Southwestern Energy (SWN) 10-K 27 Feb 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 25, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-08246
Entity Registrant Name	Southwestern Energy Co
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	71-0205415
Entity Address, Address Line One	10000 Energy Drive
Entity Address, City or Town	Spring
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77389
City Area Code	832
Local Phone Number	796-1000
Title of 12(b) Security	Common Stock, Par Value $0.01
Trading Symbol	SWN
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 1,703,566,444
Entity Common Stock, Shares Outstanding		541,057,922
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0000007332
Current Fiscal Year End Date	--12-31
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement to be filed with respect to the annual meeting of stockholders to be held on or about May 19, 2020 are incorporated by reference into Part III of this Form 10-K.

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Operating Revenues:
Operating Revenues	$ 3,038	$ 3,862		$ 3,203
Operating Costs and Expenses:
Operating expenses	720	785		671
General and administrative expenses	166	209		233
(Gain) loss on sale of operating assets, net	2	(17)		(6)
Restructuring charges	11	39		0
Depreciation, depletion and amortization	471	560		504
Impairments	16	171		0
Taxes, other than income taxes	62	89		94
Total Operating Costs and Expenses	2,768	3,065		2,472
Operating Income	270	797		731
Interest Expense:
Interest on debt	166	231		239
Other interest charges	8	8		9
Interest capitalized	(109)	(115)		(113)
Total Interest Expense	65	124		135
Gain (Loss) on Derivatives	274	(118)		422
Gain (Loss) on Early Extinguishment of Debt	8	(17)		(70)
Other Income (Loss), Net	(7)	0		5
Income (Loss) Before Income Taxes	480	538		953
Provision (Benefit) for Income Taxes:
Current	(2)	1		(22)
Deferred	(409)	0		(71)
Provision (benefit) for income taxes	(411)	1		(93)
Net Income (Loss)	891	537	[1]	1,046	[1]
Mandatory convertible preferred stock dividend	0	0		108
Participating securities - mandatory convertible preferred stock	0	2		123
Net Income (Loss) Attributable to Common Stock	$ 891	$ 535		$ 815
Earnings Per Common Share
Basic (in dollars per share)	$ 1.65	$ 0.93		$ 1.64
Diluted (in dollars per share)	$ 1.65	$ 0.93		$ 1.63
Weighted Average Common Shares Outstanding:
Basic (in shares)	539,345,343	574,631,756		498,264,321
Diluted (in shares)	540,382,914	576,642,808		500,804,297
Gas sales
Operating Revenues:
Operating Revenues	$ 1,241	$ 1,998		$ 1,793
Oil sales
Operating Revenues:
Operating Revenues	223	196		102
NGL sales
Operating Revenues:
Operating Revenues	274	352		206
Marketing
Operating Revenues:
Operating Revenues	1,297	1,222		972
Gas gathering
Operating Revenues:
Operating Revenues	0	89		126
Other
Operating Revenues:
Operating Revenues	3	5		4
Marketing purchases
Operating Costs and Expenses:
Marketing purchases	$ 1,320	$ 1,229		$ 976
[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, 2019		Dec. 31, 2018	[1]	Dec. 31, 2017	[1]
Statement of Comprehensive Income [Abstract]
Net income	$ 891		$ 537		$ 1,046
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss, including loss on settlements and curtailments included in net periodic pension cost	8	[2]	10		2
Net actuarial loss incurred in period	(5)	[3]	(2)		(13)
Total change in value of pension and postretirement liabilities	3		8		(11)
Change in currency translation adjustment	0		0		6
Comprehensive income	$ 894		$ 545		$ 1,041
[1]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.
[2]	Net of $2 million in taxes for the year ended December 31, 2019.
[3]	Net of ($1) million in taxes for the year ended December 31, 2019.

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Statement of Comprehensive Income [Abstract]
Amortization of prior service cost and net loss included in net periodic pension cost, tax	$ 2
Net gain (loss) incurred in period, tax	$ (1)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 5	$ 201
Accounts receivable, net	345	581
Derivative assets	278	130
Other current assets	51	44
Total current assets	679	956
Natural gas and oil properties, using the full cost method, including $1,506 million as of December 31, 2019 and $1,755 million as of December 31, 2018 excluded from amortization	25,250	24,180
Other	520	525
Less: Accumulated depreciation, depletion and amortization	(20,503)	(20,049)
Total property and equipment, net	5,267	4,656
Operating lease assets	159
Deferred tax assets	407	0
Other long-term assets	205	185
Total long-term assets	771	185
TOTAL ASSETS	6,717	5,797
Current liabilities:
Accounts payable	525	609
Taxes payable	59	58
Interest payable	51	52
Derivative liabilities	125	79
Current operating lease liabilities	34
Other current liabilities	54	48
Total current liabilities	848	846
Long-term debt	2,242	2,318
Long-term operating lease liabilities	119
Pension and other postretirement liabilities	43	46
Other long-term liabilities	219	225
Total long-term liabilities	2,623	2,589
Commitments and contingencies (Note 10)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 585,555,923 shares as of December 31, 2019 and 585,407,107 as of December 31, 2018	6	6
Additional paid-in capital	4,726	4,715
Accumulated deficit	(1,251)	(2,142)
Accumulated other comprehensive loss	(33)	(36)
Common stock in treasury, 44,353,224 shares as of December 31, 2019 and 39,092,537 shares as of December 31, 2018	(202)	(181)
Total equity	3,246	2,362
TOTAL LIABILITIES AND EQUITY	$ 6,717	$ 5,797

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Net unevaluated costs excluded from amortization, cumulative	$ 1,506	$ 1,755
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,250,000,000	1,250,000,000
Common stock, shares issued (in shares)	585,555,923	585,407,107
Treasury stock, shares (in shares)	44,353,224	39,092,537

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Cash Flows From Operating Activities:
Net income	$ 891	$ 537	[1]	$ 1,046	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	471	560		504
Amortization of debt issuance costs	8	8		9
Impairments	16	171		0
Deferred income taxes	(409)	0		(71)
(Gain) loss on derivatives, unsettled	(94)	24		(451)
Stock-based compensation	8	14		24
Gain (Loss) on Extinguishment of Debt	(8)	17		70
(Gain) loss on sale of operating assets, net	2	(17)		(6)
Other	10	(1)		13
Change in assets and liabilities:
Accounts receivable	234	(153)		(65)
Accounts payable	(141)	65		48
Taxes payable	0	2		4
Interest payable	0	(10)		(2)
Inventories	(7)	(13)		(1)
Other assets and liabilities	(17)	19		(25)
Net cash provided by operating activities	964	1,223		1,097
Cash Flows From Investing Activities:
Capital investments	(1,099)	(1,290)		(1,268)
Proceeds from sale of property and equipment	54	1,643		10
Other	0	6		6
Net cash provided by (used in) investing activities	(1,045)	359		(1,252)
Cash Flows From Financing Activities:
Payments on current portion of long-term debt	(52)	0		(328)
Payments on long-term debt	(54)	(2,095)		(1,139)
Payments on revolving credit facility	(532)	(1,983)		0
Borrowings under revolving credit facility	566	1,983		0
Change in bank drafts outstanding	(19)	17		9
Proceeds from issuance of long-term debt	0	0		1,150
Debt issuance costs	(3)	(9)		(24)
Purchase of treasury stock	(21)	(180)		0
Preferred stock dividend	0	(27)		(16)
Cash paid for tax withholding	(1)	(3)		(2)
Other	1	0		(2)
Net cash used in financing activities	(115)	(2,297)		(352)
Decrease in cash and cash equivalents	(196)	(715)		(507)
Cash and cash equivalents at beginning of year	201	916		1,423
Cash and cash equivalents at end of year	$ 5	$ 201		$ 916
[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		Total		Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit	[1]	Accumulated Other Comprehensive Income (Loss)	Common Stock in Treasury
Beginning balance (in shares) at Dec. 31, 2016				495,248,369	1,725,000					31,269
Beginning balance at Dec. 31, 2016		$ 917		$ 5		$ 4,677	$ (3,725)		$ (39)	$ (1)
Comprehensive income:
Net income		1,046	[2]				1,046
Other comprehensive loss		(5)							(5)
Comprehensive income	[2]	1,041
Stock-based compensation		38				38
Preferred stock dividend (in shares)				12,791,716
Preferred stock dividend		(16)				(16)
Issuance of restricted stock (in shares)				5,055,208
Cancellation of restricted stock (in shares)				(742,028)
Performance units vested (in shares)				121,208
Issuance of common stock (in shares)				72
Tax withholding - stock compensation (in shares)				(340,234)
Tax withholding - stock compensation		(1)				(1)
Ending balance (in shares) at Dec. 31, 2017				512,134,311	1,725,000					31,269
Ending balance at Dec. 31, 2017		1,979		$ 5		4,698	(2,679)		(44)	$ (1)
Comprehensive income:
Net income		537	[2]				537
Other comprehensive loss		8							8
Comprehensive income	[2]	545
Stock-based compensation		$ 21				21
Conversion of preferred stock (in shares)				74,998,614	(1,725,000)
Conversion of preferred stock				$ 1		(1)
Issuance of restricted stock (in shares)				349,562
Cancellation of restricted stock (in shares)				(1,804,122)
Treasury stock (in shares)		39,061,268								39,061,268
Treasury stock		$ (180)								$ (180)
Performance units vested (in shares)				214,866
Tax withholding - stock compensation (in shares)				(486,124)
Tax withholding - stock compensation		(3)				(3)
Ending balance (in shares) at Dec. 31, 2018				585,407,107	0					39,092,537
Ending balance at Dec. 31, 2018		2,362		$ 6		4,715	(2,142)		(36)	$ (181)
Comprehensive income:
Net income		891					891
Other comprehensive loss		3							3
Comprehensive income		894
Stock-based compensation		$ 12				12
Issuance of restricted stock (in shares)				236,978
Cancellation of restricted stock (in shares)				(239,571)
Treasury stock (in shares)		5,260,687								5,260,687
Treasury stock		$ (21)								$ (21)
Performance units vested (in shares)				535,802
Tax withholding - stock compensation (in shares)				(384,393)
Tax withholding - stock compensation		(1)				(1)
Ending balance (in shares) at Dec. 31, 2019				585,555,923	0					44,353,224
Ending balance at Dec. 31, 2019		$ 3,246		$ 6		$ 4,726	$ (1,251)		$ (33)	$ (202)
[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 2016-9 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	Jan. 01, 2018USD ($)
Accounting Standards Update 2016-09
Net cumulative-effect adjustment	$ 59

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Summary of Significant Accounting Policies	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 NGLs exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business (“Marketing”), which was previously referred to as “Midstream” when it included the operations of gathering systems. Southwestern conducts most of its business through subsidiaries and operates principally in two segments: E&P and Marketing. The Company’s historical financial and operating results include its Fayetteville Shale E&P and related midstream gathering businesses, which were sold in early December 2018 (“the Fayetteville Shale sale”). The sale is discussed in further detail in Note 3 . 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 “Appalachia.” The Company also operates drilling rigs located in Pennsylvania and West Virginia, and provides oilfield products and services, principally serving the Company's E&P operations through vertical integration. Marketing. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in its E&P operations. 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. 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 that 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 minority partner’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, 2019, 2018 and 2017 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. In 2019, no single customer accounted for 10% or greater of total sales. 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. 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, 2019, and December 31, 2018: (in millions) December 31, 2019 December 31, 2018 Cash $ 5 $ 32 Marketable securities (1) — 169 Total $ 5 $ 201 (1) Consists of government stable value money market funds. 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 $15 million and $34 million as of December 31, 2019 and 2018, 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 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, 2019, the Company had a total of $1,506 million 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 non-cash ceiling test impairments. At December 31, 2019, using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.58 per MMBtu, West Texas Intermediate oil of $55.69 per barrel and NGLs of $11.58 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties was $218 million below the ceiling amount and therefore did not result in a ceiling test impairment at December 31, 2019. Given the fall in commodity prices in 2019 and early 2020, the Company expects some non-cash impairment of its assets will likely occur as early as the first quarter of 2020. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2019. 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 results 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. 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 . Natural gas and oil properties require expenditures to plug and abandon the wells and reclaim the associated pads and other supporting infrastructure when the wells are no longer producing. An asset retirement obligation associated with the retirement of a tangible long-lived asset such as oil and gas properties 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 Company’s non-full cost pool assets include water facilities, gathering systems, technology infrastructure, land, buildings and other equipment with useful lives that range from 3 to 30 years. 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. Should an impairment exist, the impairment loss would be measured as the amount that the asset’s carrying value exceeds its fair value. For the year ended December 31, 2019, the Company recognized non-cash impairments of $16 million for non-core assets. 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, a non-cash 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 non-cash 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. At December 31, 2019 and 2018, the Company had $56 million and $65 million, respectively, in marketing-related intangible assets that were included in Other long-term assets on the consolidated balance sheets. The Company amortized $9 million of its marketing-related intangible asset in each of the years ended December 31, 2019, 2018 and 2017, and expects to amortize $9 million in 2020, $8 million in 2021 and $5 million for the three years thereafter. 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 the Tax Reform Act can be found in Note 1 1 . 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 6 and Note 8 for a discussion of the Company’s hedging activities. Earnings Per Share Basic earnings per common share is computed by dividing net income (loss) attributable to 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 resulting from the conversion, exercise, or contingent issuance of certain securities. 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. In January 2018, all outstanding shares of mandatory convertible preferred stock were converted to 74,998,614 shares of the Company’s common stock. The Company paid its last dividend payment of approximately $27 million associated with the depositary shares in January 2018. 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 part of the Company’s share repurchase program, the Company paid approximately $180 million to repurchase 39,061,268 shares of its outstanding common stock in 2018 and paid approximately $21 million to repurchase 5,260,687 shares in 2019, which are included in the Company's treasury stock. The following table presents the computation of earnings per share for the years ended December 31, 2019, 2018 and 2017:  For the years ended December 31, (in millions, except share/per share amounts) 2019 2018 2017 Net income $ 891 $ 537 $ 1,046 Mandatory convertible preferred stock dividend — — 108 Participating securities – mandatory convertible preferred stock — 2 123 Net income attributable to common stock $ 891 $ 535 $ 815  Number of common shares: Weighted average outstanding 539,345,343 574,631,756 498,264,321 Issued upon assumed exercise of outstanding stock options — — — Effect of issuance of non-vested restricted common stock 361,380 698,103 1,061,056 Effect of issuance of non-vested performance units 676,191 1,312,949 1,478,920 Weighted average and potential dilutive outstanding 540,382,914 576,642,808 500,804,297  Earnings per common share: Basic $ 1.65 $ 0.93 $ 1.64 Diluted $ 1.65 $ 0.93 $ 1.63 The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2019, 2018 and 2017, as they would have had an antidilutive effect:  For the years ended December 31,  2019 2018 2017 Unexercised stock options 5,078,253 5,909,082 116,717 Unvested share-based payment 1,728,264 3,692,794 5,361,849 Performance units 271,268 642,568 765,689 Mandatory convertible preferred stock — 2,465,708 74,999,895 Total 7,077,785 12,710,152 81,244,150 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, 2019, 2018 and 2017:  For the years ended December 31, (in millions) 2019 2018 2017 Cash paid during the year for interest, net of amounts capitalized $ 58 $ 135 $ 130 Cash paid (received) during the year for income taxes (52) 6 (5) Increase (decrease) in noncash property additions 41 (42) 25 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 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 1 4 for a discussion of the Company’s stock-based compensation. Liability-Classified Awards The Company classifies certain awards that can or will be settled in cash as liability 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 that were granted in 2018 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 Company’s liability-classified performance unit awards that were granted in 2019 include a performance condition based on the return of average capital employed and the same two market conditions as in the 2018 awards. The fair values of the two market conditions are calculated by Monte Carlo models on a quarterly basis. See Note 14 for a discussion of the Company’s stock-based compensation. 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. At December 31, 2018, approximately $180 million had been spent to repurchase 39,061,268 shares at an average price of $4.63 per share. In the first quarter of 2019, the Company completed its share repurchase program by purchasing 5,260,687 shares of its outstanding common stock for approximately $21 million at an average price of $3.84 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, 2019 and 2018, 5,115 shares and 10,653 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 February 2016, the FASB issued Accounting Standards Update No. 2016-2, Leases (Topic 842) (“Update 2016-2”), 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. For public entities, Update 2016-02 became effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted Accounting Standards Codification (“ASC”) 842 with an effective date of January 1, 2019 using the modified retrospective approach for all leases that existed at the date of initial application. The Company elected to apply the transition as of the beginning of the period of adoption. For leases that existed at the period of adoption on January 1, 2019, the incremental borrowing rate as of the adoption date was used to calculate the present value of remaining lease payments. Upon adoption of ASC 842, the Company recognized a discounted right-of-use asset and corresponding lease liability with opening balances of approximately $105 million as of January 1, 2019. The adoption of the standard did not materially change the Company's consolidated statement of operations or its consolidated statement of cash flows. Please refer to Note 4 for additional disclosure. New Accounting Standards Not Yet Adopted in this Report In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“Update 2016-13”). Update 2016-13 replaces the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. For public business entities, the new standard is effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. From an evaluation of the Company’s existing credit portfolio, which includes trade receivables from commodity sales, joint interest billings due from partners, other receivables and cash equivalents, historical credit losses have been de minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of our business partners. As anticipated, the CECL model did not have a significant impact on Southwestern's consolidated financial statements or related control environment upon adoption on January 1, 2020.

Restructuring Charges

Restructuring Charges	12 Months Ended
	Dec. 31, 2019
Restructuring and Related Activities [Abstract]
Restructuring Charges	RESTRUCTURING CHARGES As part of an ongoing strategic effort to reposition its portfolio, optimize operational performance and improve margins, the Company has incurred charges related to restructuring that include reductions in workforce, office consolidation and other costs, including those associated with the sale of a large asset such as the Fayetteville Shale. These charges are further discussed below. The following table presents a summary of the restructuring charges included in Operating Income for the years ended December 31, 2019, 2018 and 2017: For the years ended December 31, (in millions) 2019 2018 (1) 2017 Reduction in workforce (not Fayetteville Shale sale-related) $ — $ 23 $ — Fayetteville Shale sale-related 11 16 — Total restructuring charges $ 11 $ 39 $ — (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. The following table presents a summary of liabilities associated with the Company’s restructuring activities at December 31, 2019, which are reflected in accounts payable on the consolidated balance sheet: ໿ (in millions) Liability at December 31, 2018 $ 5 Additions 11 Distributions (14) Liability at December 31, 2019 $ 2 Reduction in Workforce (Not Fayetteville Shale Sale-Related) 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. The following table presents a summary of the restructuring charges related to workforce reduction plans included in Operating Income (Loss) for the year ended December 31, 2018:  For the year ended December 31, (in millions) 2018 Severance (including payroll taxes) $ 21 Stock-based compensation — Other benefits — Outplacement services, other 2 Total reduction in workforce-related restructuring charges (1) $ 23 (1) Total restructuring charges for the Company's E&P and Marketing segments were $21 million and $2 million, respectively, for the year ended December 31, 2018. 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 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. As of December 31, 2019, the Company has substantially completed the Fayetteville Shale sale-related employment terminations. As a result of the Fayetteville Shale sale, the Company relocated certain employees and infrastructure to other locations and began the process of consolidating and reorganizing its office space. These charges related to office consolidation and reorganization have been recognized as restructuring charges. In July 2019, the Company terminated its existing lease agreement in its headquarters office building and entered into a new 10-year lease agreement for a smaller portion of the building. Approximately $3 million of the fees associated with the Company’s headquarters office consolidation are reflected as restructuring charges for the year ended December 31, 2019. The Company also recognized additional severance costs in the third and fourth quarters of 2019, related to continued organizational restructuring, for which a liability of $2 million has been accrued as of December 31, 2019. The following table presents a summary of the restructuring charges related to the consolidation and reorganization associated with the Fayetteville Shale sale included in Operating Income on the condensed statements of operations for the years ended December 31, 2019 and 2018: For the years ended December 31, (in millions) 2019 2018 Severance (including payroll taxes) $ 5 $ 12 Office consolidation 6 4 Total Fayetteville Shale sale-related charges (1) (2) $ 11 $ 16 (1) Total restructuring charges were $11 million and $16 million for the Company’s E&P segment for the years ended December 31, 2019 and 2018, respectively. (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, 2019
Discontinued Operations and Disposal Groups [Abstract]
Divestitures	DIVESTITURES In August 2018, the Company entered into an agreement with Flywheel Energy Operating, LLC to sell 100% of the equity in the Company’s 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, with an economic effective date of July 1, 2018. In December 2018, the Company closed the Fayetteville Shale sale and received approximately $1,650 million, which included 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. As 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 certain natural gas derivative positions that 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 positions 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 (gain) loss on sale of operating assets, net. In addition, the Company paid $22 million in premiums for these novated derivatives which was recorded as a loss in (gain) loss on sale of operating assets, net in 2018. The 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, 2019, approximately $108 million of these contractual commitments remain, of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $58 million through 2020 depending on the buyer’s actual use. At December 31, 2019, the Company has recorded a $46 million liability for the estimated future payments. In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of the carrying value or fair value less costs to sell. Because the assets outside the full cost pool included in the Fayetteville Shale sale met the criteria for held for sale accounting as of September 30, 2018, the Company determined the carrying value of certain non-full cost pool assets exceeded the fair value less costs to sell. As a result, a non-cash impairment charge of $161 million was recorded in the third quarter of 2018, of which $145 million related to midstream gathering assets held for sale and $15 million related to E&P assets held for sale. Additionally, the Company recorded a $1 million non-cash impairment related to other non-core assets that were not included in the sale. 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 in December 2018. In addition, $201 million, including approximately $1 million in commissions, was used to repurchase approximately 44 million shares of the Company's outstanding common stock, including $21 million in the first quarter of 2019. The Company earmarked the remaining net proceeds from the sale to supplement 2019 and 2020 Appalachia development and for general corporate purposes. Pending these other uses, a portion of these remaining net proceeds has been used to repay revolving credit facility borrowings until investments are made.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	LEASES 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. For public entities, Update 2016-02 became effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted ASC 842 with an effective date of January 1, 2019 using the modified retrospective approach for all leases that existed at the date of initial adoption. The Company elected to apply the transition as of the beginning of the period of adoption. For leases that existed at the period of adoption on January 1, 2019, the incremental borrowing rate as of the adoption date was used to calculate the present value of remaining lease payments. The standard provides optional practical expedients to ease the burden of transition. The Company has adopted the following practical expedients through implementation: • an election not to apply the recognition requirements in the leases standard to short-term leases and recognize lease payments in the consolidated statement of operations (a lease that at commencement date has an initial term of 12 months or less and does not contain a purchase option that the Company is reasonably certain to exercise); • a package of practical expedients to not reassess: whether a contract is or contains a lease, lease classification and initial direct costs; • a practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset class); • a practical expedient to not reassess certain land easements in existence prior to January 1, 2019; and • an election to adopt the modified retrospective approach for all leases existing at or entered into after the initial date of adoption which does not require a restatement of prior period. No cumulative-effect adjustment to retained earnings was required as a result of the modified retrospective approach. Upon adoption of ASC 842, the Company recognized a discounted right-of-use asset and corresponding lease liability with opening balances of approximately $105 million as of January 1, 2019. The adoption of the standard did not materially change the Company’s consolidated statement of operations or its consolidated statement of cash flows. The Company determines if a contract contains a lease at inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration. A right-of-use asset and corresponding lease liability are recognized on the balance sheet at commencement at an amount based on the present value of the remaining lease payments over the lease term. As the implicit rate of the lease is not always readily determinable, the Company uses the incremental borrowing rate to calculate the present value of the lease payments based on information available at commencement date, such as the initial lease term. Operating right-of-use assets and operating lease liabilities are presented separately on the consolidated balance sheet. The Company does not have any finance leases as of December 31, 2019. By policy election, leases with an initial term of twelve months or less are not recorded on the balance sheet. The Company recognizes lease expense for these leases on a straight-line basis, and variable lease payments are recognized in the period as incurred. Certain leases contain both lease and non-lease components. The Company has chosen to account for most of these leases as a single lease component instead of bifurcating lease and non-lease components. However, for compression service leases and fleet vehicle leases, the lease and non-lease components are accounted for separately. The Company leases drilling rigs, pressure pumping equipment, vehicles, office space, certain water transportation lines, an aircraft and other equipment under non-cancelable operating leases expiring through 2032. Certain lease agreements include options to renew the lease, early terminate the lease or purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. The Company’s water transportation lines are the only leases with renewal options that are reasonably certain to be exercised. These renewal options are reflected in the right-of-use asset and lease liability balances. In July 2019, the Company terminated its existing lease agreement and entered into a new ten The components of lease costs are shown below: For the year ended (in millions) December 31, 2019 Operating lease cost $ 45 Short-term lease cost 45 Variable lease cost 1 Total lease cost $ 91 As of December 31, 2019, the Company has operating leases of $15 million, related primarily to compressor and information technology leases, that have been executed but not yet commenced. These operating leases are planned to commence during 2020 with lease terms expiring through 2030. The Company’s existing operating leases do not contain any material restrictive covenants. Supplemental cash flow information related to leases is set forth below: For the year ended (in millions) December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 47 Right-of-use assets obtained in exchange for operating liabilities: Operating leases $ 95 Supplemental balance sheet information related to leases is as follows: (in millions) December 31, 2019 Right-of-use asset balance: Operating leases $ 159 Lease liability balance: Current operating leases $ 34 Long-term operating leases 119 Total operating leases $ 153 Weighted average remaining lease term: (years) Operating leases 6.6 Weighted average discount rate: Operating leases 5.33 % Maturity analysis of operating lease liabilities: (in millions) December 31, 2019 2020 $ 41 2021 33 2022 22 2023 19 2024 15 Thereafter 52 Total undiscounted lease liability 182 Imputed interest (29) Total discounted lease liability $ 153 Undiscounted maturities of operating leases accounted for under ASC 840: (in millions) December 31, 2018 2019 $ 38 2020 28 2021 14 2022 6 2023 5 Thereafter 4 Total minimum payments required $ 95

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue Recognition	REVENUE RECOGNITIONEffective January 1, 2018, the Company adopted 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 resulted 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 the Company. 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 in December 2018, the Company, through its midstream gathering affiliate, gathered natural gas 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 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. 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: (in millions) E&P Marketing Intersegment Total Year ended December 31, 2019 Gas sales $ 1,207 $ — $ 34 $ 1,241 Oil sales 220 — 3 223 NGL sales 274 — — 274 Marketing — 2,849 (1,552) 1,297 Other (1) 2 1 — 3 Total $ 1,703 $ 2,850 $ (1,515) $ 3,038  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 (2) — 248 (159) 89 Other (1) 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 (2) — 331 (205) 126 Other (1) 4 — — 4 Total $ 2,086 $ 3,198 $ (2,081) $ 3,203 (1) Other E&P revenues consists primarily of water sales to third-party operators and other marketing revenues consists primarily of sales of gas from storage. (2) The Company’s gas gathering assets were divested in December 2018 as part of the Fayetteville Shale sale. Associated E&P revenues are also disaggregated for analysis on a geographic basis by the core areas in which the Company operates, which are primarily in Pennsylvania and West Virginia. In December 2018, the Company sold 100% of its Fayetteville Shale assets. For the years ended December 31, (in millions) 2019 2018 2017 Northeast Appalachia $ 964 $ 1,165 $ 837 Southwest Appalachia 736 817 498 Fayetteville Shale — 537 743 Other 3 6 8 Total $ 1,703 $ 2,525 $ 2,086 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, 2019 December 31, 2018 Receivables from contracts with customers $ 284 $ 494 Other accounts receivable 61 87 Total accounts receivable $ 345 $ 581

Derivatives and Risk Management

Derivatives and Risk Management	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives and Risk Management	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, 2019, 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. 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. As part of the Fayetteville Shale sale agreement, the Company entered into certain natural gas derivative positions that were subsequently novated to the buyer in conjunction with finalization of the sale. The derivatives that were novated to the buyer are not included in the tables below. The following tables provide 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 tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of December 31, 2019: Financial Protection on Production  Weighted Average Price per MMBtu Fair value at December 31, 2019 ($ in millions)  Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Natural Gas 2020 Fixed price swaps 280 $ 2.51 $ — $ — $ — $ — $ 76 (1) Two-way costless collars 31 — — 2.56 2.85 — 6 Three-way costless collars 185 — 2.28 2.65 3.00 — 42 Total 496 $ 124 2021 Fixed price swaps 30 $ 2.54 $ — $ — $ — $ — $ 7 Two-way costless collars 17 — — 2.50 2.83 — — Three-way costless collars 213 — 2.23 2.53 2.90 — — Total 260 $ 7 2022 Three-way costless collars 31 $ — $ 2.30 $ 2.69 $ 3.15 $ — $ 2  Basis swaps 2020 198 $ — $ — $ — $ — $ (0.31) $ — 2021 86 — — — — 0.04 7 2022 45 — — — — (0.50) (1) Total 329 $ 6 (1) Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statement of operations.  Weighted Average Price per Bbl Fair value at December 31, 2019 ($ in millions)  Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Oil 2020 Fixed price swaps 3,465 $ 57.83 $ — $ — $ — $ (2) Two-way costless collars 966 — — 56.89 59.81 — Three-way costless collars 971 — 45.12 55.12 59.68 (1) Total 5,402 $ (3) 2021 Fixed price swaps 1,584 $ 53.20 $ — $ — $ — $ (1) Three-way costless collars 1,445 — 43.52 53.25 58.14 (1) Total 3,029 $ (2) 2022 Fixed price swaps 438 $ 51.74 $ — $ — $ — $ —  Propane 2020 Fixed price swaps 4,746 $ 23.90 $ — $ — $ — $ 21 Two-way costless collars 366 — — 25.20 29.40 2 Total 5,112 $ 23 2021 Fixed price swaps 2,460 $ 21.77 $ — $ — — $ 3  Ethane 2020 Fixed price swaps 7,520 $ 8.84 $ — $ — $ — $ 11 2021 Fixed price swaps 2,410 $ 7.53 $ — $ — $ — $ — Other Derivative Contracts  Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2019 ($ in millions) Purchased Call Options – Natural Gas 2020 104 $ 3.46 $ 1 2021 57 3.52 2 Total 161 $ 3  Sold Call Options – Natural Gas 2020 173 $ 3.24 $ (3) 2021 115 3.33 (6) 2022 58 3.00 (5) 2023 6 3.00 (1) 2024 9 3.00 (3) Total 361 $ (18) Volume (MBbls) Weighted Average Strike Price per Bbl Fair value at December 31, 2019 ($ in millions) Sold Call Options – Oil 2021 — $ 60.00 $ (1) Weighted Average Strike Price per MMBtu Fair value at December 31, 2019 ($ in millions) Natural Gas Storage (1) Volume (Bcf) Swaps Basis Differential 2020 Purchased fixed price swap — $ 2.37 $ — $ — Purchased basis swap — — (0.32) — Sold fixed price swap 1 3.06 — 1 Sold basis swap — — (0.32) — Total 1 $ 1 (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. Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2019 ($ in millions) Purchased Fixed Price Swaps – Marketing (Natural Gas) (1) 2020 7 $ 2.44 $ (1) 2021 6 2.44 — Total 13 $ (1) (1) The Company has entered into a limited number of derivatives to protect the value of certain long-term sales contracts. At December 31, 2019, the net fair value of the Company’s financial instruments related to commodities was a $155 million asset. As of December 31, 2019, 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. 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 are summarized below as of December 31, 2019 and 2018: Derivative Assets  Balance Sheet Classification Fair Value (in millions) December 31, 2019 December 31, 2018 Derivatives not designated as hedging instruments: Fixed price swap – natural gas Derivative assets $ 77 (1) $ 32 Fixed price swap – oil Derivative assets 4 13 Fixed price swap – propane Derivative assets 21 11 Fixed price swap – ethane Derivative assets 11 7 Two-way costless collar – natural gas Derivative assets 10 11 Two-way costless collar – oil Derivative assets 5 6 Two-way costless collar – propane Derivative assets 2 — Three-way costless collar – natural gas Derivative assets 126 41 Three-way costless collar – oil Derivative assets 3 — Basis swap – natural gas Derivative assets 17 8 Purchased call option – natural gas Derivative assets 1 — Fixed price swap – natural gas storage Derivative assets 1 — Interest rate swap Derivative assets — 1 Fixed price swap – natural gas Other long-term assets 7 6 Fixed price swap – oil Other long-term assets 1 6 Fixed price swap – propane Other long-term assets 3 — Fixed price swap – ethane Other long-term assets — 1 Two-way costless collar – natural gas Other long-term assets 4 — Two-way costless collar – oil Other long-term assets — 5 Three-way costless collar – natural gas Other long-term assets 74 34 Three-way costless collar – oil Other long-term assets 7 — Basis swap – natural gas Other long-term assets 15 3 Purchased call options – natural gas Other long-term assets 2 6 Total derivative assets $ 391 $ 191 (1) Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations. Derivative Liabilities  Balance Sheet Classification Fair Value (in millions) December 31, 2019 December 31, 2018 Derivatives not designated as hedging instruments: Purchased fixed price swap – natural gas Derivative liabilities $ 1 $ — Purchased fixed price swap – oil Derivative liabilities — 6 Fixed price swap – natural gas Derivative liabilities 1 9 Fixed price swap – oil Derivative liabilities 6 — Fixed price swap – ethane Derivative liabilities — 3 Two-way costless collar – natural gas Derivative liabilities 4 7 Two-way costless collar – oil Derivative liabilities 5 — Three-way costless collar – natural gas Derivative liabilities 84 33 Three-way costless collar – oil Derivative liabilities 4 — Basis swap – natural gas Derivative liabilities 17 18 Sold call option – natural gas Derivative liabilities 3 3 Fixed price swap – natural gas Other long-term liabilities — 1 Fixed price swap – oil Other long-term liabilities 2 — Two-way costless collar – natural gas Other long-term liabilities 4 — Two-way costless collar – oil Other long-term liabilities — 1 Three-way costless collar – natural gas Other long-term liabilities 72 35 Three-way costless collar – oil Other long-term liabilities 8 — Basis swap – natural gas Other long-term liabilities 9 4 Sold call option – natural gas Other long-term liabilities 15 19 Sold call option – oil Other long-term liabilities 1 — Total derivative liabilities $ 236 $ 139 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, 2019 and 2018: Unsettled Gain (Loss) on Derivatives Recognized in Earnings  Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled For the years ended Derivative Instrument 2019 2018  (in millions) Purchased fixed price swap – natural gas Gain (Loss) on Derivatives $ (1) $ — Purchased fixed price swap – oil Gain (Loss) on Derivatives 6 (6) Fixed price swap – natural gas Gain (Loss) on Derivatives 46 (27) Fixed price swap – oil Gain (Loss) on Derivatives (22) 19 Fixed price swap – propane Gain (Loss) on Derivatives 13 11 Fixed price swap – ethane Gain (Loss) on Derivatives 6 5 Two-way costless collar – natural gas Gain (Loss) on Derivatives 2 — Two-way costless collar – oil Gain (Loss) on Derivatives (10) 10 Two-way costless collar – propane Gain (Loss) on Derivatives 2 — Three-way costless collar – natural gas Gain (Loss) on Derivatives 37 (48) Three-way costless collar – oil Gain (Loss) on Derivatives (2) — Basis swap – natural gas Gain (Loss) on Derivatives 17 10 Purchased call option – natural gas Gain (Loss) on Derivatives (3) 4 Sold call option – natural gas Gain (Loss) on Derivatives 4 (4) Sold call option – oil Gain (Loss) on Derivatives (1) — Fixed price swap – natural gas storage Gain (Loss) on Derivatives 1 — Interest rate swap Gain (Loss) on Derivatives (1) 2 Total gain (loss) on unsettled derivatives $ 94 $ (24)  Settled Gain (Loss) on Derivatives Recognized in Earnings (1)  Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled For the years ended Derivative Instrument 2019 2018  (in millions) Purchased fixed price swap – oil Gain (Loss) on Derivatives $ (3) $ — Fixed price swap – natural gas Gain (Loss) on Derivatives 78 (32) Fixed price swap – oil Gain (Loss) on Derivatives 10 — Fixed price swap – propane Gain (Loss) on Derivatives 29 (6) Fixed price swap – ethane Gain (Loss) on Derivatives 17 (8) Two-way costless collar – natural gas Gain (Loss) on Derivatives 16 (1) Two-way costless collar – oil Gain (Loss) on Derivatives 6 — Two-way costless collar – propane Gain (Loss) on Derivatives 2 — Three-way costless collar – natural gas Gain (Loss) on Derivatives 31 (9) Basis swap – natural gas Gain (Loss) on Derivatives (3) (31) Purchased call option – natural gas Gain (Loss) on Derivatives (1) (2) 2 (2) Sold call option – natural gas Gain (Loss) on Derivatives (1) (7) Sold call option – oil Gain (Loss) on Derivatives — (2) Purchased fixed price swap – natural gas storage Gain (Loss) on Derivatives (1) — Total gain (loss) on settled derivatives $ 180 $ (94)  Total gain (loss) on derivatives $ 274 $ (118) (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 purchased call options for each of the years ended December 31, 2019 and 2018, which is included in gain (loss) on derivatives on the consolidated statement of operations.

Reclassifications from Accumula

Reclassifications from Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Reclassifications from Accumulated Other Comprehensive Income (Loss)	RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) In 2019, changes in AOCI primarily related to settlements in the Company's pension and other postretirement benefits. The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects, for the year ended December 31, 2019:  For the year ended December 31, 2019 (in millions) Pension and Other Postretirement Foreign Currency Total Beginning balance, December 31, 2018 $ (22) $ (14) $ (36) Other comprehensive loss before reclassifications (5) — (5) Amounts reclassified from other comprehensive income (1) 8 — 8 Net current-period other comprehensive income 3 — 3 Ending balance, December 31, 2019 $ (19) $ (14) $ (33) (1) 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, 2019 Pension and other postretirement: (in millions) Amortization of prior service cost and net loss (1) Other Income, Net $ 10  Provision for income taxes (2)  Net income $ 8  Total reclassifications for the period Net income $ 8 (1) See Note 1 3 for additional details regarding the Company’s pension and other postretirement benefit plans.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	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, 2019 and 2018 were as follows:  December 31, 2019 December 31, 2018 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents $ 5 $ 5 $ 201 $ 201 2018 revolving credit facility due April 2024 (1) 34 34 — — Senior notes (2) 2,228 2,085 2,342 2,190 Derivative instruments, net 155 (3) 155 (3) 52 52 (1) In October 2019, the Company amended its 2018 revolving credit facility agreement which, among other things, extended the maturity from 2023 to 2024. (2) Excludes unamortized debt issuance costs and debt discounts. (3) Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet. 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 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 certain senior notes were updated to a Level 1 in the second quarter of 2018 as the market activity for a portion of the Company’s debt resulted in timely quoted prices. In 2019, the 4.10% Senior Notes due March 2022 were reclassified as a Level 2 measurement due to relative market inactivity. The 4.05% Senior Notes due January 2020, which were classified as a Level 2 measurement at December 31, 2018, were retired in December 2019. The carrying value of the borrowings under the Company’s revolving credit facility (to the extent utilized) approximates 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 Company has classified its derivatives into the fair value hierarchy 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 New York Mercantile Exchange (“NYMEX”) futures index for natural gas and oil derivatives and Oil Price Information Service (“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, 2019 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative contracts expire in June 2020. 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, 2019  Fair Value Measurements Using: (in millions) Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs (Level 3) Assets (Liabilities) at Fair Value Assets Fixed price swap – natural gas (1) $ — $ 84 $ — $ 84 Fixed price swap – oil — 5 — 5 Fixed price swap – propane — 24 — 24 Fixed price swap – ethane — 11 — 11 Two-way costless collar – natural gas — 14 — 14 Two-way costless collar – oil — 5 — 5 Two-way costless collar – propane — 2 — 2 Three-way costless collar – natural gas — 200 — 200 Three-way costless collar – oil — 10 — 10 Basis swap – natural gas — 32 — 32 Purchased call option – natural gas — 3 — 3 Fixed price swap – natural gas storage — 1 — 1 Liabilities Purchased fixed price swap – natural gas — (1) — (1) Fixed price swap – natural gas — (1) — (1) Fixed price swap – oil — (8) — (8) Two-way costless collar – natural gas — (8) — (8) Two-way costless collar – oil — (5) — (5) Three-way costless collar – natural gas — (156) — (156) Three-way costless collar – oil — (12) — (12) Basis swap – natural gas — (26) — (26) Sold call option – natural gas — (18) — (18) Sold call option – oil — (1) — (1) Total $ — $ 155 $ — $ 155 (1) Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statement of operations.  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 swaps – 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 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, 2019 and 2018. The fair values of Level 3 derivative instruments were 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, 2019 and 2018. 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.  For the years ended December 31, (in millions) 2019 2018 Balance at beginning of year $ — $ 22 Total gains (losses): Included in earnings — (17) Settlements (1) — 1 Transfers into/out of Level 3 (2) — (6) Balance at end of period $ — $ — Change in gains (losses) included in earnings relating to derivatives still held as of December 31 $ — $ — (1) Includes $1 million for amortization of premiums paid related to certain natural gas purchased call options for the year ended December 31, 2018. (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 1 3 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 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. Because the assets outside of the full cost pool included in the Fayetteville Shale sale met the criteria for held for sale accounting in the third quarter of 2018, the Company determined the carrying value of certain non-full cost pool assets exceeded the fair value less costs to sell. As a result, the Company recorded a non-cash

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	DEBT The components of debt as of December 31, 2019 and 2018 consisted of the following:  December 31, 2019 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Total Long-term debt: Variable rate (4.310% at December 31, 2019) 2018 revolving credit facility, due April 2024 $ 34 $ — (1) $ — $ 34 4.10% Senior Notes due March 2022 213 (1) — 212 4.95% Senior Notes due January 2025 (2) 892 (5) (1) 886 7.50% Senior Notes due April 2026 639 (7) — 632 7.75% Senior Notes due October 2027 484 (6) — 478 Total long-term debt $ 2,262 $ (19) $ (1) $ 2,242  December 31, 2018 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total Long-term debt: Variable rate (3.920% at December 31, 2018) 2018 term loan facility, due April 2023 $ — $ — (1) $ — $ — 4.05% Senior Notes due January 2020 (2) 52 — — 52 4.10% Senior Notes due March 2022 213 (1) — 212 4.95% Senior Notes due January 2025 (2) 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 long-term debt $ 2,342 $ (23) $ (1) $ 2,318 (1) At December 31, 2019 and 2018, unamortized issuance expense of $11 million associated with the 2018 revolving credit facility was classified as other long-term assets on the consolidated balance sheet. (2) In February and June 2016, Moody’s and S&P downgraded certain senior notes, increasing 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. S&P and Moody’s upgraded certain senior 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 the bondholders at the lower interest rate was paid in January 2019. The following is a summary of scheduled debt maturities by year as of December 31, 2019: (in millions) 2020 $ — 2021 — 2022 213 2023 — 2024 (1) 34 Thereafter 2,015  $ 2,262 (1) The Company’s current revolving credit facility matures in 2024. Credit Facilities 2016 Credit Facility In June 2016, the Company reduced its $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 2018 credit facility agreement in April 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. 2018 Credit Facility In April 2018, the Company replaced its credit facility entered into in 2016 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 with a current aggregate commitment of $2.0 billion and borrowing base (limit on availability) that is redetermined at least each April and October. The 2018 credit facility is secured by substantially all of the assets owned by the Company and its subsidiaries. The permitted lien provisions in the senior notes indentures currently limit liens securing indebtedness to the greater of $2.0 billion and 25% of adjusted consolidated net tangible assets. On October 8, 2019, the Company entered into an amendment to the 2018 credit facility that, among other things, established the October 2019 borrowing base at $2.1 billion and extended the maturity date to April 2024. 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 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 greater 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. As of December 31, 2019, the Company was in compliance with all of the covenants of the 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 its 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 1 6 for the Company’s Condensed Consolidated Financial Information, presented in accordance with Rule 3-10 of Regulation S-X. As of December 31, 2019, the Company had $172 million in letters of credit and $34 million in borrowings outstanding under the 2018 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, increasing 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 were 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 subsequently 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 was paid in January 2019. As discussed in Note 3 above, in December 2018, the Company closed 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. In the second half of 2019, the Company repurchased $35 million of its 4.95% senior notes due 2025, $11 million of its 7.50% Senior Notes due 2026 and $16 million of its 7.75% Senior Notes due 2027 at a discount for $54 million, and recognized an $8 million gain on extinguishment of debt. Additionally, in December 2019, the Company retired the remaining $52 million principal of its 4.05% Senior Notes due January 2020.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Operating Commitments and Contingencies As of December 31, 2019, 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 $8.5 billion, $1.1 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 $293 million of that amount. As of December 31, 2019, 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 $ 7,414 $ 767 $ 1,200 $ 1,066 $ 1,531 $ 2,850 Pending regulatory approval and/or construction (1) 1,056 1 35 103 208 709 Total transportation charges $ 8,470 $ 768 $ 1,235 $ 1,169 $ 1,739 $ 3,559 (1) Based on the estimated in-service dates as of December 31, 2019. In December 2018, the Company closed on the Fayetteville Shale sale and 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, 2019, approximately $108 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $58 million through December 2020 depending on the buyer’s actual use, and has recorded a $46 million liability for the estimated future payments, reduced from $88 million at December 31, 2018. 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 is approximately $6 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 office space, vehicles and equipment under non-cancelable operating leases expiring through 2029. As of December 31, 2019, future minimum payments under these non-cancelable leases accounted for as operating leases (including short-term) are approximately $33 million in 2020, $24 million in 2021, $18 million in 2022, $16 million in 2023, $12 million in 2024 and $45 million thereafter. The Company also has commitments for compression services and compression rentals related to its E&P segment. As of December 31, 2019, future minimum payments under these non-cancelable agreements (including short-term obligations) are approximately $13 million in 2020, $13 million in 2021, $9 million in 2022 and $2 million in 2023. In the first quarter of 2019, 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, which is presented in the table above; the seller has agreed to reimburse $133 million of these commitments. In February 2020, the Company was notified that the proposed Constitution pipeline project was cancelled and that the Company was released from a firm transportation agreement with its sponsor. As of December 31, 2019, the Company had contractual commitments totaling $512 million over the next seventeen Environmental Risk The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position, results of operations or cash flows of the Company. Litigation The Company is subject to various litigation, claims and proceedings, most of which 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 litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of December 31, 2019, the Company does not currently have any material amounts accrued related to litigation matters. For any matters not accrued for, 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 was 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. In 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 comprised 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. On April 23, 2019, the Court of Appeals affirmed the trial court’s order denying all requests to intervene in the case, and, in a separate order, affirmed the trial court’s judgment in favor of the Company on all claims. The Court of Appeals subsequently denied all requests for rehearing. In 2018, the company entered into an agreement to settle another of the class actions, which was 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 and the deadline to appeal the order approving the settlement passed without any appeals filed. The amount of the settlement was reflected in the Company’s consolidated statement of operations for 2018 and has been paid. The third class action was also dismissed in 2018. As of December 31, 2019, some actions filed on behalf of mineral interest owners who opted out of the class actions mentioned above remain pending. 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. St. Lucie County Fire District Firefighters’ Pension Trust On October 17, 2016, the St. Lucie County Fire District Firefighters’ Pension Trust filed a putative class action in the 61st District Court in Harris County, Texas, against the Company, certain of its former officers and current and former directors and the underwriters on behalf of itself and others that purchased certain depositary shares from the Company’s January 2015 equity offering, alleging material misstatements and omissions in the registration statement for that offering. The Company removed the case to federal court, but after a decision by the United States Supreme Court in an unrelated case that these types of cases are not subject to removal, the federal court remanded the case to the Texas state court. The Texas trial court denied the Company’s motion to dismiss, and in February 2020, the court of appeals declined to exercise discretion to reverse the trial court’s decision. The Company carries insurance for the claims asserted against it and the officer and director defendants, and the carrier has accepted coverage. The Company denies all allegations and intend to continue to defend this case vigorously. The Company does not expect this case 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 has provided certain indemnifications to various third parties, including in relation to asset and entity dispositions, securities offerings and other financings, such as the St. Lucie County Fire District Firefighters’ Pension Trust case described above. In the case of asset dispositions, 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. In the case of equity offerings, these indemnifications typically relate to claims asserted against underwriters in connection with an offering. No material liabilities have been recognized in connection with these indemnifications.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES The provision (benefit) for income taxes included the following components: (in millions) 2019 2018 2017 Current: Federal $ (1) $ (5) $ (22) State (1) 6 —  (2) 1 (22) Deferred: Federal (431) — (71) State 22 — —  (409) — (71) Provision (benefit) for income taxes $ (411) $ 1 $ (93) The provision for income taxes was an effective rate of (86)% in 2019, 0% in 2018 and (10)% in 2017. The Company’s effective tax rate decreased in 2019, as compared with 2018, primarily due to the release of a valuation allowance in 2019. 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) 2019 2018 2017 Expected provision at federal statutory rate $ 101 $ 113 $ 333 Decrease resulting from: State income taxes, net of federal income tax effect 11 13 16 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) Change in valuation allowance (522) (121) (364) Removal of sequestration fee on AMT receivables — (5) — Other (1) 1 (5) Provision (benefit) for income taxes $ (411) $ 1 $ (93) The 2019 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, 2019 and 2018 were as follows: (in millions) 2019 2018 Deferred tax liabilities: Differences between book and tax basis of property $ 312 $ 226 Derivative activity 34 12 Right of use lease asset 37 — Other 2 2  385 240 Deferred tax assets: Accrued compensation 33 33 Accrued pension costs 9 10 Asset retirement obligations 13 15 Net operating loss carryforward 769 777 Future lease payments 37 — Other 18 14  879 849 Valuation allowance (87) (609) Net deferred tax asset $ 407 $ — The Tax Reform Act 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. The adjustments required to deferred taxes as a result of the Tax Reform Act have been reflected in the Company’s tax provision. 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 $30 million in refundable credits remaining that are expected to be fully refunded by 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 2019, the Company received refunds related to state income tax of $1.0 million. In 2018, the Company paid $6.3 million in state income tax. The Company’s net operating loss carryforward as of December 31, 2019 was $3.0 billion and $2.3 billion for federal and state reporting purposes, respectively, the majority of which will expire between 2035 and 2039. 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 million and $29 million related to interest deduction carryforward as of December 31, 2019. 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 assets will not be realized. To assess that 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. For the years ended December 31, 2018 and 2017, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to non-cash impairments of proved natural gas and oil properties recognized in 2015 and 2016. As of the first quarter of 2019, the Company had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted taxable income, the Company concluded that it was more likely than not that the deferred tax assets would be realized and determined that $522 million of the valuation allowance would be released during 2019. Accordingly, a tax benefit of $522 million was recorded. As of December 31, 2019, the Company expects to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which it no longer operates. The Company is continually evaluating deferred tax asset realizability, and if pricing changes occur that would significantly affect the forecast, the Company will reconsider the need for a valuation allowance at such time. A reconciliation of the changes to the valuation allowance is as follows: (in millions) Valuation allowance as of December 31, 2018 $ 609 Release of valuation allowance in 2019 (522) Valuation allowance as of December 31, 2019 $ 87 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, 2019, there were no unrecognized tax positions identified that would have a material effect on the effective tax rate. All positions booked as of December 31, 2018 were released in 2019 due to audit completion and statute expirations. A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: (in millions) 2019 2018 Unrecognized tax benefits at beginning of year $ 7 $ 12 Additions based on tax positions related to the current year — — Additions to tax positions of prior years — — Reductions to tax positions of prior years (7) (5) Unrecognized tax benefits at end of year $ — $ 7 The Internal Revenue Service closed the 2014 audit of the Company’s federal return in 2019 with no change and is currently auditing the Company’s 2016 and 2017 tax periods. The income tax years 2016 to 2019 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, 2019
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS The following table summarizes the Company’s 2019 and 2018 activity related to asset retirement obligations: (in millions) 2019 2018 Asset retirement obligation at January 1 $ 61 $ 165 Accretion of discount 3 9 Obligations incurred 2 1 Obligations settled/removed (1) (9) (116) Revisions of estimates — 2 Asset retirement obligation at December 31 $ 57 $ 61  Current liability $ 6 $ 6 Long-term liability 51 55 Asset retirement obligation at December 31 $ 57 $ 61 (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, 2019
Retirement Benefits [Abstract]
Retirement and Employee Benefit Plans	RETIREMENT AND EMPLOYEE BENEFIT PLANS 401(k) Defined Contribution Plan The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $2 million, $3 million and $3 million of contribution expense in 2019, 2018 and 2017, respectively. Additionally, the Company capitalized $1 million of contributions in 2019 and $2 million in both 2018 and 2017, directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems. Defined Benefit Pension and Other Postretirement Plans Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible. The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages. Substantially all 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. In December 2018, the Company closed 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 for the year ended December 31, 2018. In 2019, the Company recognized a $6 million non-cash settlement loss related to $21 million of lump sum payments as a result of these restructuring events. The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status as of December 31, 2019 and 2018:  Pension Benefits Other Postretirement Benefits (in millions) 2019 2018 2019 2018 Change in benefit obligations: Benefit obligation at January 1 $ 125 $ 143 $ 13 $ 17 Service cost 7 10 1 2 Interest cost 5 5 — 1 Participant contributions — — — — Actuarial (gain) loss 15 (14) 1 — Benefits paid (2) (14) (2) (1) Plan amendments — — — — Curtailments — (5) — (6) Settlements (24) — — — Benefit obligation at December 31 $ 126 $ 125 $ 13 $ 13  Pension Benefits Other Postretirement Benefits (in millions) 2019 2018 2019 2018 Change in plan assets: Fair value of plan assets at January 1 $ 91 $ 101 $ — $ — Actual return on plan assets 16 (8) — — Employer contributions 12 12 2 1 Participant contributions — — — — Benefits paid (2) (14) (2) (1) Settlements (21) — — — Fair value of plan assets at December 31 $ 96 $ 91 $ — $ —  Funded status of plans at December 31 $ (30) $ (34) $ (13) $ (13) 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, 2019 and 2018 are as follows: (in millions) 2019 2018 Projected benefit obligation $ 126 $ 125 Accumulated benefit obligation 124 122 Fair value of plan assets 96 91 Pension and other postretirement benefit costs include the following components for 2019, 2018 and 2017:  Pension Benefits Other Postretirement Benefits (in millions) 2019 2018 2017 2019 2018 2017 Service cost $ 7 $ 10 $ 9 $ 1 $ 2 $ 2 Interest cost 5 5 5 — 1 — Expected return on plan assets (6) (7) (6) — — — Amortization of transition obligation — — — — — — Amortization of prior service cost — — — — — — Amortization of net loss 2 2 2 — — — Net periodic benefit cost 8 10 10 1 3 2 Curtailment gain — — — — (4) — Settlement loss 6 — — — — — Total benefit cost (benefit) $ 14 $ 10 $ 10 $ 1 $ (1) $ 2 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, 2019 and 2018 were as follows:  Pension Benefits Other Postretirement Benefits (in millions) 2019 2018 2019 2018 Net actuarial loss arising during the year $ (5) $ (2) $ (1) $ — Amortization of prior service cost — — — — Amortization of net loss 2 2 — — Settlements 8 — — — Curtailments — 5 — 3 Tax effect (1) (1) (1) — (1)  $ 4 $ 4 $ (1) $ 2 (1) For the year ended December 31, 2018, deferred tax activity related to pension and other postretirement benefits was offset by a valuation allowance, resulting in no tax expense presented on the consolidated statements of operations. Included in accumulated other comprehensive income as of December 31, 2019 and 2018 was a $30 million loss ($22 million net of tax) and a $34 million loss ($20 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2019, $3 million was classified from accumulated other comprehensive income, primarily driven by settlement losses. 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 2020 is a $1 million expense. The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2019 and 2018 are as follows:  Pension Benefits Other Postretirement Benefits  2019 2018 2019 2018 Discount rate 3.70 % 4.35 % 3.50 % 4.35 % 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 2019, 2018 and 2017 are as follows:  Pension Benefits Other Postretirement Benefits  2019 2018 2017 2019 2018 2017 Discount rate 3.70 % 4.35 % 4.20 % 4.35 % 4.35 % 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 2019 and 2018:  2019 2018 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 2037 2036 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 $ 2 $ (1) Effect on postretirement benefit obligations $ 2 $ (2) Pension Payments and Asset Management In 2019, the Company contributed $12 million to its pension plans and $2 million to its other postretirement benefit plan. The Company expects to contribute $13 million to its pension and other postretirement benefit plans in 2020. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Benefits Other Postretirement Benefits (in millions) 2020 $ 5 2020 $ 1 2021 5 2021 1 2022 6 2022 1 2023 6 2023 1 2024 7 2024 1 Years 2025-2029 34 Years 2025-2029 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, 2019, 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 % 34 % Non-U.S. equity (2) 35 % 33 % Fixed income (3) 28 % 31 % Cash (4) 2 % 2 % 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 fixed income pension plan assets in the table below. (4) Includes Cash and cash equivalent pension plan assets in the table below. Utilizing the fair value hierarchy described in Note 8 , the Company’s fair value measurement of pension plan assets as of December 31, 2019 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) $ 3 $ 3 $ — $ — U.S. large cap value equity (2) 6 6 — — U.S. small cap equity (3) 2 2 — — Non-U.S. equity (4) 32 32 — — Fixed income (6) 22 22 — — Cash and cash equivalents 2 2 — — Total measured within fair value hierarchy $ 67 $ 67 $ — $ — Measured at net asset value (8) Equity securities: U.S. large cap growth equity (9) 3 U.S. large cap core equity (10) 18 Fixed income (6) 8 Total measured at net asset value $ 29  Total plan assets at fair value $ 96 Note: Footnotes are located after the prior year comparative table below. Utilizing the fair value hierarchy described in Note 8 , the Company’s fair value measurement of pension plan assets at December 31, 2018 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) $ 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 (10) 12 Fixed income (6) 7 Total measured at net asset value $ 19  Total plan assets at fair value $ 91 (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) Included 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 invest in companies with sustainable competitive advantages, as identified through proprietary research. (10) 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, 2019
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation	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 and May 2019 (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 88,700,000 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 GAAP. The fair value of an equity-classified award is determined at the grant date and is amortized to general and administrative expense and capitalized 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 seven four three three three 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 the Fayetteville Shale sale. As part of this transaction, most employees associated with those assets became employees of the buyer although the employment of some was 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 years ended December 31, 2019 and 2018 on the consolidated statements of operations. Equity-Classified Awards Equity-Classified Stock Options The Company recorded the following compensation costs related to stock options for the years ended December 31, 2019, 2018 and 2017: (in millions) 2019 2018 2017 Stock options – general and administrative expense $ 1 $ 2 $ 3 Stock options – general and administrative expense capitalized $ — $ — $ 1 The Company also recorded a reduction in the deferred tax asset of less than $1 million related to stock options for the year ended December 31, 2019, compared to deferred tax assets of less than $1 million and $1 million for the years ended December 31, 2018 and 2017, respectively. Unrecognized compensation cost related to the Company’s unvested stock options totaled less than $1 million at December 31, 2019. This cost is expected to be recognized over a weighted-average period of less than one 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 2019 or 2018. Assumptions 2017 Risk-free interest rate 1.9 % Expected dividend yield — Expected volatility 50.5 % Expected term 5 years The following tables summarize stock option activity for the years 2019, 2018 and 2017, and provide information for options outstanding at December 31 of each year:  2019 2018 2017  Number of Shares Weighted Average Exercise Price Number of Shares Weighted Average Exercise Price Number of Shares Weighted Average Exercise Price  (in thousands) (in thousands) (in thousands) Options outstanding at January 1 5,178 $ 17.06 6,020 $ 19.43 5,416 $ 23.46 Granted — $ — — $ — 1,604 $ 8.00 Exercised — $ — — $ — — $ — Forfeited or expired (543) $ 32.38 (842) $ 33.99 (1,000) $ 22.93 Options outstanding at December 31 4,635 $ 15.26 5,178 $ 17.06 6,020 $ 19.43  Options Outstanding Options Exercisable Range of Exercise Prices Options Outstanding at December 31, 2019 Weighted Average Exercise Price Weighted Average Remaining Contractual Life Options Exercisable at December 31, 2019 Weighted Average Exercise Price Weighted Average Remaining Contractual Life  (in thousands) (years) (in thousands) (years) $5.22-$29.42 3,467 $ 8.63 3.4 3,045 $ 8.74 3.3 $30.59-$35.64 644 $ 30.60 1.9 644 $ 30.60 1.9 $38.20-$38.97 434 $ 38.97 0.9 434 $ 38.97 0.9 $46.55-$46.55 90 $ 46.55 1.4 90 $ 46.55 1.4  4,635 $ 15.26 2.9 4,213 $ 16.01 2.8 No options were granted in 2019 or 2018. The weighted-average grant date fair value of options granted during 2017 was $3.47. No options were exercised in 2019, 2018 or 2017. Equity-Classified Restricted Stock The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2019, 2018 and 2017: (in millions) 2019 2018 2017 Restricted stock grants – general and administrative expense $ 6 $ 9 $ 16 Restricted stock grants – general and administrative expense capitalized $ 4 $ 5 $ 11 The Company also recorded a reduction in the deferred tax asset of less than $1 million related to restricted stock for the year ended December 31, 2019, compared to deferred tax assets of $2 million and $9 million for 2018 and 2017, respectively. As of December 31, 2019, there was $6 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 one The following table summarizes the restricted stock activity for the years 2019, 2018 and 2017, and provides information for restricted stock outstanding at December 31 of each year:  2019 2018 2017  Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value  (in thousands) (in thousands) (in thousands) Unvested shares at January 1 2,717 $ 7.91 6,254 $ 8.85 3,321 $ 11.85 Granted 493 $ 3.06 350 $ 4.72 5,055 $ 8.38 Vested (1,516) $ 7.16 (2,058) $ 9.24 (1,380) $ 13.28 Forfeited (214) (1) $ 8.38 (1,829) (2) $ 9.01 (742) $ 10.04 Unvested shares at December 31 1,480 $ 7.00 2,717 $ 7.91 6,254 $ 8.85 (1) Includes 65,196 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2019. (2) Includes 1,287,636 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2018. The fair values of the grants were $2 million for 2019, $2 million for 2018 and $42 million for 2017. The total fair value of shares vested were $11 million for 2019, $19 million for 2018 and $18 million for 2017. Equity-Classified Performance Units The Company recorded compensation costs related to equity-classified performance units for the years ended December 31, 2019, 2018 and 2017. The performance units awarded in 2017 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. There were no equity-classified performance units awarded in 2019 and 2018. (in millions) 2019 2018 2017 Performance units – general and administrative expense $ 1 $ 3 $ 5 Performance units – general and administrative expense capitalized $ — $ 1 $ 2 The Company also recorded a deferred tax asset of less than $1 million related to equity-classified performance units for the year ended December 31, 2019, compared to deferred tax assets of $1 million and $3 million in 2018 and 2017, respectively. As of December 31, 2019, there was less than $1 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 less than one The following table summarizes equity-classified performance unit activity to be paid out in Company stock for the years ended December 31, 2019, 2018 and 2017, and provides information for unvested units as of December 31, 2019, 2018 and 2017: 2019 2018 2017 Number of Units (1) Weighted Number of Units (1) Weighted Number of Units (1) Weighted (in thousands) (in thousands) (in thousands) Unvested shares at January 1 598 $ 10.01 1,084 $ 10.12 719 $ 11.46 Granted — $ — — $ — 1,197 $ 10.47 Vested (378) $ 9.59 (290) $ 10.47 (325) $ 12.21 Forfeited (42) (2) $ 10.47 (196) (3) $ 9.94 (507) $ 9.53 Unvested shares at December 31 178 $ 10.47 598 $ 10.01 1,084 $ 10.12 (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 (2) Includes 41,761 units related to the reduction in workforce for the year ended December 31, 2019. (3) Includes 144,927 units related to the reduction in workforce for the year ended December 31, 2018. Liability-Classified Awards Liability-Classified Restricted Stock Units In the first quarter of 2019 and 2018, the Company granted restricted stock units that vest over a period of four ໿ (in millions) 2019 2018 Restricted stock units – general and administrative expense $ 7 $ 4 Restricted stock units – general and administrative expense capitalized $ 5 $ 3 The Company also recorded deferred tax assets of less than $1 million and $2 million related to liability-classified restricted stock units for the years ended December 31, 2019 and 2018, respectively. As of December 31, 2019, there was $24 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 The following table summarizes restricted stock unit activity to be paid out in cash for the years ended December 31, 2019 and 2018 and provides information for unvested units as of December 31, 2019 and 2018: 2019 2018  Number Weighted Average Fair Value Number Weighted Average Fair Value  (in thousands) (in thousands) Unvested units at January 1 8,202 $ 3.41 — $ — Granted 8,659 $ 4.34 12,216 $ 3.69 Vested (2,624) $ 4.09 (232) $ 5.14 Forfeited (1,245) (1) $ 3.48 (3,782) (2) $ 4.86 Unvested units at December 31 12,992 $ 2.42 8,202 $ 3.41 (1) Includes 400,056 units related to the reduction in workforce for the year ended December 31, 2019. (2) Includes 2,766,610 units related to the reduction in workforce for the year ended December 31, 2018. Liability-Classified Performance Units In 2019 and 2018, the Company granted performance units that vest at the end of, or over, a three ໿ (in millions) 2019 2018 Liability-classified performance units – general and administrative expense $ 2 $ 2 Liability-classified performance units – general and administrative expense capitalized $ 1 $ — The Company also recorded a reduction in the deferred tax assets of less than $1 million related to liability-classified performance units for the year ended December 31, 2019, compared to a deferred tax asset of $1 million for the year ended December 31, 2018. As of December 31, 2019, there was $6 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 The following table summarizes liability-classified performance unit activity to be paid out in cash for the years ended December 31, 2019 and 2018 and provides information for unvested units as of December 31, 2019 and 2018: 2019 2018  Number Weighted Average Number Weighted Average  (in thousands) (in thousands) Unvested units at January 1 2,803 $ 3.41 — $ — Granted 2,757 $ 4.34 3,200 $ 3.70 Vested (43) $ 2.42 — $ — Forfeited (375) (1) $ 3.12 (397) (2) $ 4.55 Unvested units at December 31 5,142 $ 2.42 2,803 $ 3.41 (1) Includes 375,086 units related to the reduction in workforce for the year ended December 31, 2019. (2) 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, 2019
Segment Reporting [Abstract]
Segment Information	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 Marketing segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes. Prior to December 2018, the Marketing segment included the Company’s natural gas gathering business in its Fayetteville Shale assets. With the closing of the Fayetteville Shale sale in December 2018, the Company's marketing business comprises substantially all of the Company’s Marketing segment. 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 (loss), interest expense, gain (loss) on derivatives, gain (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. (in millions) Exploration and Production Marketing Other Total 2019 Revenues from external customers $ 1,740 $ 1,298 $ — $ 3,038 Intersegment revenues (37) 1,552 — 1,515 Depreciation, depletion and amortization expense 462 9 — 471 Impairments 13 3 — 16 Operating income (loss) 283 (1) (13) — 270 Interest expense (2) 65 — — 65 Gain on derivatives 274 — — 274 Gain on early extinguishment of debt — — 8 8 Other income (loss), net (9) — 2 (7) Benefit from income taxes (2) (411) — — (411) Assets 6,235 (3) 314 168 (4) 6,717 Capital investments (5) 1,138 — 2 1,140  2018 (6) 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 (8) 1 171 Operating income (loss) 794 (7) 4 (9) (1) 797 Interest expense (2) 124 — — 124 Loss on derivatives (118) — — (118) Loss on early extinguishment of debt — — (17) (17) Other income (loss), net 2 (2) — — Provision for income taxes (2) 1 — — 1 Assets 4,872 (3) 539 386 (4) 5,797 Capital investments (5) 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 (2) 135 — — 135 Gain on derivatives 421 1 — 422 Loss on early extinguishment of debt — — (70) (70) Other income, net 4 1 — 5 Benefit from income taxes (2) (93) — — (93) Assets 5,109 (3) 1,288 1,124 (4) 7,521 Capital investments (5) 1,248 32 13 1,293 (1) Operating income for the E&P segment includes $11 million of restructuring charges for the year ended December 31, 2019. (2) Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level. (3) E&P assets includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties. This also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level. (4) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At December 31, 2019, 2018 and 2017, other assets included approximately $5 million, $205 million and $914 million, respectively, in cash and cash equivalents, $30 million, $89 million and $89 million, respectively, in income taxes receivable, $27 million, $60 million and $95 million, respectively, in property, plant and equipment, $11 million, $11 million and $5 million, respectively, in unamortized debt expense, $8 million, $8 million and $11 million, respectively, in prepayments and $7 million, $8 million and $10 million, respectively, in a non-qualified retirement plan. Additionally, the December 31, 2019 asset balance includes $80 million in right-of-use lease assets and the December 31, 2018 asset balance includes $4 million of accounts receivable and $1 million of current hedging assets. (5) Capital investments include an increase of $34 million for 2019 and a decrease of $53 million for 2018 related to the change in accrued expenditures between years. There was no impact to 2017. (6) Includes the impact of approximately eleven months of Fayetteville Shale-related E&P and midstream gathering operations which were divested in December 2018. (7) Operating income for the E&P segment includes $37 million related to restructuring charges for the year ended December 31, 2018. (8) Marketing includes a $10 million non-cash impairment related to certain non-core midstream gathering assets at December 31, 2018. (9) Operating income for the Marketing segment includes $2 million related to restructuring charges for the year ended December 31, 2018. Included in intersegment revenues of the Marketing segment are $1.6 billion, $2.3 billion and $1.9 billion for 2019, 2018 and 2017, 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, 2019
Condensed Financial Information Disclosure [Abstract]
Condensed Consolidating Financial Information	(16) 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 operating units which are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes (“Non-Guarantor Subsidiaries”). See Note 9 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, its 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, 2019 Operating Revenues: Gas sales $ — $ 1,241 $ — $ — $ 1,241 Oil sales — 223 — — 223 NGL sales — 274 — — 274 Marketing — 1,297 — — 1,297 Other — 3 — — 3 — 3,038 — — 3,038 Operating Costs and Expenses: Marketing purchases — 1,320 — — 1,320 Operating expenses — 720 1 (1) 720 General and administrative expenses — 166 — — 166 Restructuring charges — 11 — — 11 Depreciation, depletion and amortization — 470 1 — 471 Impairments — 16 — — 16 Loss on sale of assets, net — 2 — — 2 Taxes, other than income taxes — 62 — — 62 — 2,767 2 (1) 2,768 Operating Income (Loss) — 271 (2) 1 270 Interest Expense, Net 65 — — — 65 Gain on Derivatives — 274 — — 274 Gain on Early Extinguishment of Debt 8 — — — 8 Other Loss, Net — (7) — — (7) Equity in Earnings of Subsidiaries 947 (2) — (945) — Income (Loss) Before Income Taxes 890 536 (2) (944) 480 Benefit from Income Taxes — (411) — — (411) Net Income (Loss) $ 890 $ 947 $ (2) $ (944) $ 891 Net Income (Loss) $ 890 $ 947 $ (2) $ (944) $ 891 Other comprehensive income 3 — — — 3 Comprehensive Income (Loss) $ 893 $ 947 $ (2) $ (944) $ 894 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 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 (loss) (5) 6 6 (12) (5) Comprehensive Income (Loss) $ 1,041 $ 1,257 $ 6 $ (1,263) $ 1,041 CONDENSED CONSOLIDATED BALANCE SHEETS  (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated December 31, 2019 ASSETS Cash and cash equivalents $ 5 $ — $ — $ — $ 5 Accounts receivable, net — 345 — — 345 Other current assets 7 322 — — 329 Total current assets 12 667 — — 679  Intercompany receivables 7,922 — — (7,922) —  Natural gas and oil properties, using the full cost method — 25,195 55 — 25,250 Other 169 322 29 — 520 Less: Accumulated depreciation, depletion and amortization (144) (20,300) (59) — (20,503) Total property and equipment, net 25 5,217 25 — 5,267  Investments in subsidiaries (equity method) — 23 — (23) — Operating lease assets 80 79 — — 159 Deferred tax assets — 407 — — 407 Other long-term assets 19 186 — — 205 TOTAL ASSETS $ 8,058 $ 6,579 $ 25 $ (7,945) $ 6,717  LIABILITIES AND EQUITY Accounts payable $ 79 $ 446 $ — $ — $ 525 Current operating lease liabilities 8 26 — — 34 Other current liabilities 108 181 — — 289 Total current liabilities 195 653 — — 848  Intercompany payables — 7,920 2 (7,922) —  Long-term debt 2,242 — — — 2,242 Long-term operating lease liabilities 66 53 — — 119 Pension and other postretirement liabilities 43 — — — 43 Other long-term liabilities 11 208 — — 219 Negative carrying amount of subsidiaries, net 2,255 — — (2,255) — Total long-term liabilities 4,617 261 — (2,255) 2,623 Commitments and contingencies Total equity (accumulated deficit) 3,246 (2,255) 23 2,232 3,246 TOTAL LIABILITIES AND EQUITY $ 8,058 $ 6,579 $ 25 $ (7,945) $ 6,717 ໿ 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 Other 197 301 27 — 525 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 STATEMENT OF CASH FLOWS (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated Year ended December 31, 2019 Net cash provided by (used in) operating activities $ 1,280 $ 629 $ — $ (945) $ 964 Investing activities: Capital investments (4) (1,093) (2) — (1,099) Proceeds from the sale of property and equipment — 54 — — 54 Net cash used in investing activities (4) (1,039) (2) — (1,045) Financing activities Intercompany activities (1,357) 410 2 945 — Payments on current portion of long-term debt (52) — — — (52) Payments on long-term debt (54) — — — (54) Payments on revolving credit facility (532) — — — (532) Borrowings under revolving credit facility 566 — — — 566 Change in bank drafts outstanding (19) — — — (19) Debt issuance costs (3) — — — (3) Purchase of treasury stock (21) — — — (21) Cash paid for tax withholding (1) — — — (1) Other 1 — — — 1 Net cash provided by (used in) financing activities (1,472) 410 2 945 (115) Decrease in cash and cash equivalents (196) — — — (196) Cash and cash equivalents at beginning of year 201 — — — 201 Cash and cash equivalents at end of year $ 5 $ — $ — $ — $ 5 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 Change in bank drafts outstanding 17 — — — 17 Debt issuance costs (9) — — — (9) Purchase of treasury stock (180) — — — (180) Preferred stock dividend (27) — — — (27) Cash paid for tax withholding (3) — — — (3) Net cash provided by (used in) financing activities (997) (1,976) — 676 (2,297) 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 CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated 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 Change in bank drafts outstanding 9 — — — 9 Debt issuance costs (24) — — — (24) Cash paid for tax withholding (2) — — — (2) Preferred stock dividend (16) — — — (16) Other (2) — — — (2) Net cash provided by (used in) financing activities (1,510) (96) 5 1,249 (352) 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

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTSOn February 4, 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of its organizational structure. 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 their unvested long-term incentive awards that were forfeited. The plan is expected to be substantially implemented by the end of the first quarter of 2020. The Company expects to record a pre-tax charge to earnings of approximately $9 million in the first quarter of 2020 related to the severance payments.

Supplemental Quarterly Results

Supplemental Quarterly Results	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Data [Abstract]
Supplemental Quarterly Results	SUPPLEMENTAL QUARTERLY RESULTS (UNAUDITED) The following is a summary of the quarterly results of operations for the years ended December 31, 2019 and 2018: (in millions, except share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter  2019 Operating revenues $ 990 $ 667 $ 636 $ 745 Operating income (loss) 213 22 (29) 64 Net income attributable to common stock 594 138 49 110 Earnings per share – Basic 1.10 0.26 0.09 0.20 Earnings per share – Diluted 1.10 0.26 0.09 0.20   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

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures	12 Months Ended
	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Disclosures	SUPPLEMENTAL 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, 2019 and 2018: (in millions) 2019 2018 Proved properties $ 23,744 $ 22,425 Unproved properties 1,506 1,755 Total capitalized costs 25,250 24,180 Less: Accumulated depreciation, depletion and amortization (20,203) (19,761) Net capitalized costs $ 5,047 $ 4,419 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, 2019: (in millions) 2019 2018 2017 Prior Total Property acquisition costs $ 45 $ 40 $ 32 $ 1,106 $ 1,223 Exploration and development costs 53 23 16 12 104 Capitalized interest 67 47 27 38 179  $ 165 $ 110 $ 75 $ 1,156 $ 1,506 Of the total net unevaluated costs excluded from amortization as of December 31, 2019, approximately $1.2 billion is related to undeveloped properties in Southwest Appalachia (acquired in 2014 and 2015) and approximately $10 million is related to the acquisition of undeveloped properties in Northeast Appalachia. Additionally, the Company has approximately $179 million of unevaluated capitalized interest and $95 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) 2019 2018 2017 Unproved property acquisition costs $ 162 $ 164 $ 194 Exploration costs 2 5 22 Development costs 936 1,014 1,024 Capitalized costs incurred $ 1,100 $ 1,183 $ 1,240 Full cost pool amortization per Mcfe $ 0.56 $ 0.51 $ 0.45 Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $109 million, $115 million and $113 million during 2019, 2018 and 2017, 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 $77 million, $90 million and $99 million during 2019, 2018 and 2017, 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) 2019 2018 2017 Sales $ 1,703 $ 2,525 $ 2,086 Production (lifting) costs (781) (974) (891) Depreciation, depletion and amortization (462) (514) (440)  460 1,037 755 Provision for income taxes (1) 110 — — Results of operations (2) $ 350 $ 1,037 $ 755 (1) Prior to the recognition of a valuation allowance, in 2018 and 2017 the Company recognized income tax provisions of $254 million and $287 million, respectively. (2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 6 . 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 2019, 2018 and 2017. 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 2019, 2018 and 2017, all of which were located in the United States: ໿  Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) 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 Revisions of previous estimates due to price (480) (2,041) (37,492) (717) Revisions of previous estimates other than price (3) 685 3,707 65,869 1,102 Extensions, discoveries and other additions 992 6,948 26,941 1,195 Production (609) (4,696) (23,620) (778) Acquisition of reserves in place — — — — Disposition of reserves in place (2) — — (2) December 31, 2019 8,630 72,925 608,761 12,721 (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. (3) Revisions of previous estimates other than price includes 109 Bcfe of proved undeveloped reserves reclassified to unproved due to changes in the drilling plan, in accordance with the SEC five-year rule.  Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) Proved developed reserves as of: December 31, 2017 6,979 14,513 142,213 7,920 December 31, 2018 4,395 18,037 175,480 5,557 December 31, 2019 4,906 26,124 226,271 6,421 Proved undeveloped reserves as of: December 31, 2017 4,147 51,123 400,242 6,855 December 31, 2018 3,649 50,970 401,583 6,364 December 31, 2019 3,724 46,801 382,490 6,300 The Company’s estimated proved natural gas, oil and NGL reserves were 12,721 Bcfe at December 31, 2019, compared to 11,921 Bcfe at December 31, 2018. The Company’s reserves increased in 2019, compared to 2018, as positive extensions, discoveries, other additions and non-price revisions in Appalachia were only partially offset by negative price revisions. The decrease in the Company’s reserves in 2018 primarily resulted from the disposition of the reserves related to the Fayetteville Shale and was only partially offset by positive extensions, discoveries, other additions and revisions in Appalachia. The increase in the Company’s reserves in 2017 was primarily due to extensions, discoveries and other additions in Appalachia along with increases in both price and performance revisions across the portfolio. The following table summarizes the changes in reserves for 2017, 2018 and 2019: ໿  Appalachia Fayetteville (in Bcfe) Northeast Southwest Shale (1) Other (2) Total 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 Net revisions Price revisions (57) (660) — — (717) Performance and production revisions (3) 127 975 — — 1,102 Total net revisions 70 315 — — 385 Extensions, discoveries and other additions Proved developed 185 6 — — 191 Proved undeveloped 677 327 — — 1,004 Total reserve additions 862 333 — — 1,195 Production (459) (319) — — (778) Acquisition of reserves in place — — — — — Disposition of reserves in place (2) — — — (2) December 31, 2019 4,837 7,883 — 1 12,721 (1) The Fayetteville Shale E&P assets and associated reserves were divested in December 2018. (2) Other includes properties outside of Appalachia and Fayetteville Shale. (3) Performance and production revisions includes 109 Bcfe of proved undeveloped reserves reclassified to unproved due to changes in the drilling plan, in accordance with the SEC five-year rule. The Company’s December 31, 2019 proved reserves included 929 Bcfe of proved undeveloped reserves from 90 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 $50 million when discounted at 10%. The Company made a final investment decision and is committed to developing these reserves within the next five 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 that have a negative $24 million present value when discounted at 10%. 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 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, 2019, 2018 and 2017 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) 2019 2018 2017 Future cash inflows $ 27,003 $ 34,523 $ 36,576 Future production costs (14,981) (15,347) (18,390) Future development costs (1) (3,246) (4,095) (4,676) Future income tax expense (476) (2,079) (1,342) Future net cash flows 8,300 13,002 12,168 10% annual discount for estimated timing of cash flows (4,600) (7,003) (6,606) Standardized measure of discounted future net cash flows $ 3,700 $ 5,999 $ 5,562 (1) Includes abandonment costs. 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) 2019 2018 2017 Natural gas (per MMBtu) $ 2.58 $ 3.10 $ 2.98 Oil (per Bbl) 55.69 65.56 47.79 NGLs (per Bbl) 11.58 17.64 14.41 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 2019, 2018 and 2017: (in millions) 2019 2018 2017 Standardized measure, beginning of year $ 5,999 $ 5,562 $ 1,665 Sales and transfers of natural gas and oil produced, net of production costs (923) (1,564) (1,191) Net changes in prices and production costs (3,510) 2,162 1,963 Extensions, discoveries, and other additions, net of future production and development costs 234 335 1,715 Acquisition of reserves in place — — — Sales of reserves in place (2) (2,022) — Revisions of previous quantity estimates 152 361 1,721 Net change in income taxes 491 (304) (222) Changes in estimated future development costs 621 (166) (6) Previously estimated development costs incurred during the year 704 536 55 Changes in production rates (timing) and other (718) 521 (304) Accretion of discount 652 578 166 Standardized measure, end of year $ 3,700 $ 5,999 $ 5,562

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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.
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 that 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 minority partner’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, 2019, 2018 and 2017 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. In 2019, no single customer accounted for 10% or greater of total sales. 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. 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, 2019, and December 31, 2018: (in millions) December 31, 2019 December 31, 2018 Cash $ 5 $ 32 Marketable securities (1) — 169 Total $ 5 $ 201 (1) Consists of government stable value money market funds. 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 $15 million and $34 million as of December 31, 2019 and 2018, 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 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, 2019, the Company had a total of $1,506 million 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 non-cash ceiling test impairments. At December 31, 2019, using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.58 per MMBtu, West Texas Intermediate oil of $55.69 per barrel and NGLs of $11.58 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties was $218 million below the ceiling amount and therefore did not result in a ceiling test impairment at December 31, 2019. Given the fall in commodity prices in 2019 and early 2020, the Company expects some non-cash impairment of its assets will likely occur as early as the first quarter of 2020. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2019. 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 results 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. 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 . Natural gas and oil properties require expenditures to plug and abandon the wells and reclaim the associated pads and other supporting infrastructure when the wells are no longer producing. An asset retirement obligation associated with the retirement of a tangible long-lived asset such as oil and gas properties 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 Company’s non-full cost pool assets include water facilities, gathering systems, technology infrastructure, land, buildings and other equipment with useful lives that range from 3 to 30 years. 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. Should an impairment exist, the impairment loss would be measured as the amount that the asset’s carrying value exceeds its fair value. For the year ended December 31, 2019, the Company recognized non-cash impairments of $16 million for non-core assets. 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, a non-cash 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 non-cash 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. At December 31, 2019 and 2018, the Company had $56 million and $65 million, respectively, in marketing-related intangible assets that were included in Other long-term assets on the consolidated balance sheets. The Company amortized $9 million of its marketing-related intangible asset in each of the years ended December 31, 2019, 2018 and 2017, and expects to amortize $9 million in 2020, $8 million in 2021 and $5 million for the three years thereafter.
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.
Derivative Financial Instruments	Derivative Financial InstrumentsThe 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.
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 resulting from the conversion, exercise, or contingent issuance of certain securities.
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 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 1 4 for a discussion of the Company’s stock-based compensation.
Liability-Classified Awards	Liability-Classified AwardsThe Company classifies certain awards that can or will be settled in cash as liability 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 that were granted in 2018 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 Company’s liability-classified performance unit awards that were granted in 2019 include a performance condition based on the return of average capital employed and the same two market conditions as in the 2018 awards. 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. At December 31, 2018, approximately $180 million had been spent to repurchase 39,061,268 shares at an average price of $4.63 per share. In the first quarter of 2019, the Company completed its share repurchase program by purchasing 5,260,687 shares of its outstanding common stock for approximately $21 million at an average price of $3.84 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, 2019 and 2018, 5,115 shares and 10,653 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 ReportIn February 2016, the FASB issued Accounting Standards Update No. 2016-2, Leases (Topic 842) (“Update 2016-2”), 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.  For public entities, Update 2016-02 became effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted Accounting Standards Codification (“ASC”) 842 with an effective date of January 1, 2019 using the modified retrospective approach for all leases that existed at the date of initial application. The Company elected to apply the transition as of the beginning of the period of adoption. For leases that existed at the period of adoption on January 1, 2019, the incremental borrowing rate as of the adoption date was used to calculate the present value of remaining lease payments. Upon adoption of ASC 842, the Company recognized a discounted right-of-use asset and corresponding lease liability with opening balances of approximately $105 million as of January 1, 2019. The adoption of the standard did not materially change the Company's consolidated statement of operations or its consolidated statement of cash flows.
New Accounting Standards Not Yet Implemented in this Report	New Accounting Standards Not Yet Adopted in this Report In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“Update 2016-13”). Update 2016-13 replaces the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. For public business entities, the new standard is effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. From an evaluation of the Company’s existing credit portfolio, which includes trade receivables from commodity sales, joint interest billings due from partners, other receivables and cash equivalents, historical credit losses have been de minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of our business partners. As anticipated, the CECL model did not have a significant impact on Southwestern's consolidated financial statements or related control environment upon adoption on January 1, 2020.

Organization and Summary of S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Cash and Cash Equivalents	The following table presents a summary of cash and cash equivalents as of December 31, 2019, and December 31, 2018: (in millions) December 31, 2019 December 31, 2018 Cash $ 5 $ 32 Marketable securities (1) — 169 Total $ 5 $ 201 (1) Consists of government stable value money market funds.
Schedule of Earnings Per Share	The following table presents the computation of earnings per share for the years ended December 31, 2019, 2018 and 2017:  For the years ended December 31, (in millions, except share/per share amounts) 2019 2018 2017 Net income $ 891 $ 537 $ 1,046 Mandatory convertible preferred stock dividend — — 108 Participating securities – mandatory convertible preferred stock — 2 123 Net income attributable to common stock $ 891 $ 535 $ 815  Number of common shares: Weighted average outstanding 539,345,343 574,631,756 498,264,321 Issued upon assumed exercise of outstanding stock options — — — Effect of issuance of non-vested restricted common stock 361,380 698,103 1,061,056 Effect of issuance of non-vested performance units 676,191 1,312,949 1,478,920 Weighted average and potential dilutive outstanding 540,382,914 576,642,808 500,804,297  Earnings per common share: Basic $ 1.65 $ 0.93 $ 1.64 Diluted $ 1.65 $ 0.93 $ 1.63
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2019, 2018 and 2017, as they would have had an antidilutive effect:  For the years ended December 31,  2019 2018 2017 Unexercised stock options 5,078,253 5,909,082 116,717 Unvested share-based payment 1,728,264 3,692,794 5,361,849 Performance units 271,268 642,568 765,689 Mandatory convertible preferred stock — 2,465,708 74,999,895 Total 7,077,785 12,710,152 81,244,150
Schedule of 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, 2019, 2018 and 2017:  For the years ended December 31, (in millions) 2019 2018 2017 Cash paid during the year for interest, net of amounts capitalized $ 58 $ 135 $ 130 Cash paid (received) during the year for income taxes (52) 6 (5) Increase (decrease) in noncash property additions 41 (42) 25

Restructuring Charges (Tables)

Restructuring Charges (Tables)	12 Months Ended
	Dec. 31, 2019
Restructuring Cost and Reserve [Line Items]
Summary of Restructuring Charges	The following table presents a summary of the restructuring charges included in Operating Income for the years ended December 31, 2019, 2018 and 2017: For the years ended December 31, (in millions) 2019 2018 (1) 2017 Reduction in workforce (not Fayetteville Shale sale-related) $ — $ 23 $ — Fayetteville Shale sale-related 11 16 — Total restructuring charges $ 11 $ 39 $ — (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.
Summary of Liabilities Associated with Restructuring Activities	The following table presents a summary of liabilities associated with the Company’s restructuring activities at December 31, 2019, which are reflected in accounts payable on the consolidated balance sheet: ໿ (in millions) Liability at December 31, 2018 $ 5 Additions 11 Distributions (14) Liability at December 31, 2019 $ 2
Workforce Reduction
Restructuring Cost and Reserve [Line Items]
Summary of Restructuring Charges	The following table presents a summary of the restructuring charges related to workforce reduction plans included in Operating Income (Loss) for the year ended December 31, 2018:  For the year ended December 31, (in millions) 2018 Severance (including payroll taxes) $ 21 Stock-based compensation — Other benefits — Outplacement services, other 2 Total reduction in workforce-related restructuring charges (1) $ 23 (1) Total restructuring charges for the Company's E&P and Marketing segments were $21 million and $2 million, respectively, for the year ended December 31, 2018.
Fayetteville Shale
Restructuring Cost and Reserve [Line Items]
Summary of Restructuring Charges	The following table presents a summary of the restructuring charges related to the consolidation and reorganization associated with the Fayetteville Shale sale included in Operating Income on the condensed statements of operations for the years ended December 31, 2019 and 2018: For the years ended December 31, (in millions) 2019 2018 Severance (including payroll taxes) $ 5 $ 12 Office consolidation 6 4 Total Fayetteville Shale sale-related charges (1) (2) $ 11 $ 16 (1) Total restructuring charges were $11 million and $16 million for the Company’s E&P segment for the years ended December 31, 2019 and 2018, respectively. (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.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Disclosure of Lease Costs	The components of lease costs are shown below: For the year ended (in millions) December 31, 2019 Operating lease cost $ 45 Short-term lease cost 45 Variable lease cost 1 Total lease cost $ 91 Supplemental cash flow information related to leases is set forth below: For the year ended (in millions) December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 47 Right-of-use assets obtained in exchange for operating liabilities: Operating leases $ 95
Supplemental Balance Sheet Information	Supplemental balance sheet information related to leases is as follows: (in millions) December 31, 2019 Right-of-use asset balance: Operating leases $ 159 Lease liability balance: Current operating leases $ 34 Long-term operating leases 119 Total operating leases $ 153 Weighted average remaining lease term: (years) Operating leases 6.6 Weighted average discount rate: Operating leases 5.33 %
Maturity Analysis of Operating Lease Liabilities	Maturity analysis of operating lease liabilities: (in millions) December 31, 2019 2020 $ 41 2021 33 2022 22 2023 19 2024 15 Thereafter 52 Total undiscounted lease liability 182 Imputed interest (29) Total discounted lease liability $ 153
Undiscounted Maturities of Operating Leases Under ASC 840	Undiscounted maturities of operating leases accounted for under ASC 840: (in millions) December 31, 2018 2019 $ 38 2020 28 2021 14 2022 6 2023 5 Thereafter 4 Total minimum payments required $ 95

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue by Segment	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: (in millions) E&P Marketing Intersegment Total Year ended December 31, 2019 Gas sales $ 1,207 $ — $ 34 $ 1,241 Oil sales 220 — 3 223 NGL sales 274 — — 274 Marketing — 2,849 (1,552) 1,297 Other (1) 2 1 — 3 Total $ 1,703 $ 2,850 $ (1,515) $ 3,038  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 (2) — 248 (159) 89 Other (1) 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 (2) — 331 (205) 126 Other (1) 4 — — 4 Total $ 2,086 $ 3,198 $ (2,081) $ 3,203 (1) Other E&P revenues consists primarily of water sales to third-party operators and other marketing revenues consists primarily of sales of gas from storage. (2) The Company’s gas gathering assets were divested in December 2018 as part of the Fayetteville Shale sale.
Disaggregation of Revenue on Geographic Basis	Associated E&P revenues are also disaggregated for analysis on a geographic basis by the core areas in which the Company operates, which are primarily in Pennsylvania and West Virginia. In December 2018, the Company sold 100% of its Fayetteville Shale assets. For the years ended December 31, (in millions) 2019 2018 2017 Northeast Appalachia $ 964 $ 1,165 $ 837 Southwest Appalachia 736 817 498 Fayetteville Shale — 537 743 Other 3 6 8 Total $ 1,703 $ 2,525 $ 2,086
Reconciliation of Accounts Receivable	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, 2019 December 31, 2018 Receivables from contracts with customers $ 284 $ 494 Other accounts receivable 61 87 Total accounts receivable $ 345 $ 581

Derivatives and Risk Manageme_2

Derivatives and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value	The following tables provide 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 tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of December 31, 2019: Financial Protection on Production  Weighted Average Price per MMBtu Fair value at December 31, 2019 ($ in millions)  Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Natural Gas 2020 Fixed price swaps 280 $ 2.51 $ — $ — $ — $ — $ 76 (1) Two-way costless collars 31 — — 2.56 2.85 — 6 Three-way costless collars 185 — 2.28 2.65 3.00 — 42 Total 496 $ 124 2021 Fixed price swaps 30 $ 2.54 $ — $ — $ — $ — $ 7 Two-way costless collars 17 — — 2.50 2.83 — — Three-way costless collars 213 — 2.23 2.53 2.90 — — Total 260 $ 7 2022 Three-way costless collars 31 $ — $ 2.30 $ 2.69 $ 3.15 $ — $ 2  Basis swaps 2020 198 $ — $ — $ — $ — $ (0.31) $ — 2021 86 — — — — 0.04 7 2022 45 — — — — (0.50) (1) Total 329 $ 6 (1) Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statement of operations.  Weighted Average Price per Bbl Fair value at December 31, 2019 ($ in millions)  Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Oil 2020 Fixed price swaps 3,465 $ 57.83 $ — $ — $ — $ (2) Two-way costless collars 966 — — 56.89 59.81 — Three-way costless collars 971 — 45.12 55.12 59.68 (1) Total 5,402 $ (3) 2021 Fixed price swaps 1,584 $ 53.20 $ — $ — $ — $ (1) Three-way costless collars 1,445 — 43.52 53.25 58.14 (1) Total 3,029 $ (2) 2022 Fixed price swaps 438 $ 51.74 $ — $ — $ — $ —  Propane 2020 Fixed price swaps 4,746 $ 23.90 $ — $ — $ — $ 21 Two-way costless collars 366 — — 25.20 29.40 2 Total 5,112 $ 23 2021 Fixed price swaps 2,460 $ 21.77 $ — $ — — $ 3  Ethane 2020 Fixed price swaps 7,520 $ 8.84 $ — $ — $ — $ 11 2021 Fixed price swaps 2,410 $ 7.53 $ — $ — $ — $ — Other Derivative Contracts  Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2019 ($ in millions) Purchased Call Options – Natural Gas 2020 104 $ 3.46 $ 1 2021 57 3.52 2 Total 161 $ 3  Sold Call Options – Natural Gas 2020 173 $ 3.24 $ (3) 2021 115 3.33 (6) 2022 58 3.00 (5) 2023 6 3.00 (1) 2024 9 3.00 (3) Total 361 $ (18) Volume (MBbls) Weighted Average Strike Price per Bbl Fair value at December 31, 2019 ($ in millions) Sold Call Options – Oil 2021 — $ 60.00 $ (1) Weighted Average Strike Price per MMBtu Fair value at December 31, 2019 ($ in millions) Natural Gas Storage (1) Volume (Bcf) Swaps Basis Differential 2020 Purchased fixed price swap — $ 2.37 $ — $ — Purchased basis swap — — (0.32) — Sold fixed price swap 1 3.06 — 1 Sold basis swap — — (0.32) — Total 1 $ 1 (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. Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2019 ($ in millions) Purchased Fixed Price Swaps – Marketing (Natural Gas) (1) 2020 7 $ 2.44 $ (1) 2021 6 2.44 — Total 13 $ (1) (1) The Company has entered into a limited number of derivatives to protect the value of certain long-term sales contracts.
Balance Sheet Classification of Derivative Financial Instruments	The balance sheet classification of the assets and liabilities related to derivative financial instruments are summarized below as of December 31, 2019 and 2018: Derivative Assets  Balance Sheet Classification Fair Value (in millions) December 31, 2019 December 31, 2018 Derivatives not designated as hedging instruments: Fixed price swap – natural gas Derivative assets $ 77 (1) $ 32 Fixed price swap – oil Derivative assets 4 13 Fixed price swap – propane Derivative assets 21 11 Fixed price swap – ethane Derivative assets 11 7 Two-way costless collar – natural gas Derivative assets 10 11 Two-way costless collar – oil Derivative assets 5 6 Two-way costless collar – propane Derivative assets 2 — Three-way costless collar – natural gas Derivative assets 126 41 Three-way costless collar – oil Derivative assets 3 — Basis swap – natural gas Derivative assets 17 8 Purchased call option – natural gas Derivative assets 1 — Fixed price swap – natural gas storage Derivative assets 1 — Interest rate swap Derivative assets — 1 Fixed price swap – natural gas Other long-term assets 7 6 Fixed price swap – oil Other long-term assets 1 6 Fixed price swap – propane Other long-term assets 3 — Fixed price swap – ethane Other long-term assets — 1 Two-way costless collar – natural gas Other long-term assets 4 — Two-way costless collar – oil Other long-term assets — 5 Three-way costless collar – natural gas Other long-term assets 74 34 Three-way costless collar – oil Other long-term assets 7 — Basis swap – natural gas Other long-term assets 15 3 Purchased call options – natural gas Other long-term assets 2 6 Total derivative assets $ 391 $ 191 (1) Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations. Derivative Liabilities  Balance Sheet Classification Fair Value (in millions) December 31, 2019 December 31, 2018 Derivatives not designated as hedging instruments: Purchased fixed price swap – natural gas Derivative liabilities $ 1 $ — Purchased fixed price swap – oil Derivative liabilities — 6 Fixed price swap – natural gas Derivative liabilities 1 9 Fixed price swap – oil Derivative liabilities 6 — Fixed price swap – ethane Derivative liabilities — 3 Two-way costless collar – natural gas Derivative liabilities 4 7 Two-way costless collar – oil Derivative liabilities 5 — Three-way costless collar – natural gas Derivative liabilities 84 33 Three-way costless collar – oil Derivative liabilities 4 — Basis swap – natural gas Derivative liabilities 17 18 Sold call option – natural gas Derivative liabilities 3 3 Fixed price swap – natural gas Other long-term liabilities — 1 Fixed price swap – oil Other long-term liabilities 2 — Two-way costless collar – natural gas Other long-term liabilities 4 — Two-way costless collar – oil Other long-term liabilities — 1 Three-way costless collar – natural gas Other long-term liabilities 72 35 Three-way costless collar – oil Other long-term liabilities 8 — Basis swap – natural gas Other long-term liabilities 9 4 Sold call option – natural gas Other long-term liabilities 15 19 Sold call option – oil Other long-term liabilities 1 — Total derivative liabilities $ 236 $ 139
Summary of Before Tax Effect of Cash Flow Hedges on Consolidated Financial Statements	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, 2019 and 2018: Unsettled Gain (Loss) on Derivatives Recognized in Earnings  Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled For the years ended Derivative Instrument 2019 2018  (in millions) Purchased fixed price swap – natural gas Gain (Loss) on Derivatives $ (1) $ — Purchased fixed price swap – oil Gain (Loss) on Derivatives 6 (6) Fixed price swap – natural gas Gain (Loss) on Derivatives 46 (27) Fixed price swap – oil Gain (Loss) on Derivatives (22) 19 Fixed price swap – propane Gain (Loss) on Derivatives 13 11 Fixed price swap – ethane Gain (Loss) on Derivatives 6 5 Two-way costless collar – natural gas Gain (Loss) on Derivatives 2 — Two-way costless collar – oil Gain (Loss) on Derivatives (10) 10 Two-way costless collar – propane Gain (Loss) on Derivatives 2 — Three-way costless collar – natural gas Gain (Loss) on Derivatives 37 (48) Three-way costless collar – oil Gain (Loss) on Derivatives (2) — Basis swap – natural gas Gain (Loss) on Derivatives 17 10 Purchased call option – natural gas Gain (Loss) on Derivatives (3) 4 Sold call option – natural gas Gain (Loss) on Derivatives 4 (4) Sold call option – oil Gain (Loss) on Derivatives (1) — Fixed price swap – natural gas storage Gain (Loss) on Derivatives 1 — Interest rate swap Gain (Loss) on Derivatives (1) 2 Total gain (loss) on unsettled derivatives $ 94 $ (24)  Settled Gain (Loss) on Derivatives Recognized in Earnings (1)  Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled For the years ended Derivative Instrument 2019 2018  (in millions) Purchased fixed price swap – oil Gain (Loss) on Derivatives $ (3) $ — Fixed price swap – natural gas Gain (Loss) on Derivatives 78 (32) Fixed price swap – oil Gain (Loss) on Derivatives 10 — Fixed price swap – propane Gain (Loss) on Derivatives 29 (6) Fixed price swap – ethane Gain (Loss) on Derivatives 17 (8) Two-way costless collar – natural gas Gain (Loss) on Derivatives 16 (1) Two-way costless collar – oil Gain (Loss) on Derivatives 6 — Two-way costless collar – propane Gain (Loss) on Derivatives 2 — Three-way costless collar – natural gas Gain (Loss) on Derivatives 31 (9) Basis swap – natural gas Gain (Loss) on Derivatives (3) (31) Purchased call option – natural gas Gain (Loss) on Derivatives (1) (2) 2 (2) Sold call option – natural gas Gain (Loss) on Derivatives (1) (7) Sold call option – oil Gain (Loss) on Derivatives — (2) Purchased fixed price swap – natural gas storage Gain (Loss) on Derivatives (1) — Total gain (loss) on settled derivatives $ 180 $ (94)  Total gain (loss) on derivatives $ 274 $ (118) (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 purchased call options for each of the years ended December 31, 2019 and 2018, which is included in gain (loss) on derivatives on the consolidated statement of operations.

Reclassifications from Accumu_2

Reclassifications from Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Components of Accumulated Other Comprehensive Income (Loss)	In 2019, changes in AOCI primarily related to settlements in the Company's pension and other postretirement benefits. The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects, for the year ended December 31, 2019:  For the year ended December 31, 2019 (in millions) Pension and Other Postretirement Foreign Currency Total Beginning balance, December 31, 2018 $ (22) $ (14) $ (36) Other comprehensive loss before reclassifications (5) — (5) Amounts reclassified from other comprehensive income (1) 8 — 8 Net current-period other comprehensive income 3 — 3 Ending balance, December 31, 2019 $ (19) $ (14) $ (33) (1) 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, 2019 Pension and other postretirement: (in millions) Amortization of prior service cost and net loss (1) Other Income, Net $ 10  Provision for income taxes (2)  Net income $ 8  Total reclassifications for the period Net income $ 8 (1) See Note 1 3 for additional details regarding the Company’s pension and other postretirement benefit plans.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Carrying Amount and Estimated Fair Values of Financial Instruments	The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2019 and 2018 were as follows:  December 31, 2019 December 31, 2018 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents $ 5 $ 5 $ 201 $ 201 2018 revolving credit facility due April 2024 (1) 34 34 — — Senior notes (2) 2,228 2,085 2,342 2,190 Derivative instruments, net 155 (3) 155 (3) 52 52 (1) In October 2019, the Company amended its 2018 revolving credit facility agreement which, among other things, extended the maturity from 2023 to 2024. (2) Excludes unamortized debt issuance costs and debt discounts.
Summary of Assets and Liabilities Measured at Fair Value on Recurring Basis	Assets and liabilities measured at fair value on a recurring basis are summarized below:  December 31, 2019  Fair Value Measurements Using: (in millions) Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs (Level 3) Assets (Liabilities) at Fair Value Assets Fixed price swap – natural gas (1) $ — $ 84 $ — $ 84 Fixed price swap – oil — 5 — 5 Fixed price swap – propane — 24 — 24 Fixed price swap – ethane — 11 — 11 Two-way costless collar – natural gas — 14 — 14 Two-way costless collar – oil — 5 — 5 Two-way costless collar – propane — 2 — 2 Three-way costless collar – natural gas — 200 — 200 Three-way costless collar – oil — 10 — 10 Basis swap – natural gas — 32 — 32 Purchased call option – natural gas — 3 — 3 Fixed price swap – natural gas storage — 1 — 1 Liabilities Purchased fixed price swap – natural gas — (1) — (1) Fixed price swap – natural gas — (1) — (1) Fixed price swap – oil — (8) — (8) Two-way costless collar – natural gas — (8) — (8) Two-way costless collar – oil — (5) — (5) Three-way costless collar – natural gas — (156) — (156) Three-way costless collar – oil — (12) — (12) Basis swap – natural gas — (26) — (26) Sold call option – natural gas — (18) — (18) Sold call option – oil — (1) — (1) Total $ — $ 155 $ — $ 155 (1) Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statement of operations.  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 swaps – 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
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)	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, 2019 and 2018. The fair values of Level 3 derivative instruments were 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, 2019 and 2018. 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.  For the years ended December 31, (in millions) 2019 2018 Balance at beginning of year $ — $ 22 Total gains (losses): Included in earnings — (17) Settlements (1) — 1 Transfers into/out of Level 3 (2) — (6) Balance at end of period $ — $ — Change in gains (losses) included in earnings relating to derivatives still held as of December 31 $ — $ — (1) Includes $1 million for amortization of premiums paid related to certain natural gas purchased call options for the year ended December 31, 2018. (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, 2019
Debt Disclosure [Abstract]
Components of Debt	The components of debt as of December 31, 2019 and 2018 consisted of the following:  December 31, 2019 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Total Long-term debt: Variable rate (4.310% at December 31, 2019) 2018 revolving credit facility, due April 2024 $ 34 $ — (1) $ — $ 34 4.10% Senior Notes due March 2022 213 (1) — 212 4.95% Senior Notes due January 2025 (2) 892 (5) (1) 886 7.50% Senior Notes due April 2026 639 (7) — 632 7.75% Senior Notes due October 2027 484 (6) — 478 Total long-term debt $ 2,262 $ (19) $ (1) $ 2,242  December 31, 2018 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total Long-term debt: Variable rate (3.920% at December 31, 2018) 2018 term loan facility, due April 2023 $ — $ — (1) $ — $ — 4.05% Senior Notes due January 2020 (2) 52 — — 52 4.10% Senior Notes due March 2022 213 (1) — 212 4.95% Senior Notes due January 2025 (2) 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 long-term debt $ 2,342 $ (23) $ (1) $ 2,318 (1) At December 31, 2019 and 2018, unamortized issuance expense of $11 million associated with the 2018 revolving credit facility was classified as other long-term assets on the consolidated balance sheet. (2) In February and June 2016, Moody’s and S&P downgraded certain senior notes, increasing 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. S&P and Moody’s upgraded certain senior 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 the bondholders at the lower interest rate was paid in January 2019.
Schedule of Long Term Debt Maturities	The following is a summary of scheduled debt maturities by year as of December 31, 2019: (in millions) 2020 $ — 2021 — 2022 213 2023 — 2024 (1) 34 Thereafter 2,015  $ 2,262 (1) The Company’s current revolving credit facility matures in 2024.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Obligation under Transportation Agreements	As of December 31, 2019, 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 $ 7,414 $ 767 $ 1,200 $ 1,066 $ 1,531 $ 2,850 Pending regulatory approval and/or construction (1) 1,056 1 35 103 208 709 Total transportation charges $ 8,470 $ 768 $ 1,235 $ 1,169 $ 1,739 $ 3,559 (1) Based on the estimated in-service dates as of December 31, 2019.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes	The provision (benefit) for income taxes included the following components: (in millions) 2019 2018 2017 Current: Federal $ (1) $ (5) $ (22) State (1) 6 —  (2) 1 (22) Deferred: Federal (431) — (71) State 22 — —  (409) — (71) Provision (benefit) for income taxes $ (411) $ 1 $ (93)
Reconciliation of Provision for Income Taxes	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) 2019 2018 2017 Expected provision at federal statutory rate $ 101 $ 113 $ 333 Decrease resulting from: State income taxes, net of federal income tax effect 11 13 16 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) Change in valuation allowance (522) (121) (364) Removal of sequestration fee on AMT receivables — (5) — Other (1) 1 (5) Provision (benefit) for income taxes $ (411) $ 1 $ (93)
Components of Deferred Tax Balances	The components of the Company’s deferred tax balances as of December 31, 2019 and 2018 were as follows: (in millions) 2019 2018 Deferred tax liabilities: Differences between book and tax basis of property $ 312 $ 226 Derivative activity 34 12 Right of use lease asset 37 — Other 2 2  385 240 Deferred tax assets: Accrued compensation 33 33 Accrued pension costs 9 10 Asset retirement obligations 13 15 Net operating loss carryforward 769 777 Future lease payments 37 — Other 18 14  879 849 Valuation allowance (87) (609) Net deferred tax asset $ 407 $ —
Reconciliation of Changes to the Valuation Allowance	A reconciliation of the changes to the valuation allowance is as follows: (in millions) Valuation allowance as of December 31, 2018 $ 609 Release of valuation allowance in 2019 (522) Valuation allowance as of December 31, 2019 $ 87
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: (in millions) 2019 2018 Unrecognized tax benefits at beginning of year $ 7 $ 12 Additions based on tax positions related to the current year — — Additions to tax positions of prior years — — Reductions to tax positions of prior years (7) (5) Unrecognized tax benefits at end of year $ — $ 7

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation [Abstract]
Schedule of Asset Retirement Obligations	The following table summarizes the Company’s 2019 and 2018 activity related to asset retirement obligations: (in millions) 2019 2018 Asset retirement obligation at January 1 $ 61 $ 165 Accretion of discount 3 9 Obligations incurred 2 1 Obligations settled/removed (1) (9) (116) Revisions of estimates — 2 Asset retirement obligation at December 31 $ 57 $ 61  Current liability $ 6 $ 6 Long-term liability 51 55 Asset retirement obligation at December 31 $ 57 $ 61 (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, 2019
Retirement Benefits [Abstract]
Changes in Plans Benefit Obligations, Fair Value of Assets, and Funded Status	The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status as of December 31, 2019 and 2018:  Pension Benefits Other Postretirement Benefits (in millions) 2019 2018 2019 2018 Change in benefit obligations: Benefit obligation at January 1 $ 125 $ 143 $ 13 $ 17 Service cost 7 10 1 2 Interest cost 5 5 — 1 Participant contributions — — — — Actuarial (gain) loss 15 (14) 1 — Benefits paid (2) (14) (2) (1) Plan amendments — — — — Curtailments — (5) — (6) Settlements (24) — — — Benefit obligation at December 31 $ 126 $ 125 $ 13 $ 13  Pension Benefits Other Postretirement Benefits (in millions) 2019 2018 2019 2018 Change in plan assets: Fair value of plan assets at January 1 $ 91 $ 101 $ — $ — Actual return on plan assets 16 (8) — — Employer contributions 12 12 2 1 Participant contributions — — — — Benefits paid (2) (14) (2) (1) Settlements (21) — — — Fair value of plan assets at December 31 $ 96 $ 91 $ — $ —  Funded status of plans at December 31 $ (30) $ (34) $ (13) $ (13)
Projected Benefit Obligation, Accumulated Benefit Obligation, and Fair Value of Plan Assets	The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2019 and 2018 are as follows: (in millions) 2019 2018 Projected benefit obligation $ 126 $ 125 Accumulated benefit obligation 124 122 Fair value of plan assets 96 91
Pension and Other Postretirement Benefit Costs	Pension and other postretirement benefit costs include the following components for 2019, 2018 and 2017:  Pension Benefits Other Postretirement Benefits (in millions) 2019 2018 2017 2019 2018 2017 Service cost $ 7 $ 10 $ 9 $ 1 $ 2 $ 2 Interest cost 5 5 5 — 1 — Expected return on plan assets (6) (7) (6) — — — Amortization of transition obligation — — — — — — Amortization of prior service cost — — — — — — Amortization of net loss 2 2 2 — — — Net periodic benefit cost 8 10 10 1 3 2 Curtailment gain — — — — (4) — Settlement loss 6 — — — — — Total benefit cost (benefit) $ 14 $ 10 $ 10 $ 1 $ (1) $ 2
Amounts Recognized in Other Comprehensive Income	Amounts recognized in other comprehensive income for the years ended December 31, 2019 and 2018 were as follows:  Pension Benefits Other Postretirement Benefits (in millions) 2019 2018 2019 2018 Net actuarial loss arising during the year $ (5) $ (2) $ (1) $ — Amortization of prior service cost — — — — Amortization of net loss 2 2 — — Settlements 8 — — — Curtailments — 5 — 3 Tax effect (1) (1) (1) — (1)  $ 4 $ 4 $ (1) $ 2 (1) For the year ended December 31, 2018, deferred tax activity related to pension and other postretirement benefits was offset by a valuation allowance, resulting in no tax expense 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, 2019 and 2018 are as follows:  Pension Benefits Other Postretirement Benefits  2019 2018 2019 2018 Discount rate 3.70 % 4.35 % 3.50 % 4.35 % 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 2019, 2018 and 2017 are as follows:  Pension Benefits Other Postretirement Benefits  2019 2018 2017 2019 2018 2017 Discount rate 3.70 % 4.35 % 4.20 % 4.35 % 4.35 % 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	For measurement purposes, the following trend rates were assumed for 2019 and 2018:  2019 2018 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 2037 2036
One Percentage Point Change in Assumed Health Care Cost Trend Rates	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 $ 2 $ (1) Effect on postretirement benefit obligations $ 2 $ (2)
Schedule of Expected Benefit Payments	The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Benefits Other Postretirement Benefits (in millions) 2020 $ 5 2020 $ 1 2021 5 2021 1 2022 6 2022 1 2023 6 2023 1 2024 7 2024 1 Years 2025-2029 34 Years 2025-2029 5
Schedule of Allocation of Plan Assets	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 % 34 % Non-U.S. equity (2) 35 % 33 % Fixed income (3) 28 % 31 % Cash (4) 2 % 2 % 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 fixed income pension plan assets in the table below. (4) 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 8 , the Company’s fair value measurement of pension plan assets as of December 31, 2019 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) $ 3 $ 3 $ — $ — U.S. large cap value equity (2) 6 6 — — U.S. small cap equity (3) 2 2 — — Non-U.S. equity (4) 32 32 — — Fixed income (6) 22 22 — — Cash and cash equivalents 2 2 — — Total measured within fair value hierarchy $ 67 $ 67 $ — $ — Measured at net asset value (8) Equity securities: U.S. large cap growth equity (9) 3 U.S. large cap core equity (10) 18 Fixed income (6) 8 Total measured at net asset value $ 29  Total plan assets at fair value $ 96 Note: Footnotes are located after the prior year comparative table below. Utilizing the fair value hierarchy described in Note 8 , the Company’s fair value measurement of pension plan assets at December 31, 2018 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) $ 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 (10) 12 Fixed income (6) 7 Total measured at net asset value $ 19  Total plan assets at fair value $ 91 (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) Included 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 invest in companies with sustainable competitive advantages, as identified through proprietary research. (10) 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, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Valuation Assumptions	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 2019 or 2018. Assumptions 2017 Risk-free interest rate 1.9 % Expected dividend yield — Expected volatility 50.5 % Expected term 5 years
Summary of Equity-Classified Stock Option Activity	The following tables summarize stock option activity for the years 2019, 2018 and 2017, and provide information for options outstanding at December 31 of each year:  2019 2018 2017  Number of Shares Weighted Average Exercise Price Number of Shares Weighted Average Exercise Price Number of Shares Weighted Average Exercise Price  (in thousands) (in thousands) (in thousands) Options outstanding at January 1 5,178 $ 17.06 6,020 $ 19.43 5,416 $ 23.46 Granted — $ — — $ — 1,604 $ 8.00 Exercised — $ — — $ — — $ — Forfeited or expired (543) $ 32.38 (842) $ 33.99 (1,000) $ 22.93 Options outstanding at December 31 4,635 $ 15.26 5,178 $ 17.06 6,020 $ 19.43
Summary of Stock Options Outstanding and Options Exercisable	 Options Outstanding Options Exercisable Range of Exercise Prices Options Outstanding at December 31, 2019 Weighted Average Exercise Price Weighted Average Remaining Contractual Life Options Exercisable at December 31, 2019 Weighted Average Exercise Price Weighted Average Remaining Contractual Life  (in thousands) (years) (in thousands) (years) $5.22-$29.42 3,467 $ 8.63 3.4 3,045 $ 8.74 3.3 $30.59-$35.64 644 $ 30.60 1.9 644 $ 30.60 1.9 $38.20-$38.97 434 $ 38.97 0.9 434 $ 38.97 0.9 $46.55-$46.55 90 $ 46.55 1.4 90 $ 46.55 1.4  4,635 $ 15.26 2.9 4,213 $ 16.01 2.8
Summary of Equity-Classified Restricted Stock Activity	The following table summarizes the restricted stock activity for the years 2019, 2018 and 2017, and provides information for restricted stock outstanding at December 31 of each year:  2019 2018 2017  Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value  (in thousands) (in thousands) (in thousands) Unvested shares at January 1 2,717 $ 7.91 6,254 $ 8.85 3,321 $ 11.85 Granted 493 $ 3.06 350 $ 4.72 5,055 $ 8.38 Vested (1,516) $ 7.16 (2,058) $ 9.24 (1,380) $ 13.28 Forfeited (214) (1) $ 8.38 (1,829) (2) $ 9.01 (742) $ 10.04 Unvested shares at December 31 1,480 $ 7.00 2,717 $ 7.91 6,254 $ 8.85 (1) Includes 65,196 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2019. (2) Includes 1,287,636 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2018.
Summary of Equity-Classified Performance Units Activity	The following table summarizes equity-classified performance unit activity to be paid out in Company stock for the years ended December 31, 2019, 2018 and 2017, and provides information for unvested units as of December 31, 2019, 2018 and 2017: 2019 2018 2017 Number of Units (1) Weighted Number of Units (1) Weighted Number of Units (1) Weighted (in thousands) (in thousands) (in thousands) Unvested shares at January 1 598 $ 10.01 1,084 $ 10.12 719 $ 11.46 Granted — $ — — $ — 1,197 $ 10.47 Vested (378) $ 9.59 (290) $ 10.47 (325) $ 12.21 Forfeited (42) (2) $ 10.47 (196) (3) $ 9.94 (507) $ 9.53 Unvested shares at December 31 178 $ 10.47 598 $ 10.01 1,084 $ 10.12 (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 (2) Includes 41,761 units related to the reduction in workforce for the year ended December 31, 2019. (3) Includes 144,927 units related to the reduction in workforce for the year ended December 31, 2018.
Summary of Liability-Classified Restricted Stock Unit Activity	The following table summarizes restricted stock unit activity to be paid out in cash for the years ended December 31, 2019 and 2018 and provides information for unvested units as of December 31, 2019 and 2018: 2019 2018  Number Weighted Average Fair Value Number Weighted Average Fair Value  (in thousands) (in thousands) Unvested units at January 1 8,202 $ 3.41 — $ — Granted 8,659 $ 4.34 12,216 $ 3.69 Vested (2,624) $ 4.09 (232) $ 5.14 Forfeited (1,245) (1) $ 3.48 (3,782) (2) $ 4.86 Unvested units at December 31 12,992 $ 2.42 8,202 $ 3.41 (1) Includes 400,056 units related to the reduction in workforce for the year ended December 31, 2019. (2) 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	The following table summarizes liability-classified performance unit activity to be paid out in cash for the years ended December 31, 2019 and 2018 and provides information for unvested units as of December 31, 2019 and 2018: 2019 2018  Number Weighted Average Number Weighted Average  (in thousands) (in thousands) Unvested units at January 1 2,803 $ 3.41 — $ — Granted 2,757 $ 4.34 3,200 $ 3.70 Vested (43) $ 2.42 — $ — Forfeited (375) (1) $ 3.12 (397) (2) $ 4.55 Unvested units at December 31 5,142 $ 2.42 2,803 $ 3.41 (1) Includes 375,086 units related to the reduction in workforce for the year ended December 31, 2019. (2) Includes 295,160 units related to the reduction in workforce for the year ended December 31, 2018.
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Equity-Classified Stock-Based Compensation Costs	The Company recorded the following compensation costs related to stock options for the years ended December 31, 2019, 2018 and 2017: (in millions) 2019 2018 2017 Stock options – general and administrative expense $ 1 $ 2 $ 3 Stock options – general and administrative expense capitalized $ — $ — $ 1
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Equity-Classified Stock-Based Compensation Costs	The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2019, 2018 and 2017: (in millions) 2019 2018 2017 Restricted stock grants – general and administrative expense $ 6 $ 9 $ 16 Restricted stock grants – general and administrative expense capitalized $ 4 $ 5 $ 11
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Equity-Classified Stock-Based Compensation Costs	(in millions) 2019 2018 2017 Performance units – general and administrative expense $ 1 $ 3 $ 5 Performance units – general and administrative expense capitalized $ — $ 1 $ 2
Liability-Classified RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Liability-Classified Stock-Based Compensation Costs	(in millions) 2019 2018 Restricted stock units – general and administrative expense $ 7 $ 4 Restricted stock units – general and administrative expense capitalized $ 5 $ 3
Liability-Classified Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Liability-Classified Stock-Based Compensation Costs	(in millions) 2019 2018 Liability-classified performance units – general and administrative expense $ 2 $ 2 Liability-classified performance units – general and administrative expense capitalized $ 1 $ —

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Summary of Financial Information for Company's Reportable Segments	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 (loss), interest expense, gain (loss) on derivatives, gain (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. (in millions) Exploration and Production Marketing Other Total 2019 Revenues from external customers $ 1,740 $ 1,298 $ — $ 3,038 Intersegment revenues (37) 1,552 — 1,515 Depreciation, depletion and amortization expense 462 9 — 471 Impairments 13 3 — 16 Operating income (loss) 283 (1) (13) — 270 Interest expense (2) 65 — — 65 Gain on derivatives 274 — — 274 Gain on early extinguishment of debt — — 8 8 Other income (loss), net (9) — 2 (7) Benefit from income taxes (2) (411) — — (411) Assets 6,235 (3) 314 168 (4) 6,717 Capital investments (5) 1,138 — 2 1,140  2018 (6) 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 (8) 1 171 Operating income (loss) 794 (7) 4 (9) (1) 797 Interest expense (2) 124 — — 124 Loss on derivatives (118) — — (118) Loss on early extinguishment of debt — — (17) (17) Other income (loss), net 2 (2) — — Provision for income taxes (2) 1 — — 1 Assets 4,872 (3) 539 386 (4) 5,797 Capital investments (5) 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 (2) 135 — — 135 Gain on derivatives 421 1 — 422 Loss on early extinguishment of debt — — (70) (70) Other income, net 4 1 — 5 Benefit from income taxes (2) (93) — — (93) Assets 5,109 (3) 1,288 1,124 (4) 7,521 Capital investments (5) 1,248 32 13 1,293 (1) Operating income for the E&P segment includes $11 million of restructuring charges for the year ended December 31, 2019. (2) Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level. (3) E&P assets includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties. This also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level. (4) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At December 31, 2019, 2018 and 2017, other assets included approximately $5 million, $205 million and $914 million, respectively, in cash and cash equivalents, $30 million, $89 million and $89 million, respectively, in income taxes receivable, $27 million, $60 million and $95 million, respectively, in property, plant and equipment, $11 million, $11 million and $5 million, respectively, in unamortized debt expense, $8 million, $8 million and $11 million, respectively, in prepayments and $7 million, $8 million and $10 million, respectively, in a non-qualified retirement plan. Additionally, the December 31, 2019 asset balance includes $80 million in right-of-use lease assets and the December 31, 2018 asset balance includes $4 million of accounts receivable and $1 million of current hedging assets. (5) Capital investments include an increase of $34 million for 2019 and a decrease of $53 million for 2018 related to the change in accrued expenditures between years. There was no impact to 2017. (6) Includes the impact of approximately eleven months of Fayetteville Shale-related E&P and midstream gathering operations which were divested in December 2018. (7) Operating income for the E&P segment includes $37 million related to restructuring charges for the year ended December 31, 2018. (8) Marketing includes a $10 million non-cash impairment related to certain non-core midstream gathering assets at December 31, 2018. (9) Operating income for the Marketing segment includes $2 million related to restructuring charges for the year ended December 31, 2018.

Condensed Consolidating Finan_2

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Condensed Consolidating Statements Of Operations	CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS  (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated Year ended December 31, 2019 Operating Revenues: Gas sales $ — $ 1,241 $ — $ — $ 1,241 Oil sales — 223 — — 223 NGL sales — 274 — — 274 Marketing — 1,297 — — 1,297 Other — 3 — — 3 — 3,038 — — 3,038 Operating Costs and Expenses: Marketing purchases — 1,320 — — 1,320 Operating expenses — 720 1 (1) 720 General and administrative expenses — 166 — — 166 Restructuring charges — 11 — — 11 Depreciation, depletion and amortization — 470 1 — 471 Impairments — 16 — — 16 Loss on sale of assets, net — 2 — — 2 Taxes, other than income taxes — 62 — — 62 — 2,767 2 (1) 2,768 Operating Income (Loss) — 271 (2) 1 270 Interest Expense, Net 65 — — — 65 Gain on Derivatives — 274 — — 274 Gain on Early Extinguishment of Debt 8 — — — 8 Other Loss, Net — (7) — — (7) Equity in Earnings of Subsidiaries 947 (2) — (945) — Income (Loss) Before Income Taxes 890 536 (2) (944) 480 Benefit from Income Taxes — (411) — — (411) Net Income (Loss) $ 890 $ 947 $ (2) $ (944) $ 891 Net Income (Loss) $ 890 $ 947 $ (2) $ (944) $ 891 Other comprehensive income 3 — — — 3 Comprehensive Income (Loss) $ 893 $ 947 $ (2) $ (944) $ 894 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 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 (loss) (5) 6 6 (12) (5) Comprehensive Income (Loss) $ 1,041 $ 1,257 $ 6 $ (1,263) $ 1,041
Condensed Consolidating Balance Sheets	CONDENSED CONSOLIDATED BALANCE SHEETS  (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated December 31, 2019 ASSETS Cash and cash equivalents $ 5 $ — $ — $ — $ 5 Accounts receivable, net — 345 — — 345 Other current assets 7 322 — — 329 Total current assets 12 667 — — 679  Intercompany receivables 7,922 — — (7,922) —  Natural gas and oil properties, using the full cost method — 25,195 55 — 25,250 Other 169 322 29 — 520 Less: Accumulated depreciation, depletion and amortization (144) (20,300) (59) — (20,503) Total property and equipment, net 25 5,217 25 — 5,267  Investments in subsidiaries (equity method) — 23 — (23) — Operating lease assets 80 79 — — 159 Deferred tax assets — 407 — — 407 Other long-term assets 19 186 — — 205 TOTAL ASSETS $ 8,058 $ 6,579 $ 25 $ (7,945) $ 6,717  LIABILITIES AND EQUITY Accounts payable $ 79 $ 446 $ — $ — $ 525 Current operating lease liabilities 8 26 — — 34 Other current liabilities 108 181 — — 289 Total current liabilities 195 653 — — 848  Intercompany payables — 7,920 2 (7,922) —  Long-term debt 2,242 — — — 2,242 Long-term operating lease liabilities 66 53 — — 119 Pension and other postretirement liabilities 43 — — — 43 Other long-term liabilities 11 208 — — 219 Negative carrying amount of subsidiaries, net 2,255 — — (2,255) — Total long-term liabilities 4,617 261 — (2,255) 2,623 Commitments and contingencies Total equity (accumulated deficit) 3,246 (2,255) 23 2,232 3,246 TOTAL LIABILITIES AND EQUITY $ 8,058 $ 6,579 $ 25 $ (7,945) $ 6,717 ໿ 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 Other 197 301 27 — 525 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 Consolidating Statements Of Cash Flows	CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated Year ended December 31, 2019 Net cash provided by (used in) operating activities $ 1,280 $ 629 $ — $ (945) $ 964 Investing activities: Capital investments (4) (1,093) (2) — (1,099) Proceeds from the sale of property and equipment — 54 — — 54 Net cash used in investing activities (4) (1,039) (2) — (1,045) Financing activities Intercompany activities (1,357) 410 2 945 — Payments on current portion of long-term debt (52) — — — (52) Payments on long-term debt (54) — — — (54) Payments on revolving credit facility (532) — — — (532) Borrowings under revolving credit facility 566 — — — 566 Change in bank drafts outstanding (19) — — — (19) Debt issuance costs (3) — — — (3) Purchase of treasury stock (21) — — — (21) Cash paid for tax withholding (1) — — — (1) Other 1 — — — 1 Net cash provided by (used in) financing activities (1,472) 410 2 945 (115) Decrease in cash and cash equivalents (196) — — — (196) Cash and cash equivalents at beginning of year 201 — — — 201 Cash and cash equivalents at end of year $ 5 $ — $ — $ — $ 5 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 Change in bank drafts outstanding 17 — — — 17 Debt issuance costs (9) — — — (9) Purchase of treasury stock (180) — — — (180) Preferred stock dividend (27) — — — (27) Cash paid for tax withholding (3) — — — (3) Net cash provided by (used in) financing activities (997) (1,976) — 676 (2,297) 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 CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated 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 Change in bank drafts outstanding 9 — — — 9 Debt issuance costs (24) — — — (24) Cash paid for tax withholding (2) — — — (2) Preferred stock dividend (16) — — — (16) Other (2) — — — (2) Net cash provided by (used in) financing activities (1,510) (96) 5 1,249 (352) 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

Supplemental Quarterly Results

Supplemental Quarterly Results (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information	(in millions, except share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter  2019 Operating revenues $ 990 $ 667 $ 636 $ 745 Operating income (loss) 213 22 (29) 64 Net income attributable to common stock 594 138 49 110 Earnings per share – Basic 1.10 0.26 0.09 0.20 Earnings per share – Diluted 1.10 0.26 0.09 0.20   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

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Line Items]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	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, 2019 and 2018: (in millions) 2019 2018 Proved properties $ 23,744 $ 22,425 Unproved properties 1,506 1,755 Total capitalized costs 25,250 24,180 Less: Accumulated depreciation, depletion and amortization (20,203) (19,761) Net capitalized costs $ 5,047 $ 4,419
Composition of Net Unevaluated Costs Excluded from Amortization	The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2019: (in millions) 2019 2018 2017 Prior Total Property acquisition costs $ 45 $ 40 $ 32 $ 1,106 $ 1,223 Exploration and development costs 53 23 16 12 104 Capitalized interest 67 47 27 38 179  $ 165 $ 110 $ 75 $ 1,156 $ 1,506
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	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) 2019 2018 2017 Unproved property acquisition costs $ 162 $ 164 $ 194 Exploration costs 2 5 22 Development costs 936 1,014 1,024 Capitalized costs incurred $ 1,100 $ 1,183 $ 1,240 Full cost pool amortization per Mcfe $ 0.56 $ 0.51 $ 0.45
Results of Operations for Oil and Gas Producing Activities Disclosure	The table below sets forth the results of operations from natural gas and oil producing activities: ໿ (in millions) 2019 2018 2017 Sales $ 1,703 $ 2,525 $ 2,086 Production (lifting) costs (781) (974) (891) Depreciation, depletion and amortization (462) (514) (440)  460 1,037 755 Provision for income taxes (1) 110 — — Results of operations (2) $ 350 $ 1,037 $ 755 (1) Prior to the recognition of a valuation allowance, in 2018 and 2017 the Company recognized income tax provisions of $254 million and $287 million, respectively. (2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 6 .
Summary of Changes in Reserves	The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2019, 2018 and 2017, all of which were located in the United States: ໿  Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) 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 Revisions of previous estimates due to price (480) (2,041) (37,492) (717) Revisions of previous estimates other than price (3) 685 3,707 65,869 1,102 Extensions, discoveries and other additions 992 6,948 26,941 1,195 Production (609) (4,696) (23,620) (778) Acquisition of reserves in place — — — — Disposition of reserves in place (2) — — (2) December 31, 2019 8,630 72,925 608,761 12,721 (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. (3) Revisions of previous estimates other than price includes 109 Bcfe of proved undeveloped reserves reclassified to unproved due to changes in the drilling plan, in accordance with the SEC five-year rule.  Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) Proved developed reserves as of: December 31, 2017 6,979 14,513 142,213 7,920 December 31, 2018 4,395 18,037 175,480 5,557 December 31, 2019 4,906 26,124 226,271 6,421 Proved undeveloped reserves as of: December 31, 2017 4,147 51,123 400,242 6,855 December 31, 2018 3,649 50,970 401,583 6,364 December 31, 2019 3,724 46,801 382,490 6,300 The following table summarizes the changes in reserves for 2017, 2018 and 2019: ໿  Appalachia Fayetteville (in Bcfe) Northeast Southwest Shale (1) Other (2) Total 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 Net revisions Price revisions (57) (660) — — (717) Performance and production revisions (3) 127 975 — — 1,102 Total net revisions 70 315 — — 385 Extensions, discoveries and other additions Proved developed 185 6 — — 191 Proved undeveloped 677 327 — — 1,004 Total reserve additions 862 333 — — 1,195 Production (459) (319) — — (778) Acquisition of reserves in place — — — — — Disposition of reserves in place (2) — — — (2) December 31, 2019 4,837 7,883 — 1 12,721 (1) The Fayetteville Shale E&P assets and associated reserves were divested in December 2018. (2) Other includes properties outside of Appalachia and Fayetteville Shale. (3) Performance and production revisions includes 109 Bcfe of proved undeveloped reserves reclassified to unproved due to changes in the drilling plan, in accordance with the SEC five-year rule.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	The following standardized measures of discounted future net cash flows relating to proved natural gas, oil and NGL reserves as of December 31, 2019, 2018 and 2017 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) 2019 2018 2017 Future cash inflows $ 27,003 $ 34,523 $ 36,576 Future production costs (14,981) (15,347) (18,390) Future development costs (1) (3,246) (4,095) (4,676) Future income tax expense (476) (2,079) (1,342) Future net cash flows 8,300 13,002 12,168 10% annual discount for estimated timing of cash flows (4,600) (7,003) (6,606) Standardized measure of discounted future net cash flows $ 3,700 $ 5,999 $ 5,562 (1) Includes abandonment costs.
Schedule of Prices used for Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	Prices used for the standardized measure above were as follows: (in millions) 2019 2018 2017 Natural gas (per MMBtu) $ 2.58 $ 3.10 $ 2.98 Oil (per Bbl) 55.69 65.56 47.79 NGLs (per Bbl) 11.58 17.64 14.41
Schedule of Analysis of Changes in Standardized Measure	Following is an analysis of changes in the standardized measure during 2019, 2018 and 2017: (in millions) 2019 2018 2017 Standardized measure, beginning of year $ 5,999 $ 5,562 $ 1,665 Sales and transfers of natural gas and oil produced, net of production costs (923) (1,564) (1,191) Net changes in prices and production costs (3,510) 2,162 1,963 Extensions, discoveries, and other additions, net of future production and development costs 234 335 1,715 Acquisition of reserves in place — — — Sales of reserves in place (2) (2,022) — Revisions of previous quantity estimates 152 361 1,721 Net change in income taxes 491 (304) (222) Changes in estimated future development costs 621 (166) (6) Previously estimated development costs incurred during the year 704 536 55 Changes in production rates (timing) and other (718) 521 (304) Accretion of discount 652 578 166 Standardized measure, end of year $ 3,700 $ 5,999 $ 5,562

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies (Narrative) (Details)	1 Months Ended			3 Months Ended			9 Months Ended	12 Months Ended
	Dec. 31, 2018USD ($)shares	Jan. 31, 2018USD ($)shares	Jan. 31, 2015shares	Mar. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Sep. 30, 2018USD ($)	Sep. 30, 2017shares	Dec. 31, 2024USD ($)	Dec. 31, 2023USD ($)	Dec. 31, 2022USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)derivative_positionsegmentsubsidiary$ / bbl$ / MMBTUshares	Dec. 31, 2018USD ($)subsidiaryderivative_position$ / bbl$ / MMBTUshares	Dec. 31, 2017USD ($)derivative_positionsubsidiary$ / bbl$ / MMBTU	Jan. 01, 2019USD ($)	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of segments | segment													2
Outstanding checks included in accounts payable	$ 34,000,000				$ 34,000,000								$ 15,000,000	$ 34,000,000
Natural gas, oil and NGL reserves discount													10.00%
Net unevaluated costs excluded from amortization, cumulative	1,755,000,000				1,755,000,000								$ 1,506,000,000	$ 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 | derivative_position													0	0	0
Impairments													$ 16,000,000	$ 171,000,000	$ 0
Preferred stock dividend		$ 27,000,000											0	27,000,000	16,000,000
Preferred stock, common shares issued as stock dividend (in shares) | shares							10,040,306
Stock repurchase, authorized amount						$ 200,000,000
Treasury stock acquired	$ 201,000,000			$ 21,000,000	$ 180,000,000								$ 21,000,000	$ 180,000,000
Treasury stock (in shares) | shares	44,000,000			5,260,687	39,061,268								5,260,687	39,061,268
Treasury stock acquired, average cost per share (in dollars per share) | $ / shares				$ 3.84	$ 4.63
Shares held in trust (in shares) | shares	10,653				10,653								5,115	10,653
Shares held in trust, shares released (in shares) | shares														20,616
Operating lease assets													$ 159,000,000
Operating lease liability													153,000,000
Marketing-Related Intangible Assets
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Amortization of intangible asset								$ 5,000,000	$ 5,000,000	$ 5,000,000	$ 8,000,000	$ 9,000,000	9,000,000	$ 9,000,000	$ 9,000,000
Intangible Assets, Current	$ 65,000,000				$ 65,000,000								$ 56,000,000	$ 65,000,000
Accounting Standards Update 2016-02
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Operating lease assets																$ 105,000,000
Operating lease liability																$ 105,000,000
Natural Gas
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Average sales price ($ per unit) | $ / MMBTU													2.58	3.10	2.98
Oil
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Average sales price ($ per unit) | $ / bbl													55.69	65.56	47.79
NGL
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Average sales price ($ per unit) | $ / bbl													11.58	17.64	14.41
Royal Dutch Shell Plc
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of subsidiaries of major customer with which business is conducted | subsidiary													0	2	2
Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued upon conversion (in shares) | shares		74,998,614
Depositary Shares
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued (in shares) | shares			34,500,000
WPX Property Acquisition
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Percentage of interest acquired																	86.00%
Discontinued operations, held-for-sale
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments						161,000,000								$ 160,000,000
Discontinued operations, held-for-sale | Marketing
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments						145,000,000								145,000,000
Discontinued operations, held-for-sale | Exploration and Production
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments						15,000,000								15,000,000
Other non-core assets
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments						$ 1,000,000							$ 16,000,000	$ 11,000,000
Customer concentration risk | Natural Gas, Oil and NGL | Sales Revenue
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Concentration percentage														10.40%	10.30%

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, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash	$ 5	$ 32
Marketable securities	0	169
Total	$ 5	$ 201

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Earnings Per Share [Line Items]
Net income									$ 891	$ 537	[1]	$ 1,046	[1]
Mandatory convertible preferred stock dividend									0	0		108
Participating securities - mandatory convertible preferred stock									0	2		123
Net Income (Loss) Attributable to Common Stock	$ 110	$ 49	$ 138	$ 594	$ 307	$ (29)	$ 51	$ 205	$ 891	$ 535		$ 815
Number of common shares:
Weighted average outstanding (in shares)									539,345,343	574,631,756		498,264,321
Weighted average and potential dilutive outstanding (in shares)									540,382,914	576,642,808		500,804,297
Basic (in dollars per share)	$ 0.20	$ 0.09	$ 0.26	$ 1.10	$ 0.54		$ 0.09	$ 0.36	$ 1.65	$ 0.93		$ 1.64
Diluted (in dollars per share)	$ 0.20	$ 0.09	$ 0.26	$ 1.10	$ 0.54	$ (0.05)	$ 0.09	$ 0.36	$ 1.65	$ 0.93		$ 1.63
Stock Options
Number of common shares:
Effect of share-based compensation (in shares)									0	0		0
Restricted Stock
Number of common shares:
Effect of share-based compensation (in shares)									361,380	698,103		1,061,056
Performance units
Number of common shares:
Effect of share-based compensation (in shares)									676,191	1,312,949		1,478,920
[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, 2019	Dec. 31, 2018	Dec. 31, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	7,077,785	12,710,152	81,244,150
Unexercised stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	5,078,253	5,909,082	116,717
Unvested share-based payment
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	1,728,264	3,692,794	5,361,849
Performance units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	271,268	642,568	765,689
Mandatory convertible preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	0	2,465,708	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, 2019	Dec. 31, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash paid during the year for interest, net of amounts capitalized	$ 58	$ 135	$ 130
Cash paid (received) during the year for income taxes	(52)	6	(5)
Increase (decrease) in noncash property additions	$ 41	$ (42)	$ 25

Restructuring Charges (Narrativ

Restructuring Charges (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jul. 31, 2019
Restructuring Cost and Reserve [Line Items]
Restructuring liability	$ 2	$ 5
Operating lease term			10 years
Fayetteville Shale
Restructuring Cost and Reserve [Line Items]
Office consolidation	6	$ 4
Restructuring liability	2
Operating lease term			10 years
Fayetteville Shale | Lease Termination
Restructuring Cost and Reserve [Line Items]
Office consolidation	$ 3

Restructuring Charges (Summary

Restructuring Charges (Summary of Restructuring Charges) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restructuring Cost and Reserve [Line Items]
Stock-based compensation	$ 8	$ 14	$ 24
Total restructuring charges	11	39	0
Non-cash curtailment gain (loss)		4
Workforce Reduction
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)		21
Stock-based compensation		0
Other benefits		0
Outplacement services, other		2
Total restructuring charges	0	23	0
Workforce Reduction | Exploration and Production
Restructuring Cost and Reserve [Line Items]
Total restructuring charges		21
Workforce Reduction | Marketing
Restructuring Cost and Reserve [Line Items]
Total restructuring charges		2
Fayetteville Shale
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)	5	12
Office consolidation	6	4
Total restructuring charges	11	16	$ 0
Non-cash curtailment gain (loss)		4
Fayetteville Shale | Exploration and Production
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	$ 11	$ 16

Restructuring Charges (Summar_2

Restructuring Charges (Summary of Liabilities Associated with Restructuring Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restructuring Reserve [Roll Forward]
Liability, at Jan 1	$ 5
Additions	11	$ 39	$ 0
Distributions	(14)
Liability at December 31	$ 2	$ 5

Divestitures (Narrative) (Detai

Divestitures (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended			3 Months Ended			6 Months Ended	12 Months Ended
	Jul. 31, 2019	Dec. 31, 2018	Aug. 31, 2018	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 03, 2018	Aug. 30, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
(Gain) loss on sale of operating assets, net									$ 2	$ (17)	$ (6)
Contractual commitments assumed by buyer							$ 108		108
Potential amount to be reimbursed to buyer									58
Liability for estimated future payments		$ 88			$ 88		46		46	88
Impairments									16	171	0
Cash paid for interest									58	135	130
Treasury stock acquired		$ 201		$ 21	$ 180				$ 21	$ 180
Treasury stock (in shares)		44,000,000		5,260,687	39,061,268				5,260,687	39,061,268
Payments for commissions		$ 1
Proceeds from sale of property and equipment									$ 54	$ 1,643	$ 10
Discontinued operations, held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments						$ 161				160
Fayetteville Shale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest prior to disposal			100.00%
Disposal Group, Including Discontinued Operation, Consideration													$ 1,865
Proceeds from sale of oil and gas property and equipment		1,650
Adjustment due to differences from economic effective date to close date		215
Gain on the sale of non-full cost pool assets		17
Reduction of full cost pool assets		887
Derivative liabilities												$ 151
(Gain) loss on sale of operating assets, net										22
Contractual commitments assumed by buyer							108		108
Liability for estimated future payments							46		46
Fayetteville Shale | Forecast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Potential amount to be reimbursed to buyer								$ 58
Other non-core assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments						1			16	11
Proceeds from sale of property and equipment									$ 38
Land
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
(Gain) loss on sale of operating assets, net	$ (2)
Proceeds from sale of property and equipment	$ 16
Senior Notes
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Repayment of debt		914
Repayments of long-term debt		900					$ 54
Cash paid for interest		$ 9
Marketing | Discontinued operations, held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments						145				145
Exploration and Production | Discontinued operations, held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments						$ 15				$ 15

Leases (Components of Lease Cos

Leases (Components of Lease Costs) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Components of lease costs:
Operating lease cost	$ 45
Short-term lease cost	45
Variable lease cost	1
Total lease cost	$ 91

Leases (Narrative) (Details)

Leases (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended
	Jul. 31, 2019	Dec. 31, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Operating lease liability		$ 153
Operating lease assets		159
Operating lease term	10 years
Payment to previous lessor	$ 6
Operating lease not yet commenced		$ 15
Accounting Standards Update 2016-02
Lessee, Lease, Description [Line Items]
Operating lease liability			$ 105
Operating lease assets			$ 105

Leases (Supplemental Informatio

Leases (Supplemental Information) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 47
Right-of-use assets obtained in exchange for operating liabilities:
Operating leases	95
Right-of-use asset balance:
Operating lease assets	159
Lease liability balance:
Current operating lease liabilities	34
Long-term operating lease liabilities	119
Total operating leases	$ 153
Operating Lease, Weighted Average Remaining Lease Term	6 years 7 months 6 days
Operating Lease, Weighted Average Discount Rate, Percent	5.33%

Leases (Maturity Analysis) (Det

Leases (Maturity Analysis) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Maturities of operating leases (ASC 842):
2020	$ 41
2021	33
2022	22
2023	19
2024	15
Thereafter	52
Total undiscounted lease liability	182
Imputed interest	(29)
Total discounted lease liability	$ 153
Maturities of operating leases (ASC 840):
2019		$ 38
2020		28
2021		14
2022		6
2023		5
Thereafter		4
Total minimum payments required		$ 95

Revenue Recognition (Narrative)

Revenue Recognition (Narrative) (Details) - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Contract asset associated with revenues from contracts with customers		$ 0
Contract liability associated with revenues from contracts with customers		$ 0
Fayetteville Shale
Disaggregation of Revenue [Line Items]
Percentage of assets sold	100.00%
Natural gas and liquids | Minimum
Disaggregation of Revenue [Line Items]
Revenue payment terms		30 days
Natural gas and liquids | Maximum
Disaggregation of Revenue [Line Items]
Revenue payment terms		60 days
Marketing | Minimum
Disaggregation of Revenue [Line Items]
Revenue payment terms		30 days
Marketing | Maximum
Disaggregation of Revenue [Line Items]
Revenue payment terms		60 days
Gas gathering | Minimum
Disaggregation of Revenue [Line Items]
Revenue payment terms		30 days
Gas gathering | Maximum
Disaggregation of Revenue [Line Items]
Revenue payment terms		60 days

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregation of Revenue by Segment) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Operating Revenues	$ 745	$ 636	$ 667	$ 990	$ 1,175	$ 951	$ 816	$ 920	$ 3,038	$ 3,862	$ 3,203
Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues									1,740	2,551	2,105
Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									1,298	1,311	1,098
Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues									1,703	2,525	2,086
Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									2,850	3,745	3,198
Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating Revenues									(1,515)	(2,408)	(2,081)
Intersegment Revenues | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues									37	26	19
Intersegment Revenues | Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									(1,552)	(2,434)	(2,100)
Gas sales
Disaggregation of Revenue [Line Items]
Operating Revenues									1,241	1,998	1,793
Gas sales | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues									1,207	1,974	1,775
Gas sales | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									0	0	0
Gas sales | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating Revenues									34	24	18
Oil sales
Disaggregation of Revenue [Line Items]
Operating Revenues									223	196	102
Oil sales | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues									220	193	101
Oil sales | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									0	0	0
Oil sales | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating Revenues									3	3	1
NGL sales
Disaggregation of Revenue [Line Items]
Operating Revenues									274	352	206
NGL sales | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues									274	353	206
NGL sales | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									0	0	0
NGL sales | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating Revenues									0	(1)	0
Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									1,297	1,222	972
Marketing | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues									0	0	0
Marketing | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									2,849	3,497	2,867
Marketing | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating Revenues									(1,552)	(2,275)	(1,895)
Marketing | Intersegment Revenues | Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									(1,600)	(2,300)	(1,900)
Gas gathering
Disaggregation of Revenue [Line Items]
Operating Revenues									0	89	126
Gas gathering | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues										0	0
Gas gathering | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues										248	331
Gas gathering | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating Revenues										(159)	(205)
Other
Disaggregation of Revenue [Line Items]
Operating Revenues									3	5	4
Other | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues									2	5	4
Other | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating Revenues									1	0	0
Other | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating Revenues									$ 0	$ 0	$ 0

Revenue Recognition (Disaggre_2

Revenue Recognition (Disaggregation of Revenue on Geographic Basis) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Operating Revenues	$ 745	$ 636	$ 667	$ 990	$ 1,175	$ 951	$ 816	$ 920	$ 3,038	$ 3,862	$ 3,203
Exploration and Production
Disaggregation of Revenue [Line Items]
Operating Revenues									1,740	2,551	2,105
Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating Revenues									1,703	2,525	2,086
Northeast Appalachia | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating Revenues									964	1,165	837
Southwest Appalachia | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating Revenues									736	817	498
Fayetteville Shale | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating Revenues									0	537	743
Other | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating Revenues									$ 3	$ 6	$ 8

Revenue Recognition (Reconcilia

Revenue Recognition (Reconciliation of Accounts Receivable) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 284	$ 494
Other accounts receivable	61	87
Total accounts receivable	$ 345	$ 581

Derivatives and Risk Manageme_3

Derivatives and Risk Management (Narrative) (Details) $ in Millions	Dec. 31, 2019USD ($)
Interest rate swap
Derivative [Line Items]
Derivative notional amount	$ 170
Commodity Contract
Derivative [Line Items]
Derivative asset (liability)	$ 155

Derivatives and Risk Manageme_4

Derivatives and Risk Management (Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value) (Details) bbl in Thousands, Mcf in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)$ / MMBTU$ / bblbblMcf
Natural Gas | Purchased
Derivative [Line Items]
Volume | Mcf	13
Fair Value	$ (1)
Natural gas storage
Derivative [Line Items]
Fair Value	$ 1
Financial protection on production - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	496
Fair Value	$ 124
Financial protection on production - 2020 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	5,402
Fair Value	$ (3)
Financial protection on production - 2020 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	5,112
Fair Value	$ 23
Fixed price swaps - 2020 | Natural Gas | Purchased
Derivative [Line Items]
Volume | Mcf	7
Average price per MMBtu and Bbls | $ / MMBTU	2.44
Fair Value	$ (1)
Fixed price swaps - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	280
Average price per MMBtu and Bbls | $ / MMBTU	2.51
Fair Value	$ 76
Fixed price swaps - 2020 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	3,465
Average price per MMBtu and Bbls | $ / bbl	57.83
Fair Value	$ (2)
Fixed price swaps - 2020 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	4,746
Average price per MMBtu and Bbls | $ / bbl	23.90
Fair Value	$ 21
Fixed price swaps - 2020 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	7,520
Average price per MMBtu and Bbls | $ / bbl	8.84
Fair Value	$ 11
Two-way costless collars - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	31
Floor price per MMBtu and Bbls | $ / MMBTU	2.56
Cap price per MMBtu and Bbls | $ / MMBTU	2.85
Fair Value	$ 6
Two-way costless collars - 2020 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	966
Cap price per MMBtu and Bbls | $ / bbl	59.81
Fair Value	$ 0
Two-way costless collars - 2020 | Not Designated as Hedging Instrument | Oil | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	56.89
Two-way costless collars - 2020 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	366
Cap price per MMBtu and Bbls | $ / bbl	29.40
Fair Value	$ 2
Two-way costless collars - 2020 | Not Designated as Hedging Instrument | Propane | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	25.20
Three-way costless collars - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	185
Cap price per MMBtu and Bbls | $ / MMBTU	3
Fair Value	$ 42
Three-way costless collars - 2020 | Not Designated as Hedging Instrument | Natural Gas | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.65
Three-way costless collars - 2020 | Not Designated as Hedging Instrument | Natural Gas | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.28
Three-way costless collars - 2020 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	971
Cap price per MMBtu and Bbls | $ / bbl	59.68
Fair Value	$ (1)
Three-way costless collars - 2020 | Not Designated as Hedging Instrument | Oil | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	55.12
Three-way costless collars - 2020 | Not Designated as Hedging Instrument | Oil | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	45.12
Financial protection on production - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	260
Fair Value	$ 7
Financial protection on production - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	3,029
Fair Value	$ (2)
Fixed Price Swaps - 2021 | Natural Gas | Purchased
Derivative [Line Items]
Volume | Mcf	6
Average price per MMBtu and Bbls | $ / MMBTU	2.44
Fair Value	$ 0
Fixed Price Swaps - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	30
Average price per MMBtu and Bbls | $ / MMBTU	2.54
Fair Value	$ 7
Fixed Price Swaps - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	1,584
Average price per MMBtu and Bbls | $ / bbl	53.20
Fair Value	$ (1)
Fixed Price Swaps - 2021 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	2,460
Average price per MMBtu and Bbls | $ / bbl	21.77
Fair Value	$ 3
Fixed Price Swaps - 2021 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	2,410
Average price per MMBtu and Bbls | $ / bbl	7.53
Fair Value	$ 0
Two-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	17
Floor price per MMBtu and Bbls | $ / MMBTU	2.50
Cap price per MMBtu and Bbls | $ / MMBTU	2.83
Three-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	213
Cap price per MMBtu and Bbls | $ / MMBTU	2.90
Three-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Natural Gas | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.53
Three-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Natural Gas | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.23
Three-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	1,445
Cap price per MMBtu and Bbls | $ / bbl	58.14
Average price per MMBtu and Bbls | $ / bbl	0
Fair Value	$ (1)
Three-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Oil | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	53.25
Three-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Oil | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	43.52
Three-way costless collars - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	31
Cap price per MMBtu and Bbls | $ / MMBTU	3.15
Fair Value	$ 2
Three-way costless collars - 2022 | Not Designated as Hedging Instrument | Natural Gas | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.69
Three-way costless collars - 2022 | Not Designated as Hedging Instrument | Natural Gas | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.30
Fixed price swaps - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	438
Average price per MMBtu and Bbls | $ / bbl	51.74
Fair Value	$ 0
Basis swaps | Natural gas storage
Derivative [Line Items]
Volume | Mcf	1
Basis swaps | Natural gas storage | Purchased
Derivative [Line Items]
Volume | Mcf	0
Fair Value	$ 0
Basis Differential | $ / MMBTU	(0.32)
Basis swaps | Natural gas storage | Sold
Derivative [Line Items]
Volume | Mcf	0
Fair Value	$ 0
Basis Differential | $ / MMBTU	(0.32)
Basis swaps | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	329
Fair Value	$ 6
Basis Swaps - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	198
Fair Value	$ 0
Basis Differential | $ / MMBTU	(0.31)
Basis Swaps - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	86
Fair Value	$ 7
Basis Differential | $ / MMBTU	0.04
Basis Swaps - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	45
Fair Value	$ (1)
Basis Differential | $ / MMBTU	(0.50)
Call Option | Natural Gas | Purchased
Derivative [Line Items]
Volume | Mcf	161
Fair Value	$ 3
Call Option | Natural Gas | Sold
Derivative [Line Items]
Volume | Mcf	361
Fair Value	$ (18)
Call Option - 2020 | Natural Gas | Purchased
Derivative [Line Items]
Volume | Mcf	104
Cap price per MMBtu and Bbls | $ / MMBTU	3.46
Fair Value	$ 1
Call Option - 2020 | Natural Gas | Sold
Derivative [Line Items]
Volume | Mcf	173
Cap price per MMBtu and Bbls | $ / MMBTU	3.24
Fair Value	$ (3)
Call Option - 2021 | Natural Gas | Purchased
Derivative [Line Items]
Volume | Mcf	57
Cap price per MMBtu and Bbls | $ / MMBTU	3.52
Fair Value	$ 2
Call Option - 2021 | Natural Gas | Sold
Derivative [Line Items]
Volume | Mcf	115
Cap price per MMBtu and Bbls | $ / MMBTU	3.33
Fair Value	$ (6)
Call Option - 2021 | Oil | Purchased
Derivative [Line Items]
Volume | bbl	0
Cap price per MMBtu and Bbls | $ / bbl	60
Fair Value	$ (1)
Call Option - 2022 | Natural Gas | Sold
Derivative [Line Items]
Volume | Mcf	58
Cap price per MMBtu and Bbls | $ / MMBTU	3
Fair Value	$ (5)
Call Option - 2023 | Natural Gas | Sold
Derivative [Line Items]
Volume | Mcf	6
Cap price per MMBtu and Bbls | $ / MMBTU	3
Fair Value	$ (1)
Call Option - 2024 | Natural Gas | Sold
Derivative [Line Items]
Volume | Mcf	9
Cap price per MMBtu and Bbls | $ / MMBTU	3
Fair Value	$ (3)
Fixed Price Swaps | Natural gas storage | Purchased
Derivative [Line Items]
Volume | Mcf	0
Average price per MMBtu and Bbls | $ / MMBTU	2.37
Fair Value	$ 0
Fixed Price Swaps | Natural gas storage | Sold
Derivative [Line Items]
Volume | Mcf	1
Average price per MMBtu and Bbls | $ / MMBTU	3.06
Fair Value	$ 1

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, 2019	Dec. 31, 2018
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative assets	$ 391	$ 191
Derivative liabilities	236	139
Not Designated as Hedging Instrument | Interest rate swap | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	1
Natural Gas | Fixed Price Swaps
Derivatives, Fair Value [Line Items]
Premium paid	9
Natural Gas | Not Designated as Hedging Instrument | Fixed Price Swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	77	32
Premium paid	9
Natural Gas | Not Designated as Hedging Instrument | Fixed Price Swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	7	6
Natural Gas | Not Designated as Hedging Instrument | Fixed Price Swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	9
Natural Gas | Not Designated as Hedging Instrument | Fixed Price Swaps | Derivative liabilities | Purchased
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	0
Natural Gas | Not Designated as Hedging Instrument | Fixed Price Swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	1
Natural Gas | Not Designated as Hedging Instrument | Two-Way Costless Collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	10	11
Natural Gas | Not Designated as Hedging Instrument | Two-Way Costless Collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	4	0
Natural Gas | Not Designated as Hedging Instrument | Two-Way Costless Collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	7
Natural Gas | Not Designated as Hedging Instrument | Two-Way Costless Collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	0
Natural Gas | Not Designated as Hedging Instrument | Three-Way Costless Collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	126	41
Natural Gas | Not Designated as Hedging Instrument | Three-Way Costless Collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	74	34
Natural Gas | Not Designated as Hedging Instrument | Three-Way Costless Collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	84	33
Natural Gas | Not Designated as Hedging Instrument | Three-Way Costless Collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	72	35
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	17	8
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	15	3
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	17	18
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	9	4
Natural Gas | Not Designated as Hedging Instrument | Call Option | Derivative assets | Purchased
Derivatives, Fair Value [Line Items]
Derivative assets	1	0
Natural Gas | Not Designated as Hedging Instrument | Call Option | Other long-term assets | Purchased
Derivatives, Fair Value [Line Items]
Derivative assets	2	6
Natural Gas | Not Designated as Hedging Instrument | Call Option | Derivative liabilities | Sold
Derivatives, Fair Value [Line Items]
Derivative liabilities	3	3
Natural Gas | Not Designated as Hedging Instrument | Call Option | Other long-term liabilities | Sold
Derivatives, Fair Value [Line Items]
Derivative liabilities	15	19
Oil | Not Designated as Hedging Instrument | Fixed Price Swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	4	13
Oil | Not Designated as Hedging Instrument | Fixed Price Swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	1	6
Oil | Not Designated as Hedging Instrument | Fixed Price Swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	6	0
Oil | Not Designated as Hedging Instrument | Fixed Price Swaps | Derivative liabilities | Purchased
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	6
Oil | Not Designated as Hedging Instrument | Fixed Price Swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	2	0
Oil | Not Designated as Hedging Instrument | Two-Way Costless Collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	5	6
Oil | Not Designated as Hedging Instrument | Two-Way Costless Collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	5
Oil | Not Designated as Hedging Instrument | Two-Way Costless Collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	5	0
Oil | Not Designated as Hedging Instrument | Two-Way Costless Collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	1
Oil | Not Designated as Hedging Instrument | Three-Way Costless Collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	3	0
Oil | Not Designated as Hedging Instrument | Three-Way Costless Collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	7	0
Oil | Not Designated as Hedging Instrument | Three-Way Costless Collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	0
Oil | Not Designated as Hedging Instrument | Three-Way Costless Collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	8	0
Oil | Not Designated as Hedging Instrument | Call Option | Other long-term liabilities | Sold
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	0
Propane | Not Designated as Hedging Instrument | Fixed Price Swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	21	11
Propane | Not Designated as Hedging Instrument | Fixed Price Swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	3	0
Propane | Not Designated as Hedging Instrument | Two-Way Costless Collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	2	0
Ethane | Not Designated as Hedging Instrument | Fixed Price Swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	11	7
Ethane | Not Designated as Hedging Instrument | Fixed Price Swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	1
Ethane | Not Designated as Hedging Instrument | Fixed Price Swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	3
Natural gas storage | Not Designated as Hedging Instrument | Fixed Price Swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	$ 1	$ 0

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, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	$ 94	$ (24)
Derivative Instrument, Settled Gain (Loss) on Derivatives	180	(94)
Total gain (loss) on derivatives	274	(118)
Fixed Price Swaps | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	46	(27)
Derivative Instrument, Settled Gain (Loss) on Derivatives	78	(32)
Fixed Price Swaps | Natural Gas | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(1)	0
Fixed Price Swaps | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(22)	19
Derivative Instrument, Settled Gain (Loss) on Derivatives	10	0
Fixed Price Swaps | Oil | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	6	(6)
Derivative Instrument, Settled Gain (Loss) on Derivatives	(3)	0
Fixed Price Swaps | Propane
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	13	11
Derivative Instrument, Settled Gain (Loss) on Derivatives	29	(6)
Fixed Price Swaps | Ethane
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	6	5
Derivative Instrument, Settled Gain (Loss) on Derivatives	17	(8)
Fixed Price Swaps | Natural gas storage
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	1	0
Fixed Price Swaps | Natural gas storage | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Settled Gain (Loss) on Derivatives	(1)	0
Two-Way Costless Collars | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	2	0
Derivative Instrument, Settled Gain (Loss) on Derivatives	16	(1)
Two-Way Costless Collars | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(10)	10
Derivative Instrument, Settled Gain (Loss) on Derivatives	6	0
Two-Way Costless Collars | Propane
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	2	0
Derivative Instrument, Settled Gain (Loss) on Derivatives	2	0
Three-Way Costless Collars | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	37	(48)
Derivative Instrument, Settled Gain (Loss) on Derivatives	31	(9)
Three-Way Costless Collars | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(2)	0
Basis swaps | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	17	10
Derivative Instrument, Settled Gain (Loss) on Derivatives	(3)	(31)
Call Option | Natural Gas | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(3)	4
Derivative Instrument, Settled Gain (Loss) on Derivatives	(1)	2
Amortization of premium paid	1	1
Call Option | Natural Gas | Sold
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	4	(4)
Derivative Instrument, Settled Gain (Loss) on Derivatives	(1)	(7)
Call Option | Oil | Sold
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	(1)	0
Derivative Instrument, Settled Gain (Loss) on Derivatives	0	(2)
Interest rate swap
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Unsettled Gain (Loss) on Derivatives	$ (1)	$ 2

Reclassifications from Accumu_3

Reclassifications from Accumulated Other Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ 2,362	$ 1,979	$ 917
Other comprehensive loss before reclassifications	(5)
Amounts reclassified from other comprehensive income	8
Net current-period other comprehensive income	3	8	(5)
Ending balance	3,246	2,362	1,979
Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(36)	(44)	(39)
Net current-period other comprehensive income	3	8	(5)
Ending balance	(33)	(36)	$ (44)
Pension and Other Postretirement
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(22)
Other comprehensive loss before reclassifications	(5)
Amounts reclassified from other comprehensive income	8
Net current-period other comprehensive income	3
Ending balance	(19)	(22)
Foreign Currency
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(14)
Other comprehensive loss before reclassifications	0
Amounts reclassified from other comprehensive income	0
Net current-period other comprehensive income	0
Ending balance	$ (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	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other income, net	$ 7	$ 0		$ (5)
Provision (benefit) for income taxes	(411)	1		(93)
Net income	(891)	$ (537)	[1]	$ (1,046)	[1]
Reclassified from Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income	8
Pension and Other Postretirement | Reclassified from Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other income, net	10
Provision (benefit) for income taxes	(2)
Net income	$ 8
[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, 2019	Dec. 31, 2018	Dec. 31, 2017	Jul. 31, 2018	Jul. 31, 2016	Jan. 31, 2015
Debt Instrument [Line Items]
Stated interest rate		7.75%
Impairments		$ 16	$ 171	$ 0
Nonrecurring
Debt Instrument [Line Items]
Impairments			161
Other non-core assets
Debt Instrument [Line Items]
Impairments	$ 1	16	11
Other non-core assets | Nonrecurring
Debt Instrument [Line Items]
Impairments		16	1
Carrying value of non core assets		$ 26
Marketing | Nonrecurring
Debt Instrument [Line Items]
Impairments			145
Exploration and Production | Nonrecurring
Debt Instrument [Line Items]
Impairments			$ 15
Senior Notes | 4.05% Senior Notes Due January 2020
Debt Instrument [Line Items]
Stated interest rate		4.05%	4.05%		5.30%	5.80%	4.05%
Senior Notes | 4.10% Senior Notes Due January March 2022
Debt Instrument [Line Items]
Stated interest rate		4.10%

Fair Value Measurements (Carryi

Fair Value Measurements (Carrying Amount and Estimated Fair Values of Financial Instruments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	$ 155	$ 52
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	5	201
Revolving credit facility	34	0
Derivative instruments, net	155	52
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	5	201
Revolving credit facility	34	0
Derivative instruments, net	155	52
Senior Notes | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	2,228	2,342
Senior Notes | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	2,085	$ 2,190
Natural Gas | Fixed Price Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid	$ 9

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, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	$ 155	$ 52
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	0	0
Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	155	52
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	0	0
Fixed Price Swaps | Natural Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	84	38
Derivative liabilities	(1)	(10)
Premium paid	9
Fixed Price Swaps | Natural Gas | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(1)
Fixed Price Swaps | Natural Gas | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Fixed Price Swaps | Natural Gas | Quoted Prices in Active Markets for Identical Assets (Level 1) | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Fixed Price Swaps | Natural Gas | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	84	38
Derivative liabilities	(1)	(10)
Fixed Price Swaps | Natural Gas | Significant Observable Inputs (Level 2) | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(1)
Fixed Price Swaps | Natural Gas | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Fixed Price Swaps | Natural Gas | Significant Unobservable Inputs (Level 3) | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Fixed Price Swaps | Oil
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5	19
Derivative liabilities	(8)
Fixed Price Swaps | Oil | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(6)
Fixed Price Swaps | Oil | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0
Fixed Price Swaps | Oil | Quoted Prices in Active Markets for Identical Assets (Level 1) | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		0
Fixed Price Swaps | Oil | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5	19
Derivative liabilities	(8)
Fixed Price Swaps | Oil | Significant Observable Inputs (Level 2) | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(6)
Fixed Price Swaps | Oil | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0
Fixed Price Swaps | Oil | Significant Unobservable Inputs (Level 3) | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		0
Fixed Price Swaps | Propane
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	24	11
Fixed Price Swaps | Propane | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Fixed Price Swaps | Propane | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	24	11
Fixed Price Swaps | Propane | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Fixed Price Swaps | Ethane
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	11	8
Derivative liabilities		(3)
Fixed Price Swaps | Ethane | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities		0
Fixed Price Swaps | Ethane | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	11	8
Derivative liabilities		(3)
Fixed Price Swaps | Ethane | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities		0
Fixed Price Swaps | Natural gas storage
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1
Fixed Price Swaps | Natural gas storage | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Fixed Price Swaps | Natural gas storage | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1
Fixed Price Swaps | Natural gas storage | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Two-Way Costless Collars | Natural Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	14	11
Derivative liabilities	(8)	(7)
Two-Way Costless Collars | Natural Gas | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Two-Way Costless Collars | Natural Gas | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	14	11
Derivative liabilities	(8)	(7)
Two-Way Costless Collars | Natural Gas | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Two-Way Costless Collars | Oil
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5	11
Derivative liabilities	(5)	(1)
Two-Way Costless Collars | Oil | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Two-Way Costless Collars | Oil | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5	11
Derivative liabilities	(5)	(1)
Two-Way Costless Collars | Oil | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Two-Way Costless Collars | Propane
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2
Two-Way Costless Collars | Propane | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Two-Way Costless Collars | Propane | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2
Two-Way Costless Collars | Propane | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Three-Way Costless Collars | Natural Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	200	75
Derivative liabilities	(156)	(68)
Three-Way Costless Collars | Natural Gas | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Three-Way Costless Collars | Natural Gas | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	200	75
Derivative liabilities	(156)	(68)
Three-Way Costless Collars | Natural Gas | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Three-Way Costless Collars | Oil
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	10
Derivative liabilities	(12)
Three-Way Costless Collars | Oil | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Derivative liabilities	0
Three-Way Costless Collars | Oil | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	10
Derivative liabilities	(12)
Three-Way Costless Collars | Oil | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Derivative liabilities	0
Basis swaps | Natural Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	32	11
Derivative liabilities	(26)	(22)
Basis swaps | Natural Gas | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Basis swaps | Natural Gas | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	32	11
Derivative liabilities	(26)	(22)
Basis swaps | Natural Gas | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Interest rate swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		1
Interest rate swap | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Interest rate swap | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		1
Interest rate swap | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Call Option | Natural Gas | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3	6
Call Option | Natural Gas | Sold
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(18)	(22)
Call Option | Natural Gas | Quoted Prices in Active Markets for Identical Assets (Level 1) | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Call Option | Natural Gas | Quoted Prices in Active Markets for Identical Assets (Level 1) | Sold
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Call Option | Natural Gas | Significant Observable Inputs (Level 2) | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3	6
Call Option | Natural Gas | Significant Observable Inputs (Level 2) | Sold
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(18)	(22)
Call Option | Natural Gas | Significant Unobservable Inputs (Level 3) | Purchased
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Call Option | Natural Gas | Significant Unobservable Inputs (Level 3) | Sold
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	$ 0
Call Option | Oil | Sold
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(1)
Call Option | Oil | Quoted Prices in Active Markets for Identical Assets (Level 1) | Sold
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Call Option | Oil | Significant Observable Inputs (Level 2) | Sold
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(1)
Call Option | Oil | Significant Unobservable Inputs (Level 3) | Sold
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	$ 0

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, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of year	$ 0	$ 22
Included in earnings	0	(17)
Settlements	0	1
Transfers into/out of Level 3	0	(6)
Balance at end of period	0	0
Change in gains (losses) included in earnings relating to derivatives still held as of December 31	0	0
Natural Gas | Call Option | Purchased
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Amortization of premium paid	$ 1	$ 1

Debt (Components of Debt) (Deta

Debt (Components of Debt) (Details) - USD ($) $ in Millions	1 Months Ended
	Jul. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Jul. 31, 2018	Jan. 31, 2015
Debt Instrument [Line Items]
Debt Instrument		$ 2,262	$ 2,342
Unamortized Issuance Expense		(19)	(23)
Unamortized Debt Discount		(1)	(1)
Total		$ 2,242	2,318
Stated interest rate		7.75%
Debt issuance costs, line of credit		$ 11	11
Line of Credit | 2018 Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility, variable interest rate		4.31%
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Debt Instrument		$ 34
Unamortized Issuance Expense		0
Unamortized Debt Discount		0
Total		$ 34
Senior Notes | LIBOR
Debt Instrument [Line Items]
Increase in basis spread	1.75%
Senior Notes | 4.05% Senior Notes Due January 2020
Debt Instrument [Line Items]
Debt Instrument			52
Unamortized Issuance Expense			0
Unamortized Debt Discount			0
Total			$ 52
Stated interest rate	5.80%	4.05%	4.05%	5.30%	4.05%
Senior Notes | 4.10% Senior Notes Due January March 2022
Debt Instrument [Line Items]
Debt Instrument		$ 213	$ 213
Unamortized Issuance Expense		(1)	(1)
Unamortized Debt Discount		0	0
Total		$ 212	212
Stated interest rate		4.10%
Senior Notes | 4.95% Senior Notes Due January 2025
Debt Instrument [Line Items]
Debt Instrument		$ 892	927
Unamortized Issuance Expense		(5)	(7)
Unamortized Debt Discount		(1)	(1)
Total		$ 886	919
Stated interest rate	6.70%	4.95%		6.20%	4.95%
Senior Notes | 7.50% Senior Notes Due April 2026
Debt Instrument [Line Items]
Debt Instrument		$ 639	650
Unamortized Issuance Expense		(7)	(8)
Unamortized Debt Discount		0	0
Total		$ 632	642
Stated interest rate		7.50%
Senior Notes | 7.75% Senior Notes Due October 2027
Debt Instrument [Line Items]
Debt Instrument		$ 484	500
Unamortized Issuance Expense		(6)	(7)
Unamortized Debt Discount		0	0
Total		$ 478	493
Stated interest rate		7.75%
Term Loan | 2018 Term Loan Facility Due April 2023
Debt Instrument [Line Items]
Debt Instrument			0
Unamortized Issuance Expense			0
Unamortized Debt Discount			0
Total			$ 0
Debt variable rate			3.92%

Debt (Schedule of Debt Maturiti

Debt (Schedule of Debt Maturities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Long-term Debt, Fiscal Year Maturity [Abstract]
2020	$ 0
2021	0
2022	213
2023	0
2024	34
Thereafter	2,015
Total	$ 2,262	$ 2,342

Debt (2016 Credit Facility - Na

Debt (2016 Credit Facility - Narrative) (Details) - USD ($)	Apr. 26, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jun. 30, 2016	Dec. 31, 2013
Debt Instrument [Line Items]
Debt Instrument		$ 2,262,000,000	$ 2,342,000,000
Extinguishment of debt	$ 1,191,000,000
Gain (Loss) on Early Extinguishment of Debt		8,000,000	(17,000,000)	$ (70,000,000)
Unamortized debt expense		$ 19,000,000	$ 23,000,000
2013 Revolving Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity					$ 66,000,000
2016 Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity					1,934,000,000
Line of Credit | 2013 Revolving Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity						$ 2,000,000,000
Line of Credit | 2016 Revolving Credit Facility Maturing December 2020 | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity					743,000,000
Unamortized debt expense	4,000,000
Term Loan | 2016 Term Loan Due December 2020
Debt Instrument [Line Items]
Debt Instrument					$ 1,191,000,000
Gain (Loss) on Early Extinguishment of Debt	$ (8,000,000)

Debt (2018 Revolving Credit Fac

Debt (2018 Revolving Credit Facility - Narrative) (Details) - USD ($)	1 Months Ended	12 Months Ended
	Apr. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Oct. 08, 2019
Debt Instrument [Line Items]
Subsidiary ownership		100.00%	100.00%
Letters of credit outstanding		$ 172,000,000
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 3,500,000,000
Current borrowing capacity	2,000,000,000			$ 2,100,000,000
Debt instrument limit of securing indebtedness	$ 2,000,000,000
Debt instrument limit of securing indebtedness, percent of consolidated net tangible assets	25.00%
Minimum current ratio	1
Leverage ratio, percentage of credit limit	10.00%
Leverage ratio, amount of credit limit	$ 150,000,000
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | June 30, 2018 Through March 31, 2019
Debt Instrument [Line Items]
Leverage ratio	4.50
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | June 30, 2019 Through March 31, 2020
Debt Instrument [Line Items]
Leverage ratio	4.25
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | On Or After June 30, 2020
Debt Instrument [Line Items]
Leverage ratio	4
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | Eurodollar | Minimum
Debt Instrument [Line Items]
Basis points	1.50%
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | Eurodollar | Maximum
Debt Instrument [Line Items]
Basis points	2.50%
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | Base Rate | Minimum
Debt Instrument [Line Items]
Basis points	0.50%
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | Base Rate | Maximum
Debt Instrument [Line Items]
Basis points	1.50%

Debt (Senior Notes - Narrative)

Debt (Senior Notes - Narrative) (Details) - USD ($)	Apr. 26, 2018	Dec. 31, 2019	Dec. 31, 2018	Jul. 31, 2016	Jan. 31, 2015	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jul. 31, 2018	Dec. 31, 2015
Debt Instrument [Line Items]
Stated interest rate		7.75%				7.75%	7.75%
Gain (Loss) on Early Extinguishment of Debt							$ 8,000,000	$ (17,000,000)	$ (70,000,000)
Extinguishment of debt	$ 1,191,000,000
Senior Notes
Debt Instrument [Line Items]
Gain (Loss) on Early Extinguishment of Debt			$ (9,000,000)			$ 8,000,000
Payment of premiums			2,000,000
Repayments of long-term debt			$ 900,000,000			$ 54,000,000
Senior Notes | LIBOR
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%
Senior Notes | 4.05% Senior Notes Due January 2020
Debt Instrument [Line Items]
Senior notes											$ 850,000,000
Stated interest rate		4.05%	4.05%	5.80%	4.05%	4.05%	4.05%	4.05%		5.30%
Debt stated interest rate cap				6.05%
Debt repurchased face amount			$ 40,000,000					$ 40,000,000
Extinguishment of debt		$ 52,000,000
Senior Notes | 4.95% Senior Notes Due January 2025
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 stated interest rate cap				6.95%
Debt repurchased face amount		$ 35,000,000	73,000,000			$ 35,000,000	$ 35,000,000	73,000,000
Senior Notes | 4.10% Senior Notes Due January March 2022
Debt Instrument [Line Items]
Stated interest rate		4.10%				4.10%	4.10%
Debt repurchased face amount			$ 787,000,000					$ 787,000,000
Senior Notes | 7.75% Senior Notes Due October 2027
Debt Instrument [Line Items]
Stated interest rate		7.75%				7.75%	7.75%
Debt repurchased face amount		$ 16,000,000				$ 16,000,000	$ 16,000,000
Senior Notes | 7.50% Senior Notes Due April 2026
Debt Instrument [Line Items]
Stated interest rate		7.50%				7.50%	7.50%
Debt repurchased face amount		$ 11,000,000				$ 11,000,000	$ 11,000,000

Commitments and Contingencies_2

Commitments and Contingencies (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)caselease	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Commitments And Contingencies [Line Items]
Obligation under transportation agreements	$ 8,470,000
Guarantee obligations relative to the firms transportation agreements and gathering project and services	293,000
Contractual commitments assumed by buyer	108,000
Potential amount to be reimbursed to buyer	58,000
Liability for estimated future payments	46,000		$ 88,000
Maturities of operating leases (ASC 842):
2020	41,000
2021	33,000
2022	22,000
2023	19,000
2024	15,000
Thereafter	52,000
Obligation under transportation, 1 to 3 years	1,235,000
Obligation under transportation, 3 to 5 years	1,169,000
Obligation under transportation, 5 to 8 years	1,739,000
Obligation under transportation, more than 8 years	3,559,000
Indemnification liability	$ 0
Appalachian Basin
Commitments And Contingencies [Line Items]
Obligation under transportation agreements		$ 357,000
Maturities of operating leases (ASC 842):
Obligation under transportation agreements, reimbursed by seller		$ 133,000
Arkansas Royalty Litigation
Maturities of operating leases (ASC 842):
Number of cases | case	3
Arkansas Royalty Litigation | Arkansas State Court
Maturities of operating leases (ASC 842):
Number of cases | case	2
Regulatory Approval and or Construction Subsequently Cancelled
Commitments And Contingencies [Line Items]
Obligation under transportation agreements	$ 512,000
Maturities of operating leases (ASC 842):
Other commitment term	17 years
Obligation under transportation, 1 to 3 years	$ 6,000
Obligation under transportation, 3 to 5 years	68,000
Obligation under transportation, 5 to 8 years	102,000
Obligation under transportation, more than 8 years	336,000
Pressure Pumping Equipment | Exploration and Production
Commitments And Contingencies [Line Items]
Aggregate annual lease payment	$ 6,000
Drilling Rigs | Exploration and Production
Commitments And Contingencies [Line Items]
Number of leases | lease	7
Aggregate annual lease payment	$ 13,000
Office Space, Vehicles And Equipment
Maturities of operating leases (ASC 842):
2020	33,000
2021	24,000
2022	18,000
2023	16,000
2024	12,000
Thereafter	45,000
Compression Rentals
Maturities of operating leases (ASC 842):
2020	13,000
2021	13,000
2022	9,000
2023	2,000
Access Capacity on Future Projects Concentration Risk
Commitments And Contingencies [Line Items]
Obligation under transportation agreements	$ 1,100,000

Commitments and Contingencies_3

Commitments and Contingencies (Schedule of Future Obligation under Transportation Agreements) (Details) $ in Millions	Dec. 31, 2019USD ($)
Other Commitments [Line Items]
Total	$ 8,470
Less than 1 year	768
1 to 3 years	1,235
3 to 5 years	1,169
5 to 8 years	1,739
Obligation under transportation, more than 8 years	3,559
Infrastructure Currently in Service
Other Commitments [Line Items]
Total	7,414
Less than 1 year	767
1 to 3 years	1,200
3 to 5 years	1,066
5 to 8 years	1,531
Obligation under transportation, more than 8 years	2,850
Pending Regulatory Approval and/or Construction
Other Commitments [Line Items]
Total	1,056
Less than 1 year	1
1 to 3 years	35
3 to 5 years	103
5 to 8 years	208
Obligation under transportation, more than 8 years	$ 709

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Effective tax rate	(86.00%)	0.00%	(10.00%)
Corporate income tax rate	21.00%
Alternative minimum tax carryforward, expected refund	$ 30,000,000
Income tax refund received	1,000,000
Income taxes paid		$ 6,300,000
Release of valuation allowance in 2019	(522,000,000)
Change in valuation allowance	(522,000,000)	$ (121,000,000)	$ (364,000,000)
Operating loss carryforward valuation allowance	87,000,000
Unrecognized tax benefits that would impact effective tax rate	0
Statutory depletion carryforward
Income Taxes [Line Items]
Tax credit carryforward	13,000,000
Interest deduction carryforward
Income Taxes [Line Items]
Tax credit carryforward	29,000,000
Exploration Program in Canada
Income Taxes [Line Items]
Net operating loss carryforward	29,000,000
Federal
Income Taxes [Line Items]
Net operating loss carryforward	3,000,000,000
Statel
Income Taxes [Line Items]
Net operating loss carryforward	$ 2,300,000,000

Income Taxes (Provision (Benefi

Income Taxes (Provision (Benefit) for Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current:
Federal	$ (1)	$ (5)	$ (22)
State	(1)	6	0
Total Current	(2)	1	(22)
Deferred:
Federal	(431)	0	(71)
State	22	0	0
Total Deferred	(409)	0	(71)
Provision (benefit) for income taxes	$ (411)	$ 1	$ (93)

Income Taxes (Reconciliation of

Income Taxes (Reconciliation of Provision for Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Expected provision at federal statutory rate	$ 101	$ 113	$ 333
Decrease resulting from:
State income taxes, net of federal income tax effect	11	13	16
Rate impacts due to tax reform	0	0	370
Changes to valuation allowance due to tax reform	0	0	(370)
AMT tax reform impact – valuation allowance release	0	0	(68)
Changes in uncertain tax positions	0	0	(5)
Change in valuation allowance	(522)	(121)	(364)
Removal of sequestration fee on AMT receivables	0	(5)	0
Other	(1)	1	(5)
Provision (benefit) for income taxes	$ (411)	$ 1	$ (93)

Income Taxes (Components of Def

Income Taxes (Components of Deferred Tax Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred tax liabilities:
Differences between book and tax basis of property	$ 312	$ 226
Derivative activity	34	12
Right of use lease assets	37	0
Other	2	2
Total deferred tax liabilities	385	240
Deferred tax assets
Accrued compensation	33	33
Accrued pension costs	9	10
Asset retirement obligations	13	15
Net operating loss carryforward	769	777
Future lease payments	37	0
Other	18	14
Total deferred tax assets	879	849
Valuation allowance	(87)	(609)
Net deferred tax asset	$ 407	$ 0

Income Taxes (Reconciliation _2

Income Taxes (Reconciliation of Changes to the Valuation Allowance) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Deferred Tax Asset, Valuation Allowance [Roll Forward]
Valuation allowance as of December 31, 2018	$ 609
Release of valuation allowance in 2019	(522)
Valuation allowance as of December 31, 2019	$ 87

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, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at beginning of year	$ 7	$ 12
Additions based on tax positions related to the current year	0	0
Additions to tax positions of prior years	0	0
Reductions to tax positions of prior years	(7)	(5)
Unrecognized tax benefits at end of year	$ 0	$ 7

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at January 1	$ 61	$ 165
Accretion of discount	3	9
Obligations incurred	2	1
Obligations settled/removed	(9)	(116)
Revisions of estimates	0	2
Asset retirement obligation at December 31	57	61
Current liability			$ 6	$ 6
Long-term liability			51	55
Asset retirement obligation at December 31	$ 57	165	$ 57	$ 61
Asset Divestitures
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Obligations settled/removed		(111)
Fayetteville Shale
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Obligations settled/removed		$ (107)

Retirement and Employee Benef_3

Retirement and Employee Benefit Plans (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan cost	$ 2	$ 3		$ 3
Contributions capitalized	1	2		2
Non-cash curtailment gain (loss)		4
Lump-sum payment	21
Defined benefit plan included in accumulated other comprehensive (income) loss, before tax	30	34
Defined benefit plan included in accumulated other comprehensive (income) loss after tax	22	20
Change in value of pension and postretirement in AOCI	3	8	[1]	(11)	[1]
Expected future net loss	1
Company's expected additional annual contribution	13
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-cash curtailment gain (loss)	0	0		0
Settlement loss	6	0		0
Change in value of pension and postretirement in AOCI	4	4
Employer contributions	12	12
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-cash curtailment gain (loss)	0	4		0
Settlement loss	0	0		$ 0
Change in value of pension and postretirement in AOCI	(1)	2
Employer contributions	$ 2	$ 1
[1]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at January 1	$ 125	$ 143
Service cost	7	10	$ 9
Interest cost	5	5	5
Participant contributions	0	0
Actuarial loss (gain)	15	(14)
Benefits paid	(2)	(14)
Plan amendments	0	0
Curtailments	0	(5)
Settlements	(24)	0
Benefit obligation at December 31	126	125	143
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at January 1	91	101
Actual return on plan assets	16	(8)
Employer contributions	12	12
Participant contributions	0	0
Benefits paid	(2)	(14)
Settlements	(21)	0
Fair value of plan assets at December 31	96	91	101
Funded status of plans at December 31	(30)	(34)
Other Postretirement Benefits
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at January 1	13	17
Service cost	1	2	2
Interest cost	0	1	0
Participant contributions	0	0
Actuarial loss (gain)	1	0
Benefits paid	(2)	(1)
Plan amendments	0	0
Curtailments	0	(6)
Settlements	0	0
Benefit obligation at December 31	13	13	17
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at January 1	0	0
Actual return on plan assets	0	0
Employer contributions	2	1
Participant contributions	0	0
Benefits paid	(2)	(1)
Settlements	0	0
Fair value of plan assets at December 31	0	0	$ 0
Funded status of plans at December 31	$ (13)	$ (13)

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, 2019	Dec. 31, 2018
Retirement Benefits [Abstract]
Projected benefit obligation	$ 126	$ 125
Accumulated benefit obligation	124	122
Fair value of plan assets	$ 96	$ 91

Retirement and Employee Benef_6

Retirement and Employee Benefit Plans (Pension and Other Postretirement Benefit Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Curtailment (gain) loss		$ (4)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 7	10	$ 9
Interest cost	5	5	5
Expected return on plan assets	(6)	(7)	(6)
Amortization of transition obligation	0	0	0
Amortization of prior service cost	0	0	0
Amortization of net loss	2	2	2
Net periodic benefit cost	8	10	10
Curtailment (gain) loss	0	0	0
Settlement loss	6	0	0
Net periodic benefit cost	14	10	10
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	2	2
Interest cost	0	1	0
Expected return on plan assets	0	0	0
Amortization of transition obligation	0	0	0
Amortization of prior service cost	0	0	0
Amortization of net loss	0	0	0
Net periodic benefit cost	1	3	2
Curtailment (gain) loss	0	(4)	0
Settlement loss	0	0	0
Net periodic benefit cost	$ 1	$ (1)	$ 2

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, 2019	Dec. 31, 2018		Dec. 31, 2017	[1]
Defined Benefit Plan Disclosure [Line Items]
Total change in value of pension and postretirement liabilities	$ 3	$ 8	[1]	$ (11)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss arising during the year	(5)	(2)
Amortization of prior service cost	0	0
Amortization of net loss	2	2
Settlements	8	0
Curtailments	0	5
Tax effect	(1)	(1)
Total change in value of pension and postretirement liabilities	4	4
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss arising during the year	(1)	0
Amortization of prior service cost	0	0
Amortization of net loss	0	0
Settlements	0	0
Curtailments	0	3
Tax effect	0	(1)
Total change in value of pension and postretirement liabilities	$ (1)	$ 2
[1]	In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Retirement and Employee Benef_8

Retirement and Employee Benefit Plans (Schedule of Assumptions Used - Benefit Obligations) (Details)	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.50%	3.50%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.70%	4.35%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.50%	4.35%

Retirement and Employee Benef_9

Retirement and Employee Benefit Plans (Schedule of Assumptions Used - Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.70%	4.35%	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
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.35%	4.35%	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, 2019	Dec. 31, 2018
Retirement Benefits [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	2037	2036

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, 2019USD ($)
Retirement Benefits [Abstract]
Effect on the total service and interest cost components, 1% increase	$ 2
Effect on the total service and interest cost components, 1% decrease	(1)
Effect on postretirement benefit obligations, 1% Increase	2
Effect on postretirement benefit obligation, 1% Decrease	$ (2)

Retirement and Employee Bene_12

Retirement and Employee Benefit Plans (Schedule of Expected Benefit Payments) (Details) $ in Millions	Dec. 31, 2019USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2020	$ 5
2021	5
2022	6
2023	6
2024	7
Years 2025-2029	34
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2020	1
2021	1
2022	1
2023	1
2024	1
Years 2025-2029	$ 5

Retirement and Employee Bene_13

Retirement and Employee Benefit Plans (Schedule of Allocation of Plan Assets) (Details) - Pension Benefits	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	100.00%
Actual asset allocations	100.00%
Equity securities, US equity
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	35.00%
Actual asset allocations	34.00%
Equity securities, Non-U.S. developed equity
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	35.00%
Actual asset allocations	33.00%
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	28.00%
Actual asset allocations	31.00%
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	2.00%
Actual asset allocations	2.00%

Retirement and Employee Bene_14

Retirement and Employee Benefit Plans (Fair Value Measurement of Pension Plan Assets) (Details) - Pension Benefits - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 96	$ 91	$ 101
Cash and cash equivalents | Fayetteville Shale
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	21
Excluding Net Asset Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	67	72
Excluding Net Asset Value | Equity securities, U.S. large cap growth equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	5
Excluding Net Asset Value | Equity securities, U.S. large cap value equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6	5
Excluding Net Asset Value | Equity securities, U.S. small cap equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	2
Excluding Net Asset Value | Non-U.S. equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	32	20
Excluding Net Asset Value | Emerging markets equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		3
Excluding Net Asset Value | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22	14
Excluding Net Asset Value | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	23
Quoted Prices in Active Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	67	72
Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities, U.S. large cap growth equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	5
Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities, U.S. large cap value equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6	5
Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities, U.S. small cap equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	2
Quoted Prices in Active Markets for Identical Assets (Level 1) | Non-U.S. equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	32	20
Quoted Prices in Active Markets for Identical Assets (Level 1) | Emerging markets equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		3
Quoted Prices in Active Markets for Identical Assets (Level 1) | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22	14
Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	23
Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Observable Inputs (Level 2) | Equity securities, U.S. large cap growth equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Observable Inputs (Level 2) | Equity securities, U.S. large cap value equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Observable Inputs (Level 2) | Equity securities, U.S. small cap equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Observable Inputs (Level 2) | Non-U.S. equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Observable Inputs (Level 2) | Emerging markets equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Significant Observable Inputs (Level 2) | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Observable Inputs (Level 2) | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3) | Equity securities, U.S. large cap growth equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3) | Equity securities, U.S. large cap value equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3) | Equity securities, U.S. small cap equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3) | Non-U.S. equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3) | Emerging markets equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Significant Unobservable Inputs (Level 3) | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3) | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Net Asset Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	29	19
Net Asset Value | Equity securities, U.S. large cap growth equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3
Net Asset Value | Equity securities, U.S. large cap core equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18	12
Net Asset Value | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 8	$ 7

Stock-Based Compensation (Narra

Stock-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options, exercised, number of options (in shares)	0	0	0
Weighted-average grant-date fair value of options granted (in dollars per share)			$ 3.47
2013 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares	88,700,000
Period of service for immediate vesting upon death, disability or retirement	3 years
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	3 years
Expiration period from date of grant	7 years
Increase (decrease) in deferred tax asset	$ (1)	$ 1	$ 1
Equity-classified awards, unrecognized compensation cost	$ 1
Equity-classified awards, weighted average period over which unrecognized cost is recognized, years	1 year
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	4 years
Increase (decrease) in deferred tax asset	$ (1)	2	9
Equity-classified awards, unrecognized compensation cost	$ 6
Equity-classified awards, weighted average period over which unrecognized cost is recognized, years	1 year
Total fair value of restricted stock grants	$ 2	2	42
Total fair value of shares vested	$ 11	19	18
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	3 years
Increase (decrease) in deferred tax asset	$ 1	1	$ 3
Equity-classified awards, unrecognized compensation cost	$ 1
Equity-classified awards, weighted average period over which unrecognized cost is recognized, years	1 year
Performance units | Cliff Vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	3 years
Liability-Classified RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in deferred tax asset	$ 1	2
Liability-classified restricted stock, vesting period	4 years
Liability-classified restricted stock, unrecognized compensation cost	$ 24
Liability-classified restricted stock, weighted average period over which unrecognized cost is recognized, years	3 years
Liability-Classified Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in deferred tax asset	$ (1)	$ 1
Liability-classified performance units, vesting period	3 years
Liability-classified performance units, unrecognized compensation cost	$ 6
Liability-classified performance units, weighted average period over which unrecognized cost is recognized, years	2 years

Stock-Based Compensation (Sched

Stock-Based Compensation (Schedule of Equity-Classified Stock Option Stock-Based Compensation Costs) (Details) - Stock Options - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity-classified awards - expensed	$ 1	$ 2	$ 3
Equity-classified awards - capitalized	$ 0	$ 0	$ 1

Stock-Based Compensation (Sch_2

Stock-Based Compensation (Schedule of Equity-Classified Valuation Assumptions) (Details) - Stock Options	12 Months Ended
	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.90%
Expected dividend yield	0.00%
Expected volatility	50.50%
Expected term	5 years

Stock-Based Compensation (Summa

Stock-Based Compensation (Summary of Equity-Classified Stock Option Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Number of Shares
Number of Options, Outstanding at January 1 (in shares)	5,178,000	6,020,000	5,416,000
Number of Options, Granted (in shares)	0	0	1,604,000
Number of Options, Exercised (in shares)	0	0	0
Number of Options, Forfeited or expired (in shares)	(543,000)	(842,000)	(1,000,000)
Number of Options, Outstanding at December 31 (in shares)	4,635,000	5,178,000	6,020,000
Weighted Average Exercise Price
Weighted Average Exercise Price, Outstanding at January 1 (in dollars per share)	$ 17.06	$ 19.43	$ 23.46
Weighted Average Exercise Price, Granted (in dollars per share)	0	0	8
Weighted Average Exercise Price, Exercised (in dollars per share)	0	0	0
Weighted Average Exercise Price, Forfeited or expired (in dollars per share)	32.38	33.99	22.93
Weighted Average Exercise Price, Outstanding at December 31 (in dollars per share)	$ 15.26	$ 17.06	$ 19.43

Stock-Based Compensation (Sum_2

Stock-Based Compensation (Summary of Equity-Classified Stock Options Outstanding and Options Exercisable) (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Outstanding - Options Outstanding at December 31, 2019 (in shares)	4,635	5,178	6,020	5,416
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 15.26	$ 17.06	$ 19.43	$ 23.46
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	2 years 10 months 24 days
Options Exercisable - Options Exercisable at December 31, 2019 (in shares)	4,213
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 16.01
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	2 years 9 months 18 days
Range of Exercise Prices $5.22-$29.42
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit (in dollars per share)	$ 5.22
Range of Exercise Prices, Upper Range Limit (in dollars per share)	$ 29.42
Options Outstanding - Options Outstanding at December 31, 2019 (in shares)	3,467
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 8.63
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	3 years 4 months 24 days
Options Exercisable - Options Exercisable at December 31, 2019 (in shares)	3,045
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 8.74
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	3 years 3 months 18 days
Range of Exercise Prices $30.59-$35.64
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit (in dollars per share)	$ 30.59
Range of Exercise Prices, Upper Range Limit (in dollars per share)	$ 35.64
Options Outstanding - Options Outstanding at December 31, 2019 (in shares)	644
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 30.60
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	1 year 10 months 24 days
Options Exercisable - Options Exercisable at December 31, 2019 (in shares)	644
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 30.60
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	1 year 10 months 24 days
Range of Exercise Prices $38.20-$38.97
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit (in dollars per share)	$ 38.20
Range of Exercise Prices, Upper Range Limit (in dollars per share)	$ 38.97
Options Outstanding - Options Outstanding at December 31, 2019 (in shares)	434
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 38.97
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	10 months 24 days
Options Exercisable - Options Exercisable at December 31, 2019 (in shares)	434
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 38.97
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	10 months 24 days
Range of Exercise Prices $46.55-$46.55
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit (in dollars per share)	$ 46.55
Range of Exercise Prices, Upper Range Limit (in dollars per share)	$ 46.55
Options Outstanding - Options Outstanding at December 31, 2019 (in shares)	90
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 46.55
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	1 year 4 months 24 days
Options Exercisable - Options Exercisable at December 31, 2019 (in shares)	90
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 46.55
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	1 year 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 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	$ 6	$ 9	$ 16
Equity-classified awards - capitalized	$ 4	$ 5	$ 11

Stock-Based Compensation (Sum_3

Stock-Based Compensation (Summary of Equity-Classified Restricted Stock Activity) (Details) - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	2,717,000	6,254,000	3,321,000
Number of Shares/Units, Granted (in shares)	493,000	350,000	5,055,000
Number of Shares/Units, Vested (in shares)	(1,516,000)	(2,058,000)	(1,380,000)
Number of Shares/Units, Forfeited (in shares)	(214,000)	(1,829,000)	(742,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	1,480,000	2,717,000	6,254,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 7.91	$ 8.85	$ 11.85
Weighted Average Fair Value, Granted (in dollars per share)	3.06	4.72	8.38
Weighted Average Fair Value, Vested (in dollars per share)	7.16	9.24	13.28
Weighted Average Fair Value, Forfeited (in dollars per share)	8.38	9.01	10.04
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 7	$ 7.91	$ 8.85
Workforce Reduction
Number of Shares
Number of Shares/Units, Forfeited (in shares)	(65,196)	(1,287,636)

Stock-Based Compensation (Sch_4

Stock-Based Compensation (Schedule of Equity-Classified Performance Units Stock-Based Compensation Costs) (Details) - Performance units - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	$ 1	$ 3	$ 5
Equity-classified awards - capitalized	$ 0	$ 1	$ 2

Stock-Based Compensation (Sum_4

Stock-Based Compensation (Summary of Equity-Classified Performance Units Activity) (Details) - Performance units - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	598,000	1,084,000	719,000
Number of Shares/Units, Granted (in shares)	0	0	1,197,000
Number of Shares/Units, Vested (in shares)	(378,000)	(290,000)	(325,000)
Number of Shares/Units, Forfeited (in shares)	(42,000)	(196,000)	(507,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	178,000	598,000	1,084,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 10.01	$ 10.12	$ 11.46
Weighted Average Fair Value, Granted (in dollars per share)	0	0	10.47
Weighted Average Fair Value, Vested (in dollars per share)	9.59	10.47	12.21
Weighted Average Fair Value, Forfeited (in dollars per share)	10.47	9.94	9.53
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 10.47	$ 10.01	$ 10.12
Vesting period for stock awards from grant date	3 years
Cliff Vesting
Weighted Average Fair Value
Vesting period for stock awards from grant date	3 years
Workforce Reduction
Number of Shares
Number of Shares/Units, Forfeited (in shares)	(41,761)	(144,927)

Stock-Based Compensation (Sch_5

Stock-Based Compensation (Schedule of Liability-Classified Restricted Stock Units Stock-Based Compensation Costs) (Details) - Liability-Classified RSUs - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Liability-classified stock-based compensation cost - expensed	$ 7	$ 4
Liability-classified stock-based compensation cost - capitalized	$ 5	$ 3

Stock-Based Compensation (Sum_5

Stock-Based Compensation (Summary of Liability-Classified Restricted Stock Unit Activity) (Details) - Liability-Classified RSUs - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Number of Units
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	8,202,000	0
Number of Shares/Units, Granted (in shares)	8,659,000	12,216,000
Number of Shares/Units, Vested (in shares)	(2,624,000)	(232,000)
Number of Shares/Units, Forfeited (in shares)	(1,245,000)	(3,782,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	12,992,000	8,202,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 3.41	$ 0
Weighted Average Fair Value, Granted (in dollars per share)	4.34	3.69
Weighted Average Fair Value, Vested (in dollars per share)	4.09	5.14
Weighted Average Fair Value, Forfeited (in dollars per share)	3.48	4.86
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 2.42	$ 3.41
Workforce Reduction
Number of Units
Number of Shares/Units, Forfeited (in shares)	(400,056)	(2,766,610)

Stock-Based Compensation (Sch_6

Stock-Based Compensation (Schedule of Liability-Classified Performance Units Stock-Based Compensation Costs) (Details) - Liability-Classified Performance Units - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Liability-classified stock-based compensation cost - expensed	$ 2	$ 2
Liability-classified stock-based compensation cost - capitalized	$ 1	$ 0

Stock-Based Compensation (Sum_6

Stock-Based Compensation (Summary of Liability-Classified Performance Unit Activity) (Details) - Liability-Classified Performance Units - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Number of Units
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	2,803,000	0
Number of Shares/Units, Granted (in shares)	2,757,000	3,200,000
Number of Shares/Units, Vested (in shares)	(43,000)	0
Number of Shares/Units, Forfeited (in shares)	(375,000)	(397,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	5,142,000	2,803,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 3.41	$ 0
Weighted Average Fair Value, Granted (in dollars per share)	4.34	3.70
Weighted Average Fair Value, Vested (in dollars per share)	2.42	0
Weighted Average Fair Value, Forfeited (in dollars per share)	3.12	4.55
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 2.42	$ 3.41
Workforce Reduction
Number of Units
Number of Shares/Units, Forfeited (in shares)	(375,086)	(295,160)

Segment Information (Details)

Segment Information (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenues from external customers	$ 745,000,000	$ 636,000,000	$ 667,000,000	$ 990,000,000	$ 1,175,000,000	$ 951,000,000	$ 816,000,000	$ 920,000,000	$ 3,038,000,000	$ 3,862,000,000	$ 3,203,000,000
Depreciation, depletion and amortization expense									471,000,000	560,000,000	504,000,000
Impairments									16,000,000	171,000,000	0
Operating income (loss)	64,000,000	$ (29,000,000)	$ 22,000,000	$ 213,000,000	352,000,000	$ 66,000,000	$ 124,000,000	$ 255,000,000	270,000,000	797,000,000	731,000,000
Interest expense									65,000,000	124,000,000	135,000,000
Gain (loss) on derivatives									274,000,000	(118,000,000)	422,000,000
Loss on early extinguishment of debt									8,000,000	(17,000,000)	(70,000,000)
Other income (loss), net									(7,000,000)	0	5,000,000
Provision (benefit) for income taxes									(411,000,000)	1,000,000	(93,000,000)
Assets	6,717,000,000				5,797,000,000				6,717,000,000	5,797,000,000	7,521,000,000
Capital investments									1,140,000,000	1,248,000,000	1,293,000,000
Restructuring charges									11,000,000	39,000,000	0
Cash and cash equivalents	5,000,000				201,000,000				5,000,000	201,000,000
Property plant and equipment	5,267,000,000				4,656,000,000				5,267,000,000	4,656,000,000
Unamortized debt expense	19,000,000				23,000,000				19,000,000	23,000,000
Operating lease assets	159,000,000								159,000,000
Derivative assets	278,000,000				130,000,000				278,000,000	130,000,000
Increase (decrease) in accrued expenditures between periods									34,000,000	(53,000,000)	0
Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									1,297,000,000	1,222,000,000	972,000,000
Exploration and Production
Segment Reporting Information [Line Items]
Revenues from external customers									1,740,000,000	2,551,000,000	2,105,000,000
Depreciation, depletion and amortization expense											440,000,000
Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									1,298,000,000	1,311,000,000	1,098,000,000
Depreciation, depletion and amortization expense											64,000,000
Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Revenues from external customers									1,703,000,000	2,525,000,000	2,086,000,000
Depreciation, depletion and amortization expense									462,000,000	514,000,000
Impairments									13,000,000	15,000,000
Operating income (loss)									283,000,000	794,000,000	549,000,000
Interest expense									65,000,000	124,000,000	135,000,000
Gain (loss) on derivatives									274,000,000	(118,000,000)	421,000,000
Loss on early extinguishment of debt									0	0	0
Other income (loss), net									(9,000,000)	2,000,000	4,000,000
Provision (benefit) for income taxes									(411,000,000)	1,000,000	(93,000,000)
Assets	6,235,000,000				4,872,000,000				6,235,000,000	4,872,000,000	5,109,000,000
Capital investments									1,138,000,000	1,231,000,000	1,248,000,000
Restructuring charges									11,000,000	37,000,000
Operating Segments | Exploration and Production | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									0	0	0
Operating Segments | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									2,850,000,000	3,745,000,000	3,198,000,000
Depreciation, depletion and amortization expense									9,000,000	46,000,000
Impairments									3,000,000	155,000,000
Operating income (loss)									(13,000,000)	4,000,000	183,000,000
Interest expense									0	0	0
Gain (loss) on derivatives									0	0	1,000,000
Loss on early extinguishment of debt									0	0	0
Other income (loss), net									0	(2,000,000)	1,000,000
Provision (benefit) for income taxes									0	0	0
Assets	314,000,000				539,000,000				314,000,000	539,000,000	1,288,000,000
Capital investments									0	9,000,000	32,000,000
Restructuring charges										2,000,000
Operating Segments | Marketing | Non Core Gathering Assets
Segment Reporting Information [Line Items]
Impairments										10,000,000
Operating Segments | Marketing | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									2,849,000,000	3,497,000,000	2,867,000,000
Intersegment Revenues
Segment Reporting Information [Line Items]
Revenues from external customers									(1,515,000,000)	(2,408,000,000)	(2,081,000,000)
Intersegment Revenues | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									(1,552,000,000)	(2,275,000,000)	(1,895,000,000)
Intersegment Revenues | Exploration and Production
Segment Reporting Information [Line Items]
Revenues from external customers									37,000,000	26,000,000	19,000,000
Intersegment Revenues | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									(1,552,000,000)	(2,434,000,000)	(2,100,000,000)
Intersegment Revenues | Marketing | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									(1,600,000,000)	(2,300,000,000)	(1,900,000,000)
Other
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization expense									0	0	0
Impairments									0	1,000,000
Operating income (loss)									0	(1,000,000)	(1,000,000)
Interest expense									0	0	0
Gain (loss) on derivatives									0	0	0
Loss on early extinguishment of debt									8,000,000	(17,000,000)	(70,000,000)
Other income (loss), net									2,000,000	0	0
Provision (benefit) for income taxes									0	0	0
Assets	168,000,000				386,000,000				168,000,000	386,000,000	1,124,000,000
Capital investments									2,000,000	8,000,000	13,000,000
Cash and cash equivalents	5,000,000				205,000,000				5,000,000	205,000,000	914,000,000
Income taxes receivable	30,000,000				89,000,000				30,000,000	89,000,000	89,000,000
Property plant and equipment	27,000,000				60,000,000				27,000,000	60,000,000	95,000,000
Unamortized debt expense	11,000,000				11,000,000				11,000,000	11,000,000	5,000,000
Prepayments	8,000,000				8,000,000				8,000,000	8,000,000	11,000,000
Assets for non-qualified retirement plan	7,000,000				8,000,000				7,000,000	8,000,000	$ 10,000,000
Operating lease assets	$ 80,000,000								$ 80,000,000
Accounts receivable, net					4,000,000					4,000,000
Derivative assets					$ 1,000,000					$ 1,000,000

Condensed Consolidating Finan_3

Condensed Consolidating Financial Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Condensed Financial Information Disclosure [Abstract]
Subsidiary ownership	100.00%	100.00%

Condensed Consolidating Finan_4

Condensed Consolidating Financial Information (Condensed Consolidating Statement of Operations) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Condensed Income Statements, Captions [Line Items]
Operating Revenues	$ 745	$ 636	$ 667	$ 990	$ 1,175	$ 951	$ 816	$ 920	$ 3,038	$ 3,862		$ 3,203
Operating expenses									720	785		671
General and administrative expenses									166	209		233
Restructuring charges									11	39		0
Depreciation, depletion and amortization									471	560		504
Impairments									16	171		0
(Gain) loss on sale of operating assets, net									2	(17)		(6)
Taxes, other than income taxes									62	89		94
Total Operating Costs and Expenses									2,768	3,065		2,472
Operating Income	64	(29)	22	213	352	66	124	255	270	797		731
Interest Expense, Net									65	124		135
Gain (Loss) on Derivatives									274	(118)		422
Gain (Loss) on Early Extinguishment of Debt									8	(17)		(70)
Other Income (Loss), Net									(7)	0		5
Equity in Earnings of Subsidiaries									0	0		0
Income (Loss) Before Income Taxes									480	538		953
Provision (benefit) for income taxes									(411)	1		(93)
Net Income (Loss)									891	537	[1]	1,046	[1]
Mandatory convertible preferred stock dividend									0	0		108
Participating securities - mandatory convertible preferred stock									0	2		123
Net Income (Loss) Attributable to Common Stock	$ 110	$ 49	$ 138	$ 594	$ 307	$ (29)	$ 51	$ 205	891	535		815
Other comprehensive loss									3	8		(5)
Comprehensive income									894	545	[1]	1,041	[1]
Eliminations
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Operating expenses									(1)	0		0
General and administrative expenses									0	0		0
Restructuring charges									0	0
Depreciation, depletion and amortization									0	0		0
Impairments									0	0
(Gain) loss on sale of operating assets, net									0	0		0
Taxes, other than income taxes									0	0		0
Total Operating Costs and Expenses									(1)	0		0
Operating Income									1	0		0
Interest Expense, Net									0	0		0
Gain (Loss) on Derivatives									0	0		0
Gain (Loss) on Early Extinguishment of Debt									0	0		0
Other Income (Loss), Net									0			0
Equity in Earnings of Subsidiaries									(945)	(678)		(1,251)
Income (Loss) Before Income Taxes									(944)	(678)		(1,251)
Provision (benefit) for income taxes									0	0		0
Net Income (Loss)									(944)	(678)		(1,251)
Mandatory convertible preferred stock dividend												0
Participating securities - mandatory convertible preferred stock										0		0
Net Income (Loss) Attributable to Common Stock										(678)		(1,251)
Other comprehensive loss									0	0		(12)
Comprehensive income									(944)	(678)		(1,263)
Parent | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Operating expenses									0	0		0
General and administrative expenses									0	0		0
Restructuring charges									0	0
Depreciation, depletion and amortization									0	0		0
Impairments									0	0
(Gain) loss on sale of operating assets, net									0	0		0
Taxes, other than income taxes									0	0		0
Total Operating Costs and Expenses									0	0		0
Operating Income									0	0		0
Interest Expense, Net									65	124		135
Gain (Loss) on Derivatives									0	0		0
Gain (Loss) on Early Extinguishment of Debt									8	(17)		(70)
Other Income (Loss), Net									0			0
Equity in Earnings of Subsidiaries									947	678		1,251
Income (Loss) Before Income Taxes									890	537		1,046
Provision (benefit) for income taxes									0	0		0
Net Income (Loss)									890	537		1,046
Mandatory convertible preferred stock dividend												108
Participating securities - mandatory convertible preferred stock										2		123
Net Income (Loss) Attributable to Common Stock										535		815
Other comprehensive loss									3	8		(5)
Comprehensive income									893	545		1,041
Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									3,038	3,862		3,203
Operating expenses									720	785		671
General and administrative expenses									166	209		233
Restructuring charges									11	39
Depreciation, depletion and amortization									470	560		504
Impairments									16	171
(Gain) loss on sale of operating assets, net									2	(17)		(6)
Taxes, other than income taxes									62	89		94
Total Operating Costs and Expenses									2,767	3,065		2,472
Operating Income									271	797		731
Interest Expense, Net									0	0		0
Gain (Loss) on Derivatives									274	(118)		422
Gain (Loss) on Early Extinguishment of Debt									0	0		0
Other Income (Loss), Net									(7)			5
Equity in Earnings of Subsidiaries									(2)	0		0
Income (Loss) Before Income Taxes									536	679		1,158
Provision (benefit) for income taxes									(411)	1		(93)
Net Income (Loss)									947	678		1,251
Mandatory convertible preferred stock dividend												0
Participating securities - mandatory convertible preferred stock										0		0
Net Income (Loss) Attributable to Common Stock										678		1,251
Other comprehensive loss									0	0		6
Comprehensive income									947	678		1,257
Non-Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Operating expenses									1	0		0
General and administrative expenses									0	0		0
Restructuring charges									0	0
Depreciation, depletion and amortization									1	0		0
Impairments									0	0
(Gain) loss on sale of operating assets, net									0	0		0
Taxes, other than income taxes									0	0		0
Total Operating Costs and Expenses									2	0		0
Operating Income									(2)	0		0
Interest Expense, Net									0	0		0
Gain (Loss) on Derivatives									0	0		0
Gain (Loss) on Early Extinguishment of Debt									0	0		0
Other Income (Loss), Net									0			0
Equity in Earnings of Subsidiaries									0	0		0
Income (Loss) Before Income Taxes									(2)	0		0
Provision (benefit) for income taxes									0	0		0
Net Income (Loss)									(2)	0		0
Mandatory convertible preferred stock dividend												0
Participating securities - mandatory convertible preferred stock										0		0
Net Income (Loss) Attributable to Common Stock										0		0
Other comprehensive loss									0	0		6
Comprehensive income									(2)	0		6
Gas sales
Condensed Income Statements, Captions [Line Items]
Operating Revenues									1,241	1,998		1,793
Gas sales | Eliminations
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Gas sales | Parent | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Gas sales | Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									1,241	1,998		1,793
Gas sales | Non-Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Oil sales
Condensed Income Statements, Captions [Line Items]
Operating Revenues									223	196		102
Oil sales | Eliminations
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Oil sales | Parent | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Oil sales | Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									223	196		102
Oil sales | Non-Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
NGL sales
Condensed Income Statements, Captions [Line Items]
Operating Revenues									274	352		206
NGL sales | Eliminations
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
NGL sales | Parent | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
NGL sales | Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									274	352		206
NGL sales | Non-Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Marketing
Condensed Income Statements, Captions [Line Items]
Operating Revenues									1,297	1,222		972
Marketing | Eliminations
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Marketing | Parent | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Marketing | Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									1,297	1,222		972
Marketing | Non-Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Gas gathering
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	89		126
Gas gathering | Eliminations
Condensed Income Statements, Captions [Line Items]
Operating Revenues										0		0
Gas gathering | Parent | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues										0		0
Gas gathering | Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues										89		126
Gas gathering | Non-Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues										0		0
Other
Condensed Income Statements, Captions [Line Items]
Operating Revenues									3	5		4
Other | Eliminations
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Other | Parent | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Other | Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									3	5		4
Other | Non-Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Operating Revenues									0	0		0
Marketing purchases
Condensed Income Statements, Captions [Line Items]
Marketing purchases									1,320	1,229		976
Marketing purchases | Eliminations
Condensed Income Statements, Captions [Line Items]
Marketing purchases									0	0		0
Marketing purchases | Parent | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Marketing purchases									0	0		0
Marketing purchases | Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Marketing purchases									1,320	1,229		976
Marketing purchases | Non-Guarantors | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Marketing purchases									$ 0	$ 0		$ 0
[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, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
ASSETS
Cash and cash equivalents	$ 5	$ 201
Accounts receivable, net	345	581
Other current assets	329	174
Total current assets	679	956
Intercompany receivables	0	0
Natural gas and oil properties, using the full cost method	25,250	24,180
Other	520	525
Less: Accumulated depreciation, depletion and amortization	(20,503)	(20,049)
Total property and equipment, net	5,267	4,656
Investments in subsidiaries (equity method)	0	0
Operating lease assets	159
Deferred tax assets	407	0
Other long-term assets	205	185
TOTAL ASSETS	6,717	5,797	$ 7,521
LIABILITIES AND EQUITY
Accounts payable	525	609
Current operating lease liabilities	34
Other current liabilities	289	237
Total current liabilities	848	846
Intercompany payables	0	0
Long-term debt	2,242	2,318
Long-term operating lease liabilities	119
Pension and other postretirement liabilities	43	46
Other long-term liabilities	219	225
Negative carrying amount of subsidiaries, net	0	0
Total long-term liabilities	2,623	2,589
Commitments and contingencies
Total equity	3,246	2,362	$ 1,979	$ 917
TOTAL LIABILITIES AND EQUITY	6,717	5,797
Reportable Legal Entities | Parent
ASSETS
Cash and cash equivalents	5	201
Accounts receivable, net	0	4
Other current assets	7	8
Total current assets	12	213
Intercompany receivables	7,922	7,932
Natural gas and oil properties, using the full cost method	0	0
Other	169	197
Less: Accumulated depreciation, depletion and amortization	(144)	(154)
Total property and equipment, net	25	43
Investments in subsidiaries (equity method)	0	0
Operating lease assets	80
Deferred tax assets	0
Other long-term assets	19	19
TOTAL ASSETS	8,058	8,207
LIABILITIES AND EQUITY
Accounts payable	79	113
Current operating lease liabilities	8
Other current liabilities	108	115
Total current liabilities	195	228
Intercompany payables	0	0
Long-term debt	2,242	2,318
Long-term operating lease liabilities	66
Pension and other postretirement liabilities	43	46
Other long-term liabilities	11	54
Negative carrying amount of subsidiaries, net	2,255	3,199
Total long-term liabilities	4,617	5,617
Total equity	3,246	2,362
TOTAL LIABILITIES AND EQUITY	8,058	8,207
Reportable Legal Entities | Guarantors
ASSETS
Cash and cash equivalents	0	0
Accounts receivable, net	345	577
Other current assets	322	166
Total current assets	667	743
Intercompany receivables	0	0
Natural gas and oil properties, using the full cost method	25,195	24,128
Other	322	301
Less: Accumulated depreciation, depletion and amortization	(20,300)	(19,840)
Total property and equipment, net	5,217	4,589
Investments in subsidiaries (equity method)	23	24
Operating lease assets	79
Deferred tax assets	407
Other long-term assets	186	166
TOTAL ASSETS	6,579	5,522
LIABILITIES AND EQUITY
Accounts payable	446	496
Current operating lease liabilities	26
Other current liabilities	181	122
Total current liabilities	653	618
Intercompany payables	7,920	7,932
Long-term debt	0	0
Long-term operating lease liabilities	53
Pension and other postretirement liabilities	0	0
Other long-term liabilities	208	171
Negative carrying amount of subsidiaries, net	0	0
Total long-term liabilities	261	171
Total equity	(2,255)	(3,199)
TOTAL LIABILITIES AND EQUITY	6,579	5,522
Reportable Legal Entities | Non-Guarantors
ASSETS
Cash and cash equivalents	0	0
Accounts receivable, net	0	0
Other current assets	0	0
Total current assets	0	0
Intercompany receivables	0	0
Natural gas and oil properties, using the full cost method	55	52
Other	29	27
Less: Accumulated depreciation, depletion and amortization	(59)	(55)
Total property and equipment, net	25	24
Investments in subsidiaries (equity method)	0	0
Operating lease assets	0
Deferred tax assets	0
Other long-term assets	0	0
TOTAL ASSETS	25	24
LIABILITIES AND EQUITY
Accounts payable	0	0
Current operating lease liabilities	0
Other current liabilities	0	0
Total current liabilities	0	0
Intercompany payables	2	0
Long-term debt	0	0
Long-term operating lease liabilities	0
Pension and other postretirement liabilities	0	0
Other long-term liabilities	0	0
Negative carrying amount of subsidiaries, net	0	0
Total long-term liabilities	0	0
Total equity	23	24
TOTAL LIABILITIES AND EQUITY	25	24
Eliminations
ASSETS
Cash and cash equivalents	0	0
Accounts receivable, net	0	0
Other current assets	0	0
Total current assets	0	0
Intercompany receivables	(7,922)	(7,932)
Natural gas and oil properties, using the full cost method	0	0
Other	0	0
Less: Accumulated depreciation, depletion and amortization	0	0
Total property and equipment, net	0	0
Investments in subsidiaries (equity method)	(23)	(24)
Operating lease assets	0
Deferred tax assets	0
Other long-term assets	0	0
TOTAL ASSETS	(7,945)	(7,956)
LIABILITIES AND EQUITY
Accounts payable	0	0
Current operating lease liabilities	0
Other current liabilities	0	0
Total current liabilities	0	0
Intercompany payables	(7,922)	(7,932)
Long-term debt	0	0
Long-term operating lease liabilities	0
Pension and other postretirement liabilities	0	0
Other long-term liabilities	0	0
Negative carrying amount of subsidiaries, net	(2,255)	(3,199)
Total long-term liabilities	(2,255)	(3,199)
Total equity	2,232	3,175
TOTAL LIABILITIES AND EQUITY	$ (7,945)	$ (7,956)

Condensed Consolidating Finan_6

Condensed Consolidating Financial Information (Condensed Consolidating Statements of Cash Flows) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		$ 964	$ 1,223	$ 1,097
Investing activities:
Capital investments		(1,099)	(1,290)	(1,268)
Proceeds from sale of property and equipment		54	1,643	10
Other		0	6	6
Net cash provided by (used in) investing activities		(1,045)	359	(1,252)
Financing activities
Intercompany activities		0	0	0
Payments on current portion of long-term debt		(52)	0	(328)
Payments on long-term debt		(54)	(2,095)	(1,139)
Payments on revolving credit facility		(532)	(1,983)	0
Borrowings under revolving credit facility		566	1,983	0
Change in bank drafts outstanding		(19)	17	9
Debt issuance costs		(3)	(9)	(24)
Proceeds from issuance of long-term debt		0	0	1,150
Purchase of treasury stock		(21)	(180)	0
Cash paid for tax withholding		(1)	(3)	(2)
Preferred stock dividend	$ (27)	0	(27)	(16)
Other		1	0	(2)
Net cash used in financing activities		(115)	(2,297)	(352)
Decrease in cash and cash equivalents		(196)	(715)	(507)
Cash and cash equivalents at beginning of year	916	201	916	1,423
Cash and cash equivalents at end of year		5	201	916
Reportable Legal Entities | Parent
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		1,280	304	1,019
Investing activities:
Capital investments		(4)	(20)	(13)
Proceeds from sale of property and equipment		0	0	1
Other			0	1
Net cash provided by (used in) investing activities		(4)	(20)	(11)
Financing activities
Intercompany activities		(1,357)	1,300	(1,158)
Payments on current portion of long-term debt		(52)		(328)
Payments on long-term debt		(54)	(2,095)	(1,139)
Payments on revolving credit facility		(532)	(1,983)
Borrowings under revolving credit facility		566	1,983
Change in bank drafts outstanding		(19)	17	9
Debt issuance costs		(3)	(9)	(24)
Proceeds from issuance of long-term debt				1,150
Purchase of treasury stock		(21)	(180)
Cash paid for tax withholding		(1)	(3)	(2)
Preferred stock dividend			(27)	(16)
Other		1		(2)
Net cash used in financing activities		(1,472)	(997)	(1,510)
Decrease in cash and cash equivalents		(196)	(713)	(502)
Cash and cash equivalents at beginning of year	914	201	914	1,416
Cash and cash equivalents at end of year		5	201	914
Reportable Legal Entities | Guarantors
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		629	1,595	1,327
Investing activities:
Capital investments		(1,093)	(1,270)	(1,250)
Proceeds from sale of property and equipment		54	1,643	9
Other			6	5
Net cash provided by (used in) investing activities		(1,039)	379	(1,236)
Financing activities
Intercompany activities		410	(1,976)	(96)
Payments on current portion of long-term debt		0		0
Payments on long-term debt		0	0	0
Payments on revolving credit facility		0	0
Borrowings under revolving credit facility		0	0
Change in bank drafts outstanding		0	0	0
Debt issuance costs		0	0	0
Proceeds from issuance of long-term debt				0
Purchase of treasury stock		0	0
Cash paid for tax withholding		0	0	0
Preferred stock dividend			0	0
Other		0		0
Net cash used in financing activities		410	(1,976)	(96)
Decrease in cash and cash equivalents		0	(2)	(5)
Cash and cash equivalents at beginning of year	2	0	2	7
Cash and cash equivalents at end of year		0	0	2
Reportable Legal Entities | Non-Guarantors
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		0	0	0
Investing activities:
Capital investments		(2)	0	(5)
Proceeds from sale of property and equipment		0	0	0
Other			0	0
Net cash provided by (used in) investing activities		(2)	0	(5)
Financing activities
Intercompany activities		2	0	5
Payments on current portion of long-term debt		0		0
Payments on long-term debt		0	0	0
Payments on revolving credit facility		0	0
Borrowings under revolving credit facility		0	0
Change in bank drafts outstanding		0	0	0
Debt issuance costs		0	0	0
Proceeds from issuance of long-term debt				0
Purchase of treasury stock		0	0
Cash paid for tax withholding		0	0	0
Preferred stock dividend			0	0
Other		0		0
Net cash used in financing activities		2	0	5
Decrease in cash and cash equivalents		0	0	0
Cash and cash equivalents at beginning of year	0	0	0	0
Cash and cash equivalents at end of year		0	0	0
Eliminations
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		(945)	(676)	(1,249)
Investing activities:
Capital investments		0	0	0
Proceeds from sale of property and equipment		0	0	0
Other			0	0
Net cash provided by (used in) investing activities		0	0	0
Financing activities
Intercompany activities		945	676	1,249
Payments on current portion of long-term debt		0		0
Payments on long-term debt		0	0	0
Payments on revolving credit facility		0	0
Borrowings under revolving credit facility		0	0
Change in bank drafts outstanding		0	0	0
Debt issuance costs		0	0	0
Proceeds from issuance of long-term debt				0
Purchase of treasury stock		0	0
Cash paid for tax withholding		0	0	0
Preferred stock dividend			0	0
Other		0		0
Net cash used in financing activities		945	676	1,249
Decrease in cash and cash equivalents		0	0	0
Cash and cash equivalents at beginning of year	$ 0	0	0	0
Cash and cash equivalents at end of year		$ 0	$ 0	$ 0

Subsequent Events (Details)

Subsequent Events (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)
Subsequent Event | Forecast
Subsequent Event [Line Items]
Severance Costs	$ 9

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Operating Revenues	$ 745	$ 636	$ 667	$ 990	$ 1,175	$ 951	$ 816	$ 920	$ 3,038	$ 3,862	$ 3,203
Operating income	64	(29)	22	213	352	66	124	255	270	797	731
Net income (loss) attributable to common stock	$ 110	$ 49	$ 138	$ 594	$ 307	$ (29)	$ 51	$ 205	$ 891	$ 535	$ 815
Earnings (loss) per share: -Basic	$ 0.20	$ 0.09	$ 0.26	$ 1.10	$ 0.54		$ 0.09	$ 0.36	$ 1.65	$ 0.93	$ 1.64
Earnings (loss) per share - Diluted	$ 0.20	$ 0.09	$ 0.26	$ 1.10	$ 0.54	$ (0.05)	$ 0.09	$ 0.36	$ 1.65	$ 0.93	$ 1.63

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures (Narrative) (Details) Mcfe in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)Mcfelocation	Dec. 31, 2018USD ($)Mcfelocation	Dec. 31, 2017USD ($)Mcfelocation	Dec. 31, 2016Mcfe
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	$ 1,506	$ 1,755
Capitalized interest	179
Capitalized interest based on weighted average cost of borrowings	109	115	$ 113
Capitalized internal costs related to acquisition, exploration and development	$ 77	$ 90	$ 99
Percentage of present worth of proved reserves evaluated in audit	99.00%	99.00%	99.00%
Proved reserves, end of period, (bcfe) | Mcfe	12,721	11,921	14,775	5,253
Proved undeveloped reverses (energy) | Mcfe	929	190	1,375
Number of locations | location	90	30	330
Present value of proved reserves, discounted basis	$ 50	$ 24	$ 124
Natural gas, oil and NGL reserves discount	10.00%
Proved reserves, committed development period	5 years
Undeveloped Properties Southwest Appalachia
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	$ 1,200
Undeveloped Properties Northeast Appalachia
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	10
Wells In Progress
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	95
Capitalized interest	$ 179
United States
Natural Gas and Oil Properties [Line Items]
Proved reserves, end of period, (bcfe) | Mcfe	12,721	11,921	14,775	5,253
Proved undeveloped reverses (energy) | Mcfe	6,300	6,364	6,855

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, 2019	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved properties	$ 23,744	$ 22,425
Unproved properties	1,506	1,755
Total capitalized costs	25,250	24,180
Less: Accumulated depreciation, depletion and amortization	(20,203)	(19,761)
Net capitalized costs	$ 5,047	$ 4,419

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			156 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost [Abstract]
Property acquisition costs	$ 45	$ 40	$ 32	$ 1,106
Exploration and development costs	53	23	16	12
Capitalized interest	67	47	27	38
Net unevaluated costs excluded from amortization	165	110	$ 75	$ 1,156
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Property acquisition costs	1,223
Exploration and development costs	104
Capitalized interest	179
Net unevaluated costs excluded from amortization, cumulative	$ 1,506	$ 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, 2019USD ($)$ / Mcfe	Dec. 31, 2018USD ($)$ / Mcfe	Dec. 31, 2017USD ($)$ / Mcfe
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Unproved property acquisition costs	$ 162	$ 164	$ 194
Exploration costs	2	5	22
Development costs	936	1,014	1,024
Capitalized costs incurred	$ 1,100	$ 1,183	$ 1,240
Full cost pool amortization per Mcfe | $ / Mcfe	0.56	0.51	0.45

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Sales	$ 1,703	$ 2,525	$ 2,086
Production (lifting) costs	(781)	(974)	(891)
Depreciation, depletion and amortization	(462)	(514)	(440)
Results of operations - income before income taxes	460	1,037	755
Provision (benefit) for income taxes	110	0	0
Results of operations	$ 350	1,037	755
Income tax expense, before valuation allowance		$ 254	$ 287

Supplemental Oil and Gas Disc_8

Supplemental Oil and Gas Disclosures (Summary of Changes in Reserves - United States) (Details) Mcfe in Millions, Mcf in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019McfeMcfbbl	Dec. 31, 2019McfeMcfbbl	Dec. 31, 2019USD ($)McfeMcfbbl	Dec. 31, 2019McfeMcfbbl	Dec. 31, 2018USD ($)McfebblMcf	Dec. 31, 2017McfebblMcf	Dec. 31, 2017McfebblMcf	Dec. 31, 2017USD ($)McfebblMcf	Dec. 31, 2017McfebblMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Acquisition of reserve in place		0		0			0		0
Revisions of previous quantity estimates | $			$ 152		$ 361			$ 1,721
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe) | Mcfe	11,921				14,775	5,253
Revisions of previous estimates due to price | Mcfe	(717)				154	1,691
Extensions, discoveries and other additions | Mcfe	1,195				1,009	8,087
Production | Mcfe	(778)				(946)	(897)
Acquisition of reserves in place | Mcfe	0				0	0
Disposition of reserves in place | Mcfe	(2)				(3,443)	0
Proved reserves, end of period, (bcfe) | Mcfe	12,721				11,921	14,775
Proved undeveloped reserves:
Proved undeveloped reverses (energy) | Mcfe	929	929	929	929	190	1,375	1,375	1,375	1,375
United States
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe) | Mcfe	11,921				14,775	5,253
Revisions of previous estimates due to price | Mcfe	(717)				154	1,691
Revisions of previous estimates other than price | Mcfe	1,102				372	641
Extensions, discoveries and other additions | Mcfe	1,195				1,009	8,087
Production | Mcfe	(778)				(946)	(897)
Acquisition of reserves in place | Mcfe					0
Disposition of reserves in place | Mcfe	(2)				(3,443)	0
Proved reserves, end of period, (bcfe) | Mcfe	12,721				11,921	14,775
Proved developed reserves:
Proved developed reserves (energy) | Mcfe	6,421	6,421	6,421	6,421	5,557	7,920	7,920	7,920	7,920
Proved undeveloped reserves:
Proved undeveloped reverses (energy) | Mcfe	6,300	6,300	6,300	6,300	6,364	6,855	6,855	6,855	6,855
United States | Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of year | Mcf		8,044			11,126		4,866
Revisions of previous estimates due to price | Mcf		(480)			96		1,327
Revisions of previous estimates other than price | Mcf		685			316		571
Extensions, discoveries and other additions | Mcf		992			753		5,159
Production | Mcf		(609)			(807)		(797)
Acquisition of reserve in place | Mcf					0
Disposition of reserves in place | Mcf		(2)			(3,440)		0
Proved reserves, end of year | Mcf		8,630			8,044		11,126
Proved developed reserves:
Proved developed reserves (volume) | Mcf	4,906	4,906	4,906	4,906	4,395	6,979	6,979	6,979	6,979
Proved undeveloped reserves:
Proved undeveloped reserves (volume) | Mcf	3,724	3,724	3,724	3,724	3,649	4,147	4,147	4,147	4,147
United States | Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of year				69,007,000	65,636,000				10,523,000
Revisions of previous estimates due to price				(2,041,000)	788,000				3,197,000
Revisions of previous estimates other than price				3,707,000	410,000				(1,529,000)
Extensions, discoveries and other additions				6,948,000	5,830,000				55,772,000
Production				(4,696,000)	(3,407,000)				(2,327,000)
Acquisition of reserve in place					0
Disposition of reserves in place				0	(250,000)				0
Proved reserves, end of year				72,925,000	69,007,000				65,636,000
Proved developed reserves:
Proved developed reserves (volume)	26,124,000	26,124,000	26,124,000	26,124,000	18,037,000	14,513,000	14,513,000	14,513,000	14,513,000
Proved undeveloped reserves:
Proved undeveloped reserves (volume)	46,801,000	46,801,000	46,801,000	46,801,000	50,970,000	51,123,000	51,123,000	51,123,000	51,123,000
United States | NGL
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of year				577,063,000	542,455,000				53,931,000
Revisions of previous estimates due to price				(37,492,000)	8,912,000				57,447,000
Revisions of previous estimates other than price				65,869,000	8,855,000				13,102,000
Extensions, discoveries and other additions				26,941,000	36,823,000				432,220,000
Production				(23,620,000)	(19,706,000)				(14,245,000)
Acquisition of reserve in place					0
Disposition of reserves in place				0	(276,000)				0
Proved reserves, end of year				608,761,000	577,063,000				542,455,000
Proved developed reserves:
Proved developed reserves (volume)	226,271,000	226,271,000	226,271,000	226,271,000	175,480,000	142,213,000	142,213,000	142,213,000	142,213,000
Proved undeveloped reserves:
Proved undeveloped reserves (volume)	382,490,000	382,490,000	382,490,000	382,490,000	401,583,000	400,242,000	400,242,000	400,242,000	400,242,000

Supplemental Oil and Gas Disc_9

Supplemental Oil and Gas Disclosures (Summary of Changes in Reserves) (Details) - Mcfe Mcfe in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	11,921	14,775	5,253
Net revisions
Revisions of previous estimates due to price	(717)	154	1,691
Performance and production revisions	1,102	372	641
Total net revisions	385	526	2,332
Extensions, discoveries and other additions
Proved developed	191	177	1,258
Proved undeveloped	1,004	832	6,829
Total reserve additions	1,195	1,009	8,087
Production	(778)	(946)	(897)
Acquisition of reserves in place	0	0	0
Disposition of reserves in place	(2)	(3,443)	0
Proved reserves, end of period, (bcfe)	11,921	14,775	5,253	12,721
Proved and unproved reserves reclassified				109
Northeast Appalachia
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	4,366	4,126	1,574
Net revisions
Revisions of previous estimates due to price	(57)	41	903
Performance and production revisions	127	107	154
Total net revisions	70	148	1,057
Extensions, discoveries and other additions
Proved developed	185	154	790
Proved undeveloped	677	397	1,100
Total reserve additions	862	551	1,890
Production	(459)	(459)	(395)
Acquisition of reserves in place	0	0	0
Disposition of reserves in place	(2)	0	0
Proved reserves, end of period, (bcfe)	4,366	4,126	1,574	4,837
Southwest Appalachia
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	7,554	6,962	677
Net revisions
Revisions of previous estimates due to price	(660)	106	738
Performance and production revisions	975	272	125
Total net revisions	315	378	863
Extensions, discoveries and other additions
Proved developed	6	22	419
Proved undeveloped	327	435	5,186
Total reserve additions	333	457	5,605
Production	(319)	(243)	(183)
Acquisition of reserves in place	0	0	0
Disposition of reserves in place	0	0	0
Proved reserves, end of period, (bcfe)	7,554	6,962	677	7,883
Fayetteville Shale
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	0	3,679	2,997
Net revisions
Revisions of previous estimates due to price	0	6	49
Performance and production revisions	0	(6)	358
Total net revisions	0	0	407
Extensions, discoveries and other additions
Proved developed	0	1	48
Proved undeveloped	0	0	543
Total reserve additions	0	1	591
Production	0	(243)	(316)
Acquisition of reserves in place	0	0	0
Disposition of reserves in place	0	(3,437)	0
Proved reserves, end of period, (bcfe)	0	3,679	2,997	0
Other
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	1	8	5
Net revisions
Revisions of previous estimates due to price	0	1	1
Performance and production revisions	0	(1)	4
Total net revisions	0	0	5
Extensions, discoveries and other additions
Proved developed	0	0	1
Proved undeveloped	0	0	0
Total reserve additions	0	0	1
Production	0	(1)	(3)
Acquisition of reserves in place	0	0	0
Disposition of reserves in place	0	(6)	0
Proved reserves, end of period, (bcfe)	1	8	5	1

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, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 27,003	$ 34,523	$ 36,576
Future production costs	(14,981)	(15,347)	(18,390)
Future development costs	(3,246)	(4,095)	(4,676)
Future income tax expense	(476)	(2,079)	(1,342)
Future net cash flows	8,300	13,002	12,168
10% annual discount for estimated timing of cash flows	(4,600)	(7,003)	(6,606)
Standardized measure of discounted future net cash flows	$ 3,700	$ 5,999	$ 5,562	$ 1,665

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)	12 Months Ended
	Dec. 31, 2019$ / bbl$ / MMBTU	Dec. 31, 2018$ / bbl$ / MMBTU	Dec. 31, 2017$ / bbl$ / MMBTU
Natural Gas
Reserve Quantities [Line Items]
Average sales price ($ per unit) | $ / MMBTU	2.58	3.10	2.98
Oil
Reserve Quantities [Line Items]
Average sales price ($ per unit)	55.69	65.56	47.79
NGL
Reserve Quantities [Line Items]
Average sales price ($ per unit)	11.58	17.64	14.41

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure, beginning of year	$ 5,999	$ 5,562	$ 1,665
Sales and transfers of natural gas and oil produced, net of production costs	(923)	(1,564)	(1,191)
Net changes in prices and production costs	(3,510)	2,162	1,963
Extensions, discoveries, and other additions, net of future production and development costs	234	335	1,715
Increase Due to Purchases of Minerals in Place	0	0	0
Sales of reserves in place	(2)	(2,022)	0
Revisions of previous quantity estimates	152	361	1,721
Net change in income taxes	491	(304)	(222)
Changes in estimated future development costs	621	(166)	(6)
Previously estimated development costs incurred during the year	704	536	55
Changes in production rates (timing) and other	(718)	521	(304)
Accretion of discount	652	578	166
Standardized measure, end of year	$ 3,700	$ 5,999	$ 5,562