SOUTHWESTERN ENERGY CO, 10-K filed on 2/22/2024
Annual Report
v3.24.0.1
Cover Page - USD ($)
 12 Months Ended
Dec. 31, 2023
Feb. 20, 2024
Jun. 30, 2023
Cover [Abstract]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2023    
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 2023    
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    
Document Financial Statement Error Correction false    
Entity Shell Company false    
Entity Public Float     $ 6,577,423,795
Entity Common Stock, Shares Outstanding   1,101,463,052  
Documents Incorporated by Reference
None.
    
Document Transition Report false    
v3.24.0.1
Audit Information
 12 Months Ended
Dec. 31, 2023
Auditor Information [Abstract]  
Auditor name PricewaterhouseCoopers LLP
Auditor location Houston, Texas
Auditor firm ID 238
v3.24.0.1
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Operating Revenues:      
Total operating revenues $ 6,522 $ 15,002 $ 6,667
Operating Costs and Expenses:      
Marketing purchases 2,331 4,392 1,957
Operating expenses 1,717 1,616 1,170
General and administrative expenses 187 170 138
Merger-related expenses 0 27 76
Restructuring charges 0 0 7
Depreciation, depletion and amortization 1,307 1,174 546
Impairments 1,710 0 6
Taxes, other than income taxes 244 269 132
Total Operating Costs and Expenses 7,496 7,648 4,032
Operating Income (Loss) (974) 7,354 2,635
Interest Expense:      
Interest on debt 246 292 220
Other interest charges 11 13 13
Interest capitalized (115) (121) (97)
Total Interest Expense 142 184 136
Gain (Loss) on Derivatives 2,433 (5,259) (2,436)
Loss on Early Extinguishment of Debt (19) (14) (93)
Other Income, Net 2 3 5
Income (Loss) Before Income Taxes 1,300 1,900 (25)
Provision (Benefit) for Income Taxes:      
Current (5) 51 0
Deferred (252) 0 0
Provision (Benefit) for Income Taxes (257) 51 0
Net Income (Loss) $ 1,557 $ 1,849 $ (25)
Earnings (Loss) Per Common Share      
Basic (in dollars per share) $ 1.41 $ 1.67 $ (0.03)
Diluted (in dollars per share) $ 1.41 $ 1.66 $ (0.03)
Weighted Average Common Shares Outstanding:      
Basic (in shares) 1,100,980,199 1,110,564,839 789,657,776
Diluted (in shares) 1,103,406,255 1,113,184,254 789,657,776
Gas sales      
Operating Revenues:      
Total operating revenues $ 3,089 $ 9,101 $ 3,412
Oil sales      
Operating Revenues:      
Total operating revenues 379 439 394
NGL sales      
Operating Revenues:      
Total operating revenues 702 1,046 890
Marketing      
Operating Revenues:      
Total operating revenues 2,355 4,419 1,963
Other      
Operating Revenues:      
Total operating revenues $ (3) $ (3) $ 8
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Statement of Comprehensive Income [Abstract]      
Net income (loss) $ 1,557 $ 1,849 $ (25)
Change in value of pension and other postretirement liabilities:      
Amortization of prior service cost and net (gain) loss, including (gain) loss on settlements and curtailments included in net periodic pension cost [1] (2) (3) 2
Net actuarial gain (loss) incurred in period [2] 7 34 11
Tax valuation allowance release impact on pension settlements (14) 0 0
Total change in value of pension and postretirement liabilities (9) 31 13
Comprehensive income (loss) $ 1,548 $ 1,880 $ (12)
[1] Includes tax effects that were not significant for 2021 which were netted against the valuation allowance and therefore included in accumulated other comprehensive income.
[2] Includes tax effect gains which were not significant for all periods presented and were netted against a valuation allowance and therefore included in accumulated other comprehensive income.
v3.24.0.1
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Current assets:    
Cash and cash equivalents $ 21 $ 50
Accounts receivable, net 680 1,401
Derivative assets 614 145
Other current assets 100 68
Total current assets 1,415 1,664
Natural gas and oil properties, using the full cost method, including $2,075 million as of December 31, 2023 and $2,217 million as of December 31, 2022 excluded from amortization 37,772 35,763
Other 566 527
Less: Accumulated depreciation, depletion and amortization (28,425) (25,387)
Total property and equipment, net 9,913 10,903
Operating lease assets 154 177
Long-term derivative assets 175 72
Deferred tax assets 238 0
Other long-term assets 96 110
Total long-term assets 663 359
TOTAL ASSETS 11,991 12,926
Current liabilities:    
Accounts payable 1,384 1,835
Taxes payable 128 136
Interest payable 77 86
Derivative liabilities 79 1,317
Current operating lease liabilities 44 42
Other current liabilities 17 65
Total current liabilities 1,729 3,481
Long-term debt 3,947 4,392
Long-term operating lease liabilities 107 133
Long-term derivative liabilities 100 378
Other long-term liabilities 220 218
Total long-term liabilities 4,374 5,121
Commitments and contingencies (Note 10)
Equity:    
Common stock, $0.01 par value; 2,500,000,000 shares authorized; issued 1,163,077,745 shares as of December 31, 2023 and 1,161,545,588 as of December 31, 2022 12 12
Additional paid-in capital 7,188 7,172
Accumulated deficit (982) (2,539)
Accumulated other comprehensive income (loss) (3) 6
Common stock in treasury, 61,614,693 shares as of December 31, 2023 and as of December 31, 2022 (327) (327)
Total equity 5,888 4,324
TOTAL LIABILITIES AND EQUITY $ 11,991 $ 12,926
Treasury stock, shares (in shares) 61,614,693 61,614,693
v3.24.0.1
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Statement of Financial Position [Abstract]    
Net unevaluated costs excluded from amortization, cumulative $ 2,075 $ 2,217
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) 1,163,077,745 1,161,545,588
Treasury stock, shares (in shares) 61,614,693 61,614,693
v3.24.0.1
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Cash Flows From Operating Activities:      
Net income (loss) $ 1,557 $ 1,849 $ (25)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:      
Depreciation, depletion and amortization 1,307 1,174 546
Amortization of debt issuance costs 7 11 9
Impairments 1,710 0 6
Deferred income taxes (252) 0 0
(Gain) loss on derivatives, unsettled (2,088) (24) 944
Stock-based compensation 9 4 2
Loss on early extinguishment of debt 19 14 93
Other 4 2 (3)
Changes in assets and liabilities, net of effect of Mergers:      
Accounts receivable 721 (240) (425)
Accounts payable (375) 390 261
Taxes payable (8) 43 (4)
Interest payable (5) 4 6
Inventories (27) 2 (3)
Other assets and liabilities (63) (75) (44)
Net cash provided by operating activities 2,516 3,154 1,363
Cash Flows From Investing Activities:      
Capital investments (2,170) (2,115) (1,032)
Proceeds from sale of property and equipment 123 72 4
Cash acquired in mergers 0 0 66
Cash paid in mergers 0 0 (1,642)
Net cash used in investing activities (2,047) (2,043) (2,604)
Cash Flows From Financing Activities:      
Payments on current portion of long-term debt 0 (210) 0
Payments on long-term debt (437) (612) (1,177)
Payments on revolving credit facility (4,718) (12,071) (6,628)
Borrowings under revolving credit facility 4,688 11,861 6,388
Change in bank drafts outstanding (27) 79 5
Repayment of revolving credit facilities associated with Mergers 0 0 (176)
Proceeds from exercise of common stock options 0 7 0
Proceeds from issuance of long-term debt 0 0 2,900
Debt issuance and other financing costs 0 (14) (53)
Purchase of treasury stock 0 (125) 0
Cash paid for tax withholding (4) (4) (3)
Net cash provided by (used in) financing activities (498) (1,089) 1,256
Increase (decrease) in cash and cash equivalents (29) 22 15
Cash and cash equivalents at beginning of year 50 28 13
Cash and cash equivalents at end of year $ 21 $ 50 $ 28
v3.24.0.1
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, 2020   718,795,700        
Beginning balance at Dec. 31, 2020 $ 497 $ 7 $ 5,093 $ (4,363) $ (38) $ (202)
Beginning balance treasury stock (in share) at Dec. 31, 2020           44,353,224
Comprehensive loss            
Net income (loss) (25)     (25)    
Other comprehensive income 13       13  
Comprehensive income (loss) (12)          
Stock-based compensation $ 2   2      
Exercise of stock options (in shares) 0          
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        
Treasury Stock 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        
Ending balance at Dec. 31, 2021 2,547 $ 12 7,150 (4,388) (25) $ (202)
Ending balance treasury stock (in share) at Dec. 31, 2021           44,353,224
Comprehensive loss            
Net income (loss) 1,849     1,849    
Other comprehensive income 31       31  
Comprehensive income (loss) 1,880          
Stock-based compensation $ 7   7      
Exercise of stock options (in shares) 893,000 893,312        
Exercise of stock options $ 7   7      
Issuance of common stock (in shares)   79        
Issuance of common stock 0   0      
Issuance of restricted stock (in shares)   185,774        
Restricted units granted (in shares)   21,981        
Performance units vested (in shares)   2,499,860        
Performance units vested $ 12   12      
Treasury stock (in shares) 17,261,469         17,261,469
Treasury stock $ (125)         $ (125)
Tax withholding - stock compensation (in shares)   (728,084)        
Tax withholding – stock compensation (4)   (4)      
Ending balance (in shares) at Dec. 31, 2022   1,161,545,588        
Ending balance at Dec. 31, 2022 $ 4,324 $ 12 7,172 (2,539) 6 $ (327)
Ending balance treasury stock (in share) at Dec. 31, 2022 61,614,693         61,614,693
Comprehensive loss            
Net income (loss) $ 1,557     1,557    
Other comprehensive income (9)       (9)  
Comprehensive income (loss) 1,548          
Stock-based compensation $ 12   12      
Exercise of stock options (in shares) 0          
Issuance of restricted stock (in shares)   188,382        
Restricted units granted (in shares)   2,009,007        
Restricted units granted $ 8   8      
Treasury stock (in shares) 0          
Tax withholding - stock compensation (in shares)   (665,232)        
Tax withholding – stock compensation $ (4)   (4)      
Ending balance (in shares) at Dec. 31, 2023   1,163,077,745        
Ending balance at Dec. 31, 2023 $ 5,888 $ 12 $ 7,188 $ (982) $ (3) $ (327)
Ending balance treasury stock (in share) at Dec. 31, 2023 61,614,693         61,614,693
v3.24.0.1
Organization and Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2023
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 development, exploration 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 development 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 (“Haynesville and Bossier Shales”). 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 2023 and 2022 amounts to prior periods could be impacted as a result of the Indigo Merger (as defined below) completed 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, 2023, 2022 and 2021 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, 2023 one purchaser accounted for approximately 14% 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, 2022, one purchaser accounted for 17% 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 $21 million and $50 million in cash and cash equivalents as of December 31, 2023 and 2022, 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 $73 million and $100 million as of December 31, 2023 and 2022, 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. 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, 2023 and 2022:
(in millions)20232022
Proved properties$35,697 $33,546 
Unproved properties2,075 2,217 
Total capitalized costs37,772 35,763 
Less:  Accumulated depreciation, depletion and amortization(28,031)(25,033)
Net capitalized costs$9,741 $10,730 
Under the full cost method of accounting, productive and nonproductive costs, 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,
202320222021
Natural gas (per MMBtu)
$2.64 $6.36 $3.60 
Oil (per Bbl)
$78.22 $93.67 $66.56 
NGLs (per Bbl)
$21.38 $34.35 $28.65 
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 exceeded the ceiling amount at December 31, 2023, resulting in an impairment of $1,710 million. The net book value of its natural gas and oil properties did not exceed the ceiling amount at December 31, 2022 or 2021. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2023, 2022 and 2021. Given the decline in commodity prices during 2023 and early 2024, the Company expects that an additional non-cash impairment of its asset will likely occur in the first quarter of 2024 and perhaps later.
No impairment expense was recorded in 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. Had management not received the waiver from the SEC, no impairment charge would have been recorded in 2021 even when including the Montage natural gas and oil properties in the full cost ceiling test due to improved commodity prices during 2021.
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, 2023, the Company had a total of $2,075 million of costs excluded from the amortization base, all of which related to its properties in the United States.
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, 2023:
(in millions)202320222021PriorTotal
Property acquisition costs$63 $86 $559 $1,005 $1,713 
Exploration and development costs24 9 8 18 59 
Capitalized interest115 91 75 22 303 
$202 $186 $642 $1,045 $2,075 
Of the total net unevaluated costs excluded from amortization as of December 31, 2023, approximately $1,048 million is related to undeveloped properties in Appalachia which were acquired in 2014 and 2015, $137 million is related to Montage properties acquired in November 2020 and approximately $587 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 $303 million of unevaluated capitalized interest. The Company has $59 million of unevaluated costs related to wells in progress (included within the Appalachia, Montage and Haynesville amounts above). 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.
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
3 – 10 years
Gathering systems
15 – 25 years
Technology infrastructure
3 – 10 years
Drilling rigs and equipment
3 years
Buildings and leasehold improvements
5 – 30 years
Other property, plant and equipment is comprised of the following:
(in millions)December 31, 2023December 31, 2022
Water facilities$252 $238 
Gathering systems60 56 
Technology infrastructure146 135 
Drilling rigs and equipment35 31 
Land, buildings and leasehold improvements16 16 
Other57 51 
Less: Accumulated depreciation and impairment(394)(354)
Total$172 $173 
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. The Company did not recognize an impairment on its non-full cost pool long-lived assets during the years ended December 31, 2023 and December 31, 2022. The Company recognized an impairment of $6 million related to non-core assets for the year ended December 31, 2021.
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, 2023 and 2022, the Company had $38 million and $43 million, respectively, in marketing-related intangible assets, of which $33 million and $38 million were included in Other long-term assets on the respective consolidated balance sheets. The Company amortized $5 million of its marketing-related intangible asset in 2023, $5 million in 2022 and $8 million in 2021. The Company expects to amortize $5 million during each year from 2024 to 2027 and $4 million in 2028.
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, 2023. By policy election, leases with an initial term of twelve months or less are not recorded on the balance sheet. The Company recognizes lease expense for these leases on a straight-line basis, and variable lease payments are recognized in the period as incurred.
Certain leases contain both lease and non-lease components. The Company has chosen to account for most of these leases as a single lease component instead of bifurcating lease and non-lease components. However, for compression service leases and fleet vehicle leases, the lease and non-lease components are accounted for separately.
The Company leases drilling rigs, pressure pumping equipment, vehicles, office space, certain water transportation lines and other equipment under non-cancelable operating leases expiring through 2036. Certain lease agreements include options to renew the lease, early terminate the lease or purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. The Company’s water transportation lines are the only leases with renewal options that are reasonably certain to be exercised. These renewal options are reflected in the right-of-use asset and lease liability balances.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized.
The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations. Additional information regarding uncertain tax positions can be found in Note 11.
Derivative Financial Instruments
The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses derivative instruments to financially protect sales of natural gas, oil and NGLs. In addition, the Company uses interest rate swaps to manage exposure to unfavorable interest rate changes. Since the Company does not designate its derivatives for hedge accounting treatment, gains and losses resulting from the settlement of derivative contracts have been recognized in gain (loss) on derivatives in the consolidated statements of operations when the contracts expire and the related physical transactions of the underlying commodity are settled. Additionally, changes in the fair value of the unsettled portion of derivative contracts are also recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 6 and Note 8 for a discussion of the Company’s hedging activities.
Earnings Per Share
Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during the reportable period. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock, restricted stock units and performance units. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.
In 2023, there were no share repurchases that occurred during the year.
In 2022, in connection with our share repurchase program, we repurchased approximately 17,261,469 shares at an average price of $7.24 per share for a total cost of approximately $125 million.
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.
The following table presents the computation of earnings per share for the years ended December 31, 2023, 2022 and 2021:
For the years ended December 31,
(in millions, except share/per share amounts)202320222021
Net income (loss)$1,557 $1,849 $(25)
Number of common shares:
Weighted average outstanding1,100,980,199 1,110,564,839 789,657,776 
Issued upon assumed exercise of outstanding stock options— — — 
Effect of issuance of non-vested restricted common stock862,434 763,067 — 
Effect of issuance of non-vested restricted units1,431,754 1,500,815 — 
Effect of issuance of non-vested performance units131,868 355,533 — 
Weighted average and potential dilutive outstanding1,103,406,255 1,113,184,254 789,657,776 
   
Earnings (loss) per common share:   
Basic$1.41 $1.67 $(0.03)
Diluted$1.41 $1.66 $(0.03)
The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2023, 2022 and 2021, as they would have had an antidilutive effect:
For the years ended December 31,
202320222021
Unexercised stock options831,525 2,265,589 3,683,363 
Unvested share-based payment46,101 53,924 832,989 
Restricted units211,506 192,515 2,226,981 
Performance units— — 2,194,477 
Total1,089,132 2,512,028 8,937,810 
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, 2023, 2022 and 2021:
For the years ended December 31,
(in millions)202320222021
Cash paid during the year for interest, net of amounts capitalized$140 $161 $106 
Cash paid during the year for income taxes13 41 — 
(1)
Non-cash investing activities(39)94 3,690 
(2)
Non-cash financing activities— — 2,051 
(3)
(1)Cash received in 2021 for income taxes was immaterial.
(2)Includes $3,045 million and $581 million in non-cash property additions related to the Indigo Merger and the GEPH Merger, respectively.
(3)Includes $1,588 million and $463 million in common stock consideration related to the Indigo Merger and the GEPH Merger, respectively.
Stock-Based Compensation
The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties. See Note 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 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 total shareholder return (“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. In 2022 and 2023, two types of performance units were granted. One type of award includes performance conditions based on return on capital employed and reinvestment rate. The other awards granted in 2022 and 2023 were accounted for as equity classified awards. 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 cancelled.
Treasury Stock
In 2022, the Company repurchased 17,261,469 shares of its outstanding common stock per a previously announced share repurchase program at an average price of $7.24 per share for approximately $125 million.
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, 2023 and 2022, 1,455 shares and 1,743 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
None that are expected to have a material impact.
New Accounting Standards Not Yet Adopted in this Report
In November 2023, the Financial Accounting Standards Board (the “FASB”) issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The purpose of this update is to enhance disclosures on reportable segments and provide additional detailed information about significant segment expenses. The guidance in ASU 2023-07 is effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. The Company continues to assess the impact of the new guidance, but it is not expected to have a material impact on the consolidated financial statements.
In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The purpose of this update is to enhance disclosures through further disaggregated information on the effective tax rate reconciliation based on specified categories, as well as disaggregation of income taxes paid by jurisdiction. The guidance in ASU 2023-09 is effective for fiscal years beginning after December 15, 2024. The Company continues to assess the impact of the new guidance, but it is not expected to have a material impact on the consolidated financial statements.
v3.24.0.1
Acquisitions
 12 Months Ended
Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]  
Acquisitions ACQUISITIONS
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 and Bossier Shales.
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 $1,263 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 issued99,337,748 
NYSE closing price per share of Southwestern common shares on December 31, 2021$4.66 
$463 
Cash consideration(1)
1,263 
Total consideration$1,726 
(1)Reflects $6 million of post-close cash consideration adjustments.
The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation was complete as of the fourth quarter of 2022.
(in millions)As of December 31, 2021
Consideration:
Total consideration$1,726 
Fair Value of Assets Acquired:
Cash and cash equivalents11 
Accounts receivable(1)
180 
Other current assets(1)
1 
Commodity derivative assets56 
Evaluated oil and gas properties1,783 
Unevaluated oil and gas properties59 
Other property, plant and equipment2 
Other long-term assets3 
Total assets acquired2,095 
Fair Value of Liabilities Assumed:
Accounts payable(1)
176 
Other current liabilities1 
Derivative liabilities75 
Revolving credit facility81 
Asset retirement obligations24 
Other noncurrent liabilities(1)
12 
Total liabilities assumed369 
Net Assets Acquired and Liabilities Assumed$1,726 
(1)Reflects adjustments consisting of a $9 million increase to accounts receivable, a $2 million decrease to other current assets, a $6 million increase to accounts payable and a $7 million increase to other non-current liabilities during the twelve months ended December 31, 2022.
The assets acquired and liabilities assumed were recorded at their fair values at the date of the GEPH Merger. The valuation of certain assets, including property, were based on appraisals. The fair value of acquired equipment was 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 issued337,827,171 
NYSE closing price per share of Southwestern common shares on September 1, 2021$4.70 
$1,588 
Cash consideration373 
Total consideration$1,961 
The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation was complete as of the third quarter of 2022.
(in millions)As of September 1, 2021
Consideration:
Total consideration$1,961 
Fair Value of Assets Acquired:
Cash and cash equivalents55 
Accounts receivable (2)
193 
Other current assets2 
Commodity derivative assets2 
Evaluated oil and gas properties2,724 
Unevaluated oil and gas properties (1)
690 
Other property, plant and equipment4 
Other long-term assets27 
Total assets acquired3,697 
Fair Value of Liabilities Assumed:
Accounts payable (2)
285 
Other current liabilities55 
Derivative liabilities501 
Revolving credit facility95 
Senior unsecured notes726 
Asset retirement obligations8 
Other noncurrent liabilities (2)
66 
Total liabilities assumed1,736 
Net Assets Acquired and Liabilities Assumed$1,961 
(1)Reflects a $6 million adjustment during 2022 due to finalization of purchase accounting.
(2)Reflects adjustments consisting of a $1 million increase to accounts receivable, an $11 million increase to accounts payable and a $4 million decrease to other non-current liabilities during 2022 due to finalization of purchase accounting.
The assets acquired and liabilities assumed were recorded at their fair values at the date of the Indigo Merger. The valuation of certain assets, including property, were based on appraisals. The fair value of acquired equipment was 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 $690 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 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 the acquisition date, up to approximately $34 million of these contractual commitments remained and the Company recorded a $17 million liability. As of
December 31, 2023, up to approximately $24 million of these contractual commitments remain, and the Company has a $14 million remaining liability for the estimated future payments.
Excluding the Cotton Valley gathering agreement (discussed above), the Company has recorded additional liabilities totaling $81 million as of the acquisition close date and had $3 million remaining as of December 31, 2023, primarily related to purchase or volume commitments associated with gathering, fresh water and sand.
Pro Forma Information
The following table summarizes the unaudited pro forma condensed financial information of Southwestern as if the Indigo Merger and the GEPH Merger each had occurred on January 1, 2020:
For the year ended December 31,
(in millions, except per share amounts)2021
Revenues$8,301 
Net income (loss) attributable to common stock$(354)
Net income (loss) attributable to common stock per share – basic$(0.32)
Net income (loss) attributable to common stock per share – diluted$(0.32)
The unaudited pro forma information is not necessarily indicative of the operating results that would have occurred had 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 date discussed above and is a result of combining the statements of operations of Southwestern with the pre-merger results of 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. Interest expense was also adjusted to include the impact of the assumption and exchange of Indigo’s $700 million of 5.375% Senior Notes due 2029 for equivalent Southwestern senior notes and to reflect the retirement of the Indigo and GEPH credit facilities, all related accrued interest and the associated decreases in amortization of issuance costs related to the respective revolving lines of credit. Management believes the estimates and assumptions are reasonable, and the relative effects of the Mergers are properly reflected.
Merger-Related Expenses
There were no merger-related expenses incurred for the year ended December 31, 2023. The following table summarizes the merger-related expenses incurred for the years ended December 31, 2022 and 2021:
For the years ended December 31,
20222021
(in millions)Indigo
Merger		GEPH
Merger		TotalIndigo
Merger		GEPH
Merger
Other (1)
Total
Transition Services$— $18 $18 $— $— $— $— 
Professional fees (bank, legal, consulting)— 1 1 27 19 1 47 
Representation & warranty insurance— — — 4 7 — 11 
Contract buyouts, terminations and transfers1 2 3 7 1 — 8 
Due diligence and environmental1 1 2 3 1 — 4 
Employee-related— 1 1 2 — 1 3 
Other— 2 2 2 — 1 3 
Total merger-related expenses$2 $25 $27 $45 $28 $3 $76 
v3.24.0.1
Restructuring Charges
 12 Months Ended
Dec. 31, 2023
Restructuring and Related Activities [Abstract]  
Restructuring Charges RESTRUCTURING CHARGES
In February 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. The Company incurred total severance related costs of approximately $7 million
for the year ended December 31, 2021 which were recognized as restructuring charges and were substantially complete by the end of the first quarter of 2021. All restructuring charges were recorded on the Company’s E&P segment and are included in Operating Income for the year ended December 31, 2021.
The Company had no material restructuring activities during the years ended December 31, 2023 and December 31, 2022, and had no material liabilities associated with restructuring at December 31, 2023 and December 31, 2022.
v3.24.0.1
Leases
 12 Months Ended
Dec. 31, 2023
Leases [Abstract]  
Leases LEASES
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)202320222021
Operating lease cost$62 $63 $54 
Short-term lease cost103 93 15 
Variable lease cost3 3 3 
Total lease cost$168 $159 $72 
As of December 31, 2023, the Company had operating leases of $4 million, related primarily to compressor leases, which have been executed but not yet commenced. These operating leases are planned to commence during 2024 with lease terms expiring through 2027. 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)202320222021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$61 $62 $53 
Right-of-use assets obtained in exchange for operating liabilities:
Operating leases$27 $43 $73 

Supplemental balance sheet information related to leases is as follows:
(in millions)December 31, 2023December 31, 2022
Right-of-use asset balance:
Operating leases$154 $177 
Lease liability balance:
Current operating leases$44 $42 
Long-term operating leases107 133 
Total operating leases$151 $175 
Weighted average remaining lease term: (years)
Operating leases4.14.9
Weighted average discount rate:
Operating leases7.50 %7.32 %
Maturity analysis of operating lease liabilities:
(in millions)December 31, 2023
2024$53 
202539 
202633 
202729 
202814 
Thereafter6 
Total undiscounted lease liability174 
Imputed interest(23)
Total discounted lease liability$151 
v3.24.0.1
Revenue Recognition
 12 Months Ended
Dec. 31, 2023
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&PMarketingIntersegment
Revenues		Total
Year ended December 31, 2023    
Gas sales$3,036 $— $53 $3,089 
Oil sales374 — 5 379 
NGL sales702 — — 702 
Marketing— 6,277 (3,922)2,355 
Other (1)
(3)— — (3)
Total$4,109 $6,277 $(3,864)$6,522 
    
Year ended December 31, 2022    
Gas sales$9,100 $— $1 $9,101 
Oil sales434 — 5 439 
NGL sales1,046 — — 1,046 
Marketing— 14,521 (10,102)4,419 
Other (1)
(3)— — (3)
Total$10,577 $14,521 $(10,096)$15,002 
    
Year ended December 31, 2021    
Gas sales$3,358 $— $54 $3,412 
Oil sales389 — 5 394 
NGL sales888 — 2 890 
Marketing— 6,186 (4,223)1,963 
Other (1)
5 3 — 8 
Total$4,640 $6,189 $(4,162)$6,667 
(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)202320222021
Appalachia$2,543 $6,314 $3,955 
Haynesville1,566 4,263 682 
Other— — 3 
Total$4,109 $10,577 $4,640 
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, 2023December 31, 2022
Receivables from contracts with customers$622 $1,313 
Other accounts receivable58 88 
Total accounts receivable$680 $1,401 
Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were not significant for the years ended December 31, 2023 and 2022. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.
v3.24.0.1
Derivatives and Risk Management
 12 Months Ended
Dec. 31, 2023
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, 2023, 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 swapsIf 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 collarsArrangements 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 collarsArrangements 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 swapsArrangements 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.
Interest rate swapsInterest 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, 2023:
Financial Protection on Production
 Weighted Average Price per MMBtu
 Fair value at December 31, 2023
($ in millions)
Volume
(Bcf)
SwapsSold PutsPurchased PutsSold CallsBasis Differential
Natural Gas
2024
Fixed price swaps528 $3.54 $— $— $— $— $448 
Two-way costless collars44 — — 3.07 3.53 — 22 
Three-way costless collars88 — 2.47 3.20 4.09 — 35 
Total660 $505 
2025
Two-way costless collars73 $— $— $3.50 $5.40 $— $31 
Three-way costless collars161 — 2.59 3.66 5.88 — 56 
Total234 $87 
Basis swaps
202482 $— $— $— $— $(0.72)$8 
20259 — — — — (0.64)4 
Total91 $12 
 Weighted Average Price per Bbl
Fair value at December 31, 2023
($ in millions)
Volume
(MBbls)
SwapsSold PutsPurchased PutsSold Calls
Oil     
2024     
Fixed price swaps1,571 $71.06 $— $— $— $(1)
Two-way costless collars512 — — 70.00 85.63 2 
Three-way costless collars92 — 65.00 75.00 93.10 — 
Total2,175 $1 
2025
Fixed price swaps41 $77.66 $— $— $— $— 
Three-way costless collars1,002 — 60.00 70.00 94.64 2 
Total1,043 $2 
Ethane
2024
Fixed price swaps4,897 $10.61 $— $— $— $9 
Propane
2024
Fixed price swaps4,008 $31.38 $— $— $— $11 
2025
Fixed price swaps63 $26.46 $— $— — $— 
Normal Butane
2024
Fixed price swaps329 $40.74 $— $— $— $1 
Natural Gasoline
2024
Fixed price swaps329 $64.37 $— $— $— $2 
Other Derivative Contracts
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair value at December 31, 2023
($ in millions)
Call Options – Natural Gas (Net)   
202482 $6.56 $(1)
202573 7.00 (6)
202673 7.00 (11)
Total228 $(18)
At December 31, 2023, the net fair value of the Company’s financial instruments was a $610 million asset, including a net reduction of the asset of $2 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, 2023, 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, 2023 and 2022:
Derivative Assets 
Balance Sheet ClassificationFair Value
(in millions)December 31, 2023December 31, 2022
Derivatives not designated as hedging instruments:   
Fixed price swaps – natural gasDerivative assets$466 $— 
Fixed price swaps – oilDerivative assets1 — 
Fixed price swaps – ethaneDerivative assets9 4 
Fixed price swaps – propaneDerivative assets12 9 
Fixed price swaps – normal butaneDerivative assets1 1 
Fixed price swaps – natural gasolineDerivative assets2 1 
Two-way costless collars – natural gasDerivative assets36 47 
Two-way costless collars – oilDerivative assets3 — 
Three-way costless collars – natural gasDerivative assets62 18 
Three-way costless collars – oilDerivative assets1 1 
Basis swaps – natural gasDerivative assets14 64 
Put options – natural gasDerivative assets8 — 
Fixed price swaps – natural gasOther long-term assets— 28 
Fixed price swaps – oilOther long-term assets— 1 
Fixed price swaps – ethaneOther long-term assets— 1 
Fixed price swaps – propaneOther long-term assets— 1 
Two-way costless collars – natural gasOther long-term assets46 18 
Three-way costless collars – natural gasOther long-term assets116 3 
Three-way costless collars – oilOther long-term assets10 — 
Basis swaps – natural gasOther long-term assets4 17 
Put options – natural gasOther long-term assets— 4 
Total derivative assets $791 $218 
Derivative Liabilities
Balance Sheet ClassificationFair Value
(in millions)December 31, 2023December 31, 2022
Derivatives not designated as hedging instruments:   
Fixed price swaps – natural gasDerivative liabilities$18 $581 
Fixed price swaps – oilDerivative liabilities2 20 
Fixed price swaps – ethaneDerivative liabilities— 1 
Fixed price swaps – propaneDerivative liabilities1 — 
Fixed price swaps – natural gasolineDerivative liabilities— 1 
Two-way costless collars – natural gasDerivative liabilities14 235 
Two-way costless collars – oilDerivative liabilities1 — 
Three-way costless collars – natural gasDerivative liabilities27 311 
Three-way costless collars – oilDerivative liabilities1 31 
Basis swaps – natural gasDerivative liabilities6 69 
Call options – natural gasDerivative liabilities1 70 
Put options – natural gasDerivative liabilities8 — 
Fixed price swaps – natural gas
Other long-term liabilities— 281 
Fixed price swaps – oilOther long-term liabilities— 4 
Two-way costless collars – natural gasOther long-term liabilities15 56 
Three-way costless collars – natural gasOther long-term liabilities60 20 
Three-way costless collars – oilOther long-term liabilities8 — 
Basis swaps – natural gasOther long-term liabilities— 1 
Call options – natural gasOther long-term liabilities17 18 
Total derivative liabilities $179 $1,699 
Net Derivative Position
As of December 31,
2023 2022
 (in millions)
Net current derivative assets (liabilities)$536 $(1,174)
Net long-term derivative assets (liabilities)76 (307)
Non-performance risk adjustment(2)3 
Net total derivative assets (liabilities) $610 $(1,478)
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, 2023 and 2022:
Unsettled Gain (Loss) on Derivatives Recognized in Earnings
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Unsettled
For the years ended
December 31,
Derivative Instrument2023 2022
 (in millions)
Fixed price swaps – natural gasGain (Loss) on Derivatives$1,281 $(166)
Fixed price swaps – oilGain (Loss) on Derivatives22 46 
Fixed price swaps – ethaneGain (Loss) on Derivatives5 12 
Fixed price swaps – propaneGain (Loss) on Derivatives1 87 
Fixed price swaps – normal butaneGain (Loss) on Derivatives— 27 
Fixed price swaps – natural gasolineGain (Loss) on Derivatives2 34 
Two-way costless collars – natural gasGain (Loss) on Derivatives279 (116)
Two-way costless collars – oilGain (Loss) on Derivatives2 — 
Two-way costless collars – ethaneGain (Loss) on Derivatives— 1 
Three-way costless collars – natural gasGain (Loss) on Derivatives402 117 
Three-way costless collars – oilGain (Loss) on Derivatives32 11 
Three-way costless collars – propaneGain (Loss) on Derivatives— 4 
Basis swaps – natural gasGain (Loss) on Derivatives1 (57)
Call options – natural gasGain (Loss) on Derivatives70 21 
Put options – natural gasGain (Loss) on Derivatives(4)4 
Fixed price swaps – natural gas storageGain (Loss) on Derivatives— 1 
Interest rate swapsGain (Loss) on Derivatives— (2)
Total gain on unsettled derivatives $2,093 $24 
Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Settled
For the years ended
December 31,
Derivative Instrument2023 2022
 (in millions)
Fixed price swaps – natural gasGain (Loss) on Derivatives$300 $(2,918)
Fixed price swaps – oil
Gain (Loss) on Derivatives(27)(129)
Fixed price swaps – ethaneGain (Loss) on Derivatives6 (49)
Fixed price swaps – propaneGain (Loss) on Derivatives26 (100)
Fixed price swaps – normal butaneGain (Loss) on Derivatives3 (35)
Fixed price swaps – natural gasolineGain (Loss) on Derivatives1 (49)
Two-way costless collars – natural gasGain (Loss) on Derivatives48 

(448)
Two-way costless collars – oilGain (Loss) on Derivatives(1)— 
Two-way costless collars – ethaneGain (Loss) on Derivatives— (1)
Three-way costless collars – natural gasGain (Loss) on Derivatives(19)(1,319)
Three-way costless collars – oilGain (Loss) on Derivatives(27)(51)
Three-way costless collars – propaneGain (Loss) on Derivatives— (5)
Index swaps - natural gasGain (Loss) on Derivatives— (1)
Basis swaps – natural gasGain (Loss) on Derivatives43 128 
Call options – natural gasGain (Loss) on Derivatives(8)(304)
Purchased fixed price swaps – natural gas storageGain (Loss) on Derivatives— 1 
Fixed price swaps – natural gas storageGain (Loss) on Derivatives— (3)
Total gain (loss) on settled derivatives $345 $(5,283)
(1)The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.
Total Gain (Loss) on Derivatives Recognized in Earnings
For the years ended
December 31,
20232022
 (in millions)
Total gain on unsettled derivatives$2,093 $24 
Total gain (loss) on settled derivatives345 (5,283)
Non-performance risk adjustment(5)— 
Total gain (loss) on derivatives $2,433 $(5,259)
v3.24.0.1
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 12 Months Ended
Dec. 31, 2023
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]  
Reclassifications from Accumulated Other Comprehensive Income (Loss) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
In 2023, 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, 2023:
For the year ended December 31, 2023
(in millions)Pension and Other PostretirementForeign CurrencyTotal
Beginning balance, December 31, 2022$20 $(14)$6 
Other comprehensive income before reclassifications7 — 7 
Amounts reclassified from other comprehensive income (1)
(16)— (16)
Net current-period other comprehensive loss(9)— (9)
Ending balance, December 31, 2023$11 $(14)$(3)
(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, 2023
Pension and other postretirement: (1)
(in millions)
SettlementsOther income, net$(2)
Tax valuation allowance release impact on pension settlementsProvision for income taxes(14)
Total reclassifications for the periodNet income$(16)
(1)See Note 13 for additional details regarding the Company’s pension and other postretirement benefit plans.
v3.24.0.1
Fair Value Measurements
 12 Months Ended
Dec. 31, 2023
Fair Value Disclosures [Abstract]  
Fair Value Measurements FAIR VALUE MEASUREMENTS
The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2023 and 2022 were as follows:
December 31, 2023December 31, 2022
(in millions)Carrying AmountFair ValueCarrying Amount Fair Value
Cash and cash equivalents$21 $21 $50  $50 
2022 revolving credit facility due April 2027220 220 250  250 
Senior notes (1)
3,743 3,626 4,164  3,847 
Derivative instruments, net610 610 (1,478)(1,478)
(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. The fair values of the Company's senior notes are considered to be a Level 1 measurement as they are actively traded. The carrying values of the borrowings under both the Company's 2022 credit facility (to the extent utilized) approximates fair value because the interest rates are variable and reflective of market rates. The Company considers the fair values of its 2022 credit facility to be a Level 1 measurement on the fair value hierarchy.
Derivative Instruments: The Company measures the fair value of its derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas and liquids forward curves, discount rates 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, 2023, the impact of non-performance risk on the fair value of the Company’s net derivative liability position was a reduction to the asset position of $2 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’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.
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, 2023
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: (1)
    
Fixed price swaps$— $491 $— $491 
Two-way costless collars— 85 — 85 
Three-way costless collars— 189 — 189 
Basis swaps— 18 — 18 
Purchase Put - Natural Gas— 8 — 8 
Liabilities:
Fixed price swaps— (21)— (21)
Two-way costless collars— (30)— (30)
Three-way costless collars— (96)— (96)
Basis swaps— (6)— (6)
Call options— (18)— (18)
Put options— (8)— (8)
Total$— $612 $— $612 
(1)Excludes a net reduction to the asset fair value of $2 million related to estimated non-performance risk.
December 31, 2022
Fair Value Measurements Using: 
(in millions)
Quoted Prices in Active Markets
(Level 1)
Significant Other Observable Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
Assets (Liabilities) at Fair Value
Assets:    
Fixed price swaps$— $46 $— $46 
Two-way costless collars— 65 — 65 
Three-way costless collars— 22 — 22 
Basis swaps— 81 — 81 
Purchase Put - Natural Gas— 4 — 4 
Liabilities: (1)
Fixed price swaps— (888)— (888)
Two-way costless collars— (291)— (291)
Three-way costless collars— (362)— (362)
Basis swaps— (70)— (70)
Call options— (88)— (88)
Total$— $(1,481)$— $(1,481)
(1)Excludes a net reduction to the liability fair value of $3 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.
v3.24.0.1
Debt
 12 Months Ended
Dec. 31, 2023
Debt Disclosure [Abstract]  
Debt DEBT
The components of debt as of December 31, 2023 and 2022 consisted of the following:
December 31, 2023
(in millions)Debt InstrumentUnamortized Issuance ExpenseUnamortized
Debt Premium / Discount		Total
Variable rate (7.20% at December 31, 2023)
2022 revolving credit facility, due April 2027
$220 $— 
(1)
$— $220 
4.95% Senior Notes due January 2025 (2)
389 — — 389 
8.375% Senior Notes due September 2028
304 (3)— 301 
5.375% Senior Notes due February 2029
700 (5)18 713 
5.375% Senior Notes due March 2030
1,200 (13)— 1,187 
4.75% Senior Notes due February 2032
1,150 (13)— 1,137 
Total debt$3,963 $(34)$18 $3,947 
December 31, 2022
(in millions)Debt InstrumentUnamortized Issuance ExpenseUnamortized
Debt Premium / Discount		Total
Variable rate (6.15% at December 31, 2022)
2022 revolving credit facility, due April 2027
$250 $— 
(1)
$— $250 
4.95% Senior Notes due January 2025 (2)
389 (1)— 388 
7.75% Senior Notes due October 2027
421 (3)— 418 
8.375% Senior Notes due September 2028
304 (3)— 301 
5.375% Senior Notes due February 2029
700 (5)22 717 
5.375% Senior Notes due March 2030
1,200 (16)— 1,184 
4.75% Senior Notes due February 2032
1,150 (16)— 1,134 
Total debt$4,414 $(44)$22 $4,392 
(1)At December 31, 2023 and 2022, unamortized issuance expense of $15 million and $19 million, respectively, associated with the 2022 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheet.
(2)Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company's bond ratings since 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
decreased the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022.

The following is a summary of scheduled debt maturities by year as of December 31, 2023:
(in millions)
2024$— 
2025389 
2026— 
2027 (1)
220 
2028304 
Thereafter3,050 
$3,963 
(1)The Company’s 2022 credit facility matures in 2027.
Credit Facility
2022 Credit Facility
On April 8, 2022, the Company entered into an Amended and Restated Credit Agreement that replaces its previous credit facility, that as amended, has a maturity date of April 2027 (the “2022 credit facility”). As of December 31, 2023, the 2022 credit facility has an aggregate maximum revolving credit amount and borrowing base of $3.5 billion and elected five-year revolving commitments of $2.0 billion (the “Five-Year Tranche”). 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. On October 4, 2023, the Company’s borrowing base was reaffirmed $3.5 billion and the Five-Year Tranche was reaffirmed at $2.0 billion with a maturity date of April 8, 2027.
Effective August 4, 2022, the Company elected to temporarily increase commitments under the 2022 credit facility by $500 million under the Short-Term Tranche as a temporary working capital liquidity resource. The Company had no borrowings under the Short-Term Tranche which expired on April 30, 2023 and was not renewed.
The Company may utilize the 2022 credit facility in the form of loans and letters of credit. Loans under the Five-Year Tranche of the 2022 credit facility are subject to varying rates of interest based on whether the loan is a SOFR loan or an alternate base rate loan. Term SOFR loans bear interest at term SOFR plus an applicable rate ranging from 1.75% to 2.75% based on the Company’s utilization of the Five-Year Tranche of the 2022 credit facility, plus a 0.10% credit spread adjustment. Base rate loans bear interest at a base rate per year equal to the greatest of: (i) the prime rate; (ii) the federal funds effective rate plus 0.50%; and (iii) the adjusted term SOFR rate for a one-month interest period plus 1.00%, plus an applicable margin ranging from 0.75% to 1.75%, depending on the percentage of the commitments utilized. Commitment fees on unused commitment amounts under the Five-Year Tranche of the 2022 credit facility range between 0.375% to 0.50%, depending on the percentage of the commitments utilized.
The 2022 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, declaring dividends, repurchasing junior debt, transactions with affiliates, or change of principal business; and
•maintenance of the following financial covenants, commencing with the fiscal quarter ended March 31, 2022:
(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 the prior four fiscal quarters ending on or after March 31, 2022, 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. Consolidated EBITDAX, as defined in the credit agreement governing the Company’s 2022 credit facility,
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 2022 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 2022 credit facility may become immediately due and payable. As of December 31, 2023, the Company was in compliance with all of the covenants of the credit agreement in all material respects.
Currently, each United States domestic subsidiary of the Company for which the Company owns 100% of its equity guarantees the 2022 credit facility. Pursuant to requirements under the indentures governing its senior notes, each subsidiary that became a guarantor of the 2022 credit facility also became a guarantor of each of the Company’s senior notes.
Certain features of the facility depend on whether Southwestern has obtained any of the following ratings:
•An unsecured long-term debt credit rating (an “Index Debt Rating”) of BBB- or higher with S&P;
•An Index Debt Rating of Baa3 or higher with Moody’s; or
•An Index Debt Rating of BBB- or higher with Fitch (each of the foregoing an “Investment Grade Rating”).
Upon receiving one Investment Grade Rating from either S&P or Moody’s, repayment in full of the term loan obligations under Southwestern’s Term Loan Agreement dated December 22, 2021, and delivering a certification to the administrative agent (the period beginning at such time, an “Interim Investment Grade Period”), amongst other changes, the following occurs:
•The Guarantors may be released from their guarantees;
•The collateral under the facility will be released;
•The facility will no longer be subject to a borrowing base; and
•Certain title and collateral-related covenants will no longer be applicable.
During the Interim Investment Grade Period, the Company will be required to maintain compliance with the existing financial covenants as well as a PV-9 coverage ratio of the net present value, discounted at 9% per annum, of the estimated future net revenues expected in the proved reserves to the Company’s total indebtedness as of such date of not less than 1.50 to 1.00 (“PV-9 Coverage Ratio”). In addition, during an Interim Investment Grade Period or Investment Grade Period (as defined below), term SOFR loans will bear interest at term SOFR plus an applicable rate ranging from 1.25% to 1.875%, depending on the Company’s Index Debt Rating (as defined in the 2022 credit facility), plus an additional 0.10% credit spread adjustment. Base rate loans will bear interest at the base rate described above plus an applicable rate ranging from 0.25% to 0.875%, depending on the Company’s Index Debt Rating. During an Interim Investment Grade Period or Investment Grade Period (defined below), the commitment fee on unused commitment amounts under the facility will range from 0.15% to 0.275%, depending on the Company’s Index Debt Rating.
The Interim Investment Grade Period will end, and the facility will revert to its characteristics prior to the Interim Investment Grade Period, including being guaranteed by the Guarantors, being secured by collateral and being subject to a borrowing base, having applicable margins and commitment fee determined based on percentage of commitments utilized, as well as limited to compliance with the leverage ratio and current ratio financial covenants but not the PV-9 Coverage Ratio if both of the following are achieved during the Interim Investment Grade Period:
•An Index Debt Rating from Moody’s that is Ba2 or lower; and
•An Index Debt Rating from S&P that is BB or lower.
Upon receiving two Investment Grade Ratings from S&P, Moody’s, or Fitch (such period following, an “Investment Grade Period”), certain restrictive covenants fall away or become more permissive. Upon Investment Grade Period, the leverage ratio and current ratio financial covenants and PV-9 Coverage Ratio will no longer be effective, and the Company will be required to maintain compliance with a total indebtedness to capitalization ratio, which is the ratio of the Company’s total indebtedness to the sum of total indebtedness plus stockholders’ equity, not to exceed 65%.
As of December 31, 2023, the Company had no outstanding letters of credit and $220 million in borrowings outstanding under the 2022 credit facility. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.
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”). 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 required minimum quarterly payments of $1.375 million, subject to adjustment for voluntary prepayments.
On December 30, 2022, the Company repaid in full all outstanding indebtedness under the Term Loan. The payoff amount included the principal amount of approximately $546 million, plus accrued but unpaid interest, fees, and expenses, which satisfied all of the Company’s indebtedness obligations thereunder. In connection with the repayment of such outstanding indebtedness obligations, all security interests, mortgages, liens and encumbrances securing the obligations under the Term Loan, the Term Loan, related loan documents, and all guarantees of such indebtedness obligations were terminated. The Company funded the repayment of the obligations under the Term Loan with approximately $305 million in cash on hand and approximately $250 million of borrowings under the Company’s 2022 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 decreased the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022.  
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 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.
For the year ended December 31, 2022, the Company retired $816 million of long term debt at a cost of $822 million and recorded a loss on early debt extinguishment of $14 million, which included $6 million of premiums and fees and the write off of $8 million in related unamortized debt discounts and issuance costs. The debt retirements included the repurchase of $46 million of its 8.375% Senior Notes due September 2028, $19 million of its 7.75% Senior Notes due October 2027, and the full redemption of $201 million of its outstanding 4.10% Senior Notes due March 2022, and its $550 million Term Loan.
On February 26, 2023, the Company redeemed all of its 7.75% Senior Notes due October 2027 (the “2027 Notes”) at a redemption price equal to 103.875% of the principal amount thereof plus accrued and unpaid interest of $13 million for a total payment of $450 million. The Company recognized a $19 million loss on the extinguishment of debt, which included the write-off of $3 million in related unamortized debt discounts and debt issuance costs. The Company funded the redemption of the 2027 Notes using approximately $316 million of cash on hand and approximately $134 million of borrowings under the 2022 credit facility.
v3.24.0.1
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies COMMITMENTS AND CONTINGENCIES
Operating Commitments and Contingencies
As of December 31, 2023, 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 $9.3 billion, $1,015 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 $808 million of that amount. As of December 31, 2023, future payments under non-cancelable firm transportation and gathering agreements are as follows:
Payments Due by Period
(in millions)TotalLess than 1 Year1 to 3 Years3 to 5 Years5 to 8 YearsMore than 8 Years
Infrastructure currently in service$8,331 $1,055 $1,983 $1,778 $1,727 $1,788 
Pending regulatory approval and/or construction (1)
1,015 46 157 177 266 369 
Total transportation charges$9,346 $1,101 $2,140 $1,955 $1,993 $2,157 
(1)Based on the estimated in-service dates as of December 31, 2023.
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, 2023, up to approximately $24 million of these contractual commitments remain (included in the table above), and the Company has recorded a $14 million liability for its portion of the estimated future payments.
The Company leases pressure pumping equipment for its E&P operations under three leases that expire in 2027 and 2028. The current aggregate annual payment under these leases is approximately $9 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 $11 million. The lease payments for the pressure pumping equipment, as well as other operating expenses for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings to third-party working interest owners.
The Company leases office space, vehicles and equipment under non-cancelable operating leases expiring through 2036. As of December 31, 2023, future minimum payments under these non-cancelable leases accounted for as operating leases (including short-term) are approximately $43 million in 2024, $34 million in 2025, $30 million in 2026, $27 million in 2027, $11 million in 2028 and $6 million thereafter.
The Company also has commitments for compression services and compression rentals related to its E&P segment. As of December 31, 2023, future minimum payments under these non-cancelable agreements (including short-term obligations) are approximately $19 million in 2024, $6 million in 2025, $2 million in 2026 and less than $1 million in 2027.
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, 2023, the Company does not currently have any material amounts accrued related to litigation matters, including the case 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.
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, including punitive damages.
On September 13, 2018, Indigo and other defendants 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 which the Company has opposed. Plaintiffs later filed seventh and eighth supplemental petitions naming additional defendants. The parties are currently engaging in settlement discussions.
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.
v3.24.0.1
Income Taxes
 12 Months Ended
Dec. 31, 2023
Income Tax Disclosure [Abstract]  
Income Taxes INCOME TAXES
The provision (benefit) for income taxes included the following components:
(in millions)202320222021
Current:   
Federal$(4)$47 $— 
State(1)4 — 
(5)51 — 
Deferred:
Federal(192)— — 
State(60)— — 
(252)— — 
Provision (benefit) for income taxes$(257)$51 $— 
The provision for income taxes was an effective rate of (20)% in 2023, 3% in 2022 and 0% in 2021. The Company’s effective tax rate decreased in 2023, as compared with 2022, primarily due to the release of the valuation allowance. 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)202320222021
Expected provision (benefit) at federal statutory rate$273 $400 $(5)
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect18 39 — 
Change in valuation allowance(526)(392)2 
Return to accrual(16)— — 
Federal research and development credit(13)— — 
Other7 4 3 
Provision (benefit) for income taxes$(257)$51 $— 
The components of the Company’s deferred tax balances as of December 31, 2023 and 2022 were as follows:
(in millions)20232022
Deferred tax liabilities:
Differences between book and tax basis of property$255 $379 
Derivative activity137 — 
Right of use lease asset34 41 
Accrued pension costs— 1 
Other3 3 
429 424 
Deferred tax assets:
Accrued compensation53 50 
Accrued pension costs1 — 
Asset retirement obligations27 24 
Net operating loss carryforward450 469 
Future lease payments35 41 
Derivative activity— 340 
Capital loss carryover26 27 
Interest carryover93 41 
Research and development credits17 — 
Other17 21 
719 1,013 
Valuation allowance(52)(589)
Net deferred tax asset$238 $— 
In 2023, the Company made federal and state income tax payments of approximately $12 million and $1 million, respectively. In 2022, the Company made federal and state income tax payments of approximately $36 million and $5 million, respectively. In 2021, there were no material tax payments or refunds.
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, 2023, 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 and accordingly, no value has been ascribed to these NOLs on the Company’s balance sheet. 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 which were approximately $856 million as of December 31, 2023. 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 2042. The Company also had a statutory depletion carryforward of $13 million and $415 million related to interest deduction carryforward as of December 31, 2023.
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 year ended December 31, 2022, 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, 2022, primarily due to impairments of proved oil and gas properties recognized in 2020. The Company sustained a three-year cumulative level of profitability as of the first quarter of 2023 which was maintained through the end of 2023. Based on this factor and other positive evidence such as forecasted income, the Company concluded that $512 million of its federal and state deferred tax assets were more likely than not to be realized and released this portion of the valuation allowance in 2023. Accordingly, for the year ended December 31, 2023, the Company recognized $269 million of deferred income tax expense related to recording its tax provision which was offset by $526 million of tax benefit, including $14 million that was reclassified from OCI, attributable to the release of the valuation allowance. The Company expects to keep a valuation allowance of $52 million related to NOLs in jurisdictions in which it no longer operates and against a portion of its federal and state deferred tax assets such as capital losses and interest carryovers, which may expire before being fully utilized due to the application of the limitations under Section 382 and the ordering in which they may be applied.
A reconciliation of the changes to the valuation allowance is as follows:
(in millions)20232022
Valuation allowance at beginning of year$589 $1,079 
Return to accrual adjustments(12)(36)
State rate and apportionment changes(13)(66)
Current period deferred activity— (388)
Release of valuation allowance(512)— 
Valuation allowance at end of year$52 $589 
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, 2023, there were no unrecognized tax positions identified that would have a material effect on the effective tax rate. 
The Inflation Reduction Act of 2022 (the “IRA”) was enacted on August 16, 2022 and may impact how the U.S. taxes certain large corporations. The IRA imposes a 15% alternative minimum tax on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated
financial statements) for tax years beginning after December 31, 2022. The Company was not impacted by the alternative minimum tax during 2023. The Company will continue to monitor updates to the IRA and the impact it will have on the Company’s consolidated financial statements.
The Internal Revenue Service closed the 2016 and 2017 audits of the Company’s federal returns in 2021 with no change. The 2018 and 2019 income tax years expired and the income tax years 2020 to 2022 remain open to examination by the major taxing jurisdictions to which the Company is subject.
v3.24.0.1
Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2023
Asset Retirement Obligation [Abstract]  
Asset Retirement Obligations ASSET RETIREMENT OBLIGATIONS
The following table summarizes the Company’s 2023 and 2022 activity related to asset retirement obligations:
(in millions)20232022
Asset retirement obligation at January 1$105 $109 
Accretion of discount6 6 
Obligations incurred1 1 
Obligations settled/removed(1)(10)
Revisions of estimates8 (1)
Asset retirement obligation at December 31$119 $105 
Current liability$4 $6 
Long-term liability115 99 
Asset retirement obligation at December 31$119 $105 
v3.24.0.1
Retirement and Employee Benefit Plans
 12 Months Ended
Dec. 31, 2023
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 $4 million of contribution expense in 2023, and $2 million in 2022 and 2021, respectively. Additionally, the Company capitalized $4 million of contributions in 2023, and $2 million in 2022 and 2021, respectively, 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 plan, a cash balance plan that provided benefits based upon a fixed percentage of an employee’s annual compensation (the “Plan”). As part of an ongoing effort to reduce costs, the Company elected to freeze the Plan effective January 1, 2021. Employees that were participants in the Plan prior to January 1, 2021 will no longer receive an increased benefit based on service after December 31, 2020 but will continue to receive an increased benefit based on the interest component of the Plan until such time as they receive a lump sum distribution payment or their balance is converted into an annuity payment agreement as elected by the Plan participant. On September 13, 2021, the Compensation Committee of the Board of Directors approved terminating the Plan, effective December 31, 2021. This decision, among other benefits, provided Plan participants quicker access to, and greater flexibility in, the management of participants’ respective benefits due under the Plan.
The Company commenced the Plan termination process, and, on April 6, 2022, the Internal Revenue Service issued a favorable determination letter, concurring that the Plan has met all of the qualification requirements under the Internal Revenue Code. In December 2022, the Company distributed approximately $38 million of the Plan’s assets to participants in the form of lump sum payments in connection with a limited distribution window provided to all active and former employee participants as part of the Plan termination process.
In March 2023, the Company entered into a group annuity contract with a qualified insurance company relating to the Plan. Under the group annuity contract, the Company purchased an irrevocable nonparticipating single premium group annuity contract from the insurer and transferred to the insurer the future benefit obligations and annuity administration for remaining retirees and beneficiaries under the Plan.
Upon issuance of the group annuity contract, the pension benefit obligations and annuity administration for the remaining participants was irrevocably transferred from the Plan to the insurer. By transferring these obligations through the payment to the insurer in March 2023, the Company has no remaining obligations under the Plan or any other U.S. tax-qualified defined benefit pension plan. The purchase of the group annuity contract was funded directly by the assets of the Plan. The Company recognized
a pre-tax non-cash pension settlement charge of approximately $2 million during the twelve months ended December 31, 2023 as a result of the settlement of the Plan.
The Company transferred the remaining residual Plan assets balance of approximately $14 million to a qualified replacement plan in September 2023 and closed the Plan during the fourth quarter of 2023.
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, 2023 and 2022:
Pension BenefitsOther Postretirement Benefits
(in millions)2023202220232022
Change in benefit obligations:    
Benefit obligation at January 1$57 $126 $9 $13 
Service cost— — 2 2 
Interest cost— 3 1 — 
Actuarial gain— (29)(7)(5)
Benefits paid— (2)— (1)
Plan amendments— (2)— — 
Settlements(57)(39)— — 
Benefit obligation at December 31$— $57 $5 $9 
Pension BenefitsOther Postretirement Benefits
(in millions)2023202220232022
Change in plan assets:    
Fair value of plan assets at January 1$72 $114 $— $— 
Actual return on plan assets— — — — 
Employer contributions— — — 1 
Benefits paid— (2)— (1)
Settlements(58)(40)— — 
Transfer to qualified replacement plan (1)
(14)— — — 
Fair value of plan assets at December 31$— $72 $— $— 
Funded status of plans at December 31$— $15 $(5)$(9)
(1)Funds in the qualified replacement plan are presented as cash and cash equivalents on the Company’s consolidated balance sheet as of December 31, 2023.
The Company uses a December 31 measurement date for all of its plans and had assets recorded for the overfunded status and 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, 2023 and 2022 are as follows:
(in millions)2023
(1)
2022
Projected benefit obligation$— $57 
Accumulated benefit obligation— 57 
Fair value of plan assets— 72 
(1)The Company completed the termination of the Plan in 2023.
Pension and other postretirement benefit costs include the following components for 2023, 2022 and 2021:
Pension BenefitsOther Postretirement Benefits
(in millions)202320222021202320222021
Service cost (1)
$— $— $— $2 $2 $2 
Interest cost— 3 4 1 — — 
Expected return on plan assets— — (4)— — — 
Amortization of prior service cost— (1)— — — — 
Amortization of net loss— — — — — — 
Net periodic benefit cost— 2 — 3 2 2 
Settlement (gain) loss2 (1)2 — — — 
Total benefit cost$2 $1 $2 $3 $2 $2 
(1)The Company froze the Plan effective January 1, 2021, resulting in no service cost for the years ended December 31, 2023, December 31, 2022 and December 31, 2021.
Service cost is classified as general and administrative expenses on the consolidated statements of operations. All other components of total benefit cost (benefit) are classified as other income (loss), net on the consolidated statements of operations. The Company froze the Plan effective January 1, 2021, resulting in no service cost for the years ended December 31, 2023, 2022 and 2021.
Amounts recognized in other comprehensive income for the years ended December 31, 2023 and 2022 were as follows:
Pension BenefitsOther Postretirement Benefits
(in millions)2023202220232022
Net actuarial gain arising during the year$— $30 $7 $4 
Amortization of prior service cost— (2)— — 
Tax valuation allowance release impact on pension settlements(14)— — — 
Settlements(2)(1)— — 
Less: Tax effect (1)
— — — — 
Amounts recognized in other comprehensive income$(16)$27 $7 $4 
(1)Other postretirement benefit tax effects of approximately $1 million for each of the years ended December 31, 2023 and December 31, 2022 were netted against a valuation allowance and therefore included in accumulated other comprehensive income.
For the year ended December 31, 2023, $9 million current period other comprehensive loss was classified from accumulated other comprehensive income, primarily driven by the impact of the tax valuation allowance release on pension settlements offset by actuarial gains on the Company’s other postretirement benefits. 
The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2023 and 2022 are as follows:
Pension Benefits (1)
Other Postretirement Benefits
2023202220232022
Discount raten/a5.60 %5.20 %5.50 %
Rate of compensation increase (2)
n/an/an/an/a
(1)The Company completed the termination of its pension plan in 2023.
(2)Rate of compensation increase for other postretirement benefits is disclosed as “n/a” as the benefit is the same for all employees and not based on compensation.
The assumptions used in the measurement of the Company’s net periodic benefit cost for 2023, 2022 and 2021 are as follows:
Pension Benefits (1)
Other Postretirement Benefits
202320222021202320222021
Discount raten/a5.60 %3.20 %5.50 %3.10 %2.80 %
Expected return on plan assetsn/a0.10 %0.10 %n/an/an/a
Rate of compensation increase (2)
n/an/a3.50 %n/an/an/a
(1)The Company completed the termination of the Plan in 2023.
(2)Rate of compensation increase for other postretirement benefits is disclosed as “n/a” as the benefit is the same for all employees and not based on compensation.
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 2023 and 2022:
20232022
Health care cost trend assumed for next year7.0 %7.0 %
Rate to which the cost trend is assumed to decline5.0 %5.0 %
Year that the rate reaches the ultimate trend rate20412040
Pension Payments and Asset Management
In 2023, the Company made no contributions to the Plan and less than $1 million to its other postretirement benefit plan and did not make any additional contributions to the Plan through the completion of the Plan termination.
As of December 31, 2023, the Company expects to make benefit payments, including projected future interest costs, related to its Other Postretirement Benefits of $3 million from 2029 through 2033.
The Company had no Plan assets as of December 31, 2023. Utilizing the fair value hierarchy described in Note 8, the Company’s fair value measurement of Plan assets at December 31, 2022 was as follows:
(in millions)TotalQuoted Prices in Active Markets for Identical Assets (Level 1)
Significant Observable Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
Measured within fair value hierarchy
Fixed income (1)
69 69 — — 
Cash and cash equivalents2 2 — — 
Total plan assets at fair value$71 $71 $— $— 
(1)U.S. Treasury Notes
The Company’s Plan assets that were classified as Level 1 were 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. No concentration of risk arising within or across categories of Plan assets existed due to any significant investments in a single entity, industry, country or investment fund.
v3.24.0.1
Long-Term Incentive Compensation
 12 Months Ended
Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]  
Long-Term Incentive Compensation LONG-TERM INCENTIVE COMPENSATION
The Southwestern Energy Company 2022 Incentive Plan (the “2022 Plan”) was approved by stockholders on May 19, 2022 and replaced the Southwestern Energy Company 2013 Incentive Plan, as amended (the “2013 Plan”). The 2013 Plan terminated on May 20, 2022, and no new awards will be granted under the 2013 Plan. The 2022 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries.
The 2022 Plan provides for grants of options, stock appreciation rights, shares of restricted stock, restricted stock units, cash-based awards and other equity-based or equity-related awards to employees, officers and non-employee directors that, in the aggregate, do not exceed 40,000,000 shares, minus any shares awarded under the 2013 Plan after March 21, 2022 through May 20, 2022. 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 2022 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, 2023, 2022 and 2021:
(in millions)202320222021
Long-term incentive compensation – expensed$23 $30 $30 
Long-term incentive compensation – capitalized$15 $20 $18 
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 10 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 three years. 
Restricted stock, restricted stock units and stock options granted to participants under the 2022 Plan immediately vest upon death, disability or retirement (subject to a minimum of three years of service). To the extent no provision is made in connection with a “change in control” (as defined in the 2022 Plan) for the assumption of awards previously granted under the 2022 Plan substitution of such awards for new awards, then (i) outstanding time-based awards will become fully vested, and (ii) each outstanding performance-based award will vest with respect to the number of shares of common stock underlying such award or the amount of cash underlying the award eligible to vest based on performance during the performance period that includes the date of the change in control, prorated for the number of days which have elapsed during the performance period prior to the change in control. To the extent an award is assumed or substituted in connection with the change in control, if a participant is terminated by the Company without “cause” or the participant resigns for “good reason” (each as defined in the 2022 Plan) within 12 months following a change in control, then (i) each time-based award will become fully vested, and (ii) each outstanding performance-based award will vest based on performance during the performance period that includes the date of the change in control, prorated for the number of days which have elapsed during the performance period prior to such termination.
The Company issues performance units which have historically vested over three years to employees. The performance units granted in 2021, 2022 and 2023 cliff-vest at the end of three years.
As further discussed in Note 3, in February of 2021 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 on the consolidated statements of operations.
Equity-Classified Awards
The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Equity-classified awards – expensed$9 $4 $2 
Equity-classified awards – capitalized$3 $3 $— 
Equity-Classified Stock Options
The Company recorded no compensation costs related to equity-classified stock options for the years ended December 31, 2023, 2022 and 2021.
The Company recorded less than $1 million and $1 million in deferred tax liabilities related to stock options for the years ended December 31, 2023 and 2022, respectively. The Company recorded less than $1 million in deferred tax assets for the year ended December 31, 2021. Additionally, the Company had no unrecognized compensation cost related to unvested stock options at December 31, 2023.
The following tables summarize stock option activity for the years 2023, 2022 and 2021, and provide information for options outstanding at December 31 of each year:
202320222021
Number
of Shares		Weighted Average Exercise Price
Number
of Shares
Weighted Average Exercise Price
Number
of Shares
Weighted Average Exercise Price
(in thousands) (in thousands) (in thousands) 
Options outstanding at January 1997 $8.59 3,006 $8.98 3,850 $13.39 
Granted— $— — $— — $— 
Exercised— $— (893)$7.80 — $— 
Forfeited or expired(177)$8.60 (1,116)$10.26 (844)$29.10 
Options outstanding at December 31820 $8.59 997 $8.59 3,006 $8.98 
Options exercisable at December 31 (1)
820 $8.59 
(1)Weighted average remaining contractual life for options outstanding and exercisable was 1.1 years, as of December 31, 2023.
Equity-Classified Restricted Stock
The Company recorded the following compensation costs related to equity-classified restricted stock grants for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Restricted stock grants – general and administrative expense$2 $1 $2 
Restricted stock grants – capitalized expense$— $— $— 
The Company also recorded a deferred tax liability of less than $1 million related to restricted stock for the year ended December 31, 2023, compared to $1 million in deferred tax assets for the years ended December 31, 2022 and 2021. As of December 31, 2023, there was less than $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 0.4 years.
The following table summarizes the restricted stock activity for the years 2023, 2022 and 2021, and provides information for restricted stock outstanding at December 31 of each year:
202320222021
Number of
Shares		Weighted Average Fair Value
Number of
Shares
Weighted Average Fair Value
Number of
Shares
Weighted Average Fair Value
(in thousands) (in thousands) (in thousands) 
Unvested shares at January 1211 $5.81 242 $5.12 697 $5.97 
Granted336 $5.34 231 $6.92 438 $5.18 
Vested(378)$5.71 (262)$6.15 (893)$5.81 
Forfeited— $— — $— — $8.59 
Unvested shares at December 31169 $5.09 211 $5.81 242 $5.12 
The fair values of the grants were $2 million for each of 2023, 2022 and 2021. The total fair value of shares vested were $2 million for 2023 and 2022 and $5 million for 2021.
Equity-Classified Restricted Stock Units
The Company recorded the following compensation costs related to equity-classified restricted stock units for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Restricted stock units – general and administrative expense$5 $2 $— 
Restricted stock units – capitalized expense$2 $2 $— 
As of December 31, 2023, there was $6 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 1.5 years.
The following table summarizes equity-classified restricted stock unit activity to be paid out in Company stock for the years ended December 31, 2023, 2022 and 2021.
202320222021
Number
of Units		Weighted Average
Fair Value		Number
of Units		Weighted Average
Fair Value		Number
of Shares		Weighted Average
Fair Value
(in thousands)(in thousands)(in thousands)
Unvested Units at January 11,645 $4.44 37 $3.05 134 $3.05 
Granted1,617 $4.94 1,699 $4.45 — $— 
Vested(555)$4.42 (22)$3.05 (92)$3.05 
Forfeited(1)$3.05 (69)$4.37 (5)$3.05 
Unvested Units at December 312,706 $4.74 1,645 $4.44 37 $3.05 
Equity-Classified Performance Units
In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a three-year period and are payable in either cash or shares. The performance units granted during 2020 and 2021 were accounted for as liability-classified awards as further described below. In 2022 and 2023, two types of performance units were granted. The first type of awards were liability-classified given the awards are payable only in cash as prescribed under the compensation agreements. The second type of awards granted during 2022 and 2023 have been accounted for as equity-classified awards given the intention to settle these awards in stock. The equity-classified awards were recognized at their fair value as of the grant date and are amortized throughout the vesting period. The 2022 and 2023 performance unit awards include a market condition based on relative TSR (as defined below). The fair values of the market conditions were calculated by Monte Carlo models as of the grant date. As of December 31, 2023, there was $6 million of total unrecognized compensation costs related to the Company’s unvested equity-classified performance units. This cost is expected to be recognized over a weighted-average of 1.8 years.
(in millions)202320222021
Performance units – general and administrative expense$2 $1 $— 
Performance units – capitalized expense$1 $1 $— 
The Company recorded deferred tax assets of approximately $3 million related to equity-classified performance units for the years ended December 31, 2023 and 2022, compared to approximately $2 million in deferred tax assets for the year ended December 31, 2021.
The following table summarizes equity-classified performance unit activity to be paid out in Company stock for the years ended December 31, 2023, 2022 and 2021, and provides information for unvested units as of December 31, 2023, 2022 and 2021:
202320222021
Number of
Units (1)
Weighted
Average Fair Value
Number of
Units (1)
Weighted
Average Fair Value		Number of
Units		Weighted
Average Fair Value
(in thousands)(in thousands)(in thousands)
Unvested units at January 1817 $6.04 — $— — $— 
Granted940 $6.12 850 $6.04 — $— 
Vested— $— — $— — $— 
Forfeited— $— (33)

$6.04 — $— 
Unvested shares at December 311,757 $6.08 817 $6.04 — $— 
Liability-Classified Awards
The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Liability-classified stock-based compensation – expensed$5 $20 $24 
Liability-classified stock-based compensation awards – capitalized$2 $11 $14 
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. The liability-classified 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 restricted stock units granted in 2022 and 2023 were classified as equity awards.
The Company recorded the following compensation costs related to liability-classified restricted stock unit grants for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Restricted stock units – general and administrative expense$4 $9 $12 
Restricted stock units – capitalized expense$2 $6 $8 
The Company also recorded $1 million in deferred tax liabilities related to liability-classified restricted stock units for the years ended December 31, 2023, and 2022, compared to $1 million in deferred tax asset for the year ended December 31, 2021. As of December 31, 2023, there was approximately $1 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 0.2 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, 2023, 2022 and 2021 and provides information for unvested units as of December 31, 2023, 2022 and 2021:
202320222021
Number
of Units		Weighted Average Fair ValueNumber
of Units		Weighted Average Fair ValueNumber
of Units		Weighted Average Fair Value
(in thousands) (in thousands)(in thousands)
Unvested units at January 13,950 $4.81 7,937 $4.08 11,613 $2.67 
Granted— $— — $— 1,486 $4.23 
Vested(2,206)$4.84 (3,817)$4.48 (4,522)$3.40 
Forfeited(3)$5.57 (170)$6.83 (640)
(1)
$4.56 
Unvested units at December 311,741 $4.67 3,950 $4.81 7,937 $4.08 
(1)Includes 360,253 units related to the reduction in workforce for the year ended December 31, 2021.
Liability-Classified Performance Units
In each year beginning with 2018, the Company granted performance units that vest at the end of, or over a three-year period and are payable in either cash or shares. The performance units granted in 2020 vest over a three-year period and are payable in cash as prescribed under the compensation agreements and have been accounted for as liability-classified awards. The Company granted two types of performance units in 2021 that vest over a three-year period. One type is payable in cash as prescribed under the compensation agreements and the other type is payable in either cash or stock at the option of the Compensation Committee of the Company’s Board. Both award types have been accounted for as liability-classified awards. The Company granted two types of performance units in 2022 and 2023 that vest over a three-year period. For both 2022 and 2023, one type is payable in cash as prescribed under the compensation agreements and has been liability-classified while the other type is equity-classified as further discussed above. Changes in the fair market value of the instruments for liability-classified awards will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards.
The performance units granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative TSR. In 2021, of the two types of performance units that were granted, the first 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 liability classified performance units granted in 2022 and 2023 include performance conditions based on return of capital employed and reinvestment rate. 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, 2023, 2022 and 2021:
(in millions)202320222021
Liability-classified performance units – general and administrative expense$1 $11 $12 
Liability-classified performance units – capitalized expense$— $5 $6 
The Company also recorded deferred tax assets of less than $1 million related to liability-classified performance units for the year ended December 31, 2023, compared to $4 million in deferred tax assets for the years ended December 31, 2022 and 2021. As of December 31, 2023, there was $4 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 1.9 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, 2023, 2022 and 2021 and provides information for unvested units as of December 31, 2023, 2022 and 2021:
202320222021
Number
of Units		Weighted Average
Fair Value		Number
of Units		Weighted Average
Fair Value		Number
of Units		Weighted Average
Fair Value
(in thousands) (in thousands)(in thousands)
Unvested units at January 110,982 $2.25 9,515 $2.88 8,699 $2.57 
Granted5,136 $4.83 3,798 $1.00 3,580 $4.14 
Vested(3,966)$6.13 (1,910)$6.45 (2,020)$4.05 
Forfeited— $— (421)$6.70 (744)$3.40 
Unvested units at December 3112,152 $0.94 10,982 $2.25 9,515 $2.88 
Cash-Based Compensation
Performance Cash Awards
From 2020 through 2022, the Company granted performance cash awards that vest over a four-year period and are payable in cash on an annual basis. In 2023, the Company granted performance cash awards that vest over a three-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 from 2020 through 2023 include a performance condition determined annually by the Company. For all 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, 2023, 2022 and 2021:
(in millions)202320222021
Performance cash awards – general and administrative expense$9 $6 $4 
Performance cash awards – capitalized expense$10 $6 $4 
The Company also recorded approximately $1 million in deferred tax assets related to performance cash awards for each of the years ended December 31, 2023, 2022 and 2021. As of December 31, 2023, there was $33 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 2.0 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, 2023, 2022 and 2021 and provides information for unvested units as of December 31, 2023, 2022 and 2021:
202320222021
Number
of Units		Weighted Average
Fair Value		Number
of Units		Weighted Average
Fair Value		Number
of Shares		Weighted Average
Fair Value
(in thousands)(in thousands)
Unvested units at January 139,994 $1.00 28,272 $1.00 18,353 $1.00 
Granted27,493 $1.00 24,416 $1.00 18,546 $1.00 
Vested(13,320)$1.00 (8,786)$1.00 (4,955)$1.00 
Forfeited(4,489)$1.00 (3,908)$1.00 (3,672)
(1)
$1.00 
Unvested Units at December 3149,678 $1.00 39,994 $1.00 28,272 $1.00 
(1) Includes 1,241,000 units related to the reduction in workforce for the year ended December 31, 2021.
v3.24.0.1
Segment Information
 12 Months Ended
Dec. 31, 2023
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. The Company’s E&P segment is comprised of gas and oil properties which are managed as a whole rather than through discrete operations. Operational information for the Company’s E&P segment is tracked by geographic area; however, financial performance and allocation of resources are assessed at the segment level without regard to geographic area. 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
MarketingTotal Reportable SegmentsOtherTotal
2023
Revenues from external customers$4,167 $2,355 $6,522 $— $6,522 
Intersegment revenues(58)3,922 3,864 — 3,864 
Depreciation, depletion and amortization expense1,302 5 1,307 — 1,307 
Impairments1,710 — 1,710 — 1,710 
Operating income (loss)(1,061)92 (969)(5)(974)
Interest expense (1)
142 — 142 — 142 
Gain on derivatives2,433 — 2,433 — 2,433 
Loss on early extinguishment of debt— — — (19)(19)
Other income, net2 — 2 — 2 
Benefit from income taxes (1)
(257)— (257)— (257)
Assets11,253 
(2)
591 11,844 147 11,991 
Capital investments (3)
2,122 — 2,122 9 2,131 
(in millions)
Exploration
and
Production
MarketingTotal Reportable SegmentsOtherTotal
2022
Revenues from external customers$10,583 $4,419 $15,002 $— $15,002 
Intersegment revenues(6)10,102 10,096 — 10,096 
Depreciation, depletion and amortization expense1,169 5 1,174 — 1,174 
Operating income7,253 
(4)
101 7,354 — 7,354 
Interest expense (1)
184 — 184 — 184 
Loss on derivatives(5,257)— (5,257)(2)(5,259)
Loss on early extinguishment of debt— — — (14)(14)
Other income, net3 — 3 — 3 
Provision for income taxes (1)
51 — 51 — 51 
Assets11,473 
(2)
1,274 12,747 179 12,926 
Capital investments (3)
2,196 — 2,196 13 2,209 
2021
Revenues from external customers$4,701 $1,966 $6,667 $— $6,667 
Intersegment revenues(61)4,223 4,162 — 4,162 
Depreciation, depletion and amortization expense537 9 546 — 546 
Impairments6 — 6 — 6 
Operating income2,583 
(5)
52 2,635 — 2,635 
Interest expense (1)
136 — 136 — 136 
Gain (loss) on derivatives(2,437)— (2,437)1 (2,436)
Loss on early extinguishment of debt— — — (93)(93)
Other income, net5 — 5 — 5 
Provision for income taxes (1)
— — — — — 
Assets10,767 
(2)
956 11,723 125 11,848 
Capital investments (3)
1,107 — 1,107 1 1,108 
(1)Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.
(2)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.
(3)Capital investments include a decrease of $44 million for 2023, an increase of $88 million for 2022 and an increase of $70 million for 2021 related to the change in accrued expenditures between years. 
(4)Operating income for the E&P segment includes $27 million of acquisition-related charges for the year ended December 31, 2022.
(5)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.
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, 2023, 2022 and 2021:
For the years ended December 31,
(in millions)202320222021
Cash and cash equivalents$21 $50 $28 
Accounts receivable— 1 — 
Prepayments18 14 6 
Other current assets2 — — 
Property, plant and equipment24 19 12 
Unamortized debt expense15 19 10 
Right-of-use lease assets49 57 65 
Non-qualified retirement plan3 3 4 
Long term assets15 16 — 
$147 $179 $125 
Included in intersegment revenues of the Marketing segment are $3.9 billion, $10.1 billion and $4.2 billion for 2023, 2022 and 2021, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture
and fixtures and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments.
v3.24.0.1
Subsequent Events
 12 Months Ended
Dec. 31, 2023
Subsequent Events [Abstract]  
Subsequent Events SUBSEQUENT EVENTS
On January 10, 2024, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Chesapeake Energy Corporation, an Oklahoma corporation (“Chesapeake”), Hulk Merger Sub, Inc., a Delaware corporation and a newly formed, wholly owned subsidiary of Chesapeake (“Merger Sub”) and Hulk LLC Sub, LLC, a Delaware limited liability company and a wholly owned subsidiary of Chesapeake (“LLC Sub” and together with Merger Sub, the Company and Chesapeake, the “Parties”), pursuant to which Merger Sub will merge with and into the Company (the “Proposed Merger”), with the Company continuing as a wholly owned subsidiary of Chesapeake (the “Surviving Corporation”). Immediately following the time the Proposed Merger becomes effective (the “Effective Time”), the Surviving Corporation will be merged with and into LLC Sub, with LLC Sub continuing as the surviving entity and as a wholly owned subsidiary of Chesapeake. Under the terms of the Merger Agreement, upon completion of the Proposed Merger, Southwestern shareholders will receive 0.0867 shares of Chesapeake common stock for one share of Southwestern common stock. The consideration to be paid under the Merger Agreement is subject to adjustment as provided in the Merger Agreement. No fractional shares of Chesapeake common stock will be issued in the Proposed Merger, the holders of shares of Southwestern common stock will receive cash in lieu of fractional shares of Chesapeake common stock, if any, in accordance with the terms of the Merger Agreement.
The consummation of the Proposed Merger is subject to the satisfaction or waiver of customary closing conditions, including: receipt of the required approvals from the stockholders of the Company and Chesapeake, and the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”) and no agreement between or commitment by the Parties and any governmental entity not to consummate the Proposed Merger being in effect. The Company and Chesapeake have each made customary representations and warranties in the Merger Agreement. The Merger Agreement also contains customary pre-closing covenants of the Company and Chesapeake, including, subject to certain exceptions, covenants relating to conducting their respective businesses in the ordinary course consistent with past practice and refraining from taking certain actions, excepting in each case actions expressly permitted or required by the Merger Agreement, required by law or consented to by the other party in writing. The Merger Agreement provides that in the event of termination of the Merger Agreement under certain circumstances, we may be required to reimburse Chesapeake’s expenses up to $55.6 million or pay Chesapeake a termination fee equal to $389 million less any expenses previously paid. Further, Chesapeake may be required to reimburse our expenses up to $37.25 million or pay us a termination fee equal to $260 million less any expenses previously paid.
v3.24.0.1
Supplemental Oil and Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2023
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.
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)202320222021
Unproved property acquisition costs$184 $202 $139 
Exploration costs— — — 
Development costs1,939 2,021 984 
Capitalized costs incurred$2,123 $2,223 $1,123 
Full cost pool amortization per Mcfe$0.77 $0.67 $0.42 
Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $115 million, $121 million and $97 million during 2023, 2022 and 2021, 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 $85 million during 2023 and 2022, respectively, and $64 million during 2021 all of 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)202320222021
Sales$4,109 $10,577 $4,640 
Production (lifting) costs(1,990)(1,969)(1,304)
Depreciation, depletion and amortization(1,302)(1,169)(537)
Impairment of natural gas and oil properties(1,710)— — 
(893)7,439 2,799 
Provision (benefit) for income taxes (1)
(200)— — 
Results of operations (2)
$(693)$7,439 $2,799 
(1)No tax provision (benefit) in 2022 and 2021 due to recognition of a tax valuation allowance for the years ended December 31, 2022 and 2021, respectively.
(2)Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 6.
The results of operations shown above exclude general and administrative expenses and interest expense and are not necessarily indicative of the contribution made by the Company’s natural gas and oil operations to its consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.
Natural Gas and Oil Reserve Quantities
The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s 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 properties, and accounted for approximately 99% of the present worth of the Company’s total proved reserves as of December 31, 2023. For 2022 and 2021, NSAI’s audit accounted for 99% 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 2021, 2022 and 2023, all of which were located in the United States:
Natural Gas
(Bcf)
Oil
(MBbls)
NGL
(MBbls)
Total
(Bcfe)
December 31, 20209,181 58,024 410,151 11,990 
Revisions of previous estimates due to price (1)
501 1,414 (15,525)415 
Revisions of previous estimates other than price (2)
1,402 17,384 127,197 2,270 
Extensions, discoveries and other additions (2)
1,389 9,381 85,901 1,961 
Production(1,015)(6,610)(30,940)(1,240)
Acquisition of reserves in place (3)
5,750 247 180 5,753 
Disposition of reserves in place(1)(61)— (1)
December 31, 202117,207 79,779 576,964 21,148 
Revisions of previous estimates due to price61 (107)(828)55 
Revisions of previous estimates other than price (4)
(458)(2,149)40,138 (230)
Extensions, discoveries and other additions 2,106 10,877 42,719 2,428 
Production(1,520)(4,993)(30,446)(1,733)
Disposition of reserves in place (34)(21)(1,411)(43)
December 31, 202217,362 83,386 627,136 21,625 
Revisions of previous estimates due to price
(1,779)(1,118)(10,217)(1,847)
Revisions of previous estimates other than price (5)
(417)(3,630)52,283 (125)
Extensions, discoveries and other additions1,813 5,062 30,444 2,026 
Production(1,438)(5,602)(32,859)(1,669)
Disposition of reserves in place(350)— — (350)
December 31, 202315,191 78,098 666,787 19,660 
(1)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.
(2)Includes 1,155 Bcf, 15 MBbls and 126 MBbls of natural gas, oil and NGL proved reserves, respectively, that were previously presented as “Extensions, discoveries and other additions” which have been reclassified to “Revisions of previous estimate other than price” to conform with 2022 and 2023 presentation of infill reserves.
(3)The 2021 acquisition amounts are primarily associated with the Indigo Merger and the GEPH Merger.
(4)Includes performance revisions of a positive 272 Bcf, negative 681 MBbls and positive 41,490 MBbls of natural gas, oil and NGL proved reserves, respectively. Includes additions associated with infill development of 303 Bcf, 5,254 MBbls, and 40,423 MBbls of natural gas, oil and NGL proved reserves, respectively. Includes downward revisions from change in development plans of 1,033 Bcf, 6,722 MBbls, and 41,775 MBbls of natural gas, oil and NGL proved reserves, respectively.
(5)Includes performance revisions of a positive 25 Bcf, negative 3,062 MBbls and positive 28,189 MBbls of natural gas, oil and NGL proved reserves, respectively. Includes additions associated with infill development of 647 Bcf, 12,493 MBbls, and 85,378 MBbls of natural gas, oil and NGL proved reserves, respectively. Includes downward revisions from change in development plans of 1,089 Bcf, 13,061 MBbls, and 61,284 MBbls of natural gas, oil and NGL proved reserves, respectively.
Natural Gas
(Bcf)
Oil
(MBbls)
NGL
(MBbls)
Total
(Bcfe)
Proved developed reserves as of:    
December 31, 20219,308 40,930 296,832 11,335 
December 31, 20229,793 41,138 350,821 12,145 
December 31, 20239,196 38,581 362,983 11,605 
Proved undeveloped reserves as of:    
December 31, 20217,899 38,849 280,132 9,813 
December 31, 20227,569 42,248 276,315 9,480 
December 31, 20235,995 39,517 303,804 8,055 
The Company’s estimated proved natural gas, oil and NGL reserves were 19,660 Bcfe at December 31, 2023, compared to 21,625 Bcfe at December 31, 2022. The Company’s reserves decreased in 2023, compared to 2022, as downward performance and price revisions, production and dispositions were only partially offset by extensions and discoveries.
The Company’s reserves increased in 2022, as compared to 2021, as extensions and discoveries, positive performance revisions, and positive price revisions were only partially offset by production, changes in the development plan, and dispositions.
The following table summarizes the changes in reserves for 2021, 2022 and 2023:
(in Bcfe)AppalachiaHaynesville
Other (1)
Total
December 31, 202011,989 — 1 11,990 
Net revisions
Price revisions415 — — 415 
Performance and production revisions (2)
2,271 — (1)2,270 
Total net revisions2,686 — (1)2,685 
Extensions, discoveries and other additions
Proved developed (2)
197 — — 197 
Proved undeveloped (2)
1,764 — — 1,764 
Total reserve additions1,961 — — 1,961 
Production(1,108)(132)— (1,240)
Acquisition of reserves in place— 5,753 — 5,753 
Disposition of reserves in place(1)— — (1)
December 31, 202115,527 5,621 — 21,148 
Net revisions
Price revisions(4)59 — 55 
Performance and production revisions (3)
(33)(197)— (230)
Total net revisions(37)(138)— (175)
Extensions, discoveries and other additions
Proved developed 235 171 — 406 
Proved undeveloped 1,038 984 — 2,022 
Total reserve additions1,273 1,155 — 2,428 
Production(1,054)(679)— (1,733)
Acquisition of reserves in place— — — — 
Disposition of reserves in place(43)— — (43)
December 31, 202215,666 5,959 — 21,625 
Net revisions
Price revisions(570)(1,277)— (1,847)
Performance and production revisions (4)
189 (314)— (125)
Total net revisions(381)(1,591)— (1,972)
Extensions, discoveries and other additions
Proved developed14 66 — 80 
Proved undeveloped769 1,177 — 1,946 
Total reserve additions783 1,243 — 2,026 
Production(1,034)(635)— (1,669)
Acquisition of reserves in place— — — — 
Disposition of reserves in place(349)(1)— (350)
December 31, 202314,685 4,975 — 19,660 
(1)Other includes properties outside of Appalachia and Haynesville.
(2)Includes 158 Bcf, 2 MBbls and 14 MBbls of natural gas, oil and NGL proved developed reserves, respectively, that were previously presented as “Extensions, discoveries and other additions” which have been reclassified to “Performance and production revisions” to conform with current year presentation for infill reserves. Includes 997 Bcf, 13 MBbls and 112 MBbls of natural gas, oil and NGL proved undeveloped reserves, respectively, that were previously presented as “Extensions, discoveries and other additions” which have been reclassified to “Performance and production revisions” to conform with 2022 and 2023 presentation of infill reserves.
(3)Includes Appalachia reserves with positive performance revisions of 381 Bcf, additions associated with infill development of 577 Bcf, and downward revisions from changes in development plans of 991 Bcf. Includes Haynesville reserves with positive performance revisions of 136 Bcf and downward revisions from changes in development plans of 333 Bcf.
(4)Includes Appalachia reserves with positive performance revisions of 246 Bcf, additions associated with infill development of 1,200 Bcf, and downward revisions from changes in development plans of 1,257 Bcf. Includes Haynesville reserves with negative performance revisions of 70 Bcf, additions associated with infill development of 34 Bcf and downward revisions from changes in development plans of 278 Bcf.
As of December 31, 2023, the Company had 2,548 Bcfe of proved undeveloped reserves from 200 locations that had a positive present value on an undiscounted basis in compliance with proved reserves requirements but had a negative present value of $270 million when discounted at 10%. The Company’s December 31, 2022 and December 31, 2021 reserves included no proved undeveloped reserves that had a negative present value on a 10% discounted basis, respectively. 
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, 2023, 2022 and 2021 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)202320222021
Future cash inflows$50,499 $132,037 $75,314 
Future production costs(26,147)(29,632)(23,235)
Future development costs (1)
(6,558)(7,458)(6,032)
Future income tax expense(1,581)(19,323)(8,135)
Future net cash flows16,213 75,624 37,912 
10% annual discount for estimated timing of cash flows(8,900)(38,036)(19,181)
Standardized measure of discounted future net cash flows$7,313 $37,588 $18,731 
(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:
202320222021
Natural gas (per MMBtu)
$2.64 $6.36 $3.60 
Oil (per Bbl)
78.22 93.67 66.56 
NGLs (per Bbl)
21.38 34.35 28.65 
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 2023, 2022 and 2021:
(in millions)202320222021
Standardized measure, beginning of year$37,588 $18,731 $1,847 
Sales and transfers of natural gas and oil produced, net of production costs(2,123)(8,611)(3,332)
Net changes in prices and production costs(36,514)23,198 10,417 
Extensions, discoveries, and other additions, net of future production and development costs63 4,976 3,183 
Acquisition of reserves in place— 1 6,499 
Sales of reserves in place(710)(49)(1)
Revisions of previous quantity estimates(1,174)(400)596 
Net change in income taxes8,364 (5,158)(3,689)
Changes in estimated future development costs1,005 (709)137 
Previously estimated development costs incurred during the year1,336 1,208 419 
Changes in production rates (timing) and other(5,165)2,159 2,470 
Accretion of discount4,643 2,242 185 
Standardized measure, end of year$7,313 $37,588 $18,731 
v3.24.0.1
Pay vs Performance Disclosure - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Pay vs Performance Disclosure      
Net income (loss) $ 1,557 $ 1,849 $ (25)
v3.24.0.1
Insider Trading Arrangements
 3 Months Ended
Dec. 31, 2023
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
v3.24.0.1
Organization and Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2023
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 2023 and 2022 amounts to prior periods could be impacted as a result of the Indigo Merger (as defined below) completed 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.
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.
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, 2023 one purchaser accounted for approximately 14% 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, 2022, one purchaser accounted for 17% 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 $21 million and $50 million in cash and cash equivalents as of December 31, 2023 and 2022, 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 $73 million and $100 million as of December 31, 2023 and 2022, 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. 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, 2023 and 2022:
(in millions)20232022
Proved properties$35,697 $33,546 
Unproved properties2,075 2,217 
Total capitalized costs37,772 35,763 
Less:  Accumulated depreciation, depletion and amortization(28,031)(25,033)
Net capitalized costs$9,741 $10,730 
Under the full cost method of accounting, productive and nonproductive costs, 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,
202320222021
Natural gas (per MMBtu)
$2.64 $6.36 $3.60 
Oil (per Bbl)
$78.22 $93.67 $66.56 
NGLs (per Bbl)
$21.38 $34.35 $28.65 
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 exceeded the ceiling amount at December 31, 2023, resulting in an impairment of $1,710 million. The net book value of its natural gas and oil properties did not exceed the ceiling amount at December 31, 2022 or 2021. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2023, 2022 and 2021. Given the decline in commodity prices during 2023 and early 2024, the Company expects that an additional non-cash impairment of its asset will likely occur in the first quarter of 2024 and perhaps later.
No impairment expense was recorded in 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. Had management not received the waiver from the SEC, no impairment charge would have been recorded in 2021 even when including the Montage natural gas and oil properties in the full cost ceiling test due to improved commodity prices during 2021.
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, 2023, the Company had a total of $2,075 million of costs excluded from the amortization base, all of which related to its properties in the United States.
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, 2023:
(in millions)202320222021PriorTotal
Property acquisition costs$63 $86 $559 $1,005 $1,713 
Exploration and development costs24 9 8 18 59 
Capitalized interest115 91 75 22 303 
$202 $186 $642 $1,045 $2,075 
Of the total net unevaluated costs excluded from amortization as of December 31, 2023, approximately $1,048 million is related to undeveloped properties in Appalachia which were acquired in 2014 and 2015, $137 million is related to Montage properties acquired in November 2020 and approximately $587 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 $303 million of unevaluated capitalized interest. The Company has $59 million of unevaluated costs related to wells in progress (included within the Appalachia, Montage and Haynesville amounts above). 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.
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
3 – 10 years
Gathering systems
15 – 25 years
Technology infrastructure
3 – 10 years
Drilling rigs and equipment
3 years
Buildings and leasehold improvements
5 – 30 years
Other property, plant and equipment is comprised of the following:
(in millions)December 31, 2023December 31, 2022
Water facilities$252 $238 
Gathering systems60 56 
Technology infrastructure146 135 
Drilling rigs and equipment35 31 
Land, buildings and leasehold improvements16 16 
Other57 51 
Less: Accumulated depreciation and impairment(394)(354)
Total$172 $173 
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. The Company did not recognize an impairment on its non-full cost pool long-lived assets during the years ended December 31, 2023 and December 31, 2022. The Company recognized an impairment of $6 million related to non-core assets for the year ended December 31, 2021.
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, 2023 and 2022, the Company had $38 million and $43 million, respectively, in marketing-related intangible assets, of which $33 million and $38 million were included in Other long-term assets on the respective consolidated balance sheets. The Company amortized $5 million of its marketing-related intangible asset in 2023, $5 million in 2022 and $8 million in 2021. The Company expects to amortize $5 million during each year from 2024 to 2027 and $4 million in 2028.
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, 2023. By policy election, leases with an initial term of twelve months or less are not recorded on the balance sheet. The Company recognizes lease expense for these leases on a straight-line basis, and variable lease payments are recognized in the period as incurred.
Certain leases contain both lease and non-lease components. The Company has chosen to account for most of these leases as a single lease component instead of bifurcating lease and non-lease components. However, for compression service leases and fleet vehicle leases, the lease and non-lease components are accounted for separately.
The Company leases drilling rigs, pressure pumping equipment, vehicles, office space, certain water transportation lines and other equipment under non-cancelable operating leases expiring through 2036. Certain lease agreements include options to renew the lease, early terminate the lease or purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. The Company’s water transportation lines are the only leases with renewal options that are reasonably certain to be exercised. These renewal options are reflected in the right-of-use asset and lease liability balances.
Income Taxes
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized.
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.
Derivative Financial Instruments
Derivative Financial Instruments
The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses derivative instruments to financially protect sales of natural gas, oil and NGLs. In addition, the Company uses interest rate swaps to manage exposure to unfavorable interest rate changes. Since the Company does not designate its derivatives for hedge accounting treatment, gains and losses resulting from the settlement of derivative contracts have been recognized in gain (loss) on derivatives in the consolidated statements of operations when the contracts expire and the related physical transactions of the underlying commodity are settled. Additionally, changes in the fair value of the unsettled portion of derivative contracts are also recognized in gain (loss) on derivatives in the consolidated statement of operations.
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 Compensation
The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties.
Liability-Classified Awards
Liability-Classified Awards
The Company classifies certain awards that can or will be settled in cash as liability awards. The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense, operating expense and capitalized expense over the vesting period of the award. The 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 total shareholder return (“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. In 2022 and 2023, two types of performance units were granted. One type of award includes performance conditions based on return on capital employed and reinvestment rate. The other awards granted in 2022 and 2023 were accounted for as equity classified awards. 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 cancelled.
Treasury Stock
Treasury Stock
In 2022, the Company repurchased 17,261,469 shares of its outstanding common stock per a previously announced share repurchase program at an average price of $7.24 per share for approximately $125 million.
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, 2023 and 2022, 1,455 shares and 1,743 shares, respectively, were held in the Rabbi Trust and were accounted for as treasury stock.
Foreign Currency Translation
Foreign Currency Translation
The Company has designated the Canadian dollar as the functional currency for its activities in Canada. The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of other comprehensive income within stockholders’ equity.
New Accounting Standards Implemented in this Report and New Accounting Standards Not Yet Adopted in this Report
New Accounting Standards Implemented in this Report
None that are expected to have a material impact.
New Accounting Standards Not Yet Adopted in this Report
In November 2023, the Financial Accounting Standards Board (the “FASB”) issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The purpose of this update is to enhance disclosures on reportable segments and provide additional detailed information about significant segment expenses. The guidance in ASU 2023-07 is effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. The Company continues to assess the impact of the new guidance, but it is not expected to have a material impact on the consolidated financial statements.
In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The purpose of this update is to enhance disclosures through further disaggregated information on the effective tax rate reconciliation based on specified categories, as well as disaggregation of income taxes paid by jurisdiction. The guidance in ASU 2023-09 is effective for fiscal years beginning after December 15, 2024. The Company continues to assess the impact of the new guidance, but it is not expected to have a material impact on the consolidated financial statements.
v3.24.0.1
Organization and Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [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, 2023 and 2022:
(in millions)20232022
Proved properties$35,697 $33,546 
Unproved properties2,075 2,217 
Total capitalized costs37,772 35,763 
Less:  Accumulated depreciation, depletion and amortization(28,031)(25,033)
Net capitalized costs$9,741 $10,730 
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,
202320222021
Natural gas (per MMBtu)
$2.64 $6.36 $3.60 
Oil (per Bbl)
$78.22 $93.67 $66.56 
NGLs (per Bbl)
$21.38 $34.35 $28.65 
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, 2023:
(in millions)202320222021PriorTotal
Property acquisition costs$63 $86 $559 $1,005 $1,713 
Exploration and development costs24 9 8 18 59 
Capitalized interest115 91 75 22 303 
$202 $186 $642 $1,045 $2,075 
Schedule of Property, Plant and Equipment
The estimated useful lives of those assets depreciated under the straight-line method are as follows:
Water facilities
3 – 10 years
Gathering systems
15 – 25 years
Technology infrastructure
3 – 10 years
Drilling rigs and equipment
3 years
Buildings and leasehold improvements
5 – 30 years
Other property, plant and equipment is comprised of the following:
(in millions)December 31, 2023December 31, 2022
Water facilities$252 $238 
Gathering systems60 56 
Technology infrastructure146 135 
Drilling rigs and equipment35 31 
Land, buildings and leasehold improvements16 16 
Other57 51 
Less: Accumulated depreciation and impairment(394)(354)
Total$172 $173 
Schedule of Earnings Per Share
The following table presents the computation of earnings per share for the years ended December 31, 2023, 2022 and 2021:
For the years ended December 31,
(in millions, except share/per share amounts)202320222021
Net income (loss)$1,557 $1,849 $(25)
Number of common shares:
Weighted average outstanding1,100,980,199 1,110,564,839 789,657,776 
Issued upon assumed exercise of outstanding stock options— — — 
Effect of issuance of non-vested restricted common stock862,434 763,067 — 
Effect of issuance of non-vested restricted units1,431,754 1,500,815 — 
Effect of issuance of non-vested performance units131,868 355,533 — 
Weighted average and potential dilutive outstanding1,103,406,255 1,113,184,254 789,657,776 
   
Earnings (loss) per common share:   
Basic$1.41 $1.67 $(0.03)
Diluted$1.41 $1.66 $(0.03)
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, 2023, 2022 and 2021, as they would have had an antidilutive effect:
For the years ended December 31,
202320222021
Unexercised stock options831,525 2,265,589 3,683,363 
Unvested share-based payment46,101 53,924 832,989 
Restricted units211,506 192,515 2,226,981 
Performance units— — 2,194,477 
Total1,089,132 2,512,028 8,937,810 
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, 2023, 2022 and 2021:
For the years ended December 31,
(in millions)202320222021
Cash paid during the year for interest, net of amounts capitalized$140 $161 $106 
Cash paid during the year for income taxes13 41 — 
(1)
Non-cash investing activities(39)94 3,690 
(2)
Non-cash financing activities— — 2,051 
(3)
(1)Cash received in 2021 for income taxes was immaterial.
(2)Includes $3,045 million and $581 million in non-cash property additions related to the Indigo Merger and the GEPH Merger, respectively.
(3)Includes $1,588 million and $463 million in common stock consideration related to the Indigo Merger and the GEPH Merger, respectively.
v3.24.0.1
Acquisitions (Tables)
 12 Months Ended
Dec. 31, 2023
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 issued99,337,748 
NYSE closing price per share of Southwestern common shares on December 31, 2021$4.66 
$463 
Cash consideration(1)
1,263 
Total consideration$1,726 
(1)Reflects $6 million of post-close cash consideration adjustments.
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 issued337,827,171 
NYSE closing price per share of Southwestern common shares on September 1, 2021$4.70 
$1,588 
Cash consideration373 
Total consideration$1,961 
Schedule of Business Acquisitions, by Acquisition
The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation was complete as of the fourth quarter of 2022.
(in millions)As of December 31, 2021
Consideration:
Total consideration$1,726 
Fair Value of Assets Acquired:
Cash and cash equivalents11 
Accounts receivable(1)
180 
Other current assets(1)
1 
Commodity derivative assets56 
Evaluated oil and gas properties1,783 
Unevaluated oil and gas properties59 
Other property, plant and equipment2 
Other long-term assets3 
Total assets acquired2,095 
Fair Value of Liabilities Assumed:
Accounts payable(1)
176 
Other current liabilities1 
Derivative liabilities75 
Revolving credit facility81 
Asset retirement obligations24 
Other noncurrent liabilities(1)
12 
Total liabilities assumed369 
Net Assets Acquired and Liabilities Assumed$1,726 
(1)Reflects adjustments consisting of a $9 million increase to accounts receivable, a $2 million decrease to other current assets, a $6 million increase to accounts payable and a $7 million increase to other non-current liabilities during the twelve months ended December 31, 2022.
The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation was complete as of the third quarter of 2022.
(in millions)As of September 1, 2021
Consideration:
Total consideration$1,961 
Fair Value of Assets Acquired:
Cash and cash equivalents55 
Accounts receivable (2)
193 
Other current assets2 
Commodity derivative assets2 
Evaluated oil and gas properties2,724 
Unevaluated oil and gas properties (1)
690 
Other property, plant and equipment4 
Other long-term assets27 
Total assets acquired3,697 
Fair Value of Liabilities Assumed:
Accounts payable (2)
285 
Other current liabilities55 
Derivative liabilities501 
Revolving credit facility95 
Senior unsecured notes726 
Asset retirement obligations8 
Other noncurrent liabilities (2)
66 
Total liabilities assumed1,736 
Net Assets Acquired and Liabilities Assumed$1,961 
(1)Reflects a $6 million adjustment during 2022 due to finalization of purchase accounting.
(2)Reflects adjustments consisting of a $1 million increase to accounts receivable, an $11 million increase to accounts payable and a $4 million decrease to other non-current liabilities during 2022 due to finalization of purchase accounting.
Business Acquisition, Pro Forma Information
The following table summarizes the unaudited pro forma condensed financial information of Southwestern as if the Indigo Merger and the GEPH Merger each had occurred on January 1, 2020:
For the year ended December 31,
(in millions, except per share amounts)2021
Revenues$8,301 
Net income (loss) attributable to common stock$(354)
Net income (loss) attributable to common stock per share – basic$(0.32)
Net income (loss) attributable to common stock per share – diluted$(0.32)
Schedule of Acquisition Related Costs
There were no merger-related expenses incurred for the year ended December 31, 2023. The following table summarizes the merger-related expenses incurred for the years ended December 31, 2022 and 2021:
For the years ended December 31,
20222021
(in millions)Indigo
Merger		GEPH
Merger		TotalIndigo
Merger		GEPH
Merger
Other (1)
Total
Transition Services$— $18 $18 $— $— $— $— 
Professional fees (bank, legal, consulting)— 1 1 27 19 1 47 
Representation & warranty insurance— — — 4 7 — 11 
Contract buyouts, terminations and transfers1 2 3 7 1 — 8 
Due diligence and environmental1 1 2 3 1 — 4 
Employee-related— 1 1 2 — 1 3 
Other— 2 2 2 — 1 3 
Total merger-related expenses$2 $25 $27 $45 $28 $3 $76 
(1)Consists of merger related costs associated with the Company’s merger of Montage Resources which closed during 2020.
v3.24.0.1
Leases (Tables)
 12 Months Ended
Dec. 31, 2023
Leases [Abstract]  
Disclosure of Lease Costs
The components of lease costs are shown below:
For the years ended December 31,
(in millions)202320222021
Operating lease cost$62 $63 $54 
Short-term lease cost103 93 15 
Variable lease cost3 3 3 
Total lease cost$168 $159 $72 
Supplemental cash flow information related to leases is set forth below:
For the years ended December 31,
(in millions)202320222021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$61 $62 $53 
Right-of-use assets obtained in exchange for operating liabilities:
Operating leases$27 $43 $73 
Supplemental Balance Sheet Information
Supplemental balance sheet information related to leases is as follows:
(in millions)December 31, 2023December 31, 2022
Right-of-use asset balance:
Operating leases$154 $177 
Lease liability balance:
Current operating leases$44 $42 
Long-term operating leases107 133 
Total operating leases$151 $175 
Weighted average remaining lease term: (years)
Operating leases4.14.9
Weighted average discount rate:
Operating leases7.50 %7.32 %
Maturity Analysis of Operating Lease Liabilities
Maturity analysis of operating lease liabilities:
(in millions)December 31, 2023
2024$53 
202539 
202633 
202729 
202814 
Thereafter6 
Total undiscounted lease liability174 
Imputed interest(23)
Total discounted lease liability$151 
v3.24.0.1
Revenue Recognition (Tables)
 12 Months Ended
Dec. 31, 2023
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&PMarketingIntersegment
Revenues		Total
Year ended December 31, 2023    
Gas sales$3,036 $— $53 $3,089 
Oil sales374 — 5 379 
NGL sales702 — — 702 
Marketing— 6,277 (3,922)2,355 
Other (1)
(3)— — (3)
Total$4,109 $6,277 $(3,864)$6,522 
    
Year ended December 31, 2022    
Gas sales$9,100 $— $1 $9,101 
Oil sales434 — 5 439 
NGL sales1,046 — — 1,046 
Marketing— 14,521 (10,102)4,419 
Other (1)
(3)— — (3)
Total$10,577 $14,521 $(10,096)$15,002 
    
Year ended December 31, 2021    
Gas sales$3,358 $— $54 $3,412 
Oil sales389 — 5 394 
NGL sales888 — 2 890 
Marketing— 6,186 (4,223)1,963 
Other (1)
5 3 — 8 
Total$4,640 $6,189 $(4,162)$6,667 
(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)202320222021
Appalachia$2,543 $6,314 $3,955 
Haynesville1,566 4,263 682 
Other— — 3 
Total$4,109 $10,577 $4,640 
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, 2023December 31, 2022
Receivables from contracts with customers$622 $1,313 
Other accounts receivable58 88 
Total accounts receivable$680 $1,401 
v3.24.0.1
Derivatives and Risk Management (Tables)
 12 Months Ended
Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value The tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of December 31, 2023:
Financial Protection on Production
 Weighted Average Price per MMBtu
 Fair value at December 31, 2023
($ in millions)
Volume
(Bcf)
SwapsSold PutsPurchased PutsSold CallsBasis Differential
Natural Gas
2024
Fixed price swaps528 $3.54 $— $— $— $— $448 
Two-way costless collars44 — — 3.07 3.53 — 22 
Three-way costless collars88 — 2.47 3.20 4.09 — 35 
Total660 $505 
2025
Two-way costless collars73 $— $— $3.50 $5.40 $— $31 
Three-way costless collars161 — 2.59 3.66 5.88 — 56 
Total234 $87 
Basis swaps
202482 $— $— $— $— $(0.72)$8 
20259 — — — — (0.64)4 
Total91 $12 
 Weighted Average Price per Bbl
Fair value at December 31, 2023
($ in millions)
Volume
(MBbls)
SwapsSold PutsPurchased PutsSold Calls
Oil     
2024     
Fixed price swaps1,571 $71.06 $— $— $— $(1)
Two-way costless collars512 — — 70.00 85.63 2 
Three-way costless collars92 — 65.00 75.00 93.10 — 
Total2,175 $1 
2025
Fixed price swaps41 $77.66 $— $— $— $— 
Three-way costless collars1,002 — 60.00 70.00 94.64 2 
Total1,043 $2 
Ethane
2024
Fixed price swaps4,897 $10.61 $— $— $— $9 
Propane
2024
Fixed price swaps4,008 $31.38 $— $— $— $11 
2025
Fixed price swaps63 $26.46 $— $— — $— 
Normal Butane
2024
Fixed price swaps329 $40.74 $— $— $— $1 
Natural Gasoline
2024
Fixed price swaps329 $64.37 $— $— $— $2 
Other Derivative Contracts
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair value at December 31, 2023
($ in millions)
Call Options – Natural Gas (Net)   
202482 $6.56 $(1)
202573 7.00 (6)
202673 7.00 (11)
Total228 $(18)
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, 2023 and 2022:
Derivative Assets 
Balance Sheet ClassificationFair Value
(in millions)December 31, 2023December 31, 2022
Derivatives not designated as hedging instruments:   
Fixed price swaps – natural gasDerivative assets$466 $— 
Fixed price swaps – oilDerivative assets1 — 
Fixed price swaps – ethaneDerivative assets9 4 
Fixed price swaps – propaneDerivative assets12 9 
Fixed price swaps – normal butaneDerivative assets1 1 
Fixed price swaps – natural gasolineDerivative assets2 1 
Two-way costless collars – natural gasDerivative assets36 47 
Two-way costless collars – oilDerivative assets3 — 
Three-way costless collars – natural gasDerivative assets62 18 
Three-way costless collars – oilDerivative assets1 1 
Basis swaps – natural gasDerivative assets14 64 
Put options – natural gasDerivative assets8 — 
Fixed price swaps – natural gasOther long-term assets— 28 
Fixed price swaps – oilOther long-term assets— 1 
Fixed price swaps – ethaneOther long-term assets— 1 
Fixed price swaps – propaneOther long-term assets— 1 
Two-way costless collars – natural gasOther long-term assets46 18 
Three-way costless collars – natural gasOther long-term assets116 3 
Three-way costless collars – oilOther long-term assets10 — 
Basis swaps – natural gasOther long-term assets4 17 
Put options – natural gasOther long-term assets— 4 
Total derivative assets $791 $218 
Derivative Liabilities
Balance Sheet ClassificationFair Value
(in millions)December 31, 2023December 31, 2022
Derivatives not designated as hedging instruments:   
Fixed price swaps – natural gasDerivative liabilities$18 $581 
Fixed price swaps – oilDerivative liabilities2 20 
Fixed price swaps – ethaneDerivative liabilities— 1 
Fixed price swaps – propaneDerivative liabilities1 — 
Fixed price swaps – natural gasolineDerivative liabilities— 1 
Two-way costless collars – natural gasDerivative liabilities14 235 
Two-way costless collars – oilDerivative liabilities1 — 
Three-way costless collars – natural gasDerivative liabilities27 311 
Three-way costless collars – oilDerivative liabilities1 31 
Basis swaps – natural gasDerivative liabilities6 69 
Call options – natural gasDerivative liabilities1 70 
Put options – natural gasDerivative liabilities8 — 
Fixed price swaps – natural gas
Other long-term liabilities— 281 
Fixed price swaps – oilOther long-term liabilities— 4 
Two-way costless collars – natural gasOther long-term liabilities15 56 
Three-way costless collars – natural gasOther long-term liabilities60 20 
Three-way costless collars – oilOther long-term liabilities8 — 
Basis swaps – natural gasOther long-term liabilities— 1 
Call options – natural gasOther long-term liabilities17 18 
Total derivative liabilities $179 $1,699 
Net Derivative Position
As of December 31,
2023 2022
 (in millions)
Net current derivative assets (liabilities)$536 $(1,174)
Net long-term derivative assets (liabilities)76 (307)
Non-performance risk adjustment(2)3 
Net total derivative assets (liabilities) $610 $(1,478)
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, 2023 and 2022:
Unsettled Gain (Loss) on Derivatives Recognized in Earnings
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Unsettled
For the years ended
December 31,
Derivative Instrument2023 2022
 (in millions)
Fixed price swaps – natural gasGain (Loss) on Derivatives$1,281 $(166)
Fixed price swaps – oilGain (Loss) on Derivatives22 46 
Fixed price swaps – ethaneGain (Loss) on Derivatives5 12 
Fixed price swaps – propaneGain (Loss) on Derivatives1 87 
Fixed price swaps – normal butaneGain (Loss) on Derivatives— 27 
Fixed price swaps – natural gasolineGain (Loss) on Derivatives2 34 
Two-way costless collars – natural gasGain (Loss) on Derivatives279 (116)
Two-way costless collars – oilGain (Loss) on Derivatives2 — 
Two-way costless collars – ethaneGain (Loss) on Derivatives— 1 
Three-way costless collars – natural gasGain (Loss) on Derivatives402 117 
Three-way costless collars – oilGain (Loss) on Derivatives32 11 
Three-way costless collars – propaneGain (Loss) on Derivatives— 4 
Basis swaps – natural gasGain (Loss) on Derivatives1 (57)
Call options – natural gasGain (Loss) on Derivatives70 21 
Put options – natural gasGain (Loss) on Derivatives(4)4 
Fixed price swaps – natural gas storageGain (Loss) on Derivatives— 1 
Interest rate swapsGain (Loss) on Derivatives— (2)
Total gain on unsettled derivatives $2,093 $24 
Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Settled
For the years ended
December 31,
Derivative Instrument2023 2022
 (in millions)
Fixed price swaps – natural gasGain (Loss) on Derivatives$300 $(2,918)
Fixed price swaps – oil
Gain (Loss) on Derivatives(27)(129)
Fixed price swaps – ethaneGain (Loss) on Derivatives6 (49)
Fixed price swaps – propaneGain (Loss) on Derivatives26 (100)
Fixed price swaps – normal butaneGain (Loss) on Derivatives3 (35)
Fixed price swaps – natural gasolineGain (Loss) on Derivatives1 (49)
Two-way costless collars – natural gasGain (Loss) on Derivatives48 

(448)
Two-way costless collars – oilGain (Loss) on Derivatives(1)— 
Two-way costless collars – ethaneGain (Loss) on Derivatives— (1)
Three-way costless collars – natural gasGain (Loss) on Derivatives(19)(1,319)
Three-way costless collars – oilGain (Loss) on Derivatives(27)(51)
Three-way costless collars – propaneGain (Loss) on Derivatives— (5)
Index swaps - natural gasGain (Loss) on Derivatives— (1)
Basis swaps – natural gasGain (Loss) on Derivatives43 128 
Call options – natural gasGain (Loss) on Derivatives(8)(304)
Purchased fixed price swaps – natural gas storageGain (Loss) on Derivatives— 1 
Fixed price swaps – natural gas storageGain (Loss) on Derivatives— (3)
Total gain (loss) on settled derivatives $345 $(5,283)
(1)The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.
Total Gain (Loss) on Derivatives Recognized in Earnings
For the years ended
December 31,
20232022
 (in millions)
Total gain on unsettled derivatives$2,093 $24 
Total gain (loss) on settled derivatives345 (5,283)
Non-performance risk adjustment(5)— 
Total gain (loss) on derivatives $2,433 $(5,259)
v3.24.0.1
Reclassifications from Accumulated Other Comprehensive Income (Loss) (Tables)
 12 Months Ended
Dec. 31, 2023
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]  
Components of Accumulated Other Comprehensive Income (Loss)
In 2023, 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, 2023:
For the year ended December 31, 2023
(in millions)Pension and Other PostretirementForeign CurrencyTotal
Beginning balance, December 31, 2022$20 $(14)$6 
Other comprehensive income before reclassifications7 — 7 
Amounts reclassified from other comprehensive income (1)
(16)— (16)
Net current-period other comprehensive loss(9)— (9)
Ending balance, December 31, 2023$11 $(14)$(3)
(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, 2023
Pension and other postretirement: (1)
(in millions)
SettlementsOther income, net$(2)
Tax valuation allowance release impact on pension settlementsProvision for income taxes(14)
Total reclassifications for the periodNet income$(16)
(1)See Note 13 for additional details regarding the Company’s pension and other postretirement benefit plans.
v3.24.0.1
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2023
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, 2023 and 2022 were as follows:
December 31, 2023December 31, 2022
(in millions)Carrying AmountFair ValueCarrying Amount Fair Value
Cash and cash equivalents$21 $21 $50  $50 
2022 revolving credit facility due April 2027220 220 250  250 
Senior notes (1)
3,743 3,626 4,164  3,847 
Derivative instruments, net610 610 (1,478)(1,478)
(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, 2023
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: (1)
    
Fixed price swaps$— $491 $— $491 
Two-way costless collars— 85 — 85 
Three-way costless collars— 189 — 189 
Basis swaps— 18 — 18 
Purchase Put - Natural Gas— 8 — 8 
Liabilities:
Fixed price swaps— (21)— (21)
Two-way costless collars— (30)— (30)
Three-way costless collars— (96)— (96)
Basis swaps— (6)— (6)
Call options— (18)— (18)
Put options— (8)— (8)
Total$— $612 $— $612 
(1)Excludes a net reduction to the asset fair value of $2 million related to estimated non-performance risk.
December 31, 2022
Fair Value Measurements Using: 
(in millions)
Quoted Prices in Active Markets
(Level 1)
Significant Other Observable Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
Assets (Liabilities) at Fair Value
Assets:    
Fixed price swaps$— $46 $— $46 
Two-way costless collars— 65 — 65 
Three-way costless collars— 22 — 22 
Basis swaps— 81 — 81 
Purchase Put - Natural Gas— 4 — 4 
Liabilities: (1)
Fixed price swaps— (888)— (888)
Two-way costless collars— (291)— (291)
Three-way costless collars— (362)— (362)
Basis swaps— (70)— (70)
Call options— (88)— (88)
Total$— $(1,481)$— $(1,481)
(1)Excludes a net reduction to the liability fair value of $3 million related to estimated non-performance risk.
v3.24.0.1
Debt (Tables)
 12 Months Ended
Dec. 31, 2023
Debt Disclosure [Abstract]  
Components of Debt
The components of debt as of December 31, 2023 and 2022 consisted of the following:
December 31, 2023
(in millions)Debt InstrumentUnamortized Issuance ExpenseUnamortized
Debt Premium / Discount		Total
Variable rate (7.20% at December 31, 2023)
2022 revolving credit facility, due April 2027
$220 $— 
(1)
$— $220 
4.95% Senior Notes due January 2025 (2)
389 — — 389 
8.375% Senior Notes due September 2028
304 (3)— 301 
5.375% Senior Notes due February 2029
700 (5)18 713 
5.375% Senior Notes due March 2030
1,200 (13)— 1,187 
4.75% Senior Notes due February 2032
1,150 (13)— 1,137 
Total debt$3,963 $(34)$18 $3,947 
December 31, 2022
(in millions)Debt InstrumentUnamortized Issuance ExpenseUnamortized
Debt Premium / Discount		Total
Variable rate (6.15% at December 31, 2022)
2022 revolving credit facility, due April 2027
$250 $— 
(1)
$— $250 
4.95% Senior Notes due January 2025 (2)
389 (1)— 388 
7.75% Senior Notes due October 2027
421 (3)— 418 
8.375% Senior Notes due September 2028
304 (3)— 301 
5.375% Senior Notes due February 2029
700 (5)22 717 
5.375% Senior Notes due March 2030
1,200 (16)— 1,184 
4.75% Senior Notes due February 2032
1,150 (16)— 1,134 
Total debt$4,414 $(44)$22 $4,392 
(1)At December 31, 2023 and 2022, unamortized issuance expense of $15 million and $19 million, respectively, associated with the 2022 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheet.
(2)Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company's bond ratings since their issuance. On April 7, 2020, S&P downgraded the Company's bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment due date. The first coupon payment to the bondholders at the higher interest rate was paid in January 2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which
decreased the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022.
Schedule of Long Term Debt Maturities
The following is a summary of scheduled debt maturities by year as of December 31, 2023:
(in millions)
2024$— 
2025389 
2026— 
2027 (1)
220 
2028304 
Thereafter3,050 
$3,963 
(1)The Company’s 2022 credit facility matures in 2027.
v3.24.0.1
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]  
Schedule of Future Obligation under Transportation Agreements As of December 31, 2023, future payments under non-cancelable firm transportation and gathering agreements are as follows:
Payments Due by Period
(in millions)TotalLess than 1 Year1 to 3 Years3 to 5 Years5 to 8 YearsMore than 8 Years
Infrastructure currently in service$8,331 $1,055 $1,983 $1,778 $1,727 $1,788 
Pending regulatory approval and/or construction (1)
1,015 46 157 177 266 369 
Total transportation charges$9,346 $1,101 $2,140 $1,955 $1,993 $2,157 
(1)Based on the estimated in-service dates as of December 31, 2023.
v3.24.0.1
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2023
Income Tax Disclosure [Abstract]  
Provision (Benefit) for Income Taxes
The provision (benefit) for income taxes included the following components:
(in millions)202320222021
Current:   
Federal$(4)$47 $— 
State(1)4 — 
(5)51 — 
Deferred:
Federal(192)— — 
State(60)— — 
(252)— — 
Provision (benefit) for income taxes$(257)$51 $— 
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)202320222021
Expected provision (benefit) at federal statutory rate$273 $400 $(5)
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect18 39 — 
Change in valuation allowance(526)(392)2 
Return to accrual(16)— — 
Federal research and development credit(13)— — 
Other7 4 3 
Provision (benefit) for income taxes$(257)$51 $— 
Components of Deferred Tax Balances
The components of the Company’s deferred tax balances as of December 31, 2023 and 2022 were as follows:
(in millions)20232022
Deferred tax liabilities:
Differences between book and tax basis of property$255 $379 
Derivative activity137 — 
Right of use lease asset34 41 
Accrued pension costs— 1 
Other3 3 
429 424 
Deferred tax assets:
Accrued compensation53 50 
Accrued pension costs1 — 
Asset retirement obligations27 24 
Net operating loss carryforward450 469 
Future lease payments35 41 
Derivative activity— 340 
Capital loss carryover26 27 
Interest carryover93 41 
Research and development credits17 — 
Other17 21 
719 1,013 
Valuation allowance(52)(589)
Net deferred tax asset$238 $— 
Reconciliation of Changes to the Valuation Allowance
A reconciliation of the changes to the valuation allowance is as follows:
(in millions)20232022
Valuation allowance at beginning of year$589 $1,079 
Return to accrual adjustments(12)(36)
State rate and apportionment changes(13)(66)
Current period deferred activity— (388)
Release of valuation allowance(512)— 
Valuation allowance at end of year$52 $589 
v3.24.0.1
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2023
Asset Retirement Obligation [Abstract]  
Schedule of Asset Retirement Obligations
The following table summarizes the Company’s 2023 and 2022 activity related to asset retirement obligations:
(in millions)20232022
Asset retirement obligation at January 1$105 $109 
Accretion of discount6 6 
Obligations incurred1 1 
Obligations settled/removed(1)(10)
Revisions of estimates8 (1)
Asset retirement obligation at December 31$119 $105 
Current liability$4 $6 
Long-term liability115 99 
Asset retirement obligation at December 31$119 $105 
v3.24.0.1
Retirement and Employee Benefit Plans (Tables)
 12 Months Ended
Dec. 31, 2023
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, 2023 and 2022:
Pension BenefitsOther Postretirement Benefits
(in millions)2023202220232022
Change in benefit obligations:    
Benefit obligation at January 1$57 $126 $9 $13 
Service cost— — 2 2 
Interest cost— 3 1 — 
Actuarial gain— (29)(7)(5)
Benefits paid— (2)— (1)
Plan amendments— (2)— — 
Settlements(57)(39)— — 
Benefit obligation at December 31$— $57 $5 $9 
Pension BenefitsOther Postretirement Benefits
(in millions)2023202220232022
Change in plan assets:    
Fair value of plan assets at January 1$72 $114 $— $— 
Actual return on plan assets— — — — 
Employer contributions— — — 1 
Benefits paid— (2)— (1)
Settlements(58)(40)— — 
Transfer to qualified replacement plan (1)
(14)— — — 
Fair value of plan assets at December 31$— $72 $— $— 
Funded status of plans at December 31$— $15 $(5)$(9)
(1)Funds in the qualified replacement plan are presented as cash and cash equivalents on the Company’s consolidated balance sheet as of December 31, 2023.
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, 2023 and 2022 are as follows:
(in millions)2023
(1)
2022
Projected benefit obligation$— $57 
Accumulated benefit obligation— 57 
Fair value of plan assets— 72 
(1)The Company completed the termination of the Plan in 2023.
Pension and Other Postretirement Benefit Costs
Pension and other postretirement benefit costs include the following components for 2023, 2022 and 2021:
Pension BenefitsOther Postretirement Benefits
(in millions)202320222021202320222021
Service cost (1)
$— $— $— $2 $2 $2 
Interest cost— 3 4 1 — — 
Expected return on plan assets— — (4)— — — 
Amortization of prior service cost— (1)— — — — 
Amortization of net loss— — — — — — 
Net periodic benefit cost— 2 — 3 2 2 
Settlement (gain) loss2 (1)2 — — — 
Total benefit cost$2 $1 $2 $3 $2 $2 
(1)The Company froze the Plan effective January 1, 2021, resulting in no service cost for the years ended December 31, 2023, December 31, 2022 and December 31, 2021.
Amounts Recognized in Other Comprehensive Income
Amounts recognized in other comprehensive income for the years ended December 31, 2023 and 2022 were as follows:
Pension BenefitsOther Postretirement Benefits
(in millions)2023202220232022
Net actuarial gain arising during the year$— $30 $7 $4 
Amortization of prior service cost— (2)— — 
Tax valuation allowance release impact on pension settlements(14)— — — 
Settlements(2)(1)— — 
Less: Tax effect (1)
— — — — 
Amounts recognized in other comprehensive income$(16)$27 $7 $4 
(1)Other postretirement benefit tax effects of approximately $1 million for each of the years ended December 31, 2023 and December 31, 2022 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, 2023 and 2022 are as follows:
Pension Benefits (1)
Other Postretirement Benefits
2023202220232022
Discount raten/a5.60 %5.20 %5.50 %
Rate of compensation increase (2)
n/an/an/an/a
(1)The Company completed the termination of its pension plan in 2023.
(2)Rate of compensation increase for other postretirement benefits is disclosed as “n/a” as the benefit is the same for all employees and not based on compensation.
The assumptions used in the measurement of the Company’s net periodic benefit cost for 2023, 2022 and 2021 are as follows:
Pension Benefits (1)
Other Postretirement Benefits
202320222021202320222021
Discount raten/a5.60 %3.20 %5.50 %3.10 %2.80 %
Expected return on plan assetsn/a0.10 %0.10 %n/an/an/a
Rate of compensation increase (2)
n/an/a3.50 %n/an/an/a
(1)The Company completed the termination of the Plan in 2023.
(2)Rate of compensation increase for other postretirement benefits is disclosed as “n/a” as the benefit is the same for all employees and not based on compensation.
Schedule of Health Care Cost Trend Rates
For measurement purposes, the following trend rates were assumed for 2023 and 2022:
20232022
Health care cost trend assumed for next year7.0 %7.0 %
Rate to which the cost trend is assumed to decline5.0 %5.0 %
Year that the rate reaches the ultimate trend rate20412040
Fair Value Measurement of Pension Plan Assets Utilizing the fair value hierarchy described in Note 8, the Company’s fair value measurement of Plan assets at December 31, 2022 was as follows:
(in millions)TotalQuoted Prices in Active Markets for Identical Assets (Level 1)
Significant Observable Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
Measured within fair value hierarchy
Fixed income (1)
69 69 — — 
Cash and cash equivalents2 2 — — 
Total plan assets at fair value$71 $71 $— $— 
(1)U.S. Treasury Notes
v3.24.0.1
Long-Term Incentive Compensation (Tables)
 12 Months Ended
Dec. 31, 2023
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, 2023, 2022 and 2021:
(in millions)202320222021
Long-term incentive compensation – expensed$23 $30 $30 
Long-term incentive compensation – capitalized$15 $20 $18 
The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Equity-classified awards – expensed$9 $4 $2 
Equity-classified awards – capitalized$3 $3 $— 
The Company recorded the following compensation costs related to equity-classified restricted stock grants for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Restricted stock grants – general and administrative expense$2 $1 $2 
Restricted stock grants – capitalized expense$— $— $— 
The Company recorded the following compensation costs related to equity-classified restricted stock units for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Restricted stock units – general and administrative expense$5 $2 $— 
Restricted stock units – capitalized expense$2 $2 $— 
(in millions)202320222021
Performance units – general and administrative expense$2 $1 $— 
Performance units – capitalized expense$1 $1 $— 
The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Liability-classified stock-based compensation – expensed$5 $20 $24 
Liability-classified stock-based compensation awards – capitalized$2 $11 $14 
The Company recorded the following compensation costs related to performance cash awards for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Performance cash awards – general and administrative expense$9 $6 $4 
Performance cash awards – capitalized expense$10 $6 $4 
Summary of Equity-Classified Stock Option Activity
The following tables summarize stock option activity for the years 2023, 2022 and 2021, and provide information for options outstanding at December 31 of each year:
202320222021
Number
of Shares		Weighted Average Exercise Price
Number
of Shares
Weighted Average Exercise Price
Number
of Shares
Weighted Average Exercise Price
(in thousands) (in thousands) (in thousands) 
Options outstanding at January 1997 $8.59 3,006 $8.98 3,850 $13.39 
Granted— $— — $— — $— 
Exercised— $— (893)$7.80 — $— 
Forfeited or expired(177)$8.60 (1,116)$10.26 (844)$29.10 
Options outstanding at December 31820 $8.59 997 $8.59 3,006 $8.98 
Options exercisable at December 31 (1)
820 $8.59 
(1)Weighted average remaining contractual life for options outstanding and exercisable was 1.1 years, as of December 31, 2023.
Summary of Equity-Classified Restricted Stock Activity
The following table summarizes the restricted stock activity for the years 2023, 2022 and 2021, and provides information for restricted stock outstanding at December 31 of each year:
202320222021
Number of
Shares		Weighted Average Fair Value
Number of
Shares
Weighted Average Fair Value
Number of
Shares
Weighted Average Fair Value
(in thousands) (in thousands) (in thousands) 
Unvested shares at January 1211 $5.81 242 $5.12 697 $5.97 
Granted336 $5.34 231 $6.92 438 $5.18 
Vested(378)$5.71 (262)$6.15 (893)$5.81 
Forfeited— $— — $— — $8.59 
Unvested shares at December 31169 $5.09 211 $5.81 242 $5.12 
The following table summarizes equity-classified restricted stock unit activity to be paid out in Company stock for the years ended December 31, 2023, 2022 and 2021.
202320222021
Number
of Units		Weighted Average
Fair Value		Number
of Units		Weighted Average
Fair Value		Number
of Shares		Weighted Average
Fair Value
(in thousands)(in thousands)(in thousands)
Unvested Units at January 11,645 $4.44 37 $3.05 134 $3.05 
Granted1,617 $4.94 1,699 $4.45 — $— 
Vested(555)$4.42 (22)$3.05 (92)$3.05 
Forfeited(1)$3.05 (69)$4.37 (5)$3.05 
Unvested Units at December 312,706 $4.74 1,645 $4.44 37 $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, 2023, 2022 and 2021, and provides information for unvested units as of December 31, 2023, 2022 and 2021:
202320222021
Number of
Units (1)
Weighted
Average Fair Value
Number of
Units (1)
Weighted
Average Fair Value		Number of
Units		Weighted
Average Fair Value
(in thousands)(in thousands)(in thousands)
Unvested units at January 1817 $6.04 — $— — $— 
Granted940 $6.12 850 $6.04 — $— 
Vested— $— — $— — $— 
Forfeited— $— (33)

$6.04 — $— 
Unvested shares at December 311,757 $6.08 817 $6.04 — $— 
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, 2023, 2022 and 2021:
(in millions)202320222021
Restricted stock units – general and administrative expense$4 $9 $12 
Restricted stock units – capitalized expense$2 $6 $8 
The Company recorded the following compensation costs related to liability-classified performance unit grants for the years ended December 31, 2023, 2022 and 2021:
(in millions)202320222021
Liability-classified performance units – general and administrative expense$1 $11 $12 
Liability-classified performance units – capitalized expense$— $5 $6 
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, 2023, 2022 and 2021 and provides information for unvested units as of December 31, 2023, 2022 and 2021:
202320222021
Number
of Units		Weighted Average Fair ValueNumber
of Units		Weighted Average Fair ValueNumber
of Units		Weighted Average Fair Value
(in thousands) (in thousands)(in thousands)
Unvested units at January 13,950 $4.81 7,937 $4.08 11,613 $2.67 
Granted— $— — $— 1,486 $4.23 
Vested(2,206)$4.84 (3,817)$4.48 (4,522)$3.40 
Forfeited(3)$5.57 (170)$6.83 (640)
(1)
$4.56 
Unvested units at December 311,741 $4.67 3,950 $4.81 7,937 $4.08 
(1)Includes 360,253 units related to the reduction in workforce for the year ended December 31, 2021.
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, 2023, 2022 and 2021 and provides information for unvested units as of December 31, 2023, 2022 and 2021:
202320222021
Number
of Units		Weighted Average
Fair Value		Number
of Units		Weighted Average
Fair Value		Number
of Units		Weighted Average
Fair Value
(in thousands) (in thousands)(in thousands)
Unvested units at January 110,982 $2.25 9,515 $2.88 8,699 $2.57 
Granted5,136 $4.83 3,798 $1.00 3,580 $4.14 
Vested(3,966)$6.13 (1,910)$6.45 (2,020)$4.05 
Forfeited— $— (421)$6.70 (744)$3.40 
Unvested units at December 3112,152 $0.94 10,982 $2.25 9,515 $2.88 
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, 2023, 2022 and 2021 and provides information for unvested units as of December 31, 2023, 2022 and 2021:
202320222021
Number
of Units		Weighted Average
Fair Value		Number
of Units		Weighted Average
Fair Value		Number
of Shares		Weighted Average
Fair Value
(in thousands)(in thousands)
Unvested units at January 139,994 $1.00 28,272 $1.00 18,353 $1.00 
Granted27,493 $1.00 24,416 $1.00 18,546 $1.00 
Vested(13,320)$1.00 (8,786)$1.00 (4,955)$1.00 
Forfeited(4,489)$1.00 (3,908)$1.00 (3,672)
(1)
$1.00 
Unvested Units at December 3149,678 $1.00 39,994 $1.00 28,272 $1.00 
(1) Includes 1,241,000 units related to the reduction in workforce for the year ended December 31, 2021.
v3.24.0.1
Segment Information (Tables)
 12 Months Ended
Dec. 31, 2023
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
MarketingTotal Reportable SegmentsOtherTotal
2023
Revenues from external customers$4,167 $2,355 $6,522 $— $6,522 
Intersegment revenues(58)3,922 3,864 — 3,864 
Depreciation, depletion and amortization expense1,302 5 1,307 — 1,307 
Impairments1,710 — 1,710 — 1,710 
Operating income (loss)(1,061)92 (969)(5)(974)
Interest expense (1)
142 — 142 — 142 
Gain on derivatives2,433 — 2,433 — 2,433 
Loss on early extinguishment of debt— — — (19)(19)
Other income, net2 — 2 — 2 
Benefit from income taxes (1)
(257)— (257)— (257)
Assets11,253 
(2)
591 11,844 147 11,991 
Capital investments (3)
2,122 — 2,122 9 2,131 
(in millions)
Exploration
and
Production
MarketingTotal Reportable SegmentsOtherTotal
2022
Revenues from external customers$10,583 $4,419 $15,002 $— $15,002 
Intersegment revenues(6)10,102 10,096 — 10,096 
Depreciation, depletion and amortization expense1,169 5 1,174 — 1,174 
Operating income7,253 
(4)
101 7,354 — 7,354 
Interest expense (1)
184 — 184 — 184 
Loss on derivatives(5,257)— (5,257)(2)(5,259)
Loss on early extinguishment of debt— — — (14)(14)
Other income, net3 — 3 — 3 
Provision for income taxes (1)
51 — 51 — 51 
Assets11,473 
(2)
1,274 12,747 179 12,926 
Capital investments (3)
2,196 — 2,196 13 2,209 
2021
Revenues from external customers$4,701 $1,966 $6,667 $— $6,667 
Intersegment revenues(61)4,223 4,162 — 4,162 
Depreciation, depletion and amortization expense537 9 546 — 546 
Impairments6 — 6 — 6 
Operating income2,583 
(5)
52 2,635 — 2,635 
Interest expense (1)
136 — 136 — 136 
Gain (loss) on derivatives(2,437)— (2,437)1 (2,436)
Loss on early extinguishment of debt— — — (93)(93)
Other income, net5 — 5 — 5 
Provision for income taxes (1)
— — — — — 
Assets10,767 
(2)
956 11,723 125 11,848 
Capital investments (3)
1,107 — 1,107 1 1,108 
(1)Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.
(2)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.
(3)Capital investments include a decrease of $44 million for 2023, an increase of $88 million for 2022 and an increase of $70 million for 2021 related to the change in accrued expenditures between years. 
(4)Operating income for the E&P segment includes $27 million of acquisition-related charges for the year ended December 31, 2022.
(5)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.
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, 2023, 2022 and 2021:
For the years ended December 31,
(in millions)202320222021
Cash and cash equivalents$21 $50 $28 
Accounts receivable— 1 — 
Prepayments18 14 6 
Other current assets2 — — 
Property, plant and equipment24 19 12 
Unamortized debt expense15 19 10 
Right-of-use lease assets49 57 65 
Non-qualified retirement plan3 3 4 
Long term assets15 16 — 
$147 $179 $125 
v3.24.0.1
Supplemental Oil and Gas Disclosures (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
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)202320222021
Unproved property acquisition costs$184 $202 $139 
Exploration costs— — — 
Development costs1,939 2,021 984 
Capitalized costs incurred$2,123 $2,223 $1,123 
Full cost pool amortization per Mcfe$0.77 $0.67 $0.42 
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)202320222021
Sales$4,109 $10,577 $4,640 
Production (lifting) costs(1,990)(1,969)(1,304)
Depreciation, depletion and amortization(1,302)(1,169)(537)
Impairment of natural gas and oil properties(1,710)— — 
(893)7,439 2,799 
Provision (benefit) for income taxes (1)
(200)— — 
Results of operations (2)
$(693)$7,439 $2,799 
(1)No tax provision (benefit) in 2022 and 2021 due to recognition of a tax valuation allowance for the years ended December 31, 2022 and 2021, respectively.
(2)Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 6.
Summary of Changes in Reserves
The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2021, 2022 and 2023, all of which were located in the United States:
Natural Gas
(Bcf)
Oil
(MBbls)
NGL
(MBbls)
Total
(Bcfe)
December 31, 20209,181 58,024 410,151 11,990 
Revisions of previous estimates due to price (1)
501 1,414 (15,525)415 
Revisions of previous estimates other than price (2)
1,402 17,384 127,197 2,270 
Extensions, discoveries and other additions (2)
1,389 9,381 85,901 1,961 
Production(1,015)(6,610)(30,940)(1,240)
Acquisition of reserves in place (3)
5,750 247 180 5,753 
Disposition of reserves in place(1)(61)— (1)
December 31, 202117,207 79,779 576,964 21,148 
Revisions of previous estimates due to price61 (107)(828)55 
Revisions of previous estimates other than price (4)
(458)(2,149)40,138 (230)
Extensions, discoveries and other additions 2,106 10,877 42,719 2,428 
Production(1,520)(4,993)(30,446)(1,733)
Disposition of reserves in place (34)(21)(1,411)(43)
December 31, 202217,362 83,386 627,136 21,625 
Revisions of previous estimates due to price
(1,779)(1,118)(10,217)(1,847)
Revisions of previous estimates other than price (5)
(417)(3,630)52,283 (125)
Extensions, discoveries and other additions1,813 5,062 30,444 2,026 
Production(1,438)(5,602)(32,859)(1,669)
Disposition of reserves in place(350)— — (350)
December 31, 202315,191 78,098 666,787 19,660 
(1)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.
(2)Includes 1,155 Bcf, 15 MBbls and 126 MBbls of natural gas, oil and NGL proved reserves, respectively, that were previously presented as “Extensions, discoveries and other additions” which have been reclassified to “Revisions of previous estimate other than price” to conform with 2022 and 2023 presentation of infill reserves.
(3)The 2021 acquisition amounts are primarily associated with the Indigo Merger and the GEPH Merger.
(4)Includes performance revisions of a positive 272 Bcf, negative 681 MBbls and positive 41,490 MBbls of natural gas, oil and NGL proved reserves, respectively. Includes additions associated with infill development of 303 Bcf, 5,254 MBbls, and 40,423 MBbls of natural gas, oil and NGL proved reserves, respectively. Includes downward revisions from change in development plans of 1,033 Bcf, 6,722 MBbls, and 41,775 MBbls of natural gas, oil and NGL proved reserves, respectively.
(5)Includes performance revisions of a positive 25 Bcf, negative 3,062 MBbls and positive 28,189 MBbls of natural gas, oil and NGL proved reserves, respectively. Includes additions associated with infill development of 647 Bcf, 12,493 MBbls, and 85,378 MBbls of natural gas, oil and NGL proved reserves, respectively. Includes downward revisions from change in development plans of 1,089 Bcf, 13,061 MBbls, and 61,284 MBbls of natural gas, oil and NGL proved reserves, respectively.
Natural Gas
(Bcf)
Oil
(MBbls)
NGL
(MBbls)
Total
(Bcfe)
Proved developed reserves as of:    
December 31, 20219,308 40,930 296,832 11,335 
December 31, 20229,793 41,138 350,821 12,145 
December 31, 20239,196 38,581 362,983 11,605 
Proved undeveloped reserves as of:    
December 31, 20217,899 38,849 280,132 9,813 
December 31, 20227,569 42,248 276,315 9,480 
December 31, 20235,995 39,517 303,804 8,055 
The following table summarizes the changes in reserves for 2021, 2022 and 2023:
(in Bcfe)AppalachiaHaynesville
Other (1)
Total
December 31, 202011,989 — 1 11,990 
Net revisions
Price revisions415 — — 415 
Performance and production revisions (2)
2,271 — (1)2,270 
Total net revisions2,686 — (1)2,685 
Extensions, discoveries and other additions
Proved developed (2)
197 — — 197 
Proved undeveloped (2)
1,764 — — 1,764 
Total reserve additions1,961 — — 1,961 
Production(1,108)(132)— (1,240)
Acquisition of reserves in place— 5,753 — 5,753 
Disposition of reserves in place(1)— — (1)
December 31, 202115,527 5,621 — 21,148 
Net revisions
Price revisions(4)59 — 55 
Performance and production revisions (3)
(33)(197)— (230)
Total net revisions(37)(138)— (175)
Extensions, discoveries and other additions
Proved developed 235 171 — 406 
Proved undeveloped 1,038 984 — 2,022 
Total reserve additions1,273 1,155 — 2,428 
Production(1,054)(679)— (1,733)
Acquisition of reserves in place— — — — 
Disposition of reserves in place(43)— — (43)
December 31, 202215,666 5,959 — 21,625 
Net revisions
Price revisions(570)(1,277)— (1,847)
Performance and production revisions (4)
189 (314)— (125)
Total net revisions(381)(1,591)— (1,972)
Extensions, discoveries and other additions
Proved developed14 66 — 80 
Proved undeveloped769 1,177 — 1,946 
Total reserve additions783 1,243 — 2,026 
Production(1,034)(635)— (1,669)
Acquisition of reserves in place— — — — 
Disposition of reserves in place(349)(1)— (350)
December 31, 202314,685 4,975 — 19,660 
(1)Other includes properties outside of Appalachia and Haynesville.
(2)Includes 158 Bcf, 2 MBbls and 14 MBbls of natural gas, oil and NGL proved developed reserves, respectively, that were previously presented as “Extensions, discoveries and other additions” which have been reclassified to “Performance and production revisions” to conform with current year presentation for infill reserves. Includes 997 Bcf, 13 MBbls and 112 MBbls of natural gas, oil and NGL proved undeveloped reserves, respectively, that were previously presented as “Extensions, discoveries and other additions” which have been reclassified to “Performance and production revisions” to conform with 2022 and 2023 presentation of infill reserves.
(3)Includes Appalachia reserves with positive performance revisions of 381 Bcf, additions associated with infill development of 577 Bcf, and downward revisions from changes in development plans of 991 Bcf. Includes Haynesville reserves with positive performance revisions of 136 Bcf and downward revisions from changes in development plans of 333 Bcf.
(4)Includes Appalachia reserves with positive performance revisions of 246 Bcf, additions associated with infill development of 1,200 Bcf, and downward revisions from changes in development plans of 1,257 Bcf. Includes Haynesville reserves with negative performance revisions of 70 Bcf, additions associated with infill development of 34 Bcf and downward revisions from changes in development plans of 278 Bcf.
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, 2023, 2022 and 2021 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)202320222021
Future cash inflows$50,499 $132,037 $75,314 
Future production costs(26,147)(29,632)(23,235)
Future development costs (1)
(6,558)(7,458)(6,032)
Future income tax expense(1,581)(19,323)(8,135)
Future net cash flows16,213 75,624 37,912 
10% annual discount for estimated timing of cash flows(8,900)(38,036)(19,181)
Standardized measure of discounted future net cash flows$7,313 $37,588 $18,731 
(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:
202320222021
Natural gas (per MMBtu)
$2.64 $6.36 $3.60 
Oil (per Bbl)
78.22 93.67 66.56 
NGLs (per Bbl)
21.38 34.35 28.65 
Schedule of Analysis of Changes in Standardized Measure
Following is an analysis of changes in the standardized measure during 2023, 2022 and 2021:
(in millions)202320222021
Standardized measure, beginning of year$37,588 $18,731 $1,847 
Sales and transfers of natural gas and oil produced, net of production costs(2,123)(8,611)(3,332)
Net changes in prices and production costs(36,514)23,198 10,417 
Extensions, discoveries, and other additions, net of future production and development costs63 4,976 3,183 
Acquisition of reserves in place— 1 6,499 
Sales of reserves in place(710)(49)(1)
Revisions of previous quantity estimates(1,174)(400)596 
Net change in income taxes8,364 (5,158)(3,689)
Changes in estimated future development costs1,005 (709)137 
Previously estimated development costs incurred during the year1,336 1,208 419 
Changes in production rates (timing) and other(5,165)2,159 2,470 
Accretion of discount4,643 2,242 185 
Standardized measure, end of year$7,313 $37,588 $18,731 
v3.24.0.1
Organization and Summary of Significant Accounting Policies (Narrative) (Details)
 1 Months Ended 12 Months Ended
Dec. 31, 2021
USD ($)
$ / shares
shares
Sep. 01, 2021
USD ($)
$ / shares
shares
Sep. 30, 2021
shares
Dec. 31, 2023
USD ($)
segment
shares
Dec. 31, 2022
USD ($)
$ / shares
shares
Dec. 31, 2021
USD ($)
$ / shares
shares
Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Number of segments | segment       2      
Cash and cash equivalents       $ 21,000,000 $ 50,000,000    
Outstanding checks included in accounts payable       $ 73,000,000 100,000,000    
Natural gas, oil and NGL reserves discount       10.00%      
Net book value adjusted for market differentials       $ 1,710,000,000      
Impairments       1,710,000,000 0 $ 6,000,000  
Net unevaluated costs excluded from amortization, cumulative       2,075,000,000 2,217,000,000    
Capitalized interest       303,000,000      
Other long-term assets       $ 96,000,000 $ 110,000,000    
Treasury stock (in shares) | shares       0 17,261,469    
Treasury stock acquired, average cost per share (in dollars per share) | $ / shares         $ 7.24    
Treasury stock acquired         $ 125,000,000    
Shares held in trust (in shares) | shares       1,455 1,743    
Marketing-Related Intangible Assets              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Intangible assets, current       $ 38,000,000 $ 43,000,000    
Other long-term assets       33,000,000 38,000,000    
Amortization of intangible asset       5,000,000 5,000,000 8,000,000  
Expected amortization in year one       5,000,000      
Expected amortization in year two       5,000,000      
Expected amortization in year three       5,000,000      
Expected amortization in year four       5,000,000      
Expected amortization in year five       4,000,000      
Other non-core assets              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Impairments       $ 0 $ 0 6,000,000  
Minimum | Non-full cost pool assets              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Long lived assets, useful life       3 years      
Maximum | Non-full cost pool assets              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Long lived assets, useful life       30 years      
Undeveloped Properties Southwest Appalachia              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Net unevaluated costs excluded from amortization, cumulative       $ 1,048,000,000      
Undeveloped Properties Northeast Appalachia              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Net unevaluated costs excluded from amortization, cumulative       587,000,000      
Wells In Progress              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Net unevaluated costs excluded from amortization, cumulative       59,000,000      
Capitalized interest       $ 303,000,000      
One Customer | Revenue Benchmark | Customer concentration risk              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Concentration percentage       14.00% 17.00%    
WPX Property Acquisition              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Percentage of voting interest             86.00%
Other              
Organization, Consolidation and Presentation of Financial Statements [Line Items]              
Impairments       $ 0 $ 0 0  
Net unevaluated costs excluded from amortization, cumulative       $ 137,000,000      
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            
Business acquisition, equity interest issued or issuable, value assigned $ 463,000,000         $ 463,000,000  
NYSE closing price per share of Southwestern common shares (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  
Business acquisition, equity interest issued or issuable, value assigned $ 463,000,000         $ 463,000,000  
NYSE closing price per share of Southwestern common shares (in dollars per share) | $ / shares $ 4.66         $ 4.66  
Indigo 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   337,827,171          
Business acquisition, equity interest issued or issuable, value assigned   $ 1,588,000,000          
NYSE closing price per share of Southwestern common shares (in dollars per share) | $ / shares   $ 4.70          
Indigo 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     337,827,171        
Business acquisition, equity interest issued or issuable, value assigned   $ 1,588,000,000          
NYSE closing price per share of Southwestern common shares (in dollars per share) | $ / shares   $ 4.70          
v3.24.0.1
Organization and Summary of Significant Accounting Policies (Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]    
Proved properties $ 35,697 $ 33,546
Unproved properties 2,075 2,217
Total capitalized costs 37,772 35,763
Less:  Accumulated depreciation, depletion and amortization (28,031) (25,033)
Net capitalized costs $ 9,741 $ 10,730
v3.24.0.1
Organization and Summary of Significant Accounting Policies (Oil and Gas, Average Sale Price and Production Cost) (Details)
 12 Months Ended
Dec. 31, 2023
$ / MMBTU
Dec. 31, 2023
$ / barrel
Dec. 31, 2023
$ / bbl
Dec. 31, 2022
$ / MMBTU
Dec. 31, 2022
$ / barrel
Dec. 31, 2022
$ / bbl
Dec. 31, 2021
$ / MMBTU
Dec. 31, 2021
$ / barrel
Dec. 31, 2021
$ / bbl
Natural Gas                  
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]                  
Average sales price (in dollars per unit) 2.64     6.36     3.60    
Oil                  
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]                  
Average sales price (in dollars per unit)   78.22 78.22   93.67 93.67   66.56 66.56
NGL                  
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]                  
Average sales price (in dollars per unit)   21.38 21.38   34.35 34.35   28.65 28.65
v3.24.0.1
Organization and Summary of Significant Accounting Policies (Composition of Net Unevaluated Costs Excluded from Amortization) (Details) - USD ($)
$ in Millions
 12 Months Ended 204 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost [Abstract]        
Property acquisition costs $ 63 $ 86 $ 559 $ 1,005
Exploration and development costs 24 9 8 18
Capitalized interest 115 91 75 22
Net unevaluated costs excluded from amortization 202 186 $ 642 $ 1,045
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]        
Property acquisition costs 1,713      
Exploration and development costs 59      
Capitalized interest 303      
Net unevaluated costs excluded from amortization, cumulative $ 2,075 $ 2,217    
v3.24.0.1
Organization and Summary of Significant Accounting Policies (Summary of Other Property and Equipment) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Property, Plant and Equipment [Line Items]    
Oil and gas property, full cost method, gross $ 37,772 $ 35,763
Less: Accumulated depreciation and impairment (394) (354)
Total 172 173
Water facilities    
Property, Plant and Equipment [Line Items]    
Oil and gas property, full cost method, gross 252 238
Gathering systems    
Property, Plant and Equipment [Line Items]    
Oil and gas property, full cost method, gross 60 56
Technology infrastructure    
Property, Plant and Equipment [Line Items]    
Oil and gas property, full cost method, gross $ 146 135
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 $ 35 31
Land, buildings and leasehold improvements    
Property, Plant and Equipment [Line Items]    
Oil and gas property, full cost method, gross 16 16
Other    
Property, Plant and Equipment [Line Items]    
Oil and gas property, full cost method, gross $ 57 $ 51
Minimum | Water facilities    
Property, Plant and Equipment [Line Items]    
Long lived assets, useful life 3 years  
Minimum | Gathering systems    
Property, Plant and Equipment [Line Items]    
Long lived assets, useful life 15 years  
Minimum | Technology infrastructure    
Property, Plant and Equipment [Line Items]    
Long lived assets, useful life 3 years  
Minimum | Land, buildings and leasehold improvements    
Property, Plant and Equipment [Line Items]    
Long lived assets, useful life 5 years  
Maximum | Water facilities    
Property, Plant and Equipment [Line Items]    
Long lived assets, useful life 10 years  
Maximum | Gathering systems    
Property, Plant and Equipment [Line Items]    
Long lived assets, useful life 25 years  
Maximum | Technology infrastructure    
Property, Plant and Equipment [Line Items]    
Long lived assets, useful life 10 years  
Maximum | Land, buildings and leasehold improvements    
Property, Plant and Equipment [Line Items]    
Long lived assets, useful life 30 years  
v3.24.0.1
Organization and Summary of Significant Accounting Policies (Schedule of Earnings Per Share) (Details) - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Earnings Per Share [Line Items]      
Net income (loss) $ 1,557 $ 1,849 $ (25)
Number of common shares:      
Weighted average outstanding (in shares) 1,100,980,199 1,110,564,839 789,657,776
Weighted average and potential dilutive outstanding (in shares) 1,103,406,255 1,113,184,254 789,657,776
Basic (in dollars per share) $ 1.41 $ 1.67 $ (0.03)
Diluted (in dollars per share) $ 1.41 $ 1.66 $ (0.03)
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) 862,434 763,067 0
Restricted units      
Number of common shares:      
Effect of share-based compensation (in shares) 1,431,754 1,500,815 0
Performance units      
Number of common shares:      
Effect of share-based compensation (in shares) 131,868 355,533 0
v3.24.0.1
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, 2023
Dec. 31, 2022
Dec. 31, 2021
Antidilutive Securities Excluded from Computation of Earnings Per Share      
Antidilutive securities excluded from computation of earnings per share (in shares) 1,089,132 2,512,028 8,937,810
Unexercised stock options      
Antidilutive Securities Excluded from Computation of Earnings Per Share      
Antidilutive securities excluded from computation of earnings per share (in shares) 831,525 2,265,589 3,683,363
Unvested share-based payment      
Antidilutive Securities Excluded from Computation of Earnings Per Share      
Antidilutive securities excluded from computation of earnings per share (in shares) 46,101 53,924 832,989
Restricted units      
Antidilutive Securities Excluded from Computation of Earnings Per Share      
Antidilutive securities excluded from computation of earnings per share (in shares) 211,506 192,515 2,226,981
Performance units      
Antidilutive Securities Excluded from Computation of Earnings Per Share      
Antidilutive securities excluded from computation of earnings per share (in shares) 0 0 2,194,477
v3.24.0.1
Organization and Summary of Significant Accounting Policies (Schedule of Supplemental Disclosures of Cash Flow Information) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Line Items]      
Cash paid during the year for interest, net of amounts capitalized $ 140 $ 161 $ 106
Cash paid during the year for income taxes 13 41 0
Non-cash investing activities (39) 94 3,690
Non-cash financing activities 0 $ 0 $ 2,051
Indigo Merger      
Organization, Consolidation and Presentation of Financial Statements [Line Items]      
Non-cash investing activities 3,045    
GEPH Merger      
Organization, Consolidation and Presentation of Financial Statements [Line Items]      
Non-cash investing activities $ 581    
v3.24.0.1
Acquisitions - (Acquisition Narrative) (Details) - USD ($)
 4 Months Ended 12 Months Ended
Dec. 31, 2021
Sep. 01, 2021
Dec. 31, 2021
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Nov. 30, 2021
Business Acquisition [Line Items]              
Cash consideration       $ 0 $ 0 $ 1,642,000,000  
Long-term debt       3,947,000,000 $ 4,392,000,000    
Obligation under transportation agreements       9,346,000,000      
Indigo Agreement              
Business Acquisition [Line Items]              
Obligation under transportation agreements   $ 34,000,000   24,000,000      
Liability for the estimated future payments   17,000,000   14,000,000      
Purchase or volume commitments with gathering fresh water              
Business Acquisition [Line Items]              
Obligation under transportation agreements   $ 81,000,000   $ 3,000,000      
5.375% Senior Notes due February 2029 | Senior Notes              
Business Acquisition [Line Items]              
Stated interest rate   5.375%   5.375% 5.375%    
Long-term debt   $ 700,000,000         $ 700,000,000
8.375% Senior Notes due September 2028 | Senior Notes              
Business Acquisition [Line Items]              
Stated interest rate       8.375% 8.375%    
GEPH Merger              
Business Acquisition [Line Items]              
Cash consideration $ 1,263,000,000            
Shares of Southwestern common stock issued in respect of outstanding common stock and stock-based awards (in shares) 99,337,748            
Business acquisition, equity interest issued or issuable, value assigned $ 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 oil and gas properties 1,783,000,000   1,783,000,000     1,783,000,000  
Unevaluated oil and gas 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  
Indigo Merger              
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          
Business acquisition, equity interest issued or issuable, value assigned   $ 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 oil and gas properties   2,724,000,000          
Unevaluated oil and gas properties   690,000,000          
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          
Indigo Merger | 5.375% Senior Notes due February 2029 | Senior Notes              
Business Acquisition [Line Items]              
Senior note assumed in merger agreement   $ 700,000,000          
Stated interest rate   5.375%          
v3.24.0.1
Acquisitions - (Schedule of Consideration Paid to Equity Holders of GEPH) (Details) - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Business Acquisition, Equity Interests Issued or Issuable [Line Items]        
Cash consideration   $ 0 $ 0 $ 1,642
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      
NYSE closing price per share of Southwestern common shares (in dollars per share) $ 4.66     $ 4.66
Business acquisition, equity interest issued or issuable, value assigned $ 463     $ 463
Cash consideration 1,263      
Total consideration 1,726      
Customary post-close cash consideration, adjustment $ (6)      
v3.24.0.1
Acquisitions - (Schedule of the Allocation of Purchase Price of GEPH) (Details) - GEPH Merger - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2023
Dec. 31, 2022
Consideration:      
Total consideration $ 1,726    
Fair Value of Assets Acquired:      
Cash and cash equivalents 11    
Accounts receivable 180    
Other current assets 1    
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 2,095    
Fair Value of Liabilities Assumed:      
Accounts payable 176    
Other current liabilities 1    
Derivative liabilities 75    
Revolving credit facility 81    
Asset retirement obligations 24    
Other noncurrent liabilities 12    
Total liabilities assumed 369    
Net Assets Acquired and Liabilities Assumed $ 1,726    
Business combination, provisional information, initial accounting incomplete, adjustment, accounts receivable   $ 9  
Business combination, provisional information, initial accounting incomplete, adjustment, other current asset   (2)  
Business combination, provisional information, initial accounting incomplete, adjustment, account payable   $ 6  
Business combination, provisional information, initial accounting incomplete, adjustment, other noncurrent liability     $ 7
v3.24.0.1
Acquisitions - (Schedule of Consideration Paid to Equity Holders of Indigo (Details) - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended
Sep. 01, 2021
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Business Acquisition, Equity Interests Issued or Issuable [Line Items]        
Cash consideration   $ 0 $ 0 $ 1,642
Indigo 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) 337,827,171      
NYSE closing price per share of Southwestern common shares (in dollars per share) $ 4.70      
Business acquisition, equity interest issued or issuable, value assigned $ 1,588      
Cash consideration 373      
Total consideration $ 1,961      
v3.24.0.1
Acquisitions - (Schedule of the Allocation of Purchase Price of Indigo) (Details) - Indigo Merger - USD ($)
$ in Millions
 12 Months Ended
Sep. 01, 2021
Dec. 31, 2023
Consideration:    
Total consideration $ 1,961  
Fair Value of Assets Acquired:    
Cash and cash equivalents 55  
Accounts receivable 193  
Other current assets 2  
Commodity derivative assets 2  
Evaluated oil and gas properties 2,724  
Unevaluated oil and gas properties 690  
Other property, plant and equipment 4  
Other long-term assets 27  
Total assets acquired 3,697  
Fair Value of Liabilities Assumed:    
Accounts payable 285  
Other current liabilities 55  
Derivative liabilities 501  
Revolving credit facility 95  
Senior unsecured notes 726  
Asset retirement obligations 8  
Other noncurrent liabilities 66  
Total liabilities assumed 1,736  
Net Assets Acquired and Liabilities Assumed 1,961  
Purchase price adjustment $ 6  
Business combination, provisional information, initial accounting incomplete, adjustment, accounts receivable   $ 1
Business combination, provisional information, initial accounting incomplete, adjustment, account payable   11
Business combination, provisional information, initial accounting incomplete, adjustment, other noncurrent liability   $ 4
v3.24.0.1
Acquisitions - (Schedule of Pro Forma) (Details)
$ / shares in Units, $ in Millions
 12 Months Ended
Dec. 31, 2022
USD ($)
$ / shares
Business Combination and Asset Acquisition [Abstract]  
Revenues | $ $ 8,301
Net income (loss) attributable to common stock | $ $ (354)
Net income (loss) attributable to common stock per share – basic (in dollars per share) | $ / shares $ (0.32)
Net income (loss) attributable to common stock per share – diluted (in dollars per share) | $ / shares $ (0.32)
v3.24.0.1
Acquisitions - (Schedule of Merger Related Costs) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Business Acquisition [Line Items]      
Transition Services   $ 18 $ 0
Professional fees (bank, legal, consulting)   1 47
Representation & warranty insurance   0 11
Contract buyouts, terminations and transfers   3 8
Due diligence and environmental   2 4
Employee-related   1 3
Other   2 3
Merger-related expenses $ 0 27 76
Indigo Merger      
Business Acquisition [Line Items]      
Transition Services   0 0
Professional fees (bank, legal, consulting)   0 27
Representation & warranty insurance   0 4
Contract buyouts, terminations and transfers   1 7
Due diligence and environmental   1 3
Employee-related   0 2
Other   0 2
Merger-related expenses   2 45
GEPH Merger      
Business Acquisition [Line Items]      
Transition Services   18 0
Professional fees (bank, legal, consulting)   1 19
Representation & warranty insurance   0 7
Contract buyouts, terminations and transfers   2 1
Due diligence and environmental   1 1
Employee-related   1 0
Other   2 0
Merger-related expenses   $ 25 28
Other      
Business Acquisition [Line Items]      
Transition Services     0
Professional fees (bank, legal, consulting)     1
Representation & warranty insurance     0
Contract buyouts, terminations and transfers     0
Due diligence and environmental     0
Employee-related     1
Other     1
Merger-related expenses     $ 3
v3.24.0.1
Restructuring Charges (Summary of Restructuring Charges) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Restructuring Cost and Reserve [Line Items]    
Severance costs $ 1 $ 3
Workforce Reduction    
Restructuring Cost and Reserve [Line Items]    
Severance costs   $ 7
v3.24.0.1
Leases (Narrative) (Details)
$ in Millions
Dec. 31, 2023
USD ($)
Leases [Abstract]  
Operating lease not yet commenced $ 4
v3.24.0.1
Leases (Components of Lease Costs) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Components of lease costs:      
Operating lease cost $ 62 $ 63 $ 54
Short-term lease cost 103 93 15
Variable lease cost 3 3 3
Total lease cost $ 168 $ 159 $ 72
v3.24.0.1
Leases (Supplemental Information) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Cash paid for amounts included in the measurement of lease liabilities:      
Operating cash flows from operating leases $ 61 $ 62 $ 53
Right-of-use assets obtained in exchange for operating liabilities:      
Operating leases 27 43 $ 73
Right-of-use asset balance:      
Operating leases 154 177  
Lease liability balance:      
Current operating leases 44 42  
Long-term operating leases 107 133  
Total operating leases $ 151 $ 175  
Operating lease (years) 4 years 1 month 6 days 4 years 10 months 24 days  
Operating lease (Percent) 7.50% 7.32%  
v3.24.0.1
Leases (Maturity Analysis) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Maturities of operating leases (ASC 842):    
2024 $ 53  
2025 39  
2026 33  
2027 29  
2028 14  
Thereafter 6  
Total undiscounted lease liability 174  
Imputed interest (23)  
Total discounted lease liability $ 151 $ 175
v3.24.0.1
Revenue Recognition (Narrative) (Details) - USD ($)
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Disaggregation of Revenue [Line Items]    
Contract asset associated with revenues from contracts with customers $ 0 $ 0
Contract liability associated with revenues from contracts with customers $ 0 $ 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  
v3.24.0.1
Revenue Recognition (Disaggregation of Revenue by Segment) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Disaggregation of Revenue [Line Items]      
Total operating revenues $ 6,522 $ 15,002 $ 6,667
Exploration and Production      
Disaggregation of Revenue [Line Items]      
Total operating revenues 4,167 10,583 4,701
Marketing      
Disaggregation of Revenue [Line Items]      
Total operating revenues 2,355 4,419 1,966
Operating Segments      
Disaggregation of Revenue [Line Items]      
Total operating revenues 6,522    
Operating Segments | Exploration and Production      
Disaggregation of Revenue [Line Items]      
Total operating revenues 4,109 10,577 4,640
Operating Segments | Marketing      
Disaggregation of Revenue [Line Items]      
Total operating revenues 6,277 14,521 6,189
Intersegment Revenues      
Disaggregation of Revenue [Line Items]      
Total operating revenues 3,864 10,096 4,162
Intersegment Revenues | Exploration and Production      
Disaggregation of Revenue [Line Items]      
Total operating revenues (58) (6) (61)
Intersegment Revenues | Marketing      
Disaggregation of Revenue [Line Items]      
Total operating revenues 3,922 10,102 4,223
Gas sales      
Disaggregation of Revenue [Line Items]      
Total operating revenues 3,089 9,101 3,412
Gas sales | Operating Segments | Exploration and Production      
Disaggregation of Revenue [Line Items]      
Total operating revenues 3,036 9,100 3,358
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 (53) (1) (54)
Oil sales      
Disaggregation of Revenue [Line Items]      
Total operating revenues 379 439 394
Oil sales | Operating Segments | Exploration and Production      
Disaggregation of Revenue [Line Items]      
Total operating revenues 374 434 389
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) (5) (5)
NGL sales      
Disaggregation of Revenue [Line Items]      
Total operating revenues 702 1,046 890
NGL sales | Operating Segments | Exploration and Production      
Disaggregation of Revenue [Line Items]      
Total operating revenues 702 1,046 888
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 0 0 (2)
Marketing      
Disaggregation of Revenue [Line Items]      
Total operating revenues 2,355 4,419 1,963
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 6,277 14,521 6,186
Marketing | Intersegment Revenues      
Disaggregation of Revenue [Line Items]      
Total operating revenues 3,922 10,102 4,223
Marketing | Intersegment Revenues | Marketing      
Disaggregation of Revenue [Line Items]      
Total operating revenues (3,900) (10,100) (4,200)
Other      
Disaggregation of Revenue [Line Items]      
Total operating revenues (3) (3) 8
Other | Operating Segments | Exploration and Production      
Disaggregation of Revenue [Line Items]      
Total operating revenues (3) (3) 5
Other | Operating Segments | Marketing      
Disaggregation of Revenue [Line Items]      
Total operating revenues 0 0 3
Other | Intersegment Revenues      
Disaggregation of Revenue [Line Items]      
Total operating revenues $ 0 $ 0 $ 0
v3.24.0.1
Revenue Recognition (Disaggregation of Revenue on Geographic Basis) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Disaggregation of Revenue [Line Items]      
Total operating revenues $ 6,522 $ 15,002 $ 6,667
Operating Segments      
Disaggregation of Revenue [Line Items]      
Total operating revenues 6,522    
Exploration and Production      
Disaggregation of Revenue [Line Items]      
Total operating revenues 4,167 10,583 4,701
Exploration and Production | Operating Segments      
Disaggregation of Revenue [Line Items]      
Total operating revenues 4,109 10,577 4,640
Appalachia | Exploration and Production | Operating Segments      
Disaggregation of Revenue [Line Items]      
Total operating revenues 2,543 6,314 3,955
Haynesville | Exploration and Production | Operating Segments      
Disaggregation of Revenue [Line Items]      
Total operating revenues 1,566 4,263 682
Other | Exploration and Production | Operating Segments      
Disaggregation of Revenue [Line Items]      
Total operating revenues $ 0 $ 0 $ 3
v3.24.0.1
Revenue Recognition (Reconciliation of Accounts Receivable) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Revenue from Contract with Customer [Abstract]    
Receivables from contracts with customers $ 622 $ 1,313
Other accounts receivable 58 88
Total accounts receivable $ 680 $ 1,401
v3.24.0.1
Derivatives and Risk Management (Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value) (Details)
bbl in Thousands, Mcf in Thousands, $ in Millions
 12 Months Ended
Dec. 31, 2023
USD ($)
$ / bbl
$ / MMBTU
Mcf
bbl
Financial protection on production - 2023 | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 660,000
Fair Value $ 505
Financial protection on production - 2023 | Not Designated as Hedging Instrument | Oil  
Derivative [Line Items]  
Volume | bbl 2,175
Fair Value $ 1
Fixed price swaps - 2023 | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 528,000
Average price per MMBtu and Bbls | $ / MMBTU 3.54
Fair Value $ 448
Fixed price swaps - 2023 | Not Designated as Hedging Instrument | Oil  
Derivative [Line Items]  
Volume | bbl 1,571
Average price per MMBtu and Bbls | $ / bbl 71.06
Fair Value $ (1)
Fixed price swaps - 2023 | Not Designated as Hedging Instrument | Ethane  
Derivative [Line Items]  
Volume | bbl 4,897
Average price per MMBtu and Bbls | $ / bbl 10.61
Fair Value $ 9
Fixed price swaps - 2023 | Not Designated as Hedging Instrument | Propane  
Derivative [Line Items]  
Volume | bbl 4,008
Average price per MMBtu and Bbls | $ / bbl 31.38
Fair Value $ 11
Fixed price swaps - 2023 | Not Designated as Hedging Instrument | Normal Butane  
Derivative [Line Items]  
Volume | bbl 329
Average price per MMBtu and Bbls | $ / bbl 40.74
Fair Value $ 1
Fixed price swaps - 2023 | Not Designated as Hedging Instrument | Natural Gasoline  
Derivative [Line Items]  
Volume | bbl 329
Average price per MMBtu and Bbls | $ / bbl 64.37
Fair Value $ 2
Two-way costless collars - 2023 | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 44,000
Floor price per MMBtu and Bbls | $ / MMBTU 3.07
Cap price per MMBtu and Bbls | $ / MMBTU 3.53
Fair Value $ 22
Two-way costless collars - 2023 | Not Designated as Hedging Instrument | Oil  
Derivative [Line Items]  
Volume | bbl 512
Cap price per MMBtu and Bbls | $ / bbl 85.63
Fair Value $ 2
Two-way costless collars - 2023 | Not Designated as Hedging Instrument | Oil | Purchased  
Derivative [Line Items]  
Floor price per MMBtu and Bbls | $ / bbl 70.00
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 88,000
Cap price per MMBtu and Bbls | $ / MMBTU 4.09
Fair Value $ 35
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Natural Gas | Sold  
Derivative [Line Items]  
Floor price per MMBtu and Bbls | $ / MMBTU 2.47
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Natural Gas | Purchased  
Derivative [Line Items]  
Floor price per MMBtu and Bbls | $ / MMBTU 3.20
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Oil  
Derivative [Line Items]  
Volume | bbl 92
Cap price per MMBtu and Bbls | $ / bbl 93.10
Fair Value $ 0
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Oil | Sold  
Derivative [Line Items]  
Floor price per MMBtu and Bbls | $ / bbl 65.00
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Oil | Purchased  
Derivative [Line Items]  
Floor price per MMBtu and Bbls | $ / bbl 75.00
Financial protection on production - 2024 | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 234,000
Fair Value $ 87
Financial protection on production - 2024 | Not Designated as Hedging Instrument | Oil  
Derivative [Line Items]  
Volume | bbl 1,043
Fair Value $ 2
Fixed Price Swaps - 2024 | Not Designated as Hedging Instrument | Oil  
Derivative [Line Items]  
Volume | bbl 41
Average price per MMBtu and Bbls | $ / bbl 77.66
Fair Value $ 0
Fixed Price Swaps - 2024 | Not Designated as Hedging Instrument | Propane  
Derivative [Line Items]  
Volume | bbl 63
Average price per MMBtu and Bbls | $ / bbl 26.46
Fair Value $ 0
Two-way Costless-collars - 2024 | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 73,000
Floor price per MMBtu and Bbls | $ / MMBTU 3.50
Cap price per MMBtu and Bbls | $ / MMBTU 5.40
Fair Value $ 31
Three-way Costless-collars - 2024 | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 161,000
Cap price per MMBtu and Bbls | $ / MMBTU 5.88
Fair Value $ 56
Three-way Costless-collars - 2024 | Not Designated as Hedging Instrument | Natural Gas | Sold  
Derivative [Line Items]  
Floor price per MMBtu and Bbls | $ / MMBTU 2.59
Three-way Costless-collars - 2024 | Not Designated as Hedging Instrument | Natural Gas | Purchased  
Derivative [Line Items]  
Floor price per MMBtu and Bbls | $ / MMBTU 3.66
Three-way Costless-collars - 2024 | Not Designated as Hedging Instrument | Oil  
Derivative [Line Items]  
Volume | bbl 1,002
Average price per MMBtu and Bbls | $ / bbl 0
Cap price per MMBtu and Bbls | $ / bbl 94.64
Fair Value $ 2
Three-way Costless-collars - 2024 | Not Designated as Hedging Instrument | Oil | Sold  
Derivative [Line Items]  
Floor price per MMBtu and Bbls | $ / bbl 60.00
Three-way Costless-collars - 2024 | Not Designated as Hedging Instrument | Oil | Purchased  
Derivative [Line Items]  
Floor price per MMBtu and Bbls | $ / bbl 70.00
Basis swaps | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 91,000
Fair Value $ 12
Basis Swaps - 2023 | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 82,000
Basis Differential | $ / MMBTU (0.72)
Fair Value $ 8
Basis Swaps - 2024 | Not Designated as Hedging Instrument | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 9,000
Basis Differential | $ / MMBTU (0.64)
Fair Value $ 4
Call options | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 228,000
Fair Value $ (18)
Call Option - 2023 | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 82,000
Cap price per MMBtu and Bbls | $ / MMBTU 6.56
Fair Value $ (1)
Call Option - 2024 | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 73,000
Cap price per MMBtu and Bbls | $ / MMBTU 7.00
Fair Value $ (6)
Call Option - 2024 | Natural Gas  
Derivative [Line Items]  
Volume | Mcf 73,000
Cap price per MMBtu and Bbls | $ / MMBTU 7.00
Fair Value $ (11)
v3.24.0.1
Derivatives and Risk Management (Narrative) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Not Designated as Hedging Instrument    
Derivative [Line Items]    
Impact of non-performance risk on fair value of the net derivative liability position $ 2 $ (3)
Commodity Contract    
Derivative [Line Items]    
Derivative asset (liability) $ 610  
v3.24.0.1
Derivatives and Risk Management (Balance Sheet Classification of Derivative Financial Instruments) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Derivatives, Fair Value [Line Items]    
Net current derivative assets (liabilities) $ 536 $ (1,174)
Net long-term derivative assets (liabilities) 76 (307)
Non-performance risk adjustment (2) 3
Total 610 (1,478)
Not Designated as Hedging Instrument    
Derivatives, Fair Value [Line Items]    
Derivative assets 791 218
Derivative liabilities 179 1,699
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 466 0
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 0 28
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 18 581
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 0 281
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 36 47
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Other long-term assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 46 18
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 14 235
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Other long-term liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 15 56
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 62 18
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 116 3
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 27 311
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 60 20
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 14 64
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Other long-term assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 4 17
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 6 69
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Other long-term liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 0 1
Natural Gas | Not Designated as Hedging Instrument | Call options | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 1 70
Natural Gas | Not Designated as Hedging Instrument | Call options | Other long-term liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 17 18
Natural Gas | Not Designated as Hedging Instrument | Put options | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 8 0
Natural Gas | Not Designated as Hedging Instrument | Put options | Other long-term assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 0 4
Natural Gas | Not Designated as Hedging Instrument | Put options | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 8 0
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 1 0
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 0 1
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 2 20
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 0 4
Oil | Not Designated as Hedging Instrument | Two-way costless collars | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 3 0
Oil | Not Designated as Hedging Instrument | Two-way costless collars | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 1 0
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 1 1
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 10 0
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 1 31
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 8 0
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 9 4
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 0 1
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 0 1
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 12 9
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 0 1
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities 1 0
Normal Butane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 1 1
Natural Gasoline | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets    
Derivatives, Fair Value [Line Items]    
Derivative assets 2 1
Natural Gasoline | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities    
Derivatives, Fair Value [Line Items]    
Derivative liabilities $ 0 $ 1
v3.24.0.1
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, 2023
Dec. 31, 2022
Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings $ 2,093 $ 24  
Total gain (loss) on settled derivatives 345 (5,283)  
Non-performance risk adjustment (5) 0  
Total gain (loss) on derivatives 2,433 (5,259) $ (2,436)
Fixed price swaps | Natural Gas      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 1,281 (166)  
Total gain (loss) on settled derivatives 300 (2,918)  
Fixed price swaps | Oil      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 22 46  
Total gain (loss) on settled derivatives (27) (129)  
Fixed price swaps | Ethane      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 5 12  
Total gain (loss) on settled derivatives 6 (49)  
Fixed price swaps | Propane      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 1 87  
Total gain (loss) on settled derivatives 26 (100)  
Fixed price swaps | Normal Butane      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 0 27  
Total gain (loss) on settled derivatives 3 (35)  
Fixed price swaps | Natural Gasoline      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 2 34  
Total gain (loss) on settled derivatives 1 (49)  
Fixed price swaps | Natural gas storage      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 0 1  
Total gain (loss) on settled derivatives 0 (3)  
Two-way costless collars | Natural Gas      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 279 (116)  
Total gain (loss) on settled derivatives 48 (448)  
Two-way costless collars | Oil      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 2 0  
Total gain (loss) on settled derivatives (1) 0  
Two-way costless collars | Ethane      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 0 1  
Total gain (loss) on settled derivatives 0 (1)  
Three-way costless collars | Natural Gas      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 402 117  
Total gain (loss) on settled derivatives (19) (1,319)  
Three-way costless collars | Oil      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 32 11  
Total gain (loss) on settled derivatives (27) (51)  
Three-way costless collars | Propane      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 0 4  
Total gain (loss) on settled derivatives 0 (5)  
Basis swaps | Natural Gas      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 1 (57)  
Total gain (loss) on settled derivatives 43 128  
Call options | Natural Gas      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 70 21  
Call options | Natural Gas | Purchased      
Derivative Instruments, Gain (Loss) [Line Items]      
Total gain (loss) on settled derivatives (8) (304)  
Put options | Natural Gas      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings (4) 4  
Interest rate swaps      
Derivative Instruments, Gain (Loss) [Line Items]      
Unsettled Gain (Loss) on Derivatives Recognized in Earnings 0 (2)  
Index Swap | Natural Gas      
Derivative Instruments, Gain (Loss) [Line Items]      
Total gain (loss) on settled derivatives 0 (1)  
Purchased fixed price swaps | Natural gas storage | Purchased      
Derivative Instruments, Gain (Loss) [Line Items]      
Total gain (loss) on settled derivatives $ 0 $ 1  
v3.24.0.1
Reclassifications from Accumulated Other Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
AOCI Attributable to Parent, Net of Tax [Roll Forward]      
Beginning balance $ 4,324 $ 2,547 $ 497
Other comprehensive income before reclassifications 7    
Amounts reclassified from other comprehensive income (16)    
Net current-period other comprehensive loss (9) 31 13
Ending balance 5,888 4,324 2,547
Accumulated Other Comprehensive Income (Loss)      
AOCI Attributable to Parent, Net of Tax [Roll Forward]      
Beginning balance 6 (25) (38)
Net current-period other comprehensive loss (9) 31 13
Ending balance (3) 6 $ (25)
Pension and Other Postretirement      
AOCI Attributable to Parent, Net of Tax [Roll Forward]      
Beginning balance 20    
Other comprehensive income before reclassifications 7    
Amounts reclassified from other comprehensive income (16)    
Net current-period other comprehensive loss (9)    
Ending balance 11 20  
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 loss 0    
Ending balance $ (14) $ (14)  
v3.24.0.1
Reclassifications from Accumulated Other Comprehensive Income (Loss) (Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]      
Other Income, Net $ (2) $ (3) $ (5)
Provision for income taxes (257) 51 0
Net income (1,557) $ (1,849) $ 25
Reclassified from Accumulated Other Comprehensive Income      
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]      
Net income (16)    
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, Net (2)    
Pension and Other Postretirement | Reclassified from Accumulated Other Comprehensive Income      
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]      
Provision for income taxes $ (14)    
v3.24.0.1
Fair Value Measurements (Carrying Amount and Estimated Fair Values of Financial Instruments) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative instruments, net $ 610 $ (1,478)
Carrying Amount    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Cash and cash equivalents 21 50
2022 revolving credit facility due April 2027 220 250
Derivative instruments, net 610 (1,478)
Fair Value    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Cash and cash equivalents 21 50
2022 revolving credit facility due April 2027 220 250
Derivative instruments, net 610 (1,478)
Senior Notes | Carrying Amount    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Senior notes 3,743 4,164
Senior Notes | Fair Value    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Senior notes $ 3,626 $ 3,847
v3.24.0.1
Fair Value Measurements (Narrative) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Not Designated as Hedging Instrument    
Debt Instrument [Line Items]    
Impact of non-performance risk on fair value of the net derivative liability position $ 2 $ (3)
v3.24.0.1
Fair Value Measurements (Summary of Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total $ 612 $ (1,481)
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 2 (3)
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 612 (1,481)
Significant Unobservable Inputs (Level 3)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total 0 0
Fixed price swaps    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 491 46
Derivative liabilities (21) (888)
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 491 46
Derivative liabilities (21) (888)
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 85 65
Derivative liabilities (30) (291)
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 85 65
Derivative liabilities (30) (291)
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 189 22
Derivative liabilities (96) (362)
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 189 22
Derivative liabilities (96) (362)
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 18 81
Derivative liabilities (6) (70)
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 18 81
Derivative liabilities (6) (70)
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   4
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   4
Interest rate swaps | Significant Unobservable Inputs (Level 3)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets   0
Purchase Put - Natural Gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 8  
Purchase Put - Natural Gas | Quoted Prices in Active Markets for Identical Assets (Level 1)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 0  
Purchase Put - Natural Gas | Significant Observable Inputs (Level 2)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative assets 8  
Purchase Put - Natural Gas | 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 liabilities (18) (88)
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 liabilities 0 0
Call options | Significant Observable Inputs (Level 2)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative liabilities (18) (88)
Call options | Significant Unobservable Inputs (Level 3)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative liabilities 0 $ 0
Put options    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative liabilities (8)  
Put options | Quoted Prices in Active Markets for Identical Assets (Level 1)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative liabilities 0  
Put options | Significant Observable Inputs (Level 2)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative liabilities (8)  
Put options | Significant Unobservable Inputs (Level 3)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative liabilities $ 0  
v3.24.0.1
Debt (Components of Debt) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Feb. 26, 2023
Dec. 31, 2022
Dec. 30, 2022
May 31, 2022
Jan. 06, 2022
Nov. 30, 2021
Sep. 01, 2021
Aug. 30, 2021
Apr. 07, 2020
Jul. 31, 2018
Jan. 31, 2015
Debt Instrument [Line Items]                        
Total $ 3,963   $ 4,414                  
Unamortized Issuance Expense (34)   (44)                  
Unamortized Debt Premium / Discount 18   22                  
Long-term debt 3,947   4,392                  
Total 3,947   4,392                  
Debt issuance costs, line of credit $ 15   $ 19                  
Line of Credit | 2022 Revolving Credit Facility                        
Debt Instrument [Line Items]                        
Credit facility, variable interest rate 7.20%   6.15%                  
Line of Credit | 2022 Revolving Credit Facility | Revolving Credit Facility                        
Debt Instrument [Line Items]                        
Debt instrument, excluding current maturities, gross $ 220   $ 250 $ 250                
Unamortized Issuance Expense 0   0                  
Unamortized Debt Premium / Discount 0   0                  
Long-term debt 220   250                  
Senior Notes | 4.95% Senior Notes due January 2025                        
Debt Instrument [Line Items]                        
Debt instrument, excluding current maturities, gross 389   389                  
Unamortized Issuance Expense 0   (1)                  
Unamortized Debt Premium / Discount 0   0                  
Long-term debt $ 389   $ 388                  
Stated interest rate 4.95%   4.95%     5.95%     4.95% 6.45% 6.20% 4.95%
Senior Notes | 4.95% Senior Notes due January 2025 | Minimum                        
Debt Instrument [Line Items]                        
Stated interest rate         5.95%              
Senior Notes | 4.95% Senior Notes due January 2025 | Maximum                        
Debt Instrument [Line Items]                        
Stated interest rate         5.70%              
Senior Notes | 7.75% Senior Notes due October 2027                        
Debt Instrument [Line Items]                        
Debt instrument, excluding current maturities, gross     $ 421                  
Unamortized Issuance Expense     (3)                  
Unamortized Debt Premium / Discount     0                  
Long-term debt     $ 418                  
Stated interest rate   7.75% 7.75%                  
Senior Notes | 8.375% Senior Notes due September 2028                        
Debt Instrument [Line Items]                        
Debt instrument, excluding current maturities, gross $ 304   $ 304                  
Unamortized Issuance Expense (3)   (3)                  
Unamortized Debt Premium / Discount 0   0                  
Long-term debt $ 301   $ 301                  
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   $ 700                  
Unamortized Issuance Expense (5)   (5)                  
Unamortized Debt Premium / Discount 18   22                  
Long-term debt $ 713   $ 717                  
Total             $ 700 $ 700        
Stated interest rate 5.375%   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   $ 1,200                  
Unamortized Issuance Expense (13)   (16)                  
Unamortized Debt Premium / Discount 0   0                  
Long-term debt $ 1,187   $ 1,184                  
Stated interest rate 5.375%   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   $ 1,150                  
Unamortized Issuance Expense (13)   (16)                  
Unamortized Debt Premium / Discount 0   0                  
Long-term debt $ 1,137   $ 1,134                  
Stated interest rate 4.75%   4.75%                  
v3.24.0.1
Debt (Schedule of Debt Maturities) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Long-term Debt, Fiscal Year Maturity [Abstract]    
2024 $ 0  
2025 389  
2026 0  
2027 220  
2028 304  
Thereafter 3,050  
Total $ 3,963 $ 4,414
v3.24.0.1
Debt (2022 Revolving Credit Facility - Narrative) (Details)
 12 Months Ended
Aug. 04, 2022
USD ($)
Dec. 22, 2021
Dec. 31, 2023
USD ($)
Oct. 04, 2023
USD ($)
Dec. 31, 2022
USD ($)
Dec. 30, 2022
USD ($)
Debt Instrument [Line Items]            
Subsidiary ownership     100.00%      
2022 Revolving Credit Facility | Minimum            
Debt Instrument [Line Items]            
Line of credit facility, unused capacity, commitment fee percentage   0.15%        
2022 Revolving Credit Facility | Maximum            
Debt Instrument [Line Items]            
Line of credit facility, unused capacity, commitment fee percentage   0.275%        
Ratio of indebtedness to net capital   0.65        
2022 Revolving Credit Facility Five-Year Tranche | Minimum            
Debt Instrument [Line Items]            
Line of credit facility, unused capacity, commitment fee percentage 0.375%          
2022 Revolving Credit Facility Five-Year Tranche | Maximum            
Debt Instrument [Line Items]            
Line of credit facility, unused capacity, commitment fee percentage 0.50%          
Revolving Credit Facility | 2022 Revolving Credit Facility | Line of Credit            
Debt Instrument [Line Items]            
Maximum borrowing capacity     $ 3,500,000,000      
Long-term line of credit       $ 3,500,000,000    
Minimum current ratio 1.00          
Leverage ratio, percentage of credit limit 10.00%          
Leverage ratio, amount of credit limit $ 150,000,000          
Letters of credit outstanding     0      
Debt instrument, excluding current maturities, gross     $ 220,000,000   $ 250,000,000 $ 250,000,000
Revolving Credit Facility | 2022 Revolving Credit Facility | Line of Credit | On Or After March 31, 2022            
Debt Instrument [Line Items]            
Leverage ratio 4.00          
Revolving Credit Facility | 2022 Revolving Credit Facility | Line of Credit | Secured Overnight Financing Rate (SOFR)            
Debt Instrument [Line Items]            
Basis points   0.10%        
Debt instrument, discount coverage ratio   9.00%        
Revolving Credit Facility | 2022 Revolving Credit Facility | Line of Credit | Minimum | Secured Overnight Financing Rate (SOFR)            
Debt Instrument [Line Items]            
Basis points   1.25%        
Revolving Credit Facility | 2022 Revolving Credit Facility | Line of Credit | Minimum | Base Rate            
Debt Instrument [Line Items]            
Basis points   0.25%        
Revolving Credit Facility | 2022 Revolving Credit Facility | Line of Credit | Maximum | Secured Overnight Financing Rate (SOFR)            
Debt Instrument [Line Items]            
Basis points   1.875%        
Revolving Credit Facility | 2022 Revolving Credit Facility | Line of Credit | Maximum | Base Rate            
Debt Instrument [Line Items]            
Basis points   0.875%        
Revolving Credit Facility | 2022 Revolving Credit Facility | Long-Term Debt            
Debt Instrument [Line Items]            
Minimum interest coverage ratio (less than)   1.50        
Revolving Credit Facility | 2022 Revolving Credit Facility Five-Year Tranche | Line of Credit            
Debt Instrument [Line Items]            
Line of credit facility, expiration period     5 years      
Long-term line of credit     $ 2,000,000,000 $ 2,000,000,000    
Revolving Credit Facility | 2022 Revolving Credit Facility Five-Year Tranche | Line of Credit | Secured Overnight Financing Rate (SOFR)            
Debt Instrument [Line Items]            
Basis points 0.10%          
Revolving Credit Facility | 2022 Revolving Credit Facility Five-Year Tranche | Line of Credit | Base Rate            
Debt Instrument [Line Items]            
Basis points 1.00%          
Revolving Credit Facility | 2022 Revolving Credit Facility Five-Year Tranche | Line of Credit | Fed Funds Effective Rate Overnight Index Swap Rate            
Debt Instrument [Line Items]            
Basis points 0.50%          
Revolving Credit Facility | 2022 Revolving Credit Facility Five-Year Tranche | Line of Credit | Minimum | Secured Overnight Financing Rate (SOFR)            
Debt Instrument [Line Items]            
Basis points 1.75%          
Revolving Credit Facility | 2022 Revolving Credit Facility Five-Year Tranche | Line of Credit | Minimum | Base Rate            
Debt Instrument [Line Items]            
Basis points 0.75%          
Revolving Credit Facility | 2022 Revolving Credit Facility Five-Year Tranche | Line of Credit | Maximum | Secured Overnight Financing Rate (SOFR)            
Debt Instrument [Line Items]            
Basis points 2.75%          
Revolving Credit Facility | 2022 Revolving Credit Facility Five-Year Tranche | Line of Credit | Maximum | Base Rate            
Debt Instrument [Line Items]            
Basis points 1.75%          
Revolving Credit Facility | 2022 Revolving Credit Facility Short-Term Tranche | Line of Credit            
Debt Instrument [Line Items]            
Line of credit facility, increase (decrease), net $ 500,000,000          
v3.24.0.1
Debt (Term Loan Credit Agreement - Narrative) (Details) - USD ($)
$ in Thousands
 1 Months Ended
Dec. 30, 2022
Dec. 31, 2021
Mar. 31, 2022
Dec. 31, 2023
Dec. 31, 2022
Dec. 22, 2021
Term Loan Due June 2027 | Term Loan            
Debt Instrument [Line Items]            
Secured term loan facility, amount           $ 550,000
Proceeds from Loans   $ 542,000        
Repayments of term loan $ 305,000   $ 1,375      
Debt repurchased face amount 546,000       $ 550,000  
2022 Revolving Credit Facility | Line of Credit | Revolving Credit Facility            
Debt Instrument [Line Items]            
Debt instrument, excluding current maturities, gross $ 250,000     $ 220,000 $ 250,000  
v3.24.0.1
Debt (Senior Notes - Narrative) (Details) - USD ($)
 1 Months Ended 12 Months Ended
Feb. 26, 2023
Dec. 22, 2021
Sep. 01, 2021
Aug. 30, 2021
Jan. 31, 2015
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Dec. 30, 2022
May 31, 2022
Jan. 06, 2022
Nov. 30, 2021
Apr. 07, 2020
Jul. 31, 2018
Debt Instrument [Line Items]                            
Loss on Early Extinguishment of Debt           $ (19,000,000) $ (14,000,000) $ (93,000,000)            
Long-term debt           $ 3,947,000,000 4,392,000,000              
Senior Notes                            
Debt Instrument [Line Items]                            
Debt repurchased face amount             816,000,000              
Loss on Early Extinguishment of Debt   $ (33,000,000)   $ (60,000,000)     (14,000,000)              
Repayments of long-term debt       $ 845,000,000     822,000,000              
Debt instrument, unamortized discount (premium) and debt issuance costs, net             8,000,000              
Debt instrument, purchase accounting, non-cash fair value adjustment     $ 26,000,000                      
Debt instrument, fee amount             $ 6,000,000              
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 | Senior Notes                            
Debt Instrument [Line Items]                            
Senior notes, noncurrent         $ 1,000,000,000                  
Debt Instrument, Interest Rate, Stated Percentage       4.95% 4.95% 4.95% 4.95%       5.95%   6.45% 6.20%
Debt repurchased face amount       $ 167,000,000                    
4.95% Senior Notes due January 2025 | Senior Notes | Maximum                            
Debt Instrument [Line Items]                            
Debt Instrument, Interest Rate, Stated Percentage                   5.70%        
4.10% Senior Notes due March 2022 | Senior Notes                            
Debt Instrument [Line Items]                            
Debt Instrument, Interest Rate, Stated Percentage       4.10%     4.10%              
Debt repurchased face amount       $ 6,000,000     $ 201,000,000              
7.75% Senior Notes due October 2027 | Senior Notes                            
Debt Instrument [Line Items]                            
Debt Instrument, Interest Rate, Stated Percentage       7.50%                    
Debt repurchased face amount       $ 618,000,000                    
7.75% Senior Notes due October 2027 | Senior Notes                            
Debt Instrument [Line Items]                            
Debt Instrument, Interest Rate, Stated Percentage 7.75%           7.75%              
Debt repurchased face amount             $ 19,000,000              
Loss on Early Extinguishment of Debt $ (19,000,000)                          
Debt instrument, redemption price, percentage of principal amount redeemed 103.875%                          
Debt instrument, repurchased face amount, unpaid interest $ 13,000,000                          
Debt instrument, repurchase amount 450,000,000                          
Deferred debt issuance cost, writeoff 3,000,000                          
7.75% Senior Notes due October 2027 | Senior Notes | Funded From Cash On Hand                            
Debt Instrument [Line Items]                            
Repayments of senior debt 316,000,000                          
7.75% Senior Notes due October 2027 | Senior Notes | Funded From Debt Borrowings                            
Debt Instrument [Line Items]                            
Repayments of senior debt $ 134,000,000                          
8.375% Senior Notes due September 2028 | Senior Notes                            
Debt Instrument [Line Items]                            
Debt Instrument, Interest Rate, Stated Percentage           8.375% 8.375%              
Debt repurchased face amount             $ 46,000,000              
5.375% Senior Notes due March 2030 | Senior Notes                            
Debt Instrument [Line Items]                            
Senior notes, noncurrent       $ 1,200,000,000                    
Debt Instrument, Interest Rate, Stated Percentage       5.375%   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]                            
Debt Instrument, Interest Rate, Stated Percentage     5.375%     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 Merger                            
Debt Instrument [Line Items]                            
Debt Instrument, Interest Rate, Stated Percentage     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, noncurrent   1,150,000,000                        
Debt Instrument, Interest Rate, Stated Percentage           4.75% 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                        
Term Loan Due June 2027 | Term Loan                            
Debt Instrument [Line Items]                            
Debt repurchased face amount             $ 550,000,000   $ 546,000,000          
v3.24.0.1
Commitments and Contingencies (Narrative) (Details)
Jun. 12, 2018
individual
defendant
Dec. 31, 2023
USD ($)
lease
Sep. 01, 2021
USD ($)
Commitments And Contingencies [Line Items]      
Obligation under transportation agreements   $ 9,346,000,000  
Guarantee obligations relative to the firms transportation agreements and gathering project and services   808,000,000  
Maturities of operating leases (ASC 842):      
2024   53,000,000  
2025   39,000,000  
2026   33,000,000  
2027   29,000,000  
2028   14,000,000  
Thereafter   6,000,000  
Number of plaintiffs | individual 51    
Number of defendants | defendant 15    
Indemnification liability   0  
Pending regulatory approval and/or construction      
Commitments And Contingencies [Line Items]      
Obligation under transportation agreements   1,015,000,000  
Indigo Agreement      
Commitments And Contingencies [Line Items]      
Obligation under transportation agreements   24,000,000 $ 34,000,000
Liability for the estimated future payments   14,000,000 $ 17,000,000
Pressure Pumping Equipment | Exploration and Production      
Commitments And Contingencies [Line Items]      
Aggregate annual lease payment   9,000,000  
Drilling Rigs | Exploration and Production      
Commitments And Contingencies [Line Items]      
Aggregate annual lease payment   $ 11,000,000  
Number of leases | lease   7  
Office Space, Vehicles And Equipment      
Maturities of operating leases (ASC 842):      
2024   $ 43,000,000  
2025   34,000,000  
2026   30,000,000  
2027   27,000,000  
2028   11,000,000  
Thereafter   6,000,000  
Compression Rentals      
Maturities of operating leases (ASC 842):      
2024   19,000,000  
2025   6,000,000  
2026   2,000,000  
2027   $ 1,000,000  
v3.24.0.1
Commitments and Contingencies (Schedule of Future Obligation under Transportation Agreements) (Details)
$ in Millions
Dec. 31, 2023
USD ($)
Other Commitments [Line Items]  
Total $ 9,346
Less than 1 Year 1,101
1 to 3 Years 2,140
3 to 5 Years 1,955
5 to 8 Years 1,993
More than 8 Years 2,157
Infrastructure currently in service  
Other Commitments [Line Items]  
Total 8,331
Less than 1 Year 1,055
1 to 3 Years 1,983
3 to 5 Years 1,778
5 to 8 Years 1,727
More than 8 Years 1,788
Pending regulatory approval and/or construction  
Other Commitments [Line Items]  
Total 1,015
Less than 1 Year 46
1 to 3 Years 157
3 to 5 Years 177
5 to 8 Years 266
More than 8 Years $ 369
v3.24.0.1
Income Taxes (Provision (Benefit) for Income Taxes) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Current:      
Federal $ (4) $ 47 $ 0
State (1) 4 0
Total Current (5) 51 0
Deferred:      
Federal (192) 0 0
State (60) 0 0
Total Deferred (252) 0 0
Provision (Benefit) for Income Taxes $ (257) $ 51 $ 0
v3.24.0.1
Income Taxes (Narrative) (Details) - USD ($)
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Income Taxes [Line Items]      
Effective tax rate (20.00%) 3.00% 0.00%
Valuation allowance, deferred tax asset, amount $ 512,000,000    
Deferred income tax expense (benefit), tax provision recorded, before offset of release of valuation allowance 269,000,000    
Effective income tax rate reconciliation, change in deferred tax assets valuation allowance, amount 526,000,000 $ 392,000,000 $ (2,000,000)
Change in deferred tax assets valuation allowance, reclassified from OCI, amount 14,000,000    
Operating loss carryforward valuation allowance 52,000,000    
Unrecognized tax benefits that would impact effective tax rate 0    
Statutory depletion carryforward      
Income Taxes [Line Items]      
Tax credit carryforward 13,000,000    
Interest deduction carryforward      
Income Taxes [Line Items]      
Tax credit carryforward 415,000,000    
Exploration Program in Canada      
Income Taxes [Line Items]      
Net operating loss carryforward 29,000,000    
Indigo Merger      
Income Taxes [Line Items]      
Operating loss carryforwards subject to a section 382 limitation 48,000,000    
Other      
Income Taxes [Line Items]      
Operating loss carryforwards subject to a section 382 limitation 1,700,000    
Net operating loss carryforward 856,000,000    
Federal      
Income Taxes [Line Items]      
Income taxes paid 12,000,000 36,000,000 0
Operating loss carryforwards subject to a section 382 limitation 2,000,000,000    
Net operating loss carryforward 4,000,000,000    
Operating loss carryforwards, subject to expiration 3,000,000,000    
Operating loss carryforwards, not subject to expiration 1,000,000,000    
Statel      
Income Taxes [Line Items]      
Income taxes paid $ 1,000,000 $ 5,000,000 $ 0
v3.24.0.1
Income Taxes (Reconciliation of Provision for Income Taxes) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Income Tax Disclosure [Abstract]      
Expected provision (benefit) at federal statutory rate $ 273 $ 400 $ (5)
Increase (decrease) resulting from:      
State income taxes, net of federal income tax effect 18 39 0
Change in valuation allowance (526) (392) 2
Return to accrual (16) 0 0
Federal research and development credit (13) 0 0
Other 7 4 3
Provision (Benefit) for Income Taxes $ (257) $ 51 $ 0
v3.24.0.1
Income Taxes (Components of Deferred Tax Balances) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Deferred tax liabilities:      
Differences between book and tax basis of property $ 255 $ 379  
Derivative activity 137 0  
Right of use lease asset 34 41  
Accrued pension costs 0 1  
Other 3 3  
Total deferred tax liabilities 429 424  
Deferred tax assets:      
Accrued compensation 53 50  
Accrued pension costs 1 0  
Asset retirement obligations 27 24  
Net operating loss carryforward 450 469  
Future lease payments 35 41  
Derivative activity 0 340  
Capital loss carryover 26 27  
Interest carryover 93 41  
Research and development credits 17 0  
Other 17 21  
Total deferred tax assets 719 1,013  
Valuation allowance (52) (589) $ (1,079)
Net deferred tax asset $ 238 $ 0  
v3.24.0.1
Income Taxes (Reconciliation of Changes to the Valuation Allowance) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Deferred Tax Asset, Valuation Allowance [Roll Forward]    
Valuation allowance, beginning balance $ 589 $ 1,079
Return to accrual adjustments (12) (36)
State rate and apportionment changes (13) (66)
Current period deferred activity 0 (388)
Release of valuation allowance (512) 0
Valuation allowance, ending balance $ 52 $ 589
v3.24.0.1
Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Asset retirement obligation at January 1 $ 105 $ 109
Accretion of discount 6 6
Obligations incurred 1 1
Obligations settled/removed (1) (10)
Revisions of estimates 8 (1)
Asset retirement obligation at December 31 119 105
Current liability 4 6
Long-term liability 115 99
Asset retirement obligation at December 31 $ 119 $ 105
v3.24.0.1
Retirement and Employee Benefit Plans (Narrative) (Details) - USD ($)
$ in Millions
 1 Months Ended 12 Months Ended
Sep. 30, 2023
Dec. 31, 2022
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]          
Defined contribution plan cost     $ 4 $ 2 $ 2
Contributions capitalized     4 2 2
Defined benefit plan, benefit obligation, payment for settlement   $ 38      
Settlement (gain) loss     2    
Other comprehensive (income) loss, defined benefit plan, after tax and reclassification adjustment, attributable to parent     (9) 31 13
Pension Benefits          
Defined Benefit Plan Disclosure [Line Items]          
Settlement (gain) loss     2 (1) 2
Transfer from plan assets $ 14   14 0  
Settlements     58 40  
Other comprehensive (income) loss, defined benefit plan, after tax and reclassification adjustment, attributable to parent     (16) 27  
Employer contributions     0 0  
Other Postretirement Benefits          
Defined Benefit Plan Disclosure [Line Items]          
Settlement (gain) loss     0 0 0
Transfer from plan assets     0   $ 0
Settlements     0 0  
Other comprehensive (income) loss, defined benefit plan, after tax and reclassification adjustment, attributable to parent     7 4  
Employer contributions     0 $ 1  
Expected future benefit payment, after year five for next five years     $ 3    
v3.24.0.1
Retirement and Employee Benefit Plans (Changes in Plans Benefit Obligations, Fair Value of Assets, and Funded Status) (Details) - USD ($)
$ in Millions
 1 Months Ended 12 Months Ended
Sep. 30, 2023
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Pension Benefits        
Change in benefit obligations:        
Benefit obligation at January 1   $ 57 $ 126  
Service cost   0 0 $ 0
Interest cost   0 3 4
Actuarial gain   0 (29)  
Benefits paid   0 (2)  
Plan amendments   0 (2)  
Settlements   (57) (39)  
Benefit obligation at December 31   0 57 126
Change in plan assets:        
Fair value of plan assets at January 1   72 114  
Actual return on plan assets   0 0  
Employer contributions   0 0  
Benefits paid   0 (2)  
Settlements   (58) (40)  
Transfer to qualified replacement plan $ (14) (14) 0  
Fair value of plan assets at December 31   0 72 114
Funded status of plans at December 31   0 15  
Other Postretirement Benefits        
Change in benefit obligations:        
Benefit obligation at January 1   9 13  
Service cost   2 2 2
Interest cost   1 0 0
Actuarial gain   (7) (5)  
Benefits paid   0 (1)  
Plan amendments   0 0  
Settlements   0 0  
Benefit obligation at December 31   5 9 13
Change in plan assets:        
Fair value of plan assets at January 1   0 0  
Actual return on plan assets   0 0  
Employer contributions   0 1  
Benefits paid   0 (1)  
Settlements   0 0  
Transfer to qualified replacement plan   0   0
Fair value of plan assets at December 31   0 0 $ 0
Funded status of plans at December 31   $ (5) $ (9)  
v3.24.0.1
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, 2023
Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]    
Projected benefit obligation $ 0 $ 57
Accumulated benefit obligation 0 57
Fair value of plan assets $ 0 $ 72
v3.24.0.1
Retirement and Employee Benefit Plans (Pension and Other Postretirement Benefit Costs) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]      
Settlement (gain) loss $ 2    
Pension Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Service cost 0 $ 0 $ 0
Interest cost 0 3 4
Expected return on plan assets 0 0 (4)
Amortization of prior service cost 0 (1) 0
Amortization of net loss 0 0 0
Net periodic benefit cost 0 2 0
Settlement (gain) loss 2 (1) 2
Total benefit cost 2 1 2
Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Service cost 2 2 2
Interest cost 1 0 0
Expected return on plan assets 0 0 0
Amortization of prior service cost 0 0 0
Amortization of net loss 0 0 0
Net periodic benefit cost 3 2 2
Settlement (gain) loss 0 0 0
Total benefit cost $ 3 $ 2 $ 2
v3.24.0.1
Retirement and Employee Benefit Plans (Amounts Recognized in Other Comprehensive Income) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]      
Total change in value of pension and postretirement liabilities $ (9.0) $ 31.0 $ 13.0
Other postretirement benefit, tax effects 1.0    
Pension Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Net actuarial gain arising during the year 0.0 30.0  
Amortization of prior service cost 0.0 (2.0)  
Tax valuation allowance release impact on pension settlements (14.0) 0.0  
Settlements (2.0) (1.0)  
Less: Tax effect (1) 0.0 0.0  
Total change in value of pension and postretirement liabilities (16.0) 27.0  
Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Net actuarial gain arising during the year 7.0 4.0  
Amortization of prior service cost 0.0 0.0  
Tax valuation allowance release impact on pension settlements 0.0 0.0  
Settlements 0.0 0.0  
Less: Tax effect (1) 0.0 0.0  
Total change in value of pension and postretirement liabilities $ 7.0 $ 4.0  
v3.24.0.1
Retirement and Employee Benefit Plans (Schedule of Assumptions Used - Benefit Obligations) (Details)
Dec. 31, 2023
Dec. 31, 2022
Pension Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Discount rate   5.60%
Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Discount rate 5.20% 5.50%
v3.24.0.1
Retirement and Employee Benefit Plans (Schedule of Assumptions Used - Net Periodic Benefit Cost) (Details)
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]      
Rate of compensation increase (2)     3.50%
Pension Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Discount rate   5.60% 3.20%
Expected return on plan assets   0.10% 0.10%
Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Discount rate 5.50% 3.10% 2.80%
v3.24.0.1
Retirement and Employee Benefit Plans (Schedule of Health Care Cost Trend Rates) (Details)
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Retirement Benefits [Abstract]    
Health care cost trend assumed for next year 7.00% 7.00%
Rate to which the cost trend is assumed to decline 5.00% 5.00%
Year that the rate reaches the ultimate trend rate 2041 2040
v3.24.0.1
Retirement and Employee Benefit Plans (Fair Value Measurement of Pension Plan Assets) (Details) - Pension Benefits - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets $ 0 $ 72 $ 114
Excluding Net Asset Value      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   71  
Excluding Net Asset Value | Fixed income      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   69  
Excluding Net Asset Value | Cash and cash equivalents      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   2  
Quoted Prices in Active Markets for Identical Assets (Level 1)      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   71  
Quoted Prices in Active Markets for Identical Assets (Level 1) | Fixed income      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   69  
Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalents      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   2  
Significant Observable Inputs (Level 2)      
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  
Significant Observable Inputs (Level 2) | Cash and cash equivalents      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   0  
Significant Unobservable Inputs (Level 3)      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   0  
Significant Unobservable Inputs (Level 3) | Fixed income      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   0  
Significant Unobservable Inputs (Level 3) | Cash and cash equivalents      
Defined Benefit Plan Disclosure [Line Items]      
Fair value of plan assets   $ 0  
v3.24.0.1
Long-Term Incentive Compensation (Narrative) (Details) - USD ($)
 3 Months Ended 12 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Mar. 31, 2021
Mar. 31, 2020
Mar. 31, 2019
Mar. 31, 2018
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                        
Long-term incentive compensation – expensed             $ 23,000,000 $ 30,000,000 $ 30,000,000      
Number of options, granted (in shares)             0 0 0      
Liability-classified performance units, vesting period             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             10 years          
Long-term incentive compensation – expensed             $ 0 $ 0 $ 0      
Increase (decrease) in deferred tax asset (liability) (less than)             1,000,000 1,000,000 (1,000,000)      
Equity-classified awards, unrecognized compensation cost             $ 0          
Restricted Stock                        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                        
Vesting period for stock awards from grant date             3 years          
Long-term incentive compensation – expensed             $ 2,000,000 1,000,000 2,000,000      
Increase (decrease) in deferred tax asset (liability) (less than)               (1,000,000) (1,000,000)      
Equity-classified awards, unrecognized compensation cost             $ 1,000,000          
Employee service share-based compensation, nonvested awards, compensation cost not yet recognized, period for recognition             4 months 24 days          
Total fair value of restricted stock grants             $ 2,000,000 $ 2,000,000 2,000,000      
Total fair value of shares vested             $ 2,000,000   $ 5,000,000      
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 3 years 3 years
Long-term incentive compensation – expensed             $ 2,000,000 $ 1,000,000 $ 0      
Increase (decrease) in deferred tax asset (liability) (less than)             (3,000,000) $ (3,000,000) $ (2,000,000)      
Equity-classified awards, unrecognized compensation cost             $ 6,000,000          
Employee service share-based compensation, nonvested awards, compensation cost not yet recognized, period for recognition             1 year 9 months 18 days          
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 3 years 3 years      
Equity-Classified Restricted Stock Units                        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                        
Long-term incentive compensation – expensed             $ 5,000,000 $ 2,000,000 $ 0      
Equity-classified awards, unrecognized compensation cost             $ 6,000,000          
Employee service share-based compensation, nonvested awards, compensation cost not yet recognized, period for recognition             1 year 6 months          
Liability-Classified RSUs                        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                        
Increase (decrease) in deferred tax asset (liability) (less than)             $ 1,000,000   $ (1,000,000)      
Liability-classified restricted stock, vesting period 4 years 4 years 4 years 4 years 4 years 4 years     3 years      
Liability-classified restricted stock, unrecognized compensation cost             $ 1,000,000          
Liability-classified restricted stock, weighted average period over which unrecognized cost is recognized, years             2 months 12 days          
Liability-Classified Performance Units                        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                        
Increase (decrease) in deferred tax asset (liability) (less than)             $ (1,000,000) $ (4,000,000) $ (4,000,000)      
Liability-classified performance units, unrecognized compensation cost             $ 4,000,000          
Liability-classified performance units, weighted average period over which unrecognized cost is recognized, years             1 year 10 months 24 days          
Performance cash awards                        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                        
Vesting period for stock awards from grant date             3 years 4 years 4 years 4 years    
Long-term incentive compensation – expensed             $ 9,000,000 $ 6,000,000 $ 4,000,000      
Increase (decrease) in deferred tax asset (liability) (less than)             (1,000,000) $ (1,000,000) $ (1,000,000)      
Liability-classified restricted stock, unrecognized compensation cost             $ 33,000,000          
Liability-classified restricted stock, weighted average period over which unrecognized cost is recognized, years             2 years          
2022 Plan                        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                        
Maximum shares             40,000,000          
Stock Based Compensation 2013 Plan                        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]                        
Period of service for immediate vesting upon death, disability or retirement             3 years          
v3.24.0.1
Long-Term Incentive Compensation - Schedule of Stock-based Compensation Costs (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed $ 23 $ 30 $ 30
Long-term incentive compensation – capitalized 15 20 18
Share-Based Payment Arrangement, Award      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed 9 4 2
Long-term incentive compensation – capitalized $ 3 $ 3 $ 0
v3.24.0.1
Long-Term Incentive Compensation (Schedule of Equity-Classified Awards-Based Compensation Costs) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-Based Payment Arrangement [Abstract]      
Long-term incentive compensation – expensed $ 23 $ 30 $ 30
Long-term incentive compensation – capitalized $ 15 $ 20 $ 18
v3.24.0.1
Long-Term Incentive Compensation (Summary of Equity-Classified Stock Option Activity) (Details) - $ / shares
shares in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Number of Shares      
Number of Options, Outstanding at January 1 (in shares) 997 3,006 3,850
Number of options, granted (in shares) 0 0 0
Number of Options, Exercised (in shares) 0 (893) 0
Number of Options, Forfeited or expired (in shares) (177) (1,116) (844)
Number of Options, Outstanding at December 31 (in shares) 820 997 3,006
Weighted Average Exercise Price      
Weighted Average Exercise Price, Outstanding at January 1 (in dollars per share) $ 8.59 $ 8.98 $ 13.39
Weighted Average Exercise Price, Granted (in dollars per share) 0 0 0
Weighted Average Exercise Price, Exercised (in dollars per share) 0 7.80 0
Weighted Average Exercise Price, Forfeited or expired (in dollars per share) 8.60 10.26 29.10
Weighted Average Exercise Price, Outstanding at December 31 (in dollars per share) $ 8.59 $ 8.59 $ 8.98
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Additional Disclosures [Abstract]      
Options exercisable, Number of options (in shares) 820    
Options exercisable, Weighted average exercise price per share (in dollars per share) $ 8.59    
Options exercisable - weighted average remaining contractual life (in years) 1 year 1 month 6 days    
v3.24.0.1
Long-Term Incentive Compensation (Schedule of Equity-Classified Restricted Stock Stock-Based Compensation Costs) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed $ 23 $ 30 $ 30
Long-term incentive compensation – capitalized 15 20 18
Restricted Stock      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed 2 1 2
Long-term incentive compensation – capitalized $ 0 $ 0 $ 0
v3.24.0.1
Long-Term Incentive Compensation (Summary of Equity-Classified Restricted Stock Activity) (Details) - Restricted Stock - $ / shares
shares in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Number of Shares      
Number of Shares/Units, Unvested shares/units at January 1 (in shares) 211 242 697
Number of Shares/Units, Granted (in shares) 336 231 438
Number of Shares/Units, Vested (in shares) (378) (262) (893)
Number of Shares/Units, Forfeited (in shares) 0 0 0
Number of Shares/Units, Unvested shares/units at December 31 (in shares) 169 211 242
Weighted Average Fair Value      
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share) $ 5.81 $ 5.12 $ 5.97
Weighted Average Fair Value, Granted (in dollars per share) 5.34 6.92 5.18
Weighted Average Fair Value, Vested (in dollars per share) 5.71 6.15 5.81
Weighted Average Fair Value, Forfeited (in dollars per share) 0 0 8.59
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share) $ 5.09 $ 5.81 $ 5.12
v3.24.0.1
Long-Term Incentive Compensation (Schedule of Equity-Classified Restricted Units Stock-Based Compensation Costs) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed $ 23 $ 30 $ 30
Long-term incentive compensation – capitalized 15 20 18
Equity-Classified Restricted Stock Units      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed 5 2 0
Long-term incentive compensation – capitalized $ 2 $ 2 $ 0
v3.24.0.1
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, 2023
Dec. 31, 2022
Dec. 31, 2021
Number of Shares      
Number of Shares/Units, Unvested shares/units at January 1 (in shares) 1,645 37 134
Number of Shares/Units, Granted (in shares) 1,617 1,699 0
Number of Shares/Units, Vested (in shares) (555) (22) (92)
Number of Shares/Units, Forfeited (in shares) (1) (69) (5)
Number of Shares/Units, Unvested shares/units at December 31 (in shares) 2,706 1,645 37
Weighted Average Fair Value      
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share) $ 4.44 $ 3.05 $ 3.05
Weighted Average Fair Value, Granted (in dollars per share) 4.94 4.45 0
Weighted Average Fair Value, Vested (in dollars per share) 4.42 3.05 3.05
Weighted Average Fair Value, Forfeited (in dollars per share) 3.05 4.37 3.05
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share) $ 4.74 $ 4.44 $ 3.05
v3.24.0.1
Long-Term Incentive Compensation (Schedule of Equity-Classified Performance Units Stock-Based Compensation Costs) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed $ 23 $ 30 $ 30
Long-term incentive compensation – capitalized 15 20 18
Performance units      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed 2 1 0
Long-term incentive compensation – capitalized $ 1 $ 1 $ 0
v3.24.0.1
Long-Term Incentive Compensation (Schedule of Equity-Liability-Classified Awards-Based Compensation Costs) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed $ 23 $ 30 $ 30
Long-term incentive compensation – capitalized 15 20 18
Liability-Classified Awards      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed 5 20 24
Long-term incentive compensation – capitalized $ 2 $ 11 $ 14
v3.24.0.1
Long-Term Incentive Compensation (Summary of Equity-Classified Performance Units Activity) (Details) - Performance units - $ / shares
shares in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Number of Shares            
Number of Shares/Units, Unvested shares/units at January 1 (in shares) 817 0 0      
Number of Shares/Units, Granted (in shares) 940 850 0      
Number of Shares/Units, Vested (in shares) 0 0 0      
Number of Shares/Units, Forfeited (in shares) 0 (33) 0      
Number of Shares/Units, Unvested shares/units at December 31 (in shares) 1,757 817 0 0    
Weighted Average Fair Value            
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share) $ 6.04 $ 0 $ 0      
Weighted Average Fair Value, Granted (in dollars per share) 6.12 6.04 0      
Weighted Average Fair Value, Vested (in dollars per share) 0 0 0      
Weighted Average Fair Value, Forfeited (in dollars per share) 0 6.04 0      
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share) $ 6.08 $ 6.04 $ 0 $ 0    
Vesting period for stock awards from grant date 3 years 3 years 3 years 3 years 3 years 3 years
v3.24.0.1
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, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]      
Restricted stock units – general and administrative expense $ 4 $ 9 $ 12
Restricted stock units – capitalized expense $ 2 $ 6 $ 8
v3.24.0.1
Long-Term Incentive Compensation (Summary of Liability-Classified Restricted Stock Unit Activity) (Details) - Liability-Classified RSUs - $ / shares
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Number of Units      
Number of Shares/Units, Unvested shares/units at January 1 (in shares) 3,950,000 7,937,000 11,613,000
Number of Shares/Units, Granted (in shares) 0 0 1,486,000
Number of Shares/Units, Vested (in shares) (2,206,000) (3,817,000) (4,522,000)
Number of Shares/Units, Forfeited (in shares) (3,000) (170,000) (640,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares) 1,741,000 3,950,000 7,937,000
Weighted Average Fair Value      
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share) $ 4.81 $ 4.08 $ 2.67
Weighted Average Fair Value, Granted (in dollars per share) 0 0 4.23
Weighted Average Fair Value, Vested (in dollars per share) 4.84 4.48 3.40
Weighted Average Fair Value, Forfeited (in dollars per share) 5.57 6.83 4.56
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share) $ 4.67 $ 4.81 $ 4.08
Workforce Reduction      
Number of Units      
Number of Shares/Units, Forfeited (in shares)     (360,253)
v3.24.0.1
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, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]      
Liability-classified stock-based compensation cost - expensed $ 1 $ 11 $ 12
Liability-based Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount $ 0 $ 5 $ 6
v3.24.0.1
Long-Term Incentive Compensation (Summary of Liability-Classified Performance Unit Activity) (Details) - Liability-Classified Performance Units - $ / shares
shares in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Number of Units      
Number of Shares/Units, Unvested shares/units at January 1 (in shares) 10,982 9,515 8,699
Number of Shares/Units, Granted (in shares) 5,136 3,798 3,580
Number of Shares/Units, Vested (in shares) (3,966) (1,910) (2,020)
Number of Shares/Units, Forfeited (in shares) 0 (421) (744)
Number of Shares/Units, Unvested shares/units at December 31 (in shares) 12,152 10,982 9,515
Weighted Average Fair Value      
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share) $ 2.25 $ 2.88 $ 2.57
Weighted Average Fair Value, Granted (in dollars per share) 4.83 1.00 4.14
Weighted Average Fair Value, Vested (in dollars per share) 6.13 6.45 4.05
Weighted Average Fair Value, Forfeited (in dollars per share) 0 6.70 3.40
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share) $ 0.94 $ 2.25 $ 2.88
v3.24.0.1
Long-Term Incentive Compensation (Schedule of Performance Cash Awards Stock-Based Compensation Costs) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed $ 23 $ 30 $ 30
Long-term incentive compensation – capitalized 15 20 18
Performance cash awards      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Long-term incentive compensation – expensed 9 6 4
Long-term incentive compensation – capitalized $ 10 $ 6 $ 4
v3.24.0.1
Long-term Incentive Compensation (Summary of Performance Cash Awards Activity) (Details) - Performance cash awards - $ / shares
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Number of Shares      
Number of Shares/Units, Unvested shares/units at January 1 (in shares) 39,994,000 28,272,000 18,353,000
Number of Shares/Units, Granted (in shares) 27,493,000 24,416,000 18,546,000
Number of Shares/Units, Vested (in shares) (13,320,000) (8,786,000) (4,955,000)
Number of Shares/Units, Forfeited (in shares) (4,489,000) (3,908,000) (3,672,000)
Number of Shares/Units, Unvested shares/units at December 31 (in shares) 49,678,000 39,994,000 28,272,000
Weighted Average Fair Value      
Weighted Average Fair Value, Unvested shares/units at January 1 (in dollars per share) $ 1.00 $ 1.00 $ 1.00
Weighted Average Fair Value, Granted (in dollars per share) 1.00 1.00 1.00
Weighted Average Fair Value, Vested (in dollars per share) 1.00 1.00 1.00
Weighted Average Fair Value, Forfeited (in dollars per share) 1.00 1.00 1.00
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share) $ 1.00 $ 1.00 $ 1.00
Workforce Reduction      
Number of Shares      
Number of Shares/Units, Forfeited (in shares)     (1,241,000)
v3.24.0.1
Segment Information (Schedule of Summarized Financial Information) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Segment Reporting Information [Line Items]      
Revenues from external customers $ 6,522 $ 15,002 $ 6,667
Depreciation, depletion and amortization expense 1,307 1,174 546
Impairments 1,710 0 6
Operating income (loss) (974) 7,354 2,635
Interest expense 142 184 136
Total gain (loss) on derivatives 2,433 (5,259) (2,436)
Loss on Early Extinguishment of Debt (19) (14) (93)
Other income, net 2 3 5
Provision (benefit) for income taxes (257) 51 0
Assets 11,991 12,926 11,848
Capital investments 2,131 2,209 1,108
Increase (decrease) in accrued expenditures between periods (44) 88 70
Merger-related expenses 0 27 76
Restructuring charges 0 0 7
Marketing      
Segment Reporting Information [Line Items]      
Revenues from external customers 2,355 4,419 1,963
Exploration and Production      
Segment Reporting Information [Line Items]      
Revenues from external customers 4,167 10,583 4,701
Merger-related expenses   27 76
Marketing      
Segment Reporting Information [Line Items]      
Revenues from external customers 2,355 4,419 1,966
Intersegment Revenues      
Segment Reporting Information [Line Items]      
Revenues from external customers 3,864 10,096 4,162
Intersegment Revenues | Marketing      
Segment Reporting Information [Line Items]      
Revenues from external customers 3,922 10,102 4,223
Intersegment Revenues | Exploration and Production      
Segment Reporting Information [Line Items]      
Revenues from external customers (58) (6) (61)
Intersegment Revenues | Marketing      
Segment Reporting Information [Line Items]      
Revenues from external customers 3,922 10,102 4,223
Intersegment Revenues | Marketing | Marketing      
Segment Reporting Information [Line Items]      
Revenues from external customers (3,900) (10,100) (4,200)
Operating Segments      
Segment Reporting Information [Line Items]      
Revenues from external customers 6,522    
Depreciation, depletion and amortization expense 1,307 1,174 546
Impairments 1,710   6
Operating income (loss) (969) 7,354 2,635
Interest expense 142 184 136
Total gain (loss) on derivatives 2,433 (5,257) (2,437)
Loss on Early Extinguishment of Debt 0 0 0
Other income, net 2 3 5
Provision (benefit) for income taxes (257) 51 0
Assets 11,844 12,747 11,723
Capital investments 2,122 2,196 1,107
Operating Segments | Exploration and Production      
Segment Reporting Information [Line Items]      
Revenues from external customers 4,109 10,577 4,640
Depreciation, depletion and amortization expense 1,302 1,169 537
Impairments 1,710   6
Operating income (loss) (1,061) 7,253 2,583
Interest expense 142 184 136
Total gain (loss) on derivatives 2,433 (5,257) (2,437)
Loss on Early Extinguishment of Debt 0 0 0
Other income, net 2 3 5
Provision (benefit) for income taxes (257) 51 0
Assets 11,253 11,473 10,767
Capital investments 2,122 2,196 1,107
Restructuring charges     7
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 6,277 14,521 6,189
Depreciation, depletion and amortization expense 5 5 9
Impairments 0   0
Operating income (loss) 92 101 52
Interest expense 0 0 0
Total gain (loss) on derivatives 0 0 0
Loss on Early Extinguishment of Debt 0 0 0
Other income, net 0 0 0
Provision (benefit) for income taxes 0 0 0
Assets 591 1,274 956
Capital investments 0 0 0
Operating Segments | Marketing | Marketing      
Segment Reporting Information [Line Items]      
Revenues from external customers 6,277 14,521 6,186
Other      
Segment Reporting Information [Line Items]      
Depreciation, depletion and amortization expense 0 0 0
Impairments 0   0
Operating income (loss) (5) 0 0
Interest expense 0 0 0
Total gain (loss) on derivatives 0 (2) 1
Loss on Early Extinguishment of Debt (19) (14) (93)
Other income, net 0 0 0
Provision (benefit) for income taxes 0 0 0
Assets 147 179 125
Capital investments $ 9 $ 13 $ 1
v3.24.0.1
Segment Information (Schedule of Other Assets) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Segment Reporting Information [Line Items]      
Cash and cash equivalents $ 21 $ 50  
Other current assets 100 68  
Property, plant and equipment 9,913 10,903  
Unamortized debt expense 34 44  
Operating lease assets 154 177  
Long term assets 663 359  
TOTAL ASSETS 11,991 12,926 $ 11,848
Other      
Segment Reporting Information [Line Items]      
Cash and cash equivalents 21 50 28
Accounts receivable 0 1 0
Prepayments 18 14 6
Other current assets 2 0 0
Property, plant and equipment 24 19 12
Unamortized debt expense 15 19 10
Operating lease assets 49 57 65
Non-qualified retirement plan 3 3 4
Long term assets 15 16 0
TOTAL ASSETS $ 147 $ 179 $ 125
v3.24.0.1
Subsequent Events (Details) - Subsequent Event - Southwestern Energy Company - Chesapeake Energy Corporation Merger
$ in Thousands
Jan. 10, 2024
USD ($)
Subsequent Event [Line Items]  
Share exchange ratio 0.0867
Fee to be reimbursed by acquired upon termination of agreement $ 55,600
Fee to be paid by acquired upon termination of agreement 389,000
Fee to be reimbursed by acquiree upon termination of agreement 37,250
Fee to be paid by acquiree upon termination of agreement $ 260,000
v3.24.0.1
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, 2023
USD ($)
$ / Mcfe
Dec. 31, 2022
USD ($)
$ / Mcfe
Dec. 31, 2021
USD ($)
$ / Mcfe
Oil and Gas Exploration and Production Industries Disclosures [Abstract]      
Unproved property acquisition costs $ 184 $ 202 $ 139
Exploration costs 0 0 0
Development costs 1,939 2,021 984
Capitalized costs incurred $ 2,123 $ 2,223 $ 1,123
Full cost pool amortization (in dollars per mcfe) | $ / Mcfe 0.77 0.67 0.42
v3.24.0.1
Supplemental Oil and Gas Disclosures (Unaudited) (Narrative) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2023
USD ($)
Mcfe
Dec. 31, 2022
USD ($)
Mcfe
Dec. 31, 2021
USD ($)
Mcfe
Dec. 31, 2020
Mcfe
Natural Gas and Oil Properties [Line Items]        
Capitalized interest based on weighted average cost of borrowings | $ $ 115 $ 121 $ 97  
Capitalized internal costs related to acquisition, exploration and development | $ $ 85 $ 85 $ 64  
Percentage of present worth of proved reserves evaluated in audit 99.00% 99.00% 99.00%  
Proved reserves, end of period, (bcfe) 19,660,000,000 21,625,000,000 21,148,000,000 11,990,000,000
Proved undeveloped reverses (energy) 2,548,000,000 0    
United States        
Natural Gas and Oil Properties [Line Items]        
Proved reserves, end of period, (bcfe) 19,660,000,000 21,625,000,000 21,148,000,000 11,990,000,000
Proved undeveloped reverses (energy) 8,055,000,000 9,480,000,000 9,813,000,000  
v3.24.0.1
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, 2023
Dec. 31, 2022
Dec. 31, 2021
Oil and Gas Exploration and Production Industries Disclosures [Abstract]      
Sales $ 4,109 $ 10,577 $ 4,640
Production (lifting) costs (1,990) (1,969) (1,304)
Depreciation, depletion and amortization (1,302) (1,169) (537)
Impairment of natural gas and oil properties (1,710) 0 0
Results of operations - income before income taxes (893) 7,439 2,799
Provision for income taxes (200) 0 0
Results of operations $ (693) $ 7,439 $ 2,799
v3.24.0.1
Supplemental Oil and Gas Disclosures (Unaudited) (Summary of Changes in Reserves - United States) (Details)
bbl in Thousands, Mcf in Millions
 12 Months Ended
Dec. 31, 2023
Mcfe
bbl
Mcf
Dec. 31, 2022
Mcfe
bbl
Mcf
Dec. 31, 2021
Mcfe
bbl
Mcf
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]      
Proved reserves, beginning of period, (bcfe) | Mcfe 21,625,000,000 21,148,000,000 11,990,000,000
Revisions of previous estimates due to price (1) | Mcfe (1,847,000,000) 55,000,000 415,000,000
Extensions, discoveries and other additions (2) | Mcfe 2,026,000,000 2,428,000,000 1,961,000,000
Production | Mcfe (1,669,000,000) (1,733,000,000) (1,240,000,000)
Acquisition of reserves in place (3) | Mcfe 0 0 5,753,000,000
Disposition of reserves in place | Mcfe (350,000,000) (43,000,000) (1,000,000)
Proved reserves, end of period, (bcfe) | Mcfe 19,660,000,000 21,625,000,000 21,148,000,000
Proved undeveloped reserves:      
Proved undeveloped reverses (energy) | Mcfe 2,548,000,000 0  
Natural Gas      
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]      
Proved developed reserves, reclassified to performance and production revisions | Mcf 34   158
Proved undeveloped reserves, reclassified to performance and production revisions | Mcf     997
Oil      
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]      
Proved developed reserves, reclassified to performance and production revisions     2
Proved undeveloped reserves, reclassified to performance and production revisions     13
NGL      
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]      
Proved developed reserves, reclassified to performance and production revisions     14
Proved undeveloped reserves, reclassified to performance and production revisions     112
United States      
Proved Developed and Undeveloped Reserves [Roll Forward]      
Acquisition of reserves in place (3) | Mcf     5,750
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]      
Proved reserves, beginning of period, (bcfe) | Mcfe 21,625,000,000 21,148,000,000 11,990,000,000
Revisions of previous estimates due to price (1) | Mcfe (1,847,000,000) 55,000,000 415,000,000
Revisions of previous estimates other than price (4) | Mcfe (125,000,000) (230,000,000) 2,270,000,000
Extensions, discoveries and other additions (2) | Mcfe 2,026,000,000 2,428,000,000 1,961,000,000
Production | Mcfe (1,669,000,000) (1,733,000,000) (1,240,000,000)
Acquisition of reserves in place (3) | Mcfe     5,753,000,000
Disposition of reserves in place | Mcfe (350,000,000) (43,000,000) (1,000,000)
Proved reserves, end of period, (bcfe) | Mcfe 19,660,000,000 21,625,000,000 21,148,000,000
Proved developed reserves as of:      
Proved developed reserves (energy) | Mcfe 11,605,000,000 12,145,000,000 11,335,000,000
Proved undeveloped reserves:      
Proved undeveloped reverses (energy) | Mcfe 8,055,000,000 9,480,000,000 9,813,000,000
United States | Natural Gas      
Proved Developed and Undeveloped Reserves [Roll Forward]      
Proved reserves, beginning of year | Mcf 17,362 17,207 9,181
Revisions of previous estimates due to price (1) | Mcf (1,779) 61 501
Revisions of previous estimates other than price (4) | Mcf (417) (458) 1,402
Extensions, discoveries and other additions (2) | Mcf 1,813 2,106 1,389
Production | Mcf (1,438) (1,520) (1,015)
Disposition of reserves in place | Mcf (350) (34) (1)
Proved reserves, end of year | Mcf 15,191 17,362 17,207
Proved developed reserves as of:      
Proved developed reserves (volume) | Mcf 9,196 9,793 9,308
Proved undeveloped reserves:      
Proved undeveloped reserves (volume) | Mcf 5,995 7,569 7,899
United States | Oil      
Proved Developed and Undeveloped Reserves [Roll Forward]      
Proved reserves, beginning of year 83,386 79,779 58,024
Revisions of previous estimates due to price (1) (1,118) (107) 1,414
Revisions of previous estimates other than price (4) (3,630) (2,149) 17,384
Extensions, discoveries and other additions (2) 5,062 10,877 9,381
Production (5,602) (4,993) (6,610)
Acquisition of reserves in place (3)     247
Disposition of reserves in place 0 (21) (61)
Proved reserves, end of year 78,098 83,386 79,779
Proved developed reserves as of:      
Proved developed reserves (volume) 38,581 41,138 40,930
Proved undeveloped reserves:      
Proved undeveloped reserves (volume) 39,517 42,248 38,849
United States | NGL      
Proved Developed and Undeveloped Reserves [Roll Forward]      
Proved reserves, beginning of year 627,136 576,964 410,151
Revisions of previous estimates due to price (1) (10,217) (828) (15,525)
Revisions of previous estimates other than price (4) 52,283 40,138 127,197
Extensions, discoveries and other additions (2) 30,444 42,719 85,901
Production (32,859) (30,446) (30,940)
Acquisition of reserves in place (3)     180
Disposition of reserves in place 0 (1,411) 0
Proved reserves, end of year 666,787 627,136 576,964
Proved developed reserves as of:      
Proved developed reserves (volume) 362,983 350,821 296,832
Proved undeveloped reserves:      
Proved undeveloped reserves (volume) 303,804 276,315 280,132
v3.24.0.1
Supplemental Oil and Gas Disclosures (Unaudited) (Summary of Changes in Reserves) (Details)
bbl in Thousands, Mcfe in Millions, Mcf in Millions
 12 Months Ended
Dec. 31, 2023
Mcfe
Mcf
bbl
Dec. 31, 2022
Mcfe
bbl
Mcf
Dec. 31, 2021
Mcfe
bbl
Mcf
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]      
Proved reserves, beginning of period, (bcfe) 21,625 21,148 11,990
Net revisions      
Price revisions (1,847) 55 415
Performance and production revisions (3) (125) (230) 2,270
Total net revisions (1,972) (175) 2,685
Extensions, discoveries and other additions      
Proved developed (2) 80 406 197
Proved undeveloped (2) 1,946 2,022 1,764
Total reserve additions 2,026 2,428 1,961
Production (1,669) (1,733) (1,240)
Acquisition of reserves in place (3) 0 0 5,753
Disposition of reserves in place (350) (43) (1)
Proved reserves, end of period, (bcfe) 19,660 21,625 21,148
Natural Gas      
Extensions, discoveries and other additions      
Proved reserves, reclassified to revision of previous estimate other than price | Mcf     1,155
Proved developed and undeveloped reserves, other than price revisions, positive, performance revisions | Mcf 25 272  
Proved developed and undeveloped reserves, other than price revisions, additions, infilled development (energy) | Mcf 647 303  
Proved developed and undeveloped reserves, other than price revisions, downward revisions, change in development plan (energy) | Mcf 1,089 1,033  
Proved developed reserves, reclassified to performance and production revisions | Mcf 34   158
Proved undeveloped reserves, reclassified to performance and production revisions | Mcf     997
Oil      
Extensions, discoveries and other additions      
Proved reserves, reclassified to revision of previous estimate other than price | bbl     15
Proved developed and undeveloped reserves, other than price revisions, negative, performance revisions | bbl 3,062 681  
Proved developed and undeveloped reserves, other than price revisions, additions, infilled development (energy) | bbl 12,493 5,254  
Proved developed and undeveloped reserves, other than price revisions, downward revisions, change in development plan (energy) | bbl 13,061 6,722  
Proved developed reserves, reclassified to performance and production revisions | bbl     2
Proved undeveloped reserves, reclassified to performance and production revisions | bbl     13
NGL      
Extensions, discoveries and other additions      
Proved reserves, reclassified to revision of previous estimate other than price | bbl     126
Proved developed and undeveloped reserves, other than price revisions, positive, performance revisions | bbl 28,189 41,490  
Proved developed and undeveloped reserves, other than price revisions, additions, infilled development (energy) | bbl 85,378 40,423  
Proved developed and undeveloped reserves, other than price revisions, downward revisions, change in development plan (energy) | bbl 61,284 41,775  
Proved developed reserves, reclassified to performance and production revisions | bbl     14
Proved undeveloped reserves, reclassified to performance and production revisions | bbl     112
Appalachia      
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]      
Proved reserves, beginning of period, (bcfe) 15,666 15,527 11,989
Net revisions      
Price revisions (570) (4) 415
Performance and production revisions (3) 189 (33) 2,271
Total net revisions (381) (37) 2,686
Extensions, discoveries and other additions      
Proved developed (2) 14 235 197
Proved undeveloped (2) 769 1,038 1,764
Total reserve additions 783 1,273 1,961
Production (1,034) (1,054) (1,108)
Acquisition of reserves in place (3) 0 0 0
Disposition of reserves in place (349) (43) (1)
Proved reserves, end of period, (bcfe) 14,685 15,666 15,527
Proved developed and undeveloped reserves, performance and production revisions, positive performance revisions (energy) | Mcf 246 381  
Proved developed and undeveloped reserves, performance and production revisions, additions, infill development (energy) | Mcf 1,200 577  
Proved developed and undeveloped reserves, performance and production downward revisions, change in development plans (energy) | Mcf (1,257) 991  
Haynesville      
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]      
Proved reserves, beginning of period, (bcfe) 5,959 5,621 0
Net revisions      
Price revisions (1,277) 59 0
Performance and production revisions (3) (314) (197) 0
Total net revisions (1,591) (138) 0
Extensions, discoveries and other additions      
Proved developed (2) 66 171 0
Proved undeveloped (2) 1,177 984 0
Total reserve additions 1,243 1,155 0
Production (635) (679) (132)
Acquisition of reserves in place (3) 0 0 5,753
Disposition of reserves in place (1) 0 0
Proved reserves, end of period, (bcfe) 4,975 5,959 5,621
Other      
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]      
Proved reserves, beginning of period, (bcfe) 0 0 1
Net revisions      
Price revisions 0 0 0
Performance and production revisions (3) 0 0 (1)
Total net revisions 0 0 (1)
Extensions, discoveries and other additions      
Proved developed (2) 0 0 0
Proved undeveloped (2) 0 0 0
Total reserve additions 0 0 0
Production 0 0 0
Acquisition of reserves in place (3) 0 0 0
Disposition of reserves in place 0 0 0
Proved reserves, end of period, (bcfe) 0 0 0
Haynesville      
Extensions, discoveries and other additions      
Proved developed and undeveloped reserves, performance and production revisions, positive performance revisions (energy) | Mcf (70) 136  
Proved developed and undeveloped reserves, performance and production downward revisions, change in development plans (energy) | Mcf (278) 333  
v3.24.0.1
Supplemental Oil and Gas Disclosures (Unaudited) (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure) (Details) - USD ($)
$ in Millions
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]        
Future cash inflows $ 50,499 $ 132,037 $ 75,314  
Future production costs (26,147) (29,632) (23,235)  
Future development costs (1) (6,558) (7,458) (6,032)  
Future income tax expense (1,581) (19,323) (8,135)  
Future net cash flows 16,213 75,624 37,912  
10% annual discount for estimated timing of cash flows (8,900) (38,036) (19,181)  
Standardized measure of discounted future net cash flows $ 7,313 $ 37,588 $ 18,731 $ 1,847
v3.24.0.1
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, 2023
$ / MMBTU
Dec. 31, 2023
$ / barrel
Dec. 31, 2023
$ / bbl
Dec. 31, 2022
$ / MMBTU
Dec. 31, 2022
$ / barrel
Dec. 31, 2022
$ / bbl
Dec. 31, 2021
$ / MMBTU
Dec. 31, 2021
$ / barrel
Dec. 31, 2021
$ / bbl
Natural Gas                  
Reserve Quantities [Line Items]                  
Average sales price (in dollars per unit) 2.64     6.36     3.60    
Oil                  
Reserve Quantities [Line Items]                  
Average sales price (in dollars per unit)   78.22 78.22   93.67 93.67   66.56 66.56
NGL                  
Reserve Quantities [Line Items]                  
Average sales price (in dollars per unit)   21.38 21.38   34.35 34.35   28.65 28.65
v3.24.0.1
Supplemental Oil and Gas Disclosures (Unaudited) (Schedule of Analysis of Changes in Standardized Measure) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
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 $ 37,588 $ 18,731 $ 1,847
Sales and transfers of natural gas and oil produced, net of production costs (2,123) (8,611) (3,332)
Net changes in prices and production costs (36,514) 23,198 10,417
Extensions, discoveries, and other additions, net of future production and development costs 63 4,976 3,183
Acquisition of reserves in place 0 1 6,499
Sales of reserves in place (710) (49) (1)
Revisions of previous quantity estimates (1,174) (400) 596
Net change in income taxes 8,364 (5,158) (3,689)
Changes in estimated future development costs 1,005 (709) 137
Previously estimated development costs incurred during the year 1,336 1,208 419
Changes in production rates (timing) and other (5,165) 2,159 2,470
Accretion of discount 4,643 2,242 185
Standardized measure, end of year $ 7,313 $ 37,588 $ 18,731