Southwestern Energy (SWN) 10-K 1 Mar 21 2020 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2020	Feb. 25, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Current Fiscal Year End Date	--12-31
Entity File Number	001-08246
Entity Registrant Name	Southwestern Energy Company
Document Transition Report	false
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0000007332
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
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 1,493,259,580
Entity Common Stock, Shares Outstanding		674,457,398
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 18, 2021 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, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Revenues:
Operating revenues	$ 2,308	$ 3,038	$ 3,862
Operating Costs and Expenses:
Operating expenses	813	720	785
General and administrative expenses	121	166	209
Montage merger-related expenses	41	0	0
Restructuring charges	16	11	39
(Gain) loss on sale of operating assets	0	2	(17)
Depreciation, depletion and amortization	357	471	560
Impairments	2,830	16	171
Taxes, other than income taxes	55	62	89
Total Operating Costs and Expenses	5,179	2,768	3,065
Operating Income (Loss)	(2,871)	270	797
Interest Expense:
Interest on debt	171	166	231
Other interest charges	11	8	8
Interest capitalized	(88)	(109)	(115)
Total Interest Expense	94	65	124
Gain (Loss) on Derivatives	224	274	(118)
Gain (Loss) on Early Extinguishment of Debt	35	8	(17)
Other Income (Loss), Net	1	(7)	0
Income (Loss) Before Income Taxes	(2,705)	480	538
Provision (Benefit) for Income Taxes:
Current	(2)	(2)	1
Deferred	409	(409)	0
Provision (Benefit) for Income Taxes	407	(411)	1
Net Income (Loss)	(3,112)	891	537	[1]
Participating securities – mandatory convertible preferred stock	0	0	2
Net Income (Loss) Attributable to Common Stock	$ (3,112)	$ 891	$ 535
Earnings (Loss) Per Common Share
Basic (in dollars per share)	$ (5.42)	$ 1.65	$ 0.93
Diluted (in dollars per share)	$ (5.42)	$ 1.65	$ 0.93
Weighted Average Common Shares Outstanding:
Basic (in shares)	573,889,502	539,345,343	574,631,756
Diluted (in shares)	573,889,502	540,382,914	576,642,808
Gas sales
Operating Revenues:
Operating revenues	$ 967	$ 1,241	$ 1,998
Oil sales
Operating Revenues:
Operating revenues	154	223	196
NGL sales
Operating Revenues:
Operating revenues	265	274	352
Marketing
Operating Revenues:
Operating revenues	917	1,297	1,222
Gas gathering
Operating Revenues:
Operating revenues	0	0	89
Other
Operating Revenues:
Operating revenues	5	3	5
Marketing purchases
Operating Costs and Expenses:
Marketing purchases	$ 946	$ 1,320	$ 1,229
[1]	In 2018, 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, 2020	Dec. 31, 2019	Dec. 31, 2018	[1]
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ (3,112)	$ 891	$ 537
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	[2]	3	8	10
Net actuarial loss incurred in period	[3]	(8)	(5)	(2)
Total change in value of pension and postretirement liabilities		(5)	3	8
Comprehensive income (loss)		$ (3,117)	$ 894	$ 545
[1]	In 2018, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.
[2]	Net of $1 million and $2 million in taxes for the years ended December 31, 2020 and 2019, respectively.
[3]	Net of ($2) million and ($1) million in taxes for the year ended December 31, 2020 and 2019, respectively.

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Amortization of prior service cost and net loss included in net periodic pension cost, tax	$ 1	$ 2
Net gain (loss) incurred in period, tax	$ (2)	$ (1)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 13	$ 5
Accounts receivable, net	368	345
Derivative assets	241	278
Other current assets	49	51
Total current assets	671	679
Natural gas and oil properties, using the full cost method, including $1,472 million as of December 31, 2020 and $1,506 million as of December 31, 2019 excluded from amortization	27,261	25,250
Other	523	520
Less: Accumulated depreciation, depletion and amortization	(23,673)	(20,503)
Total property and equipment, net	4,111	5,267
Operating lease assets	163	159
Deferred tax assets	0	407
Other long-term assets	215	205
Total long-term assets	378	771
TOTAL ASSETS	5,160	6,717
Current liabilities:
Accounts payable	573	525
Taxes payable	74	59
Interest payable	58	51
Derivative liabilities	245	125
Current operating lease liabilities	42	34
Other current liabilities	20	54
Total current liabilities	1,012	848
Long-term debt	3,150	2,242
Long-term operating lease liabilities	117	119
Long-term derivative liabilities	183	111
Pension and other postretirement liabilities	45	43
Other long-term liabilities	156	108
Total long-term liabilities	3,651	2,623
Commitments and contingencies (Note 10)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 718,795,700 shares as of December 31, 2020 and 585,555,923 as of December 31, 2019	7	6
Additional paid-in capital	5,093	4,726
Accumulated deficit	(4,363)	(1,251)
Accumulated other comprehensive loss	(38)	(33)
Common stock in treasury, 44,353,224 shares as of December 31, 2020 and 2019	(202)	(202)
Total equity	497	3,246
TOTAL LIABILITIES AND EQUITY	$ 5,160	$ 6,717

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Net unevaluated costs excluded from amortization, cumulative	$ 1,472	$ 1,506
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)	718,795,700	585,555,923
Treasury stock, shares (in shares)	44,353,224	44,353,224

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash Flows From Operating Activities:
Net income (loss)	$ (3,112)	$ 891	$ 537	[1]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	357	471	560
Amortization of debt issuance costs	9	8	8
Impairments	2,830	16	171
Deferred income taxes	409	(409)	0
(Gain) loss on derivatives, unsettled	138	(94)	24
Stock-based compensation	3	8	14
(Gain) loss on early extinguishment of debt	(35)	(8)	17
(Gain) loss on sale of assets	0	2	(17)
Other	6	10	(1)
Change in assets and liabilities:
Accounts receivable	50	234	(153)
Accounts payable	(131)	(141)	65
Taxes payable	(7)	0	2
Interest payable	(11)	0	(10)
Inventories	2	(7)	(13)
Other assets and liabilities	20	(17)	19
Net cash provided by operating activities	528	964	1,223
Cash Flows From Investing Activities:
Capital investments	(896)	(1,099)	(1,290)
Proceeds from sale of property and equipment	12	54	1,643
Cash acquired in Montage merger	3	0	0
Other	0	0	6
Net cash provided by (used in) investing activities	(881)	(1,045)	359
Cash Flows From Financing Activities:
Payments on current portion of long-term debt	0	(52)	0
Payments on long-term debt	(72)	(54)	(2,095)
Payments on revolving credit facility	(1,671)	(532)	(1,983)
Borrowings under revolving credit facility	2,337	566	1,983
Change in bank drafts outstanding	1	(19)	17
Proceeds from issuance of long-term debt	350	0	0
Debt issuance and other financing costs	(10)	(3)	(9)
Proceeds from issuance of common stock	152	0	0
Purchase of treasury stock	0	(21)	(180)
Preferred stock dividend	0	0	(27)
Cash paid for tax withholding	(4)	(1)	(3)
Other	0	1	0
Net cash provided by (used in) financing activities	361	(115)	(2,297)
Increase (decrease) in cash and cash equivalents	8	(196)	(715)
Cash and cash equivalents at beginning of year	5	201	916
Cash and cash equivalents at end of year	13	5	201
Montage Resources Corporation
Cash Flows From Financing Activities:
Payments on revolving credit facility	(200)	0	0
Repayment of Montage senior notes	$ (522)	$ 0	$ 0
[1]	In 2018, 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	Accumulated Other Comprehensive Income (Loss)	Common Stock in Treasury
Beginning balance (in shares) at Dec. 31, 2017				512,134,311	1,725,000				31,269
Beginning balance at Dec. 31, 2017		$ 1,979		$ 5		$ 4,698	$ (2,679)	$ (44)	$ (1)
Comprehensive income
Net income (loss)		537	[1]				537
Other comprehensive income		8						8
Comprehensive income (loss)	[1]	545
Stock-based compensation		21				21
Preferred stock dividend (in shares)				74,998,614	(1,725,000)
Preferred stock dividend		$ 0		$ 1		(1)
Issuance of restricted stock (in shares)				349,562
Cancellation of restricted stock (in shares)				(1,804,122)
Performance units vested (in shares)				214,866
Treasury stock (in shares)		39,061,268							39,061,268
Treasury stock		$ (180)							$ (180)
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 (loss)		891					891
Other comprehensive income		3						3
Comprehensive income (loss)		894
Stock-based compensation		$ 12				12
Issuance of restricted stock (in shares)				236,978
Cancellation of restricted stock (in shares)				(239,571)
Performance units vested (in shares)				535,802
Treasury stock (in shares)		5,260,687							5,260,687
Treasury stock		$ (21)							$ (21)
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)
Comprehensive income
Net income (loss)		(3,112)					(3,112)
Other comprehensive income		(5)						(5)
Comprehensive income (loss)		(3,117)
Stock-based compensation		4				4
Issuance of common stock (in shares)				63,250,000
Issuance of common stock		152				152
Issuance of restricted stock (in shares)				311,446
Cancellation of restricted stock (in shares)				(1,274,802)
Restricted units granted (in shares)				2,697,170
Restricted units granted		3				3
Montage acquisition exchange (in shares)				69,740,848
Montage merger exchange		213		$ 1		212
Tax withholding - stock compensation (in shares)				(1,484,885)
Tax withholding – stock compensation		(4)				(4)
Ending balance (in shares) at Dec. 31, 2020				718,795,700	0				44,353,224
Ending balance at Dec. 31, 2020		$ 497		$ 7		$ 5,093	$ (4,363)	$ (38)	$ (202)
[1]	In 2018, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
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. 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, Ohio 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, Ohio 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, Ohio and West Virginia as “Appalachia.” The Company also operates drilling rigs located in Appalachia, and provides oilfield products and services, principally serving the Company's E&P operations through vertical integration. In August 2020, the Company entered into an Agreement and Plan of Merger (the "Merger Agreement") with Montage Resources Corporation ("Montage") pursuant to which Montage will merge with and into Southwestern, with Southwestern continuing as the surviving company (the "Merger"). The Company acquired at the effective time of the merger all of the outstanding shares of common stock in Montage in exchange for 1.8656 shares of Southwestern common stock per share of Montage common stock. The transaction closed on November 13, 2020. The Merger expanded the Company's footprint in Appalachia by supplementing the Northeast Appalachia and Southwest Appalachia operations and by expanding the Company's operations into Ohio. See Note 3 for more information about the Merger. 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, 2020, 2019 and 2018 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. Customers include major energy companies, utilities and industrial purchasers of Natural gas. For the year ended December 31, 2020, one purchaser accounted for 10% of total revenues. A default on this account could have a material impact on the Company, but the Company does not believe that there is a material risk of default. No other purchasers accounted for greater than 10% of consolidated revenues. For the year ended December 31, 2019, no single customer accounted for 10% or greater of total sales. The Company believes that the loss of any one customer would not have an adverse effect on its ability to sell its natural gas, oil and NGL production. 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, 2020, and December 31, 2019: (in millions) December 31, 2020 December 31, 2019 Cash $ 13 $ 5 Marketable securities (1) — — Total $ 13 $ 5 (1) Consists of government stable value money market funds. Immaterial as of December 31, 2020 and 2019. 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 $16 million and $15 million as of December 31, 2020 and 2019, 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, 2020, the Company had a total of $1,472 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. In the first, second and third quarters of 2020, the net book value of the Company's United States natural gas and oil properties exceeded the ceiling by approximately $1,479 million, $650 million and $361 million, respectively, and resulted in non-cash ceiling test impairments. At December 31, 2020, using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $1.98 per MMBtu, West Texas Intermediate oil of $39.57 per barrel and NGLs of $10.27 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $335 million and resulted in an additional non-cash ceiling test impairment. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2020. No impairment expense was recorded for the year ended December 31, 2020 in relation to the Company’s recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement . Pursuant to SEC guidance, the Company determined that the fair value of the properties acquired at the closing of the Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021 as long as the Company can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, the Company is required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Merger was based on forward strip natural gas and oil pricing existing at the date of the Merger, and management affirmed that there has not been a material decline to the fair value of these acquired assets since the Merger. The properties acquired in the Merger have an unamortized cost at December 31, 2020 of $1,087 million. Had management not received the waiver from the SEC, the impairment charge recorded would have been an additional $539 million for the year ended December 31, 2020. 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 did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2019. 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 results 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. 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. Other Property and Equipment. 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 estimated useful lives of those assets depreciated under the straight-line method are as follows: Water facilities 5 – 10 years Gathering systems 15 – 25 years Technology infrastructure 3 – 7 years Drilling rigs and equipment 3 years Buildings and leasehold improvements 10 – 30 years Other property, plant and equipment is comprised of the following: (in millions) December 31, 2020 December 31, 2019 Water facilities $ 228 $ 217 Gathering systems 54 32 Technology infrastructure 133 154 Drilling rigs and equipment 26 32 Land, buildings and leasehold improvements 41 41 Other 41 44 Less: Accumulated depreciation and impairment (311) (300) Total $ 212 $ 220 Impairment of Long-Lived Assets . The carrying value of non-full cost pool long-lived assets is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. 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 years ended December 31, 2020 and 2019 the Company recognized non-cash impairments of $5 million and $16 million, respectively, for non-core assets. During 2018, the Company recognized a non-cash impairment charge of $160 million related to gathering and other E&P assets sold in the Fayetteville Shale sale and $11 million related to other non-core assets. 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, 2020 and 2019, the Company had $48 million and $56 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, 2020, 2019 and 2018, and expects to amortize $8 million in 2021 and $5 million per year for the four years thereafter. Leases The Company determines if a contract contains a lease at inception or as a result of an acquisition. 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, 2020. 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 and other equipment under non-cancelable operating leases expiring through 2036. 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. 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 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. 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 11 . 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, restricted stock units and performance units. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities. In August 2020, the Company completed an underwritten public offering of 63,250,000 shares of its common stock with an offering price to the public of $2.50 per share. Net proceeds after deducting underwriting discounts and offering expenses were approximately $152 million. See Note 3 for additional details regarding the Company's use of proceeds from the equity offering. Under the Agreement and Plan of Merger, Montage shareholders received 1.8656 shares of Southwestern common stock for each share of Montage common stock issued and outstanding immediately prior to the date of Merger. On November 13, 2020, the Company issued 69,740,848 shares of its common stock, or approximately $213 million in value (based on Southwestern common stock closing price as of November 13, 2020 of $3.05), as Merger consideration. 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. 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, 2020, 2019 and 2018: For the years ended December 31, (in millions, except share/per share amounts) 2020 2019 2018 Net income (loss) $ (3,112) $ 891 $ 537 Participating securities – mandatory convertible preferred stock — — 2 Net income (loss) attributable to common stock $ (3,112) $ 891 $ 535 Number of common shares: Weighted average outstanding 573,889,502 539,345,343 574,631,756 Issued upon assumed exercise of outstanding stock options — — — Effect of issuance of non-vested restricted common stock — 361,380 698,103 Effect of issuance of non-vested restricted units — — — Effect of issuance of non-vested performance units — 676,191 1,312,949 Weighted average and potential dilutive outstanding 573,889,502 540,382,914 576,642,808 Earnings (loss) per common share: Basic $ (5.42) $ 1.65 $ 0.93 Diluted $ (5.42) $ 1.65 $ 0.93 The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2020, 2019 and 2018, as they would have had an antidilutive effect: For the years ended December 31, 2020 2019 2018 Unexercised stock options 4,427,040 5,078,253 5,909,082 Unvested share-based payment 962,662 1,728,264 3,692,794 Restricted units 4,452,876 — — Performance units 2,818,653 271,268 642,568 Mandatory convertible preferred stock — — 2,465,708 Total 12,661,231 7,077,785 12,710,152 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, 2020, 2019 and 2018: For the years ended December 31, (in millions) 2020 2019 2018 Cash paid during the year for interest, net of amounts capitalized $ 75 $ 58 $ 135 Cash paid (received) during the year for income taxes (32) (52) 6 Increase (decrease) in noncash property additions 1,084 (1) 41 (42) (1) Includes $1,097 million in noncash additions related to the Montage Merger. 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 and 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 14 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, operating expense and 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 (“TSR”) and the other on relative TSR 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 liability-based performance unit awards granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative TSR. The fair values of the market conditions discussed above are calculated by Monte Carlo models on a quarterly basis. See Note 14 for a discussion of the Company’s stock-based compensation. Cash-Based Compensation The Company classifies certain awards that will be settled in cash as cash-based compensation. The Company recognizes the cost of these awards as general and administrative expense, operating expense and capitalized expense over the vesting period of the awards. The performance cash awards include a performance condition determined annually by the Company. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be canceled. Treasury Stock In 2018, the Company repurchased 39,061,268 shares of its outstanding common stock per a previously announced share repurchase program at an average price of $4.63 per share for approximately $180 million. In 2019, the Company completed its share repurchase program by purchasing another 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 frozen legacy non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants could 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, 2020 and 2019, 3,632 shares and 5,115 shares, respectively, were held in the Rabbi Trust and were accounted for 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 August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Management (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements ("ASU 2018-13"), which modifies the disclosure requirements on fair value measurements. ASU 2018-13 became effective for public business entities for annual and interim periods in the fiscal years beginning after December 15, 2019. As a result of this adoption, this standard did not have a material impact on the Company's consolidated financial statements. 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 replaced 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 became 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 and recently acquired credit portfolios, which include trade receivables from commodity sales, joint interest billings due from partners and 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 counterparties. Update 2016-13 did not have a significant impact on the Company's consolidated financial statements or related control environment upon adoption on January 1, 2020. New Accounting Standards Not Yet Adopted in this Report In August 2018, the FASB issued ASU 2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans ("ASU 2018-14"). This ASU amends, adds and removes certain disclosure requirements under FASB ASC Topic 715 – Compensation – Retirement Benefits. The guidance in ASU 2018-14 is effective for fiscal ye

Restructuring Charges

Restructuring Charges	12 Months Ended
	Dec. 31, 2020
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, 2020, 2019 and 2018: For the years ended December 31, (in millions) 2020 2019 2018 (1) Reduction in workforce (not Fayetteville Shale sale-related) $ 16 $ — $ 23 Fayetteville Shale sale-related — 11 16 Total restructuring charges $ 16 $ 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, 2020, which are reflected in accounts payable on the consolidated balance sheet: (in millions) Liability at December 31, 2019 $ 2 Additions 16 Distributions (15) Liability at December 31, 2020 $ 3 Reduction in Workforce (Not Fayetteville Shale Sale-Related) In February 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of the Company's organizational structure. This reduction was substantially complete by the end of the first quarter of 2020. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the year ended December 31, 2020. The Company also recognized additional severance costs in the fourth quarter of 2020 related to continued organizational restructuring for which a liability of $3 million has been accrued as of December 31, 2020. 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, 2020, 2019 and 2018: For the years ended December 31, (in millions) 2020 2019 2018 Severance (including payroll taxes) $ 16 $ — $ 21 Outplacement services, other — — 2 Total reduction in workforce-related restructuring charges (1) $ 16 $ — $ 23 (1) Total restructuring charges were $16 million for the Company's E&P segment for the year ended December 31, 2020. 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. The Company had substantially completed the Fayetteville Shale sale-related employment terminations by December 31, 2019. 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. Approximately $2 million in charges related to office consolidation and reorganization were 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 and $1 million in other office consolidation expenses 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. 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. See Note 3 for a discussion of the Company’s Fayetteville Shale sale.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Acquisitions and Divestitures	ACQUISITIONS AND DIVESTITURES Montage Resources Merger On August 12, 2020, Southwestern entered into an Agreement and Plan of Merger with Montage Resources Corporation (“Montage”) whereby Montage would merge with and into Southwestern, with Southwestern continuing as the surviving company (the "Merger"). On November 12, 2020, Montage’s stockholders voted to approve the Merger and it was made effective on November 13, 2020. The Merger added to Southwestern’s oil and gas portfolio in Appalachia. In exchange for each share of Montage common stock, Montage stockholders received 1.8656 shares of Southwestern common stock, plus cash in lieu of any fractional share of Southwestern common stock that otherwise would have been issued, based on the average price of $3.05 per share of Southwestern common stock on the NYSE on November 13, 2020. Following the closing of the Merger, Southwestern's existing shareholders and Montage's existing shareholders owned approximately 90% and 10%, respectively, of the outstanding shares of the combined company. In anticipation of the Merger, in August 2020 Southwestern issued $350 million of new senior unsecured notes and 63,250,000 shares of common stock for $152 million after deducting underwriting discounts and offering expenses. The Company used the net proceeds from the debt and common stock offerings and borrowings under its revolving credit facility to fund a redemption of $510 million aggregate principal amount of Montage's outstanding 8.875% senior notes due 2023 (the "Montage Notes") and related accrued interest in connection with the closing of the Merger. See Note 1 and Note 9 for additional information. The Merger constitutes a business combination and was accounted for using the acquisition method of accounting. The following table presents the fair value of consideration transferred to Montage stockholders as a result of the Merger: (in millions, except share, per share amounts) As of November 13, 2020 Shares of Southwestern common stock issued in respect of outstanding Montage common stock 67,311,166 Shares of Southwestern common stock issued in respect of Montage stock-based awards 2,429,682 69,740,848 NYSE closing price per share of Southwestern common shares on November 13, 2020 $ 3.05 Total consideration (fair value of Southwestern common shares issued) $ 213 Increase in Southwestern common stock ($0.01 par value per share) 1 Increase in Southwestern additional paid-in capital $ 212 The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. Although the purchase price allocation is substantially complete as of the date of this filing, there may be further adjustments to the Company’s natural gas and oil properties. These amounts will be finalized no later than one year from the acquisition date. (in millions) As of November 13, 2020 Consideration: Fair value of Southwestern’s stock issued on November 13, 2020 $ 213 Fair value of assets acquired: Cash and cash equivalents 3 Accounts receivable 73 Other current assets 1 Derivative assets 11 Evaluated natural gas and oil properties 1,012 Unevaluated natural gas and oil properties 90 Other property, plant and equipment 28 Other long-term assets 26 Total assets acquired 1,244 Fair value of liabilities assumed: Accounts payable 145 Other current liabilities 49 Derivative liabilities 70 Revolving credit facility 200 Senior unsecured notes 522 Asset retirement obligations 28 Other long-term liabilities 17 Total liabilities assumed 1,031 Net assets acquired and liabilities assumed $ 213 The assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the Merger. The valuation of certain assets, including property, are based on preliminary appraisals. The fair value of acquired equipment is based on both available market data and a cost approach. Unevaluated oil and gas properties were valued primarily using a market approach based on comparable transactions for similar properties while the income approach was utilized for proved oil and gas properties based on underlying reserve projections at the Merger date. Income approaches are considered Level 3 fair value estimates and include significant assumptions of future production, commodity prices, and operating and capital cost estimates, discounted using weighted average cost of capital for industry peers, and risk adjustment factors based on reserve category. Price assumptions were based on observable market pricing adjusted for historical differentials. Cost estimates were based on current observable costs inflated based on historical and expected future inflation. Taxes were based on current statutory rates. Deferred income taxes represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed. A full valuation was placed on all deferred tax assets assumed from Montage consistent with the Company’s treatment of its deferred tax asset balance as of December 31, 2020. The measurement of senior unsecured notes was based on unadjusted quoted prices in an active market and are primarily Level 1. The Company considered the borrowings under the revolving credit facility to approximate fair value. The value of derivative instruments was based on observable inputs, primarily forward commodity-price and interest-rate curves and is considered Level 2. With the completion of the Merger, Southwestern acquired proved and unproved properties of approximately $1.0 billion and $90 million, respectively, primarily associated with the Appalachian Basin. The remaining $28 million in Other property, plant and equipment consists of a gathering system, buildings and various equipment. From the date of the Merger through December 31, 2020, revenues and the net income attributable to common stockholders associated with the operations acquired through the Merger totaled $63 million and $28 million, respectively. The following table summarizes the unaudited pro forma condensed financial information of Southwestern as if the Merger had occurred on January 1, 2019: For the years ended December 31, (in millions, except per share amounts) 2020 2019 Revenues $ 2,701 $ 3,673 Net income (loss) attributable to common stock $ (3,177) $ 995 Net income (loss) attributable to common stock per share – basic $ (4.71) $ 1.48 Net income (loss) attributable to common stock per share – diluted $ (4.71) $ 1.48 The unaudited pro forma information is not necessarily indicative of the operating results that would have occurred had the Merger been completed at January 1, 2019, nor is it necessarily indicative of future operating results of the combined entity. The unaudited pro forma information gives effect to the Merger and related equity and debt issuances along with the use of proceeds therefrom as if they had occurred on January 1, 2019. The unaudited pro forma information for 2020 and 2019 is a result of combining the statements of operations of Southwestern with the pre-Merger results from January 1, 2020, and 2019 of Montage and included adjustments for revenues and direct expenses. The pro forma results exclude any cost savings anticipated as a result of the Merger and the impact of any Merger-related costs. The pro forma results include adjustments to DD&A (depreciation, depletion and amortization) based on the purchase price allocated to property, plant, and equipment and the estimated useful lives as well as adjustments to interest expense. Interest expense was adjusted to reflect the retirement of the Montage senior notes, the Montage credit facility, all related accrued interest and the associated decrease in amortization of issuance costs related to the Montage notes and revolving line of credit. This decrease was partially offset by increases in interest on debt associated with the issuance of $350 million in new 8.375% Senior Notes due 2028 related to the Southwestern debt offering and borrowings under Southwestern’s credit facility used to pay off the Montage notes, Montage credit facility and related accrued interest. Management believes the estimates and assumptions are reasonable, and the relative effects of the Merger are properly reflected. Montage Merger-Related Expenses The following table summarizes the Merger-related expenses incurred for the year ended December 31, 2020: (in millions) For the year ended December 31, 2020 Bank, legal and consulting fees $ 18 Employee severance and related costs 17 Contract buyouts 5 Other 1 Total Montage merger-related expenses $ 41 Employee severance and related employee cost primarily relates to one-time severance costs and the accelerated vesting of certain Montage share-based awards for former Montage employees based on the terms of the Agreement and Plan of Merger and existing change of control provisions within the former Montage employment agreements. Contract buyouts primarily consist of the costs associated with the settlement of contracts inherited from Montage that had no future value to the Company’s ongoing business. 2019 Divestitures During 2019, the Company sold non-core acreage for $38 million. There was no production or proved reserves associated with this acreage. In addition, during July 2019, the Company sold the land associated with its headquarters office building for $16 million and recognized a $2 million gain on the sale. The Company also from time to time sells leases and other properties whose value, individually, is not material but is reflected in the Company’s financial statements. Fayetteville Shale Sale 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. 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.

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Leases	LEASES As part of the Montage Merger, the Company acquired $25 million of operating right of use assets and corresponding lease liabilities which were recognized as part of the Company’s acquisition accounting in the fourth quarter of 2020. In July 2019, the Company terminated its existing lease agreement and entered into a new ten-year lease agreement for a smaller portion of the headquarters office building, which resulted in the Company making a $6 million residual value guarantee short-fall payment to the building’s previous lessor. The Company’s variable lease costs are primarily comprised of variable operating charges incurred in connection with the new building lease which are expected to continue throughout the lease term. There are currently no material residual value guarantees in the Company’s existing leases. The components of lease costs are shown below: For the years ended December 31, (in millions) 2020 2019 Operating lease cost $ 48 $ 45 Short-term lease cost 35 45 Variable lease cost 3 1 Total lease cost $ 86 $ 91 As of December 31, 2020, the Company had operating leases of $6 million, related primarily to compressor leases, that have been executed but not yet commenced. These operating leases are planned to commence during 2021 with lease terms expiring through 2024. 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 years ended December 31, (in millions) 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 47 $ 47 Right-of-use assets obtained in exchange for operating liabilities: Operating leases $ 48 $ 95 Supplemental balance sheet information related to leases is as follows: (in millions) December 31, 2020 December 31, 2019 Right-of-use asset balance: Operating leases $ 163 $ 159 Lease liability balance: Current operating leases $ 42 $ 34 Long-term operating leases 117 119 Total operating leases $ 159 $ 153 Weighted average remaining lease term: (years) Operating leases 5.6 6.6 Weighted average discount rate: Operating leases 5.97 % 5.33 % Maturity analysis of operating lease liabilities: (in millions) December 31, 2020 2021 $ 50 2022 37 2023 26 2024 18 2025 14 Thereafter 42 Total undiscounted lease liability 187 Imputed interest (28) Total discounted lease liability $ 159

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue Recognition	REVENUE RECOGNITION Effective 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. 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 market indices 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, 2020 Gas sales $ 928 $ — $ 39 $ 967 Oil sales 150 — 4 154 NGL sales 265 — — 265 Marketing — 2,145 (1,228) 917 Other (1) 5 — — 5 Total $ 1,348 $ 2,145 $ (1,185) $ 2,308 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 (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) 2020 2019 2018 Northeast Appalachia $ 648 $ 964 $ 1,165 Southwest Appalachia 700 736 817 Fayetteville Shale — — 537 Other — 3 6 Total $ 1,348 $ 1,703 $ 2,525 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, 2020 December 31, 2019 Receivables from contracts with customers $ 350 $ 284 Other accounts receivable 18 61 Total accounts receivable $ 368 $ 345 Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the years ended December 31, 2020 and 2019. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

Derivatives and Risk Management

Derivatives and Risk Management	12 Months Ended
	Dec. 31, 2020
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, 2020, 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. Swaptions Instruments that refer to an option to enter into a fixed price swap. In exchange for an option premium, the purchaser gains the right but not the obligation to enter a specified swap agreement with the issuer for specified future dates. If the Company sells a swaption, the counterparty has the right to enter into a fixed price swap wherein the Company receives a fixed price for the contract and pays a floating market price to the counterparty. If the Company purchases a swaption, the Company has the right to enter into a fixed price swap wherein the Company receives a floating market price for the contract and pays a fixed price to the counterparty. 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. 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, 2020: Financial Protection on Production Weighted Average Price per MMBtu Fair value at December 31, 2020 ($ in millions) Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Natural Gas 2021 Fixed price swaps 201 $ 2.80 $ — $ — $ — $ — $ 29 Two-way costless collars 237 — — 2.57 2.95 — 11 Three-way costless collars 313 — 2.16 2.49 2.85 — (24) Total 751 $ 16 2022 Fixed price swaps 112 $ 2.68 $ — $ — $ — $ — $ 4 Two-way costless collars 63 — — 2.52 3.03 — (1) Three-way costless collars 203 — 2.06 2.46 2.89 — (15) Total 378 $ (12) 2023 Three-way costless collars 87 $ — $ 2.06 $ 2.47 $ 2.98 $ — $ — Basis swaps 2021 219 $ — $ — $ — $ — $ (0.21) $ 57 2022 139 — — — — (0.33) 8 2023 47 — — — — (0.45) — 2024 11 — — — — (0.60) — 2025 4 — — — — (0.59) — Total 420 $ 65 Weighted Average Price per Bbl Fair value at December 31, 2020 ($ in millions) Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Oil 2021 Fixed price swaps 4,887 $ 48.59 $ — $ — $ — $ 1 Two-way costless collars 201 — — 37.73 45.68 (1) Three-way costless collars 1,543 — 37.42 47.22 52.86 — Total 6,631 $ — 2022 Fixed price swaps 1,282 $ 46.37 $ — $ — $ — $ — Three-way costless collars 873 — 40.25 50.78 56.54 1 Total 2,155 $ 1 2023 Three-way costless collars 878 $ — $ 33.52 $ 43.52 $ 53.41 $ (1) Ethane 2021 Fixed price swaps 5,889 $ 7.12 $ — $ — $ — $ (10) Two-way costless collars 584 — — 7.14 10.40 — Total 6,473 $ (10) 2022 Fixed price swaps 1,575 $ 8.69 $ — $ — $ — $ — Two-way costless collars 135 — — 7.56 9.66 — Total 1,710 $ — Propane 2021 Fixed price swaps 6,974 $ 20.43 $ — $ — $ — $ (36) 2022 Fixed price swaps 2,120 $ 20.23 $ — $ — — $ (2) Normal Butane 2021 Fixed price swaps 2,004 $ 24.97 $ — $ — $ — $ (8) 2022 Fixed price swaps 667 $ 22.77 $ — $ — $ — $ (1) Natural Gasoline 2021 Fixed price swaps 1,936 $ 37.35 $ — $ — $ — $ (13) 2022 Fixed price swaps 643 $ 37.77 $ — $ — $ — $ (2) Other Derivative Contracts Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2020 ($ in millions) Call Options – Natural Gas (Net) 2021 75 $ 3.19 $ (8) 2022 77 3.00 (17) 2023 46 2.94 (8) 2024 9 3.00 (3) Total 207 $ (36) Put Options – Natural Gas 2021 18 $ 2.00 $ (1) 2022 5 2.00 — Total 23 $ (1) Volume (MBbls) Weighted Average Strike Price per Bbl Fair value at December 31, 2020 ($ in millions) Sold Call Options – Oil 2021 226 $ 60.00 $ — Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2020 ($ in millions) Swaptions – Natural Gas 2021 0.1 $ 3.00 $ (2) Weighted Average Strike Price per MMBtu Fair value at December 31, 2020 ($ in millions) Storage (1) Volume (Bcf) Swaps Basis Differential 2021 Purchased fixed price swap 1 $ 2.04 $ — $ — Fixed price swaps 2 2.49 — — Basis swaps 1 — (0.38) — Total 4 $ — (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, 2020 ($ in millions) Purchased Fixed Price Swaps – Marketing (Natural Gas) (1) 2021 6 $ 2.44 $ 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, 2020, the net fair value of the Company’s financial instruments related to commodities was a $41 million liability and included a net reduction of the liability of $1 million due to non-performance risk. See Note 8 for additional details regarding the Company's fair value measurements of its derivative positions. As of December 31, 2020, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or 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. Only the settled gains and losses are included in the Company’s realized commodity price calculations. The balance sheet classification of the assets and liabilities related to derivative financial instruments are summarized below as of December 31, 2020 and 2019: Derivative Assets Balance Sheet Classification Fair Value (in millions) December 31, 2020 December 31, 2019 Derivatives not designated as hedging instruments: Purchased fixed price swaps – natural gas Derivative assets $ 1 $ — Fixed price swaps – natural gas Derivative assets 37 77 (1) Fixed price swaps – oil Derivative assets 13 4 Fixed price swaps – ethane Derivative assets — 11 Fixed price swaps – propane Derivative assets — 21 Two-way costless collars – natural gas Derivative assets 54 10 Two-way costless collars – oil Derivative assets — 5 Two-way costless collars – propane Derivative assets — 2 Three-way costless collars – natural gas Derivative assets 57 126 Three-way costless collars – oil Derivative assets 15 3 Basis swaps – natural gas Derivative assets 60 17 Call options – natural gas Derivative assets 4 1 Fixed price swaps – natural gas storage Derivative assets — 1 Fixed price swaps – natural gas Other long-term assets 7 7 Fixed price swaps – oil Other long-term assets 2 1 Fixed price swaps – propane Other long-term assets — 3 Two-way costless collars – natural gas Other long-term assets 20 4 Three-way costless collars – natural gas Other long-term assets 87 74 Three-way costless collars – oil Other long-term assets 15 7 Basis swaps – natural gas Other long-term assets 15 15 Call options – natural gas Other long-term assets — 2 Total derivative assets $ 387 $ 391 (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, 2020 December 31, 2019 Derivatives not designated as hedging instruments: Purchased fixed price swaps – natural gas Derivative liabilities $ — $ 1 Fixed price swaps – natural gas Derivative liabilities 7 1 Fixed price swaps – oil Derivative liabilities 12 6 Fixed price swaps – ethane Derivative liabilities 10 — Fixed price swaps – propane Derivative liabilities 36 — Fixed price swaps – normal butane Derivative liabilities 8 — Fixed price swaps – natural gasoline Derivative liabilities 13 — Two-way costless collars – natural gas Derivative liabilities 43 4 Two-way costless collars – oil Derivative liabilities 1 5 Three-way costless collars – natural gas Derivative liabilities 82 84 Three-way costless collars – oil Derivative liabilities 15 4 Basis swaps – natural gas Derivative liabilities 3 17 Call options – natural gas Derivative liabilities 12 3 Put options – natural gas Derivative liabilities 1 — Swaptions – natural gas Derivative liabilities 2 — Fixed price swaps – natural gas Other long-term liabilities 3 — Fixed price swaps – oil Other long-term liabilities 2 2 Fixed price swaps – propane Other long-term liabilities 2 — Fixed price swaps – normal butane Other long-term liabilities 1 — Fixed price swaps – natural gasoline Other long-term liabilities 2 — Two-way costless collars – natural gas Other long-term liabilities 21 4 Three-way costless collars – natural gas Other long-term liabilities 102 72 Three-way costless collars – oil Other long-term liabilities 15 8 Basis swaps – natural gas Other long-term liabilities 7 9 Call options – natural gas Other long-term liabilities 28 15 Call options – oil Other long-term liabilities — 1 Total derivative liabilities $ 428 $ 236 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, 2020 and 2019: 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 2020 2019 (in millions) Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ 2 $ (1) Purchased fixed price swaps – oil Gain (Loss) on Derivatives — 6 Fixed price swaps – natural gas Gain (Loss) on Derivatives (25) 46 Fixed price swaps – oil Gain (Loss) on Derivatives — (22) Fixed price swaps – ethane Gain (Loss) on Derivatives (21) 6 Fixed price swaps – propane Gain (Loss) on Derivatives (60) 13 Fixed price swaps – normal butane Gain (Loss) on Derivatives (9) — Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (15) — Two-way costless collars – natural gas Gain (Loss) on Derivatives 10 2 Two-way costless collars – oil Gain (Loss) on Derivatives (1) (10) Two-way costless collars – propane Gain (Loss) on Derivatives (1) 2 Three-way costless collars – natural gas Gain (Loss) on Derivatives (77) 37 Three-way costless collars – oil Gain (Loss) on Derivatives 3 (2) Basis swaps – natural gas Gain (Loss) on Derivatives 59 17 Call options – natural gas Gain (Loss) on Derivatives (10) 1 Call options – oil Gain (Loss) on Derivatives 1 (1) Swaptions – natural gas Gain (Loss) on Derivatives 7 — Fixed price swaps – natural gas storage Gain (Loss) on Derivatives (1) 1 Interest rate swaps Gain (Loss) on Derivatives — (1) Total gain (loss) on unsettled derivatives $ (138) $ 94 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 2020 2019 (in millions) Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ (3) $ — Purchased fixed price swaps – oil Gain (Loss) on Derivatives — (3) Fixed price swaps – natural gas Gain (Loss) on Derivatives 142 (2) 78 Fixed price swaps – oil Gain (Loss) on Derivatives 65 10 Fixed price swaps – ethane Gain (Loss) on Derivatives 6 17 Fixed price swaps – propane Gain (Loss) on Derivatives 18 29 Fixed price swaps – normal butane Gain (Loss) on Derivatives (2) — Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (1) — Two-way costless collars – natural gas Gain (Loss) on Derivatives (5) 16 Two-way costless collars – oil Gain (Loss) on Derivatives 17 6 Two-way costless collars – propane Gain (Loss) on Derivatives 2 2 Three-way costless collars – natural gas Gain (Loss) on Derivatives 38 (3) 31 Three-way costless collars – oil Gain (Loss) on Derivatives 9 — Basis swaps – natural gas Gain (Loss) on Derivatives 76 (3) Call options – natural gas Gain (Loss) on Derivatives — (2) (4) Purchased fixed price swaps – natural gas storage Gain (Loss) on Derivatives (1) — Fixed price swaps – natural gas storage Gain (Loss) on Derivatives 2 (1) Interest rate swaps Gain (Loss) on Derivatives (1) — Total gain on settled derivatives $ 362 $ 180 Total gain on derivatives $ 224 $ 274 (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 $9 million amortization of premiums paid related to certain natural gas fixed price options for the year ended December 31, 2020, which is included in gain (loss) on derivatives on the consolidated statements of operations. (3) Includes $2 million amortization of premiums paid related to certain natural gas three-way costless collars for the year ended December 31, 2020, which is included in gain (loss) on derivatives on the consolidated statements of operations. (4) Includes $1 million amortization of premiums paid related to certain natural gas call options for the year ended December 31, 2019, 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, 2020
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Reclassifications from Accumulated Other Comprehensive Income (Loss)	RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) In 2020, 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, 2020: For the year ended December 31, 2020 (in millions) Pension and Other Postretirement Foreign Currency Total Beginning balance, December 31, 2019 $ (19) $ (14) $ (33) Other comprehensive loss before reclassifications — — — Amounts reclassified from other comprehensive income (1) (5) — (5) Net current-period other comprehensive loss (5) — (5) Ending balance, December 31, 2020 $ (24) $ (14) $ (38) (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, 2020 Pension and other postretirement: (in millions) Amortization of prior service cost and net loss (1) Other Loss, Net $ (6) Provision for income taxes (1) Net loss $ (5) Total reclassifications for the period Net loss $ (5) (1) See Note 13 for additional details regarding the Company’s pension and other postretirement benefit plans.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
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, 2020 and 2019 were as follows: December 31, 2020 December 31, 2019 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents $ 13 $ 13 $ 5 $ 5 2018 revolving credit facility due April 2024 (1) 700 700 34 34 Senior notes (2) 2,471 2,609 2,228 2,085 Derivative instruments, net (41) (41) 155 (3) 155 (3) (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 as of December 31, 2019 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. The fair value of the Company's 4.10% Senior Notes due March 2022 is considered to be a Level 2 measurement on the fair value hierarchy. The fair values of the Company's remaining senior notes are considered to be a Level 1 measurement. The carrying values 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 Company measures the fair value of its derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas and liquids forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and non-performance risk. Non-performance risk considers the effect of the Company’s credit standing on the fair value of derivative liabilities and the effect of counterparty credit standing on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. As of December 31, 2020, the impact of non-performance risk on the fair value of the Company’s net derivative liability position was a reduction of the liability of $1 million. The Company has classified its derivative instruments into 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, 2020 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s call options, two-way costless collars, three-way costless collars and swaptions (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. 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. The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves. Assets and liabilities measured at fair value on a recurring basis are summarized below: December 31, 2020 Fair Value Measurements Using: (in millions) Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Assets (Liabilities) at Fair Value Assets: Purchased fixed price swaps $ — $ 1 $ — $ 1 Fixed price swaps — 59 — 59 Two-way costless collars — 74 — 74 Three-way costless collars — 174 — 174 Basis swaps — 75 — 75 Call options — 4 — 4 Liabilities: Fixed price swaps — (96) — (96) Two-way costless collars — (65) — (65) Three-way costless collars — (214) — (214) Basis swaps — (10) — (10) Call options — (40) — (40) Put options — (1) — (1) Swaptions — (2) — (2) Total $ — $ (41) $ — $ (41) December 31, 2019 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 swaps (1) $ — $ 125 $ — $ 125 Two-way costless collars — 21 — 21 Three-way costless collars — 210 — 210 Basis swaps – natural gas — 32 — 32 Call options — 3 — 3 Liabilities: Purchased fixed price swaps — (1) — (1) Fixed price swaps — (9) — (9) Two-way costless collars — (13) — (13) Three-way costless collars — (168) — (168) Basis swaps — (26) — (26) Call options — (19) — (19) 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. See Note 13 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 On November 13, 2020, the Company completed the Merger with Montage. See Note 3 for a discussion of the fair value measurement of assets acquired and liabilities assumed. In 2020, the Company determined that the $6 million carrying value of certain non-core assets exceeded their respective fair value less costs to sell and recognized a $5 million non-cash impairment. The Company used Level 2 measurements to determine the fair value of these assets. In 2019, the Company determined that the $26 million carrying value of certain non-core assets exceeded their respective fair value less costs to sell and recognized a $16 million non-cash impairment. The Company used Level 3 measurements to determine the fair value of these assets. In the third quarter of 2018, the Company determined the carrying value of certain non-full cost pool assets associated with the Fayetteville Shale sale exceeded the fair value less costs to sell. 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, the Company recorded a non-cash impairment charge of $161 million for the year ended December 31, 2018, of which $145 million related to midstream gathering assets and $15 million related to E&P which were both reflected as assets held for sale in the third quarter of 2018. Additionally, the Company recorded a $1 million non-cash impairment related to other non-core assets that were not included in the sale. The estimated fair value of the gathering assets was based on an estimated discounted cash flow model and market assumptions. The significant Level 3 assumptions used in the calculation of estimated discounted cash flows included future commodity prices, projections of estimated quantities of natural gas reserves, operating costs, projections of future rates of production, inflation factors and risk adjusted discount rates.

Debt

Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Debt	DEBT The components of debt as of December 31, 2020 and 2019 consisted of the following: December 31, 2020 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Total Long-term debt: Variable rate (2.110% at December 31, 2020) 2018 revolving credit facility, due April 2024 $ 700 $ — (1) $ — $ 700 4.10% Senior Notes due March 2022 207 — — 207 4.95% Senior Notes due January 2025 (2) 856 (4) (1) 851 7.50% Senior Notes due April 2026 618 (6) — 612 7.75% Senior Notes due October 2027 440 (5) — 435 8.375% Senior Notes due September 2028 350 (5) — 345 Total long-term debt $ 3,171 $ (20) $ (1) $ 3,150 December 31, 2019 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount 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 (1) At December 31, 2020 and 2019, unamortized issuance expense of $12 million and $11 million, respectively, associated with the 2018 revolving credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheet. (2) Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company's bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company's bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment due date. The first coupon payment to the bondholders at the higher interest rate will be paid in January 2021. The following is a summary of scheduled debt maturities by year as of December 31, 2020: (in millions) 2021 $ — 2022 207 2023 — 2024 (1) 700 2025 856 Thereafter 1,408 $ 3,171 (1) The Company’s current revolving credit facility matures in 2024. Credit Facilities 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”) with a group of banks that, as amended, has a maturity date of April 2024. 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. The Company may utilize the 2018 credit facility in the form of loans and letters of credit. 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, as amended, ranges from 1.75% to 2.75% based on the Company’s utilization of 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, as amended, ranges from 0.75% to 1.75% based on the Company’s utilization of the 2018 credit facility. In conjunction with the October 2020 redetermination process, the Company entered into an amendment to the credit agreement governing the 2018 credit facility to, among other matters: • limit the Company's unrestricted cash and cash equivalents to $200 million when loans under the 2018 credit facility are outstanding, subject to certain exceptions; and • increase the applicable rate by 25 basis points on loans outstanding under the 2018 credit facility. In addition, the following amendments and redeterminations were made upon the closing of the Merger: • increase the elected borrowing base and total aggregate commitments to $2.0 billion, the maximum permitted lien amount based on provisions in certain of the Company's senior note indentures; • include certain Montage entities owning gas and oil properties as guarantors to the 2018 credit facility; and • deem any Montage letters of credit issued prior to the Merger close to have been issued 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, 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. For purposes of calculating consolidated EBITDAX, the Company can include the Montage consolidated EBITDAX prior to the merger for the same twelve-month rolling period. 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, 2020, 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. As of December 31, 2020, the Company had $233 million in letters of credit and $700 million in borrowings outstanding under the 2018 credit facility. The Company's exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as Administrative Agent, and the Company. The alternative rate will be based on the prevailing market convention and is expected to be the Secured Overnight Financing Rate (“SOFR”). Senior Notes In January 2015, the Company completed a public offering of $1.0 billion aggregate principal amount of its 4.95% Senior Notes due 2025 (the “2025 Notes”). The interest rate on the 2025 Notes is determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 2025 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. Effective in July 2018, the interest rate for the 2015 Notes was 6.20%, reflecting a net downgrade in the Company's bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company's bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment due date. The first coupon payment to the bondholders at the higher interest rate will be paid in January 2021. In the event of future downgrades, the coupons for this series of notes have been capped at 6.95%. 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. In the first half of 2020, the Company repurchased $6 million of its 4.10% senior notes due 2022, $36 million of its 4.95% senior notes due 2025, $21 million of its 7.50% senior notes due 2026 and $44 million of its 7.75% senior notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Operating Commitments and Contingencies As of December 31, 2020, 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, $531 million 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 $923 million of that amount. As of December 31, 2020, 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 (1) $ 8,013 $ 860 $ 1,532 $ 1,286 $ 1,813 $ 2,522 Pending regulatory approval and/or construction (2) 531 2 30 37 88 374 Total transportation charges $ 8,544 $ 862 $ 1,562 $ 1,323 $ 1,901 $ 2,896 (1) With the close of the Montage Merger the Company acquired firm transportation commitments of approximately $1,100 million. These commitments approximate $99 million within the next year, $197 million from 1 to 3 years, $196 million from 3 to 5 years, $284 million from 5 to 8 years and $324 million beyond 8 years. (2) Based on the estimated in-service dates as of December 31, 2020. 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 2025 with a current aggregate annual payment of approximately $11 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 2036. As of December 31, 2020, future minimum payments under these non-cancelable leases accounted for as operating leases (including short-term) are approximately $30 million in 2021, $21 million in 2022, $18 million in 2023, $14 million in 2024, $12 million in 2025 and $36 million thereafter. The Company also has commitments for compression services and compression rentals related to its E&P segment. As of December 31, 2020, future minimum payments under these non-cancelable agreements (including short-term obligations) are approximately $20 million in 2021, $14 million in 2022, $3 million in 2022 and less than $1 million in 2024. 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. 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, 2020, 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. 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 filed a petition to review the trial court’s decision with the Texas Supreme Court, and the Court requested a response from the plaintiff. The Court subsequently ordered full briefing on the merits of the case. 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 intends 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, 2020
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES The provision (benefit) for income taxes included the following components: (in millions) 2020 2019 2018 Current: Federal $ (2) $ (1) $ (5) State — (1) 6 (2) (2) 1 Deferred: Federal 371 (431) — State 38 22 — 409 (409) — Provision (benefit) for income taxes $ 407 $ (411) $ 1 The provision for income taxes was an effective rate of (15)% in 2020, (86)% in 2019 and 0% in 2018. The Company’s effective tax rate increased in 2020, as compared with 2019, primarily due to the increase in the valuation allowance in 2020. 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) 2020 2019 2018 Expected provision (benefit) at federal statutory rate $ (568) $ 101 $ 113 Increase (decrease) resulting from: State income taxes, net of federal income tax effect (55) 11 13 Change in valuation allowance 1,034 (522) (121) Removal of sequestration fee on AMT receivables — — (5) Other (4) (1) 1 Provision (benefit) for income taxes $ 407 $ (411) $ 1 The 2020 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, 2020 and 2019 were as follows: (in millions) 2020 2019 Deferred tax liabilities: Differences between book and tax basis of property $ — $ 312 Derivative activity — 34 Right of use lease asset 38 37 Other 2 2 40 385 Deferred tax assets: Differences between book and tax basis of property 295 — Accrued compensation 38 33 Accrued pension costs 11 9 Asset retirement obligations 20 13 Net operating loss carryforward 1,117 769 Future lease payments 38 37 Derivative activity 9 — Capital loss carryover 27 — Other 24 18 1,579 879 Valuation allowance (1,539) (87) 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. 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. Additionally, in January 2020 the IRS announced that any previously sequestered amounts relating to these alternative minimum tax refunds would also be refunded. The Company had approximately $2 million in sequestered amounts relating to alternative minimum tax refunds. All of those refunds have been received as of December 2020 after the CARES Act (enacted in March 2020) accelerated alternative minimum tax refunds. In 2020, the Company received refunds related to federal income tax of $32 million. The Company received a refund of $1 million in state income tax in 2019 and paid $6.3 million in state income tax in 2018. The Company’s net operating loss carryforward as of December 31, 2020 was $4.5 billion and $2 billion for federal and state reporting purposes, respectively, the majority of which will expire between 2035 and 2039. Included in the Company's net operating loss carryforward are the net operating loss carryforwards acquired in the Montage acquisition of $1 billion. A portion of the Montage-related net operating loss carryovers are subject to an annual section 382 limitation of $1.7 million, and the Company has appropriately accounted for this limitation in purchase accounting. In addition, certain net operating loss carryovers are subject to a section 382 limitation of $90 million, but the Company does not expect this limit to have a material impact on its net operating loss carryforward balance. 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 2039. The Company also had a statutory depletion carryforward of $13 million and $55 million related to interest deduction carryforward as of December 31, 2020. 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. Due to unexpected significant pricing declines resulting from the effects of COVID-19 and developments related to Russia/OPEC, as well as the general oversupply of the market along with the material write-down of the carrying value of the Company’s natural gas and oil properties, in addition to other negative evidence, the Company concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense of $408 million for the increase in its valuation allowance in the first quarter of 2020. The net change in valuation allowance is reflected as a component of income tax expense. The Company also has retained a valuation allowance of $87 million related to net operating losses in jurisdictions in which it no longer operates. Management will continue to assess available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence is no longer present. 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. A reconciliation of the changes to the valuation allowance is as follows: (in millions) 2020 2019 Valuation allowance at beginning of year $ 87 $ 609 Release of valuation allowance — (522) Establishment of valuation allowance on opening deferred balance 408 — Opening balance adjustments 6 — Changes based on 2020 activity 626 — Purchase accounting 412 — Valuation allowance at end of year $ 1,539 $ 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, 2020, 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) 2020 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 2018 to 2020 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, 2020
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS The following table summarizes the Company’s 2020 and 2019 activity related to asset retirement obligations: (in millions) 2020 2019 Asset retirement obligation at January 1 $ 57 $ 61 Accretion of discount 4 3 Obligations incurred 1 2 Obligations assumed from Montage 28 — Obligations settled/removed (6) (9) Revisions of estimates 1 — Asset retirement obligation at December 31 $ 85 $ 57 Current liability $ 4 $ 6 Long-term liability 81 51 Asset retirement obligation at December 31 $ 85 $ 57

Retirement and Employee Benefit

Retirement and Employee Benefit Plans	12 Months Ended
	Dec. 31, 2020
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, $2 million and $3 million of contribution expense in 2020, 2019 and 2018, respectively. Additionally, the Company capitalized $1 million of contributions in 2020 and $1 million and $2 million in 2019 and 2018, respectively, directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems. Defined Benefit Pension and Other Postretirement Plans Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. As part of ongoing effort to reduce costs, the Company has elected to freeze its pension plan effective January 1, 2021. Employees that were participants in the pension plan prior to January 1, 2021 will continue to receive the interest component of the plan but will no longer receive the service component. 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. Prior to January 1, 2021, substantially all of the Company’s employees were covered by the defined benefit pension. Substantially all of the Company’s employees continue to be covered by the 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. In 2020, the settlement loss was immaterial. The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status as of December 31, 2020 and 2019: Pension Benefits Other Postretirement Benefits (in millions) 2020 2019 2020 2019 Change in benefit obligations: Benefit obligation at January 1 $ 126 $ 125 $ 13 $ 13 Service cost 7 7 2 1 Interest cost 5 5 — — Participant contributions — — — — Actuarial loss 16 15 1 1 Benefits paid (13) (2) (1) (2) Plan amendments — — (2) — Curtailments (2) — — — Settlements — (24) — — Benefit obligation at December 31 $ 139 $ 126 $ 13 $ 13 Pension Benefits Other Postretirement Benefits (in millions) 2020 2019 2020 2019 Change in plan assets: Fair value of plan assets at January 1 $ 96 $ 91 $ — $ — Actual return on plan assets 11 16 — — Employer contributions 12 12 1 2 Participant contributions — — — — Benefits paid (13) (2) (1) (2) Settlements — (21) — — Fair value of plan assets at December 31 $ 106 $ 96 $ — $ — Funded status of plans at December 31 $ (33) $ (30) $ (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, 2020 and 2019 are as follows: (in millions) 2020 2019 Projected benefit obligation $ 139 $ 126 Accumulated benefit obligation 139 124 Fair value of plan assets 106 96 Pension and other postretirement benefit costs include the following components for 2020, 2019 and 2018: Pension Benefits Other Postretirement Benefits (in millions) 2020 2019 2018 2020 2019 2018 Service cost $ 7 $ 7 $ 10 $ 2 $ 1 $ 2 Interest cost 5 5 5 — — 1 Expected return on plan assets (6) (6) (7) — — — Amortization of transition obligation — — — — — — Amortization of prior service cost — — — — — — Amortization of net loss 1 2 2 — — — Net periodic benefit cost 7 8 10 2 1 3 Curtailment gain — — — — — (4) Settlement loss — 6 — — — — Total benefit cost (benefit) $ 7 $ 14 $ 10 $ 2 $ 1 $ (1) 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, 2020 and 2019 were as follows: Pension Benefits Other Postretirement Benefits (in millions) 2020 2019 2020 2019 Net actuarial (loss) gain arising during the year $ (12) $ (5) $ 2 $ (1) Amortization of prior service cost — — — — Amortization of net loss 1 2 — — Settlements — 8 — — Curtailments 3 — — — Tax effect 3 (1) (1) — $ (5) $ 4 $ 1 $ (1) Included in accumulated other comprehensive income as of December 31, 2020 and 2019 was a $36 million loss ($28 million net of tax) and a $30 million loss ($22 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2020, $5 million was classified from accumulated other comprehensive income, primarily driven by actuarial 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 2021 is a $1 million expense. The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2020 and 2019 are as follows: Pension Benefits Other Postretirement Benefits 2020 2019 2020 2019 Discount rate 3.10 % 3.70 % 2.80 % 3.50 % 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 2020, 2019 and 2018 are as follows: Pension Benefits Other Postretirement Benefits 2020 2019 2018 2020 2019 2018 Discount rate 3.70 % 3.70 % 4.35 % 3.50 % 4.35 % 4.35 % Expected return on plan assets 6.50 % 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 2020 and 2019: 2020 2019 Health care cost trend assumed for next year 6.5 % 7.0 % Rate to which the cost trend is assumed to decline 5.0 % 5.0 % Year that the rate reaches the ultimate trend rate 2037 2037 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 $ (2) Effect on postretirement benefit obligations $ 2 $ (2) Pension Payments and Asset Management In 2020, the Company contributed $12 million to its pension plans and $1 million to its other postretirement benefit plan. The Company expects to contribute $13 million to its pension and other postretirement benefit plans in 2021. The following benefit payments, which reflect projected future interest costs, are expected to be paid: Pension Benefits Other Postretirement Benefits (in millions) 2021 $ 5 2021 $ 1 2022 5 2022 1 2023 5 2023 1 2024 6 2024 1 2025 5 2025 1 Years 2026-2030 26 Years 2026-2030 4 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, 2020, 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) 30 % 49 % Non-U.S. equity (2) 30 % 17 % Total equity securities 60 % 66 % Fixed income (3) 35 % 32 % Cash (4) 5 % 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, 2020 is as follows: (in millions) Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs Significant Unobservable Inputs Measured within fair value hierarchy Equity securities: U.S. large cap value equity (1) $ 10 $ 10 $ — $ — U.S. large cap core equity (2) 24 24 — — U.S. small cap equity (3) 13 13 — — Non-U.S. equity (4) 18 18 — — Fixed income (5) 34 34 — — Cash and cash equivalents 2 2 — — Total measured within fair value hierarchy $ 101 $ 101 $ — $ — Measured at net asset value (6) Equity securities: U.S. large cap growth equity (7) 3 U.S. small cap equity (3) 2 Total measured at net asset value $ 5 Total plan assets at fair value $ 106 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, 2019 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 (8) $ 3 $ 3 $ — $ — U.S. large cap value equity (1) 6 6 — — U.S. small cap equity (3) 2 2 — — Non-U.S. equity (4) 32 32 — — Fixed income (5) 22 22 — — Cash and cash equivalents 2 2 — — Total measured within fair value hierarchy $ 67 $ 67 $ — $ — Measured at net asset value (6) Equity securities: U.S. large cap growth equity (7) 3 U.S. large cap core equity (2) 18 Fixed income (5) 8 Total measured at net asset value $ 29 Total plan assets at fair value $ 96 (1) 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. (2) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees. (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) 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. (6) Plan assets for which fair value was measured using net asset value as a practical expedient. (7) An institutional fund that seeks to invest in companies with sustainable competitive advantages, as identified through proprietary research. (8) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.

Long-Term Incentive Compensatio

Long-Term Incentive Compensation	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Long-Term Incentive Compensation	LONG-TERM INCENTIVE 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 years from the grant date and expire seven years from the date of grant. The Company issues shares of restricted stock or restricted stock units to employees and directors which generally vest over four years. Restricted stock, restricted stock units and stock options granted to participants under the 2013 Plan, as amended and restated, immediately vest upon death, disability or retirement (subject to a minimum of three years of service). The Company issues performance units which have historically vested over three years to employees. The performance units granted in 2018, 2019 and 2020 cliff-vest at the end of three years. 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. In February 2020, the Company announced a strategic realignment of the Company’s organizational structure. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. The Company also recognized additional severance costs in the fourth quarter of 2020 related to continued organizational restructuring. 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, 2020 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, 2020, 2019 and 2018: (in millions) 2020 2019 2018 Stock options – general and administrative expense $ — $ 1 $ 2 Stock options – general and administrative expense capitalized $ — $ — $ — The Company recorded no deferred tax assets related to stock options for the year ended December 31, 2020, compared to deferred tax assets of less than $1 million for the years ended December 31, 2019 and 2018. Additionally, the Company had no unrecognized compensation cost related to unvested stock options at December 31, 2020. 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 2020, 2019 or 2018. The following tables summarize stock option activity for the years 2020, 2019 and 2018, and provide information for options outstanding at December 31 of each year: 2020 2019 2018 Number 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 4,635 $ 15.26 5,178 $ 17.06 6,020 $ 19.43 Granted — $ — — $ — — $ — Exercised — $ — — $ — — $ — Forfeited or expired (785) $ 24.46 (543) $ 32.38 (842) $ 33.99 Options outstanding at December 31 3,850 $ 13.39 4,635 $ 15.26 5,178 $ 17.06 Options Outstanding Options Exercisable Range of Exercise Prices Options Outstanding at December 31, 2020 Weighted Average Exercise Price Weighted Average Remaining Contractual Life Options Exercisable at December 31, 2020 Weighted Average Exercise Price Weighted Average Remaining Contractual Life (in thousands) (years) (in thousands) (years) $7.74-$29.42 3,126 $ 8.95 2.3 3,126 $ 8.95 2.3 $30.59-$35.64 634 $ 30.59 0.9 634 $ 30.59 0.9 $46.55-$46.55 90 $ 46.55 0.3 90 $ 46.55 0.3 3,850 $ 13.39 2.0 3,850 $ 13.39 2.0 No options were granted or exercised in 2020, 2019 or 2018. Equity-Classified Restricted Stock The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2020, 2019 and 2018: (in millions) 2020 2019 2018 Restricted stock grants – general and administrative expense $ 3 $ 6 $ 9 Restricted stock grants – general and administrative expense capitalized $ 1 $ 4 $ 5 The Company also recorded deferred tax asset of $2 million related to restricted stock for the year ended December 31, 2020, compared to a reduction in the deferred tax assets of less than $1 million and deferred tax asset of $2 million for the years end 2019 and 2018, respectively. As of December 31, 2020, there was $1 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 less than one year. The following table summarizes the restricted stock activity for the years 2020, 2019 and 2018, and provides information for restricted stock outstanding at December 31 of each year: 2020 2019 2018 Number of 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 1,480 $ 7.00 2,717 $ 7.91 6,254 $ 8.85 Granted 584 $ 2.86 493 $ 3.06 350 $ 4.72 Vested (1,098) $ 5.26 (1,516) $ 7.16 (2,058) $ 9.24 Forfeited (269) (1) $ 7.79 (214) (2) $ 8.38 (1,829) (3) $ 9.01 Unvested shares at December 31 697 $ 5.97 1,480 $ 7.00 2,717 $ 7.91 (1) Includes 171,813 shares forfeited as a result of the reduction in workforce for the year end December 31, 2020. (2) Includes 65,196 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2019. (3) 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 2020, $2 million for 2019 and $2 million for 2018. The total fair value of shares vested were $6 million for 2020, $11 million for 2019 and $19 million for 2018. Equity-Classified Restricted Stock Units As a result of the Merger with Montage, certain Montage employees became employees of Southwestern and retained their original equity awards. The amount of compensation costs related these equity-classified restricted stock units recorded by the Company was immaterial for the year ended December 31, 2020. As of December 31, 2020, there was less than $1 million of total unrecognized compensation cost related to unvested equity-classified restricted stock units that is expected to be recognized over a weighted-average period of approximately one year. The following table summarizes equity-classified restricted stock unit activity to be paid out in Company stock for the year ended December 31, 2020. Number Weighted Average (in thousands) Unvested Units at January 1, 2020 — $ — Granted 186 $ 3.05 Vested (42) $ 3.05 Forfeited (10) $ 3.05 Unvested Units at December 31, 2020 134 $ 3.05 Equity-Classified Performance Units The Company recorded compensation costs related to equity-classified performance units for the years ended December 31, 2020, 2019 and 2018. 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 2020, 2019 or 2018. (in millions) 2020 2019 2018 Performance units – general and administrative expense $ — $ 1 $ 3 Performance units – general and administrative expense capitalized $ — $ — $ 1 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, 2020, compared to deferred tax assets of less than $1 million and $1 million in 2019 and 2018, respectively. As of December 31, 2020, there are no more equity-classified performance units outstanding. The following table summarizes equity-classified performance unit activity to be paid out in Company stock for the years ended December 31, 2020, 2019 and 2018, and provides information for unvested units as of December 31, 2020, 2019 and 2018: 2020 2019 2018 Number of Units (1) Weighted Number of Units (1) Weighted Number of Units (1) Weighted (in thousands) (in thousands) (in thousands) Unvested units at January 1 178 $ 10.47 598 $ 10.01 1,084 $ 10.12 Granted — $ — — $ — — $ — Vested (178) $ 10.47 (378) $ 9.59 (290) $ 10.47 Forfeited — $ — (42) (2) $ 10.47 (196) (3) $ 9.94 Unvested shares at December 31 — $ — 178 $ 10.47 598 $ 10.01 (1) These amounts reflect the number of performance units granted in thousands. The actual payout of shares may range from a minimum of zero shares to a maximum of two shares per unit contingent upon TSR. The performance units have a three-year vesting term and the actual disbursement of shares, if any, is determined during the first quarter following the end of the three-year vesting period. (2) Includes 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 years and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award. (in millions) 2020 2019 2018 Restricted stock units – general and administrative expense $ 5 $ 7 $ 4 Restricted stock units – general and administrative expense capitalized $ 2 $ 5 $ 3 The Company also recorded deferred tax assets of $1 million for the year ended December 31, 2020, compared to less than $1 million and $2 million related to liability-classified restricted stock units for the years ended 2019 and 2018, respectively. As of December 31, 2020, there was $22 million of total unrecognized compensation cost related to liability-classified restricted stock units that is expected to be recognized over a weighted-average period of two years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The following table summarizes restricted stock unit activity to be paid out in cash for the years ended December 31, 2020 and 2019 and provides information for unvested units as of December 31, 2020 and 2019: 2020 2019 2018 Number Weighted Average Fair Value Number Weighted Average Fair Value Number Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested units at January 1 12,992 $ 2.42 8,202 $ 3.41 — $ — Granted 6,172 $ 1.41 8,659 $ 4.34 12,216 $ 3.69 Vested (3,960) $ 1.43 (2,624) $ 4.09 (232) $ 5.14 Forfeited (3,591) (1) $ 2.67 (1,245) (2) $ 3.48 (3,782) (3) $ 4.86 Unvested units at December 31 11,613 $ 2.67 12,992 $ 2.42 8,202 $ 3.41 (1) Includes 2,010,196 units related to the reduction in workforce for the year ended December 31, 2020. (2) Includes 400,056 units related to the reduction in workforce for the year ended December 31, 2019. (3) Includes 2,766,610 units related to the reduction in workforce for the year ended December 31, 2018. Liability-Classified Performance Units In 2020, 2019 and 2018 the Company granted performance units that vest at the end of, or over, a three-year period and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers. The performance unit awards granted in 2019 include a performance condition based on return on average capital employed and two market conditions, one based on absolute TSR and the other on relative TSR. The performance unit awards granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative TSR. The fair values of all market conditions discussed above are calculated by Monte Carlo models on a quarterly basis. (in millions) 2020 2019 2018 Liability-classified performance units – general and administrative expense $ 7 $ 2 $ 2 Liability-classified performance units – general and administrative expense capitalized $ 2 $ 1 $ — The Company also recorded deferred tax assets of $2 million related to liability-classified performance units for the year ended December 31, 2020, compared to a reduction of deferred tax asset of less than $1 million and a deferred tax asset of $1 million for the years ended 2019 and 2018, respectively. As of December 31, 2020, there was $14 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of two years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against the Performance Measures. The following table summarizes liability-classified performance unit activity to be paid out in cash or stock for the years ended December 31, 2020, 2019 and 2018 and provides information for unvested units as of December 31, 2020, 2019 and 2018: 2020 2019 2018 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) (in thousands) Unvested units at January 1 5,142 $ 2.42 2,803 $ 3.41 — $ — Granted 6,172 $ 1.41 2,757 $ 4.34 3,200 $ 3.70 Vested — $ — (43) $ 2.42 — $ — Forfeited (2,615) (1) $ 3.05 (375) (2) $ 3.12 (397) (3) $ 4.55 Unvested units at December 31 8,699 $ 2.57 5,142 $ 2.42 2,803 $ 3.41 (1) Includes 518,450 units related to the reduction in workforce for the year ended December 31, 2020. (2) Includes 375,086 units related to the reduction in workforce for the year ended December 31, 2019. (3) Includes 295,160 units related to the reduction in workforce for the year ended December 31, 2018. Cash-Based Compensation Performance Cash Awards In 2020, the Company granted performance cash awards that vest over a four-year period and are payable in cash on an annual basis. The value of each unit of the award equal one dollar. The Company recognizes the cost of these awards as general and administrative expense, operating expense and capitalized expense over the vesting period of the awards. The performance cash awards granted in 2020 include a performance condition determined annually by the Company. In 2020, the performance measure is a targeted discretionary cash flow amount. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be cancelled. Number Weighted Average (in thousands) Unvested units at January 1, 2020 — $ — Granted 20,044 $ 1.00 Vested (100) $ 1.00 Forfeited (1,591) (1) $ 1.00 Unvested Units at December 31, 2020 18,353 $ 1.00 (1) Includes 945,500 units related to the reduction in workforce for the year ended December 31, 2020.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2020
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. 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 2020 Revenues from external customers $ 1,391 $ 917 $ — $ 2,308 Intersegment revenues (43) 1,228 — 1,185 Depreciation, depletion and amortization expense 348 9 — 357 Impairments 2,830 — — 2,830 Operating loss (2,864) (1) (7) — (2,871) Interest expense (2) 94 — — 94 Gain on derivatives 224 — — 224 Gain on early extinguishment of debt — — 35 35 Other income, net — — 1 1 Provision for income taxes (2) 407 — — 407 Assets 4,654 (3) 381 125 5,160 Capital investments (4) 899 — — 899 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 (5) (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 6,717 Capital investments (4) 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) 2 (2) — — Provision for income taxes (2) 1 — — 1 Assets 4,872 (3) 539 386 5,797 Capital investments (4) 1,231 9 8 1,248 (1) Operating income for the E&P segment includes $16 million of restructuring charges and $41 million of acquisition-related charges for the year ended December 31, 2020. (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) Capital investments include a decrease of $3 million for 2020, an increase of $34 million for 2019 and a decrease of $53 million for 2018 related to the change in accrued expenditures between years. (5) Operating income for the E&P segment includes $11 million of restructuring charges for the year ended December 31, 2019. (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. The following table presents the breakout of other assets, which represent corporate assets not allocated to segments and assets for non-reportable segments for the years ended December 31, 2020, 2019 and 2018: For the years ended December 31, (in millions) 2020 2019 2018 Cash and cash equivalents $ 13 $ 5 $ 205 Accounts receivable 1 — 4 Income taxes receivable — 30 89 Current hedging asset — — 1 Prepayments 6 8 8 Property, plant and equipment 16 27 60 Unamortized debt expense 11 11 11 Right-of-use lease assets 72 80 — Non-qualified retirement plan 6 7 8 $ 125 $ 168 $ 386 Included in intersegment revenues of the Marketing segment are $1.2 billion, $1.6 billion and $2.3 billion for 2020, 2019 and 2018, 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.

Supplemental Quarterly Results

Supplemental Quarterly Results (Unaudited)	12 Months Ended
	Dec. 31, 2020
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, 2020 and 2019: (in millions, except share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 2020 Operating revenues $ 592 $ 410 $ 527 $ 779 Operating loss (1,490) (756) (381) (244) Net loss (1,547) (880) (593) (92) Loss per share – Basic (2.86) (1.63) (1.04) (0.14) Loss per share – Diluted (2.86) (1.63) (1.04) (0.14) 2019 Operating revenues $ 990 $ 667 $ 636 $ 745 Operating income (loss) 213 22 (29) 64 Net income 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

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	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, 2020 and 2019: (in millions) 2020 2019 Proved properties $ 25,789 $ 23,744 Unproved properties 1,472 1,506 Total capitalized costs 27,261 25,250 Less: Accumulated depreciation, depletion and amortization (23,362) (20,203) Net capitalized costs $ 3,899 $ 5,047 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, 2020: (in millions) 2020 2019 2018 Prior Total Property acquisition costs $ 116 $ 44 $ 34 $ 1,022 $ 1,216 Exploration and development costs 17 17 14 20 68 Capitalized interest 62 47 33 46 188 $ 195 $ 108 $ 81 $ 1,088 $ 1,472 Of the total net unevaluated costs excluded from amortization as of December 31, 2020, approximately $1.1 billion is related to undeveloped properties in Southwest Appalachia (acquired in 2014 and 2015), $88 million is related to the recently acquired Montage properties and approximately $6 million is related to the acquisition of undeveloped properties in Northeast Appalachia. Additionally, the Company has approximately $188 million of unevaluated capitalized interest and $61 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) 2020 2019 2018 Unproved property acquisition costs $ 124 (1) $ 162 $ 164 Exploration costs — 2 5 Development costs 784 936 1,014 Capitalized costs incurred $ 908 $ 1,100 $ 1,183 Full cost pool amortization per Mcfe $ 0.38 $ 0.56 $ 0.51 (1) Excludes $90 million of unevaluated property acquisition costs associated with the non-cash Montage Merger. Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $88 million, $109 million and $115 million during 2020, 2019 and 2018, 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 $56 million, $77 million and $90 million during 2020, 2019 and 2018, 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) 2020 2019 2018 Sales $ 1,348 $ 1,703 $ 2,525 Production (lifting) costs (866) (781) (974) Depreciation, depletion and amortization (348) (462) (514) Impairment of natural gas and oil properties (2,825) — — (2,691) 460 1,037 Provision for income taxes (1) — 110 — Results of operations (2) $ (2,691) $ 350 $ 1,037 (1) Prior to the recognition of a valuation allowance, in 2020 and 2018 the Company recognized an income tax provision (benefit) of ($624) million and $254 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 97% of the present worth of the Company’s total proved reserves as of December 31 of 2020. For 2019 and 2018, NSAI’s audit accounted for 99% of the present worth of the Company’s total proved properties. 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. The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2020, 2019 and 2018, all of which were located in the United States: Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) 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 (1) (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 (2) 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 Revisions of previous estimates due to price (2,143) (32,507) (338,639) (4,370) Revisions of previous estimates other than price 763 3,816 106,444 1,424 Extensions, discoveries and other additions 714 135 4,371 741 Production (694) (5,141) (25,927) (880) Acquisition of reserves in place (3) 1,911 18,796 55,141 2,354 Disposition of reserves in place — — — — December 31, 2020 9,181 58,024 410,151 11,990 (1) The 2018 disposition is primarily associated with the Fayetteville Shale sale. (2) For the year ended December 31, 2019, 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. (3) The 2020 acquisition is primarily associated with the Montage Merger. Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) Proved developed reserves as of: December 31, 2018 4,395 18,037 175,480 5,557 December 31, 2019 4,906 26,124 226,271 6,421 December 31, 2020 6,342 33,563 276,548 8,203 Proved undeveloped reserves as of: December 31, 2018 3,649 50,970 401,583 6,364 December 31, 2019 3,724 46,801 382,490 6,300 December 31, 2020 2,839 24,461 133,603 3,787 The Company’s estimated proved natural gas, oil and NGL reserves were 11,990 Bcfe at December 31, 2020, compared to 12,721 Bcfe at December 31, 2019. The Company’s reserves decreased in 2020, compared to 2019, as acquisitions, non-price revisions, positive extensions, discoveries and other additions in Appalachia were more than offset by negative price revisions and production. The increase in non-price revisions at December 31, 2020 resulted primarily from increased well performance and lower operating costs. The increase in the Company’s reserves in 2019 primarily resulted from the positive extensions, discoveries, other additions and 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 following table summarizes the changes in reserves for 2018, 2019 and 2020: Appalachia Fayetteville (in Bcfe) Northeast Southwest Shale (1) Other (2) Total 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 Net revisions Price revisions (389) (3,981) — — (4,370) Performance and production revisions 46 1,378 — — 1,424 Total net revisions (343) (2,603) — — (2,946) Extensions, discoveries and other additions Proved developed 198 69 — — 267 Proved undeveloped 474 — — — 474 Total reserve additions 672 69 — — 741 Production (473) (407) — — (880) Acquisition of reserves in place 223 2,131 — — 2,354 Disposition of reserves in place — — — — — December 31, 2020 4,916 7,073 — 1 11,990 (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 for the year ended December 31, 2019 include 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, 2020 proved reserves included 2,437 Bcfe of proved undeveloped reserves from 138 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 $207 million when discounted at 10%. The Company made a final investment decision and is committed to developing these reserves within the next five years from the date of initial booking. The Company’s December 31, 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 that have a negative $50 million present value when discounted at 10%. 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 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, 2020, 2019 and 2018 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) 2020 2019 2018 Future cash inflows $ 17,997 $ 27,003 $ 34,523 Future production costs (11,969) (14,981) (15,347) Future development costs (1) (1,924) (3,246) (4,095) Future income tax expense — (476) (2,079) Future net cash flows 4,104 8,300 13,002 10% annual discount for estimated timing of cash flows (2,257) (4,600) (7,003) Standardized measure of discounted future net cash flows $ 1,847 $ 3,700 $ 5,999 (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) 2020 2019 2018 Natural gas (per MMBtu) $ 1.98 $ 2.58 $ 3.10 Oil (per Bbl) 39.57 55.69 65.56 NGLs (per Bbl) 10.27 11.58 17.64 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 2020, 2019 and 2018: (in millions) 2020 2019 2018 Standardized measure, beginning of year $ 3,700 $ 5,999 $ 5,562 Sales and transfers of natural gas and oil produced, net of production costs (478) (923) (1,564) Net changes in prices and production costs (2,720) (3,510) 2,162 Extensions, discoveries, and other additions, net of future production and development costs 81 234 335 Acquisition of reserves in place 443 — — Sales of reserves in place — (2) (2,022) Revisions of previous quantity estimates (987) 152 361 Net change in income taxes 35 491 (304) Changes in estimated future development costs 1,241 621 (166) Previously estimated development costs incurred during the year 624 704 536 Changes in production rates (timing) and other (466) (718) 521 Accretion of discount 374 652 578 Standardized measure, end of year $ 1,847 $ 3,700 $ 5,999

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
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, 2020, 2019 and 2018 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. Customers include major energy companies, utilities and industrial purchasers of Natural gas. For the year ended December 31, 2020, one purchaser accounted for 10% of total revenues. A default on this account could have a material impact on the Company, but the Company does not believe that there is a material risk of default. No other purchasers accounted for greater than 10% of consolidated revenues. For the year ended December 31, 2019, no single customer accounted for 10% or greater of total sales. The Company believes that the loss of any one customer would not have an adverse effect on its ability to sell its natural gas, oil and NGL production.
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, 2020, and December 31, 2019: (in millions) December 31, 2020 December 31, 2019 Cash $ 13 $ 5 Marketable securities (1) — — Total $ 13 $ 5 (1) Consists of government stable value money market funds. Immaterial as of December 31, 2020 and 2019. 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 $16 million and $15 million as of December 31, 2020 and 2019, 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, 2020, the Company had a total of $1,472 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. In the first, second and third quarters of 2020, the net book value of the Company's United States natural gas and oil properties exceeded the ceiling by approximately $1,479 million, $650 million and $361 million, respectively, and resulted in non-cash ceiling test impairments. At December 31, 2020, using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $1.98 per MMBtu, West Texas Intermediate oil of $39.57 per barrel and NGLs of $10.27 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $335 million and resulted in an additional non-cash ceiling test impairment. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2020. No impairment expense was recorded for the year ended December 31, 2020 in relation to the Company’s recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement . Pursuant to SEC guidance, the Company determined that the fair value of the properties acquired at the closing of the Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021 as long as the Company can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, the Company is required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Merger was based on forward strip natural gas and oil pricing existing at the date of the Merger, and management affirmed that there has not been a material decline to the fair value of these acquired assets since the Merger. The properties acquired in the Merger have an unamortized cost at December 31, 2020 of $1,087 million. Had management not received the waiver from the SEC, the impairment charge recorded would have been an additional $539 million for the year ended December 31, 2020. 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 did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2019. 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 results 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. 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. Other Property and Equipment. 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 estimated useful lives of those assets depreciated under the straight-line method are as follows: Water facilities 5 – 10 years Gathering systems 15 – 25 years Technology infrastructure 3 – 7 years Drilling rigs and equipment 3 years Buildings and leasehold improvements 10 – 30 years Other property, plant and equipment is comprised of the following: (in millions) December 31, 2020 December 31, 2019 Water facilities $ 228 $ 217 Gathering systems 54 32 Technology infrastructure 133 154 Drilling rigs and equipment 26 32 Land, buildings and leasehold improvements 41 41 Other 41 44 Less: Accumulated depreciation and impairment (311) (300) Total $ 212 $ 220 Impairment of Long-Lived Assets . The carrying value of non-full cost pool long-lived assets is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. 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 years ended December 31, 2020 and 2019 the Company recognized non-cash impairments of $5 million and $16 million, respectively, for non-core assets. During 2018, the Company recognized a non-cash impairment charge of $160 million related to gathering and other E&P assets sold in the Fayetteville Shale sale and $11 million related to other non-core assets. 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, 2020 and 2019, the Company had $48 million and $56 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, 2020, 2019 and 2018, and expects to amortize $8 million in 2021 and $5 million per year for the four years thereafter.
Leases	Leases The Company determines if a contract contains a lease at inception or as a result of an acquisition. 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, 2020. 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 and other equipment under non-cancelable operating leases expiring through 2036. 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.
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 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.
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, restricted stock units and performance units. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities. In August 2020, the Company completed an underwritten public offering of 63,250,000 shares of its common stock with an offering price to the public of $2.50 per share. Net proceeds after deducting underwriting discounts and offering expenses were approximately $152 million. See Note 3 for additional details regarding the Company's use of proceeds from the equity offering. Under the Agreement and Plan of Merger, Montage shareholders received 1.8656 shares of Southwestern common stock for each share of Montage common stock issued and outstanding immediately prior to the date of Merger. On November 13, 2020, the Company issued 69,740,848 shares of its common stock, or approximately $213 million in value (based on Southwestern common stock closing price as of November 13, 2020 of $3.05), as Merger consideration.
Stock-Based Compensation	Stock-Based CompensationThe 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 and 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.
Liability-Classified Awards	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, operating expense and 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
Cash-Based Compensation	Cash-Based Compensation The Company classifies certain awards that will be settled in cash as cash-based compensation. The Company recognizes the cost of these awards as general and administrative expense, operating expense and capitalized expense over the vesting period of the awards. The performance cash awards include a performance condition determined annually by the Company. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be canceled.
Treasury Stock	Treasury Stock In 2018, the Company repurchased 39,061,268 shares of its outstanding common stock per a previously announced share repurchase program at an average price of $4.63 per share for approximately $180 million. In 2019, the Company completed its share repurchase program by purchasing another 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 frozen legacy non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants could 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, 2020 and 2019, 3,632 shares and 5,115 shares, respectively, were held in the Rabbi Trust and were accounted for 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 and New Accounting Standards Not Yet Adopted in this Report	New Accounting Standards Implemented in this Report In August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Management (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements ("ASU 2018-13"), which modifies the disclosure requirements on fair value measurements. ASU 2018-13 became effective for public business entities for annual and interim periods in the fiscal years beginning after December 15, 2019. As a result of this adoption, this standard did not have a material impact on the Company's consolidated financial statements. 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 replaced 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 became 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 and recently acquired credit portfolios, which include trade receivables from commodity sales, joint interest billings due from partners and 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 counterparties. Update 2016-13 did not have a significant impact on the Company's consolidated financial statements or related control environment upon adoption on January 1, 2020. New Accounting Standards Not Yet Adopted in this Report In August 2018, the FASB issued ASU 2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans ("ASU 2018-14"). This ASU amends, adds and removes certain disclosure requirements under FASB ASC Topic 715 – Compensation – Retirement Benefits. The guidance in ASU 2018-14 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. This ASU will result in expanded disclosures within the Company's interim and annual footnote disclosures, however, the adoption of ASU 2018 is not expected to have a material impact on the Company's consolidated financial statements. In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform, as a new Accounting Standards Codification (“ASC”) Topic, ASC 848. The purpose of ASC 848 is to provide optional guidance to ease the potential effects on financial reporting of the market-wide migration away from Interbank Offered Rates, such as LIBOR, which is expected to be phased out at the end of calendar year 2021, to alternative reference rates. ASC 848 applies only to contracts, hedging relationships, debt arrangements and other transactions that reference a benchmark reference rate expected to be discontinued because of reference rate reform. ASC 848 contains optional expedients and exceptions for applying U.S. GAAP to transactions affected by this reform. The amendments in the ASU are effective for all entities as of March 12, 2020 through December 31, 2022. The Company is currently assessing the impact of adopting this new guidance.

Organization and Summary of S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020, and December 31, 2019: (in millions) December 31, 2020 December 31, 2019 Cash $ 13 $ 5 Marketable securities (1) — — Total $ 13 $ 5 (1) Consists of government stable value money market funds. Immaterial as of December 31, 2020 and 2019.
Schedule of Property, Plant and Equipment	The estimated useful lives of those assets depreciated under the straight-line method are as follows: Water facilities 5 – 10 years Gathering systems 15 – 25 years Technology infrastructure 3 – 7 years Drilling rigs and equipment 3 years Buildings and leasehold improvements 10 – 30 years Other property, plant and equipment is comprised of the following: (in millions) December 31, 2020 December 31, 2019 Water facilities $ 228 $ 217 Gathering systems 54 32 Technology infrastructure 133 154 Drilling rigs and equipment 26 32 Land, buildings and leasehold improvements 41 41 Other 41 44 Less: Accumulated depreciation and impairment (311) (300) Total $ 212 $ 220
Schedule of Earnings Per Share	The following table presents the computation of earnings per share for the years ended December 31, 2020, 2019 and 2018: For the years ended December 31, (in millions, except share/per share amounts) 2020 2019 2018 Net income (loss) $ (3,112) $ 891 $ 537 Participating securities – mandatory convertible preferred stock — — 2 Net income (loss) attributable to common stock $ (3,112) $ 891 $ 535 Number of common shares: Weighted average outstanding 573,889,502 539,345,343 574,631,756 Issued upon assumed exercise of outstanding stock options — — — Effect of issuance of non-vested restricted common stock — 361,380 698,103 Effect of issuance of non-vested restricted units — — — Effect of issuance of non-vested performance units — 676,191 1,312,949 Weighted average and potential dilutive outstanding 573,889,502 540,382,914 576,642,808 Earnings (loss) per common share: Basic $ (5.42) $ 1.65 $ 0.93 Diluted $ (5.42) $ 1.65 $ 0.93
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, 2020, 2019 and 2018, as they would have had an antidilutive effect: For the years ended December 31, 2020 2019 2018 Unexercised stock options 4,427,040 5,078,253 5,909,082 Unvested share-based payment 962,662 1,728,264 3,692,794 Restricted units 4,452,876 — — Performance units 2,818,653 271,268 642,568 Mandatory convertible preferred stock — — 2,465,708 Total 12,661,231 7,077,785 12,710,152
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, 2020, 2019 and 2018: For the years ended December 31, (in millions) 2020 2019 2018 Cash paid during the year for interest, net of amounts capitalized $ 75 $ 58 $ 135 Cash paid (received) during the year for income taxes (32) (52) 6 Increase (decrease) in noncash property additions 1,084 (1) 41 (42) (1) Includes $1,097 million in noncash additions related to the Montage Merger.

Restructuring Charges (Tables)

Restructuring Charges (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020, 2019 and 2018: For the years ended December 31, (in millions) 2020 2019 2018 (1) Reduction in workforce (not Fayetteville Shale sale-related) $ 16 $ — $ 23 Fayetteville Shale sale-related — 11 16 Total restructuring charges $ 16 $ 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, 2020, which are reflected in accounts payable on the consolidated balance sheet: (in millions) Liability at December 31, 2019 $ 2 Additions 16 Distributions (15) Liability at December 31, 2020 $ 3
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, 2020, 2019 and 2018: For the years ended December 31, (in millions) 2020 2019 2018 Severance (including payroll taxes) $ 16 $ — $ 21 Outplacement services, other — — 2 Total reduction in workforce-related restructuring charges (1) $ 16 $ — $ 23 (1) Total restructuring charges were $16 million for the Company's E&P segment for the year ended December 31, 2020. 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.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Schedule of Business Acquisitions by Acquisition, Equity Interest Issued or Issuable	The following table presents the fair value of consideration transferred to Montage stockholders as a result of the Merger: (in millions, except share, per share amounts) As of November 13, 2020 Shares of Southwestern common stock issued in respect of outstanding Montage common stock 67,311,166 Shares of Southwestern common stock issued in respect of Montage stock-based awards 2,429,682 69,740,848 NYSE closing price per share of Southwestern common shares on November 13, 2020 $ 3.05 Total consideration (fair value of Southwestern common shares issued) $ 213 Increase in Southwestern common stock ($0.01 par value per share) 1 Increase in Southwestern additional paid-in capital $ 212
Schedule of Business Acquisitions, by Acquisition	The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. Although the purchase price allocation is substantially complete as of the date of this filing, there may be further adjustments to the Company’s natural gas and oil properties. These amounts will be finalized no later than one year from the acquisition date. (in millions) As of November 13, 2020 Consideration: Fair value of Southwestern’s stock issued on November 13, 2020 $ 213 Fair value of assets acquired: Cash and cash equivalents 3 Accounts receivable 73 Other current assets 1 Derivative assets 11 Evaluated natural gas and oil properties 1,012 Unevaluated natural gas and oil properties 90 Other property, plant and equipment 28 Other long-term assets 26 Total assets acquired 1,244 Fair value of liabilities assumed: Accounts payable 145 Other current liabilities 49 Derivative liabilities 70 Revolving credit facility 200 Senior unsecured notes 522 Asset retirement obligations 28 Other long-term liabilities 17 Total liabilities assumed 1,031 Net assets acquired and liabilities assumed $ 213
Business Acquisition, Pro Forma Information	The following table summarizes the unaudited pro forma condensed financial information of Southwestern as if the Merger had occurred on January 1, 2019: For the years ended December 31, (in millions, except per share amounts) 2020 2019 Revenues $ 2,701 $ 3,673 Net income (loss) attributable to common stock $ (3,177) $ 995 Net income (loss) attributable to common stock per share – basic $ (4.71) $ 1.48 Net income (loss) attributable to common stock per share – diluted $ (4.71) $ 1.48
Schedule of Acquisition Related Costs	The following table summarizes the Merger-related expenses incurred for the year ended December 31, 2020: (in millions) For the year ended December 31, 2020 Bank, legal and consulting fees $ 18 Employee severance and related costs 17 Contract buyouts 5 Other 1 Total Montage merger-related expenses $ 41

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Disclosure of Lease Costs	The components of lease costs are shown below: For the years ended December 31, (in millions) 2020 2019 Operating lease cost $ 48 $ 45 Short-term lease cost 35 45 Variable lease cost 3 1 Total lease cost $ 86 $ 91 Supplemental cash flow information related to leases is set forth below: For the years ended December 31, (in millions) 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 47 $ 47 Right-of-use assets obtained in exchange for operating liabilities: Operating leases $ 48 $ 95
Supplemental Balance Sheet Information	Supplemental balance sheet information related to leases is as follows: (in millions) December 31, 2020 December 31, 2019 Right-of-use asset balance: Operating leases $ 163 $ 159 Lease liability balance: Current operating leases $ 42 $ 34 Long-term operating leases 117 119 Total operating leases $ 159 $ 153 Weighted average remaining lease term: (years) Operating leases 5.6 6.6 Weighted average discount rate: Operating leases 5.97 % 5.33 %
Maturity Analysis of Operating Lease Liabilities	Maturity analysis of operating lease liabilities: (in millions) December 31, 2020 2021 $ 50 2022 37 2023 26 2024 18 2025 14 Thereafter 42 Total undiscounted lease liability 187 Imputed interest (28) Total discounted lease liability $ 159

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 Gas sales $ 928 $ — $ 39 $ 967 Oil sales 150 — 4 154 NGL sales 265 — — 265 Marketing — 2,145 (1,228) 917 Other (1) 5 — — 5 Total $ 1,348 $ 2,145 $ (1,185) $ 2,308 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 (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) 2020 2019 2018 Northeast Appalachia $ 648 $ 964 $ 1,165 Southwest Appalachia 700 736 817 Fayetteville Shale — — 537 Other — 3 6 Total $ 1,348 $ 1,703 $ 2,525
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, 2020 December 31, 2019 Receivables from contracts with customers $ 350 $ 284 Other accounts receivable 18 61 Total accounts receivable $ 368 $ 345

Derivatives and Risk Manageme_2

Derivatives and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value	The tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of December 31, 2020: Financial Protection on Production Weighted Average Price per MMBtu Fair value at December 31, 2020 ($ in millions) Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Natural Gas 2021 Fixed price swaps 201 $ 2.80 $ — $ — $ — $ — $ 29 Two-way costless collars 237 — — 2.57 2.95 — 11 Three-way costless collars 313 — 2.16 2.49 2.85 — (24) Total 751 $ 16 2022 Fixed price swaps 112 $ 2.68 $ — $ — $ — $ — $ 4 Two-way costless collars 63 — — 2.52 3.03 — (1) Three-way costless collars 203 — 2.06 2.46 2.89 — (15) Total 378 $ (12) 2023 Three-way costless collars 87 $ — $ 2.06 $ 2.47 $ 2.98 $ — $ — Basis swaps 2021 219 $ — $ — $ — $ — $ (0.21) $ 57 2022 139 — — — — (0.33) 8 2023 47 — — — — (0.45) — 2024 11 — — — — (0.60) — 2025 4 — — — — (0.59) — Total 420 $ 65 Weighted Average Price per Bbl Fair value at December 31, 2020 ($ in millions) Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Oil 2021 Fixed price swaps 4,887 $ 48.59 $ — $ — $ — $ 1 Two-way costless collars 201 — — 37.73 45.68 (1) Three-way costless collars 1,543 — 37.42 47.22 52.86 — Total 6,631 $ — 2022 Fixed price swaps 1,282 $ 46.37 $ — $ — $ — $ — Three-way costless collars 873 — 40.25 50.78 56.54 1 Total 2,155 $ 1 2023 Three-way costless collars 878 $ — $ 33.52 $ 43.52 $ 53.41 $ (1) Ethane 2021 Fixed price swaps 5,889 $ 7.12 $ — $ — $ — $ (10) Two-way costless collars 584 — — 7.14 10.40 — Total 6,473 $ (10) 2022 Fixed price swaps 1,575 $ 8.69 $ — $ — $ — $ — Two-way costless collars 135 — — 7.56 9.66 — Total 1,710 $ — Propane 2021 Fixed price swaps 6,974 $ 20.43 $ — $ — $ — $ (36) 2022 Fixed price swaps 2,120 $ 20.23 $ — $ — — $ (2) Normal Butane 2021 Fixed price swaps 2,004 $ 24.97 $ — $ — $ — $ (8) 2022 Fixed price swaps 667 $ 22.77 $ — $ — $ — $ (1) Natural Gasoline 2021 Fixed price swaps 1,936 $ 37.35 $ — $ — $ — $ (13) 2022 Fixed price swaps 643 $ 37.77 $ — $ — $ — $ (2) Other Derivative Contracts Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2020 ($ in millions) Call Options – Natural Gas (Net) 2021 75 $ 3.19 $ (8) 2022 77 3.00 (17) 2023 46 2.94 (8) 2024 9 3.00 (3) Total 207 $ (36) Put Options – Natural Gas 2021 18 $ 2.00 $ (1) 2022 5 2.00 — Total 23 $ (1) Volume (MBbls) Weighted Average Strike Price per Bbl Fair value at December 31, 2020 ($ in millions) Sold Call Options – Oil 2021 226 $ 60.00 $ — Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2020 ($ in millions) Swaptions – Natural Gas 2021 0.1 $ 3.00 $ (2) Weighted Average Strike Price per MMBtu Fair value at December 31, 2020 ($ in millions) Storage (1) Volume (Bcf) Swaps Basis Differential 2021 Purchased fixed price swap 1 $ 2.04 $ — $ — Fixed price swaps 2 2.49 — — Basis swaps 1 — (0.38) — Total 4 $ — (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, 2020 ($ in millions) Purchased Fixed Price Swaps – Marketing (Natural Gas) (1) 2021 6 $ 2.44 $ 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, 2020 and 2019: Derivative Assets Balance Sheet Classification Fair Value (in millions) December 31, 2020 December 31, 2019 Derivatives not designated as hedging instruments: Purchased fixed price swaps – natural gas Derivative assets $ 1 $ — Fixed price swaps – natural gas Derivative assets 37 77 (1) Fixed price swaps – oil Derivative assets 13 4 Fixed price swaps – ethane Derivative assets — 11 Fixed price swaps – propane Derivative assets — 21 Two-way costless collars – natural gas Derivative assets 54 10 Two-way costless collars – oil Derivative assets — 5 Two-way costless collars – propane Derivative assets — 2 Three-way costless collars – natural gas Derivative assets 57 126 Three-way costless collars – oil Derivative assets 15 3 Basis swaps – natural gas Derivative assets 60 17 Call options – natural gas Derivative assets 4 1 Fixed price swaps – natural gas storage Derivative assets — 1 Fixed price swaps – natural gas Other long-term assets 7 7 Fixed price swaps – oil Other long-term assets 2 1 Fixed price swaps – propane Other long-term assets — 3 Two-way costless collars – natural gas Other long-term assets 20 4 Three-way costless collars – natural gas Other long-term assets 87 74 Three-way costless collars – oil Other long-term assets 15 7 Basis swaps – natural gas Other long-term assets 15 15 Call options – natural gas Other long-term assets — 2 Total derivative assets $ 387 $ 391 (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, 2020 December 31, 2019 Derivatives not designated as hedging instruments: Purchased fixed price swaps – natural gas Derivative liabilities $ — $ 1 Fixed price swaps – natural gas Derivative liabilities 7 1 Fixed price swaps – oil Derivative liabilities 12 6 Fixed price swaps – ethane Derivative liabilities 10 — Fixed price swaps – propane Derivative liabilities 36 — Fixed price swaps – normal butane Derivative liabilities 8 — Fixed price swaps – natural gasoline Derivative liabilities 13 — Two-way costless collars – natural gas Derivative liabilities 43 4 Two-way costless collars – oil Derivative liabilities 1 5 Three-way costless collars – natural gas Derivative liabilities 82 84 Three-way costless collars – oil Derivative liabilities 15 4 Basis swaps – natural gas Derivative liabilities 3 17 Call options – natural gas Derivative liabilities 12 3 Put options – natural gas Derivative liabilities 1 — Swaptions – natural gas Derivative liabilities 2 — Fixed price swaps – natural gas Other long-term liabilities 3 — Fixed price swaps – oil Other long-term liabilities 2 2 Fixed price swaps – propane Other long-term liabilities 2 — Fixed price swaps – normal butane Other long-term liabilities 1 — Fixed price swaps – natural gasoline Other long-term liabilities 2 — Two-way costless collars – natural gas Other long-term liabilities 21 4 Three-way costless collars – natural gas Other long-term liabilities 102 72 Three-way costless collars – oil Other long-term liabilities 15 8 Basis swaps – natural gas Other long-term liabilities 7 9 Call options – natural gas Other long-term liabilities 28 15 Call options – oil Other long-term liabilities — 1 Total derivative liabilities $ 428 $ 236
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, 2020 and 2019: 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 2020 2019 (in millions) Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ 2 $ (1) Purchased fixed price swaps – oil Gain (Loss) on Derivatives — 6 Fixed price swaps – natural gas Gain (Loss) on Derivatives (25) 46 Fixed price swaps – oil Gain (Loss) on Derivatives — (22) Fixed price swaps – ethane Gain (Loss) on Derivatives (21) 6 Fixed price swaps – propane Gain (Loss) on Derivatives (60) 13 Fixed price swaps – normal butane Gain (Loss) on Derivatives (9) — Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (15) — Two-way costless collars – natural gas Gain (Loss) on Derivatives 10 2 Two-way costless collars – oil Gain (Loss) on Derivatives (1) (10) Two-way costless collars – propane Gain (Loss) on Derivatives (1) 2 Three-way costless collars – natural gas Gain (Loss) on Derivatives (77) 37 Three-way costless collars – oil Gain (Loss) on Derivatives 3 (2) Basis swaps – natural gas Gain (Loss) on Derivatives 59 17 Call options – natural gas Gain (Loss) on Derivatives (10) 1 Call options – oil Gain (Loss) on Derivatives 1 (1) Swaptions – natural gas Gain (Loss) on Derivatives 7 — Fixed price swaps – natural gas storage Gain (Loss) on Derivatives (1) 1 Interest rate swaps Gain (Loss) on Derivatives — (1) Total gain (loss) on unsettled derivatives $ (138) $ 94 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 2020 2019 (in millions) Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ (3) $ — Purchased fixed price swaps – oil Gain (Loss) on Derivatives — (3) Fixed price swaps – natural gas Gain (Loss) on Derivatives 142 (2) 78 Fixed price swaps – oil Gain (Loss) on Derivatives 65 10 Fixed price swaps – ethane Gain (Loss) on Derivatives 6 17 Fixed price swaps – propane Gain (Loss) on Derivatives 18 29 Fixed price swaps – normal butane Gain (Loss) on Derivatives (2) — Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (1) — Two-way costless collars – natural gas Gain (Loss) on Derivatives (5) 16 Two-way costless collars – oil Gain (Loss) on Derivatives 17 6 Two-way costless collars – propane Gain (Loss) on Derivatives 2 2 Three-way costless collars – natural gas Gain (Loss) on Derivatives 38 (3) 31 Three-way costless collars – oil Gain (Loss) on Derivatives 9 — Basis swaps – natural gas Gain (Loss) on Derivatives 76 (3) Call options – natural gas Gain (Loss) on Derivatives — (2) (4) Purchased fixed price swaps – natural gas storage Gain (Loss) on Derivatives (1) — Fixed price swaps – natural gas storage Gain (Loss) on Derivatives 2 (1) Interest rate swaps Gain (Loss) on Derivatives (1) — Total gain on settled derivatives $ 362 $ 180 Total gain on derivatives $ 224 $ 274 (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 $9 million amortization of premiums paid related to certain natural gas fixed price options for the year ended December 31, 2020, which is included in gain (loss) on derivatives on the consolidated statements of operations. (3) Includes $2 million amortization of premiums paid related to certain natural gas three-way costless collars for the year ended December 31, 2020, which is included in gain (loss) on derivatives on the consolidated statements of operations. (4) Includes $1 million amortization of premiums paid related to certain natural gas call options for the year ended December 31, 2019, 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, 2020
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Components of Accumulated Other Comprehensive Income (Loss)	In 2020, 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, 2020: For the year ended December 31, 2020 (in millions) Pension and Other Postretirement Foreign Currency Total Beginning balance, December 31, 2019 $ (19) $ (14) $ (33) Other comprehensive loss before reclassifications — — — Amounts reclassified from other comprehensive income (1) (5) — (5) Net current-period other comprehensive loss (5) — (5) Ending balance, December 31, 2020 $ (24) $ (14) $ (38) (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, 2020 Pension and other postretirement: (in millions) Amortization of prior service cost and net loss (1) Other Loss, Net $ (6) Provision for income taxes (1) Net loss $ (5) Total reclassifications for the period Net loss $ (5) (1) See Note 13 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, 2020
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, 2020 and 2019 were as follows: December 31, 2020 December 31, 2019 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents $ 13 $ 13 $ 5 $ 5 2018 revolving credit facility due April 2024 (1) 700 700 34 34 Senior notes (2) 2,471 2,609 2,228 2,085 Derivative instruments, net (41) (41) 155 (3) 155 (3) (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, 2020 Fair Value Measurements Using: (in millions) Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Assets (Liabilities) at Fair Value Assets: Purchased fixed price swaps $ — $ 1 $ — $ 1 Fixed price swaps — 59 — 59 Two-way costless collars — 74 — 74 Three-way costless collars — 174 — 174 Basis swaps — 75 — 75 Call options — 4 — 4 Liabilities: Fixed price swaps — (96) — (96) Two-way costless collars — (65) — (65) Three-way costless collars — (214) — (214) Basis swaps — (10) — (10) Call options — (40) — (40) Put options — (1) — (1) Swaptions — (2) — (2) Total $ — $ (41) $ — $ (41) December 31, 2019 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 swaps (1) $ — $ 125 $ — $ 125 Two-way costless collars — 21 — 21 Three-way costless collars — 210 — 210 Basis swaps – natural gas — 32 — 32 Call options — 3 — 3 Liabilities: Purchased fixed price swaps — (1) — (1) Fixed price swaps — (9) — (9) Two-way costless collars — (13) — (13) Three-way costless collars — (168) — (168) Basis swaps — (26) — (26) Call options — (19) — (19) Total $ — $ 155 $ — $ 155

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Components of Debt	The components of debt as of December 31, 2020 and 2019 consisted of the following: December 31, 2020 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Total Long-term debt: Variable rate (2.110% at December 31, 2020) 2018 revolving credit facility, due April 2024 $ 700 $ — (1) $ — $ 700 4.10% Senior Notes due March 2022 207 — — 207 4.95% Senior Notes due January 2025 (2) 856 (4) (1) 851 7.50% Senior Notes due April 2026 618 (6) — 612 7.75% Senior Notes due October 2027 440 (5) — 435 8.375% Senior Notes due September 2028 350 (5) — 345 Total long-term debt $ 3,171 $ (20) $ (1) $ 3,150 December 31, 2019 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount 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 (1) At December 31, 2020 and 2019, unamortized issuance expense of $12 million and $11 million, respectively, associated with the 2018 revolving credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheet.
Schedule of Long Term Debt Maturities	The following is a summary of scheduled debt maturities by year as of December 31, 2020: (in millions) 2021 $ — 2022 207 2023 — 2024 (1) 700 2025 856 Thereafter 1,408 $ 3,171 (1) The Company’s current revolving credit facility matures in 2024.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Obligation under Transportation Agreements	As of December 31, 2020, 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 (1) $ 8,013 $ 860 $ 1,532 $ 1,286 $ 1,813 $ 2,522 Pending regulatory approval and/or construction (2) 531 2 30 37 88 374 Total transportation charges $ 8,544 $ 862 $ 1,562 $ 1,323 $ 1,901 $ 2,896 (1) With the close of the Montage Merger the Company acquired firm transportation commitments of approximately $1,100 million. These commitments approximate $99 million within the next year, $197 million from 1 to 3 years, $196 million from 3 to 5 years, $284 million from 5 to 8 years and $324 million beyond 8 years. (2) Based on the estimated in-service dates as of December 31, 2020.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes	The provision (benefit) for income taxes included the following components: (in millions) 2020 2019 2018 Current: Federal $ (2) $ (1) $ (5) State — (1) 6 (2) (2) 1 Deferred: Federal 371 (431) — State 38 22 — 409 (409) — Provision (benefit) for income taxes $ 407 $ (411) $ 1
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) 2020 2019 2018 Expected provision (benefit) at federal statutory rate $ (568) $ 101 $ 113 Increase (decrease) resulting from: State income taxes, net of federal income tax effect (55) 11 13 Change in valuation allowance 1,034 (522) (121) Removal of sequestration fee on AMT receivables — — (5) Other (4) (1) 1 Provision (benefit) for income taxes $ 407 $ (411) $ 1
Components of Deferred Tax Balances	The components of the Company’s deferred tax balances as of December 31, 2020 and 2019 were as follows: (in millions) 2020 2019 Deferred tax liabilities: Differences between book and tax basis of property $ — $ 312 Derivative activity — 34 Right of use lease asset 38 37 Other 2 2 40 385 Deferred tax assets: Differences between book and tax basis of property 295 — Accrued compensation 38 33 Accrued pension costs 11 9 Asset retirement obligations 20 13 Net operating loss carryforward 1,117 769 Future lease payments 38 37 Derivative activity 9 — Capital loss carryover 27 — Other 24 18 1,579 879 Valuation allowance (1,539) (87) 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) 2020 2019 Valuation allowance at beginning of year $ 87 $ 609 Release of valuation allowance — (522) Establishment of valuation allowance on opening deferred balance 408 — Opening balance adjustments 6 — Changes based on 2020 activity 626 — Purchase accounting 412 — Valuation allowance at end of year $ 1,539 $ 87
Summary of Unrecognized Tax Benefits	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: (in millions) 2020 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, 2020
Asset Retirement Obligation [Abstract]
Schedule of Asset Retirement Obligations	The following table summarizes the Company’s 2020 and 2019 activity related to asset retirement obligations: (in millions) 2020 2019 Asset retirement obligation at January 1 $ 57 $ 61 Accretion of discount 4 3 Obligations incurred 1 2 Obligations assumed from Montage 28 — Obligations settled/removed (6) (9) Revisions of estimates 1 — Asset retirement obligation at December 31 $ 85 $ 57 Current liability $ 4 $ 6 Long-term liability 81 51 Asset retirement obligation at December 31 $ 85 $ 57

Retirement and Employee Benef_2

Retirement and Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 and 2019: Pension Benefits Other Postretirement Benefits (in millions) 2020 2019 2020 2019 Change in benefit obligations: Benefit obligation at January 1 $ 126 $ 125 $ 13 $ 13 Service cost 7 7 2 1 Interest cost 5 5 — — Participant contributions — — — — Actuarial loss 16 15 1 1 Benefits paid (13) (2) (1) (2) Plan amendments — — (2) — Curtailments (2) — — — Settlements — (24) — — Benefit obligation at December 31 $ 139 $ 126 $ 13 $ 13 Pension Benefits Other Postretirement Benefits (in millions) 2020 2019 2020 2019 Change in plan assets: Fair value of plan assets at January 1 $ 96 $ 91 $ — $ — Actual return on plan assets 11 16 — — Employer contributions 12 12 1 2 Participant contributions — — — — Benefits paid (13) (2) (1) (2) Settlements — (21) — — Fair value of plan assets at December 31 $ 106 $ 96 $ — $ — Funded status of plans at December 31 $ (33) $ (30) $ (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, 2020 and 2019 are as follows: (in millions) 2020 2019 Projected benefit obligation $ 139 $ 126 Accumulated benefit obligation 139 124 Fair value of plan assets 106 96
Pension and Other Postretirement Benefit Costs	Pension and other postretirement benefit costs include the following components for 2020, 2019 and 2018: Pension Benefits Other Postretirement Benefits (in millions) 2020 2019 2018 2020 2019 2018 Service cost $ 7 $ 7 $ 10 $ 2 $ 1 $ 2 Interest cost 5 5 5 — — 1 Expected return on plan assets (6) (6) (7) — — — Amortization of transition obligation — — — — — — Amortization of prior service cost — — — — — — Amortization of net loss 1 2 2 — — — Net periodic benefit cost 7 8 10 2 1 3 Curtailment gain — — — — — (4) Settlement loss — 6 — — — — Total benefit cost (benefit) $ 7 $ 14 $ 10 $ 2 $ 1 $ (1)
Amounts Recognized in Other Comprehensive Income	Amounts recognized in other comprehensive income for the years ended December 31, 2020 and 2019 were as follows: Pension Benefits Other Postretirement Benefits (in millions) 2020 2019 2020 2019 Net actuarial (loss) gain arising during the year $ (12) $ (5) $ 2 $ (1) Amortization of prior service cost — — — — Amortization of net loss 1 2 — — Settlements — 8 — — Curtailments 3 — — — Tax effect 3 (1) (1) — $ (5) $ 4 $ 1 $ (1)
Schedule of Assumptions Used	The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2020 and 2019 are as follows: Pension Benefits Other Postretirement Benefits 2020 2019 2020 2019 Discount rate 3.10 % 3.70 % 2.80 % 3.50 % 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 2020, 2019 and 2018 are as follows: Pension Benefits Other Postretirement Benefits 2020 2019 2018 2020 2019 2018 Discount rate 3.70 % 3.70 % 4.35 % 3.50 % 4.35 % 4.35 % Expected return on plan assets 6.50 % 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 2020 and 2019: 2020 2019 Health care cost trend assumed for next year 6.5 % 7.0 % Rate to which the cost trend is assumed to decline 5.0 % 5.0 % Year that the rate reaches the ultimate trend rate 2037 2037
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 $ (2) Effect on postretirement benefit obligations $ 2 $ (2)
Schedule of Expected Benefit Payments	The following benefit payments, which reflect projected future interest costs, are expected to be paid: Pension Benefits Other Postretirement Benefits (in millions) 2021 $ 5 2021 $ 1 2022 5 2022 1 2023 5 2023 1 2024 6 2024 1 2025 5 2025 1 Years 2026-2030 26 Years 2026-2030 4
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) 30 % 49 % Non-U.S. equity (2) 30 % 17 % Total equity securities 60 % 66 % Fixed income (3) 35 % 32 % Cash (4) 5 % 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, 2020 is as follows: (in millions) Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs Significant Unobservable Inputs Measured within fair value hierarchy Equity securities: U.S. large cap value equity (1) $ 10 $ 10 $ — $ — U.S. large cap core equity (2) 24 24 — — U.S. small cap equity (3) 13 13 — — Non-U.S. equity (4) 18 18 — — Fixed income (5) 34 34 — — Cash and cash equivalents 2 2 — — Total measured within fair value hierarchy $ 101 $ 101 $ — $ — Measured at net asset value (6) Equity securities: U.S. large cap growth equity (7) 3 U.S. small cap equity (3) 2 Total measured at net asset value $ 5 Total plan assets at fair value $ 106 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, 2019 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 (8) $ 3 $ 3 $ — $ — U.S. large cap value equity (1) 6 6 — — U.S. small cap equity (3) 2 2 — — Non-U.S. equity (4) 32 32 — — Fixed income (5) 22 22 — — Cash and cash equivalents 2 2 — — Total measured within fair value hierarchy $ 67 $ 67 $ — $ — Measured at net asset value (6) Equity securities: U.S. large cap growth equity (7) 3 U.S. large cap core equity (2) 18 Fixed income (5) 8 Total measured at net asset value $ 29 Total plan assets at fair value $ 96 (1) 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. (2) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees. (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) 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. (6) Plan assets for which fair value was measured using net asset value as a practical expedient. (7) An institutional fund that seeks to invest in companies with sustainable competitive advantages, as identified through proprietary research. (8) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.

Long-Term Incentive Compensat_2

Long-Term Incentive Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Summary of Equity-Classified Stock Option Activity	The following tables summarize stock option activity for the years 2020, 2019 and 2018, and provide information for options outstanding at December 31 of each year: 2020 2019 2018 Number 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 4,635 $ 15.26 5,178 $ 17.06 6,020 $ 19.43 Granted — $ — — $ — — $ — Exercised — $ — — $ — — $ — Forfeited or expired (785) $ 24.46 (543) $ 32.38 (842) $ 33.99 Options outstanding at December 31 3,850 $ 13.39 4,635 $ 15.26 5,178 $ 17.06
Summary of Stock Options Outstanding and Options Exercisable	Options Outstanding Options Exercisable Range of Exercise Prices Options Outstanding at December 31, 2020 Weighted Average Exercise Price Weighted Average Remaining Contractual Life Options Exercisable at December 31, 2020 Weighted Average Exercise Price Weighted Average Remaining Contractual Life (in thousands) (years) (in thousands) (years) $7.74-$29.42 3,126 $ 8.95 2.3 3,126 $ 8.95 2.3 $30.59-$35.64 634 $ 30.59 0.9 634 $ 30.59 0.9 $46.55-$46.55 90 $ 46.55 0.3 90 $ 46.55 0.3 3,850 $ 13.39 2.0 3,850 $ 13.39 2.0
Summary of Equity-Classified Restricted Stock Activity	The following table summarizes the restricted stock activity for the years 2020, 2019 and 2018, and provides information for restricted stock outstanding at December 31 of each year: 2020 2019 2018 Number of 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 1,480 $ 7.00 2,717 $ 7.91 6,254 $ 8.85 Granted 584 $ 2.86 493 $ 3.06 350 $ 4.72 Vested (1,098) $ 5.26 (1,516) $ 7.16 (2,058) $ 9.24 Forfeited (269) (1) $ 7.79 (214) (2) $ 8.38 (1,829) (3) $ 9.01 Unvested shares at December 31 697 $ 5.97 1,480 $ 7.00 2,717 $ 7.91 (1) Includes 171,813 shares forfeited as a result of the reduction in workforce for the year end December 31, 2020. (2) Includes 65,196 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2019. (3) Includes 1,287,636 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2018. The following table summarizes equity-classified restricted stock unit activity to be paid out in Company stock for the year ended December 31, 2020. Number Weighted Average (in thousands) Unvested Units at January 1, 2020 — $ — Granted 186 $ 3.05 Vested (42) $ 3.05 Forfeited (10) $ 3.05 Unvested Units at December 31, 2020 134 $ 3.05
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, 2020, 2019 and 2018, and provides information for unvested units as of December 31, 2020, 2019 and 2018: 2020 2019 2018 Number of Units (1) Weighted Number of Units (1) Weighted Number of Units (1) Weighted (in thousands) (in thousands) (in thousands) Unvested units at January 1 178 $ 10.47 598 $ 10.01 1,084 $ 10.12 Granted — $ — — $ — — $ — Vested (178) $ 10.47 (378) $ 9.59 (290) $ 10.47 Forfeited — $ — (42) (2) $ 10.47 (196) (3) $ 9.94 Unvested shares at December 31 — $ — 178 $ 10.47 598 $ 10.01 (1) These amounts reflect the number of performance units granted in thousands. The actual payout of shares may range from a minimum of zero shares to a maximum of two shares per unit contingent upon TSR. The performance units have a three-year vesting term and the actual disbursement of shares, if any, is determined during the first quarter following the end of the three-year vesting period. (2) Includes 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, 2020 and 2019 and provides information for unvested units as of December 31, 2020 and 2019: 2020 2019 2018 Number Weighted Average Fair Value Number Weighted Average Fair Value Number Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested units at January 1 12,992 $ 2.42 8,202 $ 3.41 — $ — Granted 6,172 $ 1.41 8,659 $ 4.34 12,216 $ 3.69 Vested (3,960) $ 1.43 (2,624) $ 4.09 (232) $ 5.14 Forfeited (3,591) (1) $ 2.67 (1,245) (2) $ 3.48 (3,782) (3) $ 4.86 Unvested units at December 31 11,613 $ 2.67 12,992 $ 2.42 8,202 $ 3.41 (1) Includes 2,010,196 units related to the reduction in workforce for the year ended December 31, 2020. (2) Includes 400,056 units related to the reduction in workforce for the year ended December 31, 2019. (3) 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 or stock for the years ended December 31, 2020, 2019 and 2018 and provides information for unvested units as of December 31, 2020, 2019 and 2018: 2020 2019 2018 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) (in thousands) Unvested units at January 1 5,142 $ 2.42 2,803 $ 3.41 — $ — Granted 6,172 $ 1.41 2,757 $ 4.34 3,200 $ 3.70 Vested — $ — (43) $ 2.42 — $ — Forfeited (2,615) (1) $ 3.05 (375) (2) $ 3.12 (397) (3) $ 4.55 Unvested units at December 31 8,699 $ 2.57 5,142 $ 2.42 2,803 $ 3.41 (1) Includes 518,450 units related to the reduction in workforce for the year ended December 31, 2020. (2) Includes 375,086 units related to the reduction in workforce for the year ended December 31, 2019. (3) Includes 295,160 units related to the reduction in workforce for the year ended December 31, 2018.
Share-based Compensation, Liability-based Restricted Cash Units Nonvested Activity	Number Weighted Average (in thousands) Unvested units at January 1, 2020 — $ — Granted 20,044 $ 1.00 Vested (100) $ 1.00 Forfeited (1,591) (1) $ 1.00 Unvested Units at December 31, 2020 18,353 $ 1.00
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, 2020, 2019 and 2018: (in millions) 2020 2019 2018 Stock options – general and administrative expense $ — $ 1 $ 2 Stock options – general and administrative expense capitalized $ — $ — $ —
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, 2020, 2019 and 2018: (in millions) 2020 2019 2018 Restricted stock grants – general and administrative expense $ 3 $ 6 $ 9 Restricted stock grants – general and administrative expense capitalized $ 1 $ 4 $ 5
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Equity-Classified Stock-Based Compensation Costs	(in millions) 2020 2019 2018 Performance units – general and administrative expense $ — $ 1 $ 3 Performance units – general and administrative expense capitalized $ — $ — $ 1
Liability-Classified RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Liability-Classified Stock-Based Compensation Costs	(in millions) 2020 2019 2018 Restricted stock units – general and administrative expense $ 5 $ 7 $ 4 Restricted stock units – general and administrative expense capitalized $ 2 $ 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) 2020 2019 2018 Liability-classified performance units – general and administrative expense $ 7 $ 2 $ 2 Liability-classified performance units – general and administrative expense capitalized $ 2 $ 1 $ —

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 Revenues from external customers $ 1,391 $ 917 $ — $ 2,308 Intersegment revenues (43) 1,228 — 1,185 Depreciation, depletion and amortization expense 348 9 — 357 Impairments 2,830 — — 2,830 Operating loss (2,864) (1) (7) — (2,871) Interest expense (2) 94 — — 94 Gain on derivatives 224 — — 224 Gain on early extinguishment of debt — — 35 35 Other income, net — — 1 1 Provision for income taxes (2) 407 — — 407 Assets 4,654 (3) 381 125 5,160 Capital investments (4) 899 — — 899 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 (5) (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 6,717 Capital investments (4) 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) 2 (2) — — Provision for income taxes (2) 1 — — 1 Assets 4,872 (3) 539 386 5,797 Capital investments (4) 1,231 9 8 1,248 (1) Operating income for the E&P segment includes $16 million of restructuring charges and $41 million of acquisition-related charges for the year ended December 31, 2020. (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) Capital investments include a decrease of $3 million for 2020, an increase of $34 million for 2019 and a decrease of $53 million for 2018 related to the change in accrued expenditures between years. (5) Operating income for the E&P segment includes $11 million of restructuring charges for the year ended December 31, 2019. (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. The following table presents the breakout of other assets, which represent corporate assets not allocated to segments and assets for non-reportable segments for the years ended December 31, 2020, 2019 and 2018: For the years ended December 31, (in millions) 2020 2019 2018 Cash and cash equivalents $ 13 $ 5 $ 205 Accounts receivable 1 — 4 Income taxes receivable — 30 89 Current hedging asset — — 1 Prepayments 6 8 8 Property, plant and equipment 16 27 60 Unamortized debt expense 11 11 11 Right-of-use lease assets 72 80 — Non-qualified retirement plan 6 7 8 $ 125 $ 168 $ 386

Supplemental Quarterly Result_2

Supplemental Quarterly Results (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information	The following is a summary of the quarterly results of operations for the years ended December 31, 2020 and 2019: (in millions, except share amounts) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 2020 Operating revenues $ 592 $ 410 $ 527 $ 779 Operating loss (1,490) (756) (381) (244) Net loss (1,547) (880) (593) (92) Loss per share – Basic (2.86) (1.63) (1.04) (0.14) Loss per share – Diluted (2.86) (1.63) (1.04) (0.14) 2019 Operating revenues $ 990 $ 667 $ 636 $ 745 Operating income (loss) 213 22 (29) 64 Net income 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

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
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, 2020 and 2019: (in millions) 2020 2019 Proved properties $ 25,789 $ 23,744 Unproved properties 1,472 1,506 Total capitalized costs 27,261 25,250 Less: Accumulated depreciation, depletion and amortization (23,362) (20,203) Net capitalized costs $ 3,899 $ 5,047
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, 2020: (in millions) 2020 2019 2018 Prior Total Property acquisition costs $ 116 $ 44 $ 34 $ 1,022 $ 1,216 Exploration and development costs 17 17 14 20 68 Capitalized interest 62 47 33 46 188 $ 195 $ 108 $ 81 $ 1,088 $ 1,472
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) 2020 2019 2018 Unproved property acquisition costs $ 124 (1) $ 162 $ 164 Exploration costs — 2 5 Development costs 784 936 1,014 Capitalized costs incurred $ 908 $ 1,100 $ 1,183 Full cost pool amortization per Mcfe $ 0.38 $ 0.56 $ 0.51 (1) Excludes $90 million of unevaluated property acquisition costs associated with the non-cash Montage Merger.
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) 2020 2019 2018 Sales $ 1,348 $ 1,703 $ 2,525 Production (lifting) costs (866) (781) (974) Depreciation, depletion and amortization (348) (462) (514) Impairment of natural gas and oil properties (2,825) — — (2,691) 460 1,037 Provision for income taxes (1) — 110 — Results of operations (2) $ (2,691) $ 350 $ 1,037 (1) Prior to the recognition of a valuation allowance, in 2020 and 2018 the Company recognized an income tax provision (benefit) of ($624) million and $254 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 2020, 2019 and 2018, all of which were located in the United States: Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) 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 (1) (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 (2) 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 Revisions of previous estimates due to price (2,143) (32,507) (338,639) (4,370) Revisions of previous estimates other than price 763 3,816 106,444 1,424 Extensions, discoveries and other additions 714 135 4,371 741 Production (694) (5,141) (25,927) (880) Acquisition of reserves in place (3) 1,911 18,796 55,141 2,354 Disposition of reserves in place — — — — December 31, 2020 9,181 58,024 410,151 11,990 (1) The 2018 disposition is primarily associated with the Fayetteville Shale sale. (2) For the year ended December 31, 2019, 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. (3) The 2020 acquisition is primarily associated with the Montage Merger. Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) Proved developed reserves as of: December 31, 2018 4,395 18,037 175,480 5,557 December 31, 2019 4,906 26,124 226,271 6,421 December 31, 2020 6,342 33,563 276,548 8,203 Proved undeveloped reserves as of: December 31, 2018 3,649 50,970 401,583 6,364 December 31, 2019 3,724 46,801 382,490 6,300 December 31, 2020 2,839 24,461 133,603 3,787 The following table summarizes the changes in reserves for 2018, 2019 and 2020: Appalachia Fayetteville (in Bcfe) Northeast Southwest Shale (1) Other (2) Total 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 Net revisions Price revisions (389) (3,981) — — (4,370) Performance and production revisions 46 1,378 — — 1,424 Total net revisions (343) (2,603) — — (2,946) Extensions, discoveries and other additions Proved developed 198 69 — — 267 Proved undeveloped 474 — — — 474 Total reserve additions 672 69 — — 741 Production (473) (407) — — (880) Acquisition of reserves in place 223 2,131 — — 2,354 Disposition of reserves in place — — — — — December 31, 2020 4,916 7,073 — 1 11,990 (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 for the year ended December 31, 2019 include 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, 2020, 2019 and 2018 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) 2020 2019 2018 Future cash inflows $ 17,997 $ 27,003 $ 34,523 Future production costs (11,969) (14,981) (15,347) Future development costs (1) (1,924) (3,246) (4,095) Future income tax expense — (476) (2,079) Future net cash flows 4,104 8,300 13,002 10% annual discount for estimated timing of cash flows (2,257) (4,600) (7,003) Standardized measure of discounted future net cash flows $ 1,847 $ 3,700 $ 5,999 (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) 2020 2019 2018 Natural gas (per MMBtu) $ 1.98 $ 2.58 $ 3.10 Oil (per Bbl) 39.57 55.69 65.56 NGLs (per Bbl) 10.27 11.58 17.64
Schedule of Analysis of Changes in Standardized Measure	Following is an analysis of changes in the standardized measure during 2020, 2019 and 2018: (in millions) 2020 2019 2018 Standardized measure, beginning of year $ 3,700 $ 5,999 $ 5,562 Sales and transfers of natural gas and oil produced, net of production costs (478) (923) (1,564) Net changes in prices and production costs (2,720) (3,510) 2,162 Extensions, discoveries, and other additions, net of future production and development costs 81 234 335 Acquisition of reserves in place 443 — — Sales of reserves in place — (2) (2,022) Revisions of previous quantity estimates (987) 152 361 Net change in income taxes 35 491 (304) Changes in estimated future development costs 1,241 621 (166) Previously estimated development costs incurred during the year 624 704 536 Changes in production rates (timing) and other (466) (718) 521 Accretion of discount 374 652 578 Standardized measure, end of year $ 1,847 $ 3,700 $ 5,999

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies (Narrative) (Details)	Nov. 13, 2020USD ($)$ / sharesshares	Aug. 31, 2020USD ($)$ / sharesshares	Jan. 31, 2018USD ($)shares	Jan. 31, 2015shares	Sep. 30, 2018USD ($)	Dec. 31, 2020USD ($)derivative_positionsubsidiarysegment$ / bbl$ / MMBTUshares	Dec. 31, 2019USD ($)derivative_positionsubsidiary$ / shares$ / bbl$ / MMBTUshares	Dec. 31, 2018USD ($)derivative_position$ / shares$ / bbl$ / MMBTUshares	Sep. 30, 2020USD ($)	Jun. 30, 2020USD ($)	Mar. 31, 2020USD ($)	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of segments | segment						2
Outstanding checks included in accounts payable						$ 16,000,000	$ 15,000,000
Natural gas, oil and NGL reserves discount						10.00%
Net unevaluated costs excluded from amortization, cumulative						$ 1,472,000,000	$ 1,506,000,000
Net book value adjusted for market differentials						$ 335,000,000			$ 361,000,000	$ 650,000,000	$ 1,479,000,000
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						$ 2,830,000,000	$ 16,000,000	$ 171,000,000
Preferred stock dividend			$ 27,000,000			$ 0	0	27,000,000
Treasury stock acquired							$ 21,000,000	$ 180,000,000
Treasury stock (in shares) | shares							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						3,632	5,115
Discontinued operations, held-for-sale
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments					$ 161,000,000			$ 160,000,000
Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued (in shares) | shares						63,250,000
Marketing-Related Intangible Assets
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Intangible assets, current						$ 48,000,000	$ 56,000,000
Amortization of intangible asset						9,000,000	$ 9,000,000	$ 9,000,000
Expected amortization in year one						8,000,000
Expected amortization in year two						5,000,000
Expected amortization in year three						5,000,000
Expected amortization in year four						5,000,000
Expected amortization in year five						$ 5,000,000
Natural Gas
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Average sales price ($ per unit) | $ / MMBTU						1.98	2.58	3.10
Oil
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Average sales price ($ per unit) | $ / bbl						39.57	55.69	65.56
NGL
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Average sales price ($ per unit) | $ / bbl						10.27	11.58	17.64
Depositary Shares
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued (in shares) | shares				34,500,000
Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued upon conversion (in shares) | shares			74,998,614
Montage Resources Corporation
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of Southwestern Energy common stock for each share of Montage Resources Corporation common stock converted (in shares) | shares	1.8656	1.8656
Percentage of interest acquired	90.00%
Net unevaluated costs excluded from amortization, cumulative						$ 88,000,000
Impairments						0
Unamortized cost of properties acquired						1,087,000,000
Offering price (in dollars per share) | $ / shares	$ 3.05	$ 2.50
Shares of Southwestern common stock issued in respect of outstanding Montage common stock and stock-based awards | shares	69,740,848
Total consideration (fair value of Southwestern common shares issued)	$ 213,000,000
Montage Resources Corporation | Pro Forma
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments						$ 539,000,000
Montage Resources Corporation | Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Offering price (in dollars per share) | $ / shares	$ 3.05
Shares of Southwestern common stock issued in respect of outstanding Montage common stock and stock-based awards | shares	69,740,848
Total consideration (fair value of Southwestern common shares issued)	$ 213,000,000
Montage Resources Corporation | Public Stock Offering
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Underwritten public offering of common stock (in shares) | shares		63,250,000
Net proceeds from public offering		$ 152,000,000
WPX Property Acquisition
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Percentage of interest acquired												86.00%
Non-full cost pool assets | Minimum
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Long lived assets, useful life						3 years
Non-full cost pool assets | Maximum
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Long lived assets, useful life						30 years
Other non-core assets
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments					$ 1,000,000	$ 5,000,000	$ 16,000,000	$ 11,000,000
Revenue Benchmark | Customer concentration risk
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of subsidiaries of major customer with which business is conducted | subsidiary						1	0
Concentration percentage						10.00%

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, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash	$ 13	$ 5
Marketable securities	0	0
Total	$ 13	$ 5

Organization and Summary of S_6

Organization and Summary of Significant Accounting Policies (Summary of Other Property and Equipment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Less: Accumulated depreciation and impairment	$ (311)	$ (300)
Total	212	220
Water facilities
Property, Plant and Equipment [Line Items]
Other property and equipment gross	$ 228	217
Water facilities | Minimum
Property, Plant and Equipment [Line Items]
Long lived assets, useful life	5 years
Water facilities | Maximum
Property, Plant and Equipment [Line Items]
Long lived assets, useful life	10 years
Gathering systems
Property, Plant and Equipment [Line Items]
Other property and equipment gross	$ 54	32
Gathering systems | Minimum
Property, Plant and Equipment [Line Items]
Long lived assets, useful life	15 years
Gathering systems | Maximum
Property, Plant and Equipment [Line Items]
Long lived assets, useful life	25 years
Technology infrastructure
Property, Plant and Equipment [Line Items]
Other property and equipment gross	$ 133	154
Technology infrastructure | Minimum
Property, Plant and Equipment [Line Items]
Long lived assets, useful life	3 years
Technology infrastructure | Maximum
Property, Plant and Equipment [Line Items]
Long lived assets, useful life	7 years
Drilling rigs and equipment
Property, Plant and Equipment [Line Items]
Long lived assets, useful life	3 years
Other property and equipment gross	$ 26	32
Land, buildings and leasehold improvements
Property, Plant and Equipment [Line Items]
Other property and equipment gross	$ 41	41
Land, buildings and leasehold improvements | Minimum
Property, Plant and Equipment [Line Items]
Long lived assets, useful life	10 years
Land, buildings and leasehold improvements | Maximum
Property, Plant and Equipment [Line Items]
Long lived assets, useful life	30 years
Other
Property, Plant and Equipment [Line Items]
Other property and equipment gross	$ 41	$ 44

Organization and Summary of S_7

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, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share [Line Items]
Net income (loss)									$ (3,112)	$ 891	$ 537	[1]
Participating securities – mandatory convertible preferred stock									0	0	2
Net Income (Loss) Attributable to Common Stock	$ (92)	$ (593)	$ (880)	$ (1,547)	$ 110	$ 49	$ 138	$ 594	$ (3,112)	$ 891	$ 535
Number of common shares:
Weighted average outstanding (in shares)									573,889,502	539,345,343	574,631,756
Weighted average and potential dilutive outstanding (in shares)									573,889,502	540,382,914	576,642,808
Basic (in dollars per share)	$ (0.14)	$ (1.04)	$ (1.63)	$ (2.86)	$ 0.20	$ 0.09	$ 0.26	$ 1.10	$ (5.42)	$ 1.65	$ 0.93
Diluted (in dollars per share)	$ (0.14)	$ (1.04)	$ (1.63)	$ (2.86)	$ 0.20	$ 0.09	$ 0.26	$ 1.10	$ (5.42)	$ 1.65	$ 0.93
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)									0	361,380	698,103
Restricted units
Number of common shares:
Effect of share-based compensation (in shares)									0	0	0
Performance units
Number of common shares:
Effect of share-based compensation (in shares)									0	676,191	1,312,949
[1]	In 2018, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Organization and Summary of S_8

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	12,661,231	7,077,785	12,710,152
Unexercised stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	4,427,040	5,078,253	5,909,082
Unvested share-based payment
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	962,662	1,728,264	3,692,794
Restricted units
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	4,452,876	0	0
Performance units
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	2,818,653	271,268	642,568
Mandatory convertible preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	0	0	2,465,708

Organization and Summary of S_9

Organization and Summary of Significant Accounting Policies (Schedule of Supplemental Disclosures of Cash Flow Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Cash paid during the year for interest, net of amounts capitalized	$ 75	$ 58	$ 135
Cash paid (received) during the year for income taxes	(32)	(52)	6
Increase (decrease) in noncash property additions	1,084	$ 41	$ (42)
Montage Resources Corporation
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Increase (decrease) in noncash property additions	$ 1,097

Restructuring Charges (Summary

Restructuring Charges (Summary of Restructuring Charges) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$ 16	$ 11	$ 39
Non-cash curtailment gain			4
Fayetteville Shale
Restructuring Cost and Reserve [Line Items]
Restructuring charges	0	11	16
Non-cash curtailment gain			4
Workforce Reduction
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$ 16	$ 0	$ 23

Restructuring Charges (Summar_2

Restructuring Charges (Summary of Liabilities Associated with Restructuring Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Restructuring Reserve [Roll Forward]
Liability, beginning balance	$ 2
Additions	16	$ 11	$ 39
Distributions	(15)
Liability, ending balance	$ 3	$ 2

Restructuring Charges (Narrativ

Restructuring Charges (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jul. 31, 2019
Restructuring Cost and Reserve [Line Items]
Restructuring liability	$ 3	$ 2
Operating lease term				10 years
Restructuring charges	16	11	$ 39
Fayetteville Shale
Restructuring Cost and Reserve [Line Items]
Office consolidation		6	4
Operating lease term				10 years
Restructuring charges	$ 0	11	$ 16
Fayetteville Shale | Office Consolidation and Reorganization
Restructuring Cost and Reserve [Line Items]
Office consolidation		2
Fayetteville Shale | Lease Termination
Restructuring Cost and Reserve [Line Items]
Office consolidation		3
Fayetteville Shale | Other Office Consolidation Expenses
Restructuring Cost and Reserve [Line Items]
Restructuring charges		$ 1

Restructuring Charges (Summar_3

Restructuring Charges (Summary of Restructuring Charges Related to Workforce Reduction Plans) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	$ 16	$ 11	$ 39
Workforce Reduction
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)	16	0	21
Outplacement services, other	0	0	2
Total restructuring charges	16	$ 0	23
Workforce Reduction | Exploration and Production
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	$ 16		21
Workforce Reduction | Marketing
Restructuring Cost and Reserve [Line Items]
Total restructuring charges			$ 2

Restructuring Charges (Summar_4

Restructuring Charges (Summary of Restructuring Charges Related to Fayetteville Shale) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Restructuring Cost and Reserve [Line Items]
Total restructuring charges	$ 16	$ 11	$ 39
Non-cash curtailment gain			4
Fayetteville Shale
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)		5	12
Office consolidation		6	4
Total restructuring charges	$ 0	11	16
Non-cash curtailment gain			4
Fayetteville Shale | Exploration and Production
Restructuring Cost and Reserve [Line Items]
Total restructuring charges		$ 11	$ 16

Acquisitions and Divestitures_2

Acquisitions and Divestitures (Narrative) (Details) - USD ($)	Nov. 13, 2020	Aug. 31, 2020	Jul. 31, 2019	Dec. 31, 2018	Dec. 31, 2020	Sep. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of property and equipment							$ 12,000,000	$ 54,000,000	$ 1,643,000,000
Gain on sale of assets, net							0	(2,000,000)	17,000,000
Impairments							2,830,000,000	16,000,000	171,000,000
Montage Resources Corporation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of Southwestern Energy common stock for each share of Montage Resources Corporation common stock converted (in shares)	1.8656	1.8656
Offering price (in dollars per share)	$ 3.05	$ 2.50
Percentage of voting interest	90.00%
Proved property acquired	$ 1,000,000,000
Unproved property acquired	90,000,000
Other property, plant and equipment	$ 28,000,000
Revenues associated with the operations acquired through the Merger					$ 63,000,000
Net income attributable to common stockholders associated with the operations acquired through the Merger					$ 28,000,000
Impairments							0
Montage Resources Corporation | Public Stock Offering
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Underwritten public offering of common stock (in shares)		63,250,000
Net proceeds from public offering		$ 152,000,000
Montage Resources Corporation | Montage Resources Corporation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of voting interest	10.00%
Other non-core assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of property and equipment								38,000,000
Impairments						$ 1,000,000	$ 5,000,000	$ 16,000,000	11,000,000
Land
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of property and equipment			$ 16,000,000
Gain on sale of assets, net			$ 2,000,000
Discontinued operations, held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments						161,000,000			$ 160,000,000
Senior Notes | Eight Point Three Seven Five Percent Senior Notes Due September 2028
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Senior notes		350,000,000
Stated interest rate					8.375%		8.375%
Senior Notes | Montage Resources Corporation | Eight Point Eight Seven Five Percent Senior Notes Due 2023
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Senior notes		$ 510,000,000
Stated interest rate		8.875%
Senior Notes | Montage Resources Corporation | Eight Point Three Seven Five Percent Senior Notes Due September 2028
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Senior notes		$ 350,000,000
Stated interest rate		8.375%
Marketing | Discontinued operations, held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments						145,000,000
Exploration and Production | Discontinued operations, held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments						$ 15,000,000
Fayetteville Shale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment				$ 1,650,000,000
Adjustment due to differences from economic effective date to close date				215,000,000
Gain on the sale of non-full cost pool assets				17,000,000
Reduction of full cost pool assets				$ 887,000,000

Acquisitions and Divestitures -

Acquisitions and Divestitures - (Schedule of consideration Paid to Stockholders of Montage) (Details) - USD ($) $ / shares in Units, $ in Millions	Nov. 13, 2020	Dec. 31, 2020	Aug. 31, 2020	Dec. 31, 2019
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01		$ 0.01
Montage merger exchange		$ 213
Additional Paid-In Capital
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Montage merger exchange		212
Common Stock
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Montage merger exchange		$ 1
Montage Resources Corporation
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares of Southwestern common stock issued in respect of outstanding Montage common stock	67,311,166
Shares of Southwestern common stock issued in respect of Montage stock-based awards	2,429,682
Shares of Southwestern common stock issued during Merger	69,740,848
NYSE closing price per share of Southwestern common shares on November 13, 2020 (in dollars per share)	$ 3.05		$ 2.50
Total consideration (fair value of Southwestern common shares issued)	$ 213
Montage Resources Corporation | Additional Paid-In Capital
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Montage merger exchange	$ 212
Montage Resources Corporation | Common Stock
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares of Southwestern common stock issued during Merger	69,740,848
NYSE closing price per share of Southwestern common shares on November 13, 2020 (in dollars per share)	$ 3.05
Total consideration (fair value of Southwestern common shares issued)	$ 213
Montage merger exchange	$ 1

Acquisitions and Divestitures_3

Acquisitions and Divestitures - (Schedule of the Allocation of Purchase Price) (Details) - Montage Resources Corporation $ in Millions	Nov. 13, 2020USD ($)
Consideration:
Fair value of Southwestern’s stock issued on November 13, 2020	$ 213
Cash and cash equivalents	3
Accounts receivable	73
Other current assets	1
Derivative assets	11
Evaluated natural gas and oil properties	1,012
Unevaluated natural gas and oil properties	90
Other property, plant and equipment	28
Other long-term assets	26
Total assets acquired	1,244
Accounts payable	145
Other current liabilities	49
Derivative liabilities	70
Revolving credit facility	200
Senior unsecured notes	522
Asset retirement obligations	28
Other long-term liabilities	17
Total liabilities assumed	1,031
Net assets acquired and liabilities assumed	$ 213

Acquisitions and Divestitures_4

Acquisitions and Divestitures - (Schedule of Pro Forma) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Business Combinations [Abstract]
Revenues	$ 2,701	$ 3,673
Net income (loss) attributable to common stock	$ (3,177)	$ 995
Net income (loss) attributable to common stock per share – basic (in dollars per share)	$ (4.71)	$ 1.48
Net income (loss) attributable to common stock per share – diluted (in dollars per share)	$ (4.71)	$ 1.48

Acquisitions and Divestitures_5

Acquisitions and Divestitures - (Schedule of Merger Related Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Montage merger-related expenses	$ 41	$ 0	$ 0
Montage Resources Corporation
Business Acquisition [Line Items]
Bank, legal and consulting fees	18
Employee severance and related costs	17
Contract buyouts	5
Other	1
Montage merger-related expenses	$ 41

Leases (Narrative) (Details)

Leases (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended
	Jul. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating lease liability		$ 159	$ 153
Operating lease assets		163	$ 159
Operating lease term	10 years
Payment to previous lessor	$ 6
Operating lease not yet commenced		6
Montage Resources Corporation
Lessee, Lease, Description [Line Items]
Operating lease liability		25
Operating lease assets		$ 25

Leases (Components of Lease Cos

Leases (Components of Lease Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Components of lease costs:
Operating lease cost	$ 48	$ 45
Short-term lease cost	35	45
Variable lease cost	3	1
Total lease cost	$ 86	$ 91

Leases (Supplemental Informatio

Leases (Supplemental Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 47	$ 47
Right-of-use assets obtained in exchange for operating liabilities:
Operating leases	48	95
Right-of-use asset balance:
Operating leases	163	159
Lease liability balance:
Current operating leases	42	34
Long-term operating leases	117	119
Total operating leases	$ 159	$ 153
Operating lease (years)	5 years 7 months 6 days	6 years 7 months 6 days
Operating lease (Percent)	5.97%	5.33%

Leases (Maturity Analysis) (Det

Leases (Maturity Analysis) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Maturities of operating leases (ASC 842):
2021	$ 50
2022	37
2023	26
2024	18
2025	14
Thereafter	42
Total undiscounted lease liability	187
Imputed interest	(28)
Total discounted lease liability	$ 159	$ 153

Revenue Recognition (Narrative)

Revenue Recognition (Narrative) (Details) - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2020
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, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Operating revenues	$ 779	$ 527	$ 410	$ 592	$ 745	$ 636	$ 667	$ 990	$ 2,308	$ 3,038	$ 3,862
Exploration and Production
Disaggregation of Revenue [Line Items]
Operating revenues									1,391	1,740	2,551
Marketing
Disaggregation of Revenue [Line Items]
Operating revenues									917	1,298	1,311
Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating revenues									1,348	1,703	2,525
Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating revenues									2,145	2,850	3,745
Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating revenues									(1,185)	(1,515)	(2,408)
Intersegment Revenues | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating revenues									43	37	26
Intersegment Revenues | Marketing
Disaggregation of Revenue [Line Items]
Operating revenues									(1,228)	(1,552)	(2,434)
Gas sales
Disaggregation of Revenue [Line Items]
Operating revenues									967	1,241	1,998
Gas sales | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating revenues									928	1,207	1,974
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									39	34	24
Oil sales
Disaggregation of Revenue [Line Items]
Operating revenues									154	223	196
Oil sales | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating revenues									150	220	193
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									4	3	3
NGL sales
Disaggregation of Revenue [Line Items]
Operating revenues									265	274	352
NGL sales | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating revenues									265	274	353
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	0	(1)
Marketing
Disaggregation of Revenue [Line Items]
Operating revenues									917	1,297	1,222
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									2,145	2,849	3,497
Marketing | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating revenues									(1,228)	(1,552)	(2,275)
Marketing | Intersegment Revenues | Marketing
Disaggregation of Revenue [Line Items]
Operating revenues									(1,200)	(1,600)	(2,300)
Gas gathering
Disaggregation of Revenue [Line Items]
Operating revenues									0	0	89
Gas gathering | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating revenues											0
Gas gathering | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating revenues											248
Gas gathering | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Operating revenues											(159)
Other
Disaggregation of Revenue [Line Items]
Operating revenues									5	3	5
Other | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Operating revenues									5	2	5
Other | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Operating revenues									0	1	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, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Operating revenues	$ 779	$ 527	$ 410	$ 592	$ 745	$ 636	$ 667	$ 990	$ 2,308	$ 3,038	$ 3,862
Exploration and Production
Disaggregation of Revenue [Line Items]
Operating revenues									1,391	1,740	2,551
Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues									1,348	1,703	2,525
Northeast Appalachia | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues									648	964	1,165
Southwest Appalachia | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues									700	736	817
Fayetteville Shale | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues									0	0	537
Other | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues									$ 0	$ 3	$ 6

Revenue Recognition (Reconcilia

Revenue Recognition (Reconciliation of Accounts Receivable) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 350	$ 284
Other accounts receivable	18	61
Total accounts receivable	$ 368	$ 345

Derivatives and Risk Manageme_3

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, 2020USD ($)$ / bbl$ / MMBTUMcfbbl
Financial protection on production - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	751
Fair Value	$ 16
Financial protection on production - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	6,631
Fair Value	$ 0
Financial protection on production - 2021 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	6,473
Fair Value	$ (10)
Fixed price swaps - 2021 | Natural Gas | Purchased
Derivative [Line Items]
Volume | Mcf	6
Average price per MMBtu and Bbls | $ / MMBTU	2.44
Fair Value	$ 1
Fixed price swaps - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	201
Average price per MMBtu and Bbls | $ / MMBTU	2.80
Fair Value	$ 29
Fixed price swaps - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	4,887
Average price per MMBtu and Bbls | $ / bbl	48.59
Fair Value	$ 1
Fixed price swaps - 2021 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	5,889
Average price per MMBtu and Bbls | $ / bbl	7.12
Fair Value	$ (10)
Fixed price swaps - 2021 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	6,974
Average price per MMBtu and Bbls | $ / bbl	20.43
Fair Value	$ (36)
Fixed price swaps - 2021 | Not Designated as Hedging Instrument | Normal Butane
Derivative [Line Items]
Volume | bbl	2,004
Average price per MMBtu and Bbls | $ / bbl	24.97
Fair Value	$ (8)
Fixed price swaps - 2021 | Not Designated as Hedging Instrument | Natural Gasoline
Derivative [Line Items]
Volume | bbl	1,936
Average price per MMBtu and Bbls | $ / bbl	37.35
Fair Value	$ (13)
Two-way costless collars - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	237
Floor price per MMBtu and Bbls | $ / MMBTU	2.57
Cap price per MMBtu and Bbls | $ / MMBTU	2.95
Fair Value	$ 11
Two-way costless collars - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	201
Cap price per MMBtu and Bbls | $ / bbl	45.68
Fair Value	$ (1)
Two-way costless collars - 2021 | Not Designated as Hedging Instrument | Oil | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	37.73
Two-way costless collars - 2021 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	584
Cap price per MMBtu and Bbls | $ / bbl	10.40
Fair Value	$ 0
Two-way costless collars - 2021 | Not Designated as Hedging Instrument | Ethane | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	7.14
Three-way costless collars - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	313
Cap price per MMBtu and Bbls | $ / MMBTU	2.85
Fair Value	$ (24)
Three-way costless collars - 2021 | Not Designated as Hedging Instrument | Natural Gas | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.16
Three-way costless collars - 2021 | Not Designated as Hedging Instrument | Natural Gas | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.49
Three-way costless collars - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	1,543
Cap price per MMBtu and Bbls | $ / bbl	52.86
Fair Value	$ 0
Three-way costless collars - 2021 | Not Designated as Hedging Instrument | Oil | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	37.42
Three-way costless collars - 2021 | Not Designated as Hedging Instrument | Oil | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	47.22
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	378
Fair Value	$ (12)
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	2,155
Fair Value	$ 1
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	1,710
Fair Value	$ 0
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	112
Average price per MMBtu and Bbls | $ / MMBTU	2.68
Fair Value	$ 4
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	1,282
Average price per MMBtu and Bbls | $ / bbl	46.37
Fair Value	$ 0
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	1,575
Average price per MMBtu and Bbls | $ / bbl	8.69
Fair Value	$ 0
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	2,120
Average price per MMBtu and Bbls | $ / bbl	20.23
Fair Value	$ (2)
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Normal Butane
Derivative [Line Items]
Volume | bbl	667
Average price per MMBtu and Bbls | $ / bbl	22.77
Fair Value	$ (1)
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Natural Gasoline
Derivative [Line Items]
Volume | bbl	643
Average price per MMBtu and Bbls | $ / bbl	37.77
Fair Value	$ (2)
Two-way Costless-collars - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	63
Floor price per MMBtu and Bbls | $ / MMBTU	2.52
Cap price per MMBtu and Bbls | $ / MMBTU	3.03
Fair Value	$ (1)
Two-way Costless-collars - 2022 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	135
Cap price per MMBtu and Bbls | $ / bbl	9.66
Fair Value	$ 0
Two-way Costless-collars - 2022 | Not Designated as Hedging Instrument | Ethane | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	7.56
Three-way Costless-collars - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	203
Cap price per MMBtu and Bbls | $ / MMBTU	2.89
Fair Value	$ (15)
Three-way Costless-collars - 2022 | Not Designated as Hedging Instrument | Natural Gas | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.06
Three-way Costless-collars - 2022 | Not Designated as Hedging Instrument | Natural Gas | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.46
Three-way Costless-collars - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	873
Average price per MMBtu and Bbls | $ / bbl	0
Cap price per MMBtu and Bbls | $ / bbl	56.54
Fair Value	$ 1
Three-way Costless-collars - 2022 | Not Designated as Hedging Instrument | Oil | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	40.25
Three-way Costless-collars - 2022 | Not Designated as Hedging Instrument | Oil | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	50.78
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	87
Cap price per MMBtu and Bbls | $ / MMBTU	2.98
Fair Value	$ 0
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Natural Gas | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.06
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Natural Gas | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.47
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	878
Average price per MMBtu and Bbls | $ / bbl	0
Cap price per MMBtu and Bbls | $ / bbl	53.41
Fair Value	$ (1)
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Oil | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	33.52
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Oil | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	43.52
Basis swaps | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	420
Fair Value	$ 65
Basis Swaps - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	219
Basis Differential | $ / MMBTU	(0.21)
Fair Value	$ 57
Basis Swaps - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	139
Basis Differential | $ / MMBTU	(0.33)
Fair Value	$ 8
Basis Swaps - 2023 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	47
Basis Differential | $ / MMBTU	(0.45)
Fair Value	$ 0
Basis Swaps - 2024 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	11
Basis Differential | $ / MMBTU	(0.60)
Fair Value	$ 0
Basis Swaps - 2025 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	4
Basis Differential | $ / MMBTU	(0.59)
Fair Value	$ 0
Call options | Natural Gas
Derivative [Line Items]
Volume | Mcf	207
Fair Value	$ (36)
Call Option - 2021 | Natural Gas
Derivative [Line Items]
Volume | Mcf	75
Cap price per MMBtu and Bbls | $ / MMBTU	3.19
Fair Value	$ (8)
Call Option - 2021 | Oil | Sold
Derivative [Line Items]
Volume | bbl	226
Cap price per MMBtu and Bbls | $ / bbl	60
Fair Value	$ 0
Call Option - 2022 | Natural Gas
Derivative [Line Items]
Volume | Mcf	77
Cap price per MMBtu and Bbls | $ / MMBTU	3
Fair Value	$ (17)
Call Option - 2023 | Natural Gas
Derivative [Line Items]
Volume | Mcf	46
Cap price per MMBtu and Bbls | $ / MMBTU	2.94
Fair Value	$ (8)
Call Option - 2024 | Natural Gas
Derivative [Line Items]
Volume | Mcf	9
Cap price per MMBtu and Bbls | $ / MMBTU	3
Fair Value	$ (3)
Put options | Natural Gas
Derivative [Line Items]
Volume | Mcf	23
Fair Value	$ (1)
Put Option - 2021 | Natural Gas
Derivative [Line Items]
Volume | Mcf	18
Cap price per MMBtu and Bbls | $ / MMBTU	2
Fair Value	$ (1)
Put Option - 2022 | Natural Gas
Derivative [Line Items]
Volume | Mcf	5
Cap price per MMBtu and Bbls | $ / MMBTU	2
Fair Value	$ 0
Swaptions | Natural Gas
Derivative [Line Items]
Volume | Mcf	0.1
Cap price per MMBtu and Bbls | $ / MMBTU	3
Fair Value	$ (2)
Storage 2021 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume | Mcf	4
Fair Value	$ 0
Purchased Fixed Price Swaps, Storage, 2021 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume | Mcf	1
Average price per MMBtu and Bbls | $ / MMBTU	2.04
Basis Differential | $ / MMBTU	0
Fair Value	$ 0
Fixed Price Swap, Storage, 2021 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume | Mcf	2
Average price per MMBtu and Bbls | $ / MMBTU	2.49
Basis Differential | $ / MMBTU	0
Fair Value	$ 0
Basis Swaps Storage, 2021 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume | Mcf	1
Average price per MMBtu and Bbls | $ / MMBTU	0
Basis Differential | $ / MMBTU	(0.38)
Fair Value	$ 0

Derivatives and Risk Manageme_4

Derivatives and Risk Management (Narrative) (Details) $ in Millions	Dec. 31, 2020USD ($)
Not Designated as Hedging Instrument
Derivative [Line Items]
Impact of non-performance risk on fair value of the net derivative liability position	$ 1
Commodity Contract
Derivative [Line Items]
Derivative asset (liability)	$ (41)

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, 2020
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative assets	$ 391	$ 387
Derivative liabilities	236	428
Natural Gas | Fixed price swaps
Derivatives, Fair Value [Line Items]
Premium paid	9
Natural Gas | Not Designated as Hedging Instrument | Purchased fixed price swaps | Derivative assets | Purchased
Derivatives, Fair Value [Line Items]
Derivative assets	0	1
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	77	37
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	7
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	7
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	3
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	10	54
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	4	20
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	43
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	21
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	126	57
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	74	87
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	84	82
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	72	102
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	17	60
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	15	15
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	17	3
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	9	7
Natural Gas | Not Designated as Hedging Instrument | Call options | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	1	4
Natural Gas | Not Designated as Hedging Instrument | Call options | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	2	0
Natural Gas | Not Designated as Hedging Instrument | Call options | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	3	12
Natural Gas | Not Designated as Hedging Instrument | Call options | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	15	28
Natural Gas | Not Designated as Hedging Instrument | Put options | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	1
Natural Gas | Not Designated as Hedging Instrument | Swaptions | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	2
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	2
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	6	12
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	2	2
Oil | Not Designated as Hedging Instrument | Two-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	5	0
Oil | Not Designated as Hedging Instrument | Two-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	5	1
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	3	15
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	7	15
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	15
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	8	15
Oil | Not Designated as Hedging Instrument | Call options | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	0
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	11	0
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	10
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	21	0
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 | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	36
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	2
Propane | Not Designated as Hedging Instrument | Two-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	2	0
Natural gas storage | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	1	0
Normal Butane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	8
Normal Butane | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	1
Natural Gasoline | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	13
Natural Gasoline | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 0	$ 2

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, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	$ (138)	$ 94
Settled Gain (Loss) on Derivatives Recognized in Earnings	362	180
Total gain (loss) on derivatives	224	274
Fixed price swaps | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(25)	46
Settled Gain (Loss) on Derivatives Recognized in Earnings	142	78
Amortization of premium paid	9
Fixed price swaps | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	0	(22)
Settled Gain (Loss) on Derivatives Recognized in Earnings	65	10
Fixed price swaps | Ethane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(21)	6
Settled Gain (Loss) on Derivatives Recognized in Earnings	6	17
Fixed price swaps | Propane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(60)	13
Settled Gain (Loss) on Derivatives Recognized in Earnings	18	29
Fixed price swaps | Normal Butane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(9)	0
Settled Gain (Loss) on Derivatives Recognized in Earnings	(2)	0
Fixed price swaps | Natural Gasoline
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(15)	0
Settled Gain (Loss) on Derivatives Recognized in Earnings	(1)	0
Fixed price swaps | Natural gas storage
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(1)	1
Settled Gain (Loss) on Derivatives Recognized in Earnings	2	(1)
Two-way costless collars | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	10	2
Settled Gain (Loss) on Derivatives Recognized in Earnings	(5)	16
Two-way costless collars | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(1)	(10)
Settled Gain (Loss) on Derivatives Recognized in Earnings	17	6
Two-way costless collars | Propane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(1)	2
Settled Gain (Loss) on Derivatives Recognized in Earnings	2	2
Three-way costless collars | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(77)	37
Settled Gain (Loss) on Derivatives Recognized in Earnings	38	31
Amortization of premium paid	2
Three-way costless collars | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	3	(2)
Settled Gain (Loss) on Derivatives Recognized in Earnings	9	0
Basis swaps | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	59	17
Settled Gain (Loss) on Derivatives Recognized in Earnings	76	(3)
Call options | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(10)	1
Amortization of premium paid		1
Call options | Natural Gas | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Settled Gain (Loss) on Derivatives Recognized in Earnings	0	(2)
Call options | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	1	(1)
Swaptions | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	7	0
Purchased fixed price swaps | Natural Gas | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	2	(1)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(3)	0
Purchased fixed price swaps | Oil | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	0	6
Settled Gain (Loss) on Derivatives Recognized in Earnings	0	(3)
Purchased fixed price swaps | Natural gas storage | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Settled Gain (Loss) on Derivatives Recognized in Earnings	(1)	0
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	0	(1)
Settled Gain (Loss) on Derivatives Recognized in Earnings	$ (1)	$ 0

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, 2020	Dec. 31, 2019	Dec. 31, 2018
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ 3,246	$ 2,362	$ 1,979
Net current-period other comprehensive loss	(5)	3	8
Ending balance	497	3,246	2,362
Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(33)	(36)	(44)
Other comprehensive loss before reclassifications	0
Amounts reclassified from other comprehensive income	(5)
Net current-period other comprehensive loss	(5)	3	8
Ending balance	(38)	(33)	$ (36)
Pension and Other Postretirement
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(19)
Other comprehensive loss before reclassifications	0
Amounts reclassified from other comprehensive income	(5)
Net current-period other comprehensive loss	(5)
Ending balance	(24)	(19)
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 loss	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, 2020	Dec. 31, 2019	Dec. 31, 2018
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Income (Loss), Net	$ 1	$ (7)	$ 0
Provision for income taxes	407	(411)	1
Net Income (Loss)	(3,112)	$ 891	$ 537	[1]
Reclassified from Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income (Loss)	5
Pension and Other Postretirement | Reclassified from Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Income (Loss), Net	(6)
Provision for income taxes	(1)
Net Income (Loss)	$ (5)
[1]	In 2018, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

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, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	$ 155	$ (41)
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	5	13
Revolving credit facility	34	700
Derivative instruments, net	155	(41)
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	5	13
Revolving credit facility	34	700
Derivative instruments, net	155	(41)
Senior Notes | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	2,228	2,471
Senior Notes | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	2,085	$ 2,609
Natural Gas | Fixed price swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid	$ 9

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Impairments		$ 2,830,000,000	$ 16,000,000	$ 171,000,000
Montage Resources Corporation
Debt Instrument [Line Items]
Impairments		0
Not Designated as Hedging Instrument
Debt Instrument [Line Items]
Impact of non-performance risk on fair value of the net derivative liability position		1,000,000
Nonrecurring
Debt Instrument [Line Items]
Impairments				161,000,000
Nonrecurring | Marketing
Debt Instrument [Line Items]
Impairments				145,000,000
Nonrecurring | Exploration and Production
Debt Instrument [Line Items]
Impairments				15,000,000
Other non-core assets
Debt Instrument [Line Items]
Impairments	$ 1,000,000	5,000,000	16,000,000	11,000,000
Other non-core assets | Nonrecurring
Debt Instrument [Line Items]
Carrying value of non core assets		6,000,000	26,000,000
Impairments		$ 5,000,000	$ 16,000,000	$ 1,000,000
Senior Notes | 4.10% Senior Notes Due January March 2022
Debt Instrument [Line Items]
Stated interest rate		4.10%	4.10%

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, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	$ 155	$ (41)
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	(41)
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	0	0
Purchased fixed price swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		1
Derivative liabilities	(1)
Purchased fixed price swaps | 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
Purchased fixed price swaps | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		1
Derivative liabilities	(1)
Purchased fixed price swaps | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Derivative liabilities	0
Fixed price swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	125	59
Derivative liabilities	(9)	(96)
Fixed price swaps | 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 | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	125	59
Derivative liabilities	(9)	(96)
Fixed price swaps | 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
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid	9
Two-way costless collars
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	21	74
Derivative liabilities	(13)	(65)
Two-way costless collars | 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 | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	21	74
Derivative liabilities	(13)	(65)
Two-way costless collars | 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
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	210	174
Derivative liabilities	(168)	(214)
Three-way costless collars | 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 | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	210	174
Derivative liabilities	(168)	(214)
Three-way costless collars | 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
Basis swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	32	75
Derivative liabilities	(26)	(10)
Basis swaps | 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 | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	32	75
Derivative liabilities	(26)	(10)
Basis swaps | 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
Call options
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3	4
Derivative liabilities	(19)	(40)
Call options | 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
Call options | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3	4
Derivative liabilities	(19)	(40)
Call options | 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
Put options
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(1)
Put options | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		0
Put options | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(1)
Put options | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		0
Swaptions
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(2)
Swaptions | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		0
Swaptions | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(2)
Swaptions | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		$ 0

Debt (Components of Debt) (Deta

Debt (Components of Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Apr. 07, 2020	Dec. 31, 2019	Jul. 31, 2018	Jan. 31, 2015
Debt Instrument [Line Items]
Debt Instrument	$ 3,171		$ 2,262
Unamortized Issuance Expense	(20)		(19)
Unamortized Debt Discount	(1)		(1)
Total	3,150		2,242
Debt issuance costs, line of credit	$ 12		11
Line of Credit | 2018 Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility, variable interest rate	2.11%
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Debt Instrument	$ 700
Unamortized Issuance Expense	0
Unamortized Debt Discount	0
Total	700
Senior Notes | 4.10% Senior Notes Due January March 2022
Debt Instrument [Line Items]
Debt Instrument	207		213
Unamortized Issuance Expense	0		(1)
Unamortized Debt Discount	0		0
Total	$ 207		$ 212
Stated interest rate	4.10%		4.10%
Senior Notes | 4.95% Senior Notes Due January 2025
Debt Instrument [Line Items]
Debt Instrument	$ 856		$ 892
Unamortized Issuance Expense	(4)		(5)
Unamortized Debt Discount	(1)		(1)
Total	$ 851		$ 886
Stated interest rate	4.95%	6.45%	4.95%	6.20%	4.95%
Senior Notes | 7.50% Senior Notes Due April 2026
Debt Instrument [Line Items]
Debt Instrument	$ 618		$ 639
Unamortized Issuance Expense	(6)		(7)
Unamortized Debt Discount	0		0
Total	$ 612		$ 632
Stated interest rate	7.50%		7.50%
Senior Notes | 7.75% Senior Notes Due October 2027
Debt Instrument [Line Items]
Debt Instrument	$ 440		$ 484
Unamortized Issuance Expense	(5)		(6)
Unamortized Debt Discount	0		0
Total	$ 435		$ 478
Stated interest rate	7.75%		7.75%
Senior Notes | Eight Point Three Seven Five Percent Senior Notes Due September 2028
Debt Instrument [Line Items]
Debt Instrument	$ 350
Unamortized Issuance Expense	(5)
Unamortized Debt Discount	0
Total	$ 345
Stated interest rate	8.375%
Term Loan | 2018 Term Loan Facility Due April 2023
Debt Instrument [Line Items]
Debt Instrument			$ 34
Unamortized Issuance Expense			0
Unamortized Debt Discount			0
Total			$ 34
Debt variable rate			4.31%

Debt (Schedule of Debt Maturiti

Debt (Schedule of Debt Maturities) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Long-term Debt, Fiscal Year Maturity [Abstract]
2021	$ 0
2022	207
2023	0
2024	700
2025	856
Thereafter	1,408
Total	$ 3,171	$ 2,262

Debt (2018 Revolving Credit Fac

Debt (2018 Revolving Credit Facility - Narrative) (Details)	1 Months Ended		3 Months Ended	12 Months Ended
	Oct. 31, 2020USD ($)	Apr. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Debt Instrument [Line Items]
Subsidiary ownership				100.00%
Letters of credit outstanding				$ 233,000,000
Debt instrument				3,171,000,000	$ 2,262,000,000
October 2020 Amendment
Debt Instrument [Line Items]
Basis points	25.00%
Limit of unrestricted cash and cash equivalents	$ 200,000,000
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	2,000,000,000
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
Debt instrument				$ 700,000,000
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		1.75%
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | Eurodollar | Maximum
Debt Instrument [Line Items]
Basis points		2.75%
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | Base Rate | Minimum
Debt Instrument [Line Items]
Basis points		0.75%
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility | Base Rate | Maximum
Debt Instrument [Line Items]
Basis points		1.75%

Debt (Senior Notes - Narrative)

Debt (Senior Notes - Narrative) (Details) - USD ($)	1 Months Ended		6 Months Ended		12 Months Ended
	Aug. 31, 2020	Jan. 31, 2015	Jun. 30, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Apr. 07, 2020	Jul. 31, 2018
Debt Instrument [Line Items]
Gain on early extinguishment of debt					$ 35,000,000	$ 8,000,000	$ (17,000,000)
Senior Notes
Debt Instrument [Line Items]
Repayments of long-term debt				$ 54,000,000
Gain on early extinguishment of debt			$ 35,000,000	$ 8,000,000
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%
Senior Notes | 4.95% Senior Notes Due January 2025
Debt Instrument [Line Items]
Senior notes		$ 1,000,000,000
Stated interest rate		4.95%		4.95%	4.95%	4.95%		6.45%	6.20%
Debt stated interest rate cap									6.95%
Debt repurchased face amount			36,000,000	$ 35,000,000		$ 35,000,000
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			21,000,000	$ 11,000,000		$ 11,000,000
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			44,000,000	$ 16,000,000		$ 16,000,000
Senior Notes | 4.05% Senior Notes Due January 2020
Debt Instrument [Line Items]
Stated interest rate				4.05%		4.05%
Debt repurchased face amount			72,000,000	$ 52,000,000		$ 52,000,000
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			$ 6,000,000
Senior Notes | Eight Point Three Seven Five Percent Senior Notes Due September 2028
Debt Instrument [Line Items]
Senior notes	$ 350,000,000
Stated interest rate					8.375%
Proceeds from issuance of long-term debt	$ 345,000,000
Percentage price of face value of the notes sold to the public	100.00%
Senior Notes | Eight Point Eight Seven Five Percent Senior Notes Due 2023 | Montage Resources Corporation
Debt Instrument [Line Items]
Senior notes	$ 510,000,000
Stated interest rate	8.875%

Commitments and Contingencies_2

Commitments and Contingencies (Narrative) (Details)	Dec. 31, 2020USD ($)lease	Mar. 31, 2019USD ($)
Commitments And Contingencies [Line Items]
Obligation under transportation agreements	$ 8,544,000,000
Guarantee obligations relative to the firms transportation agreements and gathering project and services	923,000,000
Maturities of operating leases (ASC 842):
2021	50,000,000
2022	37,000,000
2023	26,000,000
2024	18,000,000
2025	14,000,000
Thereafter	42,000,000
Indemnification liability	0
Pending regulatory approval and/or construction
Commitments And Contingencies [Line Items]
Obligation under transportation agreements	531,000,000
Appalachian Basin
Commitments And Contingencies [Line Items]
Obligation under transportation agreements		$ 357,000,000
Maturities of operating leases (ASC 842):
Obligation under transportation agreements, reimbursed by seller		$ 133,000,000
Pressure Pumping Equipment | Exploration and Production
Commitments And Contingencies [Line Items]
Aggregate annual lease payment	6,000,000
Drilling Rigs | Exploration and Production
Commitments And Contingencies [Line Items]
Aggregate annual lease payment	$ 11,000,000
Number of leases | lease	7
Office Space, Vehicles And Equipment
Maturities of operating leases (ASC 842):
2021	$ 30,000,000
2022	21,000,000
2023	18,000,000
2024	14,000,000
2025	12,000,000
Thereafter	36,000,000
Compression Rentals
Maturities of operating leases (ASC 842):
2021	20,000,000
2022	14,000,000
2023	3,000,000
2024	$ 1,000,000

Commitments and Contingencies_3

Commitments and Contingencies (Schedule of Future Obligation under Transportation Agreements) (Details) $ in Millions	Dec. 31, 2020USD ($)
Other Commitments [Line Items]
Total	$ 8,544
Less than 1 Year	862
1 to 3 Years	1,562
3 to 5 Years	1,323
5 to 8 Years	1,901
More than 8 Years	2,896
Infrastructure currently in service
Other Commitments [Line Items]
Total	8,013
Less than 1 Year	860
1 to 3 Years	1,532
3 to 5 Years	1,286
5 to 8 Years	1,813
More than 8 Years	2,522
Pending regulatory approval and/or construction
Other Commitments [Line Items]
Total	531
Less than 1 Year	2
1 to 3 Years	30
3 to 5 Years	37
5 to 8 Years	88
More than 8 Years	374
Firm transportation commitments | Montage Resources Corporation
Other Commitments [Line Items]
Total	1,100
Less than 1 Year	99
1 to 3 Years	197
3 to 5 Years	196
5 to 8 Years	284
More than 8 Years	$ 324

Income Taxes (Provision (Benefi

Income Taxes (Provision (Benefit) for Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current:
Federal	$ (2)	$ (1)	$ (5)
State	0	(1)	6
Total Current	(2)	(2)	1
Deferred:
Federal	371	(431)	0
State	38	22	0
Total Deferred	409	(409)	0
Provision (Benefit) for Income Taxes	$ 407	$ (411)	$ 1

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Taxes [Line Items]
Effective tax rate		(15.00%)	(86.00%)	0.00%
Corporate income tax rate		21.00%
Alternative minimum tax carryforward, expected refund		$ 30,000,000
Sequestered amount relating to alternative minimum tax refunds		2,000,000
Income tax refund received		32,000,000	$ 1,000,000
Income taxes paid				$ 6,300,000
Operating loss carryforwards subject to a section 382 limitation		90,000,000
Discrete tax expense	$ 408,000,000
Operating loss carryforward valuation allowance	$ 87,000,000
Release of valuation allowance		0	(522,000,000)
Change in valuation allowance		1,034,000,000	$ (522,000,000)	$ (121,000,000)
Unrecognized tax benefits that would impact effective tax rate		0
Montage Resources Corporation
Income Taxes [Line Items]
Net operating loss carryforward		1,000,000,000
Operating loss carryforwards subject to a section 382 limitation		1,700,000
Statutory depletion carryforward
Income Taxes [Line Items]
Tax credit carryforward		13,000,000
Interest deduction carryforward
Income Taxes [Line Items]
Tax credit carryforward		55,000,000
Exploration Program in Canada
Income Taxes [Line Items]
Net operating loss carryforward		29,000,000
Federal
Income Taxes [Line Items]
Net operating loss carryforward		4,500,000,000
Statel
Income Taxes [Line Items]
Net operating loss carryforward		$ 2,000,000,000

Income Taxes (Reconciliation of

Income Taxes (Reconciliation of Provision for Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Expected provision (benefit) at federal statutory rate	$ (568)	$ 101	$ 113
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect	(55)	11	13
Change in valuation allowance	1,034	(522)	(121)
Removal of sequestration fee on AMT receivables	0	0	(5)
Other	(4)	(1)	1
Provision (Benefit) for Income Taxes	$ 407	$ (411)	$ 1

Income Taxes (Components of Def

Income Taxes (Components of Deferred Tax Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Deferred tax liabilities:
Differences between book and tax basis of property	$ 0	$ 312
Derivative activity	0	34
Right of use lease asset	38	37
Other	2	2
Total deferred tax liabilities	40	385
Deferred tax assets:
Differences between book and tax basis of property	295	0
Accrued compensation	38	33
Accrued pension costs	11	9
Asset retirement obligations	20	13
Net operating loss carryforward	1,117	769
Future lease payments	38	37
Derivative activity	9	0
Capital loss carryover	27	0
Other	24	18
Total deferred tax assets	1,579	879
Valuation allowance	(1,539)	(87)	$ (609)
Net deferred tax asset	$ 0	$ 407

Income Taxes (Reconciliation _2

Income Taxes (Reconciliation of Changes to the Valuation Allowance) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Deferred Tax Asset, Valuation Allowance [Roll Forward]
Valuation allowance, beginning balance	$ 87	$ 609
Release of valuation allowance	0	(522)
Establishment of valuation allowance on opening deferred balance	408	0
Opening balance adjustments	6	0
Changes based on 2020 activity	626	0
Purchase accounting	412	0
Valuation allowance, ending balance	$ 1,539	$ 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, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits, beginning balance	$ 0	$ 7	$ 12
Additions based on tax positions related to the current year	0	0	0
Additions to tax positions of prior years	0	0	0
Reductions to tax positions of prior years	0	(7)	(5)
Unrecognized tax benefits, ending balance	$ 0	$ 0	$ 7

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at January 1	$ 57	$ 61
Accretion of discount	4	3
Obligations incurred	1	2
Obligations assumed from Montage	28	0
Obligations settled/removed	(6)	(9)
Revisions of estimates	1	0
Asset retirement obligation at December 31	85	57
Current liability			$ 4	$ 6
Long-term liability			81	51
Asset retirement obligation at December 31	$ 57	$ 57	$ 85	$ 57

Retirement and Employee Benef_3

Retirement and Employee Benefit Plans (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan cost	$ 2	$ 2	$ 3
Contributions capitalized	1	1	2
Non-cash curtailment gain			4
Lump-sum payment		21
Defined benefit plan included in accumulated other comprehensive (income) loss, before tax	36	30
Defined benefit plan included in accumulated other comprehensive (income) loss after tax	28	22
Total change in value of pension and postretirement liabilities	5	(3)	(8)	[1]
Expected future net loss	1
Company's expected additional annual contribution	13
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-cash curtailment gain	0	0	4
Settlement loss	0	0	0
Total change in value of pension and postretirement liabilities	(1)	1
Employer contributions	1	2
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-cash curtailment gain	0	0	0
Settlement loss	0	6	$ 0
Total change in value of pension and postretirement liabilities	5	(4)
Employer contributions	$ 12	$ 12
[1]	In 2018, 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, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Change in benefit obligations:
Benefit obligation at January 1	$ 126	$ 125
Service cost	7	7	$ 10
Interest cost	5	5	5
Participant contributions	0	0
Actuarial loss	16	15
Benefits paid	(13)	(2)
Plan amendments	0	0
Curtailments	(2)	0
Settlements	0	(24)
Benefit obligation at December 31	139	126	125
Change in plan assets:
Fair value of plan assets at January 1	96	91
Actual return on plan assets	11	16
Employer contributions	12	12
Participant contributions	0	0
Benefits paid	(13)	(2)
Settlements	0	(21)
Fair value of plan assets at December 31	106	96	91
Funded status of plans at December 31	(33)	(30)
Other Postretirement Benefits
Change in benefit obligations:
Benefit obligation at January 1	13	13
Service cost	2	1	2
Interest cost	0	0	1
Participant contributions	0	0
Actuarial loss	1	1
Benefits paid	(1)	(2)
Plan amendments	(2)	0
Curtailments	0	0
Settlements	0	0
Benefit obligation at December 31	13	13	13
Change in plan assets:
Fair value of plan assets at January 1	0	0
Actual return on plan assets	0	0
Employer contributions	1	2
Participant contributions	0	0
Benefits paid	(1)	(2)
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) - Pension Benefits - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 139	$ 126
Accumulated benefit obligation	139	124
Fair value of plan assets	$ 106	$ 96

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Curtailment gain			$ (4)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 7	$ 7	10
Interest cost	5	5	5
Expected return on plan assets	(6)	(6)	(7)
Amortization of transition obligation	0	0	0
Amortization of prior service cost	0	0	0
Amortization of net loss	1	2	2
Net periodic benefit cost	7	8	10
Curtailment gain	0	0	0
Settlement loss	0	6	0
Total benefit cost (benefit)	7	14	10
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	2	1	2
Interest cost	0	0	1
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	2	1	3
Curtailment gain	0	0	(4)
Settlement loss	0	0	0
Total benefit cost (benefit)	$ 2	$ 1	$ (1)

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, 2020	Dec. 31, 2019	Dec. 31, 2018	[1]
Defined Benefit Plan Disclosure [Line Items]
Total change in value of pension and postretirement liabilities	$ (5)	$ 3	$ 8
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (loss) gain arising during the year	(12)	(5)
Amortization of prior service cost	0	0
Amortization of net loss	1	2
Settlements	0	8
Curtailments	3	0
Tax effect	3	(1)
Total change in value of pension and postretirement liabilities	(5)	4
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (loss) gain arising during the year	2	(1)
Amortization of prior service cost	0	0
Amortization of net loss	0	0
Settlements	0	0
Curtailments	0	0
Tax effect	(1)	0
Total change in value of pension and postretirement liabilities	$ 1	$ (1)
[1]	In 2018, 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, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.50%	3.50%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.10%	3.70%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.80%	3.50%

Retirement and Employee Benef_9

Retirement and Employee Benefit Plans (Schedule of Assumptions Used - Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.50%	3.50%	3.50%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.70%	3.70%	4.35%
Expected return on plan assets	6.50%	7.00%	7.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.50%	4.35%	4.35%

Retirement and Employee Bene_10

Retirement and Employee Benefit Plans (Schedule of Health Care Cost Trend Rates) (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Retirement Benefits [Abstract]
Health care cost trend assumed for next year	6.50%	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	2037

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, 2020USD ($)
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	(2)
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, 2020USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2021	$ 5
2022	5
2023	5
2024	6
2025	5
Years 2026-2030	26
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2021	1
2022	1
2023	1
2024	1
2025	1
Years 2026-2030	$ 4

Retirement and Employee Bene_13

Retirement and Employee Benefit Plans (Schedule of Allocation of Plan Assets) (Details) - Pension Benefits	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	100.00%
Actual asset allocations	100.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	60.00%
Actual asset allocations	66.00%
Equity securities, US equity
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	30.00%
Actual asset allocations	49.00%
Equity securities, Non-U.S. developed equity
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	30.00%
Actual asset allocations	17.00%
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	35.00%
Actual asset allocations	32.00%
Cash
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	5.00%
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 106	$ 96	$ 91
Excluding Net Asset Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	101	67
Excluding Net Asset Value | Equity securities, U.S. large cap value equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10	6
Excluding Net Asset Value | Equity securities, U.S. large cap core equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	24
Excluding Net Asset Value | Equity securities, U.S. small cap equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	13	2
Excluding Net Asset Value | Non-U.S. equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18	32
Excluding Net Asset Value | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34	22
Excluding Net Asset Value | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	2
Excluding Net Asset Value | Equity securities, U.S. large cap growth equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		3
Quoted Prices in Active Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	101	67
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	10	6
Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities, U.S. large cap core equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	24
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	13	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	18	32
Quoted Prices in Active Markets for Identical Assets (Level 1) | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34	22
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	2
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
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 value 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 core equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	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) | 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 Observable Inputs (Level 2) | Equity securities, U.S. large cap growth equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		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 value 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 core equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	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) | 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
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
Net Asset Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5	29
Net Asset Value | Equity securities, U.S. large cap core equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		18
Net Asset Value | Equity securities, U.S. small cap equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2
Net Asset Value | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		8
Net Asset Value | Equity securities, U.S. large cap growth equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 3	$ 3

Long-Term Incentive Compensat_3

Long-Term Incentive Compensation (Narrative) (Details) - USD ($)	1 Months Ended	12 Months Ended
	May 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of options granted		0	0	0
Number of options exercised		0	0	0
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		$ 0	$ 1,000,000	$ 1,000,000
Equity-classified awards, unrecognized compensation cost		$ 0
Number of options granted		0	0	0
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		$ 2,000,000	$ 1,000,000	$ 2,000,000
Equity-classified awards, unrecognized compensation cost		$ 1,000,000
Equity-classified awards, weighted average period over which unrecognized cost is recognized, years		1 year
Total fair value of restricted stock grants		$ 2,000,000	2,000,000	2,000,000
Total fair value of shares vested		$ 6,000,000	$ 11,000,000	$ 19,000,000
Number of units awarded		584,000	493,000	350,000
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	3 years	3 years	3 years	3 years
Increase (decrease) in deferred tax asset		$ 1,000,000	$ 1,000,000	$ 1,000,000
Number of units awarded		0	0	0
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
Equity-Classified Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards, unrecognized compensation cost		$ 1,000,000
Equity-classified awards, weighted average period over which unrecognized cost is recognized, years		1 year
Number of units awarded		186,000
Liability-Classified RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in deferred tax asset		$ 1,000,000	$ 1,000,000	$ 2,000,000
Liability-classified restricted stock, vesting period		4 years
Liability-classified restricted stock, unrecognized compensation cost		$ 22,000,000
Liability-classified restricted stock, weighted average period over which unrecognized cost is recognized, years		2 years
Liability-Classified Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in deferred tax asset		$ 2,000,000	$ (1,000,000)	$ 1,000,000
Liability-classified performance units, vesting period		3 years
Liability-classified performance units, unrecognized compensation cost		$ 14,000,000
Liability-classified performance units, weighted average period over which unrecognized cost is recognized, years		2 years
Performance cash awards
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		$ 1,000,000
Liability-classified restricted stock, unrecognized compensation cost		$ 14,000,000
Liability-classified restricted stock, weighted average period over which unrecognized cost is recognized, years		3 years 2 months 12 days

Long-Term Incentive Compensat_4

Long-Term Incentive Compensation (Schedule of Equity-Classified Stock Option Stock-Based Compensation Costs) (Details) - Stock Options - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity-classified awards - expensed	$ 0	$ 1	$ 2
Equity-classified awards - capitalized	$ 0	$ 0	$ 0

Long-Term Incentive Compensat_5

Long-Term Incentive Compensation (Summary of Equity-Classified Stock Option Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Number of Shares
Number of Options, Outstanding at January 1 (in shares)	4,635,000	5,178,000	6,020,000
Number of Options, Granted (in shares)	0	0	0
Number of Options, Exercised (in shares)	0	0	0
Number of Options, Forfeited or expired (in shares)	(785,000)	(543,000)	(842,000)
Number of Options, Outstanding at December 31 (in shares)	3,850,000	4,635,000	5,178,000
Weighted Average Exercise Price
Weighted Average Exercise Price, Outstanding at January 1 (in dollars per share)	$ 15.26	$ 17.06	$ 19.43
Weighted Average Exercise Price, Granted (in dollars per share)	0	0	0
Weighted Average Exercise Price, Exercised (in dollars per share)	0	0	0
Weighted Average Exercise Price, Forfeited or expired (in dollars per share)	24.46	32.38	33.99
Weighted Average Exercise Price, Outstanding at December 31 (in dollars per share)	$ 13.39	$ 15.26	$ 17.06

Long-Term Incentive Compensat_6

Long-Term Incentive Compensation (Summary of Equity-Classified Stock Options Outstanding and Options Exercisable) (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Outstanding - Options Outstanding at December 31, 2020 (in shares)	3,850	4,635	5,178	6,020
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 13.39	$ 15.26	$ 17.06	$ 19.43
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	2 years
Options Exercisable - Options Exercisable at December 31, 2020 (in shares)	3,850
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 13.39
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	2 years
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)	$ 7.74
Range of Exercise Prices, Upper Range Limit (in dollars per share)	$ 29.42
Options Outstanding - Options Outstanding at December 31, 2020 (in shares)	3,126
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 8.95
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	2 years 3 months 18 days
Options Exercisable - Options Exercisable at December 31, 2020 (in shares)	3,126
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 8.95
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	2 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, 2020 (in shares)	634
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 30.59
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	10 months 24 days
Options Exercisable - Options Exercisable at December 31, 2020 (in shares)	634
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 30.59
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, 2020 (in shares)	90
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 46.55
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	3 months 18 days
Options Exercisable - Options Exercisable at December 31, 2020 (in shares)	90
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 46.55
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	3 months 18 days

Long-Term Incentive Compensat_7

Long-Term Incentive Compensation (Schedule of Equity-Classified Restricted Stock Stock-Based Compensation Costs) (Details) - Restricted Stock - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	$ 3	$ 6	$ 9
Equity-classified awards - capitalized	$ 1	$ 4	$ 5

Long-Term Incentive Compensat_8

Long-Term Incentive Compensation (Summary of Equity-Classified Restricted Stock Activity) (Details) - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	1,480,000	2,717,000	6,254,000
Number of Shares/Units, Granted (in shares)	584,000	493,000	350,000
Number of Shares/Units, Vested (in shares)	(1,098,000)	(1,516,000)	(2,058,000)
Number of Shares/Units, Forfeited (in shares)	(269,000)	(214,000)	(1,829,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	697,000	1,480,000	2,717,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 7	$ 7.91	$ 8.85
Weighted Average Fair Value, Granted (in dollars per share)	2.86	3.06	4.72
Weighted Average Fair Value, Vested (in dollars per share)	5.26	7.16	9.24
Weighted Average Fair Value, Forfeited (in dollars per share)	7.79	8.38	9.01
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 5.97	$ 7	$ 7.91
Workforce Reduction
Number of Shares
Number of Shares/Units, Forfeited (in shares)	(171,813)	(65,196)	(1,287,636)

Long-Term Incentive Compensat_9

Long-Term Incentive Compensation (Summary of Equity-Classified Restricted Stock Unit Activity) (Details) - Equity-Classified Restricted Stock Units shares in Thousands	12 Months Ended
	Dec. 31, 2020$ / sharesshares
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares) | shares	0
Number of Shares/Units, Granted (in shares) | shares	186
Number of Shares/Units, Vested (in shares) | shares	(42)
Number of Shares/Units, Forfeited (in shares) | shares	(10)
Number of Shares/Units, Unvested shares/units at December 31 (in shares) | shares	134
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share) | $ / shares	$ 0
Weighted Average Fair Value, Granted (in dollars per share) | $ / shares	3.05
Weighted Average Fair Value, Vested (in dollars per share) | $ / shares	3.05
Weighted Average Fair Value, Forfeited (in dollars per share) | $ / shares	3.05
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share) | $ / shares	$ 3.05

Long-Term Incentive Compensa_10

Long-Term Incentive Compensation (Schedule of Equity-Classified Performance Units Stock-Based Compensation Costs) (Details) - Performance units - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	$ 0	$ 1	$ 3
Equity-classified awards - capitalized	$ 0	$ 0	$ 1

Long-Term Incentive Compensa_11

Long-Term Incentive Compensation (Summary of Equity-Classified Performance Units Activity) (Details) - Performance units - $ / shares	1 Months Ended	12 Months Ended
	May 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares)		178,000	598,000	1,084,000
Number of Shares/Units, Granted (in shares)		0	0	0
Number of Shares/Units, Vested (in shares)		(178,000)	(378,000)	(290,000)
Number of Shares/Units, Forfeited (in shares)		0	(42,000)	(196,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)		0	178,000	598,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)		$ 10.47	$ 10.01	$ 10.12
Weighted Average Fair Value, Granted (in dollars per share)		0	0	0
Weighted Average Fair Value, Vested (in dollars per share)		10.47	9.59	10.47
Weighted Average Fair Value, Forfeited (in dollars per share)		0	10.47	9.94
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)		$ 0	$ 10.47	$ 10.01
Vesting period for stock awards from grant date	3 years	3 years	3 years	3 years
Minimum
Number of Shares
Number of Shares/Units, Granted (in shares)		0	0	0
Maximum
Number of Shares
Number of Shares/Units, Granted (in shares)		2	2	2
Workforce Reduction
Number of Shares
Number of Shares/Units, Forfeited (in shares)			(41,761)	(144,927)

Long-Term Incentive Compensa_12

Long-Term Incentive Compensation (Schedule of Liability-Classified Restricted Stock Units Stock-Based Compensation Costs) (Details) - Liability-Classified RSUs - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	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	$ 5	$ 7	$ 4
Liability-classified stock-based compensation cost - capitalized	$ 2	$ 5	$ 3

Long-Term Incentive Compensa_13

Long-Term Incentive Compensation (Summary of Liability-Classified Restricted Stock Unit Activity) (Details) - Liability-Classified RSUs - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Number of Units
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	12,992,000	8,202,000	0
Number of Shares/Units, Granted (in shares)	6,172,000	8,659,000	12,216,000
Number of Shares/Units, Vested (in shares)	(3,960,000)	(2,624,000)	(232,000)
Number of Shares/Units, Forfeited (in shares)	(3,591,000)	(1,245,000)	(3,782,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	11,613,000	12,992,000	8,202,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 2.42	$ 3.41	$ 0
Weighted Average Fair Value, Granted (in dollars per share)	1.41	4.34	3.69
Weighted Average Fair Value, Vested (in dollars per share)	1.43	4.09	5.14
Weighted Average Fair Value, Forfeited (in dollars per share)	2.67	3.48	4.86
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 2.67	$ 2.42	$ 3.41
Workforce Reduction
Number of Units
Number of Shares/Units, Forfeited (in shares)	(2,010,196)	(400,056)	(2,766,610)

Long-Term Incentive Compensa_14

Long-Term Incentive Compensation (Schedule of Liability-Classified Performance Units Stock-Based Compensation Costs) (Details) - Liability-Classified Performance Units - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	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	$ 2	$ 2
Liability-classified stock-based compensation cost - capitalized	$ 2	$ 1	$ 0

Long-Term Incentive Compensa_15

Long-Term Incentive Compensation (Summary of Liability-Classified Performance Unit Activity) (Details) - Liability-Classified Performance Units - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Number of Units
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	5,142,000	2,803,000	0
Number of Shares/Units, Granted (in shares)	6,172,000	2,757,000	3,200,000
Number of Shares/Units, Vested (in shares)	0	(43,000)	0
Number of Shares/Units, Forfeited (in shares)	(2,615,000)	(375,000)	(397,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	8,699,000	5,142,000	2,803,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 2.42	$ 3.41	$ 0
Weighted Average Fair Value, Granted (in dollars per share)	1.41	4.34	3.70
Weighted Average Fair Value, Vested (in dollars per share)	0	2.42	0
Weighted Average Fair Value, Forfeited (in dollars per share)	3.05	3.12	4.55
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 2.57	$ 2.42	$ 3.41
Workforce Reduction
Number of Units
Number of Shares/Units, Forfeited (in shares)	(518,450)	(375,086)	(295,160)

Long-term Incentive Compensa_16

Long-term Incentive Compensation (Summary of Liability-Classified Restricted Cash Unit Activity) (Details) - Performance cash awards	12 Months Ended
	Dec. 31, 2020$ / sharesshares
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	0
Number of Shares/Units, Granted (in shares)	20,044,000
Number of Shares/Units, Vested (in shares)	(100,000)
Number of Shares/Units, Forfeited (in shares)	(1,591,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	18,353,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share) | $ / shares	$ 0
Weighted Average Fair Value, Granted (in dollars per share) | $ / shares	1
Weighted Average Fair Value, Vested (in dollars per share) | $ / shares	1
Weighted Average Fair Value, Forfeited (in dollars per share) | $ / shares	1
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share) | $ / shares	$ 1
Workforce Reduction
Number of Shares
Number of Shares/Units, Forfeited (in shares)	(945,500)

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenues from external customers	$ 779	$ 527	$ 410	$ 592	$ 745	$ 636	$ 667	$ 990	$ 2,308	$ 3,038	$ 3,862
Depreciation, depletion and amortization expense									357	471	560
Impairments									2,830	16	171
Operating loss	(244)	$ (381)	$ (756)	$ (1,490)	64	$ (29)	$ 22	$ 213	(2,871)	270	797
Interest expense									94	65	124
Gain (loss) on derivatives									224	274	(118)
Gain (Loss) on Early Extinguishment of Debt									35	8	(17)
Other income, net									1	(7)	0
Provision (benefit) for income taxes									407	(411)	1
Assets	5,160				6,717				5,160	6,717	5,797
Capital investments									899	1,140	1,248
Restructuring charges									16	11	39
Montage merger-related expenses									41	0	0
Increase (decrease) in accrued expenditures between periods									(3)	34	(53)
Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									917	1,297	1,222
Exploration and Production
Segment Reporting Information [Line Items]
Revenues from external customers									1,391	1,740	2,551
Depreciation, depletion and amortization expense											514
Montage merger-related expenses									41
Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									917	1,298	1,311
Depreciation, depletion and amortization expense											46
Intersegment Revenues
Segment Reporting Information [Line Items]
Revenues from external customers									(1,185)	(1,515)	(2,408)
Intersegment Revenues | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									(1,228)	(1,552)	(2,275)
Intersegment Revenues | Exploration and Production
Segment Reporting Information [Line Items]
Revenues from external customers									43	37	26
Intersegment Revenues | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									(1,228)	(1,552)	(2,434)
Intersegment Revenues | Marketing | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									(1,200)	(1,600)	(2,300)
Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Revenues from external customers									1,348	1,703	2,525
Depreciation, depletion and amortization expense									348	462
Impairments									2,830	13	15
Operating loss									(2,864)	283	794
Interest expense									94	65	124
Gain (loss) on derivatives									224	274	(118)
Gain (Loss) on Early Extinguishment of Debt									0	0	0
Other income, net									0	(9)	2
Provision (benefit) for income taxes									407	(411)	1
Assets	4,654				6,235				4,654	6,235	4,872
Capital investments									899	1,138	1,231
Restructuring charges									16	11	37
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									2,145	2,850	3,745
Depreciation, depletion and amortization expense									9	9
Impairments									0	3	155
Operating loss									(7)	(13)	4
Interest expense									0	0	0
Gain (loss) on derivatives									0	0	0
Gain (Loss) on Early Extinguishment of Debt									0	0	0
Other income, net									0	0	(2)
Provision (benefit) for income taxes									0	0	0
Assets	381				314				381	314	539
Capital investments									0	0	9
Restructuring charges											2
Operating Segments | Marketing | Non Core Gathering Assets
Segment Reporting Information [Line Items]
Impairments											10
Operating Segments | Marketing | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers									2,145	2,849	3,497
Other
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization expense									0	0	0
Impairments									0	0	1
Operating loss									0	0	(1)
Interest expense									0	0	0
Gain (loss) on derivatives									0	0	0
Gain (Loss) on Early Extinguishment of Debt									35	8	(17)
Other income, net									1	2	0
Provision (benefit) for income taxes									0	0	0
Assets	$ 125				$ 168				125	168	386
Capital investments									$ 0	$ 2	$ 8

Segment Information (Schedule o

Segment Information (Schedule of Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Cash and cash equivalents	$ 13	$ 5
Current hedging asset	241	278
Property plant and equipment	4,111	5,267
Unamortized debt expense	20	19
Operating lease assets	163	159
TOTAL ASSETS	5,160	6,717	$ 5,797
Other
Segment Reporting Information [Line Items]
Cash and cash equivalents	13	5	205
Accounts receivable	1	0	4
Income taxes receivable	0	30	89
Current hedging asset	0	0	1
Prepayments	6	8	8
Property plant and equipment	16	27	60
Unamortized debt expense	11	11	11
Operating lease assets	72	80
Non-qualified retirement plan	6	7	8
TOTAL ASSETS	$ 125	$ 168	$ 386

Supplemental Quarterly Result_3

Supplemental Quarterly Results (Unaudited) (Schedule of Quarterly Financial Inform) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Quarterly Financial Data [Abstract]
Operating revenues	$ 779	$ 527	$ 410	$ 592	$ 745	$ 636	$ 667	$ 990	$ 2,308	$ 3,038	$ 3,862
Operating loss	(244)	(381)	(756)	(1,490)	64	(29)	22	213	(2,871)	270	797
Net (loss) income	$ (92)	$ (593)	$ (880)	$ (1,547)	$ 110	$ 49	$ 138	$ 594	$ (3,112)	$ 891	$ 535
(Loss) earnings per share - basic (in dollars per share)	$ (0.14)	$ (1.04)	$ (1.63)	$ (2.86)	$ 0.20	$ 0.09	$ 0.26	$ 1.10	$ (5.42)	$ 1.65	$ 0.93
(Loss) earnings per share - diluted (in dollars per share)	$ (0.14)	$ (1.04)	$ (1.63)	$ (2.86)	$ 0.20	$ 0.09	$ 0.26	$ 1.10	$ (5.42)	$ 1.65	$ 0.93

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures (Unaudited) (Narrative) (Details) Mcfe in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)Mcfelocation	Dec. 31, 2019USD ($)Mcfelocation	Dec. 31, 2018USD ($)Mcfelocation	Dec. 31, 2017Mcfe
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	$ 1,472	$ 1,506
Capitalized interest	188
Capitalized interest based on weighted average cost of borrowings	88	109	$ 115
Capitalized internal costs related to acquisition, exploration and development	$ 56	$ 77	$ 90
Percentage of present worth of proved reserves evaluated in audit	97.00%	99.00%	99.00%
Proved reserves, end of period, (bcfe) | Mcfe	11,990	12,721	11,921	14,775
Proved undeveloped reverses (energy) | Mcfe	2,437	929	190
Number of locations | location	138	90	30
Present value of proved reserves, discounted basis	$ 207	$ 50	$ 24
Proved reserves, committed development period	5 years
Montage Resources Corporation
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	$ 88
Undeveloped Properties Southwest Appalachia
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	1,100
Undeveloped Properties Northeast Appalachia
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	6
Wells In Progress
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	61
Capitalized interest	$ 188
United States
Natural Gas and Oil Properties [Line Items]
Proved reserves, end of period, (bcfe) | Mcfe	11,990	12,721	11,921	14,775
Proved undeveloped reverses (energy) | Mcfe	3,787	6,300	6,364

Supplemental Oil and Gas Disc_4

Supplemental Oil and Gas Disclosures (Unaudited) (Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved properties	$ 25,789	$ 23,744
Unproved properties	1,472	1,506
Total capitalized costs	27,261	25,250
Less: Accumulated depreciation, depletion and amortization	(23,362)	(20,203)
Net capitalized costs	$ 3,899	$ 5,047

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures (Unaudited) (Composition of Net Unevaluated Costs Excluded from Amortization) (Details) - USD ($) $ in Millions	12 Months Ended			168 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost [Abstract]
Property acquisition costs	$ 116	$ 44	$ 34	$ 1,022
Exploration and development costs	17	17	14	20
Capitalized interest	62	47	33	46
Net unevaluated costs excluded from amortization	195	108	$ 81	$ 1,088
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Property acquisition costs	1,216
Exploration and development costs	68
Capitalized interest	188
Net unevaluated costs excluded from amortization, cumulative	$ 1,472	$ 1,506

Supplemental Oil and Gas Disc_6

Supplemental Oil and Gas Disclosures (Unaudited) (Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)$ / Mcfe	Dec. 31, 2019USD ($)$ / Mcfe	Dec. 31, 2018USD ($)$ / Mcfe
Natural Gas and Oil Properties [Line Items]
Unproved property acquisition costs	$ 124	$ 162	$ 164
Exploration costs	0	2	5
Development costs	784	936	1,014
Capitalized costs incurred	$ 908	$ 1,100	$ 1,183
Full cost pool amortization per Mcfe | $ / Mcfe	0.38	0.56	0.51
Montage Resources Corporation
Natural Gas and Oil Properties [Line Items]
Unproved property acquisition costs	$ 90

Supplemental Oil and Gas Disc_7

Supplemental Oil and Gas Disclosures (Unaudited) (Results of Operations for Oil and Gas Producing Activities Disclosure) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Sales	$ 1,348	$ 1,703	$ 2,525
Production (lifting) costs	(866)	(781)	(974)
Depreciation, depletion and amortization	(348)	(462)	(514)
Impairment of natural gas and oil properties	(2,825)	0	0
Results of operations - income before income taxes	(2,691)	460	1,037
Provision for income taxes	0	110	0
Results of operations	(2,691)	$ 350	1,037
Income tax expense (benefit), before valuation allowance	$ (624)		$ 254

Supplemental Oil and Gas Disc_8

Supplemental Oil and Gas Disclosures (Unaudited) (Summary of Changes in Reserves - United States) (Details) Mcfe in Millions, Mcf in Millions	12 Months Ended
	Dec. 31, 2020McfebblMcf	Dec. 31, 2019McfebblMcf	Dec. 31, 2018McfeMcfbbl	Dec. 31, 2018McfebblMcf	Dec. 31, 2018McfeMcfbbl
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe) | Mcfe	12,721	11,921			14,775
Revisions of previous estimates due to price | Mcfe	(4,370)	(717)			154
Extensions, discoveries and other additions | Mcfe	741	1,195			1,009
Production | Mcfe	(880)	(778)			(946)
Acquisition of reserves in place | Mcfe	2,354	0			0
Disposition of reserves in place | Mcfe	0	(2)			(3,443)
Proved reserves, end of period, (bcfe) | Mcfe	11,990	12,721			11,921
Proved undeveloped reserves:
Proved undeveloped reverses (energy) | Mcfe	2,437	929	190	190	190
United States
Proved Developed and Undeveloped Reserves [Roll Forward]
Acquisition of reserves in place			0	0
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe) | Mcfe	12,721	11,921			14,775
Revisions of previous estimates due to price | Mcfe	(4,370)	(717)			154
Revisions of previous estimates other than price | Mcfe	1,424	1,102			372
Extensions, discoveries and other additions | Mcfe	741	1,195			1,009
Production | Mcfe	(880)	(778)			(946)
Acquisition of reserves in place | Mcfe	2,354	0			0
Disposition of reserves in place | Mcfe	0	(2)			(3,443)
Proved reserves, end of period, (bcfe) | Mcfe	11,990	12,721			11,921
Proved developed reserves as of:
Proved developed reserves (energy) | Mcfe	8,203	6,421	5,557	5,557	5,557
Proved undeveloped reserves:
Proved undeveloped reverses (energy) | Mcfe	3,787	6,300	6,364	6,364	6,364
United States | Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of year | Mcf	8,630	8,044	11,126
Revisions of previous estimates due to price | Mcf	(2,143)	(480)	96
Revisions of previous estimates other than price | Mcf	763	685	316
Extensions, discoveries and other additions | Mcf	714	992	753
Production | Mcf	(694)	(609)	(807)
Acquisition of reserves in place | Mcf	1,911	0
Disposition of reserves in place | Mcf	0	(2)	(3,440)
Proved reserves, end of year | Mcf	9,181	8,630	8,044
Proved developed reserves as of:
Proved developed reserves (volume) | Mcf	6,342	4,906	4,395	4,395	4,395
Proved undeveloped reserves:
Proved undeveloped reserves (volume) | Mcf	2,839	3,724	3,649	3,649	3,649
United States | Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of year	72,925,000	69,007,000		65,636,000
Revisions of previous estimates due to price	(32,507,000)	(2,041,000)		788,000
Revisions of previous estimates other than price	3,816,000	3,707,000		410,000
Extensions, discoveries and other additions	135,000	6,948,000		5,830,000
Production	(5,141,000)	(4,696,000)		(3,407,000)
Acquisition of reserves in place	18,796,000	0
Disposition of reserves in place	0	0		(250,000)
Proved reserves, end of year	58,024,000	72,925,000		69,007,000
Proved developed reserves as of:
Proved developed reserves (volume)	33,563,000	26,124,000	18,037,000	18,037,000	18,037,000
Proved undeveloped reserves:
Proved undeveloped reserves (volume)	24,461,000	46,801,000	50,970,000	50,970,000	50,970,000
United States | NGL
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of year	608,761,000	577,063,000		542,455,000
Revisions of previous estimates due to price	(338,639,000)	(37,492,000)		8,912,000
Revisions of previous estimates other than price	106,444,000	65,869,000		8,855,000
Extensions, discoveries and other additions	4,371,000	26,941,000		36,823,000
Production	(25,927,000)	(23,620,000)		(19,706,000)
Acquisition of reserves in place	55,141,000	0
Disposition of reserves in place	0	0		(276,000)
Proved reserves, end of year	410,151,000	608,761,000		577,063,000
Proved developed reserves as of:
Proved developed reserves (volume)	276,548,000	226,271,000	175,480,000	175,480,000	175,480,000
Proved undeveloped reserves:
Proved undeveloped reserves (volume)	133,603,000	382,490,000	401,583,000	401,583,000	401,583,000

Supplemental Oil and Gas Disc_9

Supplemental Oil and Gas Disclosures (Unaudited) (Summary of Changes in Reserves) (Details) - Mcfe Mcfe in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	12,721	11,921	14,775
Net revisions
Price revisions	(4,370)	(717)	154
Performance and production revisions	1,424	1,102	372
Total net revisions	(2,946)	385	526
Extensions, discoveries and other additions
Proved developed	267	191	177
Proved undeveloped	474	1,004	832
Total reserve additions	741	1,195	1,009
Production	(880)	(778)	(946)
Acquisition of reserves in place	2,354	0	0
Disposition of reserves in place	0	(2)	(3,443)
Proved reserves, end of period, (bcfe)	12,721	11,921	14,775	11,990	12,721
Proved and unproved reserves reclassified					109
Northeast Appalachia
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	4,837	4,366	4,126
Net revisions
Price revisions	(389)	(57)	41
Performance and production revisions	46	127	107
Total net revisions	(343)	70	148
Extensions, discoveries and other additions
Proved developed	198	185	154
Proved undeveloped	474	677	397
Total reserve additions	672	862	551
Production	(473)	(459)	(459)
Acquisition of reserves in place	223	0	0
Disposition of reserves in place	0	(2)	0
Proved reserves, end of period, (bcfe)	4,837	4,366	4,126	4,916	4,837
Southwest Appalachia
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	7,883	7,554	6,962
Net revisions
Price revisions	(3,981)	(660)	106
Performance and production revisions	1,378	975	272
Total net revisions	(2,603)	315	378
Extensions, discoveries and other additions
Proved developed	69	6	22
Proved undeveloped	0	327	435
Total reserve additions	69	333	457
Production	(407)	(319)	(243)
Acquisition of reserves in place	2,131	0	0
Disposition of reserves in place	0	0	0
Proved reserves, end of period, (bcfe)	7,883	7,554	6,962	7,073	7,883
Fayetteville Shale
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	0	0	3,679
Net revisions
Price revisions	0	0	6
Performance and production revisions	0	0	(6)
Total net revisions	0	0	0
Extensions, discoveries and other additions
Proved developed	0	0	1
Proved undeveloped	0	0	0
Total reserve additions	0	0	1
Production	0	0	(243)
Acquisition of reserves in place	0	0	0
Disposition of reserves in place	0	0	(3,437)
Proved reserves, end of period, (bcfe)	0	0	3,679	0	0
Other
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	1	1	8
Net revisions
Price revisions	0	0	1
Performance and production revisions	0	0	(1)
Total net revisions	0	0	0
Extensions, discoveries and other additions
Proved developed	0	0	0
Proved undeveloped	0	0	0
Total reserve additions	0	0	0
Production	0	0	(1)
Acquisition of reserves in place	0	0	0
Disposition of reserves in place	0	0	(6)
Proved reserves, end of period, (bcfe)	1	1	8	1	1

Supplemental Oil and Gas Dis_10

Supplemental Oil and Gas Disclosures (Unaudited) (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 17,997	$ 27,003	$ 34,523
Future production costs	(11,969)	(14,981)	(15,347)
Future development costs	(1,924)	(3,246)	(4,095)
Future income tax expense	0	(476)	(2,079)
Future net cash flows	4,104	8,300	13,002
10% annual discount for estimated timing of cash flows	(2,257)	(4,600)	(7,003)
Standardized measure of discounted future net cash flows	$ 1,847	$ 3,700	$ 5,999	$ 5,562

Supplemental Oil and Gas Dis_11

Supplemental Oil and Gas Disclosures (Unaudited) (Schedule of Prices Used for Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure) (Details)	12 Months Ended
	Dec. 31, 2020$ / bbl$ / MMBTU	Dec. 31, 2019$ / bbl$ / MMBTU	Dec. 31, 2018$ / bbl$ / MMBTU
Natural Gas
Reserve Quantities [Line Items]
Average sales price ($ per unit) | $ / MMBTU	1.98	2.58	3.10
Oil
Reserve Quantities [Line Items]
Average sales price ($ per unit)	39.57	55.69	65.56
NGL
Reserve Quantities [Line Items]
Average sales price ($ per unit)	10.27	11.58	17.64

Supplemental Oil and Gas Dis_12

Supplemental Oil and Gas Disclosures (Unaudited) (Schedule of Analysis of Changes in Standardized Measure) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 3,700	$ 5,999	$ 5,562
Sales and transfers of natural gas and oil produced, net of production costs	(478)	(923)	(1,564)
Net changes in prices and production costs	(2,720)	(3,510)	2,162
Extensions, discoveries, and other additions, net of future production and development costs	81	234	335
Increase Due to Purchases of Minerals in Place	443	0	0
Sales of reserves in place	0	(2)	(2,022)
Revisions of previous quantity estimates	(987)	152	361
Net change in income taxes	35	491	(304)
Changes in estimated future development costs	1,241	621	(166)
Previously estimated development costs incurred during the year	624	704	536
Changes in production rates (timing) and other	(466)	(718)	521
Accretion of discount	374	652	578
Standardized measure, end of year	$ 1,847	$ 3,700	$ 5,999