its E&P operations.  In September 2018, the Company announced that it had signed an agreement to sell 100% of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets for $1,865 million in cash, subject to customary closing adjustments (“Fayetteville Shale sale”). The sale closed December 3, 2018 resulting in net proceeds of approximately $1,650 million, following adjustments of $215 million primarily related to the net cash flows from the economic effective date to the closing date and certain other working capital adjustments, and is discussed in further detail in Note 3 . The historical financial and operating results of the assets sold are included in these financial statements for the period of time during which we owned the assets.
Basis of Presentation	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 accordance 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 2018 presentation. In the first quarter of 2018, the Company adopted ASU 2017-07 which required that all non-service costs related to the Company’s pension plan be reclassified from general and administrative expenses to other income (loss), net for all periods presented. The adoption of ASU 2017-07 resulted in a reclassification of $5 million of curtailment and settlement costs from restructuring charges to other income (loss), net on the Company’s consolidated statements of operations for the year ended December 31, 2016.
Principles of Consolidation	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.  In 2015, the Company purchased an 86% ownership in a limited partnership which owns and operates a gathering system in Northeast Appalachia. Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The investor’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the years ended December 31, 2018, 2017 and 2016 was insignificant.
Major Customers	Major Customers  The Company sells the vast majority of its E&P natural gas, oil and NGL production to third-party customers through its marketing subsidiary. For the years ended December 31, 2018 and 2017, two subsidiaries of Royal Dutch Shell Plc in aggregate accounted for approximately 10.4% and 10.3% , respectively, of total natural gas, oil and NGL sales. In 2016, no single customer accounted for 10% or greater of our total sales. The Company believes that the loss of a major customer would not have a material adverse effect on its ability to sell its natural gas, oil and NGL production because alternative purchasers are available.
Cash and Cash Equivalents	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 as the Company monitors the credit status of the financial institutions holding its cash and marketable securities. The following table presents a summary of cash and cash equivalents as of December 31, 2018 and December 31, 2017:    For the years ended December 31,  (in millions) 2018 2017  Cash $ 32 $ 261  Marketable securities (1) 169 605  Other cash equivalents – 50 (2)  Total $ 201 $ 916  (1) Consists of government stable value money market funds.  (2) Consists of time deposits.  Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. 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 $34 million and $17 million as of December 31, 2018 and 2017, respectively.
Property, Depreciation, Depletion and Amortization	Property, Depreciation, Depletion and Amortization  Natural Gas and Oil Properties . The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). 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, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. 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.  Costs associated with unevaluated properties are excluded from the amortization base until the properties are evaluated or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from the amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. The Company’s decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on several factors, including drilling plans, availability of capital, project economics and drilling results from adjacent acreage. At December 31, 2018, the Company had a t otal of $1,755 m illion of costs excluded from the amortization base, all of which related to its properties in the United States. Inclusion of some or all of these costs in the Company’s United States properties in the future, without adding any associated reserves, could result in additional ceiling test impairments.  At December 31, 2018, using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.10 per MMBtu, West Texas Intermediate oil of $65.56 per barrel and NGLs of $17.64 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, 2018. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2018.  Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.98 per MMBtu, West Texas Intermediate oil of $47.79 per barrel and NGLs of $14.41 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, 2017. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2017.  The net book value of the Company’s United States and Canada natural gas and oil properties exceeded the ceiling by approximately $641 million (net of tax) at March 31, 2016, $297 million (net of tax) at June 30, 2016 and $506 million (net of tax) at September 30, 2016 and resulted in non-cash ceiling test impairments for the quarters ended those dates. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.48 per MMBtu, West Texas Intermediate oil of $39.25 per barrel and NGLs of $6.74 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 results in a ceiling test impairment at December 31, 2016. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2016.  Gathering Systems . The Company’s investment in gathering systems was primarily in a system serving its Fayetteville Shale operations in Arkansas. These assets were included in the Fayetteville Shale sale that closed in December 2018.  Capitalized Interest . Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization.  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 the wells are no longer producing. 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 value of non-full cost pool long-lived assets is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of carrying value or fair value less costs to sell. This accounting guidance does not apply to the Company’s full cost pool assets, which are governed under SEC Regulation S-X 4-10, and thus were not classified as held for sale. Because the assets excluding the full cost pool met the criteria for held for sale accounting in the third quarter of 2018 due to their inclusion in the Fayetteville Shale sale, the Company determined the carrying value of certain non-full cost pool assets exceeded the fair value less costs to sell. As a result, an impairment charge of $160 million was recorded for the year ended December 31, 2018, of which $145 million related to midstream gathering assets held for sale and $15 million related to E&P assets held for sale. Separately, the Company recorded an $11 million impairment of other non-core assets that were not included in the Fayetteville Shale sale, for the year ended December 31, 2018.  Intangible Assets . The carrying value of intangible assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their useful life. The Company amortized $9 million of its marketing-related intangible asset in each of the years ended December 31, 2018, 2017 and 2016.
Income Taxes	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 expected to be 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 along with the impact of recent tax reform legislation can be found in Note 10 .
Derivative Financial Instruments	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 derivative instruments to financially protect sales of natural gas, oil and NGLs. In addition, the Company uses interest rate swaps to manage exposure to unfavorable interest rate changes. Since the Company does not designate its derivatives for hedge accounting treatment, gains and losses resulting from the settlement of derivative contracts have been recognized in gain (loss) on derivatives in the consolidated statements of operations when the contracts expire and the related physical transactions of the underlying commodity are settled. Additionally, changes in the fair value of the unsettled portion of derivative contracts are also recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 5 – “Derivatives and Risk Management” and Note 7 – “Fair Value Measurements” f or a discussion of the Company’s hedging activities.
Earnings Per Share	Earnings Per Share  Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during the reportable period. 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, the vesting of unvested restricted shares of common stock, performance units and the assumed conversion of mandatory convertible preferred stock. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.  In July 2016, the Company completed an underwritten public offering of 98,900,000 shares of its common stock, with an offering price to the public of $13.00 per share. Net proceeds from the common stock offering were approximately $1,247 million, after underwriting discount and offering expenses. The proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in 2018. The remaining proceeds of the offering were used for general corporate purposes.  In January 2015, the Company issued 34,500,000 depositary shares that entitled the holder to a proportional fractional interest in the rights and preferences of the mandatory convertible preferred stock, including conversion, dividend, liquidation and voting rights. The mandatory convertible preferred stock had the non-forfeitable right to participate on an as-converted basis at the conversion rate then in effect in any common stock dividends declared and, therefore, was considered a participating security. Accordingly, it has been included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the calculation of basic earnings per share attributable to common shareholders, earnings are allocated to participating securities based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. On January 12, 2018, all outstanding shares of mandatory convertible preferred stock were converted to 74,998,614 shares of the Company’s common stock.  The Company declared dividends on its mandatory convertible preferred stock in the first, second and third quarters of 2017 that were settled partially in common stock for a total of 10,040,306 shares as well as each quarter in 2016 that were settled in common stock for a total of 9,917,799 shares.  In 2018, the Company repurchased 39,061,269 of its outstanding common stock for approximately $180 million at an average price of $4.63 per share.  The following table presents the computation of earnings per share for the years ended December 31, 2018, 2017 and 2016:    For the years ended December 31,  (in millions, except share/per share amounts) 2018 2017 2016  Net income (loss) $ 537 $ 1,046 $ (2,643)  Mandatory convertible preferred stock dividend – 108 108  Participating securities – mandatory convertible preferred stock 2 123 –  Net income (loss) attributable to common stock $ 535 $ 815 $ (2,751)   Number of common shares:  Weighted average outstanding 574,631,756 498,264,321 435,337,402  Issued upon assumed exercise of outstanding stock options – – –  Effect of issuance of non-vested restricted common stock 698,103 1,061,056 –  Effect of issuance of non-vested performance units 1,312,949 1,478,920 –  Weighted average and potential dilutive outstanding 576,642,808 500,804,297 435,337,402   Earnings (loss) per common share:  Basic $ 0.93 $ 1.64 $ (6.32)  Diluted $ 0.93 $ 1.63 $ (6.32)  The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2018, 2017 and 2016, as they would have had an antidilutive effect:    For the years ended December 31,  2018 2017 2016  Unexercised stock options 5,909,082 116,717 3,692,697  Unvested share-based payment 3,692,794 5,361,849 959,233  Performance units 642,568 765,689 884,644  Mandatory convertible preferred stock 2,465,708 74,999,895 74,999,895  Total 12,710,152 81,244,150 80,536,469 
Supplemental Disclosures of Cash Flow Information	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, 2018, 2017 and 2016:    For the years ended December 31,  (in millions) 2018 2017 2016  Cash paid during the year for interest, net of amounts capitalized $ 135 $ 130 $ 75  Cash paid (received) during the year for income taxes 6 (5) (15)  Increase (decrease) in noncash property additions (42) 25 55 
Stock-Based Compensation	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. See Note 13 for a discussion of the Company’s stock-based compensation.
Liability-Classified Awards	Liability-Classified Awards  The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense or capitalized expense over the vesting period of the award. The Company’s liability-classified performance unit awards include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute total shareholder return and the other on relative total shareholder return as compared to a group of the Company’s peers. The fair values of the two market conditions are calculated by Monte Carlo models on a quarterly basis.
Treasury Stock	Treasury Stock  In the third quarter of 2018, the Company announced its intention to repurchase up to $200 million of its outstanding common stock using a portion of the net proceeds from the Fayetteville Shale sale. As of December 31, 2018, approximately $180 million has been spent to repurchase 39,061,269 shares at an average price of $4.63 per share.  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 liabilities 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, are presented as treasury stock and are carried at cost. As of December 31, 2018 and 2017, 10,653 shares and 31,269 shares, respectively, were held in the Rabbi Trust and were accounted for as treasury stock. In 2018, 20,616 shares were released from the Rabbi Trust due to a reduction in our workforce. These shares are still held as treasury stock.
Foreign Currency Translation	Foreign Currency Translation  The Company has designated the Canadian dollar as the functional currency for its activities 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 other comprehensive income within stockholders’ equity.
New Accounting Standards Implemented in this Report	New Accounting Standards Implemented in this Report  In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606, as subsequently amended). ASC 606 supersedes the revenue recognition requirements in topic 605, Revenue Recognition, and requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which an entity expects to be entitled to in exchange for those goods or services. The Company adopted ASC 606 with an effective date of January 2018 using the modified retrospective approach. For public entities, ASC 606 became effective for fiscal years beginning after December 15, 2017. The adoption of this standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows. Additional disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flow from contracts with customers are available in Note 4 – “Revenue Recognition” .  In March 2017, the FASB issued Accounting Standards Update No. 2017-07, Compensation - Retirement Benefits (Topic 715) (“Update 2017-07”), which provides additional guidance on the presentation of net benefit cost in the statement of operations and on the components eligible for capitalization in assets, and requires retrospective adoption. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of the net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The Company adopted Update 2017-07 during the first quarter of 2018 resulting in no material impact to its consolidated statement of operations, financial position or cash flows. The non-service cost components of net periodic benefit cost are no longer presented as a component of general and administrative expense, but are now presented as a component of Other Income, Net for the years ended December 31, 2018, 2017 and 2016, and are disclosed in Note 12 – “Retirement and Employment Benefit Plans” . The Company ceased capitalizing the non-service components of net periodic benefit costs prospectively as of the beginning of the first quarter of 2018.  In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (Topic 230) (“Update 2016-15”), which seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The Company adopted this update during the first quarter of 2018 resulting in no impact on its consolidated statement of cash flows.  In February 2018, the FASB issued Accounting Standards Update No. 2018-02 that will amend the FASB Accounting Standards relating to tax effects in accumulated other comprehensive income (Topic 220) (“Updated 2018-02”). Update 2018-02 permits a company to reclassify the stranded income tax effects of the Tax Reform Act on items within accumulated comprehensive income to retained earnings. Although the amendments in Update 2018-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, the Company elected to early adopt the amendments of Update 2018-02 in the third quarter of 2018. The implementation did not have a material impact on the Company’s consolidated statement of operations, financial position or cash flows due to the tax valuation allowance currently in place. Any adjustments required under this update were fully offset by valuation allowance adjustments for both continuing operations and accumulated other comprehensive income.
New Accounting Standards Not Yet Implemented in this Report	New Accounting Standards Not Yet Implemented in this Report  In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“Update 2016-02”), which seeks to increase transparency and comparability among organizations by, among other things, recognizing lease assets and lease liabilities on the balance sheet for leases classified as operating leases under previous GAAP and disclosing key information about leasing arrangements. The codification was amended through additional ASUs. Through the year ended December 31, 2018 , the Company finalized its contract reviews for leases in effect at year-end, drafted its accounting policies, evaluated the new disclosure requirements and implemented a software solution. Upon adoption, the Company expects to recognize a discounted right-of-use asset and corresponding lease liability between $95 million and $115 million. The Company continues to review new contracts commenced during 2019 to determine the appropriate lease accounting treatment where applicable.  ASC 842 allows issuers to elect the date of initial application as either the beginning of the period of adoption or the beginning of the earliest comparative period presented in the financial statements. The Company plans to elect the period of adoption, January 1, 2019, as its initial application date which would not result in restating prior comparative periods. The adoption of this standard is not expected to materially change the Company’s consolidated statement of operations or its consolidated statement of cash flows. The Form 10-Q filing for the quarter ended March 31, 2019 will include the full impact of ASC 842, along with the presentation of the discounted right-of-use asset and lease liability on the consolidated balance sheet.

Organization and Summary of S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Organization and Summary of Significant Accounting Policies [Abstract]
Summary of Cash and Cash Equivalents	  For the years ended December 31,  (in millions) 2018 2017  Cash $ 32 $ 261  Marketable securities (1) 169 605  Other cash equivalents – 50 (2)  Total $ 201 $ 916  (1) Consists of government stable value money market funds.  (2) Consists of time deposits.
Schedule of Earnings Per Share	   For the years ended December 31,  (in millions, except share/per share amounts) 2018 2017 2016  Net income (loss) $ 537 $ 1,046 $ (2,643)  Mandatory convertible preferred stock dividend – 108 108  Participating securities – mandatory convertible preferred stock 2 123 –  Net income (loss) attributable to common stock $ 535 $ 815 $ (2,751)   Number of common shares:  Weighted average outstanding 574,631,756 498,264,321 435,337,402  Issued upon assumed exercise of outstanding stock options – – –  Effect of issuance of non-vested restricted common stock 698,103 1,061,056 –  Effect of issuance of non-vested performance units 1,312,949 1,478,920 –  Weighted average and potential dilutive outstanding 576,642,808 500,804,297 435,337,402   Earnings (loss) per common share:  Basic $ 0.93 $ 1.64 $ (6.32)  Diluted $ 0.93 $ 1.63 $ (6.32) 
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	  For the years ended December 31,  2018 2017 2016  Unexercised stock options 5,909,082 116,717 3,692,697  Unvested share-based payment 3,692,794 5,361,849 959,233  Performance units 642,568 765,689 884,644  Mandatory convertible preferred stock 2,465,708 74,999,895 74,999,895  Total 12,710,152 81,244,150 80,536,469 
Schedule of Supplemental Disclosures of Cash Flow Information	  For the years ended December 31,  (in millions) 2018 2017 2016  Cash paid during the year for interest, net of amounts capitalized $ 135 $ 130 $ 75  Cash paid (received) during the year for income taxes 6 (5) (15)  Increase (decrease) in noncash property additions (42) 25 55 

Restructuring Charges (Tables)

Restructuring Charges (Tables)	12 Months Ended
	Dec. 31, 2018
Restructuring Cost and Reserve [Line Items]
Summary of Restructuring Charges	  For the years ended December 31,  (in millions) 2018 (1) 2017 2016 (2)  Reduction in workforce $ 23 $ – $ 73  Fayetteville Shale sale-related 16 – –  Total restructuring charges $ 39 $ – $ 73  (1) Does not include a $4 million gain for the year ended December 31, 2018 related to curtailment of the other postretirement benefit plan presented in other income (loss), net on the consolidated statements of operations.  (2) Does not include a $5 million net loss for the year ended December 31, 2016 related to the curtailment and settlement of the pension and other postretirement benefit plans presented in other income (loss), net on the consolidated statements of operations.
Summary of Liabilities Associated with Restructuring Activities	  (in millions)  Liability at December 31, 2017 $ –  Additions 39  Distributions 34  Liability at December 31, 2018 $ 5 
Workforce Reduction [Member]
Restructuring Cost and Reserve [Line Items]
Summary of Restructuring Charges	 For the years ended December 31,  (in millions) 2018 2017 2016 (1)  Severance (including payroll taxes) $ 21 $ – $ 44  Stock-based compensation – – 24  Other benefits – – 3  Outplacement services, other 2 – 2  Total reduction in workforce-related restructuring charges (2) $ 23 $ – $ 73  (1) Does not include $5 million non-cash charges related to the curtailment and settlement of the pension and other postretirement benefit plans for the year ended December 31, 2016 presented in other income (loss), net in the consolidated statements of operations. See Note 12 for additional details regarding the Company’s retirement and employee benefit plans.  (2) Total restructuring charges were $21 million and $2 million for the Company’s E&P and Midstream segments, respectively, for the year ended December 31, 2018 and $70 million and $3 million for the Company’s E&P and Midstream segments, respectively, for the year ended December 31, 2016.
Fayetteville Shale [Member]
Restructuring Cost and Reserve [Line Items]
Summary of Restructuring Charges	  For the year ended  (in millions) December 31, 2018  Severance (including payroll taxes) $ 12  Office consolidation 4  Total Fayetteville Shale sale-related charges (1) (2) $ 16  (1) Total restructuring charges were $16 million for the Company’s E&P segment for the year ended December 31, 2018.  (2) Does not include a $4 million gain for the year ended December 31, 2018 related to the curtailment of the other postretirement benefit plan presented in other income (loss), net on the consolidated statements of operations.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue Recognition [Abstract]
Disaggregation of Revenue by Segment	   Intersegment  (in millions) E&P Midstream Revenues Total  Year ended December 31, 2018  Gas sales $ 1,974 $ – $ 24 $ 1,998  Oil sales 193 – 3 196  NGL sales 353 – (1) 352  Marketing – 3,497 (2,275) 1,222  Gas gathering (1) – 248 (159) 89  Other (2) 5 – – 5  Total $ 2,525 $ 3,745 $ (2,408) $ 3,862   Year ended December 31, 2017  Gas sales $ 1,775 $ – $ 18 $ 1,793  Oil sales 101 – 1 102  NGL sales 206 – – 206  Marketing – 2,867 (1,895) 972  Gas gathering – 331 (205) 126 Other (2) 4 – – 4  Total $ 2,086 $ 3,198 $ (2,081) $ 3,203   Year ended December 31, 2016  Gas sales $ 1,252 $ – $ 21 $ 1,273  Oil sales 69 – – 69  NGL sales 92 – – 92  Marketing – 2,191 (1,327) 864  Gas gathering – 378 (240) 138  Total $ 1,413 $ 2,569 $ (1,546) $ 2,436  (1) The Company’s gas gathering assets were divested in December 2018 as part of the Fayetteville Shale sale. (2) Other E&P revenues consists primarily of water sales to third-party operators.
Disaggregation of Revenue on Geographic Basis	  For the year ended December 31,  (in millions) 2018 2017 2016  North ea st Appalachia $ 1,165 $ 837 $ 470  Southwest Appalachia 817 498 259  Fayetteville Shale 537 743 675  Other 6 8 9  Total $ 2,525 $ 2,086 $ 1,413 
Reconciliation of Accounts Receivable	   (in millions) December 31, 2018 December 31, 2017  Receivables from contracts with customers $ 494 $ 322  Other accounts receivable 87 106  Total accounts receivable $ 581 $ 428 

Derivatives and Risk Manageme_2

Derivatives and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2018
Derivatives and Risk Management [Abstract]
Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value	Financial Protection on Production    Weighted Average Price per MMBtu  Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Fair value at December 31, 2018 ($ in millions)  Natural Gas  2019  Fixed price swaps 220 $ 2.93 $ – $ – $ – $ – $ 23  Two-way costless collars 53 – – 2.80 2.98 – 4  Three-way costless collars 170 – 2.48 2.90 3.28 – 8  Total 443 $ 35  2020  Fixed price swaps 24 $ 2.88 $ – $ – $ – $ – $ 5  Three-way costless collars 84 – 2.40 2.73 3.03 – –  Total 108 $ 5  2021  Three-way costless collars 37 $ – $ 2.35 $ 2.60 $ 2.93 $ – $ (1)   Basis swaps  2019 107 $ – $ – $ – $ – $ (0.29) $ (10)  2020 59 – – – – (0.44) (1)  Total 166 $ (11)    Weighted Average Price per Bbl  Volume (MBbls) Swaps Purchased Puts Sold Calls Fair value at December 31, 2018 ($ in millions)  Oil  2019  Fixed price swaps (1) 346 $ 68.74 $ – $ – $ 7  Two-way costless collars 329 – 65.00 72.30 6  Total 675 $ 13  2020  Fixed price swaps 366 $ 65.68 $ – $ – $ 6  Two-way costless collars 366 – 60.00 69.80 4  Total 732 $ 10   Propane  2019  Fixed price swaps 1,689 $ 33.12 $ – $ – $ 11   Ethane  2019  Fixed price swaps 3,687 $ 13.90 $ – $ – $ 4  2020  Fixed price swaps 732 $ 13.49 $ – $ – $ 1  (1) Includes 274 MBbls of purchased fixed price oil swaps hedged at $69.10 per barrel with a fair value of ( $6 ) million and 620 MBbls of sold fixed price oil swaps hedged at $68.90 with a fair value of $13 million.    Other Derivative Contracts  Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2018 ($ in millions)  Purchased Call Options – Natural Gas  2020 68 $ 3.63 $ 4  2021 57 3.52 2  Total 125 $ 6   Sold Call Options – Natural Gas  2019 52 $ 3.50 $ (3)  2020 137 3.39 (12)  2021 114 3.33 (7)  Total 303 $ (22)   Volume (MBbls) Weighted Average Strike Price per Bbl Fair Value at December 31, 2018 ($ in millions)  Sold Call Options – Oil  2019 270 $ 65.00 $ –    Volume (Bcf) Weighted Average Strike Price per MMBtu Basis Differential Fair Value at December 31, 2018 ($ in millions)  Storage (1)  2019  Fixed price swaps 0.8 $ 3.03 $ – $ –  Basis swaps 0.8 – (0.44) –  Total $ –  (1) The Company has entered into certain derivatives to protect the value of volumes of natural gas injected into a storage facility that will be withdrawn at a later date.
Balance Sheet Classification of Derivative Financial Instruments	 Derivative Assets  Balance Sheet Classification Fair Value  (in millions) December 31, 2018 December 31, 2017  Derivatives not designated as hedging instruments:  Fixed price swap – natural gas Derivative assets $ 32 $ 38  Fixed price swap – oil Derivative assets 13 –  Fixed price swap – propane Derivative assets 11 –  Fixed price swap – ethane Derivative assets 7 –  Two-way costless collar – natural gas Derivative assets 11 5  Two-way costless collar – oil Derivative assets 6 –  Three-way costless collar – natural gas Derivative assets 41 82  Basis swap – natural gas Derivative assets 8 2  Purchased call option – natural gas Derivative assets – 3 (1)  Interest rate swap Derivative assets 1 –  Fixed price swap – natural gas Other long-term assets 6 18  Fixed price swap – oil Other long-term assets 6 –  Fixed price swap – ethane Other long-term assets 1 –  Two-way costless collar – oil Other long-term assets 5 –  Three-way costless collar – natural gas Other long-term assets 34 39  Basis swap – natural gas Other long-term assets 3 –  Purchased call options – natural gas Other long-term assets 6 –  Total derivative assets $ 191 $ 187    Derivative Liabilities  Balance Sheet Classification Fair Value  (in millions) December 31, 2018 December 31, 2017  Derivatives not designated as hedging instruments:  Purchased fixed price swap – oil Derivative liabilities $ 6 $ –  Fixed price swap – natural gas Derivative liabilities 9 –  Fixed price swap – ethane Derivative liabilities 3 –  Two-way costless collar – natural gas Derivative liabilities 7 1  Three-way costless collar – natural gas Derivative liabilities 33 36  Basis swap – natural gas Derivative liabilities 18 23  Sold call option – natural gas Derivative liabilities 3 3  Interest rate swap Derivative liabilities – 1  Fixed price swap – natural gas Other long-term liabilities 1 1  Two-way costless collar – oil Other long-term liabilities 1 –  Three-way costless collar – natural gas Other long-term liabilities 35 30  Basis swap – natural gas Other long-term liabilities 4 –  Sold call option – natural gas Other long-term liabilities 19 15  Total derivative liabilities $ 139 $ 110  (1) Includes $1 million in premiums paid related to certain natural gas call options recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2017. As certain natural gas call options settled, the premium was amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.
Summary of Before Tax Effect of Cash Flow Hedges on Consolidated Financial Statements	 Unsettled Gain (Loss) on Derivatives Recognized in Earnings  Consolidated Statement of Operations For the years ended  Classification of Gain (Loss) December 31,  Derivative Instrument on Derivatives, Unsettled 2018 2017  (in millions)  Purchased fixed price swap – oil Gain (Loss) on Derivatives $ (6) $ –  Fixed price swap – natural gas Gain (Loss) on Derivatives (27) 232  Fixed price swap – oil Gain (Loss) on Derivatives 19 –  Fixed price swap – propane Gain (Loss) on Derivatives 11 –  Fixed price swap – ethane Gain (Loss) on Derivatives 5 –  Two-way costless collar – natural gas Gain (Loss) on Derivatives – 52  Two-way costless collar – oil Gain (Loss) on Derivatives 10 –  Three-way costless collar – natural gas Gain (Loss) on Derivatives (48) 136  Basis swap – natural gas Gain (Loss) on Derivatives 10 (36)  Purchased call option – natural gas Gain (Loss) on Derivatives 4 2  Sold call option – natural gas Gain (Loss) on Derivatives (4) 63  Interest rate swap Gain (Loss) on Derivatives 2 2  Total gain (loss) on unsettled derivatives $ (24) $ 451   Settled Gain (Loss) on Derivatives Recognized in Earnings (1)  Consolidated Statement of Operations For the years ended  Classification of Gain (Loss) December 31,  Derivative Instrument on Derivatives, Settled 2018 2017  (in millions)  Fixed price swap – natural gas Gain (Loss) on Derivatives $ (32) $ (9)  Fixed price swap – propane Gain (Loss) on Derivatives (6) –  Fixed price swap – ethane Gain (Loss) on Derivatives (8) –  Two-way costless collar – natural gas Gain (Loss) on Derivatives (1) –  Three-way costless collar – natural gas Gain (Loss) on Derivatives (9) (1)  Basis swap – natural gas Gain (Loss) on Derivatives (31) (6)  Purchased call option – natural gas Gain (Loss) on Derivatives 2 (2) –  Sold call option – natural gas Gain (Loss) on Derivatives (7) (11) (3)  Sold call option – oil Gain (Loss) on Derivatives (2) –  Interest rate swap Gain (Loss) on Derivatives – (2)  Total loss on settled derivatives $ (94) $ (29)   Total gain (loss) on derivatives $ (118) $ 422  (1) The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.  (2) Includes $1 million amortization of premiums paid related to certain natural gas call options for the year ended December 31, 2018, which is included in gain (loss) on derivatives on the consolidated statement of operations.  (3) Includes $5 million amortization of premiums paid related to certain call options for the year ended December 31, 2017.

Reclassifications from Accumu_2

Reclassifications from Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2018
Reclassifications from Accumulated Other Comprehensive Income (Loss) [Abstract]
Components of Accumulated Other Comprehensive Income (Loss)	  For the year ended December 31, 2018  (in millions) Pension and Other Postretirement Foreign Currency Total  Beginning balance, December 31, 2017 $ (30) $ (14) $ (44)  Other comprehensive (loss) before reclassifications (2) − (2)  Amounts reclassified from other comprehensive income (1) (2) 10 – 10  Net current-period other comprehensive income 8 − 8  Ending balance, December 31, 2018 $ (22) $ (14) $ (36)  (1) Deferred tax activity related to pension and other postretirement benefits was offset by a valuation allowance, resulting in no tax expense recorded for the period.  (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, 2018  (in millions)  Pension and other postretirement:  Amortization of prior service cost and net loss (1) Other Income (Loss), Net $ 10  Provision (benefit) for income taxes (2) −  Net income $ 10   Total reclassifications for the period Net income $ 10  (1) See Note 12 for additional details regarding the Company’s pension and other postretirement benefit plans.  (2) Deferred tax activity related to pension and other postretirement benefits was offset by a valuation allowance, resulting in no tax expense recorded for the period.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Measurements [Abstract]
Carrying Amount and Estimated Fair Values of Financial Instruments	    December 31, 2018 December 31, 2017  Carrying Fair Carrying Fair  (in millions) Amount Value Amount Value  Cash and cash equivalents $ 201 $ 201 $ 916 $ 916  2018 revolving credit facility due April 2023 – – – –  2016 term loan facility due December 2020 (1) (2) – – 1,191 1,191  Senior notes (1) (3) 2,342 2,190 3,242 3,358  Derivative instruments, net 52 52 77 (4) 77 (4)  (1) Excludes unamortized debt issuance costs and debt discounts.  (2) In April 2018, the Company replaced its 2016 credit facility with a new 2018 credit facility and repaid the $1,191 million secured term loan balance in full.  (3) In December 2018, the Company repurchased $900 million of certain of its outstanding senior notes with a portion of the net proceeds from the Fayetteville Shale sale.  (4) Includes $1 million in premiums paid related to certain natural gas call options recognized as a component of derivative assets within current assets on the consolidated balance sheet.
Summary of Assets and Liabilities Measured at Fair Value on Recurring Basis	    December 31, 2018  Fair Value Measurements Using:  (in millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets (Liabilities) at Fair Value  Assets  Fixed price swap – natural gas $ – $ 38 $ – $ 38  Fixed price swap – oil – 19 – 19  Fixed price swap – propane – 11 – 11  Fixed price swap – ethane – 8 – 8  Two-way costless collar – natural gas – 11 – 11  Two-way costless collar – oil – 11 – 11  Three-way costless collar – natural gas – 75 – 75  Basis swap – natural gas – 11 – 11  Purchased call option – natural gas – 6 – 6  Interest rate swap – 1 – 1  Liabilities  Purchased fixed price swap – oil – (6) – (6)  Fixed price swap – natural gas – (10) – (10)  Fixed price swap – ethane – (3) – (3)  Two-way costless collar – natural gas – (7) – (7)  Two-way costless collar – oil – (1) – (1)  Three-way costless collar – natural gas – (68) – (68)  Basis swap – natural gas – (22) – (22)  Sold call option – natural gas – (22) – (22)  Total $ – $ 52 $ – $ 52     December 31, 2017  Fair Value Measurements Using:  (in millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Assets (Liabilities) at Fair Value  Assets  Fixed price swap – natural gas $ – $ 56 $ – $ 56  Two-way costless collar – natural gas – – 5 5  Three-way costless collar – natural gas – – 121 121  Purchased call option – natural gas (1) – – 3 3  Basis swap – natural gas – – 2 2  Liabilities  Fixed price swap – natural gas – (1) – (1)  Two-way costless collar – natural gas – – (1) (1)  Three-way costless collar – natural gas – – (66) (66)  Basis swap – natural gas – – (23) (23)  Sold call option – natural gas – – (18) (18)  Interest rate swap – (1) – (1)  Total $ – $ 54 $ 23 $ 77  (1) Includes $1 million in premiums paid related to certain natural gas call options recognized as a component of derivative assets within current assets on the consolidated balance sheets at December 31, 2017.
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,  (in millions) 2018 2017  Balance at beginning of year $ 22 $ (195)  Total gains (losses):  Included in earnings (17) 199  Settlements (1) 1 18  Transfers into/out of Level 3 (2) (6) –  Balance at end of period $ – $ 22  Change in gains (losses) included in earnings relating to derivatives still held as of December 31 $ – $ 217  (1) Includes $1 million and $5 million amortization of premiums paid related to certain natural gas call options for the years ended December 31, 2018 and 2017, respectively.  (2) Commodity derivatives previously presented as Level 3 were transferred to Level 2 in the second quarter of 2018 as the Company moved from using proprietary volatility inputs and forward curves to more widely available published information, increasing market observability.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt [Abstract]
Components of Debt	   December 31, 2018  (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total  Variable rate ( 3.920% at December 31, 2018) 2018 revolving credit facility, due April 2023 $ – $ – (1) $ – $ –  4.05% Senior Notes due January 2020 (2) (3) 52 – – 52  4.10% Senior Notes due March 2022 (3) 213 (1) – 212  4.95% Senior Notes due January 2025 (2) (3) 927 (7) (1) 919  7.50 % Senior Notes due April 2026 650 (8) – 642  7.75 % Senior Notes due October 2027 500 (7) – 493  Total debt $ 2,342 $ (23) $ (1) $ 2,318     December 31, 2017  (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total  Variable rate ( 3.980% at December 31, 2017) 2016 term loan facility, due December 2020 (4) $ 1,191 $ (8) $ – $ 1,183  4.05% Senior Notes due January 2020 (2) (3) 92 – – 92  4.10% Senior Notes due March 2022 (3) 1,000 (7) – 993  4.95% Senior Notes due January 2025 (2) (3) 1,000 (8) (2) 990  7.50% Senior Notes due April 2026 650 (10) – 640  7.75% Senior Notes due October 2027 500 (7) – 493  Total debt $ 4,433 $ (40) $ (2) $ 4,391  (1) Unamortized issuance expense of $11 million associated with the 2018 revolving credit facility is classified as other long-term assets on the consolidated balance sheets and includes approximately $4 million in unamortized issuance expense associated with the Company’s previous 2016 term loan facility.  (2) In February and June 2016, Moody’s and S&P downgraded certain senior notes, which increased the interest rates by 175 basis points effective July 2016. As a result of the downgrades, interest rates increased to 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. In April and May 2018, S&P and Moody’s upgraded certain senior notes. As a result of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to the bondholders at the lower interest rate was paid in January 2019.  (3) In December 2018, the Company repurchased $40 million of its 4.05% senior notes due January 2020, $787 million of its 4.10% senior notes due March 2022 and $73 million of its 4.95% senior notes due January 2025.  (4) In April 2018, the Company repaid the $1,191 million secured term loan balance with cash on hand and borrowings under the 2018 credit facility.
Schedule of Long Term Debt Maturities	  (in millions)  2019 $ –  2020 52  2021 –  2022 213  2023 –  Thereafter 2,077  $ 2,342 

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies [Abstract]
Schedule of Future Obligation under Transportation Agreements	   Payments Due by Period  (in millions) Total Less than 1 Year 1 to 3 Years 3 to 5 Years 5 to 8 Years More than 8 Years  Infrastructure currently in service $ 5,715 $ 637 $ 1,060 $ 876 $ 1,123 $ 2,019  Pending regulatory approval and/or construction (1) 3,079 136 348 392 621 1,582  Total transportation charges $ 8,794 $ 773 $ 1,408 $ 1,268 $ 1,744 $ 3,601  (1) Based on the estimated in-service dates as of December 31, 2018.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Taxes [Abstract]
Provision (Benefit) for Income Taxes	  (in millions) 2018 2017 2016  Current:  Federal $ (5) $ (22) $ (6)  State 6 – (1)  1 (22) (7)  Deferred:  Federal – (71) (22)  State – – –  – (71) (22)  Provision (benefit) for income taxes $ 1 $ (93) $ (29) 
Reconciliation of Provision for Income Taxes	  (in millions) 2018 2017 2016  Expected provision (benefit) at federal statutory rate $ 113 $ 333 $ (935)  Increase (decrease) resulting from:  State income taxes, net of federal income tax effect 13 16 (79)  Rate impacts due to tax reform – 370 –  Changes to valuation allowance due to tax reform – (370) –  AMT tax reform impact – valuation allowance release – (68) –  Changes in uncertain tax positions – (5) (19)  Change in valuation allowance (121) (364) 1,002 Removal of sequestration fee on AMT receivables (5) – –  Other 1 (5) 2  Provision (benefit) for income taxes $ 1 $ (93) $ (29) 
Components of Deferred Tax Balances	  (in millions) 2018 2017  Deferred tax liabilities:  Differences between book and tax basis of property $ 226 $ 395  Derivative activity 12 19  Other 2 1  240 415  Deferred tax assets:  Accrued compensation 33 29  Accrued pension costs 10 14  Asset retirement obligations 15 41  Net operating loss carryforward 777 1,043  Other 14 20  849 1,147  Valuation allowance (609) (732)  Net deferred tax liability $ – $ – 
Reconciliation of Changes to the Valuation Allowance	  (in millions)  Valuation allowance as of December 31, 2017 $ 732  Changes based on 2018 activity (121)  Equity – pension benefits in OCI (2)  Valuation allowance as of December 31, 2018 $ 609 
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits	  (in millions) 2018 2017  Unrecognized tax benefits at beginning of period $ 12 $ 17  Additions based on tax positions related to the current year – –  Additions to tax positions of prior years – –  Reductions to tax positions of prior years (5) (5)  Unrecognized tax benefits at end of period $ 7 $ 12 

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligations [Abstract]
Schedule of Asset Retirement Obligations	   (in millions) 2018 2017  Asset retirement obligation at January 1 $ 165 $ 141  Accretion of discount 9 8  Obligations incurred 1 3  Obligations settled/removed (1) (116) (10)  Revisions of estimates 2 23  Asset retirement obligation at December 31 $ 61 $ 165   Current liability 6 12  Long-term liability 55 153  Asset retirement obligation at December 31 $ 61 $ 165  (1) Obligations settled/removed include $111 million related to asset divestitures in 2018, of which $107 million related to the Fayetteville Shale sale.

Retirement and Employee Benef_2

Retirement and Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2018
Retirement and Employee Benefit Plans [Abstract]
Changes in Plans Benefit Obligations, Fair Value of Assets, and Funded Status	   Other Postretirement  Pension Benefits Benefits  (in millions) 2018 2017 2018 2017  Change in benefit obligations:  Benefit obligation at January 1 $ 143 $ 117 $ 17 $ 13  Service cost 10 9 2 2  Interest cost 5 5 1 –  Participant contributions – – – –  Actuarial loss (gain) (14) 21 − 3  Benefits paid (14) (9) (1) (1)  Plan amendments – – – –  Curtailments (5) – (6) –  Benefit obligation at December 31 $ 125 $ 143 $ 13 $ 17     Other Postretirement  Pension Benefits Benefits  (in millions) 2018 2017 2018 2017  Change in plan assets:  Fair value of plan assets at January 1 $ 101 $ 81 $ – $ –  Actual return on plan assets (8) 15 – –  Employer contributions 12 14 1 1  Participant contributions – – – –  Benefits paid (14) (9) (1) (1)  Fair value of plan assets at December 31 $ 91 $ 101 $ – $ –   Funded status of plans at December 31 $ (34) $ (42) $ (13) $ (17) 
Projected Benefit Obligation, Accumulated Benefit Obligation, and Fair Value of Plan Assets	  (in millions) 2018 2017  Projected benefit obligation $ 125 $ 143  Accumulated benefit obligation 122 137  Fair value of plan assets 91 101 
Pension and Other Postretirement Benefit Costs	  Pension Benefits Other Postretirement Benefits  (in millions) 2018 2017 2016 2018 2017 2016  Service cost $ 10 $ 9 $ 11 $ 2 $ 2 $ 2  Interest cost 5 5 5 1 – 1  Expected return on plan assets (7) (6) (6) – – –  Amortization of transition obligation – – – – – –  Amortization of prior service cost – – – – – –  Amortization of net loss 2 2 2 – – –  Net periodic benefit cost 10 10 12 3 2 3  Curtailment (gain) loss – – 1 (4) – (6)  Settlement loss – – 11 – – –  Total benefit cost (benefit) $ 10 $ 10 $ 24 $ (1) $ 2 $ (3) 
Amounts Recognized in Other Comprehensive Income	   Pension Benefits Other Postretirement Benefits  (in millions) 2018 2017 2018 2017  Net actuarial (loss) gain arising during the year $ (2) $ (11) $ – $ (2)  Amortization of prior service cost – – – –  Amortization of net loss 2 2 – –  Settlements – – – – Curtailments 5 − 3 −  Tax effect (1) (1) 3 (1) 1  $ 4 $ (6) $ 2 $ (1)  (1) Deferred tax activity related to pension and other postretirement benefits was offset by a valuation allowance, resulting in no tax expense for all periods presented on the consolidated statements of operations.
Schedule of Assumptions Used	The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2018 and 2017 are as follows:    Pension Benefits Other Postretirement Benefits  2018 2017 2018 2017  Discount rate 4.35 % 3.75 % 4.35 % 3.75 %  Rate of compensation increase 3.50 % 3.50 % n/a n/a  The assumptions used in the measurement of the Company’s net periodic benefit cost for 2018, 2017 and 2016 are as follows:    Pension Benefits Other Postretirement Benefits  2018 2017 2016 2018 2017 2016  Discount rate 4.35 % 4.20 % 4.20 % 4.35 % 4.20 % 4.20 %  Expected return on plan assets 7.00 % 7.00 % 7.00 % n/a n/a n/a  Rate of compensation increase 3.50 % 3.50 % 3.50 % n/a n/a n/a 
Schedule of Health Care Cost Trend Rates	  2018 2017  Health care cost trend assumed for next year 7% 7%  Rate to which the cost trend is assumed to decline 5% 5%  Year that the rate reaches the ultimate trend rate 2036 2035 
One Percentage Point Change in Assumed Health Care Cost Trend Rates	  (in millions) 1% Increase 1% Decrease  Effect on the total service and interest cost components $ – $ –  Effect on postretirement benefit obligations $ 2 $ (1) 
Schedule of Expected Benefit Payments	  Pension Benefits Other Postretirement Benefits  (in millions)  2019 $ 22 2019 $ 1  2020 6 2020 1  2021 6 2021 1  2022 6 2022 1  2023 7 2023 1  Years 2024-2028 39 Years 2024-2028 5 
Schedule of Allocation of Plan Assets	   Pension Plan Asset Allocations  Asset category: Target Actual  Equity securities:  U.S. equity (1) 35 % 26 %  Non-U.S. developed equity (2) 30 % 22 %  Emerging markets equity (3) 5 % 4 %  Fixed income (4) 28 % 23 %  Cash (5) 2 % 25 %  Total 100 % 100 %  (1) 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) Includes Non-U.S. equity securities in the table below.  (3) Includes emerging markets equity securities below.  (4) Includes fixed income pension plan assets in the table below.  (5) Includes Cash and cash equivalent pension plan assets in the table below.
Fair Value Measurement of Pension Plan Assets	Utilizing the fair value hierarchy described in Note 7 , the Company’s fair value measurement of pension plan assets as of December 31, 2018 is as follows:    (in millions) Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)  Measured within fair value hierarchy  Equity securities:  U.S. large cap growth equity (1) $ 5 $ 5 $ – $ –  U.S. large cap value equity (2) 5 5 – –  U.S. small cap equity (3) 2 2 – –  Non-U.S. equity (4) 20 20 – –  Emerging markets equity (5) 3 3 – –  Fixed income (6) 14 14 – –  Cash and cash equivalents (7) 23 23 – –  Total measured within fair value hierarchy $ 72 $ 72 $ – $ –  Measured at net asset value ( 8 )  Equity securities:  U.S. large cap core equity ( 9 ) 12  Fixed income (6) 7  Total measured at net asset value $ 19   Total plan assets at fair value $ 91  Note: Footnotes are located after the prior year comparative table below. Utilizing the fair value hierarchy described in Note 7 , the Company’s fair value measurement of pension plan assets at December 31, 2017 was as follows:    (in millions) Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)  Measured within fair value hierarchy  Equity securities:  U.S. large cap growth equity (1) $ 7 $ 7 $ – $ –  U.S. large cap value equity (2) 8 8 – –  U.S. small cap equity (3) 3 3 – –  Non-U.S. equity (4) 30 30 – –  Emerging markets equity (5) 5 5 – –  Fixed income (6) 27 27 – –  Cash and cash equivalents 3 3 – –  Total measured within fair value hierarchy $ 83 $ 83 $ – $ –  Measured at net asset value (8)  Equity securities:  U.S. large cap core equity (9) 18  Total measured at net asset value $ 18   Total plan assets at fair value $ 101  (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) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.  (4) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.  (5) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.  (6) 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.  (7) Includes approximately $21 million for anticipated lump sum distributions resulting from the Fayetteville Shale sale in December 2018.  (8) Plan assets for which fair value was measured using net asset value as a practical expedient.  (9) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Schedule of Valuation Assumptions	  Assumptions 2018 2017 2016  Risk-free interest rate – 1.9% 1.4%  Expected dividend yield – – –  Expected volatility – 50.5% 41.0%  Expected term – 5 years 5 years 
Summary of Equity-Classified Stock Option Activity	   2018 2017 2016  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 6,020 $ 19.43 5,416 $ 23.46 5,623 $ 24.57  Granted (1) – $ – 1,604 $ 8.00 155 $ 8.60  Exercised – $ – – $ – (45) $ 7.74  Forfeited or expired (842) $ 33.99 (1,000) $ 22.93 (317) $ 38.01  Options outstanding at December 31 5,178 $ 17.06 6,020 $ 19.43 5,416 $ 23.46  (1) Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual stock option awards from December to the following February. The Company did not issue equity-classified stock options in 2018.
Summary of Stock Options Outstanding and Options Exercisable	  Options Outstanding Options Exercisable  Weighted Weighted  Options Weighted Average Options Weighted Average  Outstanding at Average Remaining Exercisable at Average Remaining  Range of December 31, Exercise Contractual December 31, Exercise Contractual  Exercise Prices 2018 Price Life 2018 Price Life  (in thousands) (years) (in thousands) (years)  $5.22 - $29.42 3,517 $ 8.68 4.4 2,605 $ 8.96 4.1  $30.59 - $35.64 1,135 $ 32.26 2.1 1,135 $ 32.26 2.1  $36.69 - $39.48 436 $ 38.97 1.9 436 $ 38.97 1.9  $40.15 - $49.00 90 $ 46.55 2.4 90 $ 46.55 2.4  5,178 $ 17.06 3.6 4,266 $ 19.02 3.3 
Summary of Equity-Classified Restricted Stock Activity	   2018 2017 2016  Weighted Weighted Weighted  Number of Average Fair Number of Average Fair Number of Average Fair  Shares Value Shares Value Shares Value  (in thousands) (in thousands) (in thousands)  Unvested shares at January 1 6,254 $ 8.85 3,321 $ 11.85 7,222 $ 13.24  Granted 350 $ 4.72 5,055 $ 8.38 81 (2) $ 8.56  Vested (2,058) (1) $ 9.24 (1,380) $ 13.28 (3,817) (3) $ 11.34  Forfeited (1,829) $ 9.01 (742) $ 10.04 (165) $ 12.05  Unvested shares at December 31 2,717 $ 7.91 6,254 $ 8.85 3,321 $ 11.85  (1) Includes 1,287,636 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2018. (2) Shares granted in 2016 were considerably lower than historical norms. In 2016, the Company changed the grant date of its annual restricted stock awards from December to the following February.  (3) Includes 2,059,626 shares and 151,575 shares related to reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. 
Summary of Equity-Classified Performance Units Activity	   2018 2017 2016  Weighted Weighted Weighted  Number of Average Fair Number of Average Fair Number of Average Fair  Units (1) Value Units (1) Value Units (1) Value  (in thousands) (in thousands) (in thousands)  Unvested shares at January 1 1,084 $ 10.12 719 $ 11.46 407 $ 36.65  Granted – $ – 1,197 $ 10.47 1,503 $ 8.60  Vested (290) $ 10.47 (325) $ 12.21 (889) (3) $ 12.78  Forfeited (196) (2) $ 9.94 (507) $ 9.53 (302) (4) $ 11.26  Unvested shares at December 31 598 $ 10.01 1,084 $ 10.12 719 $ 11.46  (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 per unit contingent upon TSR. The performance units have a three -year vesting term and the actual disbursement of shares, if any, is determined during the first quarter following the end of the three-year vesting period.  (2) Includes 144,927 units related to the reduction in workforce for the year ended December 31, 2018.  (3) Includes 22,918 units and 37,590 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.  (4) Includes 87,595 units and 195,834 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. 
Summary of Liability-Classified Restricted Stock Unit Activity	    Number Weighted Average  of Units Fair Value  (in thousands)  Unvested shares at January 1, 2018 – $ –  Granted 12,216 $ 3.69  Vested (232) $ 5.14  Forfeited (1) (3,782) $ 4.86  Unvested units at December 31, 2018 8,202 $ 3.41  (1) Includes 2,766,610 units related to the reduction in workforce for the year ended December 31, 2018. 
Summary of Liability-Classified Performance Unit Activity	    Number Weighted Average  of Shares Fair Value  (in thousands)  Unvested shares at January 1, 2018 – $ –  Granted 3,200 $ 3.70  Vested – $ –  Forfeited (1) (397) $ 4.55  Unvested units at December 31, 2018 2,803 $ 3.41 (1) Includes 295,160 units related to the reduction in workforce for the year ended December 31, 2018.
Stock Options [Member]
Schedule of Equity-Classified Stock-Based Compensation Costs	   (in millions) 2018 2017 2016  Stock options – general and administrative expense (1) $ 2 $ 3 $ 6  Stock options – general and administrative expense capitalized $ – $ 1 $ 1  (1) Includes less than $1 million related to the reduction in workforce and $1 million related to executive management restructuring for the year ended December 31, 2016.
Restricted Stock [Member]
Schedule of Equity-Classified Stock-Based Compensation Costs	   (in millions) 2018 2017 2016  Restricted stock grants – general and administrative expense (1) $ 9 $ 16 $ 33  Restricted stock grants – general and administrative expense capitalized $ 5 $ 11 $ 8  (1) Includes $16 million related to the reduction in workforce and $1 million related to executive management restructuring for the year ended December 31, 2016. 
Performance Units [Member]
Schedule of Equity-Classified Stock-Based Compensation Costs	   (in millions) 2018 2017 2016  Performance units – general and administrative expense (1) $ 3 $ 5 $ 9  Performance units – general and administrative expense capitalized $ 1 $ 2 $ 1  (1) Includes less than $1 million related to reduction in workforce and $1 million related to executive management restructuring for the year ended December 31, 2016. 
Liability-Classified Restricted Stock Units [Member]
Schedule of Liability-Classified Stock-Based Compensation Costs	  (in millions) 2018  Restricted stock units – general and administrative expense $ 4  Restricted stock units – general and administrative expense capitalized $ 3 
Liability-Classified Performance Units [Member]
Schedule of Liability-Classified Stock-Based Compensation Costs	  (in millions) 2018  Liability-classified performance units – general and administrative expense $ 2  Liability-classified performance units – general and administrative expense capitalized $ – 

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Information [Abstract]
Summary of Financial Information for Company's Reportable Segments	   Exploration  and  (in millions) Production Midstream Other Total  2018 (1)  Revenues from external customers $ 2,551 $ 1,311 $ – $ 3,862  Intersegment revenues (26) 2,434 – 2,408  Depreciation, depletion and amortization expense 514 46 – 560  Impairments 15 155 1 171  Operating income (loss) 794 ( 2 ) 4 ( 3 ) (1) 797  Interest expense (4) 124 – – 124  Loss on derivatives (118) – – (118)  Loss on early extinguishment of debt – – (17) (17)  Other loss, net 2 (2) – –  Provision for income taxes (4) 1 – – 1  Assets 4,872 ( 5 ) 539 386 ( 6 ) 5,797  Capital investments (7) 1,231 9 8 1,248   2017  Revenues from external customers $ 2,105 $ 1,098 $ – $ 3,203  Intersegment revenues (19) 2,100 – 2,081  Depreciation, depletion and amortization expense 440 64 – 504  Operating income (loss) 549 183 (1) 731  Interest expense ( 4) 135 – – 135  Gain on derivatives 421 1 – 422  Loss on early extinguishment of debt – – (70) (70)  Other income, net 4 1 – 5  Benefit for income taxes (4) (93) – – (93)  Assets 5,109 (5) 1,288 1,124 (6) 7,521  Capital investments (7) 1,248 32 13 1,293   2016  Revenues from external customers $ 1,435 $ 1,001 $ – $ 2,436  Intersegment revenues (22) 1,568 – 1,546  Depreciation, depletion and amortization expense 371 65 – 436  Impairment of natural gas and oil properties 2,321 – – 2,321  Operating income (loss) (2,399) (8) 209 (9) – (2,190)  Interest expense (4) 87 1 – 88  Loss on derivatives (338) (1) – (339)  Loss on early extinguishment of debt – – (51) (51)  Other income (loss), net – (2) (2) (4)  Benefit for income taxes (4) (29) – – (29)  Assets 4,178 (5) 1,331 1,567 (6) 7,076  Capital investments (7) 623 21 4 648  (1) Includes the impact of approximately eleven months of Fayetteville Shale-related E&P and Midstream operations which were divested on December 3, 2018.  (2) Operating income for the E&P segment includes $37 million related to restructuring charges for the year ended December 31, 2018.  (3) Operating income for the Midstream segment includes $2 million related to restructuring charges for the year ended December 31, 2018.  (4) 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.  (5) Includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities.  (6) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At December 31, 2018, other assets includes approximately $201 million in cash and cash equivalents.  (7) Capital investments include a decrease of $53 million for 2018 and an increase of $43 million for 2016 related to the change in accrued expenditures between years. There was no impact to 2017.  (8) Operating loss for the E&P segment includes $81 million related to restructuring and other one-time charges for the year ended December 31, 2016.  (9) Operating income for the Midstream segment includes $3 million related to restructuring charges for the year ended December 31, 2016.

Condensed Consolidating Finan_2

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Statements Of Operations	    CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS    (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated  Year ended December 31, 2018:  Operating Revenues:  Gas sales $ – $ 1,998 $ – $ – $ 1,998  Oil sales – 196 – – 196  NGL sales – 352 – – 352  Marketing – 1,222 – – 1,222  Gas gathering – 89 – – 89  Other – 5 – – 5  – 3,862 – – 3,862  Operating Costs and Expenses:  Marketing purchases – 1,229 – – 1,229  Operating expenses – 785 – – 785  General and administrative expenses – 209 – – 209  Restructuring charges – 39 – – 39  Depreciation, depletion and amortization – 560 – – 560  Impairments – 171 – – 171  Gain on sale of assets, net – (17) – – (17)  Taxes, other than income taxes – 89 – – 89  – 3,065 – – 3,065  Operating Income – 797 – – 797  Interest Expense, Net 124 – – – 124  Loss on Derivatives – (118) – – (118)  Loss on Early Extinguishment of Debt (17) – – – (17)  Equity in Earnings of Subsidiaries 678 – – (678) –   Income (Loss) Before Income Taxes 537 679 – (678) 538  Provision for Income Taxes – 1 – – 1  Net Income (Loss) $ 537 $ 678 $ – $ (678) $ 537  Mandatory convertible preferred stock dividend – – – – –  Participating securities – mandatory convertible preferred stock 2 – – – 2  Net Income (Loss) Attributable to Common Stock $ 535 $ 678 $ – $ (678) $ 535   Net Income (Loss) $ 537 $ 678 $ – $ (678) $ 537  Other comprehensive income 8 – – – 8  Comprehensive Income (Loss) $ 545 $ 678 $ – $ (678) $ 545     CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS   (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated Year ended December 31, 2017: Operating Revenues:  Gas sales $ – $ 1,793 $ – $ – $ 1,793  Oil sales – 102 – – 102  NGL sales – 206 – – 206  Marketing – 972 – – 972  Gas gathering – 126 – – 126  Other – 4 – – 4  – 3,203 – – 3,203 Operating Costs and Expenses:  Marketing purchases – 976 – – 976  Operating expenses – 671 – – 671  General and administrative expenses – 233 – – 233  Depreciation, depletion and amortization – 504 – – 504  Gain on sale of assets, net – (6) – – (6)  Taxes, other than income taxes – 94 – – 94  – 2,472 – – 2,472  Operating Income – 731 – – 731  Interest Expense, Net 135 – – – 135  Gain on Derivatives – 422 – – 422  Loss on Early Extinguishment of Debt (70) – – – (70)  Other Income, Net – 5 – – 5  Equity in Earnings of Subsidiaries 1,251 – – (1,251) –   Income (Loss) Before Income Taxes 1,046 1,158 – (1,251) 953  Benefit from Income Taxes – (93) – – (93)  Net Income (Loss) $ 1,046 $ 1,251 $ – $ (1,251) $ 1,046  Mandatory convertible preferred stock dividend 108 – – – 108  Participating securities – mandatory convertible preferred stock 123 – – – 123  Net Income (Loss) Attributable to Common Stock $ 815 $ 1,251 $ – $ (1,251) $ 815   Net Income (Loss) $ 1,046 $ 1,251 $ – $ (1,251) $ 1,046  Other comprehensive income (5) 6 6 (12) (5)  Comprehensive Income (Loss) $ 1,041 $ 1,257 $ 6 $ (1,263) $ 1,041        CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS   (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated Year ended December 31, 2016: Operating Revenues:  Gas sales $ – $ 1,273 $ – $ – $ 1,273  Oil sales – 69 – – 69  NGL sales – 92 – – 92  Marketing – 864 – – 864  Gas gathering – 138 – – 138  – 2,436 – – 2,436 Operating Costs and Expenses:  Marketing purchases – 864 – – 864  Operating expenses – 592 – – 592  General and administrative expenses – 247 – – 247  Restructuring charges – 73 – – 73  Depreciation, depletion and amortization – 436 – – 436  Impairments – 2,266 55 – 2,321  Taxes, other than income taxes – 93 – – 93  – 4,571 55 – 4,626  Operating Income – (2,135) (55) – (2,190)  Interest Expense, Net 88 – – – 88  Loss on Derivatives – (339) – – (339)  Loss on Early Extinguishment of Debt (51) – – – (51)  Other Loss, Net – (4) – – (4)  Equity in Earnings of Subsidiaries (2,504) (55) – 2,559 –   Income (Loss) Before Income Taxes (2,643) (2,533) (55) 2,559 (2,672)  Benefit from Income Taxes – (29) – – (29)  Net Income (Loss) $ (2,643) $ (2,504) $ (55) $ 2,559 $ (2,643)  Mandatory convertible preferred stock dividend 108 – – – 108  Participating securities – mandatory convertible preferred stock – – – – –  Net Income (Loss) Attributable to Common Stock $ (2,751) $ (2,504) $ (55) $ 2,559 $ (2,751)   Net Income (Loss) $ (2,643) $ (2,504) $ (55) $ 2,559 $ (2,643)  Other comprehensive income 9 3 3 (6) 9  Comprehensive Income (Loss) $ (2,634) $ (2,501) $ (52) $ 2,553 $ (2,634) 
Condensed Consolidating Balance Sheets	 CONDENSED CONSOLIDATED BALANCE SHEETS    (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated  December 31, 2018:  ASSETS  Cash and cash equivalents $ 201 $ – $ – $ – $ 201  Accounts receivable, net 4 577 – – 581  Other current assets 8 166 – – 174  Total current assets 213 743 – – 956   Intercompany receivables 7,932 – – (7,932) –   Natural gas and oil properties, using the full cost method – 24,128 52 – 24,180  Gathering systems – 11 27 – 38  Other 197 290 – – 487  Less: Accumulated depreciation, depletion and amortization (154) (19,840) (55) – (20,049)  Total property and equipment, net 43 4,589 24 – 4,656   Investments in subsidiaries (equity method) – 24 – (24) –  Other long-term assets 19 166 – – 185  TOTAL ASSETS $ 8,207 $ 5,522 $ 24 $ (7,956) $ 5,797   LIABILITIES AND EQUITY  Accounts payable $ 113 $ 496 $ – $ – $ 609  Other current liabilities 115 122 – – 237  Total current liabilities 228 618 – – 846   Intercompany payables – 7,932 – (7,932) –   Long-term debt 2,318 – – – 2,318  Pension and other postretirement liabilities 46 – – – 46  Other long-term liabilities 54 171 – – 225  Negative carrying amount of subsidiaries, net 3,199 – – (3,199) –  Total long-term liabilities 5,617 171 – (3,199) 2,589  Commitments and contingencies  Total equity (accumulated deficit) 2,362 (3,199) 24 3,175 2,362  TOTAL LIABILITIES AND EQUITY $ 8,207 $ 5,522 $ 24 $ (7,956) $ 5,797     CONDENSED CONSOLIDATED BALANCE SHEETS    (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated  December 31, 2017:  ASSETS  Cash and cash equivalents $ 914 $ 2 $ – $ – $ 916  Accounts receivable, net – 428 – – 428  Other current assets 10 155 – – 165  Total current assets 924 585 – – 1,509   Intercompany receivables 7,978 – – (7,978) –   Natural gas and oil properties, using the full cost method – 23,834 56 – 23,890  Gathering systems – 1,288 27 – 1,315  Other 207 357 – – 564  Less: Accumulated depreciation, depletion and amortization (134) (19,804) (59) – (19,997)  Total property and equipment, net 73 5,675 24 – 5,772   Investments in subsidiaries (equity method) – 24 – (24) –  Other long-term assets 16 224 – – 240  TOTAL ASSETS $ 8,991 $ 6,508 $ 24 $ (8,002) $ 7,521   LIABILITIES AND EQUITY  Accounts payable $ 73 $ 460 $ – $ – $ 533  Other current liabilities 110 137 – – 247  Total current liabilities 183 597 – – 780   Intercompany payables – 7,978 – (7,978) –   Long-term debt 4,391 – – – 4,391  Pension and other postretirement liabilities 58 – – – 58  Other long-term liabilities 13 300 – – 313  Negative carrying amount of subsidiaries, net 2,367 – – (2,367) –  Total long-term liabilities 6,829 300 – (2,367) 4,762  Commitments and contingencies  Total equity (accumulated deficit) 1,979 (2,367) 24 2,343 1,979  TOTAL LIABILITIES AND EQUITY $ 8,991 $ 6,508 $ 24 $ (8,002) $ 7,521 
Condensed Consolidating Statements Of Cash Flows	  CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS    (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated  Year ended December 31, 2018:  Net cash provided by (used in) operating activities $ 304 $ 1,595 $ – $ (676) $ 1,223  Investing activities:  Capital investments (20) (1,270) – – (1,290)  Proceeds from the sale of property and equipment – 1,643 – – 1,643  Other – 6 – – 6  Net cash used in investing activities (20) 379 – – 359  Financing activities  Intercompany activities 1,300 (1,976) – 676 –  Payments on long-term debt (2,095) – – – (2,095)  Payments on revolving credit facility (1,983) – – – (1,983)  Borrowings under revolving credit facility 1,983 – – – 1,983  Purchase of treasury stock (180) – – – (180)  Preferred stock dividend (27) – – – (27)  Other 5 – – – 5  Net cash provided by (used in) financing activities (997) (1,976) – 676 (2,297)  Increase (decrease) in cash and cash equivalents (713) (2) – – (715)  Cash and cash equivalents at beginning of year 914 2 – – 916  Cash and cash equivalents at end of year $ 201 $ – $ – $ – $ 201   Year ended December 31, 2017:  Net cash provided by (used in) operating activities $ 1,019 $ 1,327 $ – $ (1,249) $ 1,097  Investing activities:  Capital investments (13) (1,250) (5) – (1,268)  Proceeds from the sale of property and equipment 1 9 – – 10  Other 1 5 – – 6  Net cash used in investing activities (11) (1,236) (5) – (1,252)  Financing activities  Intercompany activities (1,158) (96) 5 1,249 –  Payments on short-term debt (328) – – – (328)  Payments on long-term debt (1,139) – – – (1,139)  Proceeds from issuance of long-term debt 1,150 – – – 1,150  Preferred stock dividend (16) – – – (16)  Other (19) – – – (19)  Net cash provided by (used in) financing activities (1,510) (96) 5 1,249 (352)  Increase (decrease) in cash and cash equivalents (502) (5) – – (507)  Cash and cash equivalents at beginning of year 1,416 7 – – 1,423  Cash and cash equivalents at end of year $ 914 $ 2 $ – $ – $ 916  Year ended December 31, 2016:  Net cash provided by (used in) operating activities $ (2,610) $ 550 $ – $ 2,558 $ 498 Investing activities:  Capital investments (3) (590) – – (593)  Proceeds from the sale of property and equipment 2 428 – – 430  Other 1 – – – 1  Net cash used in investing activities – (162) – – (162) Financing activities  Intercompany activities 2,950 (392) – (2,558) –  Payments on long-term debt (1,175) – – – (1,175)  Payments on revolving credit facility (3,268) – – – (3,268)  Borrowings on revolving credit facility 3,152 – – – 3,152  Payments on commercial paper (242) – – – (242)  Borrowings under commercial paper 242 – – – 242  Proceeds from issuance of long-term debt 1,191 – – – 1,191  Proceeds from issuance of common stock 1,247 – – – 1,247  Preferred stock dividend (27) – – – (27)  Other (48) – – – (48)  Net cash provided by (used in) financing activities 4,022 (392) – (2,558) 1,072  Increase (decrease) in cash and cash equivalents 1,412 (4) – – 1,408  Cash and cash equivalents at beginning of year 4 11 – – 15  Cash and cash equivalents at end of year $ 1,416 $ 7 $ – $ – $ 1,423 

Supplemental Quarterly Results

Supplemental Quarterly Results (Tables)	12 Months Ended
	Dec. 31, 2018
Supplemental Quarterly Results [Abstract]
Schedule of Quarterly Financial Information	  (in millions, except share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter  2018  Operating revenues $ 920 $ 816 $ 951 $ 1,175  Operating income 255 124 66 352  Net income (loss) attributable to common stock 205 51 (29) 307  Earnings (loss) per share – Basic 0.36 0.09 (0.05) 0.54  Earnings (loss) per share – Diluted 0.36 0.09 (0.05) 0.54   2017  Operating revenues $ 846 $ 811 $ 737 $ 809  Operating income 266 188 110 167  Net income attributable to common stock 281 224 43 267  Earnings per share – Basic 0.57 0.45 0.09 0.53  Earnings per share – Diluted 0.57 0.45 0.09 0.53 

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Line Items]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	  (in millions) 2018 2017  Proved properties $ 22,425 $ 22,073  Unproved properties 1,755 1,817  Total capitalized costs 24,180 23,890  Less: Accumulated depreciation, depletion and amortization (19,761) (19,287)  Net capitalized costs $ 4,419 $ 4,603 
Composition of Net Unevaluated Costs Excluded from Amortization	  (in millions) 2018 2017 2016 Prior Total  Property acquisition costs $ 49 $ 70 $ 12 $ 1,346 $ 1,477  Exploration and development costs 42 23 6 23 94  Capitalized interest 77 45 28 34 184  $ 168 $ 138 $ 46 $ 1,403 $ 1,755 
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	  (in millions, except per Mcfe amounts) 2018 2017 2016  Unproved property acquisition costs $ 164 $ 194 $ 171  Exploration costs 5 22 17  Development costs 1,014 1,024 433  Capitalized costs incurred 1,183 1,240 621  Full cost pool amortization per Mcfe $ 0.51 $ 0.45 $ 0.38 
Results of Operations for Oil and Gas Producing Activities Disclosure	   (in millions) 2018 2017 2016  Sales $ 2,525 $ 2,086 $ 1,413  Production (lifting) costs (974) (891) (839)  Depreciation, depletion and amortization (514) (440) (371)  Impairment of natural gas and oil properties – – (2,321)  1,037 755 (2,118)  Provision (benefit) for income taxes (1) – – –  Results of operations (2) $ 1,037 $ 755 $ (2,118)  (1) Prior to the recognition of a valuation allowance, in 2018, 2017 and 2016 the Company recognized income tax provisions of $254 million, $287 million and $805 million, respectively.  (2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 5 – “Derivatives and Risk Management” .
Summary of Changes in Reserves	   Appalachia Fayetteville  (in Bcfe) Northeast Southwest Shale (1) Other (2) Total  December 31, 2015 2,319 611 3,281 4 6,215  Net revisions  Price revisions (794) (127) (116) – (1,037)  Performance and production revisions 318 199 163 3 683  Total net revisions (476) 72 47 3 (354)  Extensions, discoveries and other additions  Proved developed 81 157 19 – 257  Proved undeveloped – – 25 – 25  Total reserve additions 81 157 44 – 282  Production (350) (148) (375) (2) (875)  Acquisition of reserves in place – – – – –  Disposition of reserves in place – (15) – – (15)  December 31, 2016 1,574 677 2,997 5 5,253  Net revisions  Price revisions 903 738 49 1 1,691  Performance and production revisions 154 125 358 4 641  Total net revisions 1,057 863 407 5 2,332  Extensions, discoveries and other additions  Proved developed 790 419 48 1 1,258  Proved undeveloped 1,100 5,186 543 – 6,829  Total reserve additions 1,890 5,605 591 1 8,087  Production (395) (183) (316) (3) (897)  Acquisition of reserves in place – – – – –  Disposition of reserves in place – – – – –  December 31, 2017 4,126 6,962 3,679 8 14,775  Net revisions  Price revisions 41 106 6 1 154  Performance and production revisions 107 272 (6) (1) 372  Total net revisions 148 378 – – 526  Extensions, discoveries and other additions  Proved developed 154 22 1 – 177  Proved undeveloped 397 435 – – 832  Total reserve additions 551 457 1 – 1,009  Production (459) (243) (243) (1) (946)  Acquisition of reserves in place – – – – –  Disposition of reserves in place – – (3,437) (6) (3,443)  December 31, 2018 4,366 7,554 – 1 11,921  (1) The Fayetteville Shale E&P assets and associated reserves were divested December 3, 2018.  (2) Other includes properties outside of the Appalachian Basin and Fayetteville Shale.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	  (in millions) 2018 2017 2016  Future cash inflows $ 34,523 $ 36,576 $ 9,064  Future production costs (15,347) (18,390) (5,880)  Future development costs (1) (4,095) (4,676) (485)  Future income tax expense (2) (2,079) (1,342) –  Future net cash flows 13,002 12,168 2,699  10% annual discount for estimated timing of cash flows (7,003) (6,606) (1,034)  Standardized measure of discounted future net cash flows $ 5,999 $ 5,562 $ 1,665  (1) Includes abandonment costs.  (2) The December 31, 2016 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis.
Schedule of Prices used for Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	  (in millions) 2018 2017 2016  Natural gas (per MMBtu) $ 3.10 $ 2.98 $ 2.48  Oil (per Bbl) 65.56 47.79 39.25  NGLs (per Bbl) 17.64 14.41 6.74 
Schedule of Analysis of Changes in Standardized Measure	  (in millions) 2018 2017 2016  Standardized measure, beginning of year $ 5,562 $ 1,665 $ 2,417  Sales and transfers of natural gas and oil produced, net of production costs (1,564) (1,191) (574)  Net changes in prices and production costs 2,162 1,963 (415)  Extensions, discoveries, and other additions, net of future production and development costs 335 1,715 45  Acquisition of reserves in place – – –  Sales of reserves in place (2,022) – (10)  Revisions of previous quantity estimates 361 1,721 (140)  Net change in income taxes (304) (222) –  Changes in estimated future development costs (166) (6) 71  Previously estimated development costs incurred during the year 536 55 114  Changes in production rates (timing) and other 521 (304) (85)  Accretion of discount 578 166 242  Standardized measure, end of year $ 5,999 $ 5,562 $ 1,665 
United States [Member]
Oil and Gas Exploration and Production Industries Disclosures [Line Items]
Summary of Changes in Reserves	   Natural  Gas Oil NGL Total  (Bcf) (MBbls) (MBbls) (Bcfe)  December 31, 2015 5,917 8,753 40,947 6,215  Revisions of previous estimates due to price (983) (582) (8,337) (1,037)  Revisions of previous estimates other than price 537 2,146 22,131 683  Extensions, discoveries and other additions 198 2,417 11,576 282  Production (788) (2,192) (12,372) (875)  Acquisition of reserves in place – – – –  Disposition of reserves in place (15) (19) (14) (15)  December 31, 2016 4,866 10,523 53,931 5,253  Revisions of previous estimates due to price 1,327 3,197 57,447 1,691  Revisions of previous estimates other than price 571 (1,529) 13,102 641  Extensions, discoveries and other additions (1) 5,159 55,772 432,220 8,087  Production (797) (2,327) (14,245) (897)  Acquisition of reserves in place – – – –  Disposition of reserves in place – – – –  December 31, 2017 11,126 65,636 542,455 14,775  Revisions of previous estimates due to price 96 788 8,912 154  Revisions of previous estimates other than price 316 410 8,855 372  Extensions, discoveries and other additions 753 5,830 36,823 1,009  Production (807) (3,407) (19,706) (946)  Acquisition of reserves in place – – – –  Disposition of reserves in place (2) (3,440) (250) (276) (3,443)  December 31, 2018 8,044 69,007 577,063 11,921  (1) The 2017 PUD additions are primarily associated with the increase in commodity prices.  (2) The 2018 disposition is primarily associated with the Fayetteville Shale sale.     Natural  Gas Oil NGL Total  (Bcf) (MBbls) (MBbls) (Bcfe)  Proved developed reserves as of:  December 31, 2016 4,789 10,523 53,931 5,176  December 31, 2017 6,979 14,513 142,213 7,920  December 31, 2018 4,395 18,037 175,480 5,557  Proved undeveloped reserves as of:  December 31, 2016 77 – – 77  December 31, 2017 4,147 51,123 400,242 6,855  December 31, 2018 3,649 50,970 401,583 6,364 

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies (Narrative) (Details)	Dec. 03, 2018USD ($)	Aug. 30, 2018USD ($)	Jan. 12, 2018shares	Dec. 31, 2018USD ($)shares	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Jul. 31, 2016USD ($)$ / sharesshares	Jan. 31, 2015shares	Dec. 31, 2018USD ($)shares	Sep. 30, 2018USD ($)	Sep. 30, 2017shares	Dec. 31, 2018USD ($)segmentitem$ / sharesshares	Dec. 31, 2017USD ($)itemshares	Dec. 31, 2016USD ($)itemshares	Dec. 31, 2015USD ($)	Dec. 31, 2018USD ($)shares	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Nov. 30, 2015USD ($)
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of segments | segment												2
Other income (loss), net													$ 5,000,000	$ (4,000,000)
Outstanding checks included in accounts payable				$ 34,000,000					$ 34,000,000			$ 34,000,000	17,000,000			$ 34,000,000
Net unevaluated costs excluded from amortization												$ 168,000,000	$ 138,000,000	$ 46,000,000	$ 1,403,000,000	$ 1,755,000,000
Period of time needed to calculate ceiling value of reserves												12 months	12 months	12 months
Number of derivative positions designated for hedge accounting | item												0	0	0
Impairments												$ 171,000,000		$ 2,321,000,000
Amortization of intangible asset												$ 9,000,000	$ 9,000,000	9,000,000
Natural gas, oil and NGL reserves discount												10.00%
Repayments of long-term debt												$ 2,095,000,000	$ 1,139,000,000	$ 1,175,000,000
Preferred stock, common shares issued as stock dividend | shares											10,040,306			9,917,799
Shares held in trust, shares | shares				10,653					10,653			10,653	31,269			10,653
Shares held in trust, shares released | shares												20,616
Treasury stock, shares | shares												39,061,269
Treasury stock acquired									$ 155,000,000	$ 25,000,000		$ 180,000,000
Treasury stock acquired, average cost per share | $ / shares												$ 4.63
Stock repurchase, authorized amount					$ 200,000,000					200,000,000
Sales Revenue, Net [Member] | Natural Gas, Oil and NGL [Member] | Customer Concentration Risk [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Concentration percentage												10.40%	10.30%
Accounting Standards Update 2017-07 [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Other income (loss), net														$ 5,000,000
Long-term Debt [Member] | 2015 Term Loan due December 2020 [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Repayments of long-term debt							$ 375,000,000
Debt instrument face amount																				$ 750,000,000
Senior Notes [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Repayments of long-term debt				$ 900,000,000			$ 700,000,000
Senior Notes [Member] | 2015 Term Loan due December 2020 [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Repayments of long-term debt						$ 327,000,000
Natural Gas [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Full cost ceiling test, price per MMBtu												$ 3.10	$ 2.98	2.48
Oil [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Full cost ceiling test, price per barrel												65.56	47.79	39.25
NGL [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Full cost ceiling test, price per barrel												$ 17.64	$ 14.41	6.74
Royal Dutch Shell Plc [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of subsidiaries of major customer with which business is conducted | item												2	2
United States and Canada [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Net book value that exceeds ceiling limitation																	$ 506,000,000	$ 297,000,000	$ 641,000,000
Midstream Services [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Other income (loss), net												$ (2,000,000)	$ 1,000,000	$ (2,000,000)
Impairments												155,000,000
Exploration and Production [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Other income (loss), net												2,000,000	$ 4,000,000
Impairments												15,000,000
Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued | shares							98,900,000
Price per share | $ / shares							$ 13
Proceeds from issuance of shares							$ 1,247,000,000
Shares issued upon conversion | shares			74,998,614
Depositary Shares [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued | shares								34,500,000
Minimum [Member] | Sales Revenue, Net [Member] | Natural Gas, Oil and NGL [Member] | Customer Concentration Risk [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Concentration percentage														10.00%
Minimum [Member] | Accounting Standards Update 2016-02 [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Right-of-use asset				95,000,000					95,000,000			95,000,000				$ 95,000,000
Lease liability				95,000,000					95,000,000			95,000,000				95,000,000
Maximum [Member] | Accounting Standards Update 2016-02 [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Lease liability				$ 115,000,000					$ 115,000,000			115,000,000				$ 115,000,000
WPX Property Acquisition [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Percentage of interest acquired															86.00%
Fayetteville Shale [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Ownership interest prior to disposal		100.00%			100.00%
Consideration		$ 1,865,000,000			$ 1,865,000,000					1,865,000,000
Adjustment due to differences from economic effective date to close date	$ 215,000,000
Proceeds from sale of oil and gas property and equipment	$ 1,650,000,000
Discontinued Operations, Held-for-sale [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments										160,000,000		160,000,000
Discontinued Operations, Held-for-sale [Member] | Midstream Services [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments										145,000,000		145,000,000
Discontinued Operations, Held-for-sale [Member] | Exploration and Production [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments										$ 15,000,000		15,000,000
Other Non-Core Assets [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments												$ 11,000,000

Organization and Summary of S_5

Organization and Summary of Significant Accounting Policies (Summary of Cash and Cash Equivalents) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Organization and Summary of Significant Accounting Policies [Abstract]
Cash	$ 32	$ 261
Marketable securities	169	605
Other cash equivalents		50
Total	$ 201	$ 916	$ 1,423	$ 15

Organization and Summary of S_6

Organization and Summary of Significant Accounting Policies (Schedule of Earnings Per Share) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Organization and Summary of Significant Accounting Policies [Abstract]
Net income (loss)	$ 307	$ (29)	$ 51	$ 208	$ 334	$ 77	$ 284	$ 351	$ (210)	$ (708)	$ (593)	$ (1,132)	$ 537	$ 1,046	[1]	$ (2,643)
Mandatory convertible preferred stock dividend														108		108
Participating securities - mandatory convertible preferred stock													2	123
Net Income (Loss) Attributable to Common Stock	$ 307	$ (29)	$ 51	$ 205	$ 267	$ 43	$ 224	$ 281					$ 535	$ 815		$ (2,751)
Number of common shares: Weighted average outstanding													574,631,756	498,264,321		435,337,402
Number of common shares: Effect of issuance of non-vested restricted common stock													698,103	1,061,056
Number of common shares: Effect of issuance of non-vested performance units													1,312,949	1,478,920
Number of common shares: Weighted average and potential dilutive outstanding													576,642,808	500,804,297		435,337,402
Basic	$ 0.54	$ (0.05)	$ 0.09	$ 0.36	$ 0.53	$ 0.09	$ 0.45	$ 0.57					$ 0.93	$ 1.64		$ (6.32)
Diluted	$ 0.54	$ (0.05)	$ 0.09	$ 0.36	$ 0.53	$ 0.09	$ 0.45	$ 0.57					$ 0.93	$ 1.63		$ (6.32)
[1]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Organization and Summary of S_7

Organization and Summary of Significant Accounting Policies (Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share) (Details) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	12,710,152	81,244,150	80,536,469
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	5,909,082	116,717	3,692,697
Unvested Share-Based Payment [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	3,692,794	5,361,849	959,233
Performance Units [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	642,568	765,689	884,644
Mandatory Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares	2,465,708	74,999,895	74,999,895

Organization and Summary of S_8

Organization and Summary of Significant Accounting Policies (Schedule of Supplemental Disclosures of Cash Flow Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Organization and Summary of Significant Accounting Policies [Abstract]
Cash paid during the year for interest, net of amounts capitalized	$ 135	$ 130	$ 75
Cash paid (received) during the year for income taxes	6	(5)	(15)
Increase (decrease) in noncash property additions	$ (42)	$ 25	$ 55

Restructuring Charges (Narrativ

Restructuring Charges (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restructuring Cost and Reserve [Line Items]
Restructuring liability			$ 5
Restructuring charges			39		$ 73
Positions eliminated, percent	40.00%
Workforce Reduction [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring liability			1
Restructuring charges			23		73
Positions eliminated, percent		40.00%
Fayetteville Shale [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring liability			4
Restructuring charges			$ 16

Restructuring Charges (Summary

Restructuring Charges (Summary of Restructuring Charges) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restructuring Cost and Reserve [Line Items]
Stock-based compensation	$ 14	$ 24	$ 29
Total restructuring charges	39		73
Non-cash curtailment gain (loss)	4		(5)
Exploration and Production [Member]
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	37
Midstream Services [Member]
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	2		3
Workforce Reduction [Member]
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)	21		44
Stock-based compensation			24
Other benefits			3
Outplacement services, other	2		2
Total restructuring charges	23		73
Workforce Reduction [Member] | Exploration and Production [Member]
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	21		70
Workforce Reduction [Member] | Midstream Services [Member]
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	2		3
Fayetteville Shale [Member]
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)	12
Office consolidation	4
Total restructuring charges	16
Fayetteville Shale [Member] | Exploration and Production [Member]
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	$ 16

Restructuring Charges (Summar_2

Restructuring Charges (Summary of Liabilities Associated with Restructuring Activities) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Restructuring Cost and Reserve [Line Items]
Liability at December 31, 2017
Additions	39
Distributions	34
Liability at December 31, 2018	5
Workforce Reduction [Member]
Restructuring Cost and Reserve [Line Items]
Liability at December 31, 2018	$ 1

Divestitures (Narrative) (Detai

Divestitures (Narrative) (Details) - USD ($)	Dec. 03, 2018	Aug. 30, 2018	Dec. 31, 2018	Sep. 30, 2018	Jul. 31, 2016	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2020
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments								$ 171,000,000		$ 2,321,000,000
Gain on the sale of non-full cost pool assets	$ 17,000,000
Reduction of full cost pool assets	887,000,000
Gain on sale of assets, net								(17,000,000)	$ (6,000,000)
Repayments of long-term debt								2,095,000,000	1,139,000,000	1,175,000,000
Cash paid for interest								135,000,000	$ 130,000,000	$ 75,000,000
Treasury stock acquired						$ 155,000,000	$ 25,000,000	$ 180,000,000
Treasury stock, shares								39,061,269
Discontinued Operations, Held-for-sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments							160,000,000	$ 160,000,000
Fayetteville Shale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest prior to disposal		100.00%		100.00%
Consideration		$ 1,865,000,000		$ 1,865,000,000			1,865,000,000
Proceeds from sale of oil and gas property and equipment	1,650,000,000
Adjustment due to differences from economic effective date to close date	215,000,000
Derivative liabilities	$ 151,000,000
Gain on sale of assets, net								22,000,000
Contractual commitments assumed by buyer			$ 221,000,000			221,000,000		221,000,000
Liability for estimated future payments			88,000,000			$ 88,000,000		88,000,000
Other Non-Core Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments								11,000,000
Scenario, Forecast [Member] | Fayetteville Shale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Potential amount to be reimbursed to buyer											$ 102,000,000
Midstream Services [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments								155,000,000
Gain on sale of assets, net								(35,000,000)
Midstream Services [Member] | Discontinued Operations, Held-for-sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments							145,000,000	145,000,000
Exploration and Production [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments								15,000,000
Gain on sale of assets, net								18,000,000
Exploration and Production [Member] | Discontinued Operations, Held-for-sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments							$ 15,000,000	15,000,000
Other [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments								$ 1,000,000
Senior Notes [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Repayment of debt			914,000,000
Repayments of long-term debt			900,000,000		$ 700,000,000
Cash paid for interest			$ 9,000,000

Revenue Recognition (Narrative)

Revenue Recognition (Narrative) (Details)	1 Months Ended
	Dec. 31, 2018USD ($)
Revenue from Contract with Customer [Line Items]
Contract asset associated with revenues from contracts with customers	$ 0
Contract liability associated with revenues from contracts with customers	0
Gas Gathering [Member]
Revenue from Contract with Customer [Line Items]
Contract asset associated with revenues from contracts with customers	0
Contract liability associated with revenues from contracts with customers	$ 0
Fayetteville Shale [Member]
Revenue from Contract with Customer [Line Items]
Percentage of assets sold	100.00%

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregation of Revenue by Segment) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue									$ 2,525	$ 2,086	$ 1,413
Operating Revenues	$ 1,175	$ 951	$ 816	$ 920	$ 809	$ 737	$ 811	$ 846	3,862	3,203	2,436
Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue									2,525	2,086	1,413
Operating Revenues									2,551	2,105	1,435
Midstream Services [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue									3,745	3,198	2,569
Operating Revenues									1,311	1,098	1,001
Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									(2,408)	(2,081)	(1,546)
Intersegment Eliminations [Member] | Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									26	19	22
Intersegment Eliminations [Member] | Midstream Services [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									(2,434)	(2,100)	(1,568)
Gas Sales [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									1,998	1,793	1,273
Gas Sales [Member] | Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue									1,974	1,775	1,252
Gas Sales [Member] | Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									24	18	21
Oil Sales [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									196	102	69
Oil Sales [Member] | Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue									193	101	69
Oil Sales [Member] | Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									3	1
NGL Sales [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									352	206	92
NGL Sales [Member] | Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue									353	206	92
NGL Sales [Member] | Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									(1)
Marketing [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									1,222	972	864
Marketing [Member] | Midstream Services [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue									3,497	2,867	2,191
Marketing [Member] | Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									(2,275)	(1,895)	(1,327)
Gas Gathering [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									89	126	138
Gas Gathering [Member] | Midstream Services [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue									248	331	378
Gas Gathering [Member] | Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									(159)	(205)	$ (240)
Other [Member]
Disaggregation of Revenue [Line Items]
Operating Revenues									5	4
Other [Member] | Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue									$ 5	$ 4

Revenue Recognition (Disaggre_2

Revenue Recognition (Disaggregation of Revenue on Geographic Basis) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue	$ 2,525	$ 2,086	$ 1,413
Northeast Appalachia [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue	1,165	837	470
Southwest Appalachia [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue	817	498	259
Fayetteville Shale [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue	537	743	675
Other Property [Member]
Disaggregation of Revenue [Line Items]
Operating revenues, including intersegment revenue	$ 6	$ 8	$ 9

Revenue Recognition (Reconcilia

Revenue Recognition (Reconciliation of Accounts Receivable) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Revenue Recognition [Abstract]
Receivables from contracts with customers	$ 494	$ 322
Other accounts receivable	87	106
Total accounts receivable	$ 581	$ 428

Derivatives and Risk Manageme_3

Derivatives and Risk Management (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)item	Dec. 31, 2017USD ($)item	Dec. 31, 2016item	Dec. 03, 2018USD ($)
Derivative [Line Items]
Gain on sale of assets, net	$ (17)	$ (6)
Derivative assets	$ 51
Number of derivative positions designated for hedge accounting | item	0	0	0
Interest Rate Swaps [Member]
Derivative [Line Items]
Derivative liabilities		$ 1
Derivative assets	$ 1
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Number of derivative positions designated for hedge accounting | item	0
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member]
Derivative [Line Items]
Notional amount	$ 170
Derivative, expiration	Jun. 30, 2020
Fayetteville Shale [Member]
Derivative [Line Items]
Derivative liabilities				$ 151
Gain on sale of assets, net	$ 22

Derivatives and Risk Manageme_4

Derivatives and Risk Management (Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value) (Details) ft³ in Billions	12 Months Ended
	Dec. 31, 2018USD ($)$ / bbl$ / MMBTUMBblsft³
Fixed Price Swaps -2019 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	220
Average price per MMBtu and Bbls | $ / MMBTU	2.93
Fair Value	$ 23,000,000
Fixed Price Swaps -2019 [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Volume | MBbls	346
Average price per MMBtu and Bbls | $ / bbl	68.74
Fair Value	$ 7,000,000
Fixed Price Swaps -2019 [Member] | Not Designated as Hedging Instrument [Member] | Propane [Member]
Derivative [Line Items]
Volume | MBbls	1,689
Average price per MMBtu and Bbls | $ / bbl	33.12
Fair Value	$ 11,000,000
Fixed Price Swaps -2019 [Member] | Not Designated as Hedging Instrument [Member] | Ethane [Member]
Derivative [Line Items]
Volume | MBbls	3,687
Average price per MMBtu and Bbls | $ / bbl	13.90
Fair Value	$ 4,000,000
Two-way Costless-collars - 2019 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	53
Fair Value	$ 4,000,000
Two-way Costless-collars - 2019 [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Volume | MBbls	329
Fair Value	$ 6,000,000
Two-way Costless-collars - 2019 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.80
Two-way Costless-collars - 2019 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	65
Two-way Costless-collars - 2019 Sold Calls [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Average price per MMBtu and Bbls | $ / MMBTU	2.98
Two-way Costless-collars - 2019 Sold Calls [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Average price per MMBtu and Bbls | $ / bbl	72.30
Three-way Costless-collars - 2019 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	170
Fair Value	$ 8,000,000
Three-way Costless-collars - 2019 Sold Puts [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.48
Three-way Costless-collars - 2019 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.90
Three-way Costless-collars - 2019 Sold Calls [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Average price per MMBtu and Bbls | $ / MMBTU	3.28
Financial protection on production - 2019 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	443
Fair Value	$ 35,000,000
Financial protection on production - 2019 [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Volume | MBbls	675
Fair Value	$ 13,000,000
Fixed Price Swaps -2020 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	24
Average price per MMBtu and Bbls | $ / MMBTU	2.88
Fair Value	$ 5,000,000
Fixed Price Swaps -2020 [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Volume | MBbls	366
Average price per MMBtu and Bbls | $ / bbl	65.68
Fair Value	$ 6,000,000
Fixed Price Swaps -2020 [Member] | Not Designated as Hedging Instrument [Member] | Ethane [Member]
Derivative [Line Items]
Volume | MBbls	732
Average price per MMBtu and Bbls | $ / bbl	13.49
Fair Value	$ 1,000,000
Two-way Costless-collars - 2020 [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Volume | MBbls	366
Fair Value	$ 4,000,000
Two-way Costless-collars - 2020 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	60
Two-way Costless-collars - 2020 Sold Calls [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Average price per MMBtu and Bbls | $ / bbl	69.80
Three-Way Costless Collars - 2020 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	84
Three-way Costless-collars - 2020 Sold Puts [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.40
Three-way Costless-collars - 2020 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.73
Three-way Costless-collars - 2020 Sold Calls [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Average price per MMBtu and Bbls | $ / MMBTU	3.03
Financial protection on production - 2020 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	108
Fair Value	$ 5,000,000
Financial protection on production - 2020 [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Volume | MBbls	732
Fair Value	$ 10,000,000
Three-way Costless-collars - 2021 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	37
Fair Value	$ (1,000,000)
Three-Way Costless Collars - 2021 Sold Puts [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.35
Three-Way Costless Collars - 2021 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.60
Three-Way Costless Collars - 2021 Sold Calls [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Average price per MMBtu and Bbls | $ / MMBTU	2.93
Basis Swaps - 2019 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	107
Basis differential per MMBtu	$ (0.29)
Fair Value	$ (10,000,000)
Basis Swaps - 2020 [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	59
Basis differential per MMBtu	$ (0.44)
Fair Value	$ (1,000,000)
Basis Swaps [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Volume | ft³	166
Fair Value	$ (11,000,000)
Purchased Fixed Price Swaps - 2019 [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Volume | MBbls	274
Average price per MMBtu and Bbls | $ / bbl	69.10
Fair Value	$ (6,000,000)
Sold Fixed Price Swaps - 2019 [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivative [Line Items]
Volume | MBbls	620
Average price per MMBtu and Bbls | $ / bbl	68.90
Fair Value	$ 13,000,000
Purchased Call Options - 2020 [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume | ft³	68
Cap price per MMBtu and Bbls | $ / MMBTU	3.63
Fair Value	$ 4,000,000
Purchased Call Options - 2021 [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume | ft³	57
Cap price per MMBtu and Bbls | $ / MMBTU	3.52
Fair Value	$ 2,000,000
Purchased Call Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume | ft³	125
Fair Value	$ 6,000,000
Sold Call Options - 2019 [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume | ft³	52
Cap price per MMBtu and Bbls | $ / MMBTU	3.50
Fair Value	$ (3,000,000)
Sold Call Options - 2019 [Member] | Oil [Member]
Derivative [Line Items]
Volume | MBbls	270
Cap price per MMBtu and Bbls | $ / bbl	65
Sold Call Options - 2020 [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume | ft³	137
Cap price per MMBtu and Bbls | $ / MMBTU	3.39
Fair Value	$ (12,000,000)
Sold Call Options - 2021 [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume | ft³	114
Cap price per MMBtu and Bbls | $ / MMBTU	3.33
Fair Value	$ (7,000,000)
Sold Call Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume | ft³	303
Fair Value	$ (22,000,000)
Storage Fixed Price Swaps - 2019 [Member]
Derivative [Line Items]
Volume | ft³	0.8
Average price per MMBtu and Bbls | $ / MMBTU	3.03
Storage Basis Swaps - 2019 [Member]
Derivative [Line Items]
Volume | ft³	0.8
Basis differential per MMBtu	$ (0.44)

Derivatives and Risk Manageme_5

Derivatives and Risk Management (Balance Sheet Classification of Derivative Financial Instruments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	$ 187	$ 191
Derivative liabilities	110	139
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		1
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1
Natural Gas [Member] | Purchased Call Options [Member]
Derivatives, Fair Value [Line Items]
Premium paid	1
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	38	32
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	18	6
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		9
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	1
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Two-Way Costless Collars [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	5	11
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Two-Way Costless Collars [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	7
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Three-Way Costless Collars [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	82	41
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Three-Way Costless Collars [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	39	34
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Three-Way Costless Collars [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	36	33
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Three-Way Costless Collars [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	30	35
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	2	8
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		3
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	23	18
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		4
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Purchased Call Options [Member]
Derivatives, Fair Value [Line Items]
Premium paid	1
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Purchased Call Options [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	3
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Purchased Call Options [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		6
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Sold Call Options [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	3	3
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Sold Call Options [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 15	19
Oil [Member] | Not Designated as Hedging Instrument [Member] | Purchased Fixed Price Swap [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		6
Oil [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		13
Oil [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		6
Oil [Member] | Not Designated as Hedging Instrument [Member] | Two-Way Costless Collars [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		6
Oil [Member] | Not Designated as Hedging Instrument [Member] | Two-Way Costless Collars [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		5
Oil [Member] | Not Designated as Hedging Instrument [Member] | Two-Way Costless Collars [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		1
Propane [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		11
Ethane [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		7
Ethane [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		1
Ethane [Member] | Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		$ 3

Derivatives and Risk Manageme_6

Derivatives and Risk Management (Summary of Before Tax Effect of Cash Flow Hedges on Consolidated Financial Statements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	$ (24)	$ 451
Derivative Instrument, Settled Gain (Loss) on Derivatives	(94)	(29)
Total gain (loss) on derivatives	(118)	422
Purchased Fixed Price Swap [Member] | Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(6)
Fixed Price Swaps [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(27)	232
Derivative Instrument, Settled Gain (Loss) on Derivatives	(32)	(9)
Fixed Price Swaps [Member] | Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	19
Fixed Price Swaps [Member] | Propane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	11
Derivative Instrument, Settled Gain (Loss) on Derivatives	(6)
Fixed Price Swaps [Member] | Ethane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	5
Derivative Instrument, Settled Gain (Loss) on Derivatives	(8)
Two-Way Costless Collars [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives		52
Derivative Instrument, Settled Gain (Loss) on Derivatives	(1)
Two-Way Costless Collars [Member] | Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	10
Three-Way Costless Collars [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(48)	136
Derivative Instrument, Settled Gain (Loss) on Derivatives	(9)	(1)
Basis Swaps [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	10	(36)
Derivative Instrument, Settled Gain (Loss) on Derivatives	(31)	(6)
Purchased Call Options [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	4	2
Derivative Instrument, Settled Gain (Loss) on Derivatives	2
Amortization of premium paid	1	1
Sold Call Options [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(4)	63
Derivative Instrument, Settled Gain (Loss) on Derivatives	(7)	(11)
Amortization of premium paid		5
Sold Call Options [Member] | Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Settled Gain (Loss) on Derivatives	(2)
Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	$ 2	2
Derivative Instrument, Settled Gain (Loss) on Derivatives		$ (2)

Reclassifications from Accumu_3

Reclassifications from Accumulated Other Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	3 Months Ended										12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2017				$ (44)							$ (44)
Other comprehensive (loss) before reclassifications											(2)
Amounts reclassified from other comprehensive income											10
Net current-period other comprehensive income	$ 4	$ 4			$ (7)	$ 1	$ 1	$ 2	$ 3	$ 4	8	$ (5)	$ 9
Ending balance, December 31, 2018	(36)				(44)						(36)	(44)
Pension And Other Postretirement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2017				(30)							(30)
Other comprehensive (loss) before reclassifications											(2)
Amounts reclassified from other comprehensive income											10
Net current-period other comprehensive income											8
Ending balance, December 31, 2018	(22)				(30)						(22)	(30)
Foreign Currency [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2017				$ (14)							(14)
Other comprehensive (loss) before reclassifications
Amounts reclassified from other comprehensive income
Net current-period other comprehensive income
Ending balance, December 31, 2018	$ (14)				$ (14)						$ (14)	$ (14)

Reclassifications from Accumu_4

Reclassifications from Accumulated Other Comprehensive Income (Loss) (Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other income (loss), net														$ 5		$ (4)
Provision (benefit) for income taxes													$ 1	(93)		(29)
Net Income (Loss)	$ 307	$ (29)	$ 51	$ 208	$ 334	$ 77	$ 284	$ 351	$ (210)	$ (708)	$ (593)	$ (1,132)	537	$ 1,046	[1]	$ (2,643)
Reclassified from Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income (Loss)													10
Pension And Other Postretirement [Member] | Reclassified from Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other income (loss), net													10
Provision (benefit) for income taxes
Net Income (Loss)													$ 10
[1]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Impairments		$ 171		$ 2,321
Gain on sale of assets, net		$ 17	$ 6
Long-term Debt [Member] | 4.05% Senior Notes due January 2020 [Member]
Debt Instrument [Line Items]
Stated interest rate		4.05%
Debt, maturity date		Jan. 31, 2020
Other Non-Core Assets [Member]
Debt Instrument [Line Items]
Impairments		$ 11
Midstream Services [Member]
Debt Instrument [Line Items]
Impairments		155
Gain on sale of assets, net		35
Exploration and Production [Member]
Debt Instrument [Line Items]
Impairments		15
Gain on sale of assets, net		(18)
Discontinued Operations, Held-for-sale [Member]
Debt Instrument [Line Items]
Impairments	$ 160	160
Discontinued Operations, Held-for-sale [Member] | Midstream Services [Member]
Debt Instrument [Line Items]
Impairments	145	145
Discontinued Operations, Held-for-sale [Member] | Exploration and Production [Member]
Debt Instrument [Line Items]
Impairments	$ 15	$ 15

Fair Value Measurements (Carryi

Fair Value Measurements (Carrying Amount and Estimated Fair Values of Financial Instruments) (Details) - USD ($)	Apr. 26, 2018	Dec. 31, 2018	Apr. 30, 2018	Jul. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net		$ 52,000,000			$ 52,000,000	$ 77,000,000
Repayments of long-term debt					2,095,000,000	1,139,000,000	$ 1,175,000,000
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents		201,000,000			201,000,000	916,000,000
Derivative instruments, net		52,000,000			52,000,000	77,000,000
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents		201,000,000			201,000,000	916,000,000
Derivative instruments, net		52,000,000			52,000,000	$ 77,000,000
Long-term Debt [Member] | 2016 Term Loan due December 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt, maturity date						Dec. 31, 2020
Repayments of long-term debt	$ 1,191,000,000		$ 1,191,000,000
Long-term Debt [Member] | Carrying Amount [Member] | 2016 Term Loan due December 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans						$ 1,191,000,000
Long-term Debt [Member] | Fair Value [Member] | 2016 Term Loan due December 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans						1,191,000,000
Senior Notes [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Repayments of long-term debt		900,000,000		$ 700,000,000
Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes		2,342,000,000			2,342,000,000	3,242,000,000
Senior Notes [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes		$ 2,190,000,000			$ 2,190,000,000	3,358,000,000
2018 Credit Facility [Member] | Long-term Debt [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Credit facility, maturity date					Apr. 26, 2023
Natural Gas [Member] | Purchased Call Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid						1,000,000
Natural Gas [Member] | Purchased Call Options [Member] | Not Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid						$ 1,000,000

Fair Value Measurements (Summar

Fair Value Measurements (Summary of Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		$ 51
Total	$ 77	52
Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	54	52
Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	23
Purchased Fixed Price Swap [Member] | Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(6)
Purchased Fixed Price Swap [Member] | Oil [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(6)
Fixed Price Swaps [Member] | Natural Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	56	38
Derivative liabilities	(1)	(10)
Fixed Price Swaps [Member] | Natural Gas [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	56	38
Derivative liabilities	(1)	(10)
Fixed Price Swaps [Member] | Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		19
Fixed Price Swaps [Member] | Oil [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		19
Fixed Price Swaps [Member] | Propane [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		11
Fixed Price Swaps [Member] | Propane [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		11
Fixed Price Swaps [Member] | Ethane [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		8
Derivative liabilities		(3)
Fixed Price Swaps [Member] | Ethane [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		8
Derivative liabilities		(3)
Two-Way Costless Collars [Member] | Natural Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5	11
Derivative liabilities	(1)	(7)
Two-Way Costless Collars [Member] | Natural Gas [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		11
Derivative liabilities		(7)
Two-Way Costless Collars [Member] | Natural Gas [Member] | Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5
Derivative liabilities	(1)
Two-Way Costless Collars [Member] | Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		11
Derivative liabilities		(1)
Two-Way Costless Collars [Member] | Oil [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		11
Derivative liabilities		(1)
Three-Way Costless Collars [Member] | Natural Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	121	75
Derivative liabilities	(66)	(68)
Three-Way Costless Collars [Member] | Natural Gas [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		75
Derivative liabilities		(68)
Three-Way Costless Collars [Member] | Natural Gas [Member] | Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	121
Derivative liabilities	(66)
Basis Swaps [Member] | Natural Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2	11
Derivative liabilities	(23)	(22)
Basis Swaps [Member] | Natural Gas [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		11
Derivative liabilities		(22)
Basis Swaps [Member] | Natural Gas [Member] | Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2
Derivative liabilities	(23)
Purchased Call Options [Member] | Natural Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3	6
Premium paid	1
Purchased Call Options [Member] | Natural Gas [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		6
Purchased Call Options [Member] | Natural Gas [Member] | Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3
Purchased Call Options [Member] | Natural Gas [Member] | Not Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid	1
Sold Call Options [Member] | Natural Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(18)	(22)
Sold Call Options [Member] | Natural Gas [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(22)
Sold Call Options [Member] | Natural Gas [Member] | Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(18)
Interest Rate Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		1
Derivative liabilities	(1)
Interest Rate Swaps [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		$ 1
Derivative liabilities	$ (1)

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 ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of year	$ 22	$ (195)
Included in earnings	(17)	199
Settlements	1	18
Transfers into/out of Level 3	6
Balance at end of period		22
Change in gains (losses) included in earnings relating to derivatives still held as of December 31		217
Natural Gas [Member] | Sold Call Options [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Amortization of premium paid		5
Natural Gas [Member] | Purchased Call Options [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Amortization of premium paid	$ 1	$ 1

Debt (2013 Credit Facility - Na

Debt (2013 Credit Facility - Narrative) (Details) - Long-term Debt [Member] - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Apr. 26, 2018	Jun. 30, 2016	Dec. 31, 2013
2013 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 66,000,000	$ 2,000,000,000
Credit facility, maturity date	Dec. 31, 2018
2016 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 743,000,000	743,000,000
Line of credit, amount borrowed		$ 0
2016 Term Loan due December 2020 [Member]
Debt Instrument [Line Items]
Debt instrument face amount				$ 1,191,000,000

Debt (2016 Credit Facility - Na

Debt (2016 Credit Facility - Narrative) (Details) - USD ($)	Apr. 26, 2018	Apr. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2013
Debt Instrument [Line Items]
Repayments of long-term debt			$ 2,095,000,000	$ 1,139,000,000	$ 1,175,000,000
Loss on early extinguishment of debt	$ 8,000,000		17,000,000	70,000,000	$ 51,000,000
Unamortized debt expense			23,000,000	40,000,000
2016 Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized debt expense			$ 4,000,000
Long-term Debt [Member] | 2013 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity						$ 66,000,000	$ 2,000,000,000
Credit facility, maturity date			Dec. 31, 2018
Long-term Debt [Member] | 2016 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	743,000,000					743,000,000
Unamortized debt expense	4,000,000
Line of credit, amount borrowed				0
Long-term Debt [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Amount outstanding			$ 112,000,000	$ 323,000,000
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity						1,934,000,000
Debt, maturity date			Dec. 31, 2020
2016 Term Loan due December 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Debt instrument face amount						$ 1,191,000,000
Debt, maturity date				Dec. 31, 2020
Repayments of long-term debt	$ 1,191,000,000	$ 1,191,000,000
Unamortized debt expense				$ 8,000,000

Debt (2018 Revolving Credit Fac

Debt (2018 Revolving Credit Facility - Narrative) (Details)	Apr. 26, 2018USD ($)	Apr. 30, 2018USD ($)	Jun. 30, 2020	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jun. 30, 2016USD ($)
Debt Instrument [Line Items]
Subsidiary ownership						100.00%
Repayments of long-term debt						$ 2,095,000,000	$ 1,139,000,000	$ 1,175,000,000
Long-term Debt [Member] | 2016 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 743,000,000								$ 743,000,000
Line of credit, amount borrowed							0
Long-term Debt [Member] | 2018 Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 3,500,000,000
Current borrowing capacity						2,100,000,000
Amount outstanding						$ 2,000,000,000
Credit facility, maturity date						Apr. 26, 2023
Long-term Debt [Member] | 2018 Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Minimum interest coverage ratio	1
Long-term Debt [Member] | 2018 Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Leverage ratio, percentage of credit limit	10.00%
Leverage ratio, amount of credit limit	$ 150,000,000
Long-term Debt [Member] | 2018 Credit Facility [Member] | Maximum [Member] | Scenario, Forecast [Member]
Debt Instrument [Line Items]
Leverage ratio			4	4.25	4.50
Long-term Debt [Member] | 2018 Credit Facility [Member] | Eurodollar [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis points	1.50%
Long-term Debt [Member] | 2018 Credit Facility [Member] | Eurodollar [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis points	2.50%
Long-term Debt [Member] | 2018 Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis points	0.50%
Long-term Debt [Member] | 2018 Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis points	1.50%
Long-term Debt [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Amount outstanding						$ 112,000,000	$ 323,000,000
2016 Term Loan due December 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Debt instrument face amount									$ 1,191,000,000
Repayments of long-term debt	$ 1,191,000,000	$ 1,191,000,000

Debt (Senior Notes - Narrative)

Debt (Senior Notes - Narrative) (Details) - USD ($)	Apr. 26, 2018	Dec. 31, 2018	Sep. 30, 2017	Jul. 31, 2016	Jan. 31, 2015	Jun. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jul. 31, 2018
Debt Instrument [Line Items]
Loss on early extinguishment of debt	$ 8,000,000						$ 17,000,000	$ 70,000,000	$ 51,000,000
Repayments of long-term debt							$ 2,095,000,000	1,139,000,000	$ 1,175,000,000
Repayment of short-term debt								$ 328,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Proceeds from issuance of debt			$ 1,100,000,000
Loss on early extinguishment of debt		$ 9,000,000	59,000,000			$ 11,000,000
Payment of premiums		2,000,000	53,000,000
Repayments of long-term debt		$ 900,000,000		$ 700,000,000
Senior Notes [Member] | Over LIBOR [Member]
Debt Instrument [Line Items]
Incremental increase in basis points resulting from downgrades					0.25%
Incremental decrease in basis points resulting from upgrades					0.25%
Increase in basis spread				1.75%
4.05% Senior Notes due January 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Stated interest rate		4.05%					4.05%
Debt, maturity date							Jan. 31, 2020
4.05% Senior Notes due January 2020 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes					$ 850,000,000
Stated interest rate		4.05%		5.80%	4.05%		4.05%	4.05%		5.30%
Debt, maturity date							Jan. 31, 2020	Jan. 31, 2020
Repayments of long-term debt		$ 40,000,000
4.95% Senior Notes due January 2025 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes					$ 1,000,000,000
Stated interest rate		4.95%		6.70%	4.95%		4.95%	4.95%		6.20%
Debt, maturity date							Jan. 31, 2025	Jan. 31, 2025
Repayments of long-term debt		$ 73,000,000
3.30% Senior Notes due January 2018 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate		3.30%					3.30%
Debt, maturity date							Jan. 31, 2018
Repayments of long-term debt						38,000,000
7.5% Senior Notes due 2018 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate		7.50%					7.50%
Debt, maturity date							Feb. 28, 2018
Repayments of long-term debt						212,000,000
7.15% Senior Notes due 2018 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate		7.15%					7.15%
Debt, maturity date							Jun. 30, 2018
Repayments of long-term debt						$ 26,000,000
7.50% Senior Notes due April 2026 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes			$ 650,000,000
Stated interest rate		7.50%	7.50%				7.50%	7.50%
Debt, maturity date							Apr. 30, 2026	Apr. 30, 2026
7.75% Senior Notes due October 2027 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes			$ 500,000,000
Stated interest rate		7.75%	7.75%				7.75%	7.75%
Debt, maturity date							Oct. 31, 2027	Oct. 31, 2027
2020 Senior Notes [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of long-term debt			$ 758,000,000
2015 Term Loan due December 2020 [Member] | Long-term Debt [Member]
Debt Instrument [Line Items]
Repayments of long-term debt				$ 375,000,000
2015 Term Loan due December 2020 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of long-term debt			$ 327,000,000
4.10% Senior Notes Due 2022 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate		4.10%					4.10%	4.10%
Debt, maturity date							Mar. 31, 2022	Mar. 31, 2022
Repayments of long-term debt		$ 787,000,000
Maximum [Member] | 4.05% Senior Notes due January 2020 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate				6.05%
Maximum [Member] | 4.95% Senior Notes due January 2025 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate				6.95%

Debt (Components of Debt) (Deta

Debt (Components of Debt) (Details) - USD ($)	Apr. 26, 2018	Dec. 31, 2018	Apr. 30, 2018	Sep. 30, 2017	Jul. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jul. 31, 2018	Jan. 31, 2015
Debt Instrument [Line Items]
Debt Instrument		$ 2,342,000,000				$ 2,342,000,000	$ 4,433,000,000
Unamortized Issuance Expense		(23,000,000)				(23,000,000)	(40,000,000)
Unamortized Debt Discount		(1,000,000)				(1,000,000)	(2,000,000)
Total		2,318,000,000				2,318,000,000	4,391,000,000
Other long-term assets		185,000,000				185,000,000	240,000,000
Repayments of long-term debt						2,095,000,000	1,139,000,000	$ 1,175,000,000
Payments on revolving credit facility						1,983,000,000		$ 3,268,000,000
2016 Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized Issuance Expense		$ (4,000,000)				$ (4,000,000)
Long-term Debt [Member] | 2018 Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility, variable interest rate		3.92%				3.92%
Credit facility, maturity date						Apr. 26, 2023
Other long-term assets		$ 11,000,000				$ 11,000,000
Payments on revolving credit facility			$ 1,191,000,000
Long-term Debt [Member] | 2016 Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized Issuance Expense	$ (4,000,000)
Long-term Debt [Member] | 2016 Term Loan due December 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument							1,191,000,000
Unamortized Issuance Expense							(8,000,000)
Total							$ 1,183,000,000
Variable interest rate							3.98%
Debt, maturity date							Dec. 31, 2020
Repayments of long-term debt	$ 1,191,000,000		$ 1,191,000,000
Long-term Debt [Member] | 4.05% Senior Notes due January 2020 [Member]
Debt Instrument [Line Items]
Stated interest rate		4.05%				4.05%
Debt, maturity date						Jan. 31, 2020
Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of long-term debt		$ 900,000,000			$ 700,000,000
Senior Notes [Member] | 4.05% Senior Notes due January 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument		52,000,000				$ 52,000,000	$ 92,000,000
Total		$ 52,000,000				$ 52,000,000	$ 92,000,000
Stated interest rate		4.05%			5.80%	4.05%	4.05%		5.30%	4.05%
Debt, maturity date						Jan. 31, 2020	Jan. 31, 2020
Repayments of long-term debt		$ 40,000,000
Senior Notes [Member] | 4.05% Senior Notes due January 2020 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Stated interest rate					6.05%
Senior Notes [Member] | 4.10% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument		213,000,000				$ 213,000,000	$ 1,000,000,000
Unamortized Issuance Expense		(1,000,000)				(1,000,000)	(7,000,000)
Total		$ 212,000,000				$ 212,000,000	$ 993,000,000
Stated interest rate		4.10%				4.10%	4.10%
Debt, maturity date						Mar. 31, 2022	Mar. 31, 2022
Repayments of long-term debt		$ 787,000,000
Senior Notes [Member] | 4.95% Senior Notes due January 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument		927,000,000				$ 927,000,000	$ 1,000,000,000
Unamortized Issuance Expense		(7,000,000)				(7,000,000)	(8,000,000)
Unamortized Debt Discount		(1,000,000)				(1,000,000)	(2,000,000)
Total		$ 919,000,000				$ 919,000,000	$ 990,000,000
Stated interest rate		4.95%			6.70%	4.95%	4.95%		6.20%	4.95%
Debt, maturity date						Jan. 31, 2025	Jan. 31, 2025
Repayments of long-term debt		$ 73,000,000
Senior Notes [Member] | 4.95% Senior Notes due January 2025 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Stated interest rate					6.95%
Senior Notes [Member] | 7.50% Senior Notes due April 2026 [Member]
Debt Instrument [Line Items]
Debt Instrument		650,000,000				$ 650,000,000	$ 650,000,000
Unamortized Issuance Expense		(8,000,000)				(8,000,000)	(10,000,000)
Total		$ 642,000,000				$ 642,000,000	$ 640,000,000
Stated interest rate		7.50%		7.50%		7.50%	7.50%
Debt, maturity date						Apr. 30, 2026	Apr. 30, 2026
Senior Notes [Member] | 7.75% Senior Notes due October 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument		$ 500,000,000				$ 500,000,000	$ 500,000,000
Unamortized Issuance Expense		(7,000,000)				(7,000,000)	(7,000,000)
Total		$ 493,000,000				$ 493,000,000	$ 493,000,000
Stated interest rate		7.75%		7.75%		7.75%	7.75%
Debt, maturity date						Oct. 31, 2027	Oct. 31, 2027
Senior Notes [Member] | 2020 Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of long-term debt				$ 758,000,000
Over LIBOR [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Increase in basis spread					1.75%

Debt (Schedule of Debt Maturiti

Debt (Schedule of Debt Maturities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt [Abstract]
2,020	$ 52
2,022	213
Thereafter	2,077
Total	$ 2,342	$ 4,433

Commitments and Contingencies_2

Commitments and Contingencies (Narrative) (Details)	12 Months Ended	24 Months Ended
	Dec. 31, 2018USD ($)lawsuititem	Dec. 31, 2020USD ($)	Jan. 31, 2019USD ($)
Commitments And Contingencies [Line Items]
Obligation under transportation agreements	$ 8,794,000,000
Guarantee obligations relative to the firms transportation agreements and gathering project and services	463,000,000
Operating leases, future minimum payments, 2019	38,000,000
Operating leases, future minimum payments, 2020	28,000,000
Operating leases, future minimum payments, 2021	14,000,000
Operating leases, future minimum payments, 2022	6,000,000
Operating leases, future minimum payments, 2023	5,000,000
Operating leases, future minimum payments, thereafter	4,000,000
Indemnification liability	0
Access Capacity on Future Projects Concentration Risk [Member]
Commitments And Contingencies [Line Items]
Obligation under transportation agreements	$ 3,100,000,000
Appalachian Basin [Member] | Subsequent Event [Member]
Commitments And Contingencies [Line Items]
Obligation under transportation agreements			$ 357,000,000
Obligation under transportation agreements, reimbursed by seller			$ 133,000,000
Arkansas Royalty Litigation [Member]
Commitments And Contingencies [Line Items]
Number of cases | lawsuit	3
Arkansas Royalty Litigation [Member] | Arkansas State Court [Member]
Commitments And Contingencies [Line Items]
Number of cases | lawsuit	2
Pending Regulatory Approval and/or Construction [Member]
Commitments And Contingencies [Line Items]
Obligation under transportation agreements	$ 3,079,000,000
Exploration and Production [Member]
Commitments And Contingencies [Line Items]
Operating leases, future minimum payments, 2019	3,000,000
Operating leases, future minimum payments, 2020	1,000,000
Operating leases, future minimum payments, 2021	$ 1,000,000
Exploration and Production [Member] | Pressure Pumping Equipment [Member]
Commitments And Contingencies [Line Items]
Number of leases | item	1
Lease expiration date	Dec. 31, 2021
Aggregate annual lease payment	$ 7,000,000
Exploration and Production [Member] | Drilling Rigs [Member]
Commitments And Contingencies [Line Items]
Number of leases | item	7
Lease expiration date	Dec. 31, 2024
Aggregate annual lease payment	$ 13,000,000
Fayetteville Shale [Member]
Commitments And Contingencies [Line Items]
Contractual commitments assumed by buyer	221,000,000
Liability for estimated future payments	$ 88,000,000
Fayetteville Shale [Member] | Scenario, Forecast [Member]
Commitments And Contingencies [Line Items]
Potential amount to be reimbursed to buyer		$ 102,000,000
Fayetteville Shale [Member] | Scenario, Forecast [Member] | Maximum [Member]
Commitments And Contingencies [Line Items]
Potential amount to be reimbursed to buyer		$ 102,000,000

Commitments and Contingencies_3

Commitments and Contingencies (Schedule of Future Obligation under Transportation Agreements) (Details) $ in Millions	Dec. 31, 2018USD ($)
Other Commitments [Line Items]
Total	$ 8,794
Less than 1 year	773
1 to 3 years	1,408
3 to 5 years	1,268
5 to 8 years	1,744
More than 8 years	3,601
Infrastructure Currently in Service [Member]
Other Commitments [Line Items]
Total	5,715
Less than 1 year	637
1 to 3 years	1,060
3 to 5 years	876
5 to 8 years	1,123
More than 8 years	2,019
Pending Regulatory Approval and/or Construction [Member]
Other Commitments [Line Items]
Total	3,079
Less than 1 year	136
1 to 3 years	348
3 to 5 years	392
5 to 8 years	621
More than 8 years	$ 1,582

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Effective tax rate		0.00%	(10.00%)	1.00%
Corporate income tax rate		21.00%
Alternative minimum tax carryforward, expected refund		$ 68,000,000
Cash paid for income taxes		6,000,000	$ (5,000,000)	$ (15,000,000)
Net operating loss carryforward		777,000,000	1,043,000,000
Statutory depletion carryforward		13,000,000
Net deferred tax assets		0
Reduction to valuation allowance as a component of income tax expense		(121,000,000)
Reduction to equity		2,000,000
Reduction to valuation allowance		$ 123,000,000
Cumulative loss period		3 years
Unrecognized tax benefits		$ 7,000,000	12,000,000	$ 17,000,000
Share-based Payments [Member]
Income Taxes [Line Items]
Unrecognized tax benefits		0
Exploration Program in Canada [Member]
Income Taxes [Line Items]
Net operating loss carryforward		29,000,000
State [Member]
Income Taxes [Line Items]
Cash paid for income taxes		6,300,000
Net operating loss carryforward		2,100,000,000
Federal [Member]
Income Taxes [Line Items]
Income tax refund received			4,200,000
Net operating loss carryforward		$ 3,000,000,000
Minimum [Member]
Income Taxes [Line Items]
Fully refunded year		2,019
Net operating loss carryforwards expiration date		Dec. 31, 2035
Minimum [Member] | Exploration Program in Canada [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date		Dec. 31, 2030
Maximum [Member]
Income Taxes [Line Items]
Fully refunded year		2,021
Net operating loss carryforwards expiration date		Dec. 31, 2037
Accrued liability of interest related to uncertain tax position		$ 1,000,000
Maximum [Member] | Exploration Program in Canada [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date		Dec. 31, 2038
Maximum [Member] | State [Member]
Income Taxes [Line Items]
Income tax refund received			$ 1,000,000
Accounting Standards Update 2016-09 [Member]
Income Taxes [Line Items]
Unrecognized windfall tax benefits, cumulative-effect adjustment	$ 149,000,000
Net cumulative-effect adjustment	$ 59,000,000

Income Taxes (Provision (Benefi

Income Taxes (Provision (Benefit) for Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current:
Federal	$ (5)	$ (22)	$ (6)
State	6		(1)
Total	1	(22)	(7)
Deferred:
Federal		(71)	(22)
Total		(71)	(22)
Provision (Benefit) for Income Taxes	$ 1	$ (93)	$ (29)

Income Taxes (Reconciliation of

Income Taxes (Reconciliation of Provision for Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Abstract]
Expected provision (benefit) at federal statutory rate	$ 113	$ 333	$ (935)
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect	13	16	(79)
Rate impacts due to tax reform		370
Changes to valuation allowance due to tax reform		(370)
AMT tax reform impact - valuation allowance release		(68)
Change in uncertain tax positions		(5)	(19)
Change in valuation allowance	(121)	(364)	1,002
Removal of sequestration fee on AMT receivables	(5)
Other	1	(5)	2
Provision (Benefit) for Income Taxes	$ 1	$ (93)	$ (29)

Income Taxes (Components of Def

Income Taxes (Components of Deferred Tax Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred tax liabilities:
Differences between book and tax basis of property	$ 226	$ 395
Derivative activity	12	19
Other	2	1
Total deferred tax liabilities	240	415
Deferred tax assets
Accrued compensation	33	29
Accrued pension costs	10	14
Asset retirement obligations	15	41
Net operating loss carryforward	777	1,043
Other	14	20
Total deferred tax assets	849	1,147
Valuation allowance	(609)	(732)
Net deferred tax liability

Income Taxes (Reconciliation _2

Income Taxes (Reconciliation of Changes to the Valuation Allowance) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Income Taxes [Abstract]
Valuation allowance as of December 31, 2017	$ 732
Changes based on 2018 activity	(121)
Equity - pension benefits in OCI	(2)
Valuation allowance as of December 31, 2018	$ 609

Income Taxes (Reconciliation _3

Income Taxes (Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Abstract]
Unrecognized tax benefits at beginning of period	$ 12	$ 17
Reductions to tax positions of prior years	(5)	(5)
Unrecognized tax benefits at end of period	$ 7	$ 12

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Asset retirement obligation at January 1	$ 165	$ 141
Accretion of discount	9	8
Obligations incurred	1	3
Obligations settled/removed	(116)	(10)
Revisions of estimates	2	23
Asset retirement obligation at December 31	61	165
Current liability			$ 6	$ 12
Long-term liability			55	153
Asset retirement obligation at December 31	165	$ 141	$ 61	$ 165
Asset Divestitures [Member]
Asset Retirement Obligations [Line Items]
Obligations settled/removed	(111)
Fayetteville Shale [Member]
Asset Retirement Obligations [Line Items]
Obligations settled/removed	$ (107)

Retirement and Employee Benef_3

Retirement and Employee Benefit Plans (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Non-cash curtailment gain (loss)				$ 4		$ (5)
Change in accumulated other comprehensive income (loss)				6
Defined benefit plan included in accumulated other comprehensive (income) loss, before tax				34	$ 42
Defined benefit plan included in accumulated other comprehensive (income) loss after tax				20	26
Expected future net loss				2
Company's expected additional annual contribution				13
401 (k) Defined Contribution Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution expense				3	3	4
Contributions capitalized				2	2	2
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Non-cash curtailment gain (loss)		$ (1)				(1)
Settlement loss						(11)
Lump-sum payment						37
Employer contributions				12	14
Benefit obligation				125	143	117
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Non-cash curtailment gain (loss)	$ 4		$ 6	4		6
Employer contributions				1	1
Benefit obligation				$ 13	$ 17	$ 13

Retirement and Employee Benef_4

Retirement and Employee Benefit Plans (Changes in Plans Benefit Obligations, Fair Value of Assets, and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Change in benefit obligations:
Benefit obligation at January 1	$ 143	$ 117
Service cost	10	9	$ 11
Interest cost	5	5	5
Actuarial loss (gain)	(14)	21
Benefits paid	(14)	(9)
Curtailments	(5)
Benefit obligation at December 31	125	143	117
Change in plan assets:
Fair value of plan assets at January 1	101	81
Actual return on plan assets	(8)	15
Employer contributions	12	14
Benefits paid	(14)	(9)
Fair value of plan assets at December 31	91	101	81
Funded status of plans at December 31	(34)	(42)
Other Postretirement Benefits [Member]
Change in benefit obligations:
Benefit obligation at January 1	17	13
Service cost	2	2	2
Interest cost	1		1
Actuarial loss (gain)		3
Benefits paid	(1)	(1)
Curtailments	(6)
Benefit obligation at December 31	13	17	$ 13
Change in plan assets:
Employer contributions	1	1
Benefits paid	(1)	(1)
Funded status of plans at December 31	$ (13)	$ (17)

Retirement and Employee Benef_5

Retirement and Employee Benefit Plans (Projected Benefit Obligation, Accumulated Benefit Obligation and Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Retirement and Employee Benefit Plans [Abstract]
Projected benefit obligation	$ 125	$ 143
Accumulated benefit obligation	122	137
Fair value of plan assets	$ 91	$ 101

Retirement and Employee Benef_6

Retirement and Employee Benefit Plans (Pension and Other Postretirement Benefit Costs) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Curtailment (gain) loss				$ (4)		$ 5
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost				10	$ 9	11
Interest cost				5	5	5
Expected return on plan assets				(7)	(6)	(6)
Amortization of net loss				2	2	2
Net periodic benefit cost				10	10	12
Curtailment (gain) loss		$ 1				1
Settlement loss						11
Total benefit cost (benefit)				10	10	24
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost				2	2	2
Interest cost				1		1
Net periodic benefit cost				3	2	3
Curtailment (gain) loss	$ (4)		$ (6)	(4)		(6)
Total benefit cost (benefit)				$ (1)	$ 2	$ (3)

Retirement and Employee Benef_7

Retirement and Employee Benefit Plans (Amounts Recognized in Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (loss) gain arising during the year	$ (2)	$ (11)
Amortization of net loss	2	2
Curtailments	5
Tax effect	(1)	3
Total	4	(6)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (loss) gain arising during the year		(2)
Curtailments	3
Tax effect	(1)	1
Total	$ 2	$ (1)

Retirement and Employee Benef_8

Retirement and Employee Benefit Plans (Schedule of Assumptions Used - Benefit Obligations) (Details)	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.35%	3.75%
Rate of compensation increase	3.50%	3.50%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.35%	3.75%

Retirement and Employee Benef_9

Retirement and Employee Benefit Plans (Schedule of Assumptions Used - Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.35%	4.20%	4.20%
Expected return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	3.50%	3.50%	3.50%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.35%	4.20%	4.20%

Retirement and Employee Bene_10

Retirement and Employee Benefit Plans (Schedule of Health Care Cost Trend Rates) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Retirement and Employee Benefit Plans [Abstract]
Health care cost trend assumed for next year	7.00%	7.00%
Rate to which the cost trend is assumed to decline	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2,036	2,035

Retirement and Employee Bene_11

Retirement and Employee Benefit Plans (One Percentage Point Change in Assumed Health Care Cost Trend Rates) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Retirement and Employee Benefit Plans [Abstract]
Effect on postretirement benefit obligations, 1% Increase	$ 2
Effect on postretirement benefit obligation, 1% Decrease	$ (1)

Retirement and Employee Bene_12

Retirement and Employee Benefit Plans (Schedule of Expected Benefit Payments) (Details) $ in Millions	Dec. 31, 2018USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2,019	$ 22
2,020	6
2,021	6
2,022	6
2,023	7
Years 2024-2028	39
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2,019	1
2,020	1
2,021	1
2,022	1
2,023	1
Years 2024-2028	$ 5

Retirement and Employee Bene_13

Retirement and Employee Benefit Plans (Schedule of Allocation of Plan Assets) (Details) - Pension Benefits [Member]	Dec. 31, 2018
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	28.00%
Actual asset allocations	23.00%
Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	2.00%
Actual asset allocations	25.00%
U.S. Equity [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	35.00%
Actual asset allocations	26.00%
Non-U.S. Developed Equity [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	30.00%
Actual asset allocations	22.00%
Emerging Markets Equity [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	5.00%
Actual asset allocations	4.00%

Retirement and Employee Bene_14

Retirement and Employee Benefit Plans (Fair Value Measurement of Pension Plan Assets) (Details) - Pension Benefits [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 91	$ 101	$ 81
Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	72	83
Excluding Net Assets Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	72	83
Net Asset Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19	18
Equity Securities [Member] | U.S. Large Cap Growth Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5	7
Equity Securities [Member] | U.S. 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	5	7
Equity Securities [Member] | U.S. Large Cap Value Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5	8
Equity Securities [Member] | U.S. 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	5	8
Equity Securities [Member] | U.S. Large Cap Core Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		18
Equity Securities [Member] | U.S. Large Cap Core Equity [Member] | Net Asset Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12
Equity Securities [Member] | U.S. Small Cap Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	3
Equity Securities [Member] | U.S. 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	2	3
Equity Securities [Member] | Non-U.S. Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	20	30
Equity Securities [Member] | Non-U.S. Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	20	30
Equity Securities [Member] | Emerging Markets Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	5
Equity Securities [Member] | Emerging Markets 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	5
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	27
Fixed Income [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	27
Fixed Income [Member] | Net Asset Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7
Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	23	3
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	23	$ 3
Fayetteville Shale [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 21

Stock-Based Compensation (Narra

Stock-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation [Line Items]
Period of service for immediate vesting upon death, disability or retirement			3 years
Positions eliminated, percent	40.00%
Stock Options [Member]
Share-based Compensation [Line Items]
Vesting period for stock awards from grant date			3 years
Expiration period from date of grant			7 years
Equity-classified awards, unrecognized compensation cost			$ 1
Equity-classified awards, weighted average period over which unrecognized cost is recognized, years			1 year
Deferred tax asset, recorded			$ 1	$ 1	$ 2
Number of Options, Granted			0	1,604,000	155,000
Weighted-average grant-date fair value of options granted				$ 3.47	$ 3.22
Stock options, exercised, number of options			0	0	45,000
Restricted Stock [Member]
Share-based Compensation [Line Items]
Equity-classified awards, unrecognized compensation cost			$ 15
Equity-classified awards, weighted average period over which unrecognized cost is recognized, years			2 years
Deferred tax asset, recorded			$ 2	$ 9	$ 12
Total fair value of restricted stock grants			2	42	1
Total fair value of shares vested			19	18	43
Performance Units [Member]
Share-based Compensation [Line Items]
Equity-classified awards, unrecognized compensation cost			$ 3
Equity-classified awards, weighted average period over which unrecognized cost is recognized, years			1 year
Deferred tax asset, recorded			$ 1	$ 3	4
Liability-Classified Restricted Stock Units [Member]
Share-based Compensation [Line Items]
Liability-classified restricted stock, vesting period			4 years
Liability-classified restricted stock, unrecognized compensation cost			$ 22
Liability-classified restricted stock, weighted average period over which unrecognized cost is recognized, years			3 years
Deferred tax asset, recorded			$ 2
Liability-Classified Performance Units [Member]
Share-based Compensation [Line Items]
Liability-classified performance units, vesting period			3 years
Liability-classified performance units, unrecognized compensation cost			$ 9
Liability-classified performance units, weighted average period over which unrecognized cost is recognized, years			2 years
Deferred tax asset, recorded			$ 1
Maximum [Member] | 2013 Plan [Member]
Share-based Compensation [Line Items]
Maximum shares			52,700,000
Maximum [Member] | Stock Options [Member]
Share-based Compensation [Line Items]
Intrinsic value					$ 1
Workforce Reduction [Member]
Share-based Compensation [Line Items]
Positions eliminated, percent		40.00%

Stock-Based Compensation (Sched

Stock-Based Compensation (Schedule of Equity-Classified Stock Option Stock-Based Compensation Costs) (Details) - Stock Options [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee Service Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity-classified awards - expensed	$ 2	$ 3	$ 6
Equity-classified awards - capitalized		$ 1	1
Workforce Reduction [Member]
Employee Service Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity-classified awards - expensed			1
Executive Management Restructuring [Member]
Employee Service Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity-classified awards - expensed			$ 1

Stock-Based Compensation (Sch_2

Stock-Based Compensation (Schedule of Equity-Classified Valuation Assumptions) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock-Based Compensation [Abstract]
Risk-free interest rate		1.90%	1.40%
Expected dividend yield
Expected volatility		50.50%	41.00%
Expected term	0 years	5 years	5 years

Stock-Based Compensation (Summa

Stock-Based Compensation (Summary of Equity-Classified Stock Option Activity) (Details) - Stock Options [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Options, Outstanding at January 1, 2018	6,020,000	5,416,000	5,623,000
Number of Options, Granted	0	1,604,000	155,000
Number of Options, Exercised	0	0	(45,000)
Number of Options, Forfeited or expired	(842,000)	(1,000,000)	(317,000)
Number of Options, Outstanding at December 31, 2018	5,178,000	6,020,000	5,416,000
Weighted Average Exercise Price, Outstanding at January 1, 2018	$ 19.43	$ 23.46	$ 24.57
Weighted Average Exercise Price, Granted		8	8.60
Weighted Average Exercise Price, Exercised			7.74
Weighted Average Exercise Price, Forfeited or expired	33.99	22.93	38.01
Weighted Average Exercise Price, Outstanding at December 31, 2018	$ 17.06	$ 19.43	$ 23.46

Stock-Based Compensation (Sum_2

Stock-Based Compensation (Summary of Equity-Classified Stock Options Outstanding and Options Exercisable) (Details) - Stock Options [Member] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Outstanding - Options Outstanding at December 31, 2018	5,178	6,020	5,416	5,623
Options Outstanding - Weighted Average Exercise Price	$ 17.06	$ 19.43	$ 23.46	$ 24.57
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	3 years 7 months 6 days
Options Exercisable - Options Exercisable at December 31, 2018		4,266
Options Exercisable - Weighted Average Exercise Price		$ 19.02
Options Exercisable - Weighted Average Remaining Contractual Life (Years)		3 years 3 months 18 days
Range of Exercise Prices $5.22-$29.42 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit	$ 5.22
Range of Exercise Prices, Upper Range Limit	$ 29.42
Options Outstanding - Options Outstanding at December 31, 2018	3,517
Options Outstanding - Weighted Average Exercise Price	$ 8.68
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	4 years 4 months 24 days
Options Exercisable - Options Exercisable at December 31, 2018	2,605
Options Exercisable - Weighted Average Exercise Price	$ 8.96
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	4 years 1 month 6 days
Range of Exercise Prices $30.59-$35.64 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit	$ 30.59
Range of Exercise Prices, Upper Range Limit	$ 35.64
Options Outstanding - Options Outstanding at December 31, 2018	1,135
Options Outstanding - Weighted Average Exercise Price	$ 32.26
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	2 years 1 month 6 days
Options Exercisable - Options Exercisable at December 31, 2018	1,135
Options Exercisable - Weighted Average Exercise Price	$ 32.26
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	2 years 1 month 6 days
Range of Exercise Prices $36.69-$39.48 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit	$ 36.69
Range of Exercise Prices, Upper Range Limit	$ 39.48
Options Outstanding - Options Outstanding at December 31, 2018	436
Options Outstanding - Weighted Average Exercise Price	$ 38.97
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	1 year 10 months 24 days
Options Exercisable - Options Exercisable at December 31, 2018	436
Options Exercisable - Weighted Average Exercise Price	$ 38.97
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	1 year 10 months 24 days
Range of Exercise Prices $40.15-$49.00 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit	$ 40.15
Range of Exercise Prices, Upper Range Limit	$ 49
Options Outstanding - Options Outstanding at December 31, 2018	90
Options Outstanding - Weighted Average Exercise Price	$ 46.55
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	2 years 4 months 24 days
Options Exercisable - Options Exercisable at December 31, 2018	90
Options Exercisable - Weighted Average Exercise Price	$ 46.55
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	2 years 4 months 24 days

Stock-Based Compensation (Sch_3

Stock-Based Compensation (Schedule of Equity-Classified Restricted Stock Stock-Based Compensation Costs) (Details) - Restricted Stock [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	$ 9	$ 16	$ 33
Equity-classified awards - capitalized	$ 5	$ 11	8
Workforce Reduction [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed			16
Executive Management [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed			$ 1

Stock-Based Compensation (Sum_3

Stock-Based Compensation (Summary of Equity-Classified Restricted Stock Activity) (Details) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Unvested shares/units at January 1, 2018	6,254,000	3,321,000	7,222,000
Number of Shares/Units, Granted	350,000	5,055,000	81,000
Number of Shares/Units, Vested	(2,058,000)	(1,380,000)	(3,817,000)
Number of Shares/Units, Forfeited	(1,829,000)	(742,000)	(165,000)
Number of Shares/Units, Unvested shares/units at December 31, 2018	2,717,000	6,254,000	3,321,000
Weighted Average Fair Value, Unvested shares/units at January 1, 2018	$ 8.85	$ 11.85	$ 13.24
Weighted Average Fair Value, Granted	4.72	8.38	8.56
Weighted Average Fair Value, Vested	9.24	13.28	11.34
Weighted Average Fair Value, Forfeited	9.01	10.04	12.05
Weighted Average Fair Value, Unvested shares/units at December 31, 2018	$ 7.91	$ 8.85	$ 11.85
Workforce Reduction [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Vested			(2,059,626)
Number of Shares/Units, Forfeited	(1,287,636)
Executive Management Restructuring [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Vested			(151,575)

Stock-Based Compensation (Sch_4

Stock-Based Compensation (Schedule of Equity-Classified Performance Units Stock-Based Compensation Costs) (Details) - Performance Units [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	$ 3	$ 5	$ 9
Equity-classified awards - capitalized	$ 1	$ 2	1
Workforce Reduction [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed			1
Executive Management [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed			$ 1

Stock-Based Compensation (Sum_4

Stock-Based Compensation (Summary of Equity-Classified Performance Units Activity) (Details) - Performance Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Unvested shares/units at January 1, 2018	1,084,000	719,000	407,000
Number of Shares/Units, Granted		1,197,000	1,503,000
Number of Shares/Units, Vested	(290,000)	(325,000)	(889,000)
Number of Shares/Units, Forfeited	(196,000)	(507,000)	(302,000)
Number of Shares/Units, Unvested shares/units at December 31, 2018	598,000	1,084,000	719,000
Weighted Average Fair Value, Unvested shares/units at January 1, 2018	$ 10.12	$ 11.46	$ 36.65
Weighted Average Fair Value, Granted		10.47	8.60
Weighted Average Fair Value, Vested	10.47	12.21	12.78
Weighted Average Fair Value, Forfeited	9.94	9.53	11.26
Weighted Average Fair Value, Unvested shares/units at December 31, 2018	$ 10.01	$ 10.12	$ 11.46
Share-based Compensation Award, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date		3 years
Workforce Reduction [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Vested			(22,918)
Number of Shares/Units, Forfeited	(144,927)		(87,595)
Executive Management [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Vested			(37,590)
Number of Shares/Units, Forfeited			(195,834)

Stock-Based Compensation (Sch_5

Stock-Based Compensation (Schedule of Liability-Classified Restricted Stock Units Stock-Based Compensation Costs) (Details) - Liability-Classified Restricted Stock Units [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Liability-classified stock-based compensation cost - expensed	$ 4
Liability-classified stock-based compensation cost - capitalized	$ 3

Stock-Based Compensation (Sum_5

Stock-Based Compensation (Summary of Liability-Classified Restricted Stock Unit Activity) (Details) - Liability-Classified Restricted Stock Units [Member]	12 Months Ended
	Dec. 31, 2018$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Unvested shares/units at January 1, 2018
Number of Shares/Units, Granted	12,216,000
Number of Shares/Units, Vested	(232,000)
Number of Shares/Units, Forfeited	(3,782,000)
Number of Shares/Units, Unvested shares/units at December 31, 2018	8,202,000
Weighted Average Fair Value, Unvested shares/units at January 1, 2018 | $ / shares
Weighted Average Fair Value, Granted | $ / shares	3.69
Weighted Average Fair Value, Vested | $ / shares	5.14
Weighted Average Fair Value, Forfeited | $ / shares	4.86
Weighted Average Fair Value, Unvested shares/units at December 31, 2018 | $ / shares	$ 3.41
Workforce Reduction [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Forfeited	(2,766,610)

Stock-Based Compensation (Sch_6

Stock-Based Compensation (Schedule of Liability-Classified Performance Units Stock-Based Compensation Costs) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Liability-Classified Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Liability-classified stock-based compensation cost - expensed	$ 2

Stock-Based Compensation (Sum_6

Stock-Based Compensation (Summary of Liability-Classified Performance Unit Activity) (Details) - Liability-Classified Performance Units [Member]	12 Months Ended
	Dec. 31, 2018$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Unvested shares/units at January 1, 2018
Number of Shares/Units, Granted	3,200,000
Number of Shares/Units, Vested
Number of Shares/Units, Forfeited	(397,000)
Number of Shares/Units, Unvested shares/units at December 31, 2018	2,803,000
Weighted Average Fair Value, Unvested shares/units at January 1, 2018 | $ / shares
Weighted Average Fair Value, Granted | $ / shares	3.70
Weighted Average Fair Value, Vested | $ / shares
Weighted Average Fair Value, Forfeited | $ / shares	4.55
Weighted Average Fair Value, Unvested shares/units at December 31, 2018 | $ / shares	$ 3.41
Workforce Reduction [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Forfeited	295,160

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions	Apr. 26, 2018	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenues from external customers		$ 1,175	$ 951	$ 816	$ 920	$ 809	$ 737	$ 811	$ 846	$ 3,862	$ 3,203	$ 2,436
Depreciation, depletion and amortization expense										560	504	436
Impairments										171		2,321
Impairments of natural gas and oil properties												2,321
Operating income (loss)		352	$ 66	$ 124	$ 255	167	$ 110	$ 188	$ 266	797	731	(2,190)
Interest expense										124	135	88
Gain (loss) on derivatives										(118)	422	(339)
Loss on early extinguishment of debt	$ (8)									(17)	(70)	(51)
Other income (loss), net											5	(4)
Benefit for income taxes										1	(93)	(29)
Assets		5,797				7,521				5,797	7,521	7,076
Capital investments										1,248	1,293	648
Restructuring charges										39		73
Cash and cash equivalents		201				916				201	916	1,423	$ 15
Change in accrued expenditures										(53)		43
Gain on sale of assets, net										17	6
Amortization of intangible asset										9	9	9
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										(2,408)	(2,081)	(1,546)
Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										2,551	2,105	1,435
Depreciation, depletion and amortization expense										514	440	371
Impairments										15
Impairments of natural gas and oil properties												2,321
Operating income (loss)										794	549	(2,399)
Interest expense										124	135	87
Gain (loss) on derivatives										(118)	421	(338)
Other income (loss), net										2	4
Benefit for income taxes										1	(93)	(29)
Assets		4,872				5,109				4,872	5,109	4,178
Capital investments										1,231	1,248	623
Restructuring and other one-time charges												81
Restructuring charges										37
Gain on sale of assets, net										(18)
Exploration and Production [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										26	19	22
Midstream Services [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										1,311	1,098	1,001
Depreciation, depletion and amortization expense										46	64	65
Impairments										155
Operating income (loss)										4	183	209
Interest expense												1
Gain (loss) on derivatives											1	(1)
Other income (loss), net										(2)	1	(2)
Assets		539				1,288				539	1,288	1,331
Capital investments										9	32	21
Restructuring charges										2		3
Gain on sale of assets, net										35
Midstream Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										(2,434)	(2,100)	(1,568)
Other [Member]
Segment Reporting Information [Line Items]
Impairments										1
Operating income (loss)										(1)	(1)
Loss on early extinguishment of debt										(17)	(70)	(51)
Other income (loss), net												(2)
Assets		386				$ 1,124				386	1,124	1,567
Capital investments										8	13	4
Cash and cash equivalents		$ 201								201
Marketing [Member] | Midstream Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										2,300	1,900	1,300
Workforce Reduction [Member]
Segment Reporting Information [Line Items]
Restructuring charges										23		73
Workforce Reduction [Member] | Exploration and Production [Member]
Segment Reporting Information [Line Items]
Restructuring charges										21		70
Workforce Reduction [Member] | Midstream Services [Member]
Segment Reporting Information [Line Items]
Restructuring charges										2		3
Marketing [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										1,222	972	864
Marketing [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										$ (2,275)	$ (1,895)	$ (1,327)

Condensed Consolidating Finan_3

Condensed Consolidating Financial Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018
Condensed Consolidating Financial Information [Abstract]
Subsidiary ownership	100.00%

Condensed Consolidating Finan_4

Condensed Consolidating Financial Information (Condensed Consolidating Statement of Operations) (Details) - USD ($) $ in Millions	Apr. 26, 2018	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Condensed Income Statements, Captions [Line Items]
Operating Revenues		$ 1,175	$ 951	$ 816	$ 920	$ 809	$ 737	$ 811	$ 846					$ 3,862	$ 3,203		$ 2,436
Operating expenses														785	671		592
General and administrative expenses														209	233		247
Restructuring charges														39			73
Depreciation, depletion and amortization														560	504		436
Impairments														171			2,321
Gain on sale of assets, net														(17)	(6)
Taxes, other than income taxes														89	94		93
Total Operating Costs and Expenses														3,065	2,472		4,626
Operating Income (Loss)		352	66	124	255	167	110	188	266					797	731		(2,190)
Interest Expense, Net														124	135		88
Gain (Loss) on Derivatives														(118)	422		(339)
Loss on Early Extinguishment of Debt	$ (8)													(17)	(70)		(51)
Other Income (Loss), Net															5		(4)
Income (Loss) Before Income Taxes														538	953		(2,672)
Provision (benefit) for income taxes														1	(93)		(29)
Net Income (Loss)		307	(29)	51	208	334	77	284	351	$ (210)	$ (708)	$ (593)	$ (1,132)	537	1,046	[1]	(2,643)
Mandatory convertible preferred stock dividend															108		108
Participating securities - mandatory convertible preferred stock														2	123
Net Income (Loss) Attributable to Common Stock		307	(29)	51	205	267	43	224	281					535	815		(2,751)
Other comprehensive income (loss)		4	4			(7)	1	1			2	3	4	8	(5)		9
Comprehensive income (loss)		$ 311	$ (25)	$ 51	$ 208	$ 327	$ 78	$ 285	$ 351	$ (210)	$ (706)	$ (590)	$ (1,128)	545	1,041	[1]	(2,634)
Eliminations [Member]
Condensed Income Statements, Captions [Line Items]
Equity in Earnings of Subsidiaries														(678)	(1,251)		2,559
Income (Loss) Before Income Taxes														(678)	(1,251)		2,559
Net Income (Loss)														(678)	(1,251)		2,559
Net Income (Loss) Attributable to Common Stock														(678)	(1,251)		2,559
Other comprehensive income (loss)															(12)		(6)
Comprehensive income (loss)														(678)	(1,263)		2,553
Parent [Member]
Condensed Income Statements, Captions [Line Items]
Interest Expense, Net														124	135		88
Loss on Early Extinguishment of Debt														(17)	(70)		(51)
Equity in Earnings of Subsidiaries														678	1,251		(2,504)
Income (Loss) Before Income Taxes														537	1,046		(2,643)
Net Income (Loss)														537	1,046		(2,643)
Mandatory convertible preferred stock dividend															108		108
Participating securities - mandatory convertible preferred stock														2	123
Net Income (Loss) Attributable to Common Stock														535	815		(2,751)
Other comprehensive income (loss)														8	(5)		9
Comprehensive income (loss)														545	1,041		(2,634)
Guarantors [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														3,862	3,203		2,436
Operating expenses														785	671		592
General and administrative expenses														209	233		247
Restructuring charges														39			73
Depreciation, depletion and amortization														560	504		436
Impairments														171			2,266
Gain on sale of assets, net														(17)	(6)
Taxes, other than income taxes														89	94		93
Total Operating Costs and Expenses														3,065	2,472		4,571
Operating Income (Loss)														797	731		(2,135)
Gain (Loss) on Derivatives														(118)	422		(339)
Other Income (Loss), Net															5		(4)
Equity in Earnings of Subsidiaries																	(55)
Income (Loss) Before Income Taxes														679	1,158		(2,533)
Provision (benefit) for income taxes														1	(93)		(29)
Net Income (Loss)														678	1,251		(2,504)
Net Income (Loss) Attributable to Common Stock														678	1,251		(2,504)
Other comprehensive income (loss)															6		3
Comprehensive income (loss)														678	1,257		(2,501)
Non-Guarantors [Member]
Condensed Income Statements, Captions [Line Items]
Impairments																	55
Total Operating Costs and Expenses																	55
Operating Income (Loss)																	(55)
Income (Loss) Before Income Taxes																	(55)
Net Income (Loss)																	(55)
Net Income (Loss) Attributable to Common Stock																	(55)
Other comprehensive income (loss)															6		3
Comprehensive income (loss)															6		(52)
Gas Sales [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														1,998	1,793		1,273
Gas Sales [Member] | Guarantors [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														1,998	1,793		1,273
Oil Sales [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														196	102		69
Oil Sales [Member] | Guarantors [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														196	102		69
NGL Sales [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														352	206		92
NGL Sales [Member] | Guarantors [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														352	206		92
Marketing [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														1,222	972		864
Marketing [Member] | Guarantors [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														1,222	972		864
Gas Gathering [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														89	126		138
Gas Gathering [Member] | Guarantors [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														89	126		138
Other [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														5	4
Other [Member] | Guarantors [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenues														5	4
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Condensed Income Statements, Captions [Line Items]
Marketing purchases														1,229	976		864
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | Guarantors [Member]
Condensed Income Statements, Captions [Line Items]
Marketing purchases														$ 1,229	$ 976		$ 864
[1]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Condensed Consolidating Finan_5

Condensed Consolidating Financial Information (Condensed Consolidating Balance Sheets) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	$ 201				$ 916				$ 1,423				$ 15
Accounts receivable, net	581				428
Other current assets	174				165
Total current assets	956				1,509
Natural gas and oil properties, using the full cost method	24,180				23,890
Gathering systems	38				1,315
Other	487				564
Less: Accumulated depreciation, depletion and amortization	(20,049)				(19,997)
Total property and equipment, net	4,656				5,772
Other long-term assets	185				240
TOTAL ASSETS	5,797				7,521				7,076
Accounts payable	609				533
Other current liabilities	237				247
Total current liabilities	846				780
Long-term debt	2,318				4,391
Pension and other postretirement liabilities	46				58
Other long-term liabilities	225				313
Total long-term liabilities	2,589				4,762
Commitments and contingencies
Total equity	2,362	$ 2,205	$ 2,250	$ 2,193	1,979	$ 1,652	$ 1,573	$ 1,278	917	$ 1,123	$ 573	$ 1,148	2,282
TOTAL LIABILITIES AND EQUITY	5,797				7,521
Eliminations [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Intercompany receivables	(7,932)				(7,978)
Investments in subsidiaries (equity method)	(24)				(24)
TOTAL ASSETS	(7,956)				(8,002)
Intercompany payables	(7,932)				(7,978)
Negative carrying amount of subsidiaries, net	(3,199)				(2,367)
Total long-term liabilities	(3,199)				(2,367)
Total equity	3,175				2,343
TOTAL LIABILITIES AND EQUITY	(7,956)				(8,002)
Parent [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	201				914				1,416				4
Accounts receivable, net	4
Other current assets	8				10
Total current assets	213				924
Intercompany receivables	7,932				7,978
Other	197				207
Less: Accumulated depreciation, depletion and amortization	(154)				(134)
Total property and equipment, net	43				73
Other long-term assets	19				16
TOTAL ASSETS	8,207				8,991
Accounts payable	113				73
Other current liabilities	115				110
Total current liabilities	228				183
Long-term debt	2,318				4,391
Pension and other postretirement liabilities	46				58
Other long-term liabilities	54				13
Negative carrying amount of subsidiaries, net	3,199				2,367
Total long-term liabilities	5,617				6,829
Total equity	2,362				1,979
TOTAL LIABILITIES AND EQUITY	8,207				8,991
Guarantors [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents					2				$ 7				$ 11
Accounts receivable, net	577				428
Other current assets	166				155
Total current assets	743				585
Natural gas and oil properties, using the full cost method	24,128				23,834
Gathering systems	11				1,288
Other	290				357
Less: Accumulated depreciation, depletion and amortization	(19,840)				(19,804)
Total property and equipment, net	4,589				5,675
Investments in subsidiaries (equity method)	24				24
Other long-term assets	166				224
TOTAL ASSETS	5,522				6,508
Accounts payable	496				460
Other current liabilities	122				137
Total current liabilities	618				597
Intercompany payables	7,932				7,978
Other long-term liabilities	171				300
Total long-term liabilities	171				300
Total equity	(3,199)				(2,367)
TOTAL LIABILITIES AND EQUITY	5,522				6,508
Non-Guarantors [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Natural gas and oil properties, using the full cost method	52				56
Gathering systems	27				27
Less: Accumulated depreciation, depletion and amortization	(55)				(59)
Total property and equipment, net	24				24
TOTAL ASSETS	24				24
Total equity	24				24
TOTAL LIABILITIES AND EQUITY	$ 24				$ 24

Condensed Consolidating Finan_6

Condensed Consolidating Financial Information (Condensed Consolidating Statements of Cash Flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 1,223	$ 1,097	$ 498
Capital investments	(1,290)	(1,268)	(593)
Proceeds from sale of property and equipment	1,643	10	430
Other	6	6	1
Net cash provided by (used in) investing activities	359	(1,252)	(162)
Payments on short-term debt		(328)
Payments on long-term debt	(2,095)	(1,139)	(1,175)
Payments on revolving credit facility	(1,983)		(3,268)
Borrowings under revolving credit facility	1,983		3,152
Payments on commercial paper			(242)
Borrowings under commercial paper			242
Proceeds from issuance of long-term debt		1,150	1,191
Proceeds from issuance of common stock			1,247
Purchase of treasury stock	(180)
Preferred stock dividend	(27)	(16)	(27)
Other	5	(19)	(48)
Net cash (used in) provided by financing activities	(2,297)	(352)	1,072
Increase (decrease) in cash and cash equivalents	(715)	(507)	1,408
Cash and cash equivalents at beginning of year	916	1,423	15
Cash and cash equivalents at end of year	201	916	1,423
Parent [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	304	1,019	(2,610)
Capital investments	(20)	(13)	(3)
Proceeds from sale of property and equipment		1	2
Other		1	1
Net cash provided by (used in) investing activities	(20)	(11)
Intercompany activities	1,300	(1,158)	2,950
Payments on short-term debt		(328)
Payments on long-term debt	(2,095)	(1,139)	(1,175)
Payments on revolving credit facility	(1,983)		(3,268)
Borrowings under revolving credit facility	1,983		3,152
Payments on commercial paper			(242)
Borrowings under commercial paper			242
Proceeds from issuance of long-term debt		1,150	1,191
Proceeds from issuance of common stock			1,247
Purchase of treasury stock	(180)
Preferred stock dividend	(27)	(16)	(27)
Other	5	(19)	(48)
Net cash (used in) provided by financing activities	(997)	(1,510)	4,022
Increase (decrease) in cash and cash equivalents	(713)	(502)	1,412
Cash and cash equivalents at beginning of year	914	1,416	4
Cash and cash equivalents at end of year	201	914	1,416
Guarantors [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	1,595	1,327	550
Capital investments	(1,270)	(1,250)	(590)
Proceeds from sale of property and equipment	1,643	9	428
Other	6	5
Net cash provided by (used in) investing activities	379	(1,236)	(162)
Intercompany activities	(1,976)	(96)	(392)
Net cash (used in) provided by financing activities	(1,976)	(96)	(392)
Increase (decrease) in cash and cash equivalents	(2)	(5)	(4)
Cash and cash equivalents at beginning of year	2	7	11
Cash and cash equivalents at end of year		2	7
Non-Guarantors [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Capital investments		(5)
Net cash provided by (used in) investing activities		(5)
Intercompany activities		5
Net cash (used in) provided by financing activities		5
Eliminations [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(676)	(1,249)	2,558
Intercompany activities	676	1,249	(2,558)
Net cash (used in) provided by financing activities	$ 676	$ 1,249	$ (2,558)

Supplemental Quarterly Result_2

Supplemental Quarterly Results (Schedule of Quarterly Financial Inform) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Quarterly Results [Abstract]
Operating Revenues	$ 1,175	$ 951	$ 816	$ 920	$ 809	$ 737	$ 811	$ 846	$ 3,862	$ 3,203	$ 2,436
Operating income	352	66	124	255	167	110	188	266	797	731	(2,190)
Net income (loss) attributable to common stock	$ 307	$ (29)	$ 51	$ 205	$ 267	$ 43	$ 224	$ 281	$ 535	$ 815	$ (2,751)
Earnings (loss) per share: -Basic	$ 0.54	$ (0.05)	$ 0.09	$ 0.36	$ 0.53	$ 0.09	$ 0.45	$ 0.57	$ 0.93	$ 1.64	$ (6.32)
Earnings (loss) per share - Diluted	$ 0.54	$ (0.05)	$ 0.09	$ 0.36	$ 0.53	$ 0.09	$ 0.45	$ 0.57	$ 0.93	$ 1.63	$ (6.32)

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures (Narrative) (Details) $ in Millions, ft³ in Billions	12 Months Ended			144 Months Ended	180 Months Ended
	Dec. 31, 2018USD ($)siteft³	Dec. 31, 2017USD ($)siteft³	Dec. 31, 2016USD ($)siteft³	Dec. 31, 2015USD ($)ft³	Dec. 31, 2018USD ($)siteft³
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization	$ 168	$ 138	$ 46	$ 1,403	$ 1,755
Impairments	171		2,321
Capitalized interest based on weighted average cost of borrowings	115	113	152
Capitalized internal costs related to acquisition, exploration and development	$ 90	$ 99	$ 87
Percentage of present worth of proved reserves evaluated in audit	99.00%	99.00%	99.00%
Proved developed and undeveloped reserves | ft³	11,921	14,775	5,253	6,215	11,921
Natural gas, oil and NGL reserves discount	10.00%
Undeveloped Properties Southwest Appalachia [Member]
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization	$ 1,500
Undeveloped Properties Northeast Appalachia [Member]
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization	23
Undeveloped Properties Outside the Appalachian Basin [Member]
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization	11
Wells In Progress [Member]
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization	77
Capitalized interest based on weighted average cost of borrowings	$ 184
Undeveloped Properties, Various Locations [Member]
Natural Gas and Oil Properties [Line Items]
Proved undeveloped reserves | ft³	190	1,375	77		190
Number of locations | site	30	330	15		30
Natural gas, oil and NGL reserves discount	10.00%	10.00%	10.00%
Present value of proved reserves, discounted basis	$ 24	$ 124	$ 11		$ 24
Proved reserves, committed development period	5 years

Supplemental Oil and Gas Disc_4

Supplemental Oil and Gas Disclosures (Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Supplemental Oil and Gas Disclosures [Abstract]
Proved properties	$ 22,425	$ 22,073
Unproved properties	1,755	1,817
Total capitalized costs	24,180	23,890
Less: Accumulated depreciation, depletion and amortization	(19,761)	(19,287)
Net capitalized costs	$ 4,419	$ 4,603

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures (Composition of Net Unevaluated Costs Excluded from Amortization) (Details) - USD ($) $ in Millions	12 Months Ended			144 Months Ended	180 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2018
Supplemental Oil and Gas Disclosures [Abstract]
Property acquisition costs	$ 49	$ 70	$ 12	$ 1,346	$ 1,477
Exploration and development costs	42	23	6	23	94
Capitalized interest	77	45	28	34	184
Net unevaluated costs excluded from amortization	$ 168	$ 138	$ 46	$ 1,403	$ 1,755

Supplemental Oil and Gas Disc_6

Supplemental Oil and Gas Disclosures (Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)$ / Mcf	Dec. 31, 2017USD ($)$ / Mcf	Dec. 31, 2016USD ($)$ / Mcf
Supplemental Oil and Gas Disclosures [Abstract]
Unproved property acquisition costs	$ 164	$ 194	$ 171
Exploration costs	5	22	17
Development costs	1,014	1,024	433
Capitalized costs incurred	$ 1,183	$ 1,240	$ 621
Full cost pool amortization per Mcfe | $ / Mcf	0.51	0.45	0.38

Supplemental Oil and Gas Disc_7

Supplemental Oil and Gas Disclosures (Results of Operations for Oil and Gas Producing Activities Disclosure) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Sales	$ 2,525	$ 2,086	$ 1,413
Production (lifting) costs	(974)	(891)	(839)
Depreciation, depletion and amortization	(514)	(440)	(371)
Impairment of natural gas and oil properties			(2,321)
Results of operations - income before income taxes	1,037	755	(2,118)
Provision (benefit) for income taxes
Results of operations	1,037	755	(2,118)
Prior to Recognition of Valuation Allowance [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Provision (benefit) for income taxes	$ 254	$ 287	$ 805

Supplemental Oil and Gas Disc_8

Supplemental Oil and Gas Disclosures (Summary of Changes in Reserves - United States) (Details) ft³ in Billions	12 Months Ended
	Dec. 31, 2018MBblsft³	Dec. 31, 2017MBblsft³	Dec. 31, 2016MBblsft³
Reserve Quantities [Line Items]
Proved reserves, beginning of year	14,775	5,253	6,215
Revisions of previous estimates	526	2,332	(354)
Extensions, discoveries and other additions	1,009	8,087	282
Production	(946)	(897)	(875)
Disposition of reserves in place	(3,443)		(15)
Proved reserves, end of year	11,921	14,775	5,253
United States [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	14,775	5,253	6,215
Extensions, discoveries and other additions	1,009	8,087	282
Production	(946)	(897)	(875)
Disposition of reserves in place	(3,443)		(15)
Proved reserves, end of year	11,921	14,775	5,253
Proved developed reserves:
Proved developed reserves	5,557	7,920	5,176
Proved undeveloped reserves:
Proved undeveloped reserves	6,364	6,855	77
United States [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	11,126	4,866	5,917
Extensions, discoveries and other additions	753	5,159	198
Production	(807)	(797)	(788)
Disposition of reserves in place	(3,440)		(15)
Proved reserves, end of year	8,044	11,126	4,866
Proved developed reserves:
Proved developed reserves	4,395	6,979	4,789
Proved undeveloped reserves:
Proved undeveloped reserves	3,649	4,147	77
United States [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year | MBbls	65,636	10,523	8,753
Extensions, discoveries and other additions | MBbls	5,830	55,772	2,417
Production | MBbls	(3,407)	(2,327)	(2,192)
Disposition of reserves in place | MBbls	(250)		(19)
Proved reserves, end of year | MBbls	69,007	65,636	10,523
Proved developed reserves:
Proved developed reserves | MBbls	18,037	14,513	10,523
Proved undeveloped reserves:
Proved undeveloped reserves | MBbls	50,970	51,123
United States [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year | MBbls	542,455	53,931	40,947
Extensions, discoveries and other additions | MBbls	36,823	432,220	11,576
Production | MBbls	(19,706)	(14,245)	(12,372)
Disposition of reserves in place | MBbls	(276)		(14)
Proved reserves, end of year | MBbls	577,063	542,455	53,931
Proved developed reserves:
Proved developed reserves | MBbls	175,480	142,213	53,931
Proved undeveloped reserves:
Proved undeveloped reserves | MBbls	401,583	400,242
Price Revision [Member] | United States [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	154	1,691	(1,037)
Price Revision [Member] | United States [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	96	1,327	(983)
Price Revision [Member] | United States [Member] | Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	788	3,197	(582)
Price Revision [Member] | United States [Member] | NGL [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	8,912	57,447	(8,337)
Other than Price [Member] | United States [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	372	641	683
Other than Price [Member] | United States [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	316	571	537
Other than Price [Member] | United States [Member] | Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	410	(1,529)	2,146
Other than Price [Member] | United States [Member] | NGL [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	8,855	13,102	22,131

Supplemental Oil and Gas Disc_9

Supplemental Oil and Gas Disclosures (Summary of Changes in Reserves) (Details) - ft³ ft³ in Billions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reserve Quantities [Line Items]
Proved reserves, beginning of year	14,775	5,253	6,215
Price revisions	154	1,691	(1,037)
Performance and production revisions	372	641	683
Total net revisions	526	2,332	(354)
Proved developed	177	1,258	257
Proved undeveloped	832	6,829	25
Total reserve additions	1,009	8,087	282
Production	(946)	(897)	(875)
Disposition of reserves in place	(3,443)		(15)
Proved reserves, end of year	11,921	14,775	5,253
Northeast Appalachia [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	4,126	1,574	2,319
Price revisions	41	903	(794)
Performance and production revisions	107	154	318
Total net revisions	148	1,057	(476)
Proved developed	154	790	81
Proved undeveloped	397	1,100
Total reserve additions	551	1,890	81
Production	(459)	(395)	(350)
Proved reserves, end of year	4,366	4,126	1,574
Southwest Appalachia [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	6,962	677	611
Price revisions	106	738	(127)
Performance and production revisions	272	125	199
Total net revisions	378	863	72
Proved developed	22	419	157
Proved undeveloped	435	5,186
Total reserve additions	457	5,605	157
Production	(243)	(183)	(148)
Disposition of reserves in place			(15)
Proved reserves, end of year	7,554	6,962	677
Fayetteville Shale [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	3,679	2,997	3,281
Price revisions	6	49	(116)
Performance and production revisions	(6)	358	163
Total net revisions		407	47
Proved developed	1	48	19
Proved undeveloped		543	25
Total reserve additions	1	591	44
Production	(243)	(316)	(375)
Disposition of reserves in place	(3,437)
Proved reserves, end of year		3,679	2,997
Other Property [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	8	5	4
Price revisions	1	1
Performance and production revisions	(1)	4	3
Total net revisions		5	3
Proved developed		1
Total reserve additions		1
Production	(1)	(3)	(2)
Disposition of reserves in place	(6)
Proved reserves, end of year	1	8	5

Supplemental Oil and Gas Dis_10

Supplemental Oil and Gas Disclosures (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Oil and Gas Disclosures [Abstract]
Future cash inflows	$ 34,523	$ 36,576	$ 9,064
Future production costs	(15,347)	(18,390)	(5,880)
Future development costs	(4,095)	(4,676)	(485)
Future income tax expense	(2,079)	(1,342)
Future net cash flows	13,002	12,168	2,699
10% annual discount for estimated timing of cash flows	(7,003)	(6,606)	(1,034)
Standardized measure of discounted future net cash flows	$ 5,999	$ 5,562	$ 1,665	$ 2,417

Supplemental Oil and Gas Dis_11

Supplemental Oil and Gas Disclosures (Schedule of Prices Used for Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Natural Gas [Member]
Reserve Quantities [Line Items]
Full cost ceiling test, price per MMBtu	$ 3.10	$ 2.98	$ 2.48
Oil [Member]
Reserve Quantities [Line Items]
Full cost ceiling test, price per barrel	65.56	47.79	39.25
NGL [Member]
Reserve Quantities [Line Items]
Full cost ceiling test, price per barrel	$ 17.64	$ 14.41	$ 6.74

Supplemental Oil and Gas Dis_12

Supplemental Oil and Gas Disclosures (Schedule of Analysis of Changes in Standardized Measure) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Oil and Gas Disclosures [Abstract]
Standardized measure, beginning of year	$ 5,562	$ 1,665	$ 2,417
Sales and transfers of natural gas and oil produced, net of production costs	(1,564)	(1,191)	(574)
Net changes in prices and production costs	2,162	1,963	(415)
Extensions, discoveries, and other additions, net of future production and development costs	335	1,715	45
Sales of reserves in place	(2,022)		(10)
Revisions of previous quantity estimates	361	1,721	(140)
Net change in income taxes	(304)	(222)
Changes in estimated future development costs	(166)	(6)	71
Previously estimated development costs incurred during the year	536	55	114
Changes in production rates (timing) and other	521	(304)	(85)
Accretion of discount	578	166	242
Standardized measure, end of year	$ 5,999	$ 5,562	$ 1,665