Southwestern Energy (SWN) 10-K 1 Mar 22 2021 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2021	Feb. 25, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
Entity File Number	001-08246
Entity Registrant Name	Southwestern Energy Company
Amendment Flag	false
Document Fiscal Year Focus	2021
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			$ 3,815,156,281
Entity Common Stock, Shares Outstanding		1,114,319,444
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement for the 2022 annual meeting of stockholders, to be filed no later than 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates, are incorporated by reference into Part III of this Form 10-K.
Document Transition Report	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Auditor Information [Abstract]
Auditor name	PricewaterhouseCoopers LLP
Auditor location	Houston, Texas
Auditor firm ID	238

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Revenues:
Total operating revenues	$ 6,667	$ 2,308	$ 3,038
Operating Costs and Expenses:
Operating expenses	1,170	813	720
General and administrative expenses	138	121	166
Merger-related expenses	76	41	0
Restructuring charges	7	16	11
Loss on sale of operating assets	0	0	2
Depreciation, depletion and amortization	546	357	471
Impairments	6	2,830	16
Taxes, other than income taxes	132	55	62
Total Operating Costs and Expenses	4,032	5,179	2,768
Operating Income (Loss)	2,635	(2,871)	270
Interest Expense:
Interest on debt	220	171	166
Other interest charges	13	11	8
Interest capitalized	(97)	(88)	(109)
Total Interest Expense	136	94	65
Gain (Loss) on Derivatives	(2,436)	224	274
Gain (Loss) on Early Extinguishment of Debt	(93)	35	8
Other Income (Loss), Net	5	1	(7)
Income (Loss) Before Income Taxes	(25)	(2,705)	480
Provision (Benefit) for Income Taxes:
Current	0	(2)	(2)
Deferred	0	409	(409)
Provision (Benefit) for Income Taxes	0	407	(411)
Net Income (Loss)	$ (25)	$ (3,112)	$ 891
Earnings (Loss) Per Common Share
Basic (in dollars per share)	$ (0.03)	$ (5.42)	$ 1.65
Diluted (in dollars per share)	$ (0.03)	$ (5.42)	$ 1.65
Weighted Average Common Shares Outstanding:
Basic (in shares)	789,657,776	573,889,502	539,345,343
Diluted (in shares)	789,657,776	573,889,502	540,382,914
Gas sales
Operating Revenues:
Total operating revenues	$ 3,412	$ 967	$ 1,241
Oil sales
Operating Revenues:
Total operating revenues	394	154	223
NGL sales
Operating Revenues:
Total operating revenues	890	265	274
Marketing
Operating Revenues:
Total operating revenues	1,963	917	1,297
Operating Costs and Expenses:
Marketing purchases	1,957	946	1,320
Other
Operating Revenues:
Total operating revenues	$ 8	$ 5	$ 3

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ (25)	$ (3,112)	$ 891
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	[1]	2	3	8
Net actuarial loss incurred in period		11	(8)	(5)
Total change in value of pension and postretirement liabilities		13	(5)	3
Comprehensive income (loss)		$ (12)	$ (3,117)	$ 894
[1]	$0.4 million and $2 million in tax effects for the years ended December 31, 2021 and 2019, respectively, which were netted against a valuation allowance and therefore included in accumulated other comprehensive income. The year ended December 31, 2020 is presented net of $1 million in taxes.

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	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	$ 0.4	$ 1	$ 2
Net gain (loss) incurred in period, tax	$ 2.7	$ (2)	$ (1)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 28	$ 13
Accounts receivable, net	1,160	368
Derivative assets	183	241
Other current assets	42	49
Total current assets	1,413	671
Oil and Gas Property, Full Cost Method, Gross	33,631	27,261
Other	509	523
Less: Accumulated depreciation, depletion and amortization	(24,202)	(23,673)
Total property and equipment, net	9,938	4,111
Operating lease assets	187	163
Long-term derivative assets	226	146
Deferred tax assets	0	0
Other long-term assets	84	69
Total long-term assets	497	378
TOTAL ASSETS	11,848	5,160
Current liabilities:
Current portion of long-term debt	206	0
Accounts payable	1,282	573
Taxes payable	93	74
Interest payable	75	58
Derivative liabilities	1,279	245
Current operating lease liabilities	42	42
Other current liabilities	75	20
Total current liabilities	3,052	1,012
Long-term debt	5,201	3,150
Long-term operating lease liabilities	142	117
Long-term derivative liabilities	632	183
Pension and other postretirement liabilities	23	45
Other long-term liabilities	251	156
Total long-term liabilities	6,249	3,651
Commitments and contingencies (Note 10)
Equity:
Common stock, $0.01 par value; 2,500,000,000 shares authorized; issued 1,158,672,666 shares as of December 31, 2021 and 718,795,700 as of December 31, 2020	12	7
Additional paid-in capital	7,150	5,093
Accumulated deficit	(4,388)	(4,363)
Accumulated other comprehensive loss	(25)	(38)
Common stock in treasury, 44,353,224 shares as of December 31, 2021 and 2020	(202)	(202)
Total equity	2,547	497
TOTAL LIABILITIES AND EQUITY	$ 11,848	$ 5,160

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Net unevaluated costs excluded from amortization, cumulative	$ 2,231	$ 1,472
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	2,500,000,000	2,500,000,000
Common stock, shares issued (in shares)	1,158,672,666	718,795,700
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows From Operating Activities:
Net income (loss)	$ (25)	$ (3,112)	$ 891
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	546	357	471
Amortization of debt issuance costs	9	9	8
Impairments	6	2,830	16
Deferred income taxes	0	409	(409)
(Gain) loss on derivatives, unsettled	944	138	(94)
Stock-based compensation	2	3	8
(Gain) loss on early extinguishment of debt	93	(35)	(8)
Loss on sale of assets	0	0	2
Other	(3)	6	10
Changes in assets and liabilities, net of effect of Mergers:
Accounts receivable	(425)	50	234
Accounts payable	261	(131)	(141)
Taxes payable	(4)	(7)	0
Interest payable	6	(11)	0
Inventories	(3)	2	(7)
Other assets and liabilities	(44)	20	(17)
Net cash provided by operating activities	1,363	528	964
Cash Flows From Investing Activities:
Capital investments	(1,032)	(896)	(1,099)
Proceeds from sale of property and equipment	4	12	54
Cash acquired in mergers	66	3	0
Cash paid in mergers	(1,642)	0	0
Net cash used in investing activities	(2,604)	(881)	(1,045)
Cash Flows From Financing Activities:
Payments on current portion of long-term debt	0	0	(52)
Payments on long-term debt	(1,177)	(72)	(54)
Payments on revolving credit facility	(6,628)	(1,671)	(532)
Borrowings under revolving credit facility	6,388	2,337	566
Change in bank drafts outstanding	5	1	(19)
Repayment of revolving credit facilities associated with Mergers	(176)	(200)	0
Repayment of Montage senior notes	0	(522)	0
Proceeds from issuance of long-term debt	2,900	350	0
Debt issuance and other financing costs	(53)	(10)	(3)
Proceeds from issuance of common stock	0	152	0
Purchase of treasury stock	0	0	(21)
Cash paid for tax withholding	(3)	(4)	(1)
Other	0	0	1
Net cash provided by (used in) financing activities	1,256	361	(115)
Increase (decrease) in cash and cash equivalents	15	8	(196)
Cash and cash equivalents at beginning of year	13	5	201
Cash and cash equivalents at end of year	$ 28	$ 13	$ 5

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Millions	Total	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)	Common Stock in Treasury
Beginning balance (in shares) at Dec. 31, 2018		585,407,107				39,092,537
Beginning 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				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
Merger consideration (in shares)		69,740,848
Merger consideration	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				44,353,224
Ending balance at Dec. 31, 2020	497	$ 7	5,093	(4,363)	(38)	$ (202)
Comprehensive income
Net income (loss)	(25)			(25)
Other comprehensive income	13				13
Comprehensive income (loss)	(12)
Stock-based compensation	2		2
Issuance of restricted stock (in shares)		289,442
Cancellation of restricted stock (in shares)		(405)
Restricted units granted (in shares)		2,184,681
Restricted units granted	8		8
Performance units vested (in shares)		1,001,505
Performance units vested	4		4
Merger consideration (in shares)		437,164,919
Merger consideration	2,051	$ 5	2,046
Tax withholding - stock compensation (in shares)		(763,176)
Tax withholding – stock compensation	(3)		(3)
Ending balance (in shares) at Dec. 31, 2021		1,158,672,666				44,353,224
Ending balance at Dec. 31, 2021	$ 2,547	$ 12	$ 7,150	$ (4,388)	$ (25)	$ (202)

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
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”). 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 as well as associated NGLs and oil, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania, West Virginia, Ohio and Louisiana. The Company’s operations in Pennsylvania, West Virginia and Ohio, herein referred to as “Appalachia,” are primarily focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and liquids reservoirs. The Company’s operations in Louisiana, herein referred to as “Haynesville,” are primarily focused on the Haynesville and Bossier natural gas reservoirs. The Company also operates drilling rigs and provides certain oilfield products and services, principally serving the Company's E&P operations through vertical integration. Marketing. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in its E&P operations. Basis of Presentation The consolidated financial statements included in this Annual Report present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements are issued. The comparability of certain 2021 amounts to prior periods could be impacted as a result of the Montage Merger (as defined below) in November 2020, the Indigo Merger (as defined below) on September 1, 2021, and the GEPH Merger (as defined below) on December 31, 2021. The Company believes the disclosures made are adequate to make the information presented not misleading. 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 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, 2021, 2020 and 2019 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, 2021 one purchaser accounted for 12% of annual 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 a default. For the year ended December 31, 2020, one purchaser accounted for 10% of annual revenues. No other purchasers accounted for more than 10% of consolidated revenues. 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 Company had $28 million and $13 million in cash and cash equivalents as of December 31, 2021 and 2020, respectively. 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 $21 million and $16 million as of December 31, 2021 and 2020, 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. Prices used to calculate the ceiling value of reserves were as follows: For the years ended December 31, 2021 2020 2019 Natural gas (per MMBtu) $ 3.60 $ 1.98 $ 2.58 Oil (per Bbl) $ 66.56 $ 39.57 $ 55.69 NGLs (per Bbl) $ 28.65 $ 10.27 $ 11.58 Using the average quoted prices above, adjusted for market differentials, the net book value of the Company’s United States natural gas and oil properties did not exceed the ceiling amount at December 31, 2021 or 2019. The net book value of its natural gas and oil properties exceeded the ceiling amount in each quarter of 2020 resulting in a total non-cash full cost ceiling test impairment of $2,825 million. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2021, 2020 and 2019. Future decreases in market prices, as well as changes in production rates, levels of reserves, evaluation costs excluded from amortization, future development costs and production costs may result in future non-cash impairments to the Company’s natural gas and oil properties. No impairment expense was recorded in 2020 or 2021 in relation to the Company’s natural gas and oil properties acquired from Montage. These properties were recorded at fair value as of November 13, 2020, in accordance with Accounting Standards Codification (“ASC”) Topic 820 – Fair Value Measurement . In the fourth quarter of 2020, pursuant to SEC guidance, the Company determined that the fair value of the properties acquired at the closing of the Montage 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 Montage 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 could continue to demonstrate that the fair value of properties acquired clearly exceeded the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, the Company was 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 Montage Merger was based on future commodity market pricing for natural gas and oil pricing existing at the date of the Montage Merger, and management affirmed that there has not been a material decline to the fair value of these acquired assets since the Montage Merger. The properties acquired in the Montage Merger had 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. Due to the improvement in commodity prices during 2021, no impairment charge would have been recorded in 2021 had the Montage natural gas and oil properties been included in the full cost ceiling test. 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, 2021, the Company had a total of $2,231 million of costs excluded from the amortization base, all of which related to its properties in the United States. 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, 2021 December 31, 2020 Water facilities $ 237 $ 228 Gathering systems 56 54 Technology infrastructure 135 133 Drilling rigs and equipment 28 26 Land, buildings and leasehold improvements 16 41 Other 37 41 Less: Accumulated depreciation and impairment (319) (311) Total $ 190 $ 212 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, 2021 and 2020 the Company recognized non-cash impairments of $6 million and $5 million, respectively, for 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, 2021 and 2020, the Company had $48 million and $57 million, respectively, in marketing-related intangible assets, of which $43 million and $48 million were included in Other long-term assets on the respective consolidated balance sheets. The Company amortized $8 million of its marketing-related intangible asset in December 31, 2021 and $9 million in each of the years ended December 31, 2020 and 2019, and expects to amortize $5 million in 2022 and 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, 2021. 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 2039. 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 Cuts and Jobs 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. On December 31, 2021, the Company issued 99,337,748 shares of its common stock in conjunction with the GEPH Merger. These shares of the Company’s common stock had an aggregate dollar value equal to approximately $463 million, based on the closing price of $4.66 per share of its common stock on the NYSE on December 31, 2021. See Note 2 for additional details on the GEPH Merger. In September 2021, the Company issued 337,827,171 shares of its common stock in conjunction with the Indigo Merger. These shares of the Company’s common stock had an aggregate dollar value equal to approximately $1,588 million, based on the closing price of $4.70 per share of its common stock on the NYSE on September 1, 2021. See Note 2 for additional details on the Indigo Merger. 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 Montage 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 consideration. See Note 2 for additional details on the Montage Merger. 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 2 for additional details regarding the Company's use of proceeds from the equity offering. As part of a share repurchase program, the Company 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, 2021, 2020 and 2019: For the years ended December 31, (in millions, except share/per share amounts) 2021 2020 2019 Net income (loss) $ (25) $ (3,112) $ 891 Number of common shares: Weighted average outstanding 789,657,776 573,889,502 539,345,343 Issued upon assumed exercise of outstanding stock options — — — Effect of issuance of non-vested restricted common stock — — 361,380 Effect of issuance of non-vested restricted units — — — Effect of issuance of non-vested performance units — — 676,191 Weighted average and potential dilutive outstanding 789,657,776 573,889,502 540,382,914 Earnings (loss) per common share: Basic $ (0.03) $ (5.42) $ 1.65 Diluted $ (0.03) $ (5.42) $ 1.65 The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2021, 2020 and 2019, as they would have had an antidilutive effect: For the years ended December 31, 2021 2020 2019 Unexercised stock options 3,683,363 4,427,040 5,078,253 Unvested share-based payment 832,989 962,662 1,728,264 Restricted units 2,226,981 4,452,876 — Performance units 2,194,477 2,818,653 271,268 Total 8,937,810 12,661,231 7,077,785 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, 2021, 2020 and 2019: For the years ended December 31, (in millions) 2021 2020 2019 Cash paid during the year for interest, net of amounts capitalized $ 106 $ 75 $ 58 Cash paid (received) during the year for income taxes — (1) (32) (52) Non-cash investing activities 3,690 (2) 1,084 (3) 41 Non-cash financing activities 2,051 (4) 213 (5) — (1) Cash received in 2021 for income taxes was immaterial. (2) Includes $3,039 million and $575 million in non-cash property additions related to the Indigo Merger and the GEPH Merger, respectively. (3) Includes $1,097 million in non-cash additions related to the Montage Merger. (4) Includes $1,588 million and $463 million in common stock consideration related to the Indigo Merger and the GEPH Merger, respectively. (5) Common stock consideration 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. In 2021, two types of performance unit awards were granted. One type of award includes a performance condition based on return on capital employed and a performance condition based on a reinvestment rate, and the second type of award includes one 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, 2021 and 2020, 2,035 shares and 3,632 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 Financial Accounting Standards Board (the “FASB”) issued ASU 2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU 2018-14 amends, adds and removes certain disclosure requirements under FASB Accounting Standards Codification (“ASC”) Topic 715 – Compensation – Retirement Benefits. The guidance in ASU 2018-14 is effective for fiscal years beginning after December 15, 2020 and was adopted on January 1, 2021. Adoption of ASU 2018-14 resulted in certain disclosure changes within the Company's footnote disclosures. The adoption of ASU 2018-14 did not have a material impact on the Company's consolidated financial statements. Refer to Pension Plan and Other Postretirement Benefits footnote. In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. ASU 2019-12 eliminates certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard became effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company adopted the new standard on January 1, 2021 on a prospective basis, which did not have a material impact on its consolidated financial statements. New Accounting Standards Not Yet Adopted in this Report In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform, as a new 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 was 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 USD-LIBOR settings are expected to be published through June 2023 and Southwestern will use a variation of this rate until the underlying agreements are extended beyond the LIBOR publication date. The standard was adopted on January 1, 2022 and did not have a significant impact on Southwestern’s consolidated financial statements upon adoption.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Acquisitions and Divestitures	ACQUISITIONS AND DIVESTITURES GEP Haynesville, LLC Merger On November 3, 2021, Southwestern entered into an Agreement and Plan of Merger with Mustang Acquisition Company, LLC (“Mustang”), GEP Haynesville, LLC (“GEPH”) and GEPH Unitholder Rep, LLC (the “GEPH Merger Agreement”). Pursuant to the terms of the GEPH Merger Agreement, GEPH merged with and into Mustang, a subsidiary of Southwestern, and became a wholly-owned subsidiary of Southwestern (the “GEPH Merger”). The GEPH Merger closed on December 31, 2021 and expanded the Company’s operations in the Haynesville. Under the terms and conditions of the GEPH Merger Agreement, the outstanding equity interests in GEPH were cancelled and converted into the right to receive $1,269 million in cash consideration and 99,337,748 shares of Southwestern common stock. These shares of Southwestern common stock had an aggregate dollar value equal to approximately $463 million, based on the closing price of $4.66 per share of Southwestern common stock on the NYSE on December 31, 2021. In addition, the Company assumed GEPH’s revolving line of credit balance of $81 million as of December 31, 2021. This balance was subsequently repaid, and the GEPH revolving line of credit was retired on December 31, 2021. See Note 1 and Note 9 for additional information. The GEPH Merger constituted a business combination, and was accounted for using the acquisition method of accounting. For tax purposes, the GEPH Merger was treated as a sale of partnership interests and an acquisition of assets. The following table presents the fair value of consideration transferred to GEPH equity holders as a result of the GEPH Merger: (in millions, except share, per share amounts) As of December 31, 2021 Shares of Southwestern common stock issued 99,337,748 NYSE closing price per share of Southwestern common shares on December 31, 2021 $ 4.66 $ 463 Cash consideration 1,269 Total consideration $ 1,732 The following table sets forth the preliminary fair value of the assets acquired and liabilities assumed as of the acquisition date. Certain data and studies necessary to complete the purchase price allocation are still under evaluation, including, but not limited to, the final actualization of accrued liabilities and receivable balances and the valuation of natural gas and oil properties. The Company will finalize the purchase price allocation during the twelve-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate. (in millions) As of December 31, 2021 Consideration: Total consideration $ 1,732 Fair Value of Assets Acquired: Cash and cash equivalents 11 Accounts receivable 171 Other current assets 3 Commodity derivative assets 56 Evaluated oil and gas properties 1,783 Unevaluated oil and gas properties 59 Other property, plant and equipment 2 Other long-term assets 3 Total assets acquired 2,088 Fair Value of Liabilities Assumed: Accounts payable 170 Other current liabilities 1 Derivative liabilities 75 Revolving credit facility 81 Asset retirement obligations 24 Other noncurrent liabilities 5 Total liabilities assumed 356 Net Assets Acquired and Liabilities Assumed $ 1,732 The assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the GEPH Merger. Acquired working capital amounts are expected to approximate fair value due to their short-term nature. 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. With the completion of the GEPH Merger, Southwestern acquired proved and unproved properties of approximately $1,783 million and $59 million, respectively, primarily associated with the Haynesville and Bossier formations. The remaining $2 million in Other property, plant and equipment consists of land, facilities and various equipment. The income approach was utilized for unevaluated and evaluated oil and gas properties based on underlying reserve projections at the GEPH 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. The Company considered the borrowings under the revolving credit facility to approximate fair value as the balance on the GEPH revolving credit facility was immediately paid off after the GEPH Merger close. The value of derivative instruments was based on observable inputs, primarily forward commodity-price curves, and is considered Level 2. Since the date of the GEPH Merger occurred on December 31, 2021, there were no revenues or operating income associated with the operations acquired recorded in the Company’s consolidated statements of operations for the year ended December 31, 2021. Indigo Natural Resources Merger On June 1, 2021, Southwestern entered into an Agreement and Plan of Merger with Ikon Acquisition Company, LLC (“Ikon”), Indigo Natural Resources LLC (“Indigo”) and Ibis Unitholder Representative LLC (the “Indigo Merger Agreement”). Pursuant to the terms of the Indigo Merger Agreement, Indigo merged with and into Ikon, a subsidiary of Southwestern, and became a wholly-owned subsidiary of Southwestern (the “Indigo Merger”). On August 27, 2021, Southwestern’s stockholders voted to approve the Indigo Merger and the transaction closed on September 1, 2021. The Indigo Merger established Southwestern’s natural gas operations in the Haynesville and Bossier Shales. The outstanding equity interests in Indigo were cancelled and converted into the right to receive (i) $373 million in cash consideration, subject to adjustment as provided in the Indigo Merger Agreement, and (ii) 337,827,171 shares of Southwestern common stock. These shares of Southwestern common stock had an aggregate dollar value equal to approximately $1,588 million, based on the closing price of $4.70 per share of Southwestern common stock on the NYSE on September 1, 2021. Additionally, Southwestern assumed $700 million in aggregate principal amount of Indigo’s 5.375% Senior Notes due 2029 (the “Indigo Notes”) with a fair value of $726 million as of September 1, 2021, which were subsequently exchanged for $700 million of newly issued 5.375% Senior Notes due 2029. In addition, the Company assumed Indigo’s revolving line of credit balance of $95 million as of September 1, 2021. This balance was subsequently repaid, and the Indigo revolving line of credit was retired in September 2021. See Note 1 and Note 9 for additional information. The Indigo Merger constituted a business combination, and was accounted for using the acquisition method of accounting. For tax purposes, the Indigo Merger was treated as a sale of partnership interests and an acquisition of assets. The following table presents the fair value of consideration transferred to Indigo equity holders as a result of the Indigo Merger: (in millions, except share, per share amounts) As of September 1, 2021 Shares of Southwestern common stock issued 337,827,171 NYSE closing price per share of Southwestern common shares on September 1, 2021 $ 4.70 $ 1,588 Cash consideration 373 Total consideration $ 1,961 The following table sets forth the preliminary fair value of the assets acquired and liabilities assumed as of the acquisition date. Certain data and studies necessary to complete the purchase price allocation are still under evaluation, including, but not limited to, the valuation of natural gas and oil properties and the resolution of certain matters that the Company is indemnified for under the Indigo Merger Agreement for which not enough information is available to assess the final fair value of at this time. The Company will finalize the purchase price allocation during the twelve-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate. (in millions) As of September 1, 2021 Consideration: Total consideration $ 1,961 Fair Value of Assets Acquired: Cash and cash equivalents 55 Accounts receivable 192 Other current assets 2 Commodity derivative assets 2 Evaluated oil and gas properties 2,724 Unevaluated oil and gas properties (1) 684 Other property, plant and equipment 4 Other long-term assets 27 Total assets acquired 3,690 Fair Value of Liabilities Assumed: Accounts payable (1) 274 Other current liabilities 55 Derivative liabilities 501 Revolving credit facility 95 Senior unsecured notes 726 Asset retirement obligations 8 Other noncurrent liabilities 70 Total liabilities assumed 1,729 Net Assets Acquired and Liabilities Assumed $ 1,961 (1) Reflects an $8 million purchase price adjustment due to ongoing valuation. The assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the Indigo Merger. Acquired working capital amounts are expected to approximate fair value due to their short-term nature. 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. With the completion of the Indigo Merger, Southwestern acquired proved and unproved properties of approximately $2,724 million and $684 million, respectively, primarily associated with the Haynesville and Bossier formations. The remaining $4 million in Other property, plant and equipment consists of land, water facilities and various equipment. The income approach was utilized for unevaluated and evaluated oil and gas properties based on underlying reserve projections at the Indigo 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. The measurement of senior unsecured notes was based on unadjusted quoted prices in an active market and are Level 1. The Company considered the borrowings under the 2018 credit facility to approximate fair value as the outstanding Indigo revolving credit facility was immediately paid off after the Indigo Merger close. The value of derivative instruments was based on observable inputs, primarily forward commodity-price and interest-rate curves and is considered Level 2. From the date of the Indigo Merger through December 31, 2021, revenues and operating income associated with the operations acquired through the Indigo Merger totaled $682 million and $472 million, respectively. Prior to the Indigo Merger, in May 2021, Indigo closed on an agreement to divest its Cotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which Southwestern will assume the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the buyer’s actual use. As of December 31, 2021, up to approximately $36 million of these contractual commitments remain, and the Company has recorded a $17 million liability for the estimated future payments. Excluding the Cotton Valley gathering agreement (discussed above), the Company has recorded additional liabilities totaling $74 million as of December 31, 2021, primarily related to purchase or volume commitments associated with gathering, fresh water and sand. These amounts will be recognized as payments are made over a period ranging from two Montage Resources Merger In August 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 “Montage Merger”). On November 12, 2020, Montage’s stockholders voted to approve the Montage Merger and it was made effective on November 13, 2020. The Montage 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. In anticipation of the Montage 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 2018 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 Montage Merger. See Note 1 and Note 9 for additional information. The Montage 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 Montage 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 The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation is complete as of the fourth quarter of 2021. (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 (1) 100 Other property, plant and equipment 28 Other long-term assets 26 Total assets acquired 1,254 Fair value of liabilities assumed: Accounts payable (1) 155 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 1,041 Net assets acquired and liabilities assumed $ 213 (1) Reflects a $10 million purchase price adjustment due to completion of valuation assessments during the measurement period. The assets acquired and liabilities assumed were recorded at their fair values at the date of the Montage Merger. The valuation of certain assets, including property, are based on appraisals. The fair value of acquired equipment is based on both available market data and a cost approach. With the completion of the Montage Merger, Southwestern acquired proved and unproved properties of approximately $1,012 million and $100 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. Unevaluated oil and gas properties were valued primarily using a market approach based on comparable transactions for similar properties. The income approach was utilized for proved oil and gas properties based on underlying reserve projections at the Montage 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 2018 credit facility to approximate fair value as the outstanding Montage revolving credit facility was immediately paid off after the Montage Merger closed. The value of derivative instruments was based on observable inputs, primarily forward commodity-price and interest-rate curves and is considered Level 2. From the date of the Montage Merger through December 31, 2020, revenues and the net income attributable to common stockholders associated with the operations acquired through the Montage Merger totaled $63 million and $28 million, respectively. Pro Forma Information The following table summarizes the unaudited pro forma condensed financial information of Southwestern as if the Montage Merger had occurred on January 1, 2019, and the Indigo Merger and the GEPH Merger each had occurred on January 1, 2020: For the years ended December 31, (in millions, except per share amounts) 2021 (1) 2020 2019 Revenues $ 8,301 $ 3,836 $ 3,673 Net income (loss) attributable to common stock $ (354) $ (3,243) $ 995 Net income (loss) attributable to common stock per share – basic $ (0.32) $ (2.92) $ 1.48 Net income (loss) attributable to common stock per share – diluted $ (0.32) $ (2.92) $ 1.48 (1) The year ended December 31, 2021 includes the actual operating results from the Montage Merger, which occurred in November 2020. The unaudited pro forma information is not necessarily indicative of the operating results that would have occurred had the Montage Merger been completed at January 1, 2019, and the Indigo Merger and the GEPH Merger each been completed at January 1, 2020, nor is it necessarily indicative of future operating results of the combined entities. The unaudited pro forma information gives effect to the Mergers and any related equity and debt issuances, along with the use of proceeds therefrom, as if they had occurred on the respective dates discussed above and is a result of combining the statements of operations of Southwestern with the pre-merger results of Montage, Indigo and GEPH, including adjustments for revenues and direct expenses. The pro forma results exclude any cost savings anticipated as a result of the Mergers, and 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 any retirement of assumed senior notes, credit facilities, all related accrued interest and the associated decrease in amortization of issuance costs related to notes retired and revolving lines of credit. These decreases were partially offset by increases in interest on debt associated with the issuance of $350 million in 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. Interest expense was also adjusted to include the impact of the assumption and exchange of Indigo’s $700 million of 5.375% Senior Notes due 2029 for equivalent Southwestern senior notes and to reflect the retirement of the Montage, Indigo and GEPH credit facilities, all related accrued interest and the associated decreases in amortization of issuance costs related to the respective revolving lines of credit. Management believes the estimates and assumptions are reasonable, and the relative effects of the three Mergers are properly reflected. Merger-Related Expenses The following table summarizes the merger-related expenses incurred for the years ended December 31, 2021 and 2020: For the years ended December 31, 2021 2020 (in millions) Indigo GEPH Montage Total Montage Professional fees (bank, legal, consulting) $ 27 $ 19 $ 1 $ 47 $ 18 Representation & warranty insurance 4 7 — 11 — Contract buyouts, terminations and transfers 7 1 — 8 5 Due diligence and environmental 3 1 — 4 — Employee-related 2 — 1 3 17 Other 2 — 1 3 1 Total merger-related expenses $ 45 $ 28 $ 3 $ 76 $ 41 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.

Restructuring Charges

Restructuring Charges	12 Months Ended
	Dec. 31, 2021
Restructuring and Related Activities [Abstract]
Restructuring Charges	RESTRUCTURING CHARGESAs part of a strategic effort to reposition its portfolio, optimize operational performance and improve margins, the Company incurred charges in recent years 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 in December 2018. 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, 2021, 2020 and 2019: For the years ended December 31, (in millions) 2021 2020 2019 Severance (including payroll taxes) $ 7 $ 16 $ 5 Office consolidation — — 6 Total restructuring charges (1) $ 7 $ 16 $ 11 (1) All restructuring charges were recorded on the Company's E&P segment for all years presented. On February 24, 2021, the Company notified employees of a workforce reduction plan as part of an ongoing strategic effort to reposition its portfolio, optimize operational performance and improve margins. 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, 2021, and were substantially complete by the end of the first quarter of 2021. 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. 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. 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 for the year ended December 31, 2019. In July 2019, the Company terminated its existing lease agreement in its headquarters office building and entered into a new 10 years 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 liabilities associated with the Company’s restructuring activities at December 31, 2021, which are reflected in accounts payable on the consolidated balance sheet: (in millions) Liability at December 31, 2020 $ 3 Additions 7 Distributions (10) Liability at December 31, 2021 $ —

Leases

Leases	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Leases	LEASES As part of the Indigo Merger, the Company acquired $4 million of operating right of use assets and corresponding lease liabilities which were recognized as part of the Company’s acquisition accounting in the third quarter of 2021. The Company also acquired $2 million of operating right of use assets and corresponding lease liabilities related to the GEPH Merger of which $1 million had already commenced and was reflected on the balance sheet as of December 31, 2021. The GEPH Merger closed during the fourth quarter of 2021. The Company’s variable lease costs are primarily comprised of variable operating charges incurred in connection with its headquarters lease. The variable lease costs 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) 2021 2020 2019 Operating lease cost $ 54 $ 48 $ 45 Short-term lease cost 15 35 45 Variable lease cost 3 3 1 Total lease cost $ 72 $ 86 $ 91 As of December 31, 2021, the Company had operating leases of $13 million, related primarily to compressor leases, which have been executed but not yet commenced. These operating leases are planned to commence during 2022 with lease terms expiring through 2025. 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) 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 53 $ 47 $ 47 Right-of-use assets obtained in exchange for operating liabilities: Operating leases $ 73 $ 48 $ 95 Supplemental balance sheet information related to leases is as follows: (in millions) December 31, 2021 December 31, 2020 Right-of-use asset balance: Operating leases $ 187 $ 163 Lease liability balance: Current operating leases $ 42 $ 42 Long-term operating leases 142 117 Total operating leases $ 184 $ 159 Weighted average remaining lease term: (years) Operating leases 5.5 5.6 Weighted average discount rate: Operating leases 6.77 % 5.97 % Maturity analysis of operating lease liabilities: (in millions) December 31, 2021 2022 $ 53 2023 42 2024 31 2025 28 2026 25 Thereafter 42 Total undiscounted lease liability 221 Imputed interest (37) Total discounted lease liability $ 184

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Revenue Recognition	REVENUE RECOGNITION 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. 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, 2021 Gas sales $ 3,358 $ — $ 54 $ 3,412 Oil sales 389 — 5 394 NGL sales 888 — 2 890 Marketing — 6,186 (4,223) 1,963 Other (1) 5 3 — 8 Total $ 4,640 $ 6,189 $ (4,162) $ 6,667 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 (1) Other E&P revenues consists primarily of gas balancing and water sales to third-party operators, and other marketing revenues consists primarily of sales of gas from storage. 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 Appalachia and Haynesville. For the years ended December 31, (in millions) 2021 2020 2019 Appalachia $ 3,955 $ 1,348 $ 1,700 Haynesville 682 — — Other 3 — 3 Total $ 4,640 $ 1,348 $ 1,703 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, 2021 December 31, 2020 Receivables from contracts with customers $ 1,085 $ 350 Other accounts receivable 75 18 Total accounts receivable $ 1,160 $ 368 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, 2021 and 2020. 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, 2021
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, 2021, 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 price 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 that, 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 stated terms of the contract, and receives a payment from the counterparty if the price differential is less than the stated terms of the contract. Options (Calls and Puts) The Company purchases and sells options in exchange for premiums. 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 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 purchases a put option, the Company receives from the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party. If the Company sells a put option, the Company pays the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’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, 2021: Financial Protection on Production Weighted Average Price per MMBtu Fair value at December 31, 2021 ($ in millions) Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Natural Gas 2022 Fixed price swaps 806 $ 3.08 $ — $ — $ — $ — $ (486) Two-way costless collars 144 — — 2.71 3.14 — (95) Three-way costless collars 347 — 2.06 2.52 2.94 — (286) Total 1,297 $ (867) 2023 Fixed price swaps 489 $ 3.07 $ — $ — $ — $ — $ (143) Two-way costless collars 219 — — 3.03 3.55 — (19) Three-way costless collars 215 — 2.09 2.54 3.00 — (136) Total 923 $ (298) 2024 Fixed price swaps 224 $ 2.96 $ — $ — $ — $ — $ (39) Two-way costless collars 44 $ — $ — $ 3.07 $ 3.53 $ — 4 Three-way costless collars 11 $ — $ 2.25 $ 2.80 $ 3.54 $ — (5) Total 279 $ (40) Basis swaps 2022 322 $ — $ — $ — $ — $ (0.38) $ 68 2023 200 — — — — (0.45) (1) 2024 46 — — — — (0.71) — 2025 9 — — — — (0.64) 1 Total 577 $ 68 Weighted Average Price per Bbl Fair value at December 31, 2021 ($ in millions) Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Oil 2022 Fixed price swaps 3,203 $ 53.54 $ — $ — $ — $ (60) Three-way costless collars 1,380 — 39.89 50.23 57.05 (23) Total 4,583 $ (83) 2023 Fixed price swaps 846 $ 55.98 $ — $ — $ — $ (8) Three-way costless collars 1,268 — 33.97 45.51 56.12 (18) Total 2,114 $ (26) 2024 Fixed price swaps 54 $ 53.15 $ — $ — $ — $ (1) Weighted Average Price per Bbl Fair value at December 31, 2021 ($ in millions) Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Ethane 2022 Fixed price swaps 5,797 $ 11.37 $ — $ — $ — $ (8) Two-way costless collars 135 — — 7.56 9.66 (1) Total 5,932 $ (9) 2023 Fixed price swaps 432 $ 11.67 $ — $ — $ — $ — Propane 2022 Fixed price swaps 6,369 $ 31.14 $ — $ — $ — $ (76) Three-way costless collars 305 $ — $ 16.80 $ 21.00 31.92 (4) Total 6,674 $ (80) 2023 Fixed price swaps 518 $ 33.62 $ — $ — — $ (1) Normal Butane 2022 Fixed price swaps 1,587 $ 32.86 $ — $ — $ — $ (26) 2023 Fixed price swaps 164 $ 37.84 $ — $ — $ — $ — Natural Gasoline 2022 Fixed price swaps 1,840 $ 52.85 $ — $ — $ — $ (33) 2023 Fixed price swaps 157 $ 58.65 $ — $ — $ — $ (1) Other Derivative Contracts Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2021 ($ in millions) Call Options – Natural Gas (Net) 2022 84 $ 3.01 $ (67) 2023 46 2.94 (33) 2024 9 3.00 (9) Total 139 $ (109) Put Options – Natural Gas 2022 5 $ 2.00 $ — Weighted Average Strike Price per MMBtu Fair value at December 31, 2021 ($ in millions) Storage (1) Volume (Bcf) Swaps Basis Differential 2022 Purchased fixed price swap — $ 2.14 $ — $ — Fixed price swaps 2 2.82 — (1) Basis swaps 1 — (0.57) — Total 3 $ (1) (1) The Company has entered into certain derivatives to protect the value of volumes of natural gas injected into a storage facility that will be withdrawn at a later date. At December 31, 2021, the net fair value of the Company’s financial instruments was a $1,502 million liability, including a net reduction of the liability of $3 million due to a non-performance risk adjustment. See Note 8 for additional details regarding the Company's fair value measurements of its derivative positions. As of December 31, 2021, 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, 2021 and 2020: Derivative Assets Balance Sheet Classification Fair Value (in millions) December 31, 2021 December 31, 2020 Derivatives not designated as hedging instruments: Purchased fixed price swaps – natural gas Derivative assets $ — $ 1 Fixed price swaps – natural gas Derivative assets 79 37 Fixed price swaps – oil Derivative assets — 13 Fixed price swaps – ethane Derivative assets 2 — Fixed price swaps – propane Derivative assets 2 — Fixed price swaps – normal butane Derivative assets 1 — Two-way costless collars – natural gas Derivative assets 9 54 Three-way costless collars – natural gas Derivative assets 12 57 Three-way costless collars – oil Derivative assets 1 15 Basis swaps – natural gas Derivative assets 77 60 Call options – natural gas Derivative assets — 4 Fixed price swaps – natural gas Other long-term assets 64 7 Fixed price swaps – oil Other long-term assets — 2 Two-way costless collars – natural gas Other long-term assets 100 20 Three-way costless collars – natural gas Other long-term assets 37 87 Three-way costless collars – oil Other long-term assets 3 15 Basis swaps – natural gas Other long-term assets 22 15 Interest rate swaps Other long-term assets 2 — Total derivative assets $ 411 $ 387 Derivative Liabilities Balance Sheet Classification Fair Value (in millions) December 31, 2021 December 31, 2020 Derivatives not designated as hedging instruments: Fixed price swaps – natural gas storage Derivative liabilities $ 1 $ — Fixed price swaps – natural gas Derivative liabilities 565 7 Fixed price swaps – oil Derivative liabilities 60 12 Fixed price swaps – ethane Derivative liabilities 10 10 Fixed price swaps – propane Derivative liabilities 78 36 Fixed price swaps – normal butane Derivative liabilities 27 8 Fixed price swaps – natural gasoline Derivative liabilities 33 13 Two-way costless collars – natural gas Derivative liabilities 104 43 Two-way costless collars – oil Derivative liabilities — 1 Two-way costless collars – ethane Derivative liabilities 1 — Three-way costless collars – natural gas Derivative liabilities 298 82 Three-way costless collars – oil Derivative liabilities 24 15 Three-way costless collars – propane Derivative liabilities 4 — Basis swaps – natural gas Derivative liabilities 9 3 Call options – natural gas Derivative liabilities 67 12 Put options – natural gas Derivative liabilities — 1 Swaptions – natural gas Derivative liabilities — 2 Fixed price swaps – natural gas Other long-term liabilities 246 3 Fixed price swaps – oil Other long-term liabilities 9 2 Fixed price swaps – propane Other long-term liabilities 1 2 Fixed price swaps – normal butane Other long-term liabilities — 1 Fixed price swaps – natural gasoline Other long-term liabilities 1 2 Two-way costless collars – natural gas Other long-term liabilities 115 21 Two-way costless collars – oil Other long-term liabilities — — Three-way costless collars – natural gas Other long-term liabilities 178 103 Three-way costless collars – oil Other long-term liabilities 21 15 Basis swaps – natural gas Other long-term liabilities 22 7 Call options – natural gas Other long-term liabilities 42 28 Total derivative liabilities $ 1,916 $ 429 Net Derivative Position As of December 31, 2021 2020 (in millions) Net current derivative liabilities $ (1,098) $ (4) Net long-term derivative liabilities (407) (38) Non-performance risk adjustment 3 1 Net total derivative liabilities $ (1,502) $ (41) 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, 2021 and 2020: 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 2021 2020 (in millions) Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ (1) $ 2 Fixed price swaps – natural gas Gain (Loss) on Derivatives (237) (25) Fixed price swaps – oil Gain (Loss) on Derivatives (70) — Fixed price swaps – ethane Gain (Loss) on Derivatives 2 (21) Fixed price swaps – propane Gain (Loss) on Derivatives (40) (60) Fixed price swaps – normal butane Gain (Loss) on Derivatives (18) (9) Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (18) (15) Two-way costless collars – natural gas Gain (Loss) on Derivatives (83) 10 Two-way costless collars – oil Gain (Loss) on Derivatives 1 (1) Two-way costless collars – propane Gain (Loss) on Derivatives — (1) Three-way costless collars – natural gas Gain (Loss) on Derivatives (375) (78) Three-way costless collars – oil Gain (Loss) on Derivatives (41) 3 Three-way costless collars – propane Gain (Loss) on Derivatives (4) — Basis swaps – natural gas Gain (Loss) on Derivatives 3 59 Call options – natural gas Gain (Loss) on Derivatives (68) (10) Call options – oil Gain (Loss) on Derivatives — 1 Put options – natural gas Gain (Loss) on Derivatives 1 — Swaptions – natural gas Gain (Loss) on Derivatives 2 7 Fixed price swaps – natural gas storage Gain (Loss) on Derivatives (1) (1) Interest rate swaps Gain (Loss) on Derivatives 2 — Total loss on unsettled derivatives $ (945) $ (139) 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 2021 2020 (in millions) Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ 7 $ (3) Purchased fixed price swaps – oil Gain (Loss) on Derivatives 1 — Fixed price swaps – natural gas Gain (Loss) on Derivatives (418) 142 (2) Fixed price swaps – oil Gain (Loss) on Derivatives (86) 65 Fixed price swaps – ethane Gain (Loss) on Derivatives (39) 6 Fixed price swaps – propane Gain (Loss) on Derivatives (173) 18 Fixed price swaps – normal butane Gain (Loss) on Derivatives (53) (2) Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (59) (1) Two-way costless collars – natural gas Gain (Loss) on Derivatives (325) (5) Two-way costless collars – oil Gain (Loss) on Derivatives (4) 17 Two-way costless collars – propane Gain (Loss) on Derivatives — 2 Two-way costless collars – ethane Gain (Loss) on Derivatives (2) — Three-way costless collars – natural gas Gain (Loss) on Derivatives (335) 38 Three-way costless collars – oil Gain (Loss) on Derivatives (29) 9 Basis swaps – natural gas Gain (Loss) on Derivatives 92 76 Call options – natural gas Gain (Loss) on Derivatives (66) — Call options – oil Gain (Loss) on Derivatives (2) — Put options - natural gas Gain (Loss) on Derivatives (2) (3) — Purchased fixed price swaps – natural gas storage Gain (Loss) on Derivatives 2 (1) Fixed price swaps – natural gas storage Gain (Loss) on Derivatives (1) 2 Interest rate swaps Gain (Loss) on Derivatives — (1) Total gain (loss) on settled derivatives $ (1,492) $ 362 (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 swaps 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 put options for the year ended December 31, 2021, which is included in gain (loss) on derivatives on the consolidated statements of operations. Total Gain (Loss) on Derivatives Recognized in Earnings For the years ended 2021 2020 (in millions) Total loss on unsettled derivatives $ (945) $ (139) Total gain (loss) on settled derivatives (1,492) 362 Non-performance risk adjustment 1 1 Total gain (loss) on derivatives $ (2,436) $ 224

Reclassifications from Accumula

Reclassifications from Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Reclassifications from Accumulated Other Comprehensive Income (Loss)	RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) In 2021, 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, 2021: For the year ended December 31, 2021 (in millions) Pension and Other Postretirement Foreign Currency Total Beginning balance, December 31, 2020 $ (24) $ (14) $ (38) Other comprehensive income before reclassifications 11 — 11 Amounts reclassified from other comprehensive income (1) 2 — 2 Net current-period other comprehensive income 13 — 13 Ending balance, December 31, 2021 $ (11) $ (14) $ (25) (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, 2021 Pension and other postretirement: (1) (in millions) Amortization of prior service cost and net loss Other income, net $ 1 Settlement loss Other income, net 1 Provision for income taxes (2) — Total reclassifications for the period Net income $ 2 (1) See Note 13 for additional details regarding the Company’s pension and other postretirement benefit plans. (2) As of December 31, 2021, the Company maintained a tax valuation allowance, therefore there was no tax effect on net income.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 were as follows: December 31, 2021 December 31, 2020 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents $ 28 $ 28 $ 13 $ 13 2018 revolving credit facility due April 2024 460 460 700 700 Term Loan B due 2027 550 550 — — Senior notes (1) 4,430 4,745 2,471 2,609 Derivative instruments, net (1,502) (1,502) (41) (41) (1) Excludes unamortized debt issuance costs and debt discounts. 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. Due to limited trading activity, 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 more actively traded remaining senior notes are considered to be a Level 1 measurement. The carrying values of the borrowings under both the Company's 2018 credit facility (to the extent utilized) and Term Loan approximates fair value because the interest rates are variable and reflective of market rates. The Company considers the fair values of its 2018 credit facility and Term Loan 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, 2021, 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 $3 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, 2021 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 and put options, two-way costless collars, and three-way costless collars (Level 2) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX and OPIS futures index, interest rates, volatility and credit worthiness. 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. Swaptions are valued using a variant of the Black-Scholes model referred to as the Black Swaption model, which uses its own separate volatility inputs. 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, 2021 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 $ — $ — $ — $ — Fixed price swaps — 148 — 148 Two-way costless collars — 109 — 109 Three-way costless collars — 53 — 53 Basis swaps — 99 — 99 Interest rate swaps — 2 — 2 Liabilities: (1) Fixed price swaps — (1,031) — (1,031) Two-way costless collars — (220) — (220) Three-way costless collars — (525) — (525) Basis swaps — (31) — (31) Call options — (109) — (109) Put options — — — — Swaptions — — — — Total $ — $ (1,505) $ — $ (1,505) (1) Excludes a net reduction to the liability fair value of $3 million related to estimated non-performance risk. December 31, 2020 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: 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: (1) Fixed price swaps — (96) — (96) Two-way costless collars — (65) — (65) Three-way costless collars — (215) — (215) Basis swaps — (10) — (10) Call options — (40) — (40) Put options — (1) — (1) Swaptions — (2) — (2) Total $ — $ (42) $ — $ (42) (1) Excludes a net reduction to the liability fair value of $1 million related to estimated non-performance risk. 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 The Company completed the Indigo Merger and the GEPH Merger on September 1, 2021 and December 31, 2021, respectively. In November 2020, the Company completed the Montage Merger. See Note 2 for a discussion of the fair value measurement of assets acquired and liabilities assumed. In the third quarter of 2021, the Company determined that the carrying value of certain non-core assets exceeded their respective fair value less costs to sell and recognized a $6 million non-cash impairment. The Company used Level 3 measurements to determine the fair value of these assets. 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.

Debt

Debt	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Debt	DEBT The components of debt as of December 31, 2021 and 2020 consisted of the following: December 31, 2021 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Total Current portion of long-term debt: 4.10% Senior Notes due March 2022 $ 201 $ — $ — $ 201 Variable rate (3.0% at December 31, 2021) Term Loan B due June 2027 $ 5 (1) $ — $ — $ 5 Total current portion of long-term debt $ 206 $ — $ — $ 206 Long-term debt: Variable rate (2.08% at December 31, 2021) 2018 revolving credit facility, due April 2024 $ 460 $ — (2) $ — $ 460 4.95% Senior Notes due January 2025 (3) 389 (1) — 388 Variable rate (3.0% at December 31, 2021) Term Loan B due June 2027 545 (7) (1) 537 7.75% Senior Notes due October 2027 440 (4) — 436 8.375% Senior Notes due September 2028 350 (5) — 345 5.375% Senior Notes due February 2029 700 (6) 25 719 5.375% Senior Notes due March 2030 1,200 (17) — 1,183 4.75% Senior Notes due February 2032 1,150 (17) — 1,133 Total long-term debt $ 5,234 $ (57) $ 24 $ 5,201 Total debt $ 5,440 $ (57) $ 24 $ 5,407 December 31, 2020 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Total Long-term debt: Variable rate (2.11% at December 31, 2020) 2018 revolving credit facility, due April 2024 $ 700 $ — (2) $ — $ 700 4.10% Senior Notes due March 2022 207 — — 207 4.95% Senior Notes due January 2025 (3) 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 (1) The Term Loan requires quarterly principal repayments of $1.375 million, subject to adjustment for voluntary prepayments, beginning in March 2022. (2) At December 31, 2021 and 2020, unamortized issuance expense of $10 million and $12 million, respectively, associated with the 2018 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheet. (3) 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 their issuance. 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 was paid in January 2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded our bond rating to BB+, which will have the effect of decreasing the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022. The following is a summary of scheduled debt maturities by year as of December 31, 2021 and includes the quarterly Term Loan principal repayments of $1.375 million, subject to adjustment for voluntary prepayments, beginning in March 2022: (in millions) 2022 (1) $ 206 2023 6 2024 (2) 465 2025 395 2026 5 Thereafter 4,363 $ 5,440 (1) In January 2022, the remaining $201 million principal balance on the Senior Notes due 2022 was retired using the Company’s 2018 credit facility. (2) The Company’s 2018 credit facility matures in 2024. Credit Facility 2018 Credit Facility In April 2018, the Company entered into a 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, and in October 2021, the banks participating in the 2018 credit facility reaffirmed the elected borrowing base and aggregate commitments to be $2.0 billion. The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and 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. 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 Indigo and GEPH consolidated EBITDAX prior to the respective Mergers 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, 2021, 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, 2021, the Company had $160 million in letters of credit and $460 million in borrowings outstanding under the 2018 credit facility. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts. The Company's exposure to the anticipated transition from LIBOR is limited to the 2018 credit facility. The USD-LIBOR settings are expected to be published through June 2023, and Southwestern anticipates using a variation of this rate until the underlying agreements are extended beyond the LIBOR publication date. Term Loan Credit Agreement On December 22, 2021, the Company entered into a term loan credit agreement with a group of lenders that provided for a $550 million secured term loan facility which matures in June 2027 (the “Term Loan”). As of December 31, 2021, the Company had borrowings under this Term Loan of $550 million. The net proceeds from the initial loans of $542 million were used to fund a portion of the GEPH Merger on December 31, 2021. Beginning on March 31, 2022, the Term Loan will require minimum quarterly payments of $1.375 million, subject to adjustment for voluntary prepayments. The Term Loan is subject to varying rates of interest based on whether the term loan is a term benchmark loan or an alternate base rate loan. Term benchmark loans bear interest at the adjusted term secured overnight financing rate (which includes a credit spread adjustment and is subject to a floor that is 0.50%) plus an applicable margin equal to 2.50%. Alternate base rate loans bear interest at the alternate base rate plus an applicable margin equal to 1.50%. The current borrowings are considered benchmark loans and are carried an interest rate of 3.00% as of December 31, 2021 (0.50% floor plus 2.50% margin). The term loan is subject to a quarterly collateral coverage ratio test in which the Company’s PDP PV-10 value, net of derivative mark-to-market value, must be greater than 2.0x its secured debt commitments or all secured debt becomes callable. If necessary, outstanding secured debt principal can be paid down within 45 days of the end of such fiscal quarter to come into compliance with this ratio, either by (i) prepaying the loans, (ii) prepaying the loans under the 2018 credit facility, (iii) prepaying any other secured indebtedness that is secured by a lien, or some combination thereof. The Company’s obligations under the Term Loan are guaranteed by each of the Company’s subsidiaries that guarantee the obligations under the 2018 credit facility and are secured by liens on substantially all the assets of the Company and the Company’s subsidiaries on an equal basis with the liens securing the obligations under the 2018 credit facility. 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 their issuance. 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 was paid in January 2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which will have the effect of decreasing the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022. 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. 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. In August 2020, the Company completed a public offering of $350 million aggregate principal amount of its 2028 Notes, with net proceeds from the offering totaling approximately $345 million after underwriting discounts and offering expenses. The 2028 Notes were sold to the public at 100% of their face value. The net proceeds from the notes, in conjunction with the net proceeds from the August 2020 common stock offering and borrowings under the 2018 credit facility, were utilized to fund a redemption of $510 million of Montage's Notes in connection with the closing of the Montage Merger. On August 30, 2021, Southwestern closed its public offering of $1,200 million aggregate principal amount of its 5.375% Senior Notes due 2030 (the “2030 Notes”), with net proceeds from the offering totaling $1,183 million after underwriting discounts and offering expenses. The proceeds were used to repurchase the remaining $618 million of the Company’s 7.50% Senior Notes due 2026, $167 million of the Company’s 4.95% Senior Notes due 2025 and $6 million of the Company’s 4.10% Senior Notes due 2022 for $845 million, and the Company recognized a $60 million loss on the extinguishment of debt, which included the write-off of $6 million in related unamortized debt discounts and debt issuance costs. The remaining proceeds were used to pay borrowings under its 2018 credit facility and for general corporate purposes. Upon the close of the Indigo Merger on September 1, 2021, and pursuant to the terms of the Indigo Merger Agreement, Southwestern assumed $700 million in aggregate principal amount of Indigo’s 5.375% Senior Notes due 2029 (“Indigo Notes”). As part of purchase accounting, the assumption of the Indigo Notes resulted in a non-cash fair value adjustment of $26 million, based on the market price of 103.766% on September 1, 2021, the date that the Indigo Merger closed. Subsequent to the Indigo Merger, the Company exchanged the Indigo Notes for approximately $700 million of newly issued 5.375% Senior Notes due 2029, which were registered with the SEC in November 2021. On December 22, 2021, Southwestern closed its public offering of $1,150 million aggregate principal amount of its 4.75% Senior Notes due 2032 (the “2032 Notes”), with net proceeds from the offering totaling $1,133 million after underwriting discounts and offering expenses. The net proceeds of this offering, along with the net proceeds from the Term Loan, were used to fund the cash consideration portion of the GEPH Merger, which closed on December 31, 2021, and to pay $332 million to fund tender offers for $300 million of our 2025 Notes for which the Company recorded an additional loss on extinguishment of debt of $33 million, which included the write-off of $1 million in related unamortized debt discounts and debt issuance costs. The remaining proceeds were used for general corporate purposes.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Operating Commitments and Contingencies As of December 31, 2021, 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 $10.5 billion, $872 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 $869 million of that amount. As of December 31, 2021, 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 $ 9,584 $ 1,141 $ 1,932 $ 1,731 $ 2,167 $ 2,613 Pending regulatory approval and/or construction (1) 872 3 114 163 249 343 Total transportation charges $ 10,456 $ 1,144 $ 2,046 $ 1,894 $ 2,416 $ 2,956 (1) Based on the estimated in-service dates as of December 31, 2021. Prior to the Indigo Merger, in May 2021, Indigo closed on an agreement to divest its Cotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which Southwestern assumed the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the buyer’s actual use. As of December 31, 2021, up to approximately $36 million of these contractual commitments remain (included in the table above), and the Company has recorded a $17 million liability for its portion of the estimated future payments. Excluding the Cotton Valley gathering agreement (discussed above), the Company has recorded additional liabilities totaling $74 million as of December 31, 2021, primarily related to purchase or volume commitments associated with gathering, fresh water and sand. These amounts are reflected above and will be recognized as payments are made over the next six years. The Company leases pressure pumping equipment for its E&P operations under two leases that expire in 2027 and 2028. The current aggregate annual payment under these leases is approximately $7 million. The Company has seven leases for drilling rigs for its E&P operations that expire through 2028 with a current aggregate annual payment of approximately $10 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, 2021, future minimum payments under these non-cancelable leases accounted for as operating leases (including short-term) are approximately $38 million in 2022, $34 million in 2023, $27 million in 2024, $26 million in 2025, $24 million in 2026 and $38 million thereafter. The Company also has commitments for compression services and compression rentals related to its E&P segment. As of December 31, 2021, future minimum payments under these non-cancelable agreements (including short-term obligations) are approximately $24 million in 2022, $10 million in 2023, $4 million in 2024 and less than $1 million in 2025. In the first quarter of 2019, the Company agreed to purchase firm transportation with pipelines in the Appalachian basin from 2021 through 2032. The table above includes $327 million for the remaining contractual commitments for which the seller has agreed to reimburse $100 million to the Company. 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, 2021, the Company does not currently have any material amounts accrued related to litigation matters, including the cases discussed below. 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 requested 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 accepted coverage. On June 15, 2021, the parties agreed to a settlement of the case without any admission of liability. The Company’s insurance carrier is fully funding the settlement amount. On October 21, 2021, the court orally approved the settlement agreement. It signed a final judgment dismissing the litigation on October 22, 2021. Bryant Litigation As further discussed in Note 2 , on September 1, 2021, the Company completed the Indigo Merger, resulting in the assumption of Indigo’s existing litigation. On June 12, 2018, a collection of 51 individuals and entities filed a lawsuit against fifteen oil and gas company defendants, including Indigo, in Louisiana state court claiming damages arising out of current and historical exploration and production activity on certain acreage located in DeSoto Parish, Louisiana. The plaintiffs, who claim to own the properties at issue, assert that Indigo’s actions and the actions of other current operators conducting exploration and production activity, combined with the improper plugging and abandoning of legacy wells by former operators, have caused environmental contamination to their properties. Among other things, the plaintiffs contend that the defendants’ conduct resulted in the migration of natural gas, along with oilfield contaminants, into the Carrizo-Wilcox aquifer system underlying certain portions of DeSoto Parish. The plaintiffs assert claims based in tort, breach of contract and for violations of the Louisiana Civil and Mineral Codes, and they seek injunctive relief and monetary damages in an unspecified amount, including punitive damages. On September 13, 2018, Indigo filed a variety of exceptions in response to the plaintiffs’ petition in this matter. Since the initial filing, supplemental petitions have been filed joining additional individuals and entities as plaintiffs in the matter. On September 29, 2020, plaintiffs filed their fourth supplemental and amending petition in response to the court’s order ruling that plaintiffs’ claims were improperly vague and failed to identify with reasonable specificity the defendants’ allegedly wrongful conduct. Indigo and the majority of the other defendants filed several exceptions to plaintiffs’ fourth amended petition challenging the sufficiency of plaintiffs’ allegations and seeking dismissal of certain claims. On February 18, 2021, plaintiffs filed a fifth supplemental and amending petition, which seeks to augment the claims of select plaintiffs. On October 11, 2021, a sixth supplemental petition was filed which seeks to add the Company as a party to the litigation. The presence of natural gas in a localized area of the Carrizo-Wilcox aquifer system in DeSoto Parish is currently the subject of a regulatory investigation by the Louisiana Office of Conservation (“Conservation”), and the Company is cooperating and coordinating with Conservation in that investigation. The Conservation matter number is EMER18-003. The Company does not currently expect this matter to have a material impact on its financial position, results of operations, cash flows or liquidity. Indemnifications The Company has provided certain indemnifications to various third parties, including in relation to asset and entity dispositions, securities offerings and other financings. 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, 2021
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES The provision (benefit) for income taxes included the following components: (in millions) 2021 2020 2019 Current: Federal $ — $ (2) $ (1) State — — (1) — (2) (2) Deferred: Federal — 371 (431) State — 38 22 — 409 (409) Provision (benefit) for income taxes $ — $ 407 $ (411) The provision for income taxes was an effective rate of 0% in 2021, (15)% in 2020 and (86)% in 2019. The Company’s effective tax rate increased in 2021, as compared with 2020, primarily due to the changes in the valuation allowance and refunds received 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) 2021 2020 2019 Expected provision (benefit) at federal statutory rate $ (5) $ (568) $ 101 Increase (decrease) resulting from: State income taxes, net of federal income tax effect — (55) 11 Change in valuation allowance 2 1,034 (522) Other 3 (4) (1) Provision (benefit) for income taxes $ — $ 407 $ (411) The components of the Company’s deferred tax balances as of December 31, 2021 and 2020 were as follows: (in millions) 2021 2020 Deferred tax liabilities: Right of use lease asset $ 45 $ 38 Other 3 2 48 40 Deferred tax assets: Differences between book and tax basis of property — 295 Accrued compensation 44 38 Accrued pension costs 6 11 Asset retirement obligations 25 20 Net operating loss carryforward 585 1,117 Future lease payments 46 38 Derivative activity 362 9 Capital loss carryover 28 27 Other 31 24 1,127 1,579 Valuation allowance (1,079) (1,539) Net deferred tax asset $ — $ — As the Tax Cuts and Jobs 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 Cuts and Jobs 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. Due to the issuance of common stock associated with the Indigo Merger, as discussed in Note 2 to the consolidated financial statements to this Annual Report, the Company incurred a cumulative ownership change and as such, the Company’s net operating losses (“NOLs”) prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382 of approximately $48 million. The ownership changes and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available, with a corresponding decrease in the Company’s valuation allowance. At December 31, 2021, the Company had approximately $4 billion of federal NOL carryovers, of which approximately $3 billion have an expiration date between 2035 and 2037 and $1 billion have an indefinite carryforward life. The Company currently estimates that approximately $2 billion of these federal NOLs will expire before they are able to be used. The non-expiring NOLs remain subject to a full valuation allowance. If a subsequent ownership change were to occur as a result of future transactions in the Company’s common stock, the Company’s use of remaining U.S. tax attributes may be further limited. Included in the Company’s net operating loss carryforward are the net operating loss carryforwards acquired in the Montage acquisition of $858 million. A portion of the Montage-related net operating loss carryovers is subject to an annual section 382 limitation of $1.7 million, and the Company has appropriately accounted for this limitation in purchase accounting in 2020. 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 $46 million related to interest deduction carryforward as of December 31, 2021. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as current and forecasted business economics of the oil and gas industry. For the years ended December 31, 2018 and 2017, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to non-cash impairments of proved natural gas and oil properties recognized in 2015 and 2016. As of the first quarter of 2019, the Company had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted taxable income, the Company concluded that it was more likely than not that the deferred tax assets would be realized and determined that $522 million of the valuation allowance would be released during 2019. Accordingly, a tax benefit of $522 million was recorded. In 2020, due to significant pricing declines and 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 its deferred tax assets would not be realized and recorded a valuation allowance. As of December 31, 2021, the Company still maintains a full valuation allowance. The Company also retained a valuation allowance of $59 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. A reconciliation of the changes to the valuation allowance is as follows: (in millions) 2021 2020 Valuation allowance at beginning of year $ 1,539 $ 87 Establishment of valuation allowance on opening deferred balance — 408 Return to accrual adjustments (31) 6 Current period deferred activity (1) 626 Reduction due to 382 limitations on NOLs (428) (120) Purchase accounting — 532 Valuation allowance at end of year $ 1,079 $ 1,539 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, 2021, there were no unrecognized tax positions identified that would have a material effect on the effective tax rate. All $7 million in uncertain tax positions booked as of December 31, 2018 were released in 2019 due to audit completion and statute expirations. The Internal Revenue Service closed the 2016 and 2017 audits of the Company’s federal returns in 2021 with no change. The income tax years 2018 to 2021 remain open to examination by the major taxing jurisdictions to which the Company is subject. The Company adopted Accounting Standards Update No. 2019-12 (“ASU 2019-12”) in the current period. ASU 2019-12 addressed simplification to income tax accounting rules, such as removing a few exceptions to intraperiod allocation. There was no material impact to the financial statements as a result of this adoption.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS The following table summarizes the Company’s 2021 and 2020 activity related to asset retirement obligations: (in millions) 2021 2020 Asset retirement obligation at January 1 $ 85 $ 57 Accretion of discount 6 4 Obligations incurred 1 1 Obligations assumed through mergers 36 28 Obligations settled/removed (20) (6) Revisions of estimates 1 1 Asset retirement obligation at December 31 $ 109 $ 85 Current liability $ 4 $ 4 Long-term liability 105 81 Asset retirement obligation at December 31 $ 109 $ 85

Retirement and Employee Benefit

Retirement and Employee Benefit Plans	12 Months Ended
	Dec. 31, 2021
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 of contribution expense in each of 2021, 2020 and 2019, respectively. Additionally, the Company capitalized $2 million of contributions in 2021 and $1 million in both 2020 and 2019 directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties. Defined Benefit Pension and Other Postretirement Plans Prior to January 1, 2021, substantially all of the Company’s employees were covered by the defined benefit pension, a cash balance plan that provided benefits based upon a fixed percentage of an employee’s annual compensation. As part of an ongoing effort to reduce costs, the Company elected to freeze its pension plan effective January 1, 2021. Employees that were participants in the pension plan prior to January 1, 2021 continued to receive the interest component of the plan but no longer received the service component. On September 13, 2021, the Compensation Committee of the Board of Directors approved terminating the Company’s pension plan, effective December 31, 2021, subject to approval by the Internal Revenue Service. This decision, among other benefits, will provide plan participants quicker access to, and greater flexibility in, the management of participants’ respective benefits due under the plan. The Company has commenced the pension plan termination process, but the specific date for the completion of the process is unknown at this time and will depend on certain legal and regulatory requirements or approvals. As part of the termination process, the Company expects to distribute lump sum payments to or purchase annuities for the benefit of plan participants, which is dependent on the participants’ elections. In addition, the Company expects to make a payment equal to the difference between the total benefits due under the plan and the total value of the assets available, which, as of December 31, 2021, was $11 million. The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages. Substantially all of the Company’s employees 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. The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status as of December 31, 2021 and 2020: Pension Benefits Other Postretirement Benefits (in millions) 2021 2020 2021 2020 Change in benefit obligations: Benefit obligation at January 1 $ 139 $ 126 $ 13 $ 13 Service cost (1) — 7 2 2 Interest cost 4 5 — — Participant contributions — — — — Actuarial (gain) loss (4) 16 (2) 1 Benefits paid (2) (13) — (1) Plan amendments — — — (2) Curtailments — (2) — — Settlements (11) — — — Benefit obligation at December 31 $ 126 $ 139 $ 13 $ 13 (1) The Company froze its pension plan effective January 1, 2021, resulting in no service cost for the year ended December 31, 2021. Pension Benefits Other Postretirement Benefits (in millions) 2021 2020 2021 2020 Change in plan assets: Fair value of plan assets at January 1 $ 106 $ 96 $ — $ — Actual return on plan assets 6 11 — — Employer contributions 12 12 1 1 Participant contributions — — — — Benefits paid (2) (13) (1) (1) Settlements (8) — — — Fair value of plan assets at December 31 $ 114 $ 106 $ — $ — Funded status of plans at December 31 (1) $ (12) $ (33) $ (13) $ (13) (1) The funded status of the pension plan includes a $1 million liability related to a supplemental employee retirement plan as of December 31, 2021 and 2020. 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, 2021 and 2020 are as follows: (in millions) 2021 2020 Projected benefit obligation $ 126 $ 139 Accumulated benefit obligation 126 139 Fair value of plan assets 114 106 Pension and other postretirement benefit costs include the following components for 2021, 2020 and 2019: Pension Benefits Other Postretirement Benefits (in millions) 2021 2020 2019 2021 2020 2019 Service cost (1) $ — $ 7 $ 7 $ 2 $ 2 $ 1 Interest cost 4 5 5 — — — Expected return on plan assets (4) (6) (6) — — — Amortization of transition obligation — — — — — — Amortization of prior service cost — — — — — — Amortization of net loss — 1 2 — — — Net periodic benefit cost — 7 8 2 2 1 Curtailment gain — — — — — — Settlement loss 2 — 6 — — — Total benefit cost $ 2 $ 7 $ 14 $ 2 $ 2 $ 1 (1) The Company froze its pension plan effective January 1, 2021, resulting in no service cost for the year ended December 31, 2021. 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. The Company froze its pension plan effective January 1, 2021, resulting in no service cost for the year ended December 31, 2021. The weighted average interest crediting rate for the pension plan is 6.0%. The Company recognized a $2 million non-cash settlement loss related to $8 million of lump sum payments from the pension plan for the year ended December 31, 2021. As a result of settlement accounting requirements, the Company recorded a $4 million reduction to its net pension liability as of December 31, 2021, with a corresponding reduction to accumulated other comprehensive loss. 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 restructuring, the Company recognized a $6 million non-cash settlement loss in 2019 related to $21 million of lump sum payments as a result of these restructuring events. In 2020, the settlement loss was immaterial. Amounts recognized in other comprehensive income for the years ended December 31, 2021 and 2020 were as follows: Pension Benefits Other Postretirement Benefits (in millions) 2021 2020 2021 2020 Net actuarial (loss) gain arising during the year $ 5 $ (12) $ 2 $ 2 Amortization of prior service cost — — — — Amortization of net loss 1 1 — — Settlements 5 — — — Curtailments — 3 — — Less: Tax effect (1) — 3 — (1) Amounts recognized in other comprehensive income $ 11 $ (5) $ 2 $ 1 (1) Pension and other postretirement benefit tax effects of $2.7 million and $0.4 million, respectively, for the year ended December 31, 2021, were netted against a valuation allowance and therefore included in accumulated other comprehensive income. Included in accumulated other comprehensive income as of December 31, 2021 and 2020 was a $23 million loss ($18 million net of tax) and a $36 million loss ($28 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2021, $13 million was classified from accumulated other comprehensive income, primarily driven by actuarial gains and settlements. Upon the anticipated termination of the pension plan, the Company expects the remaining associated balance in accumulated other comprehensive income to be reclassified to net income in the periods in which lump sum payments are distributed to, or annuities are purchased for, plan participants. The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2021 and 2020 are as follows: Pension Benefits Other Postretirement Benefits 2021 2020 2021 2020 Discount rate 3.20 % 3.10 % 3.10 % 2.80 % 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 2021, 2020 and 2019 are as follows: Pension Benefits Other Postretirement Benefits 2021 2020 2019 2021 2020 2019 Discount rate 3.20 % 3.70 % 3.70 % 2.80 % 3.50 % 4.35 % Expected return on plan assets 0.10 % 6.50 % 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 2021 and 2020: 2021 2020 Health care cost trend assumed for next year 6.5 % 6.5 % Rate to which the cost trend is assumed to decline 5.0 % 5.0 % Year that the rate reaches the ultimate trend rate 2038 2037 Pension Payments and Asset Management In 2021, the Company contributed $12 million to its pension plan and less than $1 million to its other postretirement benefit plan and does not expect to make any additional contributions to its pension plan until the plan termination is completed. Although the specific date for the completion of the pension plan termination process is unknown at this time and will depend on certain legal and regulatory requirements or approvals, the Company has adjusted actuarial expectations based on an estimated timeline of approvals and completion. As part of the termination process, the Company expects to distribute lump sum payments to, or purchase annuities for, the benefit plan participants, which is dependent on the participants’ elections. The following timeline reflects the Company’s current estimate of benefit payments to be made and the timing thereof, including projected future interest costs: Pension Benefits Other Postretirement Benefits (in millions) (in millions) 2022 $ 48 2022 $ 1 2023 70 2023 1 2024 — 2024 1 2025 — 2025 1 2026 — 2026 1 Years 2027-2031 — Years 2027-2031 4 The Company’s overall investment strategy has been 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 (“BAC”) of the Company, appointed by the Compensation Committee of the Board of Directors, currently administers the Company’s pension plan assets. In anticipation of the pension plan termination, the BAC has adjusted the asset-class mix to more investment grade fixed income assets to mitigate equity market risk, while also preserving cash to satisfy potential interim plan termination-related expenditures. The table below presents the allocations targeted by the BAC and the actual weighted-average asset allocation of the Company’s pension plan as of December 31, 2021, by asset category. The asset allocation targets are subject to change and the BAC 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 Fixed income (1) 78 % 78 % Cash (2) 22 % 22 % Total 100 % 100 % (1) Includes fixed income pension plan assets in the table below. (2) 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, 2021 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 Fixed income (1) 90 90 — — Cash and cash equivalents 24 24 — — Total plan assets at fair value $ 114 $ 114 $ — $ — (1) U.S. Treasury Notes. Utilizing the fair value hierarchy described in Note 8 , the Company’s fair value measurement of pension plan assets at December 31, 2020 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 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 (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. The Company’s pension plan assets that are classified as Level 1 are the investments comprised of either cash or investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of observable activity to support classification of the fair value measurement as Level 1. Due to the Company’s implementation of Accounting Standards Update No. 2015-07, assets measured using net asset value as a practical expedient have not been classified in the fair value

Long-Term Incentive Compensatio

Long-Term Incentive Compensation	12 Months Ended
	Dec. 31, 2021
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 current long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from the Company’s common stock price, and cash-based awards that are fixed in amount but are subject to meeting annual performance thresholds. The Company recorded the following costs related to long-term incentive compensation for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Long-term incentive compensation – expensed $ 30 $ 17 $ 17 Long-term incentive compensation – capitalized 18 7 10 Stock-Based Compensation 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 2019, 2020 and 2021 cliff-vest at the end of three years. As further discussed in Note 3 , 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. In February of 2021 and 2020, the Company notified employees of workforce reduction plans as a result of strategic realignments of the Company’s organizational structure. Employees affected by these events 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. 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, 2021, 2020 and 2019 on the consolidated statements of operations. Equity-Classified Awards Equity-Classified Stock Options The Company recorded the following compensation costs related to equity-classified stock options for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Stock options – general and administrative expense $ — $ — $ 1 Stock options – capitalized expense $ — $ — $ — The Company recorded less than $1 million deferred tax assets related to stock options for the years ended December 31, 2021 and 2019, compared to no deferred tax assets for the year ended December 31, 2020. Additionally, the Company had no unrecognized compensation cost related to unvested stock options at December 31, 2021. 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. There were no equity-classified stock options granted or exercised in 2021, 2020 or 2019. The following tables summarize stock option activity for the years 2021, 2020 and 2019, and provide information for options outstanding at December 31 of each year: 2021 2020 2019 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 3,850 $ 13.39 4,635 $ 15.26 5,178 $ 17.06 Granted — $ — — $ — — $ — Exercised — $ — — $ — — $ — Forfeited or expired (844) $ 29.10 (785) $ 24.46 (543) $ 32.38 Options outstanding at December 31 3,006 $ 8.98 3,850 $ 13.39 4,635 $ 15.26 Options Outstanding Options Exercisable Range of Exercise Prices Options Outstanding at December 31, 2021 Weighted Average Exercise Price Weighted Average Remaining Contractual Life Options Exercisable at December 31, 2021 Weighted Average Exercise Price Weighted Average Remaining Contractual Life (in thousands) (years) (in thousands) (years) $7.74-$29.42 3,006 $ 8.98 1.3 3,006 $ 8.98 1.3 Equity-Classified Restricted Stock The Company recorded the following compensation costs related to equity-classified restricted stock grants for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Restricted stock grants – general and administrative expense $ 2 $ 3 $ 6 Restricted stock grants – capitalized expense $ — $ 1 $ 4 The Company also recorded deferred tax asset of $1 million related to restricted stock for the year ended December 31, 2021, compared to a deferred tax asset of $2 million and a reduction in the deferred tax asset of less than $1 million for the years ended December 31, 2020 and 2019, respectively. As of December 31, 2021, 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 1.6 years. The following table summarizes the restricted stock activity for the years 2021, 2020 and 2019, and provides information for restricted stock outstanding at December 31 of each year: 2021 2020 2019 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 1 697 $ 5.97 1,480 $ 7.00 2,717 $ 7.91 Granted 438 $ 5.18 584 $ 2.86 493 $ 3.06 Vested (893) $ 5.81 (1,098) $ 5.26 (1,516) $ 7.16 Forfeited — $ 8.59 (269) (1) $ 7.79 (214) (2) $ 8.38 Unvested shares at December 31 242 $ 5.12 697 $ 5.97 1,480 $ 7.00 (1) Includes 171,813 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2020. (2) Includes 65,196 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2019. The fair values of the grants were $2 million for each of 2021, 2020 and 2019. The total fair value of shares vested were $5 million for 2021, $6 million for 2020 and $11 million for 2019. 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 to these equity-classified restricted stock units recorded by the Company was immaterial for the years ended December 31, 2021 and 2020. As of December 31, 2021, 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 1.2 years. The following table summarizes equity-classified restricted stock unit activity to be paid out in Company stock for the years ended December 31, 2021 and 2020. 2021 2020 Number Weighted Average Number Weighted Average (in thousands) (in thousands) Unvested Units at January 1 134 $ 3.05 — $ — Granted — $ — 186 $ 3.05 Vested (92) $ 3.05 (42) $ 3.05 Forfeited (5) $ 3.05 (10) $ 3.05 Unvested Units at December 31 37 $ 3.05 134 $ 3.05 Equity-Classified Performance Units The Company recorded compensation costs related to equity-classified performance units for the years ended December 31, 2020 and 2019. There have been no equity-classified performance units awarded since 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 costs recognized for the year ended December 31, 2021 associated with equity-classified performance units, and the amounts recognized in 2020 were immaterial. (in millions) 2021 2020 2019 Performance units – general and administrative expense $ — $ — $ 1 Performance units – capitalized expense $ — $ — $ — The Company recorded $2 million deferred tax assets related to equity-classified performance units for the year ended December 31, 2021. The Company recorded a deferred tax asset of less than $1 million and $1 million for the years ended December 31, 2020 and 2019, 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, 2021, 2020 and 2019, and provides information for unvested units as of December 31, 2021, 2020 and 2019: 2021 2020 2019 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 Granted — $ — — $ — — $ — Vested — $ — (178) $ 10.47 (378) $ 9.59 Forfeited — $ — — $ — (42) (2) $ 10.47 Unvested shares at December 31 — $ — — $ — 178 $ 10.47 (1) These amounts reflect the number of performance units granted in thousands. The actual payout of shares ranged from a minimum of zero shares to a maximum of two shares per unit contingent upon TSR. The performance units had a three-year vesting term and the actual disbursement of shares, if any, was determined during the first quarter following the end of the three-year vesting period. (2) Included 41,761 units related to the reduction in workforce for the year ended December 31, 2019. Liability-Classified Awards Liability-Classified Restricted Stock Units In the first quarter of each year beginning with 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 awards granted in 2021 vest over a period of three years. 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. The Company recorded the following compensation costs related to liability-classified restricted stock unit grants for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Restricted stock units – general and administrative expense $ 12 $ 5 $ 7 Restricted stock units – capitalized expense $ 8 $ 2 $ 5 The Company also recorded deferred tax assets of $1 million for the year ended December 31, 2021, compared to $1 million and less than $1 million related to liability-classified restricted stock units for the years ended 2020 and 2019, respectively. As of December 31, 2021, there was $19 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 1.7 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 or Company stock for the years ended December 31, 2021, 2020 and 2019 and provides information for unvested units as of December 31, 2021, 2020 and 2019: 2021 2020 2019 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 11,613 $ 2.67 12,992 $ 2.42 8,202 $ 3.41 Granted 1,486 $ 4.23 6,172 $ 1.41 8,659 $ 4.34 Vested (4,522) $ 3.40 (3,960) $ 1.43 (2,624) $ 4.09 Forfeited (640) (1) $ 4.56 (3,591) (2) $ 2.67 (1,245) (3) $ 3.48 Unvested units at December 31 7,937 $ 4.08 11,613 $ 2.67 12,992 $ 2.42 (1) Includes 360,253 units related to the reduction in workforce for the year ended December 31, 2021. (2) Includes 2,010,196 units related to the reduction in workforce for the year ended December 31, 2020. (3) Includes 400,056 units related to the reduction in workforce for the year ended December 31, 2019. Liability-Classified Performance Units In each of the last four years, 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. In 2021, two types of performance unit awards were granted. One type of award includes a performance condition based on return on capital employed and a performance condition based on a reinvestment rate, and the second type of award includes one 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. The Company recorded the following compensation costs related to liability-classified performance unit grants for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Liability-classified performance units – general and administrative expense $ 12 $ 7 $ 2 Liability-classified performance units – capitalized expense $ 6 $ 2 $ 1 The Company also recorded deferred tax assets of $4 million related to liability-classified performance units for the year ended December 31, 2021, compared to a deferred tax asset of $2 million and a reduction of deferred tax asset of less than $1 million for the years ended 2020 and 2019, respectively. As of December 31, 2021, 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 1.6 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, 2021, 2020 and 2019 and provides information for unvested units as of December 31, 2021, 2020 and 2019: 2021 2020 2019 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) (in thousands) Unvested units at January 1 8,699 $ 2.57 5,142 $ 2.42 2,803 $ 3.41 Granted 3,580 $ 4.14 6,172 $ 1.41 2,757 $ 4.34 Vested (2,020) $ 4.05 — $ — (43) $ 2.42 Forfeited (744) $ 3.40 (2,615) (1) $ 3.05 (375) (2) $ 3.12 Unvested units at December 31 9,515 $ 2.88 8,699 $ 2.57 5,142 $ 2.42 (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. Cash-Based Compensation Performance Cash Awards In 2021 and 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 2021 and 2020 include a performance condition determined annually by the Company. For both years, 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. The Company recorded the following compensation costs related to performance cash awards for the years ended December 31, 2021 and 2020: (in millions) 2021 2020 Performance cash awards – general and administrative expense $ 4 $ 2 Performance cash awards – capitalized expense $ 4 $ 2 The Company also recorded deferred tax assets of $1 million related to performance cash awards for each of the years ended December 31, 2021 and 2020. As of December 31, 2021 there was $21 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 2.7 years. The final value of the performance cash awards is contingent upon the Company's actual performance against these performance measures. The following table summarizes performance cash award activity to be paid out in cash for the years ended December 31, 2021 and 2020 and provides information for unvested units as of December 31, 2021 and 2020: 2021 2020 Number Weighted Average Number Weighted Average (in thousands) (in thousands) Unvested units at January 1 18,353 $ 1.00 — $ — Granted 18,546 $ 1.00 20,044 $ 1.00 Vested (4,955) $ 1.00 (100) $ 1.00 Forfeited (3,672) (1) $ 1.00 (1,591) (2) $ 1.00 Unvested Units at December 31 28,272 $ 1.00 18,353 $ 1.00 (1) Includes 1,241,000 units related to the reduction in workforce for the year ended December 31, 2021 . (2) 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, 2021
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 2021 Revenues from external customers $ 4,701 $ 1,966 $ — $ 6,667 Intersegment revenues (61) 4,223 — 4,162 Depreciation, depletion and amortization expense 537 9 — 546 Impairments 6 — — 6 Operating income 2,583 (1) 52 — 2,635 Interest expense (2) 136 — — 136 Gain (loss) on derivatives (2,437) — 1 (2,436) Loss on early extinguishment of debt — — (93) (93) Other income, net 5 — — 5 Provision for income taxes (2) — — — — Assets 10,767 (3) 956 125 11,848 Capital investments (4) 1,107 — 1 1,108 (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) (5) (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 (7) — 16 Operating income (loss) 283 (6) (13) — 270 Interest expense (2) 65 — — 65 Gain on derivatives 274 — — 274 Gain on early extinguishment of debt — — 8 8 Other income (loss) (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 (1) Operating income for the E&P segment includes $7 million of restructuring charges and $76 million of acquisition-related charges for the year ended December 31, 2021. (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 an increase of $70 million for 2021, a decrease of $3 million for 2020 and an increase of $34 million for 2019 related to the change in accrued expenditures between years. (5) 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. (6) Operating income for the E&P segment includes $11 million of restructuring charges for the year ended December 31, 2019. (7) Marketing includes a $3 million non-cash impairment related to certain non-core midstream gathering assets at December 31, 2019. 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, 2021, 2020 and 2019: For the years ended December 31, (in millions) 2021 2020 2019 Cash and cash equivalents $ 28 $ 13 $ 5 Accounts receivable — 1 — Income taxes receivable — — 30 Prepayments 6 6 8 Property, plant and equipment 12 16 27 Unamortized debt expense 10 11 11 Right-of-use lease assets 65 72 80 Non-qualified retirement plan 4 6 7 $ 125 $ 125 $ 168

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020: (in millions) 2021 2020 Proved properties $ 31,400 $ 25,789 Unproved properties 2,231 1,472 Total capitalized costs 33,631 27,261 Less: Accumulated depreciation, depletion and amortization (23,884) (23,362) Net capitalized costs $ 9,747 $ 3,899 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, 2021: (in millions) 2021 2020 2019 Prior Total Property acquisition costs $ 784 $ 85 $ 9 $ 1,079 $ 1,957 Exploration and development costs 28 9 7 10 54 Capitalized interest 75 48 36 61 220 $ 887 $ 142 $ 52 $ 1,150 $ 2,231 Of the total net unevaluated costs excluded from amortization as of December 31, 2021, approximately $1.1 billion is related to undeveloped properties in Appalachia which were acquired in 2014 and 2015, $117 million is related to Montage properties acquired in November 2020 and approximately $759 million is related to the acquisition of undeveloped properties in Haynesville which were acquired in September 2021 and December 2021. Additionally, the Company has approximately $220 million of unevaluated capitalized interest and $51 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) 2021 2020 2019 Unproved property acquisition costs $ 139 $ 124 (1) $ 162 Exploration costs — — 2 Development costs 984 784 936 Capitalized costs incurred $ 1,123 $ 908 $ 1,100 Full cost pool amortization per Mcfe $ 0.42 $ 0.38 $ 0.56 (1) Excluded $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 $97 million, $88 million and $109 million during 2021, 2020 and 2019, 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 $64 million, $56 million and $77 million during 2021, 2020 and 2019, 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) 2021 2020 2019 Sales $ 4,640 $ 1,348 $ 1,703 Production (lifting) costs (1,304) (866) (781) Depreciation, depletion and amortization (537) (348) (462) Impairment of natural gas and oil properties — (2,825) — 2,799 (2,691) 460 Provision for income taxes (1) — — 110 Results of operations (2) $ 2,799 $ (2,691) $ 350 (1) Prior to the recognition of a valuation allowance, in 2020 the Company recognized an income tax benefit of $624 million. (2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 6 . The results of operations shown above exclude general and administrative expenses and interest expense and are not necessarily indicative of the contribution made by the Company’s natural gas and oil operations to its consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits. Natural Gas and Oil Reserve Quantities The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties, and accounted for approximately 99% of the present worth of the Company’s total proved reserves as of December 31, 2021. For 2020 and 2019, NSAI’s audit accounted for 97% and 99%, respectively, of the then-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 2019, 2020 and 2021, all of which were located in the United States: Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) 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 (1) 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 (2) 1,911 18,796 55,141 2,354 Disposition of reserves in place — — — — December 31, 2020 9,181 58,024 410,151 11,990 Revisions of previous estimates due to price (3) 501 1,414 (15,525) 415 Revisions of previous estimates other than price 248 1,900 1,500 269 Extensions, discoveries and other additions 2,543 24,865 211,598 3,962 Production (1,015) (6,610) (30,940) (1,240) Acquisition of reserves in place (4) 5,750 247 180 5,753 Disposition of reserves in place (1) (61) — (1) December 31, 2021 17,207 79,779 576,964 21,148 (1) 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. (2) The 2020 acquisition amounts are primarily associated with the Montage Merger. (3) The 15,525 MBbl reduction in NGL volumes for 2021 is the result of changes to the Company’s five-year development plan and elections to retain ethane in the natural gas stream in line with ethane transportation contracts. This election is driven by commodity pricing, whereby higher natural gas pricing relative to ethane pricing creates a more economically favorable position. (4) The 2021 acquisition amounts are primarily associated with the Indigo Merger and the GEPH Merger. Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) Proved developed reserves as of: December 31, 2019 4,906 26,124 226,271 6,421 December 31, 2020 6,342 33,563 276,548 8,203 December 31, 2021 9,308 40,930 296,832 11,335 Proved undeveloped reserves as of: December 31, 2019 3,724 46,801 382,490 6,300 December 31, 2020 2,839 24,461 133,603 3,787 December 31, 2021 7,899 38,849 280,132 9,813 The Company’s estimated proved natural gas, oil and NGL reserves were 21,148 Bcfe at December 31, 2021, compared to 11,990 Bcfe at December 31, 2020. The Company’s reserves increased in 2021, compared to 2020, as acquisitions, additions and positive price and performance revisions were only partially offset by production and disposition. The Company’s reserves decreased in 2020, as 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 following table summarizes the changes in reserves for 2019, 2020 and 2021: (in Bcfe) Appalachia Haynesville Other (1) Total December 31, 2018 11,920 — 1 11,921 Net revisions Price revisions (717) — — (717) Performance and production revisions (2) 1,102 — — 1,102 Total net revisions 385 — — 385 Extensions, discoveries and other additions Proved developed 191 — — 191 Proved undeveloped 1,004 — — 1,004 Total reserve additions 1,195 — — 1,195 Production (778) — — (778) Acquisition of reserves in place — — — — Disposition of reserves in place (2) — — (2) December 31, 2019 12,720 — 1 12,721 Net revisions Price revisions (4,370) — — (4,370) Performance and production revisions 1,424 — — 1,424 Total net revisions (2,946) — — (2,946) Extensions, discoveries and other additions Proved developed 267 — — 267 Proved undeveloped 474 — — 474 Total reserve additions 741 — — 741 Production (880) — — (880) Acquisition of reserves in place 2,354 — — 2,354 Disposition of reserves in place — — — — December 31, 2020 11,989 — 1 11,990 Net revisions Price revisions 415 — — 415 Performance and production revisions 270 — (1) 269 Total net revisions 685 — (1) 684 Extensions, discoveries and other additions Proved developed 451 — — 451 Proved undeveloped (3) 3,511 — — 3,511 Total reserve additions 3,962 — — 3,962 Production (1,108) (132) — (1,240) Acquisition of reserves in place — 5,753 — 5,753 Disposition of reserves in place (1) — — (1) December 31, 2021 15,527 5,621 — 21,148 (1) Other includes properties outside of Appalachia and Haynesville. (2) 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. (3) For the year ended December 31, 2021, net extensions, discoveries and other additions in proved undeveloped reserves of 3,511 Bcfe was comprised of 1,768 Bcfe resulting from the addition of new undeveloped locations throughout the year through the Company’s successful drilling program and 1,743 Bcfe which was attributable to undeveloped locations which were uneconomical under prior year SEC pricing (and therefore excluded from prior year reserves) but which have become economical under current SEC pricing. As of December 31, 2021, the Company had no proved undeveloped reserves that had a negative present value on a 10% discounted basis. 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 that have a negative $207 million present value when discounted at 10%. 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 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 measure of discounted future net cash flows relating to proved natural gas, oil and NGL reserves as of December 31, 2021, 2020 and 2019 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) 2021 2020 2019 Future cash inflows $ 75,314 $ 17,997 $ 27,003 Future production costs (23,235) (11,969) (14,981) Future development costs (1) (6,032) (1,924) (3,246) Future income tax expense (8,135) — (476) Future net cash flows 37,912 4,104 8,300 10% annual discount for estimated timing of cash flows (19,181) (2,257) (4,600) Standardized measure of discounted future net cash flows $ 18,731 $ 1,847 $ 3,700 (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: 2021 2020 2019 Natural gas (per MMBtu) $ 3.60 $ 1.98 $ 2.58 Oil (per Bbl) 66.56 39.57 55.69 NGLs (per Bbl) 28.65 10.27 11.58 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 2021, 2020 and 2019: (in millions) 2021 2020 2019 Standardized measure, beginning of year $ 1,847 $ 3,700 $ 5,999 Sales and transfers of natural gas and oil produced, net of production costs (3,332) (478) (923) Net changes in prices and production costs 10,417 (2,720) (3,510) Extensions, discoveries, and other additions, net of future production and development costs 3,183 81 234 Acquisition of reserves in place 6,499 443 — Sales of reserves in place (1) — (2) Revisions of previous quantity estimates 596 (987) 152 Net change in income taxes (3,689) 35 491 Changes in estimated future development costs 137 1,241 621 Previously estimated development costs incurred during the year 419 624 704 Changes in production rates (timing) and other 2,470 (466) (718) Accretion of discount 185 374 652 Standardized measure, end of year $ 18,731 $ 1,847 $ 3,700

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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. The comparability of certain 2021 amounts to prior periods could be impacted as a result of the Montage Merger (as defined below) in November 2020, the Indigo Merger (as defined below) on September 1, 2021, and the GEPH Merger (as defined below) on December 31, 2021. The Company believes the disclosures made are adequate to make the information presented not misleading.
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.
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, 2021 one purchaser accounted for 12% of annual 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 a default. For the year ended December 31, 2020, one purchaser accounted for 10% of annual revenues. No other purchasers accounted for more than 10% of consolidated revenues. 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 Company had $28 million and $13 million in cash and cash equivalents as of December 31, 2021 and 2020, respectively. 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 $21 million and $16 million as of December 31, 2021 and 2020, 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. Prices used to calculate the ceiling value of reserves were as follows: For the years ended December 31, 2021 2020 2019 Natural gas (per MMBtu) $ 3.60 $ 1.98 $ 2.58 Oil (per Bbl) $ 66.56 $ 39.57 $ 55.69 NGLs (per Bbl) $ 28.65 $ 10.27 $ 11.58 Using the average quoted prices above, adjusted for market differentials, the net book value of the Company’s United States natural gas and oil properties did not exceed the ceiling amount at December 31, 2021 or 2019. The net book value of its natural gas and oil properties exceeded the ceiling amount in each quarter of 2020 resulting in a total non-cash full cost ceiling test impairment of $2,825 million. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2021, 2020 and 2019. Future decreases in market prices, as well as changes in production rates, levels of reserves, evaluation costs excluded from amortization, future development costs and production costs may result in future non-cash impairments to the Company’s natural gas and oil properties. No impairment expense was recorded in 2020 or 2021 in relation to the Company’s natural gas and oil properties acquired from Montage. These properties were recorded at fair value as of November 13, 2020, in accordance with Accounting Standards Codification (“ASC”) Topic 820 – Fair Value Measurement . In the fourth quarter of 2020, pursuant to SEC guidance, the Company determined that the fair value of the properties acquired at the closing of the Montage 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 Montage 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 could continue to demonstrate that the fair value of properties acquired clearly exceeded the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, the Company was 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 Montage Merger was based on future commodity market pricing for natural gas and oil pricing existing at the date of the Montage Merger, and management affirmed that there has not been a material decline to the fair value of these acquired assets since the Montage Merger. The properties acquired in the Montage Merger had 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. Due to the improvement in commodity prices during 2021, no impairment charge would have been recorded in 2021 had the Montage natural gas and oil properties been included in the full cost ceiling test. 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, 2021, the Company had a total of $2,231 million of costs excluded from the amortization base, all of which related to its properties in the United States. 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, 2021 December 31, 2020 Water facilities $ 237 $ 228 Gathering systems 56 54 Technology infrastructure 135 133 Drilling rigs and equipment 28 26 Land, buildings and leasehold improvements 16 41 Other 37 41 Less: Accumulated depreciation and impairment (319) (311) Total $ 190 $ 212 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, 2021 and 2020 the Company recognized non-cash impairments of $6 million and $5 million, respectively, for 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, 2021 and 2020, the Company had $48 million and $57 million, respectively, in marketing-related intangible assets, of which $43 million and $48 million were included in Other long-term assets on the respective consolidated balance sheets. The Company amortized $8 million of its marketing-related intangible asset in December 31, 2021 and $9 million in each of the years ended December 31, 2020 and 2019, and expects to amortize $5 million in 2022 and 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, 2021. 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 2039. 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.
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 AwardsThe Company classifies certain awards that can or will be settled in cash as liability awards. The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting.  Changes in the fair value of liability-classified awards are recorded to general and administrative expense, 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. In 2021, two types of performance unit awards were granted. One type of award includes a performance condition based on return on capital employed and a performance condition based on a reinvestment rate, and the second type of award includes one 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.
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
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 Financial Accounting Standards Board (the “FASB”) issued ASU 2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU 2018-14 amends, adds and removes certain disclosure requirements under FASB Accounting Standards Codification (“ASC”) Topic 715 – Compensation – Retirement Benefits. The guidance in ASU 2018-14 is effective for fiscal years beginning after December 15, 2020 and was adopted on January 1, 2021. Adoption of ASU 2018-14 resulted in certain disclosure changes within the Company's footnote disclosures. The adoption of ASU 2018-14 did not have a material impact on the Company's consolidated financial statements. Refer to Pension Plan and Other Postretirement Benefits footnote. In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. ASU 2019-12 eliminates certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard became effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company adopted the new standard on January 1, 2021 on a prospective basis, which did not have a material impact on its consolidated financial statements. New Accounting Standards Not Yet Adopted in this Report In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform, as a new 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 was 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 USD-LIBOR settings are expected to be published through June 2023 and Southwestern will use a variation of this rate until the underlying agreements are extended beyond the LIBOR publication date. The standard was adopted on January 1, 2022 and did not have a significant impact on Southwestern’s consolidated financial statements upon adoption.

Organization and Summary of S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Oil and Gas, Average Sale Price and Production Cost	Prices used to calculate the ceiling value of reserves were as follows: For the years ended December 31, 2021 2020 2019 Natural gas (per MMBtu) $ 3.60 $ 1.98 $ 2.58 Oil (per Bbl) $ 66.56 $ 39.57 $ 55.69 NGLs (per Bbl) $ 28.65 $ 10.27 $ 11.58
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, 2021 December 31, 2020 Water facilities $ 237 $ 228 Gathering systems 56 54 Technology infrastructure 135 133 Drilling rigs and equipment 28 26 Land, buildings and leasehold improvements 16 41 Other 37 41 Less: Accumulated depreciation and impairment (319) (311) Total $ 190 $ 212
Schedule of Earnings Per Share	The following table presents the computation of earnings per share for the years ended December 31, 2021, 2020 and 2019: For the years ended December 31, (in millions, except share/per share amounts) 2021 2020 2019 Net income (loss) $ (25) $ (3,112) $ 891 Number of common shares: Weighted average outstanding 789,657,776 573,889,502 539,345,343 Issued upon assumed exercise of outstanding stock options — — — Effect of issuance of non-vested restricted common stock — — 361,380 Effect of issuance of non-vested restricted units — — — Effect of issuance of non-vested performance units — — 676,191 Weighted average and potential dilutive outstanding 789,657,776 573,889,502 540,382,914 Earnings (loss) per common share: Basic $ (0.03) $ (5.42) $ 1.65 Diluted $ (0.03) $ (5.42) $ 1.65
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, 2021, 2020 and 2019, as they would have had an antidilutive effect: For the years ended December 31, 2021 2020 2019 Unexercised stock options 3,683,363 4,427,040 5,078,253 Unvested share-based payment 832,989 962,662 1,728,264 Restricted units 2,226,981 4,452,876 — Performance units 2,194,477 2,818,653 271,268 Total 8,937,810 12,661,231 7,077,785
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, 2021, 2020 and 2019: For the years ended December 31, (in millions) 2021 2020 2019 Cash paid during the year for interest, net of amounts capitalized $ 106 $ 75 $ 58 Cash paid (received) during the year for income taxes — (1) (32) (52) Non-cash investing activities 3,690 (2) 1,084 (3) 41 Non-cash financing activities 2,051 (4) 213 (5) — (1) Cash received in 2021 for income taxes was immaterial. (2) Includes $3,039 million and $575 million in non-cash property additions related to the Indigo Merger and the GEPH Merger, respectively. (3) Includes $1,097 million in non-cash additions related to the Montage Merger. (4) Includes $1,588 million and $463 million in common stock consideration related to the Indigo Merger and the GEPH Merger, respectively. (5) Common stock consideration related to the Montage Merger.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Schedule of Business Acquisitions by Acquisition, Equity Interest Issued or Issuable	The following table presents the fair value of consideration transferred to GEPH equity holders as a result of the GEPH Merger: (in millions, except share, per share amounts) As of December 31, 2021 Shares of Southwestern common stock issued 99,337,748 NYSE closing price per share of Southwestern common shares on December 31, 2021 $ 4.66 $ 463 Cash consideration 1,269 Total consideration $ 1,732 (in millions, except share, per share amounts) As of September 1, 2021 Shares of Southwestern common stock issued 337,827,171 NYSE closing price per share of Southwestern common shares on September 1, 2021 $ 4.70 $ 1,588 Cash consideration 373 Total consideration $ 1,961 (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
Schedule of Business Acquisitions, by Acquisition	The following table sets forth the preliminary fair value of the assets acquired and liabilities assumed as of the acquisition date. Certain data and studies necessary to complete the purchase price allocation are still under evaluation, including, but not limited to, the final actualization of accrued liabilities and receivable balances and the valuation of natural gas and oil properties. The Company will finalize the purchase price allocation during the twelve-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate. (in millions) As of December 31, 2021 Consideration: Total consideration $ 1,732 Fair Value of Assets Acquired: Cash and cash equivalents 11 Accounts receivable 171 Other current assets 3 Commodity derivative assets 56 Evaluated oil and gas properties 1,783 Unevaluated oil and gas properties 59 Other property, plant and equipment 2 Other long-term assets 3 Total assets acquired 2,088 Fair Value of Liabilities Assumed: Accounts payable 170 Other current liabilities 1 Derivative liabilities 75 Revolving credit facility 81 Asset retirement obligations 24 Other noncurrent liabilities 5 Total liabilities assumed 356 Net Assets Acquired and Liabilities Assumed $ 1,732 The following table sets forth the preliminary fair value of the assets acquired and liabilities assumed as of the acquisition date. Certain data and studies necessary to complete the purchase price allocation are still under evaluation, including, but not limited to, the valuation of natural gas and oil properties and the resolution of certain matters that the Company is indemnified for under the Indigo Merger Agreement for which not enough information is available to assess the final fair value of at this time. The Company will finalize the purchase price allocation during the twelve-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate. (in millions) As of September 1, 2021 Consideration: Total consideration $ 1,961 Fair Value of Assets Acquired: Cash and cash equivalents 55 Accounts receivable 192 Other current assets 2 Commodity derivative assets 2 Evaluated oil and gas properties 2,724 Unevaluated oil and gas properties (1) 684 Other property, plant and equipment 4 Other long-term assets 27 Total assets acquired 3,690 Fair Value of Liabilities Assumed: Accounts payable (1) 274 Other current liabilities 55 Derivative liabilities 501 Revolving credit facility 95 Senior unsecured notes 726 Asset retirement obligations 8 Other noncurrent liabilities 70 Total liabilities assumed 1,729 Net Assets Acquired and Liabilities Assumed $ 1,961 (1) Reflects an $8 million purchase price adjustment due to ongoing valuation. The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation is complete as of the fourth quarter of 2021. (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 (1) 100 Other property, plant and equipment 28 Other long-term assets 26 Total assets acquired 1,254 Fair value of liabilities assumed: Accounts payable (1) 155 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 1,041 Net assets acquired and liabilities assumed $ 213 (1) Reflects a $10 million purchase price adjustment due to completion of valuation assessments during the measurement period.
Business Acquisition, Pro Forma Information	The following table summarizes the unaudited pro forma condensed financial information of Southwestern as if the Montage Merger had occurred on January 1, 2019, and the Indigo Merger and the GEPH Merger each had occurred on January 1, 2020: For the years ended December 31, (in millions, except per share amounts) 2021 (1) 2020 2019 Revenues $ 8,301 $ 3,836 $ 3,673 Net income (loss) attributable to common stock $ (354) $ (3,243) $ 995 Net income (loss) attributable to common stock per share – basic $ (0.32) $ (2.92) $ 1.48 Net income (loss) attributable to common stock per share – diluted $ (0.32) $ (2.92) $ 1.48 (1) The year ended December 31, 2021 includes the actual operating results from the Montage Merger, which occurred in November 2020.
Schedule of Acquisition Related Costs	The following table summarizes the merger-related expenses incurred for the years ended December 31, 2021 and 2020: For the years ended December 31, 2021 2020 (in millions) Indigo GEPH Montage Total Montage Professional fees (bank, legal, consulting) $ 27 $ 19 $ 1 $ 47 $ 18 Representation & warranty insurance 4 7 — 11 — Contract buyouts, terminations and transfers 7 1 — 8 5 Due diligence and environmental 3 1 — 4 — Employee-related 2 — 1 3 17 Other 2 — 1 3 1 Total merger-related expenses $ 45 $ 28 $ 3 $ 76 $ 41

Restructuring Charges (Tables)

Restructuring Charges (Tables)	12 Months Ended
	Dec. 31, 2021
Restructuring and Related Activities [Abstract]
Summary of Restructuring Charges	The following table presents a summary of the restructuring charges included in Operating Income for the years ended December 31, 2021, 2020 and 2019: For the years ended December 31, (in millions) 2021 2020 2019 Severance (including payroll taxes) $ 7 $ 16 $ 5 Office consolidation — — 6 Total restructuring charges (1) $ 7 $ 16 $ 11 (1) All restructuring charges were recorded on the Company's E&P segment for all years presented.
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, 2021, which are reflected in accounts payable on the consolidated balance sheet: (in millions) Liability at December 31, 2020 $ 3 Additions 7 Distributions (10) Liability at December 31, 2021 $ —

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Disclosure of Lease Costs	The components of lease costs are shown below: For the years ended December 31, (in millions) 2021 2020 2019 Operating lease cost $ 54 $ 48 $ 45 Short-term lease cost 15 35 45 Variable lease cost 3 3 1 Total lease cost $ 72 $ 86 $ 91 Supplemental cash flow information related to leases is set forth below: For the years ended December 31, (in millions) 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 53 $ 47 $ 47 Right-of-use assets obtained in exchange for operating liabilities: Operating leases $ 73 $ 48 $ 95
Supplemental Balance Sheet Information	Supplemental balance sheet information related to leases is as follows: (in millions) December 31, 2021 December 31, 2020 Right-of-use asset balance: Operating leases $ 187 $ 163 Lease liability balance: Current operating leases $ 42 $ 42 Long-term operating leases 142 117 Total operating leases $ 184 $ 159 Weighted average remaining lease term: (years) Operating leases 5.5 5.6 Weighted average discount rate: Operating leases 6.77 % 5.97 %
Maturity Analysis of Operating Lease Liabilities	Maturity analysis of operating lease liabilities: (in millions) December 31, 2021 2022 $ 53 2023 42 2024 31 2025 28 2026 25 Thereafter 42 Total undiscounted lease liability 221 Imputed interest (37) Total discounted lease liability $ 184

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue by Segment	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, 2021 Gas sales $ 3,358 $ — $ 54 $ 3,412 Oil sales 389 — 5 394 NGL sales 888 — 2 890 Marketing — 6,186 (4,223) 1,963 Other (1) 5 3 — 8 Total $ 4,640 $ 6,189 $ (4,162) $ 6,667 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 (1) Other E&P revenues consists primarily of gas balancing and water sales to third-party operators, and other marketing revenues consists primarily of sales of gas from storage.
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 Appalachia and Haynesville. For the years ended December 31, (in millions) 2021 2020 2019 Appalachia $ 3,955 $ 1,348 $ 1,700 Haynesville 682 — — Other 3 — 3 Total $ 4,640 $ 1,348 $ 1,703
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, 2021 December 31, 2020 Receivables from contracts with customers $ 1,085 $ 350 Other accounts receivable 75 18 Total accounts receivable $ 1,160 $ 368

Derivatives and Risk Manageme_2

Derivatives and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021: Financial Protection on Production Weighted Average Price per MMBtu Fair value at December 31, 2021 ($ in millions) Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Natural Gas 2022 Fixed price swaps 806 $ 3.08 $ — $ — $ — $ — $ (486) Two-way costless collars 144 — — 2.71 3.14 — (95) Three-way costless collars 347 — 2.06 2.52 2.94 — (286) Total 1,297 $ (867) 2023 Fixed price swaps 489 $ 3.07 $ — $ — $ — $ — $ (143) Two-way costless collars 219 — — 3.03 3.55 — (19) Three-way costless collars 215 — 2.09 2.54 3.00 — (136) Total 923 $ (298) 2024 Fixed price swaps 224 $ 2.96 $ — $ — $ — $ — $ (39) Two-way costless collars 44 $ — $ — $ 3.07 $ 3.53 $ — 4 Three-way costless collars 11 $ — $ 2.25 $ 2.80 $ 3.54 $ — (5) Total 279 $ (40) Basis swaps 2022 322 $ — $ — $ — $ — $ (0.38) $ 68 2023 200 — — — — (0.45) (1) 2024 46 — — — — (0.71) — 2025 9 — — — — (0.64) 1 Total 577 $ 68 Weighted Average Price per Bbl Fair value at December 31, 2021 ($ in millions) Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Oil 2022 Fixed price swaps 3,203 $ 53.54 $ — $ — $ — $ (60) Three-way costless collars 1,380 — 39.89 50.23 57.05 (23) Total 4,583 $ (83) 2023 Fixed price swaps 846 $ 55.98 $ — $ — $ — $ (8) Three-way costless collars 1,268 — 33.97 45.51 56.12 (18) Total 2,114 $ (26) 2024 Fixed price swaps 54 $ 53.15 $ — $ — $ — $ (1) Weighted Average Price per Bbl Fair value at December 31, 2021 ($ in millions) Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Ethane 2022 Fixed price swaps 5,797 $ 11.37 $ — $ — $ — $ (8) Two-way costless collars 135 — — 7.56 9.66 (1) Total 5,932 $ (9) 2023 Fixed price swaps 432 $ 11.67 $ — $ — $ — $ — Propane 2022 Fixed price swaps 6,369 $ 31.14 $ — $ — $ — $ (76) Three-way costless collars 305 $ — $ 16.80 $ 21.00 31.92 (4) Total 6,674 $ (80) 2023 Fixed price swaps 518 $ 33.62 $ — $ — — $ (1) Normal Butane 2022 Fixed price swaps 1,587 $ 32.86 $ — $ — $ — $ (26) 2023 Fixed price swaps 164 $ 37.84 $ — $ — $ — $ — Natural Gasoline 2022 Fixed price swaps 1,840 $ 52.85 $ — $ — $ — $ (33) 2023 Fixed price swaps 157 $ 58.65 $ — $ — $ — $ (1) Other Derivative Contracts Volume (Bcf) Weighted Average Strike Price per MMBtu Fair value at December 31, 2021 ($ in millions) Call Options – Natural Gas (Net) 2022 84 $ 3.01 $ (67) 2023 46 2.94 (33) 2024 9 3.00 (9) Total 139 $ (109) Put Options – Natural Gas 2022 5 $ 2.00 $ — Weighted Average Strike Price per MMBtu Fair value at December 31, 2021 ($ in millions) Storage (1) Volume (Bcf) Swaps Basis Differential 2022 Purchased fixed price swap — $ 2.14 $ — $ — Fixed price swaps 2 2.82 — (1) Basis swaps 1 — (0.57) — Total 3 $ (1) (1) The Company has entered into certain derivatives to protect the value of volumes of natural gas injected into a storage facility that will be withdrawn at a later date.
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, 2021 and 2020: Derivative Assets Balance Sheet Classification Fair Value (in millions) December 31, 2021 December 31, 2020 Derivatives not designated as hedging instruments: Purchased fixed price swaps – natural gas Derivative assets $ — $ 1 Fixed price swaps – natural gas Derivative assets 79 37 Fixed price swaps – oil Derivative assets — 13 Fixed price swaps – ethane Derivative assets 2 — Fixed price swaps – propane Derivative assets 2 — Fixed price swaps – normal butane Derivative assets 1 — Two-way costless collars – natural gas Derivative assets 9 54 Three-way costless collars – natural gas Derivative assets 12 57 Three-way costless collars – oil Derivative assets 1 15 Basis swaps – natural gas Derivative assets 77 60 Call options – natural gas Derivative assets — 4 Fixed price swaps – natural gas Other long-term assets 64 7 Fixed price swaps – oil Other long-term assets — 2 Two-way costless collars – natural gas Other long-term assets 100 20 Three-way costless collars – natural gas Other long-term assets 37 87 Three-way costless collars – oil Other long-term assets 3 15 Basis swaps – natural gas Other long-term assets 22 15 Interest rate swaps Other long-term assets 2 — Total derivative assets $ 411 $ 387 Derivative Liabilities Balance Sheet Classification Fair Value (in millions) December 31, 2021 December 31, 2020 Derivatives not designated as hedging instruments: Fixed price swaps – natural gas storage Derivative liabilities $ 1 $ — Fixed price swaps – natural gas Derivative liabilities 565 7 Fixed price swaps – oil Derivative liabilities 60 12 Fixed price swaps – ethane Derivative liabilities 10 10 Fixed price swaps – propane Derivative liabilities 78 36 Fixed price swaps – normal butane Derivative liabilities 27 8 Fixed price swaps – natural gasoline Derivative liabilities 33 13 Two-way costless collars – natural gas Derivative liabilities 104 43 Two-way costless collars – oil Derivative liabilities — 1 Two-way costless collars – ethane Derivative liabilities 1 — Three-way costless collars – natural gas Derivative liabilities 298 82 Three-way costless collars – oil Derivative liabilities 24 15 Three-way costless collars – propane Derivative liabilities 4 — Basis swaps – natural gas Derivative liabilities 9 3 Call options – natural gas Derivative liabilities 67 12 Put options – natural gas Derivative liabilities — 1 Swaptions – natural gas Derivative liabilities — 2 Fixed price swaps – natural gas Other long-term liabilities 246 3 Fixed price swaps – oil Other long-term liabilities 9 2 Fixed price swaps – propane Other long-term liabilities 1 2 Fixed price swaps – normal butane Other long-term liabilities — 1 Fixed price swaps – natural gasoline Other long-term liabilities 1 2 Two-way costless collars – natural gas Other long-term liabilities 115 21 Two-way costless collars – oil Other long-term liabilities — — Three-way costless collars – natural gas Other long-term liabilities 178 103 Three-way costless collars – oil Other long-term liabilities 21 15 Basis swaps – natural gas Other long-term liabilities 22 7 Call options – natural gas Other long-term liabilities 42 28 Total derivative liabilities $ 1,916 $ 429 Net Derivative Position As of December 31, 2021 2020 (in millions) Net current derivative liabilities $ (1,098) $ (4) Net long-term derivative liabilities (407) (38) Non-performance risk adjustment 3 1 Net total derivative liabilities $ (1,502) $ (41)
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, 2021 and 2020: 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 2021 2020 (in millions) Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ (1) $ 2 Fixed price swaps – natural gas Gain (Loss) on Derivatives (237) (25) Fixed price swaps – oil Gain (Loss) on Derivatives (70) — Fixed price swaps – ethane Gain (Loss) on Derivatives 2 (21) Fixed price swaps – propane Gain (Loss) on Derivatives (40) (60) Fixed price swaps – normal butane Gain (Loss) on Derivatives (18) (9) Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (18) (15) Two-way costless collars – natural gas Gain (Loss) on Derivatives (83) 10 Two-way costless collars – oil Gain (Loss) on Derivatives 1 (1) Two-way costless collars – propane Gain (Loss) on Derivatives — (1) Three-way costless collars – natural gas Gain (Loss) on Derivatives (375) (78) Three-way costless collars – oil Gain (Loss) on Derivatives (41) 3 Three-way costless collars – propane Gain (Loss) on Derivatives (4) — Basis swaps – natural gas Gain (Loss) on Derivatives 3 59 Call options – natural gas Gain (Loss) on Derivatives (68) (10) Call options – oil Gain (Loss) on Derivatives — 1 Put options – natural gas Gain (Loss) on Derivatives 1 — Swaptions – natural gas Gain (Loss) on Derivatives 2 7 Fixed price swaps – natural gas storage Gain (Loss) on Derivatives (1) (1) Interest rate swaps Gain (Loss) on Derivatives 2 — Total loss on unsettled derivatives $ (945) $ (139) 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 2021 2020 (in millions) Purchased fixed price swaps – natural gas Gain (Loss) on Derivatives $ 7 $ (3) Purchased fixed price swaps – oil Gain (Loss) on Derivatives 1 — Fixed price swaps – natural gas Gain (Loss) on Derivatives (418) 142 (2) Fixed price swaps – oil Gain (Loss) on Derivatives (86) 65 Fixed price swaps – ethane Gain (Loss) on Derivatives (39) 6 Fixed price swaps – propane Gain (Loss) on Derivatives (173) 18 Fixed price swaps – normal butane Gain (Loss) on Derivatives (53) (2) Fixed price swaps – natural gasoline Gain (Loss) on Derivatives (59) (1) Two-way costless collars – natural gas Gain (Loss) on Derivatives (325) (5) Two-way costless collars – oil Gain (Loss) on Derivatives (4) 17 Two-way costless collars – propane Gain (Loss) on Derivatives — 2 Two-way costless collars – ethane Gain (Loss) on Derivatives (2) — Three-way costless collars – natural gas Gain (Loss) on Derivatives (335) 38 Three-way costless collars – oil Gain (Loss) on Derivatives (29) 9 Basis swaps – natural gas Gain (Loss) on Derivatives 92 76 Call options – natural gas Gain (Loss) on Derivatives (66) — Call options – oil Gain (Loss) on Derivatives (2) — Put options - natural gas Gain (Loss) on Derivatives (2) (3) — Purchased fixed price swaps – natural gas storage Gain (Loss) on Derivatives 2 (1) Fixed price swaps – natural gas storage Gain (Loss) on Derivatives (1) 2 Interest rate swaps Gain (Loss) on Derivatives — (1) Total gain (loss) on settled derivatives $ (1,492) $ 362 (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 swaps 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 put options for the year ended December 31, 2021, which is included in gain (loss) on derivatives on the consolidated statements of operations. Total Gain (Loss) on Derivatives Recognized in Earnings For the years ended 2021 2020 (in millions) Total loss on unsettled derivatives $ (945) $ (139) Total gain (loss) on settled derivatives (1,492) 362 Non-performance risk adjustment 1 1 Total gain (loss) on derivatives $ (2,436) $ 224

Reclassifications from Accumu_2

Reclassifications from Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Components of Accumulated Other Comprehensive Income (Loss)	In 2021, 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, 2021: For the year ended December 31, 2021 (in millions) Pension and Other Postretirement Foreign Currency Total Beginning balance, December 31, 2020 $ (24) $ (14) $ (38) Other comprehensive income before reclassifications 11 — 11 Amounts reclassified from other comprehensive income (1) 2 — 2 Net current-period other comprehensive income 13 — 13 Ending balance, December 31, 2021 $ (11) $ (14) $ (25) (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, 2021 Pension and other postretirement: (1) (in millions) Amortization of prior service cost and net loss Other income, net $ 1 Settlement loss Other income, net 1 Provision for income taxes (2) — Total reclassifications for the period Net income $ 2 (1) See Note 13 for additional details regarding the Company’s pension and other postretirement benefit plans. (2) As of December 31, 2021, the Company maintained a tax valuation allowance, therefore there was no tax effect on net income.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 were as follows: December 31, 2021 December 31, 2020 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents $ 28 $ 28 $ 13 $ 13 2018 revolving credit facility due April 2024 460 460 700 700 Term Loan B due 2027 550 550 — — Senior notes (1) 4,430 4,745 2,471 2,609 Derivative instruments, net (1,502) (1,502) (41) (41) (1) 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, 2021 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 $ — $ — $ — $ — Fixed price swaps — 148 — 148 Two-way costless collars — 109 — 109 Three-way costless collars — 53 — 53 Basis swaps — 99 — 99 Interest rate swaps — 2 — 2 Liabilities: (1) Fixed price swaps — (1,031) — (1,031) Two-way costless collars — (220) — (220) Three-way costless collars — (525) — (525) Basis swaps — (31) — (31) Call options — (109) — (109) Put options — — — — Swaptions — — — — Total $ — $ (1,505) $ — $ (1,505) (1) Excludes a net reduction to the liability fair value of $3 million related to estimated non-performance risk. December 31, 2020 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: 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: (1) Fixed price swaps — (96) — (96) Two-way costless collars — (65) — (65) Three-way costless collars — (215) — (215) Basis swaps — (10) — (10) Call options — (40) — (40) Put options — (1) — (1) Swaptions — (2) — (2) Total $ — $ (42) $ — $ (42) (1) Excludes a net reduction to the liability fair value of $1 million related to estimated non-performance risk.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Components of Debt	The components of debt as of December 31, 2021 and 2020 consisted of the following: December 31, 2021 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Total Current portion of long-term debt: 4.10% Senior Notes due March 2022 $ 201 $ — $ — $ 201 Variable rate (3.0% at December 31, 2021) Term Loan B due June 2027 $ 5 (1) $ — $ — $ 5 Total current portion of long-term debt $ 206 $ — $ — $ 206 Long-term debt: Variable rate (2.08% at December 31, 2021) 2018 revolving credit facility, due April 2024 $ 460 $ — (2) $ — $ 460 4.95% Senior Notes due January 2025 (3) 389 (1) — 388 Variable rate (3.0% at December 31, 2021) Term Loan B due June 2027 545 (7) (1) 537 7.75% Senior Notes due October 2027 440 (4) — 436 8.375% Senior Notes due September 2028 350 (5) — 345 5.375% Senior Notes due February 2029 700 (6) 25 719 5.375% Senior Notes due March 2030 1,200 (17) — 1,183 4.75% Senior Notes due February 2032 1,150 (17) — 1,133 Total long-term debt $ 5,234 $ (57) $ 24 $ 5,201 Total debt $ 5,440 $ (57) $ 24 $ 5,407 December 31, 2020 (in millions) Debt Instrument Unamortized Issuance Expense Unamortized Total Long-term debt: Variable rate (2.11% at December 31, 2020) 2018 revolving credit facility, due April 2024 $ 700 $ — (2) $ — $ 700 4.10% Senior Notes due March 2022 207 — — 207 4.95% Senior Notes due January 2025 (3) 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 (1) The Term Loan requires quarterly principal repayments of $1.375 million, subject to adjustment for voluntary prepayments, beginning in March 2022. (2) At December 31, 2021 and 2020, unamortized issuance expense of $10 million and $12 million, respectively, associated with the 2018 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheet. (3) 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 their issuance. 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 was paid in January 2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded our bond rating to BB+, which will have the effect of decreasing the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022.
Schedule of Long Term Debt Maturities	The following is a summary of scheduled debt maturities by year as of December 31, 2021 and includes the quarterly Term Loan principal repayments of $1.375 million, subject to adjustment for voluntary prepayments, beginning in March 2022: (in millions) 2022 (1) $ 206 2023 6 2024 (2) 465 2025 395 2026 5 Thereafter 4,363 $ 5,440 (1) In January 2022, the remaining $201 million principal balance on the Senior Notes due 2022 was retired using the Company’s 2018 credit facility. (2) The Company’s 2018 credit facility matures in 2024.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Obligation under Transportation Agreements	As of December 31, 2021, 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 $ 9,584 $ 1,141 $ 1,932 $ 1,731 $ 2,167 $ 2,613 Pending regulatory approval and/or construction (1) 872 3 114 163 249 343 Total transportation charges $ 10,456 $ 1,144 $ 2,046 $ 1,894 $ 2,416 $ 2,956 (1) Based on the estimated in-service dates as of December 31, 2021.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes	The provision (benefit) for income taxes included the following components: (in millions) 2021 2020 2019 Current: Federal $ — $ (2) $ (1) State — — (1) — (2) (2) Deferred: Federal — 371 (431) State — 38 22 — 409 (409) Provision (benefit) for income taxes $ — $ 407 $ (411)
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) 2021 2020 2019 Expected provision (benefit) at federal statutory rate $ (5) $ (568) $ 101 Increase (decrease) resulting from: State income taxes, net of federal income tax effect — (55) 11 Change in valuation allowance 2 1,034 (522) Other 3 (4) (1) Provision (benefit) for income taxes $ — $ 407 $ (411)
Components of Deferred Tax Balances	The components of the Company’s deferred tax balances as of December 31, 2021 and 2020 were as follows: (in millions) 2021 2020 Deferred tax liabilities: Right of use lease asset $ 45 $ 38 Other 3 2 48 40 Deferred tax assets: Differences between book and tax basis of property — 295 Accrued compensation 44 38 Accrued pension costs 6 11 Asset retirement obligations 25 20 Net operating loss carryforward 585 1,117 Future lease payments 46 38 Derivative activity 362 9 Capital loss carryover 28 27 Other 31 24 1,127 1,579 Valuation allowance (1,079) (1,539) Net deferred tax asset $ — $ —
Reconciliation of Changes to the Valuation Allowance	A reconciliation of the changes to the valuation allowance is as follows: (in millions) 2021 2020 Valuation allowance at beginning of year $ 1,539 $ 87 Establishment of valuation allowance on opening deferred balance — 408 Return to accrual adjustments (31) 6 Current period deferred activity (1) 626 Reduction due to 382 limitations on NOLs (428) (120) Purchase accounting — 532 Valuation allowance at end of year $ 1,079 $ 1,539

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation [Abstract]
Schedule of Asset Retirement Obligations	The following table summarizes the Company’s 2021 and 2020 activity related to asset retirement obligations: (in millions) 2021 2020 Asset retirement obligation at January 1 $ 85 $ 57 Accretion of discount 6 4 Obligations incurred 1 1 Obligations assumed through mergers 36 28 Obligations settled/removed (20) (6) Revisions of estimates 1 1 Asset retirement obligation at December 31 $ 109 $ 85 Current liability $ 4 $ 4 Long-term liability 105 81 Asset retirement obligation at December 31 $ 109 $ 85

Retirement and Employee Benef_2

Retirement and Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020: Pension Benefits Other Postretirement Benefits (in millions) 2021 2020 2021 2020 Change in benefit obligations: Benefit obligation at January 1 $ 139 $ 126 $ 13 $ 13 Service cost (1) — 7 2 2 Interest cost 4 5 — — Participant contributions — — — — Actuarial (gain) loss (4) 16 (2) 1 Benefits paid (2) (13) — (1) Plan amendments — — — (2) Curtailments — (2) — — Settlements (11) — — — Benefit obligation at December 31 $ 126 $ 139 $ 13 $ 13 (1) The Company froze its pension plan effective January 1, 2021, resulting in no service cost for the year ended December 31, 2021. Pension Benefits Other Postretirement Benefits (in millions) 2021 2020 2021 2020 Change in plan assets: Fair value of plan assets at January 1 $ 106 $ 96 $ — $ — Actual return on plan assets 6 11 — — Employer contributions 12 12 1 1 Participant contributions — — — — Benefits paid (2) (13) (1) (1) Settlements (8) — — — Fair value of plan assets at December 31 $ 114 $ 106 $ — $ — Funded status of plans at December 31 (1) $ (12) $ (33) $ (13) $ (13) (1) The funded status of the pension plan includes a $1 million liability related to a supplemental employee retirement plan as of December 31, 2021 and 2020.
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, 2021 and 2020 are as follows: (in millions) 2021 2020 Projected benefit obligation $ 126 $ 139 Accumulated benefit obligation 126 139 Fair value of plan assets 114 106
Pension and Other Postretirement Benefit Costs	Pension and other postretirement benefit costs include the following components for 2021, 2020 and 2019: Pension Benefits Other Postretirement Benefits (in millions) 2021 2020 2019 2021 2020 2019 Service cost (1) $ — $ 7 $ 7 $ 2 $ 2 $ 1 Interest cost 4 5 5 — — — Expected return on plan assets (4) (6) (6) — — — Amortization of transition obligation — — — — — — Amortization of prior service cost — — — — — — Amortization of net loss — 1 2 — — — Net periodic benefit cost — 7 8 2 2 1 Curtailment gain — — — — — — Settlement loss 2 — 6 — — — Total benefit cost $ 2 $ 7 $ 14 $ 2 $ 2 $ 1 (1) The Company froze its pension plan effective January 1, 2021, resulting in no service cost for the year ended December 31, 2021.
Amounts Recognized in Other Comprehensive Income	Amounts recognized in other comprehensive income for the years ended December 31, 2021 and 2020 were as follows: Pension Benefits Other Postretirement Benefits (in millions) 2021 2020 2021 2020 Net actuarial (loss) gain arising during the year $ 5 $ (12) $ 2 $ 2 Amortization of prior service cost — — — — Amortization of net loss 1 1 — — Settlements 5 — — — Curtailments — 3 — — Less: Tax effect (1) — 3 — (1) Amounts recognized in other comprehensive income $ 11 $ (5) $ 2 $ 1 (1) Pension and other postretirement benefit tax effects of $2.7 million and $0.4 million, respectively, for the year ended December 31, 2021, were netted against a valuation allowance and therefore included in accumulated other comprehensive income.
Schedule of Assumptions Used	The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2021 and 2020 are as follows: Pension Benefits Other Postretirement Benefits 2021 2020 2021 2020 Discount rate 3.20 % 3.10 % 3.10 % 2.80 % 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 2021, 2020 and 2019 are as follows: Pension Benefits Other Postretirement Benefits 2021 2020 2019 2021 2020 2019 Discount rate 3.20 % 3.70 % 3.70 % 2.80 % 3.50 % 4.35 % Expected return on plan assets 0.10 % 6.50 % 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 2021 and 2020: 2021 2020 Health care cost trend assumed for next year 6.5 % 6.5 % Rate to which the cost trend is assumed to decline 5.0 % 5.0 % Year that the rate reaches the ultimate trend rate 2038 2037
Schedule of Expected Benefit Payments	The following timeline reflects the Company’s current estimate of benefit payments to be made and the timing thereof, including projected future interest costs: Pension Benefits Other Postretirement Benefits (in millions) (in millions) 2022 $ 48 2022 $ 1 2023 70 2023 1 2024 — 2024 1 2025 — 2025 1 2026 — 2026 1 Years 2027-2031 — Years 2027-2031 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 Fixed income (1) 78 % 78 % Cash (2) 22 % 22 % Total 100 % 100 % (1) Includes fixed income pension plan assets in the table below. (2) 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, 2021 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 Fixed income (1) 90 90 — — Cash and cash equivalents 24 24 — — Total plan assets at fair value $ 114 $ 114 $ — $ — (1) U.S. Treasury Notes. Utilizing the fair value hierarchy described in Note 8 , the Company’s fair value measurement of pension plan assets at December 31, 2020 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 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 (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.

Long-Term Incentive Compensat_2

Long-Term Incentive Compensation (Tables)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Schedule of Equity-Classified Stock-Based Compensation Costs	The Company recorded the following costs related to long-term incentive compensation for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Long-term incentive compensation – expensed $ 30 $ 17 $ 17 Long-term incentive compensation – capitalized 18 7 10 The Company recorded the following compensation costs related to equity-classified stock options for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Stock options – general and administrative expense $ — $ — $ 1 Stock options – capitalized expense $ — $ — $ — The Company recorded the following compensation costs related to equity-classified restricted stock grants for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Restricted stock grants – general and administrative expense $ 2 $ 3 $ 6 Restricted stock grants – capitalized expense $ — $ 1 $ 4 (in millions) 2021 2020 2019 Performance units – general and administrative expense $ — $ — $ 1 Performance units – capitalized expense $ — $ — $ — The Company recorded the following compensation costs related to performance cash awards for the years ended December 31, 2021 and 2020: (in millions) 2021 2020 Performance cash awards – general and administrative expense $ 4 $ 2 Performance cash awards – capitalized expense $ 4 $ 2
Summary of Equity-Classified Stock Option Activity	The following tables summarize stock option activity for the years 2021, 2020 and 2019, and provide information for options outstanding at December 31 of each year: 2021 2020 2019 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 3,850 $ 13.39 4,635 $ 15.26 5,178 $ 17.06 Granted — $ — — $ — — $ — Exercised — $ — — $ — — $ — Forfeited or expired (844) $ 29.10 (785) $ 24.46 (543) $ 32.38 Options outstanding at December 31 3,006 $ 8.98 3,850 $ 13.39 4,635 $ 15.26
Summary of Stock Options Outstanding and Options Exercisable	Options Outstanding Options Exercisable Range of Exercise Prices Options Outstanding at December 31, 2021 Weighted Average Exercise Price Weighted Average Remaining Contractual Life Options Exercisable at December 31, 2021 Weighted Average Exercise Price Weighted Average Remaining Contractual Life (in thousands) (years) (in thousands) (years) $7.74-$29.42 3,006 $ 8.98 1.3 3,006 $ 8.98 1.3
Summary of Equity-Classified Restricted Stock Activity	The following table summarizes the restricted stock activity for the years 2021, 2020 and 2019, and provides information for restricted stock outstanding at December 31 of each year: 2021 2020 2019 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 1 697 $ 5.97 1,480 $ 7.00 2,717 $ 7.91 Granted 438 $ 5.18 584 $ 2.86 493 $ 3.06 Vested (893) $ 5.81 (1,098) $ 5.26 (1,516) $ 7.16 Forfeited — $ 8.59 (269) (1) $ 7.79 (214) (2) $ 8.38 Unvested shares at December 31 242 $ 5.12 697 $ 5.97 1,480 $ 7.00 (1) Includes 171,813 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2020. (2) Includes 65,196 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2019. The following table summarizes equity-classified restricted stock unit activity to be paid out in Company stock for the years ended December 31, 2021 and 2020. 2021 2020 Number Weighted Average Number Weighted Average (in thousands) (in thousands) Unvested Units at January 1 134 $ 3.05 — $ — Granted — $ — 186 $ 3.05 Vested (92) $ 3.05 (42) $ 3.05 Forfeited (5) $ 3.05 (10) $ 3.05 Unvested Units at December 31 37 $ 3.05 134 $ 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, 2021, 2020 and 2019, and provides information for unvested units as of December 31, 2021, 2020 and 2019: 2021 2020 2019 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 Granted — $ — — $ — — $ — Vested — $ — (178) $ 10.47 (378) $ 9.59 Forfeited — $ — — $ — (42) (2) $ 10.47 Unvested shares at December 31 — $ — — $ — 178 $ 10.47 (1) These amounts reflect the number of performance units granted in thousands. The actual payout of shares ranged from a minimum of zero shares to a maximum of two shares per unit contingent upon TSR. The performance units had a three-year vesting term and the actual disbursement of shares, if any, was determined during the first quarter following the end of the three-year vesting period. (2) Included 41,761 units related to the reduction in workforce for the year ended December 31, 2019.
Schedule of Liability-Classified Stock-Based Compensation Costs	The Company recorded the following compensation costs related to liability-classified restricted stock unit grants for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Restricted stock units – general and administrative expense $ 12 $ 5 $ 7 Restricted stock units – capitalized expense $ 8 $ 2 $ 5 The Company recorded the following compensation costs related to liability-classified performance unit grants for the years ended December 31, 2021, 2020 and 2019: (in millions) 2021 2020 2019 Liability-classified performance units – general and administrative expense $ 12 $ 7 $ 2 Liability-classified performance units – capitalized expense $ 6 $ 2 $ 1
Summary of Liability-Classified Restricted Stock Unit Activity	The following table summarizes restricted stock unit activity to be paid out in cash or Company stock for the years ended December 31, 2021, 2020 and 2019 and provides information for unvested units as of December 31, 2021, 2020 and 2019: 2021 2020 2019 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 11,613 $ 2.67 12,992 $ 2.42 8,202 $ 3.41 Granted 1,486 $ 4.23 6,172 $ 1.41 8,659 $ 4.34 Vested (4,522) $ 3.40 (3,960) $ 1.43 (2,624) $ 4.09 Forfeited (640) (1) $ 4.56 (3,591) (2) $ 2.67 (1,245) (3) $ 3.48 Unvested units at December 31 7,937 $ 4.08 11,613 $ 2.67 12,992 $ 2.42 (1) Includes 360,253 units related to the reduction in workforce for the year ended December 31, 2021. (2) Includes 2,010,196 units related to the reduction in workforce for the year ended December 31, 2020. (3) Includes 400,056 units related to the reduction in workforce for the year ended December 31, 2019.
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, 2021, 2020 and 2019 and provides information for unvested units as of December 31, 2021, 2020 and 2019: 2021 2020 2019 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) (in thousands) Unvested units at January 1 8,699 $ 2.57 5,142 $ 2.42 2,803 $ 3.41 Granted 3,580 $ 4.14 6,172 $ 1.41 2,757 $ 4.34 Vested (2,020) $ 4.05 — $ — (43) $ 2.42 Forfeited (744) $ 3.40 (2,615) (1) $ 3.05 (375) (2) $ 3.12 Unvested units at December 31 9,515 $ 2.88 8,699 $ 2.57 5,142 $ 2.42 (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.
Share-based Compensation, Liability-based Restricted Cash Units Nonvested Activity	The following table summarizes performance cash award activity to be paid out in cash for the years ended December 31, 2021 and 2020 and provides information for unvested units as of December 31, 2021 and 2020: 2021 2020 Number Weighted Average Number Weighted Average (in thousands) (in thousands) Unvested units at January 1 18,353 $ 1.00 — $ — Granted 18,546 $ 1.00 20,044 $ 1.00 Vested (4,955) $ 1.00 (100) $ 1.00 Forfeited (3,672) (1) $ 1.00 (1,591) (2) $ 1.00 Unvested Units at December 31 28,272 $ 1.00 18,353 $ 1.00 (1) Includes 1,241,000 units related to the reduction in workforce for the year ended December 31, 2021 . (2) Includes 945,500 units related to the reduction in workforce for the year ended December 31, 2020.

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 Revenues from external customers $ 4,701 $ 1,966 $ — $ 6,667 Intersegment revenues (61) 4,223 — 4,162 Depreciation, depletion and amortization expense 537 9 — 546 Impairments 6 — — 6 Operating income 2,583 (1) 52 — 2,635 Interest expense (2) 136 — — 136 Gain (loss) on derivatives (2,437) — 1 (2,436) Loss on early extinguishment of debt — — (93) (93) Other income, net 5 — — 5 Provision for income taxes (2) — — — — Assets 10,767 (3) 956 125 11,848 Capital investments (4) 1,107 — 1 1,108 (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) (5) (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 (7) — 16 Operating income (loss) 283 (6) (13) — 270 Interest expense (2) 65 — — 65 Gain on derivatives 274 — — 274 Gain on early extinguishment of debt — — 8 8 Other income (loss) (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 (1) Operating income for the E&P segment includes $7 million of restructuring charges and $76 million of acquisition-related charges for the year ended December 31, 2021. (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 an increase of $70 million for 2021, a decrease of $3 million for 2020 and an increase of $34 million for 2019 related to the change in accrued expenditures between years. (5) 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. (6) Operating income for the E&P segment includes $11 million of restructuring charges for the year ended December 31, 2019. (7) Marketing includes a $3 million non-cash impairment related to certain non-core midstream gathering assets at December 31, 2019. 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, 2021, 2020 and 2019: For the years ended December 31, (in millions) 2021 2020 2019 Cash and cash equivalents $ 28 $ 13 $ 5 Accounts receivable — 1 — Income taxes receivable — — 30 Prepayments 6 6 8 Property, plant and equipment 12 16 27 Unamortized debt expense 10 11 11 Right-of-use lease assets 65 72 80 Non-qualified retirement plan 4 6 7 $ 125 $ 125 $ 168

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020: (in millions) 2021 2020 Proved properties $ 31,400 $ 25,789 Unproved properties 2,231 1,472 Total capitalized costs 33,631 27,261 Less: Accumulated depreciation, depletion and amortization (23,884) (23,362) Net capitalized costs $ 9,747 $ 3,899
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, 2021: (in millions) 2021 2020 2019 Prior Total Property acquisition costs $ 784 $ 85 $ 9 $ 1,079 $ 1,957 Exploration and development costs 28 9 7 10 54 Capitalized interest 75 48 36 61 220 $ 887 $ 142 $ 52 $ 1,150 $ 2,231
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) 2021 2020 2019 Unproved property acquisition costs $ 139 $ 124 (1) $ 162 Exploration costs — — 2 Development costs 984 784 936 Capitalized costs incurred $ 1,123 $ 908 $ 1,100 Full cost pool amortization per Mcfe $ 0.42 $ 0.38 $ 0.56 (1) Excluded $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) 2021 2020 2019 Sales $ 4,640 $ 1,348 $ 1,703 Production (lifting) costs (1,304) (866) (781) Depreciation, depletion and amortization (537) (348) (462) Impairment of natural gas and oil properties — (2,825) — 2,799 (2,691) 460 Provision for income taxes (1) — — 110 Results of operations (2) $ 2,799 $ (2,691) $ 350 (1) Prior to the recognition of a valuation allowance, in 2020 the Company recognized an income tax benefit of $624 million. (2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 6 .
Summary of Changes in Reserves	The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2019, 2020 and 2021, all of which were located in the United States: Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) 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 (1) 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 (2) 1,911 18,796 55,141 2,354 Disposition of reserves in place — — — — December 31, 2020 9,181 58,024 410,151 11,990 Revisions of previous estimates due to price (3) 501 1,414 (15,525) 415 Revisions of previous estimates other than price 248 1,900 1,500 269 Extensions, discoveries and other additions 2,543 24,865 211,598 3,962 Production (1,015) (6,610) (30,940) (1,240) Acquisition of reserves in place (4) 5,750 247 180 5,753 Disposition of reserves in place (1) (61) — (1) December 31, 2021 17,207 79,779 576,964 21,148 (1) 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. (2) The 2020 acquisition amounts are primarily associated with the Montage Merger. (3) The 15,525 MBbl reduction in NGL volumes for 2021 is the result of changes to the Company’s five-year development plan and elections to retain ethane in the natural gas stream in line with ethane transportation contracts. This election is driven by commodity pricing, whereby higher natural gas pricing relative to ethane pricing creates a more economically favorable position. (4) The 2021 acquisition amounts are primarily associated with the Indigo Merger and the GEPH Merger. Natural Gas (Bcf) Oil (MBbls) NGL (MBbls) Total (Bcfe) Proved developed reserves as of: December 31, 2019 4,906 26,124 226,271 6,421 December 31, 2020 6,342 33,563 276,548 8,203 December 31, 2021 9,308 40,930 296,832 11,335 Proved undeveloped reserves as of: December 31, 2019 3,724 46,801 382,490 6,300 December 31, 2020 2,839 24,461 133,603 3,787 December 31, 2021 7,899 38,849 280,132 9,813 The following table summarizes the changes in reserves for 2019, 2020 and 2021: (in Bcfe) Appalachia Haynesville Other (1) Total December 31, 2018 11,920 — 1 11,921 Net revisions Price revisions (717) — — (717) Performance and production revisions (2) 1,102 — — 1,102 Total net revisions 385 — — 385 Extensions, discoveries and other additions Proved developed 191 — — 191 Proved undeveloped 1,004 — — 1,004 Total reserve additions 1,195 — — 1,195 Production (778) — — (778) Acquisition of reserves in place — — — — Disposition of reserves in place (2) — — (2) December 31, 2019 12,720 — 1 12,721 Net revisions Price revisions (4,370) — — (4,370) Performance and production revisions 1,424 — — 1,424 Total net revisions (2,946) — — (2,946) Extensions, discoveries and other additions Proved developed 267 — — 267 Proved undeveloped 474 — — 474 Total reserve additions 741 — — 741 Production (880) — — (880) Acquisition of reserves in place 2,354 — — 2,354 Disposition of reserves in place — — — — December 31, 2020 11,989 — 1 11,990 Net revisions Price revisions 415 — — 415 Performance and production revisions 270 — (1) 269 Total net revisions 685 — (1) 684 Extensions, discoveries and other additions Proved developed 451 — — 451 Proved undeveloped (3) 3,511 — — 3,511 Total reserve additions 3,962 — — 3,962 Production (1,108) (132) — (1,240) Acquisition of reserves in place — 5,753 — 5,753 Disposition of reserves in place (1) — — (1) December 31, 2021 15,527 5,621 — 21,148 (1) Other includes properties outside of Appalachia and Haynesville. (2) 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. (3) For the year ended December 31, 2021, net extensions, discoveries and other additions in proved undeveloped reserves of 3,511 Bcfe was comprised of 1,768 Bcfe resulting from the addition of new undeveloped locations throughout the year through the Company’s successful drilling program and 1,743 Bcfe which was attributable to undeveloped locations which were uneconomical under prior year SEC pricing (and therefore excluded from prior year reserves) but which have become economical under current SEC pricing.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	The following standardized measure of discounted future net cash flows relating to proved natural gas, oil and NGL reserves as of December 31, 2021, 2020 and 2019 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) 2021 2020 2019 Future cash inflows $ 75,314 $ 17,997 $ 27,003 Future production costs (23,235) (11,969) (14,981) Future development costs (1) (6,032) (1,924) (3,246) Future income tax expense (8,135) — (476) Future net cash flows 37,912 4,104 8,300 10% annual discount for estimated timing of cash flows (19,181) (2,257) (4,600) Standardized measure of discounted future net cash flows $ 18,731 $ 1,847 $ 3,700 (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: 2021 2020 2019 Natural gas (per MMBtu) $ 3.60 $ 1.98 $ 2.58 Oil (per Bbl) 66.56 39.57 55.69 NGLs (per Bbl) 28.65 10.27 11.58
Schedule of Analysis of Changes in Standardized Measure	Following is an analysis of changes in the standardized measure during 2021, 2020 and 2019: (in millions) 2021 2020 2019 Standardized measure, beginning of year $ 1,847 $ 3,700 $ 5,999 Sales and transfers of natural gas and oil produced, net of production costs (3,332) (478) (923) Net changes in prices and production costs 10,417 (2,720) (3,510) Extensions, discoveries, and other additions, net of future production and development costs 3,183 81 234 Acquisition of reserves in place 6,499 443 — Sales of reserves in place (1) — (2) Revisions of previous quantity estimates 596 (987) 152 Net change in income taxes (3,689) 35 491 Changes in estimated future development costs 137 1,241 621 Previously estimated development costs incurred during the year 419 624 704 Changes in production rates (timing) and other 2,470 (466) (718) Accretion of discount 185 374 652 Standardized measure, end of year $ 18,731 $ 1,847 $ 3,700

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies (Narrative) (Details)	Dec. 31, 2021USD ($)$ / sharesshares	Sep. 01, 2021USD ($)$ / sharesshares	Nov. 13, 2020USD ($)$ / sharesshares	Sep. 30, 2021USD ($)shares	Aug. 31, 2020USD ($)$ / sharesshares	Dec. 31, 2021USD ($)segmentsubsidiary$ / sharesshares	Dec. 31, 2020USD ($)subsidiaryshares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of segments | segment						2
Cash and cash equivalents	$ 28,000,000					$ 28,000,000	$ 13,000,000
Outstanding checks included in accounts payable	21,000,000					$ 21,000,000	16,000,000
Natural gas, oil and NGL reserves discount						10.00%
Net book value adjusted for market differentials							2,825,000,000
Impairments						$ 6,000,000	2,830,000,000	$ 16,000,000
Net unevaluated costs excluded from amortization, cumulative	2,231,000,000					2,231,000,000	1,472,000,000
Other long-term assets	$ 84,000,000					$ 84,000,000	$ 69,000,000
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	2,035					2,035	3,632
Marketing-Related Intangible Assets
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Intangible assets, current	$ 48,000,000					$ 48,000,000	$ 57,000,000
Other long-term assets	43,000,000					43,000,000	48,000,000
Amortization of intangible asset						8,000,000	9,000,000	$ 9,000,000
Expected amortization in year one	5,000,000					5,000,000
Expected amortization in year two	5,000,000					5,000,000
Expected amortization in year three	5,000,000					5,000,000
Expected amortization in year four	5,000,000					5,000,000
Expected amortization in year five	$ 5,000,000					5,000,000
WPX Property Acquisition
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Percentage of interest acquired										86.00%
GEPH Merger
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares) | shares	99,337,748
Total consideration (fair value of Southwestern common shares issued)	$ 463,000,000					$ 463,000,000
Offering price (in dollars per share) | $ / shares	$ 4.66					$ 4.66
GEPH Merger | Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares) | shares						99,337,748
Total consideration (fair value of Southwestern common shares issued)	$ 463,000,000					$ 463,000,000
Offering price (in dollars per share) | $ / shares	$ 4.66					$ 4.66
Indigo Natural Resources, LLC
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares) | shares		337,827,171
Total consideration (fair value of Southwestern common shares issued)		$ 1,588,000,000
Offering price (in dollars per share) | $ / shares		$ 4.70
Indigo Natural Resources, LLC | Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares) | shares				337,827,171
Total consideration (fair value of Southwestern common shares issued)				$ 1,588,000,000
Offering price (in dollars per share) | $ / shares		$ 4.70
Montage Resources Corporation
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Impairments						$ 0	0
Unamortized cost of properties acquired							1,087,000,000
Net unevaluated costs excluded from amortization, cumulative	$ 117,000,000					$ 117,000,000
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares) | shares			69,740,848
Total consideration (fair value of Southwestern common shares issued)			$ 213,000,000
Offering price (in dollars per share) | $ / shares			$ 3.05		$ 2.50
Number of Southwestern Energy common stock for each share of common stock converted (in shares) | shares			1.8656
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]
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares) | shares			69,740,848
Total consideration (fair value of Southwestern common shares issued)			$ 213,000,000
Offering price (in dollars per share) | $ / shares			$ 3.05
Number of Southwestern Energy common stock for each share of common stock converted (in shares) | shares			1.8656
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
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						$ 6,000,000	$ 5,000,000
Revenue Benchmark | Customer concentration risk | One Customer
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of subsidiaries of major customer with which business is conducted | subsidiary						1	1
Concentration percentage						12.00%	10.00%

Organization and Summary of S_5

Organization and Summary of Significant Accounting Policies (Summary of Other Property and Equipment) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)	Dec. 31, 2021USD ($)$ / MMBTU	Dec. 31, 2021USD ($)$ / barrel	Dec. 31, 2021USD ($)$ / bbl	Dec. 31, 2020USD ($)$ / MMBTU	Dec. 31, 2020USD ($)$ / barrel	Dec. 31, 2020USD ($)$ / bbl	Dec. 31, 2019$ / MMBTU	Dec. 31, 2019$ / barrel	Dec. 31, 2019$ / bbl
Property, Plant and Equipment [Line Items]
Oil and Gas Property, Full Cost Method, Gross	$ 33,631	$ 33,631	$ 33,631	$ 33,631	$ 27,261	$ 27,261	$ 27,261
Less: Accumulated depreciation and impairment	(319)	(319)	(319)	(319)	(311)	(311)	(311)
Total	190	190	190	190	212	212	212
Water facilities
Property, Plant and Equipment [Line Items]
Oil and Gas Property, Full Cost Method, Gross	$ 237	237	237	237	228	228	228
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]
Oil and Gas Property, Full Cost Method, Gross	$ 56	56	56	56	54	54	54
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]
Oil and Gas Property, Full Cost Method, Gross	$ 135	135	135	135	133	133	133
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
Oil and Gas Property, Full Cost Method, Gross	$ 28	28	28	28	26	26	26
Land, buildings and leasehold improvements
Property, Plant and Equipment [Line Items]
Oil and Gas Property, Full Cost Method, Gross	$ 16	16	16	16	41	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]
Oil and Gas Property, Full Cost Method, Gross	$ 37	$ 37	$ 37	$ 37	$ 41	$ 41	$ 41
Natural Gas
Property, Plant and Equipment [Line Items]
Average sales price ($ per unit) | $ / MMBTU		3.60			1.98			2.58
Oil
Property, Plant and Equipment [Line Items]
Average sales price ($ per unit)			66.56	66.56		39.57	39.57		55.69	55.69
NGL
Property, Plant and Equipment [Line Items]
Average sales price ($ per unit)			28.65	28.65		10.27	10.27		11.58	11.58

Organization and Summary of S_6

Organization and Summary of Significant Accounting Policies (Schedule of Earnings Per Share) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share [Line Items]
Net income (loss)	$ (25)	$ (3,112)	$ 891
Number of common shares:
Weighted average outstanding (in shares)	789,657,776	573,889,502	539,345,343
Weighted average and potential dilutive outstanding (in shares)	789,657,776	573,889,502	540,382,914
Basic (in dollars per share)	$ (0.03)	$ (5.42)	$ 1.65
Diluted (in dollars per share)	$ (0.03)	$ (5.42)	$ 1.65
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	0	361,380
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	0	676,191

Organization and Summary of S_7

Organization and Summary of Significant Accounting Policies (Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share) (Details) - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	8,937,810	12,661,231	7,077,785
Unexercised stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	3,683,363	4,427,040	5,078,253
Unvested share-based payment
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	832,989	962,662	1,728,264
Restricted units
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	2,226,981	4,452,876	0
Performance units
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities excluded from computation of earnings per share (in shares)	2,194,477	2,818,653	271,268

Organization and Summary of S_8

Organization and Summary of Significant Accounting Policies (Schedule of Supplemental Disclosures of Cash Flow Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Cash paid during the year for interest, net of amounts capitalized	$ 106	$ 75	$ 58
Cash paid (received) during the year for income taxes	0	(32)	(52)
Non-cash investing activities	3,690	1,084	41
Non-cash financing activities	2,051	213	$ 0
Indigo Natural Resources, LLC
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Non-cash investing activities	3,039
GEPH Merger
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Non-cash investing activities	$ 575
Montage Resources Corporation
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Non-cash investing activities		$ 1,097

Acquisition and Divestitures -

Acquisition and Divestitures - (Acquisition Narrative) (Details) - USD ($)	Dec. 31, 2021	Sep. 01, 2021	Nov. 13, 2020	Aug. 31, 2020	Dec. 31, 2020	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Nov. 30, 2021
Business Acquisition [Line Items]
Cash consideration							$ 1,642,000,000	$ 0	$ 0
Long-term debt	$ 5,407,000,000				$ 3,150,000,000	$ 5,407,000,000	5,407,000,000	$ 3,150,000,000
Obligation under transportation agreements	10,456,000,000					10,456,000,000	10,456,000,000
Indigo Agreement
Business Acquisition [Line Items]
Obligation under transportation agreements	36,000,000					36,000,000	36,000,000
Liability for the estimated future payments	17,000,000					17,000,000	17,000,000
Purchase or volume commitments with gathering fresh water and sand
Business Acquisition [Line Items]
Obligation under transportation agreements	74,000,000					74,000,000	$ 74,000,000
Minimum
Business Acquisition [Line Items]
Contractual commitments payments, term (in years)							2 years
Maximum
Business Acquisition [Line Items]
Contractual commitments payments, term (in years)							7 years
Indigo Natural Resources, LLC
Business Acquisition [Line Items]
Cash consideration		$ 373,000,000
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares)		337,827,171
Value of Southwestern's stock issued as consideration		$ 1,588,000,000
NYSE closing price per share of Southwestern common shares (in dollars per share)		$ 4.70
Revolving credit facility		$ 95,000,000
Evaluated natural gas and oil properties		2,724,000,000
Unevaluated natural gas and oil properties		684,000,000
Other property, plant and equipment		4,000,000
Operating revenues acquired through the merger						682,000,000
Operating income acquired through the merger						472,000,000
Senior unsecured notes		$ 726,000,000
Montage Resources Corporation
Business Acquisition [Line Items]
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares)			69,740,848
Value of Southwestern's stock issued as consideration			$ 213,000,000
NYSE closing price per share of Southwestern common shares (in dollars per share)			$ 3.05	$ 2.50
Revolving credit facility			$ 200,000,000
Evaluated natural gas and oil properties			1,012,000,000
Unevaluated natural gas and oil properties			100,000,000
Other property, plant and equipment			28,000,000
Operating revenues acquired through the merger					63,000,000
Operating income acquired through the merger					$ 28,000,000
Senior unsecured notes			$ 522,000,000
Number of Southwestern Energy common stock for each share of common stock converted (in shares)			1.8656
Proved property acquired			$ 1,012,000,000
Unproved property acquired			$ 100,000,000
Montage Resources Corporation | Public Stock Offering
Business Acquisition [Line Items]
Underwritten public offering of common stock (in shares)				63,250,000
Net proceeds from public offering				$ 152,000,000
GEPH Merger
Business Acquisition [Line Items]
Cash consideration	$ 1,269,000,000
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares)	99,337,748
Value of Southwestern's stock issued as consideration	$ 463,000,000					$ 463,000,000	$ 463,000,000
NYSE closing price per share of Southwestern common shares (in dollars per share)	$ 4.66					$ 4.66	$ 4.66
Revolving credit facility	$ 81,000,000					$ 81,000,000	$ 81,000,000
Evaluated natural gas and oil properties	1,783,000,000					1,783,000,000	1,783,000,000
Unevaluated natural gas and oil properties	59,000,000					59,000,000	59,000,000
Other property, plant and equipment	2,000,000					$ 2,000,000	$ 2,000,000
Operating revenues acquired through the merger	0
Operating income acquired through the merger	$ 0
Senior Notes | 5.375% Senior Notes due February 2029
Business Acquisition [Line Items]
Stated interest rate	5.375%	5.375%				5.375%	5.375%
Long-term debt		$ 700,000,000								$ 700,000,000
Senior Notes | 8.375% Senior Notes due September 2028
Business Acquisition [Line Items]
Stated interest rate	8.375%				8.375%	8.375%	8.375%	8.375%
Long-term debt					$ 345,000,000			$ 345,000,000
Senior notes				$ 350,000,000
Senior Notes | Montage Resources Corporation | Eight Point Eight Seven Five Percent Senior Notes Due 2023
Business Acquisition [Line Items]
Stated interest rate				8.875%
Senior notes				$ 510,000,000
Senior Notes | Indigo Natural Resources, LLC | 5.375% Senior Notes due February 2029
Business Acquisition [Line Items]
Senior note assumed in merger agreement		$ 700,000,000
Stated interest rate		5.375%
Senior Notes | Montage Resources Corporation | 8.375% Senior Notes due September 2028
Business Acquisition [Line Items]
Stated interest rate				8.375%
Senior notes				$ 350,000,000

Acquisitions and Divestitures -

Acquisitions and Divestitures - (Schedule of Consideration Paid to Equity Holders of GEPH) (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Cash consideration		$ 1,642	$ 0	$ 0
GEPH Merger
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares)	99,337,748
Offering price (in dollars per share)	$ 4.66	$ 4.66
Total consideration (fair value of Southwestern common shares issued)	$ 463	$ 463
Cash consideration	1,269
Total consideration	$ 1,732

Acquisitions and Divestitures_2

Acquisitions and Divestitures - (Schedule of the Allocation of Purchase Price of GEPH) (Details) - GEPH Merger $ in Millions	Dec. 31, 2021USD ($)
Consideration:
Total consideration	$ 1,732
Fair Value of Assets Acquired:
Cash and cash equivalents	11
Accounts receivable	171
Other current assets	3
Derivative assets	56
Evaluated natural gas and oil properties	1,783
Unevaluated natural gas and oil properties	59
Other property, plant and equipment	2
Other long-term assets	3
Total assets acquired	2,088
Fair Value of Liabilities Assumed:
Accounts payable	170
Other current liabilities	1
Derivative liabilities	75
Revolving credit facility	81
Asset retirement obligations	24
Other long-term liabilities	5
Total liabilities assumed	356
Net assets acquired and liabilities assumed	$ 1,732

Acquisition and Divestiture - (

Acquisition and Divestiture - (Schedule of Consideration Paid to Equity Holders of Indigo (Details) - USD ($) $ / shares in Units, $ in Millions	Sep. 01, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Cash consideration		$ 1,642	$ 0	$ 0
Indigo Natural Resources, LLC
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares)	337,827,171
Offering price (in dollars per share)	$ 4.70
Total consideration (fair value of Southwestern common shares issued)	$ 1,588
Cash consideration	373
Total consideration	$ 1,961

Acquisition and Divestiture -_2

Acquisition and Divestiture - (Schedule of the Allocation of Purchase Price of Indigo) (Details) - Indigo Natural Resources, LLC $ in Millions	Sep. 01, 2021USD ($)
Consideration:
Total consideration	$ 1,961
Fair Value of Assets Acquired:
Cash and cash equivalents	55
Accounts receivable	192
Other current assets	2
Derivative assets	2
Evaluated natural gas and oil properties	2,724
Unevaluated natural gas and oil properties	684
Other property, plant and equipment	4
Other long-term assets	27
Total assets acquired	3,690
Fair Value of Liabilities Assumed:
Accounts payable	274
Other current liabilities	55
Derivative liabilities	501
Revolving credit facility	95
Senior unsecured notes	726
Asset retirement obligations	8
Other long-term liabilities	70
Total liabilities assumed	1,729
Net assets acquired and liabilities assumed	1,961
Purchase price adjustment	$ 8

Acquisitions and Divestitures_3

Acquisitions and Divestitures - (Schedule of consideration Paid to Stockholders of Montage) (Details) - Montage Resources Corporation - USD ($) $ / shares in Units, $ in Millions	Nov. 13, 2020	Aug. 31, 2020
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
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

Acquisitions and Divestitures_4

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	100
Other property, plant and equipment	28
Other long-term assets	26
Total assets acquired	1,254
Accounts payable	155
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	1,041
Net assets acquired and liabilities assumed	213
Purchase price adjustment	$ 10

Acquisitions and Divestitures_5

Acquisitions and Divestitures - (Schedule of Pro Forma) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Combination and Asset Acquisition [Abstract]
Revenues	$ 8,301	$ 3,836	$ 3,673
Net income (loss) attributable to common stock	$ (354)	$ (3,243)	$ 995
Net income (loss) attributable to common stock per share – basic (in dollars per share)	$ (0.32)	$ (2.92)	$ 1.48
Net income (loss) attributable to common stock per share – diluted (in dollars per share)	$ (0.32)	$ (2.92)	$ 1.48

Acquisitions and Divestitures_6

Acquisitions and Divestitures - (Schedule of Merger Related Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Professional fees (bank, legal, consulting)	$ 47
Representation & warranty insurance	11
Contract buyouts, terminations and transfers	8
Due diligence and environmental	4
Employee-related	3
Other	3
Merger-related expenses	76	$ 41	$ 0
Indigo Natural Resources, LLC
Business Acquisition [Line Items]
Professional fees (bank, legal, consulting)	27
Representation & warranty insurance	4
Contract buyouts, terminations and transfers	7
Due diligence and environmental	3
Employee-related	2
Other	2
Merger-related expenses	45
GEPH Merger
Business Acquisition [Line Items]
Professional fees (bank, legal, consulting)	19
Representation & warranty insurance	7
Contract buyouts, terminations and transfers	1
Due diligence and environmental	1
Employee-related	0
Other	0
Merger-related expenses	28
Montage Resources Corporation
Business Acquisition [Line Items]
Professional fees (bank, legal, consulting)	1	18
Representation & warranty insurance	0	0
Contract buyouts, terminations and transfers	0	5
Due diligence and environmental	0	0
Employee-related	1	17
Other	1	1
Merger-related expenses	$ 3	$ 41

Acquisitions and Divestitures_7

Acquisitions and Divestitures - (Divestitures Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of property and equipment		$ 4	$ 12	$ 54
Gain on sale of assets, net		$ 0	$ 0	(2)
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
Land
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of property and equipment	$ 16
Gain on sale of assets, net	$ 2

Restructuring Charges (Summary

Restructuring Charges (Summary of Restructuring Charges) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)	$ 3
Restructuring charges	7	$ 16	$ 11
Workforce Reduction
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)	7	16	5
Office consolidation	0	0	6
Workforce Reduction | Exploration and Production
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$ 7	$ 16	$ 11

Restructuring Charges (Narrativ

Restructuring Charges (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jul. 31, 2019
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$ 7	$ 16	$ 11
Fayetteville Shale
Restructuring Cost and Reserve [Line Items]
Operating lease term				10 years
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_2

Restructuring Charges (Summary of Liabilities Associated with Restructuring Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restructuring Reserve [Roll Forward]
Liability, beginning balance	$ 3
Additions	7	$ 16	$ 11
Distributions	(10)
Liability, ending balance	$ 0	$ 3

Leases (Narrative) (Details)

Leases (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Sep. 30, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Operating lease liability	$ 184		$ 159
Operating lease assets	187		$ 163
Operating lease commenced	1
Operating lease not yet commenced	13
Indigo Natural Resources, LLC
Lessee, Lease, Description [Line Items]
Operating lease liability		$ 4
Operating lease assets		$ 4
GEPH Merger
Lessee, Lease, Description [Line Items]
Operating lease liability	2
Operating lease assets	$ 2

Leases (Components of Lease Cos

Leases (Components of Lease Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Components of lease costs:
Operating lease cost	$ 54	$ 48	$ 45
Short-term lease cost	15	35	45
Variable lease cost	3	3	1
Total lease cost	$ 72	$ 86	$ 91

Leases (Supplemental Informatio

Leases (Supplemental Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 53	$ 47	$ 47
Right-of-use assets obtained in exchange for operating liabilities:
Operating leases	73	48	$ 95
Right-of-use asset balance:
Operating leases	187	163
Lease liability balance:
Current operating leases	42	42
Long-term operating leases	142	117
Total operating leases	$ 184	$ 159
Operating lease (years)	5 years 6 months	5 years 7 months 6 days
Operating lease (Percent)	6.77%	5.97%

Leases (Maturity Analysis) (Det

Leases (Maturity Analysis) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Maturities of operating leases (ASC 842):
2022	$ 53
2023	42
2024	31
2025	28
2026	25
Thereafter	42
Total undiscounted lease liability	221
Imputed interest	(37)
Total discounted lease liability	$ 184	$ 159

Revenue Recognition (Narrative)

Revenue Recognition (Narrative) (Details)	12 Months Ended
	Dec. 31, 2021USD ($)
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
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

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregation of Revenue by Segment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 6,667	$ 2,308	$ 3,038
Exploration and Production
Disaggregation of Revenue [Line Items]
Total operating revenues	4,701	1,391	1,740
Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	1,966	917	1,298
Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Total operating revenues	4,640	1,348	1,703
Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	6,189	2,145	2,850
Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	(4,162)	(1,185)	(1,515)
Intersegment Revenues | Exploration and Production
Disaggregation of Revenue [Line Items]
Total operating revenues	61	43	37
Intersegment Revenues | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	(4,223)	(1,228)	(1,552)
Gas sales
Disaggregation of Revenue [Line Items]
Total operating revenues	3,412	967	1,241
Gas sales | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Total operating revenues	3,358	928	1,207
Gas sales | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0	0
Gas sales | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	54	39	34
Oil sales
Disaggregation of Revenue [Line Items]
Total operating revenues	394	154	223
Oil sales | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Total operating revenues	389	150	220
Oil sales | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0	0
Oil sales | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	5	4	3
NGL sales
Disaggregation of Revenue [Line Items]
Total operating revenues	890	265	274
NGL sales | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Total operating revenues	888	265	274
NGL sales | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0	0
NGL sales | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	2	0	0
Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	1,963	917	1,297
Marketing | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0	0
Marketing | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	6,186	2,145	2,849
Marketing | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	(4,223)	(1,228)	(1,552)
Marketing | Intersegment Revenues | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	(4,200)	(1,200)	(1,600)
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	8	5	3
Other | Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Total operating revenues	5	5	2
Other | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	3	0	1
Other | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 0	$ 0	$ 0

Revenue Recognition (Disaggre_2

Revenue Recognition (Disaggregation of Revenue on Geographic Basis) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 6,667	$ 2,308	$ 3,038
Exploration and Production
Disaggregation of Revenue [Line Items]
Total operating revenues	4,701	1,391	1,740
Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	4,640	1,348	1,703
Appalachia | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	3,955	1,348	1,700
Haynesville | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	682	0	0
Other | Exploration and Production | Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 3	$ 0	$ 3

Revenue Recognition (Reconcilia

Revenue Recognition (Reconciliation of Accounts Receivable) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 1,085	$ 350
Other accounts receivable	75	18
Total accounts receivable	$ 1,160	$ 368

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, 2021USD ($)$ / MMBTU$ / bblMcfbbl
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	1,297
Fair Value	$ (867)
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	4,583
Fair Value	$ (83)
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	5,932
Fair Value	$ (9)
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	6,674
Fair Value	$ (80)
Fixed price swaps - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	806
Average price per MMBtu and Bbls | $ / MMBTU	3.08
Fair Value	$ (486)
Fixed price swaps - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	3,203
Average price per MMBtu and Bbls | $ / bbl	53.54
Fair Value	$ (60)
Fixed price swaps - 2022 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	5,797
Average price per MMBtu and Bbls | $ / bbl	11.37
Fair Value	$ (8)
Fixed price swaps - 2022 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	6,369
Average price per MMBtu and Bbls | $ / bbl	31.14
Fair Value	$ (76)
Fixed price swaps - 2022 | Not Designated as Hedging Instrument | Normal Butane
Derivative [Line Items]
Volume | bbl	1,587
Average price per MMBtu and Bbls | $ / bbl	32.86
Fair Value	$ (26)
Fixed price swaps - 2022 | Not Designated as Hedging Instrument | Natural Gasoline
Derivative [Line Items]
Volume | bbl	1,840
Average price per MMBtu and Bbls | $ / bbl	52.85
Fair Value	$ (33)
Two-way costless collars - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	144
Floor price per MMBtu and Bbls | $ / MMBTU	2.71
Cap price per MMBtu and Bbls | $ / MMBTU	3.14
Fair Value	$ (95)
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	$ (1)
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	347
Cap price per MMBtu and Bbls | $ / MMBTU	2.94
Fair Value	$ (286)
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	2.52
Three-way costless collars - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	1,380
Cap price per MMBtu and Bbls | $ / bbl	57.05
Fair Value	$ (23)
Three-way costless collars - 2022 | Not Designated as Hedging Instrument | Oil | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	39.89
Three-way costless collars - 2022 | Not Designated as Hedging Instrument | Oil | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	50.23
Three-way costless collars - 2022 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	305
Average price per MMBtu and Bbls | $ / bbl	0
Cap price per MMBtu and Bbls | $ / bbl	31.92
Fair Value	$ (4)
Three-way costless collars - 2022 | Not Designated as Hedging Instrument | Propane | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	16.80
Three-way costless collars - 2022 | Not Designated as Hedging Instrument | Propane | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	21
Financial protection on production - 2023 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	923
Fair Value	$ (298)
Financial protection on production - 2023 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	2,114
Fair Value	$ (26)
Fixed Price Swaps - 2023 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	489
Average price per MMBtu and Bbls | $ / MMBTU	3.07
Fair Value	$ (143)
Fixed Price Swaps - 2023 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	846
Average price per MMBtu and Bbls | $ / bbl	55.98
Fair Value	$ (8)
Fixed Price Swaps - 2023 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume | bbl	432
Average price per MMBtu and Bbls | $ / bbl	11.67
Fair Value	$ 0
Fixed Price Swaps - 2023 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume | bbl	518
Average price per MMBtu and Bbls | $ / bbl	33.62
Fair Value	$ (1)
Fixed Price Swaps - 2023 | Not Designated as Hedging Instrument | Normal Butane
Derivative [Line Items]
Volume | bbl	164
Average price per MMBtu and Bbls | $ / bbl	37.84
Fair Value	$ 0
Fixed Price Swaps - 2023 | Not Designated as Hedging Instrument | Natural Gasoline
Derivative [Line Items]
Volume | bbl	157
Average price per MMBtu and Bbls | $ / bbl	58.65
Fair Value	$ (1)
Two-way Costless-collars - 2023 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	219
Floor price per MMBtu and Bbls | $ / MMBTU	3.03
Cap price per MMBtu and Bbls | $ / MMBTU	3.55
Fair Value	$ (19)
Three-way Costless-collars - 2023 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	215
Cap price per MMBtu and Bbls | $ / MMBTU	3
Fair Value	$ (136)
Three-way Costless-collars - 2023 | Not Designated as Hedging Instrument | Natural Gas | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.09
Three-way Costless-collars - 2023 | Not Designated as Hedging Instrument | Natural Gas | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.54
Three-way Costless-collars - 2023 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	1,268
Average price per MMBtu and Bbls | $ / bbl	0
Cap price per MMBtu and Bbls | $ / bbl	56.12
Fair Value	$ (18)
Three-way Costless-collars - 2023 | Not Designated as Hedging Instrument | Oil | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	33.97
Three-way Costless-collars - 2023 | Not Designated as Hedging Instrument | Oil | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / bbl	45.51
Financial protection on production - 2024 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	279
Fair Value	$ (40)
Fixed price swaps - 2024 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	224
Average price per MMBtu and Bbls | $ / MMBTU	2.96
Fair Value	$ (39)
Fixed price swaps - 2024 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume | bbl	54
Average price per MMBtu and Bbls | $ / bbl	53.15
Fair Value	$ (1)
Two way costless collars - 2024 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	44
Floor price per MMBtu and Bbls | $ / MMBTU	3.07
Cap price per MMBtu and Bbls | $ / MMBTU	3.53
Fair Value	$ 4
Three-way costless collars - 2024 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	11
Cap price per MMBtu and Bbls | $ / MMBTU	3.54
Fair Value	$ (5)
Three-way costless collars - 2024 | Not Designated as Hedging Instrument | Natural Gas | Sold
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.25
Three-way costless collars - 2024 | Not Designated as Hedging Instrument | Natural Gas | Purchased
Derivative [Line Items]
Floor price per MMBtu and Bbls | $ / MMBTU	2.80
Basis swaps | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	577
Fair Value	$ 68
Basis Swaps - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	322
Basis Differential | $ / MMBTU	(0.38)
Fair Value	$ 68
Basis Swaps - 2023 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	200
Basis Differential | $ / MMBTU	(0.45)
Fair Value	$ (1)
Basis Swaps - 2024 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	46
Basis Differential | $ / MMBTU	(0.71)
Fair Value	$ 0
Basis Swaps - 2025 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume | Mcf	9
Basis Differential | $ / MMBTU	(0.64)
Fair Value	$ 1
Call options | Natural Gas
Derivative [Line Items]
Volume | Mcf	139
Fair Value	$ (109)
Call Option - 2022 | Natural Gas
Derivative [Line Items]
Volume | Mcf	84
Cap price per MMBtu and Bbls | $ / MMBTU	3.01
Fair Value	$ (67)
Call Option - 2023 | Natural Gas
Derivative [Line Items]
Volume | Mcf	46
Cap price per MMBtu and Bbls | $ / MMBTU	2.94
Fair Value	$ (33)
Call Option - 2024 | Natural Gas
Derivative [Line Items]
Volume | Mcf	9
Cap price per MMBtu and Bbls | $ / MMBTU	3
Fair Value	$ (9)
Put Option - 2022 | Natural Gas
Derivative [Line Items]
Volume | Mcf	5
Cap price per MMBtu and Bbls | $ / MMBTU	2
Fair Value	$ 0
Storage 2022 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume | Mcf	3
Fair Value	$ (1)
Purchased Fixed Price Swaps, Storage, 2022 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume | Mcf	0
Average price per MMBtu and Bbls | $ / MMBTU	2.14
Basis Differential | $ / MMBTU	0
Fair Value	$ 0
Fixed Price Swap, Storage, 2022 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume | Mcf	2
Average price per MMBtu and Bbls | $ / MMBTU	2.82
Basis Differential | $ / MMBTU	0
Fair Value	$ (1)
Basis Swaps Storage, 2022 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume | Mcf	1
Average price per MMBtu and Bbls | $ / MMBTU	0
Basis Differential | $ / MMBTU	(0.57)
Fair Value	$ 0

Derivatives and Risk Manageme_4

Derivatives and Risk Management (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Not Designated as Hedging Instrument
Derivative [Line Items]
Impact of non-performance risk on fair value of the net derivative liability position	$ 3	$ 1
Commodity Contract
Derivative [Line Items]
Derivative asset (liability)	$ (1,502)

Derivatives and Risk Manageme_5

Derivatives and Risk Management (Balance Sheet Classification of Derivative Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Net current derivative liabilities	$ (1,098)	$ (4)
Net long-term derivative liabilities	(407)	(38)
Non-performance risk adjustment	3	1
Total	(1,502)	(41)
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative assets	411	387
Derivative liabilities	1,916	429
Not Designated as Hedging Instrument | Interest rate swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	2	0
Natural gas storage | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	0
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	79	37
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	64	7
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	565	7
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	246	3
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	9	54
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	100	20
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	104	43
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	115	21
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	12	57
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	37	87
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	298	82
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	178	103
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	77	60
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	22	15
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	9	3
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	22	7
Natural Gas | Not Designated as Hedging Instrument | Call options | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	4
Natural Gas | Not Designated as Hedging Instrument | Call options | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	67	12
Natural Gas | Not Designated as Hedging Instrument | Call options | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	42	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	0	13
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	2
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	60	12
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	9	2
Oil | Not Designated as Hedging Instrument | Two-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	1
Oil | Not Designated as Hedging Instrument | Two-way costless collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	0
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	1	15
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	3	15
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	24	15
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	21	15
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	2	0
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	10	10
Ethane | Not Designated as Hedging Instrument | Two-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	0
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	2	0
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	78	36
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	2
Propane | Not Designated as Hedging Instrument | Three-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	0
Normal Butane | 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	27	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	33	13
Natural Gasoline | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 1	$ 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	$ (945)	$ (139)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(1,492)	362
Non-performance risk adjustment	1	1
Total gain (loss) on derivatives	(2,436)	224	$ 274
Purchased fixed price swaps | Natural Gas | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(1)	2
Settled Gain (Loss) on Derivatives Recognized in Earnings	7	(3)
Purchased fixed price swaps | Oil | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Settled Gain (Loss) on Derivatives Recognized in Earnings	1	0
Purchased fixed price swaps | Natural gas storage | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Settled Gain (Loss) on Derivatives Recognized in Earnings	2	(1)
Fixed price swaps | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(237)	(25)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(418)	142
Amortization of premium paid		9
Fixed price swaps | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(70)	0
Settled Gain (Loss) on Derivatives Recognized in Earnings	(86)	65
Fixed price swaps | Ethane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	2	(21)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(39)	6
Fixed price swaps | Propane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(40)	(60)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(173)	18
Fixed price swaps | Normal Butane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(18)	(9)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(53)	(2)
Fixed price swaps | Natural Gasoline
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(18)	(15)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(59)	(1)
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	(1)	2
Two-way costless collars | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(83)	10
Settled Gain (Loss) on Derivatives Recognized in Earnings	(325)	(5)
Two-way costless collars | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	1	(1)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(4)	17
Two-way costless collars | Ethane
Derivative Instruments, Gain (Loss) [Line Items]
Settled Gain (Loss) on Derivatives Recognized in Earnings	(2)	0
Two-way costless collars | Propane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	0	(1)
Settled Gain (Loss) on Derivatives Recognized in Earnings	0	2
Three-way costless collars | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(375)	(78)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(335)	38
Three-way costless collars | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(41)	3
Settled Gain (Loss) on Derivatives Recognized in Earnings	(29)	9
Three-way costless collars | Propane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(4)	0
Basis swaps | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	3	59
Settled Gain (Loss) on Derivatives Recognized in Earnings	92	76
Call options | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(68)	(10)
Call options | Natural Gas | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Settled Gain (Loss) on Derivatives Recognized in Earnings	(66)	0
Call options | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	0	1
Call options | Oil | Purchased
Derivative Instruments, Gain (Loss) [Line Items]
Settled Gain (Loss) on Derivatives Recognized in Earnings	(2)	0
Put options | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	1	0
Settled Gain (Loss) on Derivatives Recognized in Earnings	(2)	0
Amortization of premium paid	2
Swaptions | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	2	7
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	2	0
Settled Gain (Loss) on Derivatives Recognized in Earnings	$ 0	$ (1)

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, 2021	Dec. 31, 2020	Dec. 31, 2019
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ 497	$ 3,246	$ 2,362
Other comprehensive income before reclassifications	11
Amounts reclassified from other comprehensive income	2
Net current-period other comprehensive income	13	(5)	3
Ending balance	2,547	497	3,246
Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(38)	(33)	(36)
Net current-period other comprehensive income	13	(5)	3
Ending balance	(25)	(38)	$ (33)
Pension and Other Postretirement
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(24)
Other comprehensive income before reclassifications	11
Amounts reclassified from other comprehensive income	2
Net current-period other comprehensive income	13
Ending balance	(11)	(24)
Foreign Currency
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(14)
Other comprehensive income before reclassifications	0
Amounts reclassified from other comprehensive income	0
Net current-period other comprehensive income	0
Ending balance	$ (14)	$ (14)

Reclassifications from Accumu_4

Reclassifications from Accumulated Other Comprehensive Income (Loss) (Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Income (Loss), Net	$ (5)	$ (1)	$ 7
Provision for income taxes	0	407	(411)
Net income	25	$ 3,112	$ (891)
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent | Reclassified from Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Income (Loss), Net	1
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent | Reclassified from Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Income (Loss), Net	1
Pension and Other Postretirement | Reclassified from Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Provision for income taxes	0
Net income	$ 2

Fair Value Measurements (Carryi

Fair Value Measurements (Carrying Amount and Estimated Fair Values of Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	$ (1,502)	$ (41)
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	28	13
2018 revolving credit facility due April 2024	460	700
Derivative instruments, net	(1,502)	(41)
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	28	13
2018 revolving credit facility due April 2024	460	700
Derivative instruments, net	(1,502)	(41)
Senior Notes | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	4,430	2,471
Senior Notes | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	4,745	2,609
Term Loan | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Term Loan B due 2027	550	0
Term Loan | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Term Loan B due 2027	$ 550	$ 0

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Aug. 30, 2021
Debt Instrument [Line Items]
Impairments		$ 6	$ 2,830	$ 16
Not Designated as Hedging Instrument
Debt Instrument [Line Items]
Impact of non-performance risk on fair value of the net derivative liability position		3	1
Other non-core assets
Debt Instrument [Line Items]
Impairments		$ 6	5
Other non-core assets | Nonrecurring
Debt Instrument [Line Items]
Impairments	$ 6		5
Carrying value of non core assets			$ 6
Senior Notes | 4.10% Senior Notes due March 2022
Debt Instrument [Line Items]
Stated interest rate		4.10%	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	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	$ (1,505)	$ (42)
Not Designated as Hedging Instrument
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impact of non-performance risk on fair value of the net derivative liability position	3	1
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	(1,505)	(42)
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	0	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	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	0	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	0
Fixed price swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	148	59
Derivative liabilities	(1,031)	(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	148	59
Derivative liabilities	(1,031)	(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
Two-way costless collars
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	109	74
Derivative liabilities	(220)	(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	109	74
Derivative liabilities	(220)	(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	53	174
Derivative liabilities	(525)	(215)
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	53	174
Derivative liabilities	(525)	(215)
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	99	75
Derivative liabilities	(31)	(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	99	75
Derivative liabilities	(31)	(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
Interest rate swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2
Interest rate 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
Interest rate swaps | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2
Interest rate swaps | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Call options
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		4
Derivative liabilities	(109)	(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
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		4
Derivative liabilities	(109)	(40)
Call options | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Derivative liabilities	0	0
Put options
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	(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	0
Put options | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	(1)
Put options | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Swaptions
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	(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	0
Swaptions | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	(2)
Swaptions | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	$ 0	$ 0

Debt (Components of Debt) (Deta

Debt (Components of Debt) (Details) - USD ($) $ in Thousands	1 Months Ended
	Mar. 31, 2022	Jan. 31, 2022	Dec. 31, 2021	Nov. 30, 2021	Sep. 01, 2021	Aug. 30, 2021	Dec. 31, 2020	Jun. 30, 2020	Apr. 07, 2020	Dec. 31, 2019	Jul. 31, 2018	Jan. 31, 2015
Debt Instrument [Line Items]
Current portion of long-term debt			$ 206,000				$ 0
Debt instrument, excluding current maturities, gross			5,234,000
Total			5,440,000				3,171,000
Unamortized Issuance Expense			(57,000)				(20,000)
Unamortized Debt Premium / Discount			24,000				(1,000)
Long-term debt			5,201,000				3,150,000
Total			5,407,000				3,150,000
Debt issuance costs, line of credit			$ 10,000				12,000
Line of Credit | 2018 Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility, variable interest rate			2.08%
Line of Credit | 2018 Revolving Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Debt instrument, excluding current maturities, gross			$ 460,000
Unamortized Issuance Expense			0
Unamortized Debt Premium / Discount			0
Long-term debt			460,000
Senior Notes | 4.10% Senior Notes due March 2022
Debt Instrument [Line Items]
Current portion of long-term debt			$ 201,000
Total							207,000
Unamortized Issuance Expense							0
Unamortized Debt Premium / Discount							0
Total							$ 207,000
Stated interest rate			4.10%			4.10%	4.10%
Senior Notes | 4.95% Senior Notes due January 2025 (3)
Debt Instrument [Line Items]
Debt instrument, excluding current maturities, gross			$ 389,000
Total							$ 856,000
Unamortized Issuance Expense			(1,000)				(4,000)
Unamortized Debt Premium / Discount			0				(1,000)
Long-term debt			$ 388,000
Total							$ 851,000
Stated interest rate			4.95%			4.95%	4.95%		6.45%	4.95%	6.20%	4.95%
Senior Notes | 4.95% Senior Notes due January 2025 (3) | Subsequent Event
Debt Instrument [Line Items]
Stated interest rate		5.95%
Senior Notes | 7.50% Senior Notes due April 2026
Debt Instrument [Line Items]
Total							$ 618,000
Unamortized Issuance Expense							(6,000)
Unamortized Debt Premium / Discount							0
Total							$ 612,000
Stated interest rate						7.50%	7.50%	7.50%		7.50%
Senior Notes | 7.75% Senior Notes due October 2027
Debt Instrument [Line Items]
Debt instrument, excluding current maturities, gross			$ 440,000
Total							$ 440,000
Unamortized Issuance Expense			(4,000)				(5,000)
Unamortized Debt Premium / Discount			0				0
Long-term debt			$ 436,000
Total							$ 435,000
Stated interest rate			7.75%				7.75%			7.75%
Senior Notes | 8.375% Senior Notes due September 2028
Debt Instrument [Line Items]
Debt instrument, excluding current maturities, gross			$ 350,000
Total							$ 350,000
Unamortized Issuance Expense			(5,000)				(5,000)
Unamortized Debt Premium / Discount			0				0
Long-term debt			$ 345,000
Total							$ 345,000
Stated interest rate			8.375%				8.375%
Senior Notes | 5.375% Senior Notes due February 2029
Debt Instrument [Line Items]
Debt instrument, excluding current maturities, gross			$ 700,000
Unamortized Issuance Expense			(6,000)
Unamortized Debt Premium / Discount			25,000
Long-term debt			$ 719,000
Total				$ 700,000	$ 700,000
Stated interest rate			5.375%		5.375%
Senior Notes | 5.375% Senior Notes due March 2030
Debt Instrument [Line Items]
Debt instrument, excluding current maturities, gross			$ 1,200,000
Unamortized Issuance Expense			(17,000)
Unamortized Debt Premium / Discount			0
Long-term debt			$ 1,183,000
Stated interest rate			5.375%			5.375%
Senior Notes | 4.75% Senior Notes due February 2032
Debt Instrument [Line Items]
Debt instrument, excluding current maturities, gross			$ 1,150,000
Unamortized Issuance Expense			(17,000)
Unamortized Debt Premium / Discount			0
Long-term debt			$ 1,133,000
Stated interest rate			4.75%
Term Loan | 2018 Term Loan Facility Due April 2023
Debt Instrument [Line Items]
Total							$ 700,000
Unamortized Issuance Expense							0
Unamortized Debt Premium / Discount							0
Total							$ 700,000
Debt variable rate							2.11%
Term Loan | Term Loan Due June 2027
Debt Instrument [Line Items]
Current portion of long-term debt			$ 5,000
Debt instrument, excluding current maturities, gross			545,000
Unamortized Issuance Expense			(7,000)
Unamortized Debt Premium / Discount			(1,000)
Long-term debt			$ 537,000
Credit facility, variable interest rate			3.00%
Term Loan | Term Loan Due June 2027 | Subsequent Event
Debt Instrument [Line Items]
Repayments of term loan	$ 1,375

Debt (Schedule of Debt Maturiti

Debt (Schedule of Debt Maturities) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Long-term Debt, Fiscal Year Maturity [Abstract]
2022	$ 206
2023	6
2024	465
2025	395
2026	5
Thereafter	4,363
Total	$ 5,440	$ 3,171

Debt (2018 Revolving Credit Fac

Debt (2018 Revolving Credit Facility - Narrative) (Details) - USD ($)	1 Months Ended	12 Months Ended
	Apr. 30, 2018	Dec. 31, 2021
Debt Instrument [Line Items]
Subsidiary ownership		100.00%
Letters of credit outstanding		$ 160,000,000
Debt instrument, excluding current maturities, gross		5,234,000,000
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
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, excluding current maturities, gross		460,000,000
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%
Term Loan | Term Loan Due June 2027
Debt Instrument [Line Items]
Debt instrument, excluding current maturities, gross		$ 545,000,000
Term Loan | Term Loan Due June 2027 | Minimum
Debt Instrument [Line Items]
Basis points		0.50%
Term Loan | Term Loan Due June 2027 | Maximum
Debt Instrument [Line Items]
Basis points		2.50%

Debt (Term Loan Credit Agreemen

Debt (Term Loan Credit Agreement - Narrative) (Details) - Term Loan Due June 2027 - Term Loan - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021	Dec. 22, 2021
Debt Instrument [Line Items]
Secured term loan facility, amount		$ 550	$ 550
Proceeds from Loans		$ 542
Credit facility, variable interest rate		3.00%
Subsequent Event
Debt Instrument [Line Items]
Basis points	1.50%
Minimum
Debt Instrument [Line Items]
Basis points		0.50%
Minimum | Subsequent Event
Debt Instrument [Line Items]
Basis points	0.50%
Maximum
Debt Instrument [Line Items]
Basis points		2.50%
Maximum | Subsequent Event
Debt Instrument [Line Items]
Basis points	2.50%

Debt (Senior Notes - Narrative)

Debt (Senior Notes - Narrative) (Details) - USD ($)	Dec. 22, 2021	Sep. 01, 2021	Aug. 30, 2021	Aug. 31, 2020	Jan. 31, 2015	Jun. 30, 2020	Dec. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jan. 31, 2022	Nov. 30, 2021	Apr. 07, 2020	Jul. 31, 2018
Debt Instrument [Line Items]
Gain (Loss) on Early Extinguishment of Debt								$ (93,000,000)	$ 35,000,000	$ 8,000,000
Long-term debt								$ 5,407,000,000	$ 3,150,000,000
Senior Notes
Debt Instrument [Line Items]
Repayments of long-term debt			$ 845,000,000				$ 54,000,000
Gain (Loss) on Early Extinguishment of Debt	$ (33,000,000)		$ (60,000,000)			$ 35,000,000	$ 8,000,000
Debt instrument, purchase accounting, non-cash fair value adjustment		$ 26,000,000
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%
4.95% Senior Notes due January 2025 (3) | Senior Notes
Debt Instrument [Line Items]
Senior notes					$ 1,000,000,000
Stated interest rate			4.95%		4.95%		4.95%	4.95%	4.95%	4.95%			6.45%	6.20%
Debt repurchased face amount			$ 167,000,000			$ 36,000,000	$ 35,000,000			$ 35,000,000
Long-term debt									$ 851,000,000
4.95% Senior Notes due January 2025 (3) | Senior Notes | Subsequent Event
Debt Instrument [Line Items]
Stated interest rate											5.95%
7.50% Senior Notes due April 2026 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate			7.50%			7.50%	7.50%		7.50%	7.50%
Debt repurchased face amount			$ 618,000,000			$ 21,000,000	$ 11,000,000			$ 11,000,000
Long-term debt									$ 612,000,000
7.75% Senior Notes due October 2027 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate							7.75%	7.75%	7.75%	7.75%
Debt repurchased face amount						44,000,000	$ 16,000,000			$ 16,000,000
Long-term debt									$ 435,000,000
4.10% Senior Notes due March 2022 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate			4.10%					4.10%	4.10%
Debt repurchased face amount			$ 6,000,000			6,000,000
Long-term debt									$ 207,000,000
4.05% Senior Notes Due January 2020 | Senior Notes
Debt Instrument [Line Items]
Debt repurchased face amount						$ 72,000,000
8.375% Senior Notes due September 2028 | Senior Notes
Debt Instrument [Line Items]
Senior notes				$ 350,000,000
Stated interest rate								8.375%	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%
Long-term debt									$ 345,000,000
Eight Point Eight Seven Five Percent Senior Notes Due 2023 | Senior Notes | Montage Resources Corporation
Debt Instrument [Line Items]
Senior notes				$ 510,000,000
Stated interest rate				8.875%
5.375% Senior Notes due March 2030 | Senior Notes
Debt Instrument [Line Items]
Senior notes			$ 1,200,000,000
Stated interest rate			5.375%					5.375%
Proceeds from issuance of long-term debt			$ 1,183,000,000
Debt instrument, unamortized discount (premium) and debt issuance costs, net			$ 6,000,000
5.375% Senior Notes due February 2029 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate		5.375%						5.375%
Debt instrument, purchase accounting, non-cash fair value adjustment, percentage		103.766%
Long-term debt		$ 700,000,000										$ 700,000,000
5.375% Senior Notes due February 2029 | Senior Notes | Indigo Natural Resources, LLC
Debt Instrument [Line Items]
Stated interest rate		5.375%
Senior note assumed in merger agreement		$ 700,000,000
4.75% Senior Notes due February 2032 | Senior Notes
Debt Instrument [Line Items]
Senior notes	1,150,000,000
Stated interest rate								4.75%
Proceeds from issuance of long-term debt	1,133,000,000
Debt instrument, unamortized discount (premium) and debt issuance costs, net	1,000,000
Payment to fund tender offers, amount	332,000,000
Tender offer fund, amount	$ 300,000,000

Commitments and Contingencies_2

Commitments and Contingencies (Narrative) (Details)	Jun. 12, 2018individualcompany	Dec. 31, 2021USD ($)lease
Commitments And Contingencies [Line Items]
Obligation under transportation agreements		$ 10,456,000,000
Guarantee obligations relative to the firms transportation agreements and gathering project and services		869,000,000
Maturities of operating leases (ASC 842):
2022		53,000,000
2023		42,000,000
2024		31,000,000
2025		28,000,000
2026		25,000,000
Thereafter		42,000,000
Number of plaintiffs | individual	51
Number of defendants | company	15
Indemnification liability		0
Pending regulatory approval and/or construction
Commitments And Contingencies [Line Items]
Obligation under transportation agreements		872,000,000
Indigo Agreement
Commitments And Contingencies [Line Items]
Obligation under transportation agreements		36,000,000
Liability for the estimated future payments		17,000,000
Purchase or volume commitments with gathering fresh water and sand
Commitments And Contingencies [Line Items]
Obligation under transportation agreements		74,000,000
Appalachian Basin
Commitments And Contingencies [Line Items]
Obligation under transportation agreements		327,000,000
Maturities of operating leases (ASC 842):
Obligation under transportation agreements, reimbursed by seller		100,000,000
Pressure Pumping Equipment | Exploration and Production
Commitments And Contingencies [Line Items]
Aggregate annual lease payment		7,000,000
Drilling Rigs | Exploration and Production
Commitments And Contingencies [Line Items]
Aggregate annual lease payment		$ 10,000,000
Number of leases | lease		7
Office Space, Vehicles And Equipment
Maturities of operating leases (ASC 842):
2022		$ 38,000,000
2023		34,000,000
2024		27,000,000
2025		26,000,000
2026		24,000,000
Thereafter		38,000,000
Compression Rentals
Maturities of operating leases (ASC 842):
2022		24,000,000
2023		10,000,000
2024		4,000,000
2025		$ 1,000,000

Commitments and Contingencies_3

Commitments and Contingencies (Schedule of Future Obligation under Transportation Agreements) (Details) $ in Millions	Dec. 31, 2021USD ($)
Other Commitments [Line Items]
Total	$ 10,456
Less than 1 Year	1,144
1 to 3 Years	2,046
3 to 5 Years	1,894
5 to 8 Years	2,416
More than 8 Years	2,956
Infrastructure currently in service
Other Commitments [Line Items]
Total	9,584
Less than 1 Year	1,141
1 to 3 Years	1,932
3 to 5 Years	1,731
5 to 8 Years	2,167
More than 8 Years	2,613
Pending regulatory approval and/or construction
Other Commitments [Line Items]
Total	872
Less than 1 Year	3
1 to 3 Years	114
3 to 5 Years	163
5 to 8 Years	249
More than 8 Years	$ 343

Income Taxes (Provision (Benefi

Income Taxes (Provision (Benefit) for Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current:
Federal	$ 0	$ (2)	$ (1)
State	0	0	(1)
Total Current	0	(2)	(2)
Deferred:
Federal	0	371	(431)
State	0	38	22
Total Deferred	0	409	(409)
Provision (Benefit) for Income Taxes	$ 0	$ 407	$ (411)

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Line Items]
Effective tax rate	0.00%	(15.00%)	(86.00%)
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
Valuation allowance, deferred tax asset, Amount			522,000,000
Effective income tax rate reconciliation, change in deferred tax assets valuation allowance, amount	(2,000,000)	$ (1,034,000,000)	$ 522,000,000
Operating loss carryforward valuation allowance	59,000,000
Unrecognized tax benefits that would impact effective tax rate	0
Indigo Natural Resources, LLC
Income Taxes [Line Items]
Operating loss carryforwards subject to a section 382 limitation	48,000,000
Montage Resources Corporation
Income Taxes [Line Items]
Operating loss carryforwards subject to a section 382 limitation	1,700,000
Net operating loss carryforward	858,000,000
Statutory depletion carryforward
Income Taxes [Line Items]
Tax credit carryforward	13,000,000
Interest deduction carryforward
Income Taxes [Line Items]
Tax credit carryforward	46,000,000
Exploration Program in Canada
Income Taxes [Line Items]
Net operating loss carryforward	29,000,000
Federal
Income Taxes [Line Items]
Operating loss carryforwards subject to a section 382 limitation	2,000,000,000
Operating loss carryforwards, subject to expiration	3,000,000,000
Operating loss carryforwards, not subject to expiration	1,000,000,000
Net operating loss carryforward	$ 4,000,000,000

Income Taxes (Reconciliation of

Income Taxes (Reconciliation of Provision for Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Expected provision (benefit) at federal statutory rate	$ (5)	$ (568)	$ 101
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect	0	(55)	11
Change in valuation allowance	2	1,034	(522)
Other	3	(4)	(1)
Provision (Benefit) for Income Taxes	$ 0	$ 407	$ (411)

Income Taxes (Components of Def

Income Taxes (Components of Deferred Tax Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Deferred tax liabilities:
Right of use lease asset	$ 45	$ 38
Other	3	2
Total deferred tax liabilities	48	40
Deferred tax assets:
Differences between book and tax basis of property	0	295
Accrued compensation	44	38
Accrued pension costs	6	11
Asset retirement obligations	25	20
Net operating loss carryforward	585	1,117
Future lease payments	46	38
Derivative activity	362	9
Capital loss carryover	28	27
Other	31	24
Total deferred tax assets	1,127	1,579
Valuation allowance	(1,079)	(1,539)	$ (87)
Net deferred tax asset	$ 0	$ 0

Income Taxes (Reconciliation _2

Income Taxes (Reconciliation of Changes to the Valuation Allowance) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Deferred Tax Asset, Valuation Allowance [Roll Forward]
Valuation allowance, beginning balance	$ 1,539	$ 87
Establishment of valuation allowance on opening deferred balance	0	408
Return to accrual adjustments	(31)	6
Current period deferred activity	(1)	626
Reduction due to 382 limitations on NOLs	(428)	(120)
Purchase accounting	0	532
Valuation allowance, ending balance	$ 1,079	$ 1,539

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at January 1	$ 85	$ 57
Accretion of discount	6	4
Obligations incurred	1	1
Obligations assumed through mergers	36	28
Obligations settled/removed	(20)	(6)
Revisions of estimates	1	1
Asset retirement obligation at December 31	109	85
Current liability	4	4
Long-term liability	105	81
Asset retirement obligation at December 31	$ 109	$ 85

Retirement and Employee Benef_3

Retirement and Employee Benefit Plans (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan cost	$ 2	$ 2	$ 2
Contributions capitalized	2	1	1
Defined Benefit Plan, Benefit Obligation, Special and Contractual Termination Benefits	$ 11
Defined benefit plan, assumptions used calculating benefit obligation, weighted-average interest crediting rate	6.00%
Defined benefit plan included in accumulated other comprehensive (income) loss, before tax	$ 23	36
Defined benefit plan included in accumulated other comprehensive (income) loss after tax	18	28
Total change in value of pension and postretirement liabilities	(13)	5	(3)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-cash curtailment gain	0	0	0
Settlement loss	2	0	6
Settlements	8	0	21
Decrease for remeasurement due to Settlement	4
Total change in value of pension and postretirement liabilities	(11)	5
Employer contributions	12	12
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-cash curtailment gain	0	0	0
Settlement loss	0	0	$ 0
Settlements	0	0
Total change in value of pension and postretirement liabilities	(2)	(1)
Employer contributions	$ 1	$ 1

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Change in plan assets:
Other employee-related liabilities	$ 1	$ 1
Pension Benefits
Change in benefit obligations:
Benefit obligation at January 1	139	126
Service cost	0	7	$ 7
Interest cost	4	5	5
Participant contributions	0	0
Actuarial (gain) loss	(4)	16
Benefits paid	(2)	(13)
Plan amendments	0	0
Curtailments	0	(2)
Settlements	(11)	0
Benefit obligation at December 31	126	139	126
Change in plan assets:
Fair value of plan assets at January 1	106	96
Actual return on plan assets	6	11
Employer contributions	12	12
Participant contributions	0	0
Benefits paid	(2)	(13)
Settlements	(8)	0	(21)
Fair value of plan assets at December 31	114	106	96
Funded status of plans at December 31 (1)	(12)	(33)
Other Postretirement Benefits
Change in benefit obligations:
Benefit obligation at January 1	13	13
Service cost	2	2	1
Interest cost	0	0	0
Participant contributions	0	0
Actuarial (gain) loss	(2)	1
Benefits paid	0	(1)
Plan amendments	0	(2)
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	1
Participant contributions	0	0
Benefits paid	(1)	(1)
Settlements	0	0
Fair value of plan assets at December 31	0	0	$ 0
Funded status of plans at December 31 (1)	$ (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, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 126	$ 139
Accumulated benefit obligation	126	139
Fair value of plan assets	$ 114	$ 106

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 0	$ 7	$ 7
Interest cost	4	5	5
Expected return on plan assets	(4)	(6)	(6)
Amortization of transition obligation	0	0	0
Amortization of prior service cost	0	0	0
Amortization of net loss	0	1	2
Net periodic benefit cost	0	7	8
Curtailment gain	0	0	0
Settlement loss	2	0	6
Total benefit cost	2	7	14
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	2	2	1
Interest cost	0	0	0
Expected return on plan assets	0	0	0
Amortization of transition obligation	0	0	0
Amortization of prior service cost	0	0	0
Amortization of net loss	0	0	0
Net periodic benefit cost	2	2	1
Curtailment gain	0	0	0
Settlement loss	0	0	0
Total benefit cost	$ 2	$ 2	$ 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Total change in value of pension and postretirement liabilities	$ 13	$ (5)	$ 3
Pension benefit, tax effects	2.7
Other postretirement benefit, tax effects	0.4
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (loss) gain arising during the year	5	(12)
Amortization of prior service cost	0	0
Amortization of net loss	1	1
Settlements	5	0
Curtailments	0	3
Less: Tax effect (1)	0	3
Total change in value of pension and postretirement liabilities	11	(5)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (loss) gain arising during the year	2	2
Amortization of prior service cost	0	0
Amortization of net loss	0	0
Settlements	0	0
Curtailments	0	0
Less: Tax effect (1)	0	(1)
Total change in value of pension and postretirement liabilities	$ 2	$ 1

Retirement and Employee Benef_8

Retirement and Employee Benefit Plans (Schedule of Assumptions Used - Benefit Obligations) (Details)	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.50%	3.50%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.20%	3.10%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.10%	2.80%

Retirement and Employee Benef_9

Retirement and Employee Benefit Plans (Schedule of Assumptions Used - Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	3.20%	3.70%	3.70%
Expected return on plan assets	0.10%	6.50%	7.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.80%	3.50%	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, 2021	Dec. 31, 2020
Retirement Benefits [Abstract]
Health care cost trend assumed for next year	6.50%	6.50%
Rate to which the cost trend is assumed to decline	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2038	2037

Retirement and Employee Bene_11

Retirement and Employee Benefit Plans (Schedule of Expected Benefit Payments) (Details) $ in Millions	Dec. 31, 2021USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	$ 48
2023	70
2024	0
2025	0
2026	0
Years 2027-2031	0
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	1
2023	1
2024	1
2025	1
2026	1
Years 2027-2031	$ 4

Retirement and Employee Bene_12

Retirement and Employee Benefit Plans (Schedule of Allocation of Plan Assets) (Details) - Pension Benefits	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	100.00%
Actual asset allocations	100.00%
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	78.00%
Actual asset allocations	78.00%
Cash
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	22.00%
Actual asset allocations	22.00%

Retirement and Employee Bene_13

Retirement and Employee Benefit Plans (Fair Value Measurement of Pension Plan Assets) (Details) - Pension Benefits - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 114	$ 106	$ 96
Excluding Net Asset Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	114	101
Excluding Net Asset Value | Equity securities, U.S. large cap value equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		10
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
Excluding Net Asset Value | Non-U.S. equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		18
Excluding Net Asset Value | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90	34
Excluding Net Asset Value | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	24	2
Quoted Prices in Active Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	114	101
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
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
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
Quoted Prices in Active Markets for Identical Assets (Level 1) | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90	34
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	24	2
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
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
Significant Observable Inputs (Level 2) | Non-U.S. equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Significant Observable Inputs (Level 2) | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Observable Inputs (Level 2) | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3) | Equity securities, U.S. large cap value equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		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
Significant Unobservable Inputs (Level 3) | Non-U.S. equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Significant Unobservable Inputs (Level 3) | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Unobservable Inputs (Level 3) | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	0
Net Asset Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		5
Net Asset Value | Equity securities, U.S. large cap growth equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		3
Net Asset Value | Equity securities, U.S. large cap core equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 2

Long-Term Incentive Compensat_3

Long-Term Incentive Compensation (Narrative) (Details) - USD ($)	1 Months Ended	3 Months Ended				12 Months Ended
	May 31, 2019	Mar. 31, 2021	Mar. 31, 2020	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of options granted						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						$ 1,000,000		$ 0
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						$ 1,000,000	$ 2,000,000	$ 1,000,000
Equity-classified awards, unrecognized compensation cost						$ 1,000,000
Equity-classified awards, weighted average period over which unrecognized cost is recognized, years						1 year 7 months 6 days
Total fair value of restricted stock grants						$ 2,000,000	2,000,000	2,000,000
Total fair value of shares vested						$ 5,000,000	$ 6,000,000	$ 11,000,000
Number of units awarded						438,000	584,000	493,000
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 2 months 12 days
Number of units awarded						0	186,000
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						$ 2,000,000	$ 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
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	$ 1,000,000
Liability-classified restricted stock, vesting period		4 years	4 years	4 years	4 years	3 years
Liability-classified restricted stock, unrecognized compensation cost						$ 19,000,000
Liability-classified restricted stock, weighted average period over which unrecognized cost is recognized, years						1 year 8 months 12 days
Liability-Classified Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in deferred tax asset						$ 4,000,000	$ 2,000,000	$ (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						1 year 7 months 6 days
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						$ 21,000,000
Liability-classified restricted stock, weighted average period over which unrecognized cost is recognized, years						2 years 8 months 12 days

Long-Term Incentive Compensat_4

Long-Term Incentive Compensation - Schedule of Stock-based Compensation Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Long-term incentive compensation – expensed	$ 30	$ 17	$ 17
Long-term incentive compensation – capitalized	$ 18	$ 7	$ 10

Long-Term Incentive Compensat_5

Long-Term Incentive Compensation (Schedule of Equity-Classified Stock Option Stock-Based Compensation Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Long-term incentive compensation – expensed	$ 30	$ 17	$ 17
Equity-classified awards - capitalized	18	7	10
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Long-term incentive compensation – expensed	0	0	1
Equity-classified awards - capitalized	$ 0	$ 0	$ 0

Long-Term Incentive Compensat_6

Long-Term Incentive Compensation (Summary of Equity-Classified Stock Option Activity) (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Number of Shares
Number of Options, Outstanding at January 1 (in shares)	3,850	4,635	5,178
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)	(844)	(785)	(543)
Number of Options, Outstanding at December 31 (in shares)	3,006	3,850	4,635
Weighted Average Exercise Price
Weighted Average Exercise Price, Outstanding at January 1 (in dollars per share)	$ 13.39	$ 15.26	$ 17.06
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)	29.10	24.46	32.38
Weighted Average Exercise Price, Outstanding at December 31 (in dollars per share)	$ 8.98	$ 13.39	$ 15.26

Long-Term Incentive Compensat_7

Long-Term Incentive Compensation (Summary of Equity-Classified Stock Options Outstanding and Options Exercisable) (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Outstanding - Options Outstanding at December 31, 2020 (in shares)	3,006	3,850	4,635	5,178
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 8.98	$ 13.39	$ 15.26	$ 17.06
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)	3,006
Options Outstanding - Weighted Average Exercise Price (in dollars per share)	$ 8.98
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	1 year 3 months 18 days
Options Exercisable - Options Exercisable at December 31, 2021 (in shares)	3,006
Options Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 8.98
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	1 year 3 months 18 days

Long-Term Incentive Compensat_8

Long-Term Incentive Compensation (Schedule of Equity-Classified Restricted Stock Stock-Based Compensation Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	$ 30	$ 17	$ 17
Equity-classified awards - capitalized	18	7	10
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	2	3	6
Equity-classified awards - capitalized	$ 0	$ 1	$ 4

Long-Term Incentive Compensat_9

Long-Term Incentive Compensation (Summary of Equity-Classified Restricted Stock Activity) (Details) - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	697,000	1,480,000	2,717,000
Number of Shares/Units, Granted (in shares)	438,000	584,000	493,000
Number of Shares/Units, Vested (in shares)	(893,000)	(1,098,000)	(1,516,000)
Number of Shares/Units, Forfeited (in shares)	0	(269,000)	(214,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	242,000	697,000	1,480,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 5.97	$ 7	$ 7.91
Weighted Average Fair Value, Granted (in dollars per share)	5.18	2.86	3.06
Weighted Average Fair Value, Vested (in dollars per share)	5.81	5.26	7.16
Weighted Average Fair Value, Forfeited (in dollars per share)	8.59	7.79	8.38
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 5.12	$ 5.97	$ 7
Workforce Reduction
Number of Shares
Number of Shares/Units, Forfeited (in shares)		(171,813)	(65,196)

Long-Term Incentive Compensa_10

Long-Term Incentive Compensation (Summary of Equity-Classified Restricted Stock Unit Activity) (Details) - Equity-Classified Restricted Stock Units - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	134	0
Number of Shares/Units, Granted (in shares)	0	186
Number of Shares/Units, Vested (in shares)	(92)	(42)
Number of Shares/Units, Forfeited (in shares)	(5)	(10)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	37	134
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 3.05	$ 0
Weighted Average Fair Value, Granted (in dollars per share)	0	3.05
Weighted Average Fair Value, Vested (in dollars per share)	3.05	3.05
Weighted Average Fair Value, Forfeited (in dollars per share)	3.05	3.05
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 3.05	$ 3.05

Long-Term Incentive Compensa_11

Long-Term Incentive Compensation (Schedule of Equity-Classified Performance Units Stock-Based Compensation Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	$ 30	$ 17	$ 17
Equity-classified awards - capitalized	18	7	10
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	0	0	1
Equity-classified awards - capitalized	$ 0	$ 0	$ 0

Long-Term Incentive Compensa_12

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares)		0	178,000	598,000
Number of Shares/Units, Granted (in shares)		0	0	0
Number of Shares/Units, Vested (in shares)		0	(178,000)	(378,000)
Number of Shares/Units, Forfeited (in shares)		0	0	(42,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)		0	0	178,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)		$ 0	$ 10.47	$ 10.01
Weighted Average Fair Value, Granted (in dollars per share)		0	0	0
Weighted Average Fair Value, Vested (in dollars per share)		0	10.47	9.59
Weighted Average Fair Value, Forfeited (in dollars per share)		0	0	10.47
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)		$ 0	$ 0	$ 10.47
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)

Long-Term Incentive Compensa_13

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Liability-classified stock-based compensation cost - expensed	$ 12	$ 5	$ 7
Liability-classified stock-based compensation cost - capitalized	$ 8	$ 2	$ 5

Long-Term Incentive Compensa_14

Long-Term Incentive Compensation (Summary of Liability-Classified Restricted Stock Unit Activity) (Details) - Liability-Classified RSUs - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Number of Units
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	11,613,000	12,992,000	8,202,000
Number of Shares/Units, Granted (in shares)	1,486,000	6,172,000	8,659,000
Number of Shares/Units, Vested (in shares)	(4,522,000)	(3,960,000)	(2,624,000)
Number of Shares/Units, Forfeited (in shares)	(640,000)	(3,591,000)	(1,245,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	7,937,000	11,613,000	12,992,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 2.67	$ 2.42	$ 3.41
Weighted Average Fair Value, Granted (in dollars per share)	4.23	1.41	4.34
Weighted Average Fair Value, Vested (in dollars per share)	3.40	1.43	4.09
Weighted Average Fair Value, Forfeited (in dollars per share)	4.56	2.67	3.48
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 4.08	$ 2.67	$ 2.42
Workforce Reduction
Number of Units
Number of Shares/Units, Forfeited (in shares)	(360,253)	(2,010,196)	(400,056)

Long-Term Incentive Compensa_15

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Liability-classified stock-based compensation cost - expensed	$ 12	$ 7	$ 2
Liability-classified stock-based compensation cost - capitalized	$ 6	$ 2	$ 1

Long-Term Incentive Compensa_16

Long-Term Incentive Compensation (Summary of Liability-Classified Performance Unit Activity) (Details) - Liability-Classified Performance Units - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Number of Units
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	8,699,000	5,142,000	2,803,000
Number of Shares/Units, Granted (in shares)	3,580,000	6,172,000	2,757,000
Number of Shares/Units, Vested (in shares)	(2,020,000)	0	(43,000)
Number of Shares/Units, Forfeited (in shares)	(744,000)	(2,615,000)	(375,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	9,515,000	8,699,000	5,142,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 2.57	$ 2.42	$ 3.41
Weighted Average Fair Value, Granted (in dollars per share)	4.14	1.41	4.34
Weighted Average Fair Value, Vested (in dollars per share)	4.05	0	2.42
Weighted Average Fair Value, Forfeited (in dollars per share)	3.40	3.05	3.12
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 2.88	$ 2.57	$ 2.42
Workforce Reduction
Number of Units
Number of Shares/Units, Forfeited (in shares)		(518,450)	(375,086)

Long-Term Incentive Compensa_17

Long-Term Incentive Compensation (Schedule of Performance Cash Awards Stock-Based Compensation Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	$ 30	$ 17	$ 17
Equity-classified awards - capitalized	18	7	$ 10
Performance cash awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-classified awards - expensed	4	2
Equity-classified awards - capitalized	$ 4	$ 2

Long-term Incentive Compensa_18

Long-term Incentive Compensation (Summary of Performance Cash Awards Activity) (Details) - Performance cash awards - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Number of Shares
Number of Shares/Units, Unvested shares/units at January 1 (in shares)	18,353,000	0
Number of Shares/Units, Granted (in shares)	18,546,000	20,044,000
Number of Shares/Units, Vested (in shares)	(4,955,000)	(100,000)
Number of Shares/Units, Forfeited (in shares)	(3,672,000)	(1,591,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares)	28,272,000	18,353,000
Weighted Average Fair Value
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share)	$ 1	$ 0
Weighted Average Fair Value, Granted (in dollars per share)	1	1
Weighted Average Fair Value, Vested (in dollars per share)	1	1
Weighted Average Fair Value, Forfeited (in dollars per share)	1	1
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share)	$ 1	$ 1
Workforce Reduction
Number of Shares
Number of Shares/Units, Forfeited (in shares)	(1,241,000)	(945,500)

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Revenues from external customers	$ 6,667	$ 2,308	$ 3,038
Depreciation, depletion and amortization expense	546	357	471
Impairments	6	2,830	16
Operating income	2,635	(2,871)	270
Interest expense	136	94	65
Total gain (loss) on derivatives	(2,436)	224	274
Gain (Loss) on Early Extinguishment of Debt	(93)	35	8
Other income, net	5	1	(7)
Provision (benefit) for income taxes	0	407	(411)
Assets	11,848	5,160	6,717
Capital investments	1,108	899	1,140
Restructuring charges	7	16	11
Merger-related expenses	76	41	0
Increase (decrease) in accrued expenditures between periods	70	(3)	34
Marketing
Segment Reporting Information [Line Items]
Revenues from external customers	1,963	917	1,297
Exploration and Production
Segment Reporting Information [Line Items]
Revenues from external customers	4,701	1,391	1,740
Depreciation, depletion and amortization expense			462
Merger-related expenses	76	41
Marketing
Segment Reporting Information [Line Items]
Revenues from external customers	1,966	917	1,298
Depreciation, depletion and amortization expense			9
Intersegment Revenues
Segment Reporting Information [Line Items]
Revenues from external customers	(4,162)	(1,185)	(1,515)
Intersegment Revenues | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers	(4,223)	(1,228)	(1,552)
Intersegment Revenues | Exploration and Production
Segment Reporting Information [Line Items]
Revenues from external customers	61	43	37
Intersegment Revenues | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers	(4,223)	(1,228)	(1,552)
Intersegment Revenues | Marketing | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers	(4,200)	(1,200)	(1,600)
Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Revenues from external customers	4,640	1,348	1,703
Depreciation, depletion and amortization expense	537	348
Impairments	6	2,830	13
Operating income	2,583	(2,864)	283
Interest expense	136	94	65
Total gain (loss) on derivatives	(2,437)	224	274
Gain (Loss) on Early Extinguishment of Debt	0	0	0
Other income, net	5	0	(9)
Provision (benefit) for income taxes	0	407	(411)
Assets	10,767	4,654	6,235
Capital investments	1,107	899	1,138
Restructuring charges	7	16	11
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	6,189	2,145	2,850
Depreciation, depletion and amortization expense	9	9
Impairments	0	0	3
Operating income	52	(7)	(13)
Interest expense	0	0	0
Total gain (loss) on derivatives	0	0	0
Gain (Loss) on Early Extinguishment of Debt	0	0	0
Other income, net	0	0	0
Provision (benefit) for income taxes	0	0	0
Assets	956	381	314
Capital investments	0	0	0
Operating Segments | Marketing | Marketing
Segment Reporting Information [Line Items]
Revenues from external customers	6,186	2,145	2,849
Operating Segments | Marketing | Non Core Gathering Assets
Segment Reporting Information [Line Items]
Impairments			3
Other
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization expense	0	0	0
Impairments	0	0	0
Operating income	0	0	0
Interest expense	0	0	0
Total gain (loss) on derivatives	1	0	0
Gain (Loss) on Early Extinguishment of Debt	(93)	35	8
Other income, net	0	1	2
Provision (benefit) for income taxes	0	0	0
Assets	125	125	168
Capital investments	$ 1	$ 0	$ 2

Segment Information (Schedule o

Segment Information (Schedule of Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Cash and cash equivalents	$ 28	$ 13
Property, plant and equipment	9,938	4,111
Unamortized debt expense	57	20
Operating lease assets	187	163
TOTAL ASSETS	11,848	5,160	$ 6,717
Other
Segment Reporting Information [Line Items]
Cash and cash equivalents	28	13	5
Accounts receivable	0	1	0
Income taxes receivable	0	0	30
Prepayments	6	6	8
Property, plant and equipment	12	16	27
Unamortized debt expense	10	11	11
Operating lease assets	65	72	80
Non-qualified retirement plan	4	6	7
TOTAL ASSETS	$ 125	$ 125	$ 168

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures (Unaudited) (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)Mcfe	Dec. 31, 2020USD ($)Mcfelocation	Dec. 31, 2019USD ($)Mcfelocation	Dec. 31, 2018Mcfe
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	$ 2,231	$ 1,472
Capitalized interest	220
Capitalized interest based on weighted average cost of borrowings	97	88	$ 109
Capitalized internal costs related to acquisition, exploration and development	$ 64	$ 56	$ 77
Percentage of present worth of proved reserves evaluated in audit	99.00%	97.00%	99.00%
Proved reserves, end of period, (bcfe) | Mcfe	21,148,000,000	11,990,000,000	12,721,000,000	11,921,000,000
Proved undeveloped reverses (energy) | Mcfe	0	2,437,000,000	929,000,000
Number of locations | location		138	90
Present value of proved reserves, discounted basis		$ 207	$ 50
Montage Resources Corporation
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	$ 117
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	759
Wells In Progress
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization, cumulative	51
Capitalized interest	$ 220
United States
Natural Gas and Oil Properties [Line Items]
Proved reserves, end of period, (bcfe) | Mcfe	21,148,000,000	11,990,000,000	12,721,000,000	11,921,000,000
Proved undeveloped reverses (energy) | Mcfe	9,813,000,000	3,787,000,000	6,300,000,000

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, 2021	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved properties	$ 31,400	$ 25,789
Unproved properties	2,231	1,472
Total capitalized costs	33,631	27,261
Less: Accumulated depreciation, depletion and amortization	(23,884)	(23,362)
Net capitalized costs	$ 9,747	$ 3,899

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			180 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost [Abstract]
Property acquisition costs	$ 784	$ 85	$ 9	$ 1,079
Exploration and development costs	28	9	7	10
Capitalized interest	75	48	36	61
Net unevaluated costs excluded from amortization	887	142	$ 52	$ 1,150
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Property acquisition costs	1,957
Exploration and development costs	54
Capitalized interest	220
Net unevaluated costs excluded from amortization, cumulative	$ 2,231	$ 1,472

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, 2021USD ($)$ / Mcfe	Dec. 31, 2020USD ($)$ / Mcfe	Dec. 31, 2019USD ($)$ / Mcfe
Natural Gas and Oil Properties [Line Items]
Unproved property acquisition costs	$ 139	$ 124	$ 162
Exploration costs	0	0	2
Development costs	984	784	936
Capitalized costs incurred	$ 1,123	$ 908	$ 1,100
Full cost pool amortization per Mcfe | $ / Mcfe	0.42	0.38	0.56
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Sales	$ 4,640	$ 1,348	$ 1,703
Production (lifting) costs	(1,304)	(866)	(781)
Depreciation, depletion and amortization	(537)	(348)	(462)
Impairment of natural gas and oil properties	0	(2,825)	0
Results of operations - income before income taxes	2,799	(2,691)	460
Provision for income taxes	0	0	110
Results of operations	$ 2,799	(2,691)	$ 350
Income tax expense (benefit), before valuation allowance		$ (624)

Supplemental Oil and Gas Disc_8

Supplemental Oil and Gas Disclosures (Unaudited) (Summary of Changes in Reserves - United States) (Details) Mcf in Millions	12 Months Ended
	Dec. 31, 2021McfebblMcf	Dec. 31, 2020McfeMcfbbl	Dec. 31, 2019McfeMcfbbl	Dec. 31, 2019McfebblMcf	Dec. 31, 2019McfeMcfbbl
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe) | Mcfe	11,990,000,000	12,721,000,000			11,921,000,000
Revisions of previous estimates due to price | Mcfe	415,000,000	(4,370,000,000)			(717,000,000)
Extensions, discoveries and other additions | Mcfe	3,962,000,000	741,000,000			1,195,000,000
Production | Mcfe	(1,240,000,000)	(880,000,000)			(778,000,000)
Acquisition of reserves in place | Mcfe	5,753,000,000	2,354,000,000			0
Disposition of reserves in place | Mcfe	(1,000,000)	0			(2,000,000)
Proved reserves, end of period, (bcfe) | Mcfe	21,148,000,000	11,990,000,000			12,721,000,000
Proved undeveloped reserves:
Proved undeveloped reverses (energy) | Mcfe	0	2,437,000,000	929,000,000	929,000,000	929,000,000
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	11,990,000,000	12,721,000,000			11,921,000,000
Revisions of previous estimates due to price | Mcfe	415,000,000	(4,370,000,000)			(717,000,000)
Revisions of previous estimates other than price | Mcfe	269,000,000	1,424,000,000			1,102,000,000
Extensions, discoveries and other additions | Mcfe	3,962,000,000	741,000,000			1,195,000,000
Production | Mcfe	(1,240,000,000)	(880,000,000)			(778,000,000)
Acquisition of reserves in place | Mcfe	5,753,000,000	2,354,000,000			0
Disposition of reserves in place | Mcfe	(1,000,000)	0			(2,000,000)
Proved reserves, end of period, (bcfe) | Mcfe	21,148,000,000	11,990,000,000			12,721,000,000
Proved developed reserves as of:
Proved developed reserves (energy) | Mcfe	11,335,000,000	8,203,000,000	6,421,000,000	6,421,000,000	6,421,000,000
Proved undeveloped reserves:
Proved undeveloped reverses (energy) | Mcfe	9,813,000,000	3,787,000,000	6,300,000,000	6,300,000,000	6,300,000,000
United States | Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of year | Mcf	9,181	8,630	8,044
Revisions of previous estimates due to price | Mcf	501	(2,143)	(480)
Revisions of previous estimates other than price | Mcf	248	763	685
Extensions, discoveries and other additions | Mcf	2,543	714	992
Production | Mcf	(1,015)	(694)	(609)
Acquisition of reserves in place | Mcf	5,750	1,911
Disposition of reserves in place | Mcf	(1)	0	(2)
Proved reserves, end of year | Mcf	17,207	9,181	8,630
Proved developed reserves as of:
Proved developed reserves (volume) | Mcf	9,308	6,342	4,906	4,906	4,906
Proved undeveloped reserves:
Proved undeveloped reserves (volume) | Mcf	7,899	2,839	3,724	3,724	3,724
United States | Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of year	58,024,000	72,925,000		69,007,000
Revisions of previous estimates due to price	1,414,000	(32,507,000)		(2,041,000)
Revisions of previous estimates other than price	1,900,000	3,816,000		3,707,000
Extensions, discoveries and other additions	24,865,000	135,000		6,948,000
Production	(6,610,000)	(5,141,000)		(4,696,000)
Acquisition of reserves in place	247,000	18,796,000
Disposition of reserves in place	(61,000)	0		0
Proved reserves, end of year	79,779,000	58,024,000		72,925,000
Proved developed reserves as of:
Proved developed reserves (volume)	40,930,000	33,563,000	26,124,000	26,124,000	26,124,000
Proved undeveloped reserves:
Proved undeveloped reserves (volume)	38,849,000	24,461,000	46,801,000	46,801,000	46,801,000
United States | NGL
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of year	410,151,000	608,761,000		577,063,000
Revisions of previous estimates due to price	(15,525,000)	(338,639,000)		(37,492,000)
Revisions of previous estimates other than price	1,500,000	106,444,000		65,869,000
Extensions, discoveries and other additions	211,598,000	4,371,000		26,941,000
Production	(30,940,000)	(25,927,000)		(23,620,000)
Acquisition of reserves in place	180,000	55,141,000
Disposition of reserves in place	0	0		0
Proved reserves, end of year	576,964,000	410,151,000		608,761,000
Proved developed reserves as of:
Proved developed reserves (volume)	296,832,000	276,548,000	226,271,000	226,271,000	226,271,000
Proved undeveloped reserves:
Proved undeveloped reserves (volume)	280,132,000	133,603,000	382,490,000	382,490,000	382,490,000

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	11,990	12,721	11,921
Net revisions
Price revisions	415	(4,370)	(717)
Performance and production revisions	269	1,424	1,102
Total net revisions	684	(2,946)	385
Extensions, discoveries and other additions
Proved developed	451	267	191
Proved undeveloped	3,511	474	1,004
Total reserve additions	3,962	741	1,195
Production	(1,240)	(880)	(778)
Acquisition of reserves in place	5,753	2,354	0
Disposition of reserves in place	(1)	0	(2)
Proved reserves, end of period, (bcfe)	21,148	11,990	12,721
Proved and unproved reserves reclassified			109
Proved Undeveloped Reserves, Additions (Energy) Drilling Program	1,768
Proved Undeveloped Reserves, Additions (Energy) SEC Pricing	1,743
Appalachia
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	11,989	12,720	11,920
Net revisions
Price revisions	415	(4,370)	(717)
Performance and production revisions	270	1,424	1,102
Total net revisions	685	(2,946)	385
Extensions, discoveries and other additions
Proved developed	451	267	191
Proved undeveloped	3,511	474	1,004
Total reserve additions	3,962	741	1,195
Production	(1,108)	(880)	(778)
Acquisition of reserves in place	0	2,354	0
Disposition of reserves in place	(1)	0	(2)
Proved reserves, end of period, (bcfe)	15,527	11,989	12,720
Haynesville
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	0	0	0
Net revisions
Price revisions	0	0	0
Performance and production revisions	0	0	0
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	(132)	0	0
Acquisition of reserves in place	5,753	0	0
Disposition of reserves in place	0	0	0
Proved reserves, end of period, (bcfe)	5,621	0	0
Other
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period, (bcfe)	1	1	1
Net revisions
Price revisions	0	0	0
Performance and production revisions	(1)	0	0
Total net revisions	(1)	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	0
Acquisition of reserves in place	0	0	0
Disposition of reserves in place	0	0	0
Proved reserves, end of period, (bcfe)	0	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, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 75,314	$ 17,997	$ 27,003
Future production costs	(23,235)	(11,969)	(14,981)
Future development costs	(6,032)	(1,924)	(3,246)
Future income tax expense	(8,135)	0	(476)
Future net cash flows	37,912	4,104	8,300
10% annual discount for estimated timing of cash flows	(19,181)	(2,257)	(4,600)
Standardized measure of discounted future net cash flows	$ 18,731	$ 1,847	$ 3,700	$ 5,999

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, 2021$ / MMBTU	Dec. 31, 2021$ / barrel	Dec. 31, 2021$ / bbl	Dec. 31, 2020$ / MMBTU	Dec. 31, 2020$ / barrel	Dec. 31, 2020$ / bbl	Dec. 31, 2019$ / MMBTU	Dec. 31, 2019$ / barrel	Dec. 31, 2019$ / bbl
Natural Gas
Reserve Quantities [Line Items]
Average sales price ($ per unit)	3.60			1.98			2.58
Oil
Reserve Quantities [Line Items]
Average sales price ($ per unit)		66.56	66.56		39.57	39.57		55.69	55.69
NGL
Reserve Quantities [Line Items]
Average sales price ($ per unit)		28.65	28.65		10.27	10.27		11.58	11.58

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, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 1,847	$ 3,700	$ 5,999
Sales and transfers of natural gas and oil produced, net of production costs	(3,332)	(478)	(923)
Net changes in prices and production costs	10,417	(2,720)	(3,510)
Extensions, discoveries, and other additions, net of future production and development costs	3,183	81	234
Increase Due to Purchases of Minerals in Place	6,499	443	0
Sales of reserves in place	(1)	0	(2)
Revisions of previous quantity estimates	596	(987)	152
Net change in income taxes	(3,689)	35	491
Changes in estimated future development costs	137	1,241	621
Previously estimated development costs incurred during the year	419	624	704
Changes in production rates (timing) and other	2,470	(466)	(718)
Accretion of discount	185	374	652
Standardized measure, end of year	$ 18,731	$ 1,847	$ 3,700