Cover Page
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 |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Auditor Information [Abstract] | |
Auditor name | PricewaterhouseCoopers LLP |
Auditor location | Houston, Texas |
Auditor firm ID | 238 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 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 |
CONSOLIDATED STATEMENTS OF COMP
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. 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. |
CONSOLIDATED BALANCE SHEETS
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 |
CONSOLIDATED BALANCE SHEETS (Pa
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 |
CONSOLIDATED STATEMENTS OF CASH
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 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Millions | Total | Common Stock | Additional Paid-In Capital | Accumulated Deficit | Accumulated Other Comprehensive Income (Loss) | Common Stock in Treasury |
Beginning balance (in shares) at Dec. 31, 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 |
Organization and Summary of Sig
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) 2023 2022 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 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, 2023 2022 2021 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) 2023 2022 2021 Prior Total Property acquisition costs $ 63 $ 86 $ 559 $ 1,005 $ 1,713 Exploration and development costs 24 9 8 18 59 Capitalized interest 115 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, 2023 December 31, 2022 Water facilities $ 252 $ 238 Gathering systems 60 56 Technology infrastructure 146 135 Drilling rigs and equipment 35 31 Land, buildings and leasehold improvements 16 16 Other 57 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) 2023 2022 2021 Net income (loss) $ 1,557 $ 1,849 $ (25) Number of common shares: Weighted average outstanding 1,100,980,199 1,110,564,839 789,657,776 Issued upon assumed exercise of outstanding stock options — — — Effect of issuance of non-vested restricted common stock 862,434 763,067 — Effect of issuance of non-vested restricted units 1,431,754 1,500,815 — Effect of issuance of non-vested performance units 131,868 355,533 — Weighted average and potential dilutive outstanding 1,103,406,255 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, 2023 2022 2021 Unexercised stock options 831,525 2,265,589 3,683,363 Unvested share-based payment 46,101 53,924 832,989 Restricted units 211,506 192,515 2,226,981 Performance units — — 2,194,477 Total 1,089,132 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) 2023 2022 2021 Cash paid during the year for interest, net of amounts capitalized $ 140 $ 161 $ 106 Cash paid during the year for income taxes 13 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. |
Acquisitions
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 issued 99,337,748 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 equivalents 11 Accounts receivable (1) 180 Other current assets (1) 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 (1) 176 Other current liabilities 1 Derivative liabilities 75 Revolving credit facility 81 Asset retirement obligations 24 Other noncurrent liabilities (1) 12 Total liabilities assumed 369 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 issued 337,827,171 NYSE closing price per share of Southwestern common shares on September 1, 2021 $ 4.70 $ 1,588 Cash consideration 373 Total consideration $ 1,961 The following table sets forth the 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 equivalents 55 Accounts receivable (2) 193 Other current assets 2 Commodity derivative assets 2 Evaluated oil and gas properties 2,724 Unevaluated oil and gas properties (1) 690 Other property, plant and equipment 4 Other long-term assets 27 Total assets acquired 3,697 Fair Value of Liabilities Assumed: Accounts payable (2) 285 Other current liabilities 55 Derivative liabilities 501 Revolving credit facility 95 Senior unsecured notes 726 Asset retirement obligations 8 Other noncurrent liabilities (2) 66 Total liabilities assumed 1,736 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 throu gh 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, 2022 2021 (in millions) Indigo GEPH Total Indigo GEPH 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 transfers 1 2 3 7 1 — 8 Due diligence and environmental 1 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 |
Restructuring Charges
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. |
Leases
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) 2023 2022 2021 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 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) 2023 2022 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 Supplemental balance sheet information related to leases is as follows: (in millions) December 31, 2023 December 31, 2022 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 Weighted average remaining lease term: (years) Operating leases 4.1 4.9 Weighted average discount rate: Operating leases 7.50 % 7.32 % Maturity analysis of operating lease liabilities: (in millions) December 31, 2023 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 |
Revenue Recognition
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&P Marketing Intersegment Total Year ended December 31, 2023 Gas sales $ 3,036 $ — $ 53 $ 3,089 Oil sales 374 — 5 379 NGL sales 702 — — 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 sales 434 — 5 439 NGL sales 1,046 — — 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 sales 389 — 5 394 NGL sales 888 — 2 890 Marketing — 6,186 (4,223) 1,963 Other (1) 5 3 — 8 Total $ 4,640 $ 6,189 $ (4,162) $ 6,667 (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) 2023 2022 2021 Appalachia $ 2,543 $ 6,314 $ 3,955 Haynesville 1,566 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, 2023 December 31, 2022 Receivables from contracts with customers $ 622 $ 1,313 Other accounts receivable 58 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. |
Derivatives and Risk Management
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 swaps If the Company sells a fixed price swap, the Company receives a fixed price for the contract, and pays a floating market price to the counterparty. If the Company purchases a fixed price swap, the Company receives a floating market price for the contract, and pays a fixed price to the counterparty. Two-way costless collars Arrangements that contain a fixed floor price (“purchased put option”) and a fixed ceiling price (“sold call option”) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price. Three-way costless collars Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price that, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price. Basis swaps Arrangements that guarantee a price differential for natural gas from a specified delivery point. If the Company sells a basis swap, the Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract, and pays the counterparty if the price differential is less than the stated terms of the contract. If the Company purchases a basis swap, the Company pays the counterparty if the price differential is greater than the stated terms of the contract, and receives a payment from the counterparty if the price differential is less than the stated terms of the contract. Options (Calls and Puts) The Company purchases and sells options in exchange for premiums. If the Company purchases a call option, the Company receives from the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company sells a call option, the Company pays the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company purchases a put option, the Company receives from the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party. If the Company sells a put option, the Company pays the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party. Interest rate swaps Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes. The Company chooses counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company actively monitors the credit ratings and credit default swap rates of these counterparties where applicable. However, there can be no assurance that a counterparty will be able to meet its obligations to the Company. The Company presents its derivative positions on a gross basis and does not net the asset and liability positions. The following tables provide information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of December 31, 2023: Financial Protection on Production Weighted Average Price per MMBtu Fair value at December 31, 2023 ($ in millions) Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Natural Gas 2024 Fixed price swaps 528 $ 3.54 $ — $ — $ — $ — $ 448 Two-way costless collars 44 — — 3.07 3.53 — 22 Three-way costless collars 88 — 2.47 3.20 4.09 — 35 Total 660 $ 505 2025 Two-way costless collars 73 $ — $ — $ 3.50 $ 5.40 $ — $ 31 Three-way costless collars 161 — 2.59 3.66 5.88 — 56 Total 234 $ 87 Basis swaps 2024 82 $ — $ — $ — $ — $ (0.72) $ 8 2025 9 — — — — (0.64) 4 Total 91 $ 12 Weighted Average Price per Bbl Fair value at December 31, 2023 ($ in millions) Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Oil 2024 Fixed price swaps 1,571 $ 71.06 $ — $ — $ — $ (1) Two-way costless collars 512 — — 70.00 85.63 2 Three-way costless collars 92 — 65.00 75.00 93.10 — Total 2,175 $ 1 2025 Fixed price swaps 41 $ 77.66 $ — $ — $ — $ — Three-way costless collars 1,002 — 60.00 70.00 94.64 2 Total 1,043 $ 2 Ethane 2024 Fixed price swaps 4,897 $ 10.61 $ — $ — $ — $ 9 Propane 2024 Fixed price swaps 4,008 $ 31.38 $ — $ — $ — $ 11 2025 Fixed price swaps 63 $ 26.46 $ — $ — — $ — Normal Butane 2024 Fixed price swaps 329 $ 40.74 $ — $ — $ — $ 1 Natural Gasoline 2024 Fixed price swaps 329 $ 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) 2024 82 $ 6.56 $ (1) 2025 73 7.00 (6) 2026 73 7.00 (11) Total 228 $ (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 Classification Fair Value (in millions) December 31, 2023 December 31, 2022 Derivatives not designated as hedging instruments: Fixed price swaps – natural gas Derivative assets $ 466 $ — Fixed price swaps – oil Derivative assets 1 — Fixed price swaps – ethane Derivative assets 9 4 Fixed price swaps – propane Derivative assets 12 9 Fixed price swaps – normal butane Derivative assets 1 1 Fixed price swaps – natural gasoline Derivative assets 2 1 Two-way costless collars – natural gas Derivative assets 36 47 Two-way costless collars – oil Derivative assets 3 — Three-way costless collars – natural gas Derivative assets 62 18 Three-way costless collars – oil Derivative assets 1 1 Basis swaps – natural gas Derivative assets 14 64 Put options – natural gas Derivative assets 8 — Fixed price swaps – natural gas Other long-term assets — 28 Fixed price swaps – oil Other long-term assets — 1 Fixed price swaps – ethane Other long-term assets — 1 Fixed price swaps – propane Other long-term assets — 1 Two-way costless collars – natural gas Other long-term assets 46 18 Three-way costless collars – natural gas Other long-term assets 116 3 Three-way costless collars – oil Other long-term assets 10 — Basis swaps – natural gas Other long-term assets 4 17 Put options – natural gas Other long-term assets — 4 Total derivative assets $ 791 $ 218 Derivative Liabilities Balance Sheet Classification Fair Value (in millions) December 31, 2023 December 31, 2022 Derivatives not designated as hedging instruments: Fixed price swaps – natural gas Derivative liabilities $ 18 $ 581 Fixed price swaps – oil Derivative liabilities 2 20 Fixed price swaps – ethane Derivative liabilities — 1 Fixed price swaps – propane Derivative liabilities 1 — Fixed price swaps – natural gasoline Derivative liabilities — 1 Two-way costless collars – natural gas Derivative liabilities 14 235 Two-way costless collars – oil Derivative liabilities 1 — Three-way costless collars – natural gas Derivative liabilities 27 311 Three-way costless collars – oil Derivative liabilities 1 31 Basis swaps – natural gas Derivative liabilities 6 69 Call options – natural gas Derivative liabilities 1 70 Put options – natural gas Derivative liabilities 8 — Fixed price swaps – natural gas Other long-term liabilities — 281 Fixed price swaps – oil Other long-term liabilities — 4 Two-way costless collars – natural gas Other long-term liabilities 15 56 Three-way costless collars – natural gas Other long-term liabilities 60 20 Three-way costless collars – oil Other long-term liabilities 8 — Basis swaps – natural gas Other long-term liabilities — 1 Call options – natural gas Other long-term liabilities 17 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 Derivative Instrument 2023 2022 (in millions) Fixed price swaps – natural gas Gain (Loss) on Derivatives $ 1,281 $ (166) Fixed price swaps – oil Gain (Loss) on Derivatives 22 46 Fixed price swaps – ethane Gain (Loss) on Derivatives 5 12 Fixed price swaps – propane Gain (Loss) on Derivatives 1 87 Fixed price swaps – normal butane Gain (Loss) on Derivatives — 27 Fixed price swaps – natural gasoline Gain (Loss) on Derivatives 2 34 Two-way costless collars – natural gas Gain (Loss) on Derivatives 279 (116) Two-way costless collars – oil Gain (Loss) on Derivatives 2 — Two-way costless collars – ethane Gain (Loss) on Derivatives — 1 Three-way costless collars – natural gas Gain (Loss) on Derivatives 402 117 Three-way costless collars – oil Gain (Loss) on Derivatives 32 11 Three-way costless collars – propane Gain (Loss) on Derivatives — 4 Basis swaps – natural gas Gain (Loss) on Derivatives 1 (57) Call options – natural gas Gain (Loss) on Derivatives 70 21 Put options – natural gas Gain (Loss) on Derivatives (4) 4 Fixed price swaps – natural gas storage Gain (Loss) on Derivatives — 1 Interest rate swaps Gain (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 Derivative Instrument 2023 2022 (in millions) Fixed price swaps – natural gas Gain (Loss) on Derivatives $ 300 $ (2,918) Fixed price swaps – oil Gain (Loss) on Derivatives (27) (129) Fixed price swaps – ethane Gain (Loss) on Derivatives 6 (49) Fixed price swaps – propane Gain (Loss) on Derivatives 26 (100) Fixed price swaps – normal butane Gain (Loss) on Derivatives 3 (35) Fixed price swaps – natural gasoline Gain (Loss) on Derivatives 1 (49) Two-way costless collars – natural gas Gain (Loss) on Derivatives 48 (448) Two-way costless collars – oil Gain (Loss) on Derivatives (1) — Two-way costless collars – ethane Gain (Loss) on Derivatives — (1) Three-way costless collars – natural gas Gain (Loss) on Derivatives (19) (1,319) Three-way costless collars – oil Gain (Loss) on Derivatives (27) (51) Three-way costless collars – propane Gain (Loss) on Derivatives — (5) Index swaps - natural gas Gain (Loss) on Derivatives — (1) Basis swaps – natural gas Gain (Loss) on Derivatives 43 128 Call options – natural gas Gain (Loss) on Derivatives (8) (304) Purchased fixed price swaps – natural gas storage Gain (Loss) on Derivatives — 1 Fixed price swaps – natural gas storage Gain (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 2023 2022 (in millions) Total gain on unsettled derivatives $ 2,093 $ 24 Total gain (loss) on settled derivatives 345 (5,283) Non-performance risk adjustment (5) — Total gain (loss) on derivatives $ 2,433 $ (5,259) |
Reclassifications from Accumula
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 Postretirement Foreign Currency Total Beginning balance, December 31, 2022 $ 20 $ (14) $ 6 Other comprehensive income before reclassifications 7 — 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) Settlements Other income, net $ (2) Tax valuation allowance release impact on pension settlements Provision for income taxes (14) Total reclassifications for the period Net income $ (16) (1) See Note 13 for additional details regarding the Company’s pension and other postretirement benefit plans. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 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, 2023 December 31, 2022 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents $ 21 $ 21 $ 50 $ 50 2022 revolving credit facility due April 2027 220 220 250 250 Senior notes (1) 3,743 3,626 4,164 3,847 Derivative instruments, net 610 610 (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 Significant Other Observable Inputs Significant Unobservable Inputs 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. |
Debt
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 Instrument Unamortized Issuance Expense Unamortized 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 Instrument Unamortized Issuance Expense Unamortized 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 $ — 2025 389 2026 — 2027 (1) 220 2028 304 Thereafter 3,050 $ 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 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. |
Commitments and Contingencies
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) Total Less than 1 Year 1 to 3 Years 3 to 5 Years 5 to 8 Years More than 8 Years Infrastructure currently in service $ 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. |
Income Taxes
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) 2023 2022 2021 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) 2023 2022 2021 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 — Change in valuation allowance (526) (392) 2 Return to accrual (16) — — Federal research and development credit (13) — — Other 7 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) 2023 2022 Deferred tax liabilities: Differences between book and tax basis of property $ 255 $ 379 Derivative activity 137 — Right of use lease asset 34 41 Accrued pension costs — 1 Other 3 3 429 424 Deferred tax assets: Accrued compensation 53 50 Accrued pension costs 1 — Asset retirement obligations 27 24 Net operating loss carryforward 450 469 Future lease payments 35 41 Derivative activity — 340 Capital loss carryover 26 27 Interest carryover 93 41 Research and development credits 17 — Other 17 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) 2023 2022 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. |
Asset Retirement Obligations
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) 2023 2022 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 |
Retirement and Employee Benefit
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 Benefits Other Postretirement Benefits (in millions) 2023 2022 2023 2022 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 Benefits Other Postretirement Benefits (in millions) 2023 2022 2023 2022 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 Benefits Other Postretirement Benefits (in millions) 2023 2022 2021 2023 2022 2021 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) loss 2 (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 Benefits Other Postretirement Benefits (in millions) 2023 2022 2023 2022 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 2023 2022 2023 2022 Discount rate n/a 5.60 % 5.20 % 5.50 % Rate of compensation increase (2) n/a n/a n/a n/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 2023 2022 2021 2023 2022 2021 Discount rate n/a 5.60 % 3.20 % 5.50 % 3.10 % 2.80 % Expected return on plan assets n/a 0.10 % 0.10 % n/a n/a n/a Rate of compensation increase (2) n/a n/a 3.50 % n/a n/a n/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: 2023 2022 Health care cost trend assumed for next year 7.0 % 7.0 % Rate to which the cost trend is assumed to decline 5.0 % 5.0 % Year that the rate reaches the ultimate trend rate 2041 2040 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) Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Measured within fair value hierarchy Fixed income (1) 69 69 — — Cash and cash equivalents 2 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. |
Long-Term Incentive Compensatio
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) 2023 2022 2021 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) 2023 2022 2021 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: 2023 2022 2021 Number Weighted Average Exercise Price Number of Shares Weighted Average Exercise Price Number of Shares Weighted Average Exercise Price (in thousands) (in thousands) (in thousands) Options outstanding at January 1 997 $ 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 31 820 $ 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) 2023 2022 2021 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: 2023 2022 2021 Number of Weighted Average Fair Value Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested shares at January 1 211 $ 5.81 242 $ 5.12 697 $ 5.97 Granted 336 $ 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 31 169 $ 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) 2023 2022 2021 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. 2023 2022 2021 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) (in thousands) Unvested Units at January 1 1,645 $ 4.44 37 $ 3.05 134 $ 3.05 Granted 1,617 $ 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 31 2,706 $ 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) 2023 2022 2021 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: 2023 2022 2021 Number of Units (1) Weighted Number of Units (1) Weighted Number of Weighted (in thousands) (in thousands) (in thousands) Unvested units at January 1 817 $ 6.04 — $ — — $ — Granted 940 $ 6.12 850 $ 6.04 — $ — Vested — $ — — $ — — $ — Forfeited — $ — (33) $ 6.04 — $ — Unvested shares at December 31 1,757 $ 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) 2023 2022 2021 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) 2023 2022 2021 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: 2023 2022 2021 Number Weighted Average Fair Value Number Weighted Average Fair Value Number Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested units at January 1 3,950 $ 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 31 1,741 $ 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) 2023 2022 2021 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: 2023 2022 2021 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) (in thousands) Unvested units at January 1 10,982 $ 2.25 9,515 $ 2.88 8,699 $ 2.57 Granted 5,136 $ 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 31 12,152 $ 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) 2023 2022 2021 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: 2023 2022 2021 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) Unvested units at January 1 39,994 $ 1.00 28,272 $ 1.00 18,353 $ 1.00 Granted 27,493 $ 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 31 49,678 $ 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. |
Segment Information
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 Marketing Total Reportable Segments Other Total 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 expense 1,302 5 1,307 — 1,307 Impairments 1,710 — 1,710 — 1,710 Operating income (loss) (1,061) 92 (969) (5) (974) Interest expense (1) 142 — 142 — 142 Gain on derivatives 2,433 — 2,433 — 2,433 Loss on early extinguishment of debt — — — (19) (19) Other income, net 2 — 2 — 2 Benefit from income taxes (1) (257) — (257) — (257) Assets 11,253 (2) 591 11,844 147 11,991 Capital investments (3) 2,122 — 2,122 9 2,131 (in millions) Exploration and Production Marketing Total Reportable Segments Other Total 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 expense 1,169 5 1,174 — 1,174 Operating income 7,253 (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, net 3 — 3 — 3 Provision for income taxes (1) 51 — 51 — 51 Assets 11,473 (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 expense 537 9 546 — 546 Impairments 6 — 6 — 6 Operating income 2,583 (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, net 5 — 5 — 5 Provision for income taxes (1) — — — — — Assets 10,767 (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) 2023 2022 2021 Cash and cash equivalents $ 21 $ 50 $ 28 Accounts receivable — 1 — Prepayments 18 14 6 Other current assets 2 — — Property, plant and equipment 24 19 12 Unamortized debt expense 15 19 10 Right-of-use lease assets 49 57 65 Non-qualified retirement plan 3 3 4 Long term assets 15 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. |
Subsequent Events
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. |
Supplemental Oil and Gas Disclo
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) 2023 2022 2021 Unproved property acquisition costs $ 184 $ 202 $ 139 Exploration costs — — — Development costs 1,939 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) 2023 2022 2021 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, 2020 9,181 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, 2021 17,207 79,779 576,964 21,148 Revisions of previous estimates due to price 61 (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, 2022 17,362 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 additions 1,813 5,062 30,444 2,026 Production (1,438) (5,602) (32,859) (1,669) Disposition of reserves in place (350) — — (350) December 31, 2023 15,191 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, 2021 9,308 40,930 296,832 11,335 December 31, 2022 9,793 41,138 350,821 12,145 December 31, 2023 9,196 38,581 362,983 11,605 Proved undeveloped reserves as of: December 31, 2021 7,899 38,849 280,132 9,813 December 31, 2022 7,569 42,248 276,315 9,480 December 31, 2023 5,995 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) Appalachia Haynesville Other (1) Total December 31, 2020 11,989 — 1 11,990 Net revisions Price revisions 415 — — 415 Performance and production revisions (2) 2,271 — (1) 2,270 Total net revisions 2,686 — (1) 2,685 Extensions, discoveries and other additions Proved developed (2) 197 — — 197 Proved undeveloped (2) 1,764 — — 1,764 Total reserve additions 1,961 — — 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, 2021 15,527 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 additions 1,273 1,155 — 2,428 Production (1,054) (679) — (1,733) Acquisition of reserves in place — — — — Disposition of reserves in place (43) — — (43) December 31, 2022 15,666 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 developed 14 66 — 80 Proved undeveloped 769 1,177 — 1,946 Total reserve additions 783 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, 2023 14,685 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) 2023 2022 2021 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) 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: 2023 2022 2021 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) 2023 2022 2021 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 — 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 |
Pay vs Performance Disclosure
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) |
Insider Trading Arrangements
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 |
Organization and Summary of S_2
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. |
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) 2023 2022 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 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, 2023 2022 2021 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) 2023 2022 2021 Prior Total Property acquisition costs $ 63 $ 86 $ 559 $ 1,005 $ 1,713 Exploration and development costs 24 9 8 18 59 Capitalized interest 115 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, 2023 December 31, 2022 Water facilities $ 252 $ 238 Gathering systems 60 56 Technology infrastructure 146 135 Drilling rigs and equipment 35 31 Land, buildings and leasehold improvements 16 16 Other 57 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. |
Derivative Financial Instruments | Derivative Financial Instruments |
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 |
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 |
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. |
Organization and Summary of S_3
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) 2023 2022 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 |
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, 2023 2022 2021 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) 2023 2022 2021 Prior Total Property acquisition costs $ 63 $ 86 $ 559 $ 1,005 $ 1,713 Exploration and development costs 24 9 8 18 59 Capitalized interest 115 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, 2023 December 31, 2022 Water facilities $ 252 $ 238 Gathering systems 60 56 Technology infrastructure 146 135 Drilling rigs and equipment 35 31 Land, buildings and leasehold improvements 16 16 Other 57 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) 2023 2022 2021 Net income (loss) $ 1,557 $ 1,849 $ (25) Number of common shares: Weighted average outstanding 1,100,980,199 1,110,564,839 789,657,776 Issued upon assumed exercise of outstanding stock options — — — Effect of issuance of non-vested restricted common stock 862,434 763,067 — Effect of issuance of non-vested restricted units 1,431,754 1,500,815 — Effect of issuance of non-vested performance units 131,868 355,533 — Weighted average and potential dilutive outstanding 1,103,406,255 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, 2023 2022 2021 Unexercised stock options 831,525 2,265,589 3,683,363 Unvested share-based payment 46,101 53,924 832,989 Restricted units 211,506 192,515 2,226,981 Performance units — — 2,194,477 Total 1,089,132 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) 2023 2022 2021 Cash paid during the year for interest, net of amounts capitalized $ 140 $ 161 $ 106 Cash paid during the year for income taxes 13 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. |
Acquisitions (Tables)
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 issued 99,337,748 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. (in millions, except share, per share amounts) As of September 1, 2021 Shares of Southwestern common stock issued 337,827,171 NYSE closing price per share of Southwestern common shares on September 1, 2021 $ 4.70 $ 1,588 Cash consideration 373 Total consideration $ 1,961 |
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 equivalents 11 Accounts receivable (1) 180 Other current assets (1) 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 (1) 176 Other current liabilities 1 Derivative liabilities 75 Revolving credit facility 81 Asset retirement obligations 24 Other noncurrent liabilities (1) 12 Total liabilities assumed 369 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 equivalents 55 Accounts receivable (2) 193 Other current assets 2 Commodity derivative assets 2 Evaluated oil and gas properties 2,724 Unevaluated oil and gas properties (1) 690 Other property, plant and equipment 4 Other long-term assets 27 Total assets acquired 3,697 Fair Value of Liabilities Assumed: Accounts payable (2) 285 Other current liabilities 55 Derivative liabilities 501 Revolving credit facility 95 Senior unsecured notes 726 Asset retirement obligations 8 Other noncurrent liabilities (2) 66 Total liabilities assumed 1,736 Net Assets Acquired and Liabilities Assumed $ 1,961 (1) Reflects a $6 million adjustment during 2022 due to finalization of purchase accounting. (2) |
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, 2022 2021 (in millions) Indigo GEPH Total Indigo GEPH 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 transfers 1 2 3 7 1 — 8 Due diligence and environmental 1 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. |
Leases (Tables)
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) 2023 2022 2021 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 Supplemental cash flow information related to leases is set forth below: For the years ended December 31, (in millions) 2023 2022 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 |
Supplemental Balance Sheet Information | Supplemental balance sheet information related to leases is as follows: (in millions) December 31, 2023 December 31, 2022 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 Weighted average remaining lease term: (years) Operating leases 4.1 4.9 Weighted average discount rate: Operating leases 7.50 % 7.32 % |
Maturity Analysis of Operating Lease Liabilities | Maturity analysis of operating lease liabilities: (in millions) December 31, 2023 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 |
Revenue Recognition (Tables)
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&P Marketing Intersegment Total Year ended December 31, 2023 Gas sales $ 3,036 $ — $ 53 $ 3,089 Oil sales 374 — 5 379 NGL sales 702 — — 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 sales 434 — 5 439 NGL sales 1,046 — — 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 sales 389 — 5 394 NGL sales 888 — 2 890 Marketing — 6,186 (4,223) 1,963 Other (1) 5 3 — 8 Total $ 4,640 $ 6,189 $ (4,162) $ 6,667 (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) 2023 2022 2021 Appalachia $ 2,543 $ 6,314 $ 3,955 Haynesville 1,566 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, 2023 December 31, 2022 Receivables from contracts with customers $ 622 $ 1,313 Other accounts receivable 58 88 Total accounts receivable $ 680 $ 1,401 |
Derivatives and Risk Manageme_2
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) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Natural Gas 2024 Fixed price swaps 528 $ 3.54 $ — $ — $ — $ — $ 448 Two-way costless collars 44 — — 3.07 3.53 — 22 Three-way costless collars 88 — 2.47 3.20 4.09 — 35 Total 660 $ 505 2025 Two-way costless collars 73 $ — $ — $ 3.50 $ 5.40 $ — $ 31 Three-way costless collars 161 — 2.59 3.66 5.88 — 56 Total 234 $ 87 Basis swaps 2024 82 $ — $ — $ — $ — $ (0.72) $ 8 2025 9 — — — — (0.64) 4 Total 91 $ 12 Weighted Average Price per Bbl Fair value at December 31, 2023 ($ in millions) Volume (MBbls) Swaps Sold Puts Purchased Puts Sold Calls Oil 2024 Fixed price swaps 1,571 $ 71.06 $ — $ — $ — $ (1) Two-way costless collars 512 — — 70.00 85.63 2 Three-way costless collars 92 — 65.00 75.00 93.10 — Total 2,175 $ 1 2025 Fixed price swaps 41 $ 77.66 $ — $ — $ — $ — Three-way costless collars 1,002 — 60.00 70.00 94.64 2 Total 1,043 $ 2 Ethane 2024 Fixed price swaps 4,897 $ 10.61 $ — $ — $ — $ 9 Propane 2024 Fixed price swaps 4,008 $ 31.38 $ — $ — $ — $ 11 2025 Fixed price swaps 63 $ 26.46 $ — $ — — $ — Normal Butane 2024 Fixed price swaps 329 $ 40.74 $ — $ — $ — $ 1 Natural Gasoline 2024 Fixed price swaps 329 $ 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) 2024 82 $ 6.56 $ (1) 2025 73 7.00 (6) 2026 73 7.00 (11) Total 228 $ (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 Classification Fair Value (in millions) December 31, 2023 December 31, 2022 Derivatives not designated as hedging instruments: Fixed price swaps – natural gas Derivative assets $ 466 $ — Fixed price swaps – oil Derivative assets 1 — Fixed price swaps – ethane Derivative assets 9 4 Fixed price swaps – propane Derivative assets 12 9 Fixed price swaps – normal butane Derivative assets 1 1 Fixed price swaps – natural gasoline Derivative assets 2 1 Two-way costless collars – natural gas Derivative assets 36 47 Two-way costless collars – oil Derivative assets 3 — Three-way costless collars – natural gas Derivative assets 62 18 Three-way costless collars – oil Derivative assets 1 1 Basis swaps – natural gas Derivative assets 14 64 Put options – natural gas Derivative assets 8 — Fixed price swaps – natural gas Other long-term assets — 28 Fixed price swaps – oil Other long-term assets — 1 Fixed price swaps – ethane Other long-term assets — 1 Fixed price swaps – propane Other long-term assets — 1 Two-way costless collars – natural gas Other long-term assets 46 18 Three-way costless collars – natural gas Other long-term assets 116 3 Three-way costless collars – oil Other long-term assets 10 — Basis swaps – natural gas Other long-term assets 4 17 Put options – natural gas Other long-term assets — 4 Total derivative assets $ 791 $ 218 Derivative Liabilities Balance Sheet Classification Fair Value (in millions) December 31, 2023 December 31, 2022 Derivatives not designated as hedging instruments: Fixed price swaps – natural gas Derivative liabilities $ 18 $ 581 Fixed price swaps – oil Derivative liabilities 2 20 Fixed price swaps – ethane Derivative liabilities — 1 Fixed price swaps – propane Derivative liabilities 1 — Fixed price swaps – natural gasoline Derivative liabilities — 1 Two-way costless collars – natural gas Derivative liabilities 14 235 Two-way costless collars – oil Derivative liabilities 1 — Three-way costless collars – natural gas Derivative liabilities 27 311 Three-way costless collars – oil Derivative liabilities 1 31 Basis swaps – natural gas Derivative liabilities 6 69 Call options – natural gas Derivative liabilities 1 70 Put options – natural gas Derivative liabilities 8 — Fixed price swaps – natural gas Other long-term liabilities — 281 Fixed price swaps – oil Other long-term liabilities — 4 Two-way costless collars – natural gas Other long-term liabilities 15 56 Three-way costless collars – natural gas Other long-term liabilities 60 20 Three-way costless collars – oil Other long-term liabilities 8 — Basis swaps – natural gas Other long-term liabilities — 1 Call options – natural gas Other long-term liabilities 17 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 Derivative Instrument 2023 2022 (in millions) Fixed price swaps – natural gas Gain (Loss) on Derivatives $ 1,281 $ (166) Fixed price swaps – oil Gain (Loss) on Derivatives 22 46 Fixed price swaps – ethane Gain (Loss) on Derivatives 5 12 Fixed price swaps – propane Gain (Loss) on Derivatives 1 87 Fixed price swaps – normal butane Gain (Loss) on Derivatives — 27 Fixed price swaps – natural gasoline Gain (Loss) on Derivatives 2 34 Two-way costless collars – natural gas Gain (Loss) on Derivatives 279 (116) Two-way costless collars – oil Gain (Loss) on Derivatives 2 — Two-way costless collars – ethane Gain (Loss) on Derivatives — 1 Three-way costless collars – natural gas Gain (Loss) on Derivatives 402 117 Three-way costless collars – oil Gain (Loss) on Derivatives 32 11 Three-way costless collars – propane Gain (Loss) on Derivatives — 4 Basis swaps – natural gas Gain (Loss) on Derivatives 1 (57) Call options – natural gas Gain (Loss) on Derivatives 70 21 Put options – natural gas Gain (Loss) on Derivatives (4) 4 Fixed price swaps – natural gas storage Gain (Loss) on Derivatives — 1 Interest rate swaps Gain (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 Derivative Instrument 2023 2022 (in millions) Fixed price swaps – natural gas Gain (Loss) on Derivatives $ 300 $ (2,918) Fixed price swaps – oil Gain (Loss) on Derivatives (27) (129) Fixed price swaps – ethane Gain (Loss) on Derivatives 6 (49) Fixed price swaps – propane Gain (Loss) on Derivatives 26 (100) Fixed price swaps – normal butane Gain (Loss) on Derivatives 3 (35) Fixed price swaps – natural gasoline Gain (Loss) on Derivatives 1 (49) Two-way costless collars – natural gas Gain (Loss) on Derivatives 48 (448) Two-way costless collars – oil Gain (Loss) on Derivatives (1) — Two-way costless collars – ethane Gain (Loss) on Derivatives — (1) Three-way costless collars – natural gas Gain (Loss) on Derivatives (19) (1,319) Three-way costless collars – oil Gain (Loss) on Derivatives (27) (51) Three-way costless collars – propane Gain (Loss) on Derivatives — (5) Index swaps - natural gas Gain (Loss) on Derivatives — (1) Basis swaps – natural gas Gain (Loss) on Derivatives 43 128 Call options – natural gas Gain (Loss) on Derivatives (8) (304) Purchased fixed price swaps – natural gas storage Gain (Loss) on Derivatives — 1 Fixed price swaps – natural gas storage Gain (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 2023 2022 (in millions) Total gain on unsettled derivatives $ 2,093 $ 24 Total gain (loss) on settled derivatives 345 (5,283) Non-performance risk adjustment (5) — Total gain (loss) on derivatives $ 2,433 $ (5,259) |
Reclassifications from Accumu_2
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 Postretirement Foreign Currency Total Beginning balance, December 31, 2022 $ 20 $ (14) $ 6 Other comprehensive income before reclassifications 7 — 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) Settlements Other income, net $ (2) Tax valuation allowance release impact on pension settlements Provision for income taxes (14) Total reclassifications for the period Net income $ (16) (1) See Note 13 for additional details regarding the Company’s pension and other postretirement benefit plans. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 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, 2023 December 31, 2022 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents $ 21 $ 21 $ 50 $ 50 2022 revolving credit facility due April 2027 220 220 250 250 Senior notes (1) 3,743 3,626 4,164 3,847 Derivative instruments, net 610 610 (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 Significant Other Observable Inputs Significant Unobservable Inputs 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. |
Debt (Tables)
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 Instrument Unamortized Issuance Expense Unamortized 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 Instrument Unamortized Issuance Expense Unamortized 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 |
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 $ — 2025 389 2026 — 2027 (1) 220 2028 304 Thereafter 3,050 $ 3,963 (1) The Company’s 2022 credit facility matures in 2027. |
Commitments and Contingencies (
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) Total Less than 1 Year 1 to 3 Years 3 to 5 Years 5 to 8 Years More than 8 Years Infrastructure currently in service $ 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. |
Income Taxes (Tables)
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) 2023 2022 2021 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) 2023 2022 2021 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 — Change in valuation allowance (526) (392) 2 Return to accrual (16) — — Federal research and development credit (13) — — Other 7 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) 2023 2022 Deferred tax liabilities: Differences between book and tax basis of property $ 255 $ 379 Derivative activity 137 — Right of use lease asset 34 41 Accrued pension costs — 1 Other 3 3 429 424 Deferred tax assets: Accrued compensation 53 50 Accrued pension costs 1 — Asset retirement obligations 27 24 Net operating loss carryforward 450 469 Future lease payments 35 41 Derivative activity — 340 Capital loss carryover 26 27 Interest carryover 93 41 Research and development credits 17 — Other 17 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) 2023 2022 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 |
Asset Retirement Obligations (T
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) 2023 2022 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 |
Retirement and Employee Benef_2
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 Benefits Other Postretirement Benefits (in millions) 2023 2022 2023 2022 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 Benefits Other Postretirement Benefits (in millions) 2023 2022 2023 2022 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 Benefits Other Postretirement Benefits (in millions) 2023 2022 2021 2023 2022 2021 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) loss 2 (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 Benefits Other Postretirement Benefits (in millions) 2023 2022 2023 2022 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) |
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 2023 2022 2023 2022 Discount rate n/a 5.60 % 5.20 % 5.50 % Rate of compensation increase (2) n/a n/a n/a n/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 2023 2022 2021 2023 2022 2021 Discount rate n/a 5.60 % 3.20 % 5.50 % 3.10 % 2.80 % Expected return on plan assets n/a 0.10 % 0.10 % n/a n/a n/a Rate of compensation increase (2) n/a n/a 3.50 % n/a n/a n/a (1) The Company completed the termination of the Plan in 2023. (2) |
Schedule of Health Care Cost Trend Rates | For measurement purposes, the following trend rates were assumed for 2023 and 2022: 2023 2022 Health care cost trend assumed for next year 7.0 % 7.0 % Rate to which the cost trend is assumed to decline 5.0 % 5.0 % Year that the rate reaches the ultimate trend rate 2041 2040 |
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) Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Measured within fair value hierarchy Fixed income (1) 69 69 — — Cash and cash equivalents 2 2 — — Total plan assets at fair value $ 71 $ 71 $ — $ — (1) U.S. Treasury Notes |
Long-Term Incentive Compensat_2
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) 2023 2022 2021 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) 2023 2022 2021 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) 2023 2022 2021 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) 2023 2022 2021 Restricted stock units – general and administrative expense $ 5 $ 2 $ — Restricted stock units – capitalized expense $ 2 $ 2 $ — (in millions) 2023 2022 2021 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) 2023 2022 2021 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) 2023 2022 2021 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: 2023 2022 2021 Number Weighted Average Exercise Price Number of Shares Weighted Average Exercise Price Number of Shares Weighted Average Exercise Price (in thousands) (in thousands) (in thousands) Options outstanding at January 1 997 $ 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 31 820 $ 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: 2023 2022 2021 Number of Weighted Average Fair Value Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested shares at January 1 211 $ 5.81 242 $ 5.12 697 $ 5.97 Granted 336 $ 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 31 169 $ 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. 2023 2022 2021 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) (in thousands) Unvested Units at January 1 1,645 $ 4.44 37 $ 3.05 134 $ 3.05 Granted 1,617 $ 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 31 2,706 $ 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: 2023 2022 2021 Number of Units (1) Weighted Number of Units (1) Weighted Number of Weighted (in thousands) (in thousands) (in thousands) Unvested units at January 1 817 $ 6.04 — $ — — $ — Granted 940 $ 6.12 850 $ 6.04 — $ — Vested — $ — — $ — — $ — Forfeited — $ — (33) $ 6.04 — $ — Unvested shares at December 31 1,757 $ 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) 2023 2022 2021 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) 2023 2022 2021 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: 2023 2022 2021 Number Weighted Average Fair Value Number Weighted Average Fair Value Number Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested units at January 1 3,950 $ 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 31 1,741 $ 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: 2023 2022 2021 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) (in thousands) Unvested units at January 1 10,982 $ 2.25 9,515 $ 2.88 8,699 $ 2.57 Granted 5,136 $ 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 31 12,152 $ 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: 2023 2022 2021 Number Weighted Average Number Weighted Average Number Weighted Average (in thousands) (in thousands) Unvested units at January 1 39,994 $ 1.00 28,272 $ 1.00 18,353 $ 1.00 Granted 27,493 $ 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 31 49,678 $ 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. |
Segment Information (Tables)
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 Marketing Total Reportable Segments Other Total 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 expense 1,302 5 1,307 — 1,307 Impairments 1,710 — 1,710 — 1,710 Operating income (loss) (1,061) 92 (969) (5) (974) Interest expense (1) 142 — 142 — 142 Gain on derivatives 2,433 — 2,433 — 2,433 Loss on early extinguishment of debt — — — (19) (19) Other income, net 2 — 2 — 2 Benefit from income taxes (1) (257) — (257) — (257) Assets 11,253 (2) 591 11,844 147 11,991 Capital investments (3) 2,122 — 2,122 9 2,131 (in millions) Exploration and Production Marketing Total Reportable Segments Other Total 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 expense 1,169 5 1,174 — 1,174 Operating income 7,253 (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, net 3 — 3 — 3 Provision for income taxes (1) 51 — 51 — 51 Assets 11,473 (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 expense 537 9 546 — 546 Impairments 6 — 6 — 6 Operating income 2,583 (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, net 5 — 5 — 5 Provision for income taxes (1) — — — — — Assets 10,767 (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) 2023 2022 2021 Cash and cash equivalents $ 21 $ 50 $ 28 Accounts receivable — 1 — Prepayments 18 14 6 Other current assets 2 — — Property, plant and equipment 24 19 12 Unamortized debt expense 15 19 10 Right-of-use lease assets 49 57 65 Non-qualified retirement plan 3 3 4 Long term assets 15 16 — $ 147 $ 179 $ 125 |
Supplemental Oil and Gas Disc_2
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) 2023 2022 2021 Unproved property acquisition costs $ 184 $ 202 $ 139 Exploration costs — — — Development costs 1,939 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) 2023 2022 2021 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, 2020 9,181 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, 2021 17,207 79,779 576,964 21,148 Revisions of previous estimates due to price 61 (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, 2022 17,362 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 additions 1,813 5,062 30,444 2,026 Production (1,438) (5,602) (32,859) (1,669) Disposition of reserves in place (350) — — (350) December 31, 2023 15,191 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, 2021 9,308 40,930 296,832 11,335 December 31, 2022 9,793 41,138 350,821 12,145 December 31, 2023 9,196 38,581 362,983 11,605 Proved undeveloped reserves as of: December 31, 2021 7,899 38,849 280,132 9,813 December 31, 2022 7,569 42,248 276,315 9,480 December 31, 2023 5,995 39,517 303,804 8,055 The following table summarizes the changes in reserves for 2021, 2022 and 2023: (in Bcfe) Appalachia Haynesville Other (1) Total December 31, 2020 11,989 — 1 11,990 Net revisions Price revisions 415 — — 415 Performance and production revisions (2) 2,271 — (1) 2,270 Total net revisions 2,686 — (1) 2,685 Extensions, discoveries and other additions Proved developed (2) 197 — — 197 Proved undeveloped (2) 1,764 — — 1,764 Total reserve additions 1,961 — — 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, 2021 15,527 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 additions 1,273 1,155 — 2,428 Production (1,054) (679) — (1,733) Acquisition of reserves in place — — — — Disposition of reserves in place (43) — — (43) December 31, 2022 15,666 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 developed 14 66 — 80 Proved undeveloped 769 1,177 — 1,946 Total reserve additions 783 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, 2023 14,685 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) 2023 2022 2021 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) 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: 2023 2022 2021 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) 2023 2022 2021 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 — 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 |
Organization and Summary of S_4
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% | ||||||
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% | 17% | |||||
WPX Property Acquisition | |||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | |||||||
Percentage of voting interest | 86% | ||||||
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 |
Organization and Summary of S_5
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 |
Organization and Summary of S_6
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 |
Organization and Summary of S_7
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 |
Organization and Summary of S_8
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 |
Organization and Summary of S_9
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 |
Organization and Summary of _10
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 |
Organization and Summary of _11
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 |
Acquisitions - (Acquisition Nar
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% |
Acquisitions - (Schedule of Con
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) |
Acquisitions - (Schedule of the
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 |
Acquisitions - (Schedule of C_2
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 |
Acquisitions - (Schedule of t_2
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 |
Acquisitions - (Schedule of Pro
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) |
Acquisitions - (Schedule of Mer
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 |
Restructuring Charges (Summary
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 |
Leases (Narrative) (Details)
Leases (Narrative) (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Leases [Abstract] | |
Operating lease not yet commenced | $ 4 |
Leases (Components of Lease Cos
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 |
Leases (Supplemental Informatio
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% |
Leases (Maturity Analysis) (Det
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 |
Revenue Recognition (Narrative)
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 |
Revenue Recognition (Disaggrega
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 |
Revenue Recognition (Disaggre_2
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 |
Revenue Recognition (Reconcilia
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 |
Derivatives and Risk Manageme_3
Derivatives and Risk Management (Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value) (Details) bbl in Thousands, Mcf in 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 |
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 |
Three-way costless collars - 2023 | Not Designated as Hedging Instrument | Oil | Purchased | |
Derivative [Line Items] | |
Floor price per MMBtu and Bbls | $ / bbl | 75 |
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 |
Three-way Costless-collars - 2024 | Not Designated as Hedging Instrument | Oil | Purchased | |
Derivative [Line Items] | |
Floor price per MMBtu and Bbls | $ / bbl | 70 |
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 |
Fair Value | $ (6) |
Call Option - 2024 | Natural Gas | |
Derivative [Line Items] | |
Volume | Mcf | 73,000 |
Cap price per MMBtu and Bbls | $ / MMBTU | 7 |
Fair Value | $ (11) |
Derivatives and Risk Manageme_4
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 |
Derivatives and Risk Manageme_5
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 |
Derivatives and Risk Manageme_6
Derivatives and Risk Management (Summary of Before Tax Effect of Cash Flow Hedges on Consolidated Financial Statements) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 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 |
Reclassifications from Accumu_3
Reclassifications from Accumulated Other Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 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) |
Reclassifications from Accumu_4
Reclassifications from Accumulated Other Comprehensive Income (Loss) (Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 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) |
Fair Value Measurements (Carryi
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 |
Fair Value Measurements (Narrat
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) |
Fair Value Measurements (Summar
Fair Value Measurements (Summary of Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 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 |
Debt (Components of Debt) (Deta
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% |
Debt (Schedule of Debt Maturiti
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 |
Debt (2022 Revolving Credit Fac
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% | |||||
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 | |||||
Leverage ratio, percentage of credit limit | 10% | |||||
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 | |||||
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% | |||||
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% | |||||
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 |
Debt (Term Loan Credit Agreemen
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 |
Debt (Senior Notes - Narrative)
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 |
Commitments and Contingencies_2
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 |
Commitments and Contingencies_3
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 |
Income Taxes (Provision (Benefi
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 |
Income Taxes (Narrative) (Detai
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% | 0% |
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 |
Income Taxes (Reconciliation of
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 |
Income Taxes (Components of Def
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 |
Income Taxes (Reconciliation _2
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 |
Asset Retirement Obligations (S
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 |
Retirement and Employee Benef_3
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 |
Retirement and Employee Benef_4
Retirement and Employee Benefit Plans (Changes in Plans Benefit Obligations, Fair Value of Assets, and Funded Status) (Details) - USD ($) $ in Millions | 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) |
Retirement and Employee Benef_5
Retirement and Employee Benefit Plans (Projected Benefit Obligation, Accumulated Benefit Obligation and Fair Value of Plan Assets) (Details) - Pension Benefits - USD ($) $ in Millions | Dec. 31, 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 |
Retirement and Employee Benef_6
Retirement and Employee Benefit Plans (Pension and Other Postretirement Benefit Costs) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 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 |
Retirement and Employee Benef_7
Retirement and Employee Benefit Plans (Amounts Recognized in Other Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Total change in value of pension and postretirement liabilities | $ (9) | $ 31 | $ 13 |
Other postretirement benefit, tax effects | 1 | ||
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Net actuarial gain arising during the year | 0 | 30 | |
Amortization of prior service cost | 0 | (2) | |
Tax valuation allowance release impact on pension settlements | (14) | 0 | |
Settlements | (2) | (1) | |
Less: Tax effect (1) | 0 | 0 | |
Total change in value of pension and postretirement liabilities | (16) | 27 | |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Net actuarial gain arising during the year | 7 | 4 | |
Amortization of prior service cost | 0 | 0 | |
Tax valuation allowance release impact on pension settlements | 0 | 0 | |
Settlements | 0 | 0 | |
Less: Tax effect (1) | 0 | 0 | |
Total change in value of pension and postretirement liabilities | $ 7 | $ 4 |
Retirement and Employee Benef_8
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% |
Retirement and Employee Benef_9
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% |
Retirement and Employee Bene_10
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% | 7% |
Rate to which the cost trend is assumed to decline | 5% | 5% |
Year that the rate reaches the ultimate trend rate | 2041 | 2040 |
Retirement and Employee Bene_11
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 |
Long-Term Incentive Compensat_3
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 |
Long-Term Incentive Compensat_4
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 |
Long-Term Incentive Compensat_5
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 |
Long-Term Incentive Compensat_6
Long-Term Incentive Compensation (Summary of Equity-Classified Stock Option Activity) (Details) - $ / shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 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 |
Long-Term Incentive Compensat_7
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 |
Long-Term Incentive Compensat_8
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 |
Long-Term Incentive Compensat_9
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 |
Long-Term Incentive Compensa_10
Long-Term Incentive Compensation (Summary of Equity-Classified Restricted Stock Unit Activity) (Details) - Equity-Classified Restricted Stock Units - $ / shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 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 |
Long-Term Incentive Compensa_11
Long-Term Incentive Compensation (Schedule of Equity-Classified Performance Units Stock-Based Compensation Costs) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 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 |
Long-Term Incentive Compensa_12
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 |
Long-Term Incentive Compensa_13
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 |
Long-Term Incentive Compensa_14
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 |
Long-Term Incentive Compensa_15
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) |
Long-Term Incentive Compensa_16
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 |
Long-Term Incentive Compensa_17
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 | 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 |
Long-Term Incentive Compensa_18
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 |
Long-term Incentive Compensa_19
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 | $ 1 | $ 1 |
Weighted Average Fair Value, Granted (in dollars per share) | 1 | 1 | 1 |
Weighted Average Fair Value, Vested (in dollars per share) | 1 | 1 | 1 |
Weighted Average Fair Value, Forfeited (in dollars per share) | 1 | 1 | 1 |
Weighted Average Fair Value, Unvested shares/units at December 31 (in dollars per share) | $ 1 | $ 1 | $ 1 |
Workforce Reduction | |||
Number of Shares | |||
Number of Shares/Units, Forfeited (in shares) | (1,241,000) |
Segment Information (Schedule o
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 |
Segment Information (Schedule_2
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 |
Subsequent Events (Details)
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 |
Supplemental Oil and Gas Disc_3
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 |
Supplemental Oil and Gas Disc_4
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% | 99% | 99% | |
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 |
Supplemental Oil and Gas Disc_5
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 |
Supplemental Oil and Gas Disc_6
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 |
Supplemental Oil and Gas Disc_7
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 |
Supplemental Oil and Gas Disc_8
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 |
Supplemental Oil and Gas Disc_9
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 |
Supplemental Oil and Gas Dis_10
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 |