Expand Energy (EXE) 10-K 21 Feb 24 2023 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2023	Feb. 15, 2024	Jun. 30, 2023
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-13726
Entity Registrant Name	CHESAPEAKE ENERGY CORPORATION
Entity Incorporation, State or Country Code	OK
Entity Tax Identification Number	73-1395733
Entity Address, Address Line One	6100 North Western Avenue,
Entity Address, City or Town	Oklahoma City,
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73118
City Area Code	(405)
Local Phone Number	848-8000
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			$ 7.6
Entity Common Stock, Shares Outstanding		130,794,770
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE
Amendment Flag	false
Entity Central Index Key	0000895126
Fiscal Year Focus	2023
Fiscal Period Focus	FY
Class A Warrants to purchase Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Class A Warrants to purchase Common Stock
Trading Symbol	CHKEW
Security Exchange Name	NASDAQ
Class B Warrants to purchase Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Class B Warrants to purchase Common Stock
Trading Symbol	CHKEZ
Security Exchange Name	NASDAQ
Class C Warrants to purchase Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Class C Warrants to purchase Common Stock
Trading Symbol	CHKEL
Security Exchange Name	NASDAQ
Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.01 par value per share
Trading Symbol	CHK
Security Exchange Name	NASDAQ

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Audit Information [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Oklahoma City, Oklahoma
Auditor Firm ID	238

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 1,079	$ 130
Restricted cash	74	62
Accounts receivable, net	593	1,438
Short-term derivative assets	637	34
Assets held for sale	0	819
Other current assets	226	215
Total current assets	2,609	2,698
Natural gas and oil properties, successful efforts method
Proved natural gas and oil properties	11,468	11,096
Unproved properties	1,806	2,022
Other property and equipment	497	500
Total property and equipment	13,771	13,618
Less: accumulated depreciation, depletion and amortization	(3,674)	(2,431)
Total property and equipment, net	10,097	11,187
Long-term derivative assets	74	47
Deferred income tax assets	933	1,351
Other long-term assets	663	185
Total assets	14,376	15,468
Current liabilities:
Accounts payable	425	603
Accrued interest	39	42
Short-term derivative liabilities	3	432
Other current liabilities	847	1,627
Total current liabilities	1,314	2,704
Long-term debt, net	2,028	3,093
Long-term derivative liabilities	9	174
Asset retirement obligations, net of current portion	265	323
Other long-term liabilities	31	50
Total liabilities	3,647	6,344
Contingencies and commitments (Note 7)
Stockholders' equity:
Common stock, $0.01 par value, 450,000,000 shares authorized: 130,789,936 and 134,715,094 shares issued	1	1
Additional paid-in capital	5,754	5,724
Retained earnings	4,974	3,399
Total stockholders' equity	10,729	9,124
Total liabilities and stockholders' equity	$ 14,376	$ 15,468

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	130,789,936	134,715,094

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Revenues and other:
Natural gas and oil derivatives	$ (382)	$ (1,127)	$ 1,728	$ (2,680)
Gains on sales of assets	5	12	946	300
Total revenues and other	260	5,549	8,721	11,743
Operating expenses:
Production	32	297	356	475
Gathering, processing and transportation	102	780	853	1,059
Severance and ad valorem taxes	18	158	167	242
Exploration	2	7	27	23
General and administrative	21	97	127	142
Separation and other termination costs	22	11	5	5
Depreciation, depletion and amortization	72	919	1,527	1,753
Impairments	0	1	0	0
Other operating expense (income), net	(12)	84	18	49
Total operating expenses	494	4,611	5,579	7,963
Income (loss) from operations	(234)	938	3,142	3,780
Other income (expense):
Interest expense	(11)	(73)	(104)	(160)
Losses on purchases, exchanges or extinguishments of debt	0	0	0	(5)
Other income	2	31	79	36
Reorganization items, net	5,569	0	0	0
Total other income (expense)	5,560	(42)	(25)	(129)
Income before income taxes	5,326	896	3,117	3,651
Income tax expense (benefit)	(57)	(49)	698	(1,285)
Net income	5,383	945	2,419	4,936
Deemed dividend on warrants	0	0	0	(67)
Net income available to common stockholders, Basic	5,383	945	2,419	4,869
Net income available to common stockholders, Diluted	$ 5,383	$ 945	$ 2,419	$ 4,869
Earnings per common share:
Basic (in dollars per share)	$ 550.35	$ 9.29	$ 18.21	$ 38.71
Diluted (in dollars per share)	$ 534.51	$ 8.12	$ 16.92	$ 33.36
Weighted average common shares outstanding (in thousands):
Basic (in shares)	9,781	101,754	132,840	125,785
Diluted (in shares)	10,071	116,341	142,976	145,961
Natural gas, oil and NGL
Revenues and other:
Revenues	$ 398	$ 4,401	$ 3,547	$ 9,892
Marketing
Revenues and other:
Revenues	239	2,263	2,500	4,231
Operating expenses:
Marketing	$ 237	$ 2,257	$ 2,499	$ 4,215

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
		Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Net income		$ 5,383	$ 945	$ 2,419	$ 4,936
Other comprehensive income, net of income tax:
Reclassification of losses on settled derivative instruments	[1]	3	0	0	0
Other comprehensive income		3	0	0	0
Comprehensive income		$ 5,386	$ 945	$ 2,419	$ 4,936
[1] Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Cash flows from operating activities:
Net income	$ 5,383	$ 945	$ 2,419	$ 4,936
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	72	919	1,527	1,753
Deferred income tax expense (benefit)	(57)	(49)	428	(1,332)
Derivative (gains) losses, net	382	1,127	(1,728)	2,680
Cash receipts (payments) on derivative settlements, net	(17)	(1,142)	354	(3,561)
Share-based compensation	3	9	33	22
Gains on sales of assets	(5)	(12)	(946)	(300)
Impairments	0	1	0	0
Non-cash reorganization items, net	(6,680)	0	0	0
Exploration	2	2	12	14
Losses on purchases, exchanges or extinguishments of debt	0	0	0	5
Other	45	46	6	31
Changes in assets and liabilities	851	(37)	275	(123)
Net cash provided by (used in) operating activities	(21)	1,809	2,380	4,125
Cash flows from investing activities:
Capital expenditures	(66)	(669)	(1,829)	(1,823)
Business combination, net	0	(194)	0	(1,967)
Contributions to investments	0	0	(231)	(18)
Proceeds from divestitures of property and equipment	0	13	2,533	407
Net cash provided by (used in) investing activities	(66)	(850)	473	(3,401)
Cash flows from financing activities:
Proceeds from New Credit Facility	0	0	1,125	1,600
Payments on New Credit Facility	0	0	(2,175)	(550)
Proceeds from Exit Credit Facility	0	30	0	9,583
Payments on Exit Credit Facility	(479)	(80)	0	(9,804)
Payments on DIP Facility borrowings	(1,179)	0	0	0
Proceeds from issuance of senior notes, net	1,000	0	0	0
Proceeds from issuance of common stock	600	0	0	0
Proceeds from warrant exercise	0	2	0	27
Debt issuance and other financing costs	(8)	(3)	0	(17)
Cash paid to repurchase and retire common stock	0	0	(355)	(1,073)
Cash paid for common stock dividends	0	(119)	(487)	(1,212)
Other	0	(1)	0	0
Net cash used in financing activities	(66)	(171)	(1,892)	(1,446)
Net increase (decrease) in cash, cash equivalents and restricted cash	(153)	788	961	(722)
Cash, cash equivalents and restricted cash, beginning of period	279	126	192	914
Cash, cash equivalents and restricted cash, end of period	126	914	1,153	192
Cash and cash equivalents	40	905	1,079	130
Restricted cash	86	9	74	62
Total cash, cash equivalents and restricted cash	126	914	1,153	192
Supplemental cash flow information:
Cash paid for reorganization items, net	66	65	0	0
Interest paid, net of capitalized interest	13	34	117	146
Income taxes paid (refunds received), net	0	(9)	132	193
Supplemental disclosure of significant non-cash investing and financing activities:
Put option premium on equity backstop agreement	60	0	0	0
Common stock issued for business combination	0	1,232	0	764
Operating lease obligations recognized	0	0	96	120
Change in accrued drilling and completion costs
Supplemental disclosure of significant non-cash investing and financing activities:
Change in accrued drilling and completion costs	$ (5)	$ 30	$ (31)	$ 148

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions		Total		Class A Warrants	Class B Warrants	Class C Warrants	Preferred Stock	Common Stock	Additional Paid-in Capital	Additional Paid-in Capital Class A Warrants	Additional Paid-in Capital Class B Warrants	Additional Paid-in Capital Class C Warrants	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income
Preferred stock, shares outstanding, beginning balance (in shares) at Dec. 31, 2020							5,563,358
Beginning balance (in shares) at Dec. 31, 2020								9,780,547
Beginning balance at Dec. 31, 2020		$ (5,341)					$ 1,631	$ 0	$ 16,937				$ (23,954)	$ 45
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation (in shares)								67
Share-based compensation		3							3
Hedging activity		3	[1]											3
Net income		5,383											5,383
Cancellation of Predecessor Equity (in shares)							(5,563,358)	(9,780,614)
Cancellation of Predecessor equity		(48)					$ (1,631)		(16,940)				18,571	(48)
Issuance of Successor common stock (in shares)								97,907,081
Issuance of Successor common stock		3,331						$ 1	3,330
Issuance of warrants				$ 93	$ 94	$ 68				$ 93	$ 94	$ 68
Preferred stock, shares outstanding, end of period (in shares) at Feb. 09, 2021							0
Ending balance (in shares) at Feb. 09, 2021								97,907,081
Ending balance at Feb. 09, 2021		3,586					$ 0	$ 1	3,585				0	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation (in shares)								248,487
Share-based compensation		21							21
Issuance of common stock for Acquisition (in shares)								18,709,399
Issuance of common stock for Acquisition		1,237							1,237
Issuance of common stock for warrant exercise (in shares)								188,292
Issuance of common stock for warrant exercise		2							2
Issuance of reserved common stock and warrants (in shares)								864,090
Hedging activity	[1]	0
Net income		945											945
Dividends on common stock		(120)											(120)
Preferred stock, shares outstanding, end of period (in shares) at Dec. 31, 2021							0
Ending balance (in shares) at Dec. 31, 2021								117,917,349
Ending balance at Dec. 31, 2021		5,671					$ 0	$ 1	4,845				825	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation (in shares)								174,740
Share-based compensation		21							21
Issuance of common stock for Acquisition (in shares)								9,442,185
Issuance of common stock for Acquisition		764							764
Issuance of common stock for warrant exercise (in shares)								2,102,244
Issuance of common stock for warrant exercise		27							27
Repurchase and retirement of common stock (in shares)								(11,666,778)
Repurchase and retirement of common stock		(1,073)											(1,073)
Issuance of common stock for warrant exchange offer (in shares)								16,305,984
Issuance of common stock for warrant exchange offer		67							67
Issuance of reserved common stock and warrants (in shares)								439,370
Hedging activity	[1]	0
Net income		4,936											4,936
Dividends on common stock		(1,222)											(1,222)
Deemed dividend on warrants		(67)
Preferred stock, shares outstanding, end of period (in shares) at Dec. 31, 2022							0
Ending balance (in shares) at Dec. 31, 2022								134,715,094
Ending balance at Dec. 31, 2022		9,124					$ 0	$ 1	5,724				3,399	0
Preferred stock, shares outstanding, beginning balance (in shares) at Dec. 31, 2021							0
Beginning balance (in shares) at Dec. 31, 2021								117,917,349
Beginning balance at Dec. 31, 2021		$ 5,671					$ 0	$ 1	4,845				825	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchase and retirement of common stock (in shares)		(16,040,000)
Repurchase and retirement of common stock		$ (1,430)
Preferred stock, shares outstanding, end of period (in shares) at Dec. 31, 2023							0
Ending balance (in shares) at Dec. 31, 2023								130,789,936
Ending balance at Dec. 31, 2023		10,729					$ 0	$ 1	5,754				4,974	0
Preferred stock, shares outstanding, beginning balance (in shares) at Dec. 31, 2022							0
Beginning balance (in shares) at Dec. 31, 2022								134,715,094
Beginning balance at Dec. 31, 2022		9,124					$ 0	$ 1	5,724				3,399	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation (in shares)								214,684
Share-based compensation		31							31
Issuance of common stock for warrant exercise (in shares)								221,952
Repurchase and retirement of common stock (in shares)								(4,373,883)
Repurchase and retirement of common stock		(358)							(1)				(357)
Issuance of reserved common stock and warrants (in shares)								12,089
Hedging activity	[1]	0
Net income		2,419											2,419
Dividends on common stock		(487)											(487)
Preferred stock, shares outstanding, end of period (in shares) at Dec. 31, 2023							0
Ending balance (in shares) at Dec. 31, 2023								130,789,936
Ending balance at Dec. 31, 2023		$ 10,729					$ 0	$ 1	$ 5,754				$ 4,974	$ 0
[1] Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of Presentation and Summary of Significant Accounting Policies	1. Basis of Presentation and Summary of Significant Accounting Policies Description of Company Chesapeake Energy Corporation ("Chesapeake," “we,” “our,” “us” or the "Company") is a natural gas and oil exploration and production company engaged in the acquisition, exploration and development of properties for the production of natural gas, oil and NGL from underground reservoirs. Our operations are located onshore in the United States. As discussed in Note 2 below, we filed the Chapter 11 Cases on the Petition Date and subsequently operated as a debtor-in-possession, in accordance with applicable provisions of the Bankruptcy Code, until emergence on February 9, 2021. To facilitate our financial statement presentations, we refer to the post-emergence reorganized Company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to February 9, 2021, and to the pre-emergence Company as “Predecessor” for the period on or prior to February 9, 2021. Basis of Presentation The accompanying consolidated financial statements of Chesapeake were prepared in accordance with GAAP and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. This Annual Report on Form 10-K (this “Form 10-K”) relates to the financial position of the Successor as of December 31, 2023 and as of December 31, 2022, and the year ended December 31, 2023 (“2023 Successor Period”), the year ended December 31, 2022 (“2022 Successor Period”), the period of February 10, 2021 through December 31, 2021 (“2021 Successor Period”) and the period of January 1, 2021 through February 9, 2021 (“2021 Predecessor Period”). Accounting During Bankruptcy We have applied Accounting Standards Codification (ASC) 852, Reorganizations, in preparing the consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the filing of a petition of Chapter 11 Cases, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that were realized or incurred during the bankruptcy proceedings, including losses related to executory contracts that were approved for rejection by the Bankruptcy Court, and unamortized debt issuance costs, premiums and discounts associated with debt classified as liabilities subject to compromise, are recorded as reorganization items, net on our accompanying consolidated statements of operations. See Note 2 for more information regarding reorganization items. Accounting Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the related disclosures in the financial statements. Management evaluates its estimates and related assumptions regularly, including those related to the impairment of natural gas and oil properties, natural gas and oil reserves, derivatives, income taxes, impairment of other property and equipment, environmental remediation costs, asset retirement obligations, litigation and regulatory proceedings and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ significantly from these estimates. Consolidation We consolidate entities in which we have a controlling financial interest and variable interest entities in which we are the primary beneficiary. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights. We use the equity method of accounting to record our net interests where we have the ability to exercise significant influence through our investment but lack a controlling financial interest. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. See Note 18 for further discussion of our investments. Undivided interests in natural gas and oil properties are consolidated on a proportionate basis. Segments Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker, who is our Chief Executive Officer, for the purpose of allocating an enterprise’s resources and assessing its operating performance. We have concluded that we have only one reportable operating segment, due to the similar nature of the exploration and production business across Chesapeake and its consolidated subsidiaries and the fact that our marketing activities are ancillary to our operations. Cash and Cash Equivalents For purposes of the consolidated financial statements, we consider investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Restricted Cash As of December 31, 2023, we had restricted cash of $74 million. Our restricted cash represents funds legally restricted for payment of certain convenience class unsecured claims following our emergence from bankruptcy, as well as for future payment of certain royalties. Accounts Receivable Our accounts receivable are primarily from purchasers of natural gas, oil and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. See Note 10 for additional information regarding our accounts receivable. Natural Gas and Oil Properties We follow the successful efforts method of accounting for our natural gas and oil properties. Under this method, exploration costs such as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead and similar activities are also expensed as incurred. All property acquisition costs and development costs are capitalized when incurred. Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and oil are capitalized. Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (“UOP”) method based on total estimated proved developed gas and oil reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Proceeds from the sales of individual natural gas and oil properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. When circumstances indicate that the carrying value of proved natural gas and oil properties may not be recoverable, we compare unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820, Fair Value Measurements . If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted average cost of capital. We have classified these fair value measurements as Level 3 in the fair value hierarchy. Other Property and Equipment Other property and equipment consists primarily of buildings and improvements, computers and office equipment, land and other assets that support our operations. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. Other property and equipment costs, excluding land, are depreciated on a straight-line basis and recorded within depreciation, depletion and amortization in the consolidated statement of operations. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including any disposal value, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. See Note 17 for further discussion of other property and equipment. Assets Held for Sale We may market certain non-core natural gas and oil assets or other properties for sale. At the end of each reporting period, we evaluate if these assets should be classified as held for sale. The held for sale criteria includes the following: management commits to a plan to sell, the asset is available for immediate sale, an active program to locate a buyer exists, the sale of the asset is probable and expected to be completed within a year, the asset is actively being marketed for sale and that it is unlikely that significant changes to the plan will be made. If each of the criteria are met, then the assets and associated liabilities are classified as held for sale. Additionally, once assets are classified as held for sale, we cease depreciation on those related assets. See Note 4 for further discussion. Capitalized Interest Interest from external borrowings is capitalized on significant investments in major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset. Accounts Payable Included in accounts payable as of December 31, 2022 are liabilities of approximately $150 million, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Debt Issuance Costs Costs associated with the arrangement of our credit facilities are included in other long-term assets and are amortized over the life of the facility using the straight-line method. As of December 31, 2023, these costs were $19 million. Upon the termination of the Exit Credit Facility, we recognized $5 million of losses on purchases, exchanges or extinguishment of debt during the 2022 Successor Period relating to lenders who had previously participated in the Exit Credit Facility that chose not to participate in the New Credit Facility. Costs associated with the issuance of the Successor senior notes are included in long-term debt and the remaining unamortized issuance costs are amortized over the life of the senior notes using the straight-line method. Unamortized issuance costs associated with the Successor senior notes as of December 31, 2023 totaled $5 million. Litigation Contingencies We are subject to litigation and regulatory proceedings, claims and liabilities that arise in the ordinary course of business. We accrue losses associated with litigation and regulatory claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, our best estimate within the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or third-party recoveries. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 7 for further discussion of litigation contingencies. Environmental Remediation Costs We record environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized. See Note 7 for discussion of environmental contingencies. Asset Retirement Obligations We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which a natural gas or oil well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our natural gas and oil properties. See Note 20 for further discussion of asset retirement obligations. Revenue Recognition Revenue from the sale of natural gas, oil and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. Revenue from contracts with customers includes the sale of our natural gas, oil and NGL production (recorded as natural gas, oil and NGL revenues in the consolidated statements of operations) as well as the sale of certain of our joint interest holders’ production which we purchase under joint operating arrangements (recorded in marketing revenues in the consolidated statements of operations). In connection with the marketing of these products, we obtain control of the natural gas, oil and NGL we purchase from other interest owners at defined delivery points and deliver the product to third parties, at which time revenues are recorded. See Note 10 for a presentation of the disaggregation of revenue. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 days. There are no significant judgments that significantly affect the amount or timing of revenue from contracts with customers. We also generate revenue from other sources, including from a variety of derivative and hedging activities to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility, as well as a variety of natural gas, oil and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments (recorded within marketing revenues in the consolidated statements of operations). In circumstances where we act as an agent rather than a principal, our results of operations related to natural gas, oil and NGL marketing activities are presented on a net basis. Fair Value Measurements Certain financial instruments are reported on a recurring basis at fair value on our consolidated balance sheets. We also use fair value measurements on a nonrecurring basis when a qualitative assessment of our assets indicates a potential impairment. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). The carrying values of financial instruments comprising cash and cash equivalents, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments. See Notes 6 and 15 for further discussion of fair value measurements. Derivatives Derivative instruments are recorded at fair value, and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. As of December 31, 2023, none of our open derivative instruments were designated as cash flow hedges. Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next 12 months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our commodity derivative instruments are subject to master netting arrangements by contract type which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets. We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 15 for further discussion of our derivative instruments. Share-Based Compensation Our share-based compensation program consists of restricted stock units and performance share units granted to employees and restricted stock units granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of services received in exchange for restricted stock units based on the fair value of the equity instruments as of the grant date. This value is amortized over the vesting period, which is generally three years from the grant date. Forfeitures on our share-based compensation awards are recognized as they occur. Because performance share units are settled in shares, they are classified as equity and are measured at fair value as of the grant date. To the extent compensation expense relates to employees directly involved in the acquisition of natural gas and oil leasehold and development activities, these amounts are capitalized to natural gas and oil properties. Amounts not capitalized to natural gas and oil properties are recognized as general and administrative expense, production expense, or exploration expense, based on the employees involved in those activities. See Note 13 for further discussion of share-based compensation.

Chapter 11 Emergence

Chapter 11 Emergence	12 Months Ended
	Dec. 31, 2023
Reorganizations [Abstract]
Chapter 11 Emergence	2. Chapter 11 Emergence On June 28, 2020 (the “Petition Date”), the Debtors filed voluntary petitions for relief under the Bankruptcy Code in the Bankruptcy Court. On June 29, 2020, the Bankruptcy Court entered an order authorizing the joint administration of the Chapter 11 Cases under the caption In re Chesapeake Energy Corporation , Case No. 20-33233. The Non-Filing Entities were not part of the Chapter 11 Cases. The Debtors and the Non-Filing Entities continued to operate in the ordinary course of business during the Chapter 11 Cases. The Bankruptcy Court confirmed the Plan in a bench ruling on January 13, 2021 and entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on February 9, 2021 (the “Effective Date”). The Company’s bankruptcy proceedings and related matters have been summarized below. Debtor-In-Possession During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted the first day relief we requested that was designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, vendors, suppliers, customers and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the period following the Petition Date and were also authorized to pay mineral interest owner royalties, employee wages and benefits, and certain vendors and suppliers in the ordinary course for goods and services provided prior to the Petition Date. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court. Automatic Stay Subject to certain specific exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed all judicial or administrative actions against us and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to compromise and discharge under the Bankruptcy Code. The automatic stay was lifted on the Effective Date. Plan of Reorganization In accordance with the Plan confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company’s emergence from bankruptcy on February 9, 2021: • On the Effective Date, we issued 97,907,081 shares of New Common Stock, reserved 2,092,918 shares of New Common Stock for future issuance to eligible holders of Allowed Unsecured Notes Claims and Allowed General Unsecured Claims and reserved 37,174,210 shares of New Common Stock for issuance upon exercise of the Warrants, which were the result of the transactions described below. We also entered into a registration rights agreement, warrant agreements and amended our articles of incorporation and bylaws for the authorization of the New Common Stock and to provide registration rights thereunder, among other corporate governance actions. See Note 12 for further discussion of our post-emergence equity. • Each holder of an equity interest in the Predecessor, including the Predecessor’s common and preferred stock, had such interest canceled, released, and extinguished without any distribution. • Each holder of obligations under the pre-petition revolving credit facility received, at such holder's prior determined allocation, its pro rata share of either Tranche A Loans or Tranche B Loans, on a dollar for dollar basis. • Each holder of obligations under the FLLO Term Loan Facility received its pro rata share of 23,022,420 shares of New Common Stock. • Each holder of an Allowed Second Lien Notes Claim received its pro rata share of 3,635,118 shares of New Common Stock, 11,111,111 Class A Warrants to purchase 11,111,111 shares of New Common Stock, 12,345,679 Class B Warrants to purchase 12,345,679 shares of New Common Stock, and 6,858,710 Class C Warrants to purchase 6,858,710 shares of New Common Stock. • Each holder of an Allowed Unsecured Notes Claim received its pro rata share of 1,311,089 shares of New Common Stock and 2,473,757 Class C Warrants to purchase 2,473,757 shares of New Common Stock. • Each holder of an Allowed General Unsecured Claim received its pro rata share of 231,112 shares of New Common Stock and 436,060 Class C Warrants to purchase 436,060 shares of New Common Stock; provided that to the extent such Allowed General Unsecured Claim is a Convenience Claim, such holder instead received its pro rata share of $10 million, which pro rata share shall not exceed five percent of such Convenience Claim. • Participants in the rights offering extending to the applicable classes under the Plan received 62,927,320 shares of New Common Stock. • In connection with the rights offering described above, the Backstop Parties under the Backstop Commitment Agreement received 6,337,031 shares of New Common Stock in respect to the Put Option Premium, and 442,991 shares of New Common Stock were issued in connection with the backstop obligation thereunder to purchase unsubscribed shares of the New Common Stock. • 2,092,918 shares of New Common Stock and 3,948,893 Class C Warrants were reserved for future issuance to eligible holders of Allowed Unsecured Notes Claims and Allowed General Unsecured Claims. The reserved New Common Stock and Class C Warrants will be issued on a pro rata basis upon the determination of the allowed portion of all disputed General Unsecured Claims and Unsecured Notes Claims. • The 2021 Long Term Incentive Plan (the “LTIP”) was approved with a share reserve equal to 6,800,000 shares of New Common Stock. • Each holder of an Allowed Other Secured Claim will receive, at the Company's option and in consultation with the Required Consenting Stakeholders (as defined in the Plan): (a) payment in full in cash; (b) the collateral securing its secured claim; (c) reinstatement of its secured claim; or (d) such other treatment that renders its secured claim unimpaired in accordance with Section 1124 of the Bankruptcy Code. • Each holder of an Allowed Other Priority Claim (as defined in the Plan) will receive cash up to the allowed amount of its claim. Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company’s post-emergence Board of Directors is comprised of seven directors, including the Company’s Chief Executive Officer, Domenic J. Dell’Osso Jr., the Company’s Chairman of the Board, Michael Wichterich, and five non-employee directors, Timothy S. Duncan, Benjamin C. Duster, IV, Sarah A. Emerson, Matthew M. Gallagher and Brian Steck. 3. Fresh Start Accounting Fresh Start Accounting In connection with our emergence from bankruptcy and in accordance with ASC 852, we qualified for and applied fresh start accounting on the Effective Date. We were required to apply fresh start accounting because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Plan of approximately $6.8 billion was less than the post-petition liabilities and allowed claims of $13.2 billion. In accordance with ASC 852, with the application of fresh start accounting, the Company allocated its reorganization value to its individual assets based on their estimated fair value in conformity with FASB ASC Topic 820 - Fair Value Measurements and FASB ASC Topic 805 - Business Combinations . Accordingly, the consolidated financial statements after February 9, 2021 are not comparable with the consolidated financial statements as of or prior to that date. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values, as reflected on the historical balance sheet of the Predecessor. Reorganization Value Reorganization value is derived from an estimate of enterprise value, or fair value of the Company’s interest-bearing debt and stockholders’ equity. Under ASC 852, reorganization value generally approximates fair value of the entity before considering liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after the effects of a restructuring. As set forth in the disclosure statement, amended for updated pricing, and approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $3.5 billion and $4.9 billion. With the assistance of third-party valuation advisors, we determined the enterprise value and corresponding implied equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach. For GAAP purposes, the Company valued the Successor’s individual assets, liabilities and equity instruments and determined an estimate of the enterprise value within the estimated range. Management concluded that the best estimate of enterprise value was $4.85 billion. Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below in greater detail within the valuation process. The enterprise value and corresponding implied equity value are dependent upon achieving the future financial results set forth in our valuation using an asset-based methodology of estimated proved reserves, undeveloped properties, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh start reporting date of February 9, 2021. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, the financial projections, the enterprise value and equity value projections, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially. The following table reconciles the enterprise value to the implied fair value of the Successor’s equity as of the Effective Date: February 9, 2021 Enterprise Value $ 4,851 Plus: Cash and cash equivalents (a) 48 Less: Fair value of debt (1,313) Successor equity value $ 3,586 ____________________________________________ (a) Cash and cash equivalents includes $8 million that was initially classified as restricted cash as of the Effective Date but subsequently released from escrow and returned to the Successor. Restricted cash exclusive of the $8 million is not included in the table above. The following table reconciles the enterprise value to the reorganization value as of the Effective Date: February 9, 2021 Enterprise value $ 4,851 Plus: Cash and cash equivalents (a) 48 Plus: Current liabilities 1,582 Plus: Asset retirement obligations (non-current portion) 236 Plus: Other non-current liabilities 97 Reorganization value of Successor assets $ 6,814 ____________________________________________ (a) Cash and cash equivalents includes $8 million that was initially classified as restricted cash as of the Effective Date but subsequently released from escrow and returned to the Successor. Restricted cash exclusive of the $8 million is not included in the table above. Valuation Process The fair values of our natural gas and oil properties, other property and equipment, other long-term assets, long-term debt, asset retirement obligations and warrants were estimated as of the Effective Date. Natural gas and oil properties. The Company’s principal assets are its natural gas and oil properties, which are accounted for under the successful efforts accounting method. The Company determined the fair value of its natural gas and oil properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area were prepared using the estimated future revenues and operating costs for all proved developed properties and undeveloped properties comprising the proved and unproved reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after five years, adjusted for differentials, and (v) a market-based weighted average cost of capital by operating area. The Company utilized NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions. The discount rates utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type by operating area. Other property and equipment. The fair value of other property and equipment such as buildings, land, computer equipment, and other equipment was determined using the replacement cost method under the cost approach which considers historical acquisition costs for the assets adjusted for inflation, as well as factors in any potential obsolescence based on the current condition of the assets and the ability of those assets to generate cash flow. Long-term debt. A market approach, based upon quotes from major financial institutions, was used to measure the fair value of the $500 million aggregate principal amount of 5.50% Senior Notes due 2026 (the “2026 Notes”) and $500 million aggregate principal amount of 5.875% Senior Notes due 2029 (the “2029 Notes” and, together with the 2026 Notes, the “Notes”). The carrying value of borrowings under our Exit Credit Facility approximated fair value as the terms and interest rates were based on prevailing market rates. Asset retirement obligations. The fair value of the Company’s asset retirement obligations was revalued based upon estimated reclamation costs for our assets with reclamation obligations, an appropriate long-term inflation adjustment, and our revised credit adjusted risk-free rate. The credit adjusted risk-free rate was based on an evaluation of an interest rate that equates to a risk-free interest rate adjusted for the effect of our credit standing. Warrants. The fair values of the Warrants issued upon the Effective Date were estimated using a Black-Scholes model, a commonly used option-pricing model. The Black-Scholes model was used to estimate the fair value of the warrants with an implied stock price of $20.52; initial exercise price per share of $27.63, $32.13 and $36.18 for Class A, Class B and Class C Warrants, respectively; expected volatility of 58% estimated using volatilities of similar entities; risk-free rate using a 5-year Treasury bond rate; and an expected annual dividend yield which was estimated to be zero. Condensed Consolidated Balance Sheet The following consolidated balance sheet is as of February 9, 2021. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Effective Date. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities and warrants. Predecessor Reorganization Adjustments Fresh Start Adjustments Successor Assets Current assets: Cash and cash equivalents $ 243 $ (203) (a) $ — $ 40 Restricted cash — 86 (b) — 86 Accounts receivable, net 861 (18) (c) — 843 Short-term derivative assets — — — — Other current assets 66 (5) (d) — 61 Total current assets 1,170 (140) — 1,030 Property and equipment: Natural gas and oil properties, successful efforts method Proved natural gas and oil properties 25,794 — (21,108) (o) 4,686 Unproved properties 1,546 — (1,063) (o) 483 Other property and equipment 1,755 — (1,256) (o) 499 Total property and equipment 29,095 — (23,427) (o) 5,668 Less: accumulated depreciation, depletion and amortization (23,877) — 23,877 (o) — Property and equipment held for sale, net 9 — (7) (o) 2 Total property and equipment, net 5,227 — 443 (o) 5,670 Other long-term assets 198 — (84) (p) 114 Total assets $ 6,595 $ (140) $ 359 $ 6,814 Predecessor Reorganization Adjustments Fresh Start Adjustments Successor Liabilities and stockholders’ equity (deficit) Current liabilities: Accounts payable $ 391 $ 24 (e) $ — $ 415 Current maturities of long-term debt, net 1,929 (1,929) (f) — — Accrued interest 4 (4) (g) — — Short-term derivative liabilities 398 — — 398 Other current liabilities 645 124 (h) — 769 Total current liabilities 3,367 (1,785) — 1,582 Long-term debt, net — 1,261 (i) 52 (q) 1,313 Long-term derivative liabilities 90 — — 90 Asset retirement obligations, net of current portion 139 — 97 (r) 236 Other long-term liabilities 5 2 (j) — 7 Liabilities subject to compromise 9,574 (9,574) (k) — — Total liabilities 13,175 (10,096) 149 3,228 Contingencies and commitments ( Note 7 ) Stockholders’ equity (deficit): Predecessor preferred stock 1,631 (1,631) (l) — — Predecessor common stock — — — — Predecessor additional paid-in capital 16,940 (16,940) (l) — — Successor common stock — 1 (m) — 1 Successor additional paid-in-capital — 3,585 (m) — 3,585 Accumulated other comprehensive income 48 — (48) (s) — Accumulated deficit (25,199) 24,941 (n) 258 (t) — Total stockholders’ equity (deficit) (6,580) 9,956 210 3,586 Total liabilities and stockholders’ equity (deficit) $ 6,595 $ (140) $ 359 $ 6,814 Reorganization Adjustments (a) The table below reflects the sources and uses of cash on the Effective Date from implementation of the Plan: Sources: Proceeds from issuance of the Notes $ 1,000 Proceeds from Rights Offering 600 Proceeds from refunds of interest deposit for the Notes 5 Total sources of cash $ 1,605 Uses: Payment of roll-up of DIP Facility balance $ (1,179) Payment of Exit Credit Facility - Tranche A Loan (479) Transfers to restricted cash for professional fee reserve (76) Transfers to restricted cash for convenience claim distribution reserve (10) Payment of professional fees (31) Payment of DIP Facility interest and fees (12) Payment of FLLO alternative transaction fee (12) Payment of the Notes fees funded out of escrow (8) Payment of RBL interest and fees (1) Total uses of cash $ (1,808) Net cash used $ (203) (b) Represents the transfer of funds to a restricted cash account for purposes of funding the professional fee reserve and the convenience claim distribution reserve. (c) Reflects the removal of an insurance receivable associated with a discharged legal liability. (d) Reflects the collection of an interest deposit for the senior unsecured notes. (e) Changes in accounts payable include the following: Accrual of professional service provider success fees $ 38 Accrual of convenience claim distribution reserve 10 Accrual of professional service provider fees 5 Reinstatement of accounts payable from liabilities subject to compromise 2 Payment of professional fees (31) Net impact to accounts payable $ 24 (f) Reflects payment of the pre-petition credit facility for $1.179 billion and transfer of the Tranche A and Tranche B Loans to long-term debt for $750 million. (g) Reflects payments of accrued interest and fees on the DIP Facility. (h) Changes in other current liabilities include the following: Reinstatement of other current liabilities from liabilities subject to compromise $ 191 Accrual of the Notes fees 2 Settlement of Put Option Premium through issuance of Successor Common Stock (60) Payment of DIP Facility fees (9) Net impact to other current liabilities $ 124 (i) Changes in long-term debt include the following: Issuance of the Notes $ 1,000 Issuance of Tranche A and Tranche B Loans 750 Payments on Tranche A Loans (479) Debt issuance costs for the Notes (10) Net impact to long-term debt, net $ 1,261 (j) Reflects reinstatement of a long-term lease liability. (k) On the Effective Date, liabilities subject to compromise were settled in accordance with the Plan as follows: Liabilities subject to compromise pre-emergence $ 9,574 To be reinstated on the Effective Date: Accounts payable $ (2) Other current liabilities (191) Other long-term liabilities (2) Total liabilities reinstated $ (195) Consideration provided to settle amounts per the Plan or Reorganization: Issuance of Successor common stock associated with the Rights Offering and Backstop Commitment and settlement of the Put Option Premium $ (2,311) Proceeds from issuance of Successor common stock associated with the Rights Offering and Backstop Commitment 600 Issuance of Successor common stock to FLLO Term Loan holders, incremental to the Rights Offering and Backstop Commitment (783) Issuance of Successor common stock to Second Lien Note holders, incremental to the Rights Offering and Backstop Commitment (124) Issuance of Successor common stock to unsecured note holders (45) Issuance of Successor common stock to General Unsecured Claims (8) Fair value of Class A Warrants (93) Fair value of Class B Warrants (94) Fair value of Class C Warrants (68) Proceeds to holders of general unsecured claims (10) Total consideration provided to settle amounts per the Plan $ (2,936) Gain on settlement of liabilities subject to compromise $ 6,443 (l) Pursuant to the Plan, as of the Effective Date, all equity interests in Predecessor, including Predecessor’s common and preferred stock, were canceled without any distribution. (m) Reflects the Successor equity including the issuance of 97,907,081 shares of New Common Stock, 11,111,111 shares of Class A Warrants, 12,345,679 shares of Class B Warrants and 9,768,527 shares of Class C Warrants pursuant to the Plan. Issuance of Successor equity associated with the Rights Offering and Backstop Commitment $ 2,371 Issuance of Successor equity to holders of the FLLO Term Loan, incremental to the Rights Offering and Backstop Commitment 783 Issuance of Successor equity to holders of the Second Lien Notes, incremental to the Rights Offering and Backstop Commitment 124 Issuance of Successor equity to holders of the unsecured senior notes 45 Issuance of Successor equity to holders of allowed general unsecured claims 8 Fair value of Class A warrants 93 Fair value of Class B warrants 94 Fair value of Class C warrants 68 Total change in Successor common stock and additional paid-in capital 3,586 Less: par value of Successor common stock (1) Change in Successor additional paid-in capital $ 3,585 (n) Reflects the cumulative net impact of the effects on accumulated deficit as follows: Gain on settlement of liabilities subject to compromise $ 6,443 Accrual of professional service provider success fees (38) Accrual of professional service provider fees (5) Surrender of other receivable (18) Payment of FLLO alternative transaction fee (12) Total reorganization items, net 6,370 Cancellation of predecessor equity 18,571 Net impact on accumulated deficit $ 24,941 Fresh Start Adjustments (o) Reflects fair value adjustments to our (i) proved natural gas and oil properties, (ii) unproved properties, (iii) other property and equipment and, (iv) property and equipment held for sale, and the elimination of accumulated depletion, depreciation and amortization. (p) Reflects the fair value adjustment to record historical contracts at their fair values. (q) Reflects the fair value adjustments to the 2026 Notes and 2029 Notes for $22 million and $30 million, respectively. (r) Reflects the adjustment to our asset retirement obligations using assumptions as of the Effective Date, including an inflation factor of 2% and an average credit-adjusted risk-free rate of 5.18%. (s) Reflects the fair value adjustment to eliminate the accumulated other comprehensive income of $9 million related to hedging settlements offset by the elimination of $57 million of income tax effects which has resulted in the recording of an income tax benefit of $57 million. See Note 11 for a discussion of income taxes. (t) Reflects the net cumulative impact of the fresh start adjustments on accumulated deficit as follows: Fresh start adjustments to property and equipment $ 443 Fresh start adjustments to other long-term assets (84) Fresh start adjustments to long-term debt (52) Fresh start adjustments to long-term asset retirement obligations (97) Fresh start adjustments to accumulated other comprehensive income (9) Total fresh start adjustments impacting reorganizations items, net 201 Income tax effects on accumulated other comprehensive income 57 Net impact to accumulated deficit $ 258 Reorganization Items, Net We incurred significant expenses, gains and losses associated with the reorganization, primarily the gain on settlement of liabilities subject to compromise, write-off of unamortized debt issuance costs and related unamortized premiums and discounts, debt and equity financing fees, provision for allowed claims and legal and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The accrual for allowed claims primarily represents damages from contract rejections and settlements attributable to the midstream savings requirement as stipulated in the Plan. While the claims reconciliation process is ongoing, we do not believe any existing unresolved claims will result in a material adjustment to the financial statements. The amount of these items, which were incurred in reorganization items, net within our accompanying consolidated statements of operations, have significantly affected our statements of operations. We did not have any reorganization items, net for the 2023 Successor Period, 2022 Successor Period or the 2021 Successor Period. The following table summarizes the components in reorganization items, net included in our consolidated statements of operations: Predecessor Period from January 1, 2021 through February 9, 2021 Gains on the settlement of liabilities subject to compromise $ 6,443 Accrual for allowed claims (1,002) Gain on fresh start adjustments 201 Gain from release of commitment liabilities 55 Professional service provider fees and other (60) Success fees for professional service providers (38) Surrender of other receivable (18) FLLO alternative transaction fee (12) Total reorganization items, net $ 5,569

Fresh Start Accounting

Fresh Start Accounting	12 Months Ended
	Dec. 31, 2023
Reorganizations [Abstract]
Fresh Start Accounting	2. Chapter 11 Emergence On June 28, 2020 (the “Petition Date”), the Debtors filed voluntary petitions for relief under the Bankruptcy Code in the Bankruptcy Court. On June 29, 2020, the Bankruptcy Court entered an order authorizing the joint administration of the Chapter 11 Cases under the caption In re Chesapeake Energy Corporation , Case No. 20-33233. The Non-Filing Entities were not part of the Chapter 11 Cases. The Debtors and the Non-Filing Entities continued to operate in the ordinary course of business during the Chapter 11 Cases. The Bankruptcy Court confirmed the Plan in a bench ruling on January 13, 2021 and entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on February 9, 2021 (the “Effective Date”). The Company’s bankruptcy proceedings and related matters have been summarized below. Debtor-In-Possession During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted the first day relief we requested that was designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, vendors, suppliers, customers and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the period following the Petition Date and were also authorized to pay mineral interest owner royalties, employee wages and benefits, and certain vendors and suppliers in the ordinary course for goods and services provided prior to the Petition Date. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court. Automatic Stay Subject to certain specific exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed all judicial or administrative actions against us and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to compromise and discharge under the Bankruptcy Code. The automatic stay was lifted on the Effective Date. Plan of Reorganization In accordance with the Plan confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company’s emergence from bankruptcy on February 9, 2021: • On the Effective Date, we issued 97,907,081 shares of New Common Stock, reserved 2,092,918 shares of New Common Stock for future issuance to eligible holders of Allowed Unsecured Notes Claims and Allowed General Unsecured Claims and reserved 37,174,210 shares of New Common Stock for issuance upon exercise of the Warrants, which were the result of the transactions described below. We also entered into a registration rights agreement, warrant agreements and amended our articles of incorporation and bylaws for the authorization of the New Common Stock and to provide registration rights thereunder, among other corporate governance actions. See Note 12 for further discussion of our post-emergence equity. • Each holder of an equity interest in the Predecessor, including the Predecessor’s common and preferred stock, had such interest canceled, released, and extinguished without any distribution. • Each holder of obligations under the pre-petition revolving credit facility received, at such holder's prior determined allocation, its pro rata share of either Tranche A Loans or Tranche B Loans, on a dollar for dollar basis. • Each holder of obligations under the FLLO Term Loan Facility received its pro rata share of 23,022,420 shares of New Common Stock. • Each holder of an Allowed Second Lien Notes Claim received its pro rata share of 3,635,118 shares of New Common Stock, 11,111,111 Class A Warrants to purchase 11,111,111 shares of New Common Stock, 12,345,679 Class B Warrants to purchase 12,345,679 shares of New Common Stock, and 6,858,710 Class C Warrants to purchase 6,858,710 shares of New Common Stock. • Each holder of an Allowed Unsecured Notes Claim received its pro rata share of 1,311,089 shares of New Common Stock and 2,473,757 Class C Warrants to purchase 2,473,757 shares of New Common Stock. • Each holder of an Allowed General Unsecured Claim received its pro rata share of 231,112 shares of New Common Stock and 436,060 Class C Warrants to purchase 436,060 shares of New Common Stock; provided that to the extent such Allowed General Unsecured Claim is a Convenience Claim, such holder instead received its pro rata share of $10 million, which pro rata share shall not exceed five percent of such Convenience Claim. • Participants in the rights offering extending to the applicable classes under the Plan received 62,927,320 shares of New Common Stock. • In connection with the rights offering described above, the Backstop Parties under the Backstop Commitment Agreement received 6,337,031 shares of New Common Stock in respect to the Put Option Premium, and 442,991 shares of New Common Stock were issued in connection with the backstop obligation thereunder to purchase unsubscribed shares of the New Common Stock. • 2,092,918 shares of New Common Stock and 3,948,893 Class C Warrants were reserved for future issuance to eligible holders of Allowed Unsecured Notes Claims and Allowed General Unsecured Claims. The reserved New Common Stock and Class C Warrants will be issued on a pro rata basis upon the determination of the allowed portion of all disputed General Unsecured Claims and Unsecured Notes Claims. • The 2021 Long Term Incentive Plan (the “LTIP”) was approved with a share reserve equal to 6,800,000 shares of New Common Stock. • Each holder of an Allowed Other Secured Claim will receive, at the Company's option and in consultation with the Required Consenting Stakeholders (as defined in the Plan): (a) payment in full in cash; (b) the collateral securing its secured claim; (c) reinstatement of its secured claim; or (d) such other treatment that renders its secured claim unimpaired in accordance with Section 1124 of the Bankruptcy Code. • Each holder of an Allowed Other Priority Claim (as defined in the Plan) will receive cash up to the allowed amount of its claim. Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company’s post-emergence Board of Directors is comprised of seven directors, including the Company’s Chief Executive Officer, Domenic J. Dell’Osso Jr., the Company’s Chairman of the Board, Michael Wichterich, and five non-employee directors, Timothy S. Duncan, Benjamin C. Duster, IV, Sarah A. Emerson, Matthew M. Gallagher and Brian Steck. 3. Fresh Start Accounting Fresh Start Accounting In connection with our emergence from bankruptcy and in accordance with ASC 852, we qualified for and applied fresh start accounting on the Effective Date. We were required to apply fresh start accounting because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Plan of approximately $6.8 billion was less than the post-petition liabilities and allowed claims of $13.2 billion. In accordance with ASC 852, with the application of fresh start accounting, the Company allocated its reorganization value to its individual assets based on their estimated fair value in conformity with FASB ASC Topic 820 - Fair Value Measurements and FASB ASC Topic 805 - Business Combinations . Accordingly, the consolidated financial statements after February 9, 2021 are not comparable with the consolidated financial statements as of or prior to that date. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values, as reflected on the historical balance sheet of the Predecessor. Reorganization Value Reorganization value is derived from an estimate of enterprise value, or fair value of the Company’s interest-bearing debt and stockholders’ equity. Under ASC 852, reorganization value generally approximates fair value of the entity before considering liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after the effects of a restructuring. As set forth in the disclosure statement, amended for updated pricing, and approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $3.5 billion and $4.9 billion. With the assistance of third-party valuation advisors, we determined the enterprise value and corresponding implied equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach. For GAAP purposes, the Company valued the Successor’s individual assets, liabilities and equity instruments and determined an estimate of the enterprise value within the estimated range. Management concluded that the best estimate of enterprise value was $4.85 billion. Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below in greater detail within the valuation process. The enterprise value and corresponding implied equity value are dependent upon achieving the future financial results set forth in our valuation using an asset-based methodology of estimated proved reserves, undeveloped properties, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh start reporting date of February 9, 2021. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, the financial projections, the enterprise value and equity value projections, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially. The following table reconciles the enterprise value to the implied fair value of the Successor’s equity as of the Effective Date: February 9, 2021 Enterprise Value $ 4,851 Plus: Cash and cash equivalents (a) 48 Less: Fair value of debt (1,313) Successor equity value $ 3,586 ____________________________________________ (a) Cash and cash equivalents includes $8 million that was initially classified as restricted cash as of the Effective Date but subsequently released from escrow and returned to the Successor. Restricted cash exclusive of the $8 million is not included in the table above. The following table reconciles the enterprise value to the reorganization value as of the Effective Date: February 9, 2021 Enterprise value $ 4,851 Plus: Cash and cash equivalents (a) 48 Plus: Current liabilities 1,582 Plus: Asset retirement obligations (non-current portion) 236 Plus: Other non-current liabilities 97 Reorganization value of Successor assets $ 6,814 ____________________________________________ (a) Cash and cash equivalents includes $8 million that was initially classified as restricted cash as of the Effective Date but subsequently released from escrow and returned to the Successor. Restricted cash exclusive of the $8 million is not included in the table above. Valuation Process The fair values of our natural gas and oil properties, other property and equipment, other long-term assets, long-term debt, asset retirement obligations and warrants were estimated as of the Effective Date. Natural gas and oil properties. The Company’s principal assets are its natural gas and oil properties, which are accounted for under the successful efforts accounting method. The Company determined the fair value of its natural gas and oil properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area were prepared using the estimated future revenues and operating costs for all proved developed properties and undeveloped properties comprising the proved and unproved reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after five years, adjusted for differentials, and (v) a market-based weighted average cost of capital by operating area. The Company utilized NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions. The discount rates utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type by operating area. Other property and equipment. The fair value of other property and equipment such as buildings, land, computer equipment, and other equipment was determined using the replacement cost method under the cost approach which considers historical acquisition costs for the assets adjusted for inflation, as well as factors in any potential obsolescence based on the current condition of the assets and the ability of those assets to generate cash flow. Long-term debt. A market approach, based upon quotes from major financial institutions, was used to measure the fair value of the $500 million aggregate principal amount of 5.50% Senior Notes due 2026 (the “2026 Notes”) and $500 million aggregate principal amount of 5.875% Senior Notes due 2029 (the “2029 Notes” and, together with the 2026 Notes, the “Notes”). The carrying value of borrowings under our Exit Credit Facility approximated fair value as the terms and interest rates were based on prevailing market rates. Asset retirement obligations. The fair value of the Company’s asset retirement obligations was revalued based upon estimated reclamation costs for our assets with reclamation obligations, an appropriate long-term inflation adjustment, and our revised credit adjusted risk-free rate. The credit adjusted risk-free rate was based on an evaluation of an interest rate that equates to a risk-free interest rate adjusted for the effect of our credit standing. Warrants. The fair values of the Warrants issued upon the Effective Date were estimated using a Black-Scholes model, a commonly used option-pricing model. The Black-Scholes model was used to estimate the fair value of the warrants with an implied stock price of $20.52; initial exercise price per share of $27.63, $32.13 and $36.18 for Class A, Class B and Class C Warrants, respectively; expected volatility of 58% estimated using volatilities of similar entities; risk-free rate using a 5-year Treasury bond rate; and an expected annual dividend yield which was estimated to be zero. Condensed Consolidated Balance Sheet The following consolidated balance sheet is as of February 9, 2021. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Effective Date. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities and warrants. Predecessor Reorganization Adjustments Fresh Start Adjustments Successor Assets Current assets: Cash and cash equivalents $ 243 $ (203) (a) $ — $ 40 Restricted cash — 86 (b) — 86 Accounts receivable, net 861 (18) (c) — 843 Short-term derivative assets — — — — Other current assets 66 (5) (d) — 61 Total current assets 1,170 (140) — 1,030 Property and equipment: Natural gas and oil properties, successful efforts method Proved natural gas and oil properties 25,794 — (21,108) (o) 4,686 Unproved properties 1,546 — (1,063) (o) 483 Other property and equipment 1,755 — (1,256) (o) 499 Total property and equipment 29,095 — (23,427) (o) 5,668 Less: accumulated depreciation, depletion and amortization (23,877) — 23,877 (o) — Property and equipment held for sale, net 9 — (7) (o) 2 Total property and equipment, net 5,227 — 443 (o) 5,670 Other long-term assets 198 — (84) (p) 114 Total assets $ 6,595 $ (140) $ 359 $ 6,814 Predecessor Reorganization Adjustments Fresh Start Adjustments Successor Liabilities and stockholders’ equity (deficit) Current liabilities: Accounts payable $ 391 $ 24 (e) $ — $ 415 Current maturities of long-term debt, net 1,929 (1,929) (f) — — Accrued interest 4 (4) (g) — — Short-term derivative liabilities 398 — — 398 Other current liabilities 645 124 (h) — 769 Total current liabilities 3,367 (1,785) — 1,582 Long-term debt, net — 1,261 (i) 52 (q) 1,313 Long-term derivative liabilities 90 — — 90 Asset retirement obligations, net of current portion 139 — 97 (r) 236 Other long-term liabilities 5 2 (j) — 7 Liabilities subject to compromise 9,574 (9,574) (k) — — Total liabilities 13,175 (10,096) 149 3,228 Contingencies and commitments ( Note 7 ) Stockholders’ equity (deficit): Predecessor preferred stock 1,631 (1,631) (l) — — Predecessor common stock — — — — Predecessor additional paid-in capital 16,940 (16,940) (l) — — Successor common stock — 1 (m) — 1 Successor additional paid-in-capital — 3,585 (m) — 3,585 Accumulated other comprehensive income 48 — (48) (s) — Accumulated deficit (25,199) 24,941 (n) 258 (t) — Total stockholders’ equity (deficit) (6,580) 9,956 210 3,586 Total liabilities and stockholders’ equity (deficit) $ 6,595 $ (140) $ 359 $ 6,814 Reorganization Adjustments (a) The table below reflects the sources and uses of cash on the Effective Date from implementation of the Plan: Sources: Proceeds from issuance of the Notes $ 1,000 Proceeds from Rights Offering 600 Proceeds from refunds of interest deposit for the Notes 5 Total sources of cash $ 1,605 Uses: Payment of roll-up of DIP Facility balance $ (1,179) Payment of Exit Credit Facility - Tranche A Loan (479) Transfers to restricted cash for professional fee reserve (76) Transfers to restricted cash for convenience claim distribution reserve (10) Payment of professional fees (31) Payment of DIP Facility interest and fees (12) Payment of FLLO alternative transaction fee (12) Payment of the Notes fees funded out of escrow (8) Payment of RBL interest and fees (1) Total uses of cash $ (1,808) Net cash used $ (203) (b) Represents the transfer of funds to a restricted cash account for purposes of funding the professional fee reserve and the convenience claim distribution reserve. (c) Reflects the removal of an insurance receivable associated with a discharged legal liability. (d) Reflects the collection of an interest deposit for the senior unsecured notes. (e) Changes in accounts payable include the following: Accrual of professional service provider success fees $ 38 Accrual of convenience claim distribution reserve 10 Accrual of professional service provider fees 5 Reinstatement of accounts payable from liabilities subject to compromise 2 Payment of professional fees (31) Net impact to accounts payable $ 24 (f) Reflects payment of the pre-petition credit facility for $1.179 billion and transfer of the Tranche A and Tranche B Loans to long-term debt for $750 million. (g) Reflects payments of accrued interest and fees on the DIP Facility. (h) Changes in other current liabilities include the following: Reinstatement of other current liabilities from liabilities subject to compromise $ 191 Accrual of the Notes fees 2 Settlement of Put Option Premium through issuance of Successor Common Stock (60) Payment of DIP Facility fees (9) Net impact to other current liabilities $ 124 (i) Changes in long-term debt include the following: Issuance of the Notes $ 1,000 Issuance of Tranche A and Tranche B Loans 750 Payments on Tranche A Loans (479) Debt issuance costs for the Notes (10) Net impact to long-term debt, net $ 1,261 (j) Reflects reinstatement of a long-term lease liability. (k) On the Effective Date, liabilities subject to compromise were settled in accordance with the Plan as follows: Liabilities subject to compromise pre-emergence $ 9,574 To be reinstated on the Effective Date: Accounts payable $ (2) Other current liabilities (191) Other long-term liabilities (2) Total liabilities reinstated $ (195) Consideration provided to settle amounts per the Plan or Reorganization: Issuance of Successor common stock associated with the Rights Offering and Backstop Commitment and settlement of the Put Option Premium $ (2,311) Proceeds from issuance of Successor common stock associated with the Rights Offering and Backstop Commitment 600 Issuance of Successor common stock to FLLO Term Loan holders, incremental to the Rights Offering and Backstop Commitment (783) Issuance of Successor common stock to Second Lien Note holders, incremental to the Rights Offering and Backstop Commitment (124) Issuance of Successor common stock to unsecured note holders (45) Issuance of Successor common stock to General Unsecured Claims (8) Fair value of Class A Warrants (93) Fair value of Class B Warrants (94) Fair value of Class C Warrants (68) Proceeds to holders of general unsecured claims (10) Total consideration provided to settle amounts per the Plan $ (2,936) Gain on settlement of liabilities subject to compromise $ 6,443 (l) Pursuant to the Plan, as of the Effective Date, all equity interests in Predecessor, including Predecessor’s common and preferred stock, were canceled without any distribution. (m) Reflects the Successor equity including the issuance of 97,907,081 shares of New Common Stock, 11,111,111 shares of Class A Warrants, 12,345,679 shares of Class B Warrants and 9,768,527 shares of Class C Warrants pursuant to the Plan. Issuance of Successor equity associated with the Rights Offering and Backstop Commitment $ 2,371 Issuance of Successor equity to holders of the FLLO Term Loan, incremental to the Rights Offering and Backstop Commitment 783 Issuance of Successor equity to holders of the Second Lien Notes, incremental to the Rights Offering and Backstop Commitment 124 Issuance of Successor equity to holders of the unsecured senior notes 45 Issuance of Successor equity to holders of allowed general unsecured claims 8 Fair value of Class A warrants 93 Fair value of Class B warrants 94 Fair value of Class C warrants 68 Total change in Successor common stock and additional paid-in capital 3,586 Less: par value of Successor common stock (1) Change in Successor additional paid-in capital $ 3,585 (n) Reflects the cumulative net impact of the effects on accumulated deficit as follows: Gain on settlement of liabilities subject to compromise $ 6,443 Accrual of professional service provider success fees (38) Accrual of professional service provider fees (5) Surrender of other receivable (18) Payment of FLLO alternative transaction fee (12) Total reorganization items, net 6,370 Cancellation of predecessor equity 18,571 Net impact on accumulated deficit $ 24,941 Fresh Start Adjustments (o) Reflects fair value adjustments to our (i) proved natural gas and oil properties, (ii) unproved properties, (iii) other property and equipment and, (iv) property and equipment held for sale, and the elimination of accumulated depletion, depreciation and amortization. (p) Reflects the fair value adjustment to record historical contracts at their fair values. (q) Reflects the fair value adjustments to the 2026 Notes and 2029 Notes for $22 million and $30 million, respectively. (r) Reflects the adjustment to our asset retirement obligations using assumptions as of the Effective Date, including an inflation factor of 2% and an average credit-adjusted risk-free rate of 5.18%. (s) Reflects the fair value adjustment to eliminate the accumulated other comprehensive income of $9 million related to hedging settlements offset by the elimination of $57 million of income tax effects which has resulted in the recording of an income tax benefit of $57 million. See Note 11 for a discussion of income taxes. (t) Reflects the net cumulative impact of the fresh start adjustments on accumulated deficit as follows: Fresh start adjustments to property and equipment $ 443 Fresh start adjustments to other long-term assets (84) Fresh start adjustments to long-term debt (52) Fresh start adjustments to long-term asset retirement obligations (97) Fresh start adjustments to accumulated other comprehensive income (9) Total fresh start adjustments impacting reorganizations items, net 201 Income tax effects on accumulated other comprehensive income 57 Net impact to accumulated deficit $ 258 Reorganization Items, Net We incurred significant expenses, gains and losses associated with the reorganization, primarily the gain on settlement of liabilities subject to compromise, write-off of unamortized debt issuance costs and related unamortized premiums and discounts, debt and equity financing fees, provision for allowed claims and legal and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The accrual for allowed claims primarily represents damages from contract rejections and settlements attributable to the midstream savings requirement as stipulated in the Plan. While the claims reconciliation process is ongoing, we do not believe any existing unresolved claims will result in a material adjustment to the financial statements. The amount of these items, which were incurred in reorganization items, net within our accompanying consolidated statements of operations, have significantly affected our statements of operations. We did not have any reorganization items, net for the 2023 Successor Period, 2022 Successor Period or the 2021 Successor Period. The following table summarizes the components in reorganization items, net included in our consolidated statements of operations: Predecessor Period from January 1, 2021 through February 9, 2021 Gains on the settlement of liabilities subject to compromise $ 6,443 Accrual for allowed claims (1,002) Gain on fresh start adjustments 201 Gain from release of commitment liabilities 55 Professional service provider fees and other (60) Success fees for professional service providers (38) Surrender of other receivable (18) FLLO alternative transaction fee (12) Total reorganization items, net $ 5,569

Natural Gas and Oil Property Tr

Natural Gas and Oil Property Transactions	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Natural Gas and Oil Property Transactions	4. Natural Gas and Oil Property Transactions Marcellus Acquisition On March 9, 2022, we completed the acquisition of Chief and associated non-operated interests held by affiliates of Tug Hill, of premium drilling locations in the Marcellus Shale in Northeast Pennsylvania (“Marcellus Acquisition”) for total consideration of approximately $2.77 billion, consisting of approximately $2 billion in cash, including working capital adjustments and approximately 9.4 million shares of our common stock, to acquire high quality producing assets and a deep inventory of premium drilling locations in the prolific Marcellus Shale in Northeast Pennsylvania. The Marcellus Acquisition was indebtedness free, effective as of January 1, 2022 and was subject to customary purchase price adjustments. We funded the cash portion of the consideration with cash on hand and $914 million of borrowings under the Company’s Exit Credit Facility. See Note 6 for further discussion of debt. In the 2022 Successor Period, we recognized approximately $41 million of costs related to our Marcellus Acquisition, which included integration costs, consulting fees, financial advisory fees, legal fees and change in control expense in accordance with Chief’s existing employment agreements. These acquisition-related costs are included within other operating expense (income), net within our consolidated statements of operations. Marcellus Acquisition Purchase Price Allocation We have accounted for the Marcellus Acquisition as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. We finalized the acquisition accounting for this transaction during the 2022 Successor Period, which resulted in measurement period adjustments of $39 million to both restricted cash and current liabilities, to reflect funds restricted for future payment of certain royalties . Purchase Price Allocation Consideration: Cash $ 2,000 Fair value of Chesapeake’s common stock issued in the merger (a) 764 Working capital adjustments 6 Total consideration $ 2,770 Fair Value of Liabilities Assumed: Current liabilities $ 459 Other long-term liabilities 129 Amounts attributable to liabilities assumed $ 588 Fair Value of Assets Acquired: Cash, cash equivalents and restricted cash $ 39 Other current assets 218 Proved natural gas and oil properties 2,309 Unproved properties 788 Other property and equipment 1 Other long-term assets 3 Amounts attributable to assets acquired $ 3,358 Total identifiable net assets $ 2,770 ____________________________________________ (a) The fair value of our common stock is a Level 1 input, as our stock price is a quoted price in an active market as of the acquisition date. Natural Gas and Oil Properties For the Marcellus Acquisition, we applied applicable guidance, under which an acquirer should recognize the identifiable assets acquired and the liabilities assumed on the acquisition date at fair value. The fair value estimate of proved and unproved natural gas and oil properties as of the acquisition date was based on estimated natural gas and oil reserves and related future net cash flows discounted using a weighted average cost of capital, including estimates of future production rates and future development costs. We utilized NYMEX strip pricing adjusted for inflation to value the reserves. We then applied various discount rates depending on the classification of reserves and other risk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the natural gas and oil properties acquired. Additionally, the fair value estimate of proved and unproved natural gas and oil properties was corroborated by utilizing a market approach, which considers recent comparable transactions for similar assets. The inputs used to value natural gas and oil properties require significant judgment and estimates made by management and represent Level 3 inputs. Marcellus Acquisition Revenues and Expenses Subsequent to Acquisition We included in our consolidated statements of operations natural gas, oil and NGL revenues of $1,331 million, marketing revenues of $20 million, net losses on natural gas and oil derivatives of $379 million, and direct operating expenses of $483 million, including depreciation, depletion and amortization, related to the Marcellus Acquisition businesses for the period from March 10, 2022 (the date immediately following the completion of the Marcellus Acquisition) through December 31, 2022. Vine Acquisition On November 1, 2021, we acquired Vine, an energy company focused on the development of natural gas properties in the over-pressured stacked Haynesville and Mid-Bossier shale plays in Northwest Louisiana pursuant to a definitive agreement with Vine dated August 10, 2021, for total consideration of approximately $1.5 billion, consisting of approximately 18.7 million shares of our common stock and $90 million in cash. In conjunction with the Vine Acquisition, Vine’s Second Lien Term Loan was repaid and terminated for $163 million inclusive of a $13 million make whole premium with cash on hand due to the agreement containing a change in control provision making the term loan callable upon closing. Vine’s reserve-based loan facility, which had no borrowings as of November 1, 2021, was terminated at the time of the acquisition. Additionally, Vine’s 6.75% Senior Notes, with a principal amount of $950 million were assumed by the Company. See Note 6 for additional discussion of the assumed debt. We funded the cash portion of the consideration with cash on hand. In the 2021 Successor Period, we recognized approximately $59 million of costs related to our acquisition of Vine, which included consulting fees, financial advisory fees, and legal fees. Additionally, we recognized approximately $36 million of severance expense as a result of the Vine Acquisition, which included $15 million of cash severance and $21 million of non-cash severance, primarily related to the issuance of New Common Stock for the acceleration of certain Vine restricted stock unit awards. A majority of Vine executives and employees were terminated on the date of the acquisition. These executives and employees were entitled to severance benefits in accordance with existing employment agreements. These acquisition-related costs are included within other operating expense (income), net within our consolidated statements of operations. Vine Purchase Price Allocation We have accounted for the Vine Acquisition as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of Vine to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. We finalized the acquisition accounting for this transaction during the 2022 Successor Period, which resulted in measurement period adjustments of $19 million to both deferred tax liabilities and unproved properties. See Note 11 for additional information regarding the change to deferred tax liabilities. Purchase Price Allocation Consideration: Cash $ 253 Fair value of Chesapeake’s common stock issued in the merger (a) 1,231 Restricted stock unit replacement awards 6 Total consideration $ 1,490 Fair Value of Liabilities Assumed: Current liabilities $ 765 Long-term debt 1,021 Deferred tax liabilities 30 Other long-term liabilities 272 Amounts attributable to liabilities assumed $ 2,088 Fair Value of Assets Acquired: Cash and cash equivalents $ 59 Other current assets 206 Proved natural gas and oil properties 2,181 Unproved properties 1,099 Other property and equipment 1 Other long-term assets 32 Amounts attributable to assets acquired $ 3,578 Total identifiable net assets $ 1,490 ____________________________________________ (a) The fair value of our common stock is a Level 1 input, as our stock price is a quoted price in an active market as of the acquisition date. Natural Gas and Oil Properties For the Vine Acquisition, we applied applicable guidance, under which an acquirer should recognize the identifiable assets acquired and the liabilities assumed on the acquisition date at fair value. The fair value estimate of proved and unproved natural gas and oil properties as of the acquisition date was based on estimated natural gas and oil reserves and related future net cash flows discounted using a weighted average cost of capital, including estimates of future production rates and future development costs. We utilized NYMEX strip pricing adjusted for inflation to value the reserves. We then applied various discount rates depending on the classification of reserves and other risk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the natural gas and oil properties acquired. Additionally, the fair value estimate of proved and unproved natural gas and oil properties was corroborated by utilizing a market approach, which considers recent comparable transactions for similar assets. The inputs used to value natural gas and oil properties require significant judgment and estimates made by management and represent Level 3 inputs. Financial Instruments and Other The fair value measurements of long-term debt were estimated based on a market approach using estimates provided by an independent investment data services firm and represent Level 2 inputs. Restricted Stock Unit Replacement Awards Included in consideration for the Vine Acquisition is approximately $6 million related to pre-combination service recognized on Vine’s restricted stock unit awards. For restricted stock units that were accelerated or transitioned at the time of the merger, we recognized expense for the portion of the award that was accelerated and included in consideration the portion of the award related to pre-combination service. Vine Revenues and Expenses Subsequent to Acquisition We included in our consolidated statements of operations natural gas, oil and NGL revenues of $290 million, net gains on natural gas and oil derivatives of $144 million, direct operating expenses of $177 million, including depreciation, depletion and amortization, and other expense of $12 million related to the Vine business for the period from November 1, 2021 to December 31, 2021. We included in our consolidated statements of operations natural gas, oil and NGL revenues of $1,863 million, net losses on natural gas and oil derivatives of $624 million, direct operating expenses of $924 million, including depreciation, depletion and amortization, and other expense of $39 million related to the Vine business for the 2022 Successor Period. Combined Pro Forma Financial Information As the Marcellus Acquisition closed on March 9, 2022, all subsequent activity is included in Chesapeake’s consolidated statements of operations for the 2023 Successor Period. As the Vine Acquisition closed on November 1, 2021, all subsequent activity is included in Chesapeake’s consolidated statements of operations for the 2022 Successor Period and 2023 Successor Period. The following unaudited pro forma financial information is based on our historical consolidated financial statements adjusted to reflect as if the Marcellus Acquisition and Vine Acquisition had each occurred on February 10, 2021, the date Chesapeake emerged from bankruptcy. See Note 2 for additional information on the bankruptcy. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including the estimated tax impact of the pro forma adjustments. Successor Year Ended Period from February 10, 2021 through December 31, 2021 Revenues $ 11,743 $ 5,891 Net income (loss) available to common stockholders $ 4,765 $ (5) Earnings (loss) per common share: Basic $ 37.37 $ (0.04) Diluted $ 32.26 $ (0.04) Eagle Ford Divestitures In January 2023, we entered into an agreement to sell a portion of our Eagle Ford assets to WildFire Energy I LLC for approximately $1.425 billion, subject to customary post-closing adjustments. Approximately $225 million of the purchase price was recorded as deferred consideration and treated as a non-interest-bearing note to be paid in installments of $60 million per year for the next three years, with $45 million to be paid in the fourth year following the transaction close date. The deferred consideration is recorded at fair value with an imputed rate of interest as a Level 2 input, and approximately $58 million of the deferred consideration is reflected within other current assets and approximately $135 million is reflected within other long-term assets on the consolidated balance sheets as of December 31, 2023. The divestiture, which closed on March 20, 2023 (with an effective date of October 1, 2022), resulted in a gain of approximately $337 million, inclusive of post-closing adjustments, based on the difference between the carrying value of the assets and consideration received. As of December 31, 2022, approximately $811 million of property and equipment, net, and $8 million of other assets were classified as assets held for sale on the consolidated balance sheets. Additionally, approximately $65 million of derivative liabilities, $57 million of asset retirement obligations and $22 million of other liabilities were classified as held for sale and included within other current liabilities on the consolidated balance sheets as of December 31, 2022. In February 2023, we entered into an agreement to sell a portion of our remaining Eagle Ford assets to INEOS Upstream Holdings Limited (“INEOS Energy”) for approximately $1.4 billion, subject to customary post-closing adjustments. Approximately $225 million of the purchase price was recorded as deferred consideration and treated as a non-interest-bearing note to be paid in installments of approximately $56 million per year for the next four years. The deferred consideration is recorded at fair value with an imputed rate of interest as a Level 2 input, and approximately $55 million of the deferred consideration is reflected within other current assets and approximately $144 million is reflected within other long-term assets on the consolidated balance sheets as of December 31, 2023. The divestiture, which closed on April 28, 2023 (with an effective date of October 1, 2022), resulted in a gain of approximately $470 million, based on the difference between the carrying value of the assets and consideration received. Included within the liabilities assumed by INEOS Energy was approximately $53 million of asset retirement obligations. In August 2023, we entered into an agreement to sell the final portion of our remaining Eagle Ford assets to SilverBow Resources, Inc. (“SilverBow”) for approximately $700 million, subject to customary post-closing adjustments. Approximately $50 million of the purchase price was recorded as deferred consideration and treated as a non-interest-bearing note to be paid one year from the closing date. The deferred consideration is recorded at fair value with an imputed rate of interest as a Level 2 input, and approximately $46 million of the deferred consideration is reflected within other current assets on the consolidated balance sheets as of December 31, 2023. Additionally, SilverBow has agreed to pay Chesapeake an additional contingent payment of $25 million should WTI NYMEX prices average between $75 and $80 per barrel or $50 million should WTI NYMEX prices average above $80 per barrel during the year following the close of the transaction. The fair value of the contingent consideration as of December 31, 2023 of $12 million is reflected within short-term derivative assets within our consolidated balance sheets. See Note 15 for additional information. The divestiture, which closed on November 30, 2023 (with an effective date of February 1, 2023), resulted in a gain of approximately $140 million, based on the difference between the carrying value of the assets and consideration received. Included within the liabilities assumed by SilverBow was approximately $11 million of asset retirement obligations. Powder River Divestiture

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Earnings Per Share	5. Earnings Per Share Basic earnings per common share is computed by dividing the net income available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share is calculated in the same manner but includes the impact of potentially dilutive securities utilizing the treasury stock method. Potentially dilutive securities during the Successor Periods consist of issuable shares related to warrants, unvested restricted stock units, and unvested performance share units and during the Predecessor Period consisted of unvested restricted stock units, contingently issuable shares related to preferred stock and convertible senior notes unless their effect was antidilutive. The reconciliations between basic and diluted earnings per share are as follows: Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Numerator Net income available to common stockholders, basic and diluted $ 2,419 $ 4,869 $ 945 $ 5,383 Denominator (in thousands) Weighted average common shares outstanding, basic 132,840 125,785 101,754 9,781 Effect of potentially dilutive securities Preferred stock — — — 290 Warrants 9,750 19,734 14,376 — Restricted stock units 338 395 200 — Performance share units 48 47 11 — Weighted average common shares outstanding, diluted 142,976 145,961 116,341 10,071 Earnings per common share: Basic $ 18.21 $ 38.71 $ 9.29 $ 550.35 Diluted $ 16.92 $ 33.36 $ 8.12 $ 534.51 Successor During the 2023, 2022 and 2021 Successor Periods, the diluted earnings per share calculation excludes the effect of 777,369, 789,458 and 1,228,828 reserved shares of common stock and 1,466,502, 1,489,337 and 2,318,446 reserved Class C Warrants related to the settlement of General Unsecured Claims associated with the Chapter 11 Cases, as all necessary conditions had not been met for such shares to be considered dilutive shares during the 2023, 2022 and 2021 Successor Periods, respectively. Predecessor We had the option to settle conversions of the 5.50% convertible senior notes due 2026 with cash, shares or common stock or any combination thereof. As the price of our common stock was below the conversion threshold level for any time during the conversion period, there was no impact to diluted earnings per share.

Debt

Debt	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Debt	6. Debt Our long-term debt consisted of the following as of December 31, 2023 and 2022: Successor December 31, 2023 December 31, 2022 Carrying Amount Fair Value (a) Carrying Amount Fair Value (a) New Credit Facility $ — $ — $ 1,050 $ 1,050 5.50% senior notes due 2026 500 496 500 485 5.875% senior notes due 2029 500 489 500 475 6.75% senior notes due 2029 (b) 950 958 950 917 Premiums on senior notes 83 — 100 — Debt issuance costs (5) — (7) — Total long-term debt, net $ 2,028 $ 1,943 $ 3,093 $ 2,927 ____________________________________________ (a) The carrying value of borrowings under our New Credit Facility approximates fair value as the interest rates are based on prevailing market rates; therefore, they are a Level 1 fair value measurement. For all other debt, a market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value. (b) On November 1, 2021, we acquired the debt of Vine, which consisted of 6.75% senior notes due 2029. See further discussion below. The table below presents debt maturities as of December 31, 2023, excluding debt issuance costs and premiums: Total 2024 $ — 2025 — 2026 500 2027 — 2028 — Thereafter 1,450 Total long-term debt $ 1,950 New Credit Facility. In December 2022, we entered into a senior secured reserve-based credit agreement (the “New Credit Agreement”) with the lenders and issuing banks party thereto (the “Lenders”), and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (in such capacity, the “Administrative Agent”), providing for a reserve-based credit facility (the “New Credit Facility”) with an initial borrowing base of $3.5 billion and aggregate commitments of $2.0 billion. The New Credit Facility matures in December 2027. The New Credit Facility provides for a $200 million sublimit available for the issuance of letters of credit and a $50 million sublimit available for swingline loans. As of December 31, 2023, we have approximately $2.0 billion available for borrowings under the New Credit Facility. Initially, the obligations under the New Credit Facility are guaranteed by certain of Chesapeake’s subsidiaries (the “Guarantors”), and the New Credit Facility is secured by substantially all of the assets owned by the Company and the Guarantors (subject to customary exceptions), including mortgages on not less than 85% of the total PV-9 of the borrowing base properties evaluated in the most recent reserve report (where PV-9 is the net present value, discounted at 9% per annum, of the estimated future net revenues). The borrowing base will be redetermined semi-annually in or around April and October of each year, with one interim “wildcard” redetermination available to each of the Company and the Administrative Agent, the latter at the direction of the Required Lenders (as defined in the New Credit Agreement), between scheduled redeterminations. Our borrowing base was reaffirmed in October 2023, and the next scheduled redetermination will be in or around April 2024. The New Credit Agreement contains restrictive covenants that limit Chesapeake and its subsidiaries’ ability to, among other things but subject to exceptions customary to reserve-based credit facilities: (i) incur additional indebtedness, (ii) make investments, (iii) enter into mergers; (iv) make or declare dividends; (v) repurchase or redeem certain indebtedness; (vi) enter into certain hedges; (vii) incur liens; (viii) sell assets; and (ix) engage in certain transactions with affiliates. The New Credit Agreement requires Chesapeake to maintain compliance with the following financial ratios: (A) a current ratio, which is the ratio of Chesapeake’s and its restricted subsidiaries’ consolidated current assets (including unused commitments under the New Credit Facility but excluding certain non-cash assets) to their consolidated current liabilities (excluding the current portion of long-term debt and certain non-cash liabilities), of not less than 1.00 to 1.00; (B) a net leverage ratio, which is the ratio of total indebtedness (less unrestricted cash up to a specified threshold) to Consolidated EBITDAX (as defined in the Credit Agreement) for the prior four fiscal quarters, of not greater than 3.50 to 1.00 and (C) 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 Chesapeake’s and its restricted subsidiaries’ total indebtedness of not less than 1.50 to 1.00. Borrowings under the New Credit Agreement may be alternate base rate loans or term SOFR loans, at our election. Interest is payable quarterly for alternate base rate loans and at the end of the applicable interest period for term SOFR loa ns. Term SOFR loans bear interest at term SOFR plus an applicable rate ranging from 175 to 275 basis points per annum, depending on the percentage of the commitments utilized, plus an additional 10 basis points per annum credit spread adjustment. Alternate base rate loans bear interest at a rate per annum equal to the greatest of: (i) the prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted term SOFR rate for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points per annum, depending on the percentage of the commitments utilized. Chesapeake also pays a commitment fee on unused commitment amounts under the Credit Facility ranging from 37.5 to 50 basis points per annum, depending on the percentage of the commitments utilized. The New Credit Facility is subject to customary events of default, remedies, and cure rights for credit facilities of this nature. Exit Credit Facility. On the Effective Date, pursuant to the terms of the Plan, the Company, as borrower, entered into a reserve-based credit agreement (the “Credit Agreement”) providing for a reserve-based credit facility with an initial borrowing base of $2.5 billion. The aggregate initial elected commitments of the lenders under the Exit Credit Facility were $1.75 billion of Tranche A Loans and $221 million of fully funded Tranche B Loans. The Exit Credit Facility provided for a $200 million sublimit of the aggregate commitments that was available for the issuance of letters of credit. The Exit Credit Facility bore interest at the ABR (alternate base rate) or LIBOR, at our election, plus an applicable margin (ranging from 2.25–3.25% per annum for ABR loans and 3.25–4.25% per annum for LIBOR loans, subject to a 1.00% LIBOR floor), depending on the percentage of the borrowing base then being utilized. The Tranche A Loans were due to mature three years after the Effective Date and the Tranche B Loans were due to mature four years after the Effective Date. The Company was required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Tranche A Loans. The Credit Agreement was subject to various financial and other covenants and also contained customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, and other customary covenants. In December 2022, the Tranche A Loans and Tranche B Loans were both repaid and the Exit Credit Facility was terminated. Borrowings under our credit agreements bore interest at an average interest rate of 8.7% during the 2022 Successor Period. The Company has no additional secured debt as of December 31, 2023. Outstanding Senior Notes. On February 2, 2021, Chesapeake Escrow Issuer LLC, then an indirect wholly owned subsidiary of the Company, issued $500 million aggregate principal amount of its 2026 Notes and $500 million aggregate principal amount of its 2029 Notes. The Notes included a $52 million premium to reflect fair value adjustments at the date of emergence. The Notes are guaranteed on a senior unsecured basis by each of the Company’s subsidiaries that guaranteed the Exit Credit Facility. The Notes were issued pursuant to an indenture, dated as of February 5, 2021, among the Issuer, the guarantor party thereto and Deutsche Bank Trust Company Americas, as trustee. Interest on the Notes is payable semi-annually, on February 1 and August 1 of each year to holders of record on the immediately preceding January 15 and July 15. Vine Senior Notes As a result of the completion of the Vine Acquisition, the Company and certain of its subsidiaries entered into a supplemental indenture pursuant to which the Company assumed the obligations under Vine’s $950 million aggregate principal amount of 6.75% senior notes due 2029 (the “Vine Notes”) issued under the indenture dated April 7, 2021 with Wilmington Trust, National Association, as Trustee (the “Vine Indenture”). The Vine Notes included a $71 million premium to reflect fair value adjustments at the date of acquisition. The Company and certain of its subsidiaries have agreed to guarantee such obligations under the Vine Indenture. Additionally, certain subsidiaries of Vine entered into a supplemental indenture to the Company’s existing indenture, dated February 5, 2021, with Deutsche Bank Trust Company Americas as trustee (the “CHK Indenture”), pursuant to which such subsidiaries of Vine have agreed to guarantee obligations under the CHK Indenture. Interest on the Vine Notes is payable semi-annually, on April 15 and October 15 of each year to holders of record on the immediately preceding April 1 and October 1. The Notes and the Vine Notes are the Company’s senior unsecured obligations. Accordingly, they rank (i) equal in right of payment to all existing and future senior unsecured indebtedness, (ii) effectively subordinate in right of payment to all existing and future secured indebtedness, including indebtedness under the New Credit Facility, to the extent of the value of the collateral securing such indebtedness, (iii) structurally subordinate in right of payment to all existing and future indebtedness and other liabilities of any future subsidiaries that do not guarantee the Notes and any entity that is not a subsidiary that does not guarantee the Notes and (iv) senior in right of payment to all future subordinated indebtedness. Each guarantee of the Notes by a guarantor is a general, unsecured, senior obligation of such guarantor. Accordingly, the guarantees (i) rank equally in right of payment with all existing and future senior indebtedness of such guarantor (including such guarantor’s guarantee of indebtedness under the New Credit Facility), (ii) are subordinated to all existing and future secured indebtedness of such guarantor, including such guarantor’s guarantee of indebtedness under our New Credit Facility, to the extent of the value of the collateral of such guarantor securing such secured indebtedness, (iii) are structurally subordinated to all indebtedness and other liabilities of any future subsidiaries of such guarantor that do not guarantee the notes and (iv) rank senior in right of payment to all future subordinated indebtedness of such guarantor.

Contingencies and Commitments

Contingencies and Commitments	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Contingencies and Commitments	7. Contingencies and Commitments Contingencies Business Operations and Litigation and Regulatory Proceedings We are involved in, and expect to continue to be involved in, various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. Our total accrued liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates, and our final liabilities may ultimately be materially different. The majority of the Company’s pre-petition legal proceedings were settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court, together with actions seeking to collect pre-petition indebtedness or to exercise control over the property of the Company’s bankruptcy estates. Any allowed claim related to such litigation will be treated in accordance with the Plan. The Plan in the Chapter 11 Cases, which became effective on February 9, 2021, provided for the treatment of claims against the Company’s bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases. Many of these proceedings were in early stages, and many of them sought damages and penalties, the amount of which is indeterminate. See Note 2 for additional information. Environmental Contingencies The nature of the natural gas and oil business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property. Other Matters Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates. Commitments Gathering, Processing and Transportation Agreements We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas, oil and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in our estimates of proved reserves. The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below: Successor December 31, 2023 2024 $ 284 2025 255 2026 235 2027 208 2028 194 2029-2036 956 Total $ 2,132 During the 2023 Successor Period, certain gathering, processing and transportation agreements were transferred to the buyers of our Eagle Ford assets. In addition, we have long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually, or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees may vary with the applicable agreement. Other Commitments As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance. In connection with acquisitions and divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of natural gas and oil properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title or environmental defects.

Other Liabilities

Other Liabilities	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Other Liabilities	8. Other Liabilities Other current liabilities as of December 31, 2023 and 2022 are detailed below: Successor December 31, 2023 December 31, 2022 Revenues and royalties due to others $ 360 $ 734 Accrued drilling and production costs 211 253 Accrued hedging costs 2 109 Accrued compensation and benefits 64 72 Taxes payable 84 84 Operating leases 84 86 Joint interest prepayments received 8 34 Current liabilities held for sale (a) — 144 Other 34 111 Total other current liabilities $ 847 $ 1,627 _________________________________________ (a) As of December 31, 2022, certain liabilities associated with the sale of a portion of our Eagle Ford assets were classified as current liabilities held for sale. See Note 4

Leases

Leases	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Leases	9. Leases We are a lessee under various agreements for drilling rigs, compressors, vehicles and gas treating plants. As of December 31, 2023, these leases have remaining terms ranging from one month to three years. Certain of our lease agreements include options to renew the lease, terminate the lease early or purchase the underlying asset at the end of the lease. We determine 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 we are reasonably certain to exercise the option. The company’s vehicles are the only leases with renewal options that we are reasonably certain to exercise. The renewals are reflected in the right of use (“ROU”) asset and lease liability balances. Our operating ROU assets are included in other long-term assets The following table presents our ROU assets and lease liabilities as of December 31, 2023 and 2022. As of December 31, 2023 and 2022, we did not have any finance leases. Successor Operating Leases December 31, 2023 December 31, 2022 ROU assets $ 99 $ 119 Lease liabilities: Current lease liabilities $ 84 $ 86 Long-term lease liabilities 15 33 Total lease liabilities, net $ 99 $ 119 Additional information for the Company’s operating and finance leases is presented below: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Lease cost: Finance lease cost $ — $ — $ — $ 1 Operating lease cost 107 51 33 3 Short-term lease cost 40 74 13 — Total lease cost $ 147 $ 125 $ 46 $ 4 Other information: Operating cash outflows from operating leases $ 10 $ 15 $ 7 $ — Investing cash outflows from operating leases $ 137 $ 110 $ 39 $ 3 Financing cash outflows from finance lease $ — $ — $ — $ 1 Successor December 31, 2023 December 31, 2022 Weighted average remaining lease term - operating leases 1.24 years 1.54 years Weighted average discount rate - operating leases 7.02 % 6.64 % Maturity analysis of operating lease liabilities is presented below: Successor December 31, 2023 2024 $ 85 2025 17 2026 1 Total lease payments 103 Less imputed interest (4) Present value of lease liabilities 99 Less current maturities (84) Present value of lease liabilities, less current maturities $ 15
Leases	9. Leases We are a lessee under various agreements for drilling rigs, compressors, vehicles and gas treating plants. As of December 31, 2023, these leases have remaining terms ranging from one month to three years. Certain of our lease agreements include options to renew the lease, terminate the lease early or purchase the underlying asset at the end of the lease. We determine 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 we are reasonably certain to exercise the option. The company’s vehicles are the only leases with renewal options that we are reasonably certain to exercise. The renewals are reflected in the right of use (“ROU”) asset and lease liability balances. Our operating ROU assets are included in other long-term assets The following table presents our ROU assets and lease liabilities as of December 31, 2023 and 2022. As of December 31, 2023 and 2022, we did not have any finance leases. Successor Operating Leases December 31, 2023 December 31, 2022 ROU assets $ 99 $ 119 Lease liabilities: Current lease liabilities $ 84 $ 86 Long-term lease liabilities 15 33 Total lease liabilities, net $ 99 $ 119 Additional information for the Company’s operating and finance leases is presented below: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Lease cost: Finance lease cost $ — $ — $ — $ 1 Operating lease cost 107 51 33 3 Short-term lease cost 40 74 13 — Total lease cost $ 147 $ 125 $ 46 $ 4 Other information: Operating cash outflows from operating leases $ 10 $ 15 $ 7 $ — Investing cash outflows from operating leases $ 137 $ 110 $ 39 $ 3 Financing cash outflows from finance lease $ — $ — $ — $ 1 Successor December 31, 2023 December 31, 2022 Weighted average remaining lease term - operating leases 1.24 years 1.54 years Weighted average discount rate - operating leases 7.02 % 6.64 % Maturity analysis of operating lease liabilities is presented below: Successor December 31, 2023 2024 $ 85 2025 17 2026 1 Total lease payments 103 Less imputed interest (4) Present value of lease liabilities 99 Less current maturities (84) Present value of lease liabilities, less current maturities $ 15

Revenue

Revenue	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Revenue	10. Revenue The following tables show revenue disaggregated by operating area and product type, for the periods presented: Successor Year Ended December 31, 2023 Natural Gas Oil NGL Total Marcellus $ 1,483 $ — $ — $ 1,483 Haynesville 1,300 — — 1,300 Eagle Ford 70 596 98 764 Natural gas, oil and NGL revenue $ 2,853 $ 596 $ 98 $ 3,547 Marketing revenue $ 989 $ 1,332 $ 179 $ 2,500 Successor Year Ended December 31, 2022 Natural Gas Oil NGL Total Marcellus $ 4,041 $ — $ — $ 4,041 Haynesville 3,481 — — 3,481 Eagle Ford 261 1,798 212 2,271 Powder River Basin 20 66 13 99 Natural gas, oil and NGL revenue $ 7,803 $ 1,864 $ 225 $ 9,892 Marketing revenue $ 2,455 $ 1,547 $ 229 $ 4,231 Successor Period from February 10, 2021 through December 31, 2021 Natural Gas Oil NGL Total Marcellus $ 1,370 $ — $ — $ 1,370 Haynesville 998 — — 998 Eagle Ford 179 1,354 179 1,712 Powder River Basin 75 202 44 321 Natural gas, oil and NGL revenue $ 2,622 $ 1,556 $ 223 $ 4,401 Marketing revenue $ 908 $ 1,158 $ 197 $ 2,263 Predecessor Period from January 1, 2021 through February 9, 2021 Natural Gas Oil NGL Total Marcellus $ 119 $ — $ — $ 119 Haynesville 53 — — 53 Eagle Ford 17 159 17 193 Powder River Basin 7 20 6 33 Natural gas, oil and NGL revenue $ 196 $ 179 $ 23 $ 398 Marketing revenue $ 78 $ 141 $ 20 $ 239 Major Customers For the 2023 Successor Period, sales to Valero Energy Corporation and Shell Energy North America accounted for approximately 17% and 10%, respectively, of total revenues (before the effects of hedging). For the 2022 Successor Period, sales to Shell Energy North America and Valero Energy Corporation accounted for approximately 13% and 10%, respectively, of total revenues (before the effects of hedging). For the 2021 Successor Period, sales to Valero Energy Corporation and Energy Transfer Crude Marketing accounted for approximately 14% and 11%, respectively, of total revenues (before the effects of hedging). For the 2021 Predecessor Period, sales to Valero Energy Corporation accounted for approximately 19% of total revenues (before the effects of hedging). No other purchasers accounted for more than 10% of our total revenues during the 2023 Successor Period, 2022 Successor Period, 2021 Successor Period or 2021 Predecessor Period. Accounts Receivable Accounts receivable as of December 31, 2023 and 2022 are detailed below: Successor December 31, 2023 December 31, 2022 Natural gas, oil and NGL sales $ 406 $ 1,171 Joint interest 180 246 Other 8 24 Allowance for doubtful accounts (1) (3) Total accounts receivable, net $ 593 $ 1,438

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	11. Income Taxes The components of the income tax expense (benefit) for each of the periods presented below are as follows: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Current Federal $ 264 $ 37 $ — $ — State 6 10 — — Current Income Taxes 270 47 — — Deferred Federal 381 (1,112) (45) (54) State 47 (220) (4) (3) Deferred Income Taxes 428 (1,332) (49) (57) Total $ 698 $ (1,285) $ (49) $ (57) The income tax expense (benefit) reported in our consolidated statement of operations is different from the federal income tax expense (benefit) computed using the federal statutory rate for the following reasons: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Income tax expense (benefit) at the federal statutory rate of 21% $ 655 $ 767 $ 188 $ 1,119 State income taxes (net of federal income tax benefit) 56 75 (86) 238 Change in valuation allowance due to Acquisitions — 19 (49) — Change in valuation allowance excluding impact of Acquisitions (33) (2,147) (179) (1,191) Reorganization items — — 60 (173) Transaction costs — 2 11 — Removal of stranded tax effects in accumulated other comprehensive income — — — (57) Other 20 (1) 6 7 Total $ 698 $ (1,285) $ (49) $ (57) Our state income tax provision is affected by changes in our state apportionment, changes in state tax rates, as well as state specific tax adjustments. Shifts in our state apportionment factors may cause our deferred taxes to be remeasured. The 2021 Successor Period resulted in a state tax benefit as a result of the Vine acquisition causing an increase to our Louisiana deferred tax asset. We recognize certain permanent book-to-tax differences relating to reorganization items such as differences in the treatment of the extinguishment of liabilities and differences due to the non-deductibility of certain expenses associated with administering the plan of reorganization. Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences, net operating loss (“NOL”) carryforwards and excess business interest expense carryforwards that comprise our deferred income taxes are as follows: Successor December 31, 2023 December 31, 2022 Deferred tax liabilities: Property, plant and equipment $ (295) $ (253) Derivative instruments (166) — Right of use lease asset (25) (30) Other (4) (5) Deferred tax liabilities (490) (288) Deferred tax assets: Net operating loss carryforwards 848 870 Carrying value of debt 25 29 Excess business interest expense carryforward 646 665 Capital loss carryforwards 78 101 Asset retirement obligations 65 91 Investments 1 11 Future lease payments 25 30 Accrued liabilities 15 21 Derivative instruments — 137 Other 32 29 Deferred tax assets 1,735 1,984 Valuation allowance (312) (345) Deferred tax assets after valuation allowance 1,423 1,639 Net deferred tax asset $ 933 $ 1,351 As of December 31, 2023 and 2022, we had deferred tax assets of $1.735 billion and $1.984 billion, respectively, upon which we had a valuation allowance of $312 million and $345 million, respectively. The net change in the valuation allowance of $33 million is primarily due to the expiration of a capital loss carryforward and is reflected as a component of income tax expense in the consolidated statements of operations. A valuation allowance against deferred tax assets, including NOL carryforwards and disallowed business interest carryforwards, is recognized when it is more likely than not that all or some portion of the benefit from the deferred tax assets will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of existing taxable temporary differences, tax planning strategies, as well as the current and forecasted business economics of our industry. Management assesses all available evidence, both positive and negative, to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. For the year ended December 31, 2021, we maintained a full valuation allowance against our deferred tax assets based upon the conclusion that it was more likely than not that the deferred tax assets would not be realized. An item of negative evidence consisted of the cumulative pre-tax book losses over rolling three-year periods, primarily due to recurring operational losses and impairments of proved natural gas and oil properties recorded in 2020. For the cumulative three-year period ended December 31, 2022, we were in a cumulative loss position, but given the magnitude of the 2020 losses rolling off relative to the 2021 and 2022 positive pre-tax book income, we anticipated a return to cumulative pre-tax income during 2023. The expectation of future earnings along with reversals of existing taxable timing differences provided us with sufficient positive evidence to conclude that $1.351 billion of our federal and state deferred tax assets were more likely than not to be realized. Accordingly, we released the valuation allowance for this amount during 2022. We continue to maintain a partial valuation allowance of $312 million against a portion of our federal and state deferred tax assets such as NOLs, credit carryovers, and capital losses, which may expire before we are able to utilize them due to the application of the limitations under Section 382 and the ordering in which such attributes may be applied. Our ability to utilize NOL carryforwards, disallowed business interest carryforwards, tax credits and possibly other tax attributes to reduce future taxable income and federal income tax is subject to various limitations under Section 382 of the Code. The utilization of such attributes may be subject to an annual limitation under Section 382 of the Code should transactions involving our equity result in a cumulative shift of more than 50% in the beneficial ownership of our stock during any three-year testing period (an “Ownership Change”). As a result of emergence from bankruptcy on February 9, 2021, the Company did experience an Ownership Change. The amount of the annual limitation has been computed to be $54 million. The limitation applies to our NOL carryforwards, disallowed business interest carryforwards and general business credits until such attributes expire or are fully utilized. As we were in an overall net unrealized built-in loss position at the Effective Date, the limitation also applies to any recognized built-in losses incurred for a period of five years but only to the extent of the overall net unrealized built-in loss. Recognized built-in losses include a portion of our tax depreciation, depletion, and amortization deductions along with a portion of our realized hedging losses. We incurred sufficient recognized built-in losses during the 2021 tax year such that we have no further restriction on the company’s deduction for such items. Some states impose similar limitations on tax attribute utilization upon experiencing an Ownership Change. In Chapter 11 bankruptcy cases, the cancellation of debt income (“CODI”) realized upon emergence from bankruptcy is excludible from taxable income but results in a reduction of tax attributes in accordance with the attribute reduction and ordering rules of Section 108 of the Code. The amount of our CODI was $5 billion, all of which reduced our NOL carryforwards. As a result of the Section 382 limitation, $307 million of federal NOLs remaining after the CODI reduction were estimated to expire before they would become utilizable and, as such, were removed from our deferred tax assets. The states we operate in generally have similar rules for attribute reduction and Section 382 limitation which resulted in the reduction of certain of our state NOL carryforwards. On November 1, 2021, we completed the acquisition of Vine. For federal income tax purposes, the transaction qualified as a tax-free merger under Section 368 of the Code and, as a result, we acquired carryover tax basis in Vine’s assets and liabilities. In the 2021 Successor Period, we recorded a $49 million net deferred tax liability determined through business combination accounting. Upon the completion of Vine’s tax returns in the 2022 Successor Period, the net deferred tax liability was adjusted to $30 million. As a result of this adjustment to the deferred tax liability, we increased our valuation allowance and recorded $19 million of income tax expense in the 2022 Successor Period. Additionally, we acquired NOL and interest expense carryforwards which are subject to a base annual Section 382 limitation of approximately $2 million. The base annual limitation is estimated to be increased over the first five years for recognized built-in gains of approximately $12 million per year resulting in approximately $14 million per year of available utilization in those years. The Marcellus Acquisition during the 2022 Successor Period was treated as a taxable asset acquisition with no tax carryovers acquired. As of December 31, 2023, and after taking into account each of the foregoing matters, the federal NOLs and excess business interest attributes are as follows: Attributes subject to Section 382 base annual limitation Attributes not subject to Section 382 limitation $54 million $2 million Net operating losses, by year of expiration: 2037 $ 760 $ 24 $ — Indefinitely lived 2,268 102 — Total federal net operating losses $ 3,028 $ 126 $ — Excess business interest expense (indefinitely lived) $ 1,381 $ 75 $ 1,277 We had state NOL carryforwards of approximately $3.712 billion. Several states adopt the federal NOL carryforward period such that our more recent state NOLs do not expire. The state NOL carryforwards are subject to apportioned amounts of the federal Section 382 limitations. Should we complete the Southwestern Merger as further discussed in Note 21 , we anticipate triggering a Section 382 Ownership Change for purposes of both Southwestern’s tax attributes as well as for our own. Assuming that generally higher long-term tax-exempt rates continue to apply as compared to prior years, we believe that the annual limitation will be less restrictive than the annual limitations that resulted from prior ownership changes. As a result, the new limitation would generally only apply to those attributes generated subsequent to the previous ownership changes. As of December 31, 2023 and 2022, we have an income tax receivable of $33 million and $168 million included in other current assets within our consolidated balance sheets, respectively. On August 16, 2022, the President of the United States signed into law the Inflation Reduction Act of 2022 (“IRA”) which, among other things, includes provisions for a 15% corporate alternative minimum tax on book income for companies whose average book income exceeds $1 billion for any three consecutive years preceding the tax year and a 1% excise tax on stock buybacks. These changes are generally in effect for tax years beginning after December 31, 2022. Based on our book income in the past three years, we do not believe we are subject to the corporate alternative minimum tax in 2023. However, we may become subject to the corporate alternative minimum tax in future years. It is our policy that we view the alternative minimum tax as an excess tax over regular income tax and therefore, our deferred tax assets will continue to be assessed for realizability on the basis of whether they reduce a regular tax liability. Should we pay alternative minimum tax in the future and thus acquire credit carryovers related thereto, such deferred tax assets on these will be separately evaluated for valuation allowance purposes. Accounting guidance for recognizing and measuring uncertain tax positions requires a more likely than not threshold condition be met on a tax position, based solely on the technical merits of being sustained, before any benefit of the tax position can be recognized in the financial statements. Guidance is also provided regarding recognition, classification and disclosure of uncertain tax positions. As of December 31, 2023 and 2022, the amount of unrecognized tax benefits related to NOL carryforwards, tax credit carryforwards, and tax liabilities associated with uncertain tax positions was $68 million and $69 million, respectively. As of December 31, 2023, $24 million is related to state tax receivables not expected to be recovered, $10 million is related to a liability for tax credits taken, and the remainder is related to NOL carryforwards. As of December 31, 2022, $29 million is related to state tax receivables not expected to be recovered, $4 million is related to tax credit carryforwards, and the remainder is related to NOL carryforwards. If recognized, $34 million of the uncertain tax positions identified would have an effect on the effective tax rate. As of December 31, 2023 and 2022, we had no amounts accrued for interest related to these uncertain tax positions. We recognize interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Unrecognized tax benefits at beginning of period $ 69 $ 74 $ 74 $ 74 Additions based on tax positions related to the current year 3 2 — — Additions to tax positions of prior years 3 2 — — Settlements (5) — — — Expiration of the applicable statute of limitations — — — — Reductions to tax positions of prior years (2) (9) — — Unrecognized tax benefits at end of period $ 68 $ 69 $ 74 $ 74 Our federal and state income tax returns are subject to examination by federal and state tax authorities. Our tax years 2020 through 2023 remain open for all purposes of examination by the IRS as well as the Vine 2020 federal income tax return and the Vine short period return for January 1, 2021 through November 1, 2021. However, certain earlier tax years remain open for adjustment to the extent of their NOL carryforwards available for future utilization. In addition, tax years 2020 through 2023 as well as certain earlier years remain open for examination by state tax authorities. We do not anticipate that the outcome of any federal or state audit will have a significant impact on our financial position or results of operations.

Equity

Equity	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Equity	12. Equity New Common Stock As discussed in Note 2 , on the Effective Date, we issued an aggregate of 97,907,081 shares of New Common Stock, par value $0.01 per share, to the holders of allowed claims, and 2,092,918 shares of New Common Stock were reserved for future distributions under the Plan. During the 2023, 2022 and 2021 Successor Periods, 12,089, 439,370 and 864,090 reserved shares, respectively, were issued to resolve allowed General Unsecured Claims. On November 1, 2021, we completed the Vine Acquisition and issued 18,709,399 shares of New Common Stock. On March 9, 2022, we completed the Marcellus Acquisition and issued 9,442,185 shares of New Common Stock. See further discussion of both acquisitions in Note 4 . Dividends In May 2021, we initiated a new annual dividend on our shares of common stock, expected to be paid quarterly. We declared the first quarterly dividend on our New Common Stock in the second quarter of 2021, which consisted of a base dividend per share. In March 2022, we adopted a variable return program that resulted in the payment of an additional variable dividend equal to the sum of Adjusted Free Cash Flow from the prior quarter less the base quarterly dividend, multiplied by 50%. The following table summarizes our dividend payments in the 2023, 2022 and 2021 Successor Periods: Base Variable Rate Per Share Total 2023: First Quarter $ 0.55 $ 0.74 $ 1.29 $ 175 Second Quarter $ 0.55 $ 0.63 $ 1.18 $ 160 Third Quarter $ 0.575 $ — $ 0.575 $ 77 Fourth Quarter $ 0.575 $ — $ 0.575 $ 75 2022: First Quarter $ 0.4375 $ 1.33 $ 1.7675 $ 210 Second Quarter $ 0.50 $ 1.84 $ 2.34 $ 298 Third Quarter $ 0.55 $ 1.77 $ 2.32 $ 280 Fourth Quarter $ 0.55 $ 2.61 $ 3.16 $ 424 2021: Second Quarter $ 0.34375 $ — $ 0.34375 $ 34 Third Quarter $ 0.34375 $ — $ 0.34375 $ 33 Fourth Quarter $ 0.4375 $ — $ 0.4375 $ 52 On February 20, 2024, we declared a base quarterly dividend payable of $0.575 per share, which will be paid on March 26, 2024 to stockholders of record at the close of business on March 7, 2024. Share Repurchase Program As of December 2, 2021, the Company was authorized to purchase up to $1.0 billion of the Company’s common stock and/or warrants under a share repurchase program, and in March 2022, we commenced our share repurchase program. In June 2022, our Board of Directors authorized an expansion of the share repurchase program by $1.0 billion, bringing the total authorized share repurchase amount to $2.0 billion for stock and/or warrants. The share repurchase program expired on December 31, 2023. The table below presents the shares purchased under our share repurchase program. Shares Purchased (thousands) Dollar Value of Shares Purchased Average Price Per Share 2022 First Quarter 1,000 $ 83 $ 82.98 Second Quarter 5,812 $ 515 $ 88.67 Third Quarter 750 $ 69 $ 92.14 Fourth Quarter 4,105 $ 406 $ 98.90 2023 First Quarter 793 $ 60 $ 74.95 Second Quarter 1,444 $ 115 $ 78.77 Third Quarter 1,509 $ 130 $ 86.16 Fourth Quarter 627 $ 52 $ 82.03 Total to date 16,040 $ 1,430 The repurchased shares of common stock were retired and recorded as a reduction to common stock and retained earnings. All share repurchases made after January 1, 2023 are subject to a 1% excise tax on share repurchases, as enacted under the Inflation Reduction Act of 2022. We are able to net this 1% excise tax on share repurchases against certain issuance of shares of our common stock. The impact of this 1% excise tax was immaterial during the 2023 Successor Period. Warrants Class A Warrants Class B Warrants Class C Warrants (a) Outstanding as of February 10, 2021 11,111,111 12,345,679 9,768,527 Converted into New Common Stock (254,259) (32,406) (10,603) Issued for General Unsecured Claims — — 1,630,447 Outstanding as of December 31, 2021 10,856,852 12,313,273 11,388,371 Converted into New Common Stock (b) (1,609,641) (29,679) (959,247) Converted in warrant exchange offer (b) (4,752,207) (7,879,030) (7,252,004) Issued for General Unsecured Claims — — 829,109 Outstanding as of December 31, 2022 4,495,004 4,404,564 4,006,229 Converted into New Common Stock (b) (247,389) (1,500) (5,581) Issued for General Unsecured Claims — — 22,835 Outstanding as of December 31, 2023 4,247,615 4,403,064 4,023,483 _________________________________________ (a) As of December 31, 2023, we had 1,466,502 of reserved Class C Warrants. (b) During the 2023 Successor Period, we issued 221,952 common shares as a result of Warrant exercises. During the 2022 Successor Period, we issued 18,408,228 common shares as a result of Warrant exercises, inclusive of the shares issued as part of the Warrant exchange offers described below. As discussed in Note 2 , on the Effective Date, we issued Class A, Class B and Class C Warrants that were initially exercisable for one share of New Common Stock per Warrant at initial exercise prices of $27.63, $32.13 and $36.18 per share, respectively, subject to adjustments pursuant to the terms of the Warrants. The Warrants are exercisable from the Effective Date until February 9, 2026. The Warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions. The exercise prices of the Warrants were adjusted to prevent the dilution of rights for the effects of the quarterly dividend distribution on December 6, 2023, and the adjusted exercise prices are $23.25, $27.04, and $30.45 per share for the Class A, Class B and Class C Warrants, respectively. Additionally, we have recalculated the number of shares of New Common Stock issuable upon the exercise of each of the Class A, Class B and Class C Warrants, respectively, and as a result, 1.22 shares are issuable upon the exercise of a Class A, Class B or Class C Warrant. On August 18, 2022, we announced exchange offers relating to our outstanding Class A Warrants, Class B Warrants and Class C Warrants. The exchange offers expired on October 7, 2022 and resulted in the issuance of 16,305,984 shares of our New Common Stock in exchange for the cancellation of (i) 4,752,207 Class A Warrants, (ii) 7,879,030 Class B Warrants and (iii) 7,252,004 Class C Warrants. Under the exchange offers, the Warrants were exchanged in a cashless transaction and were converted to shares of our New Common Stock at a ratio of 0.8636 for Class A Warrants, 0.8224 for Class B Warrants and 0.7890 for Class C Warrants, respectively. As the fair value of the New Common Stock issued was greater than the fair value of the Warrants tendered in the exchange offers due to stated exchange premiums, we recorded a non-cash deemed dividend of $67 million. Such fair values were determined using our stock price that is considered a Level 1 input. Chapter 11 Proceedings Upon our emergence from Chapter 11 on February 9, 2021, as discussed in Note 2 , Predecessor common stock and preferred stock were canceled and released under the Plan without receiving any recovery on account thereof.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Share-Based Compensation	13. Share-Based Compensation Successor Share-Based Compensation As of the Effective Date, the Board adopted the LTIP with a share reserve equal to 6,800,000 shares of New Common Stock. The LTIP provides for the grant of restricted stock units (“RSUs”), restricted stock awards, stock options, stock appreciation rights, performance awards and other stock awards to the Company’s employees and non-employee directors. Restricted Stock Units. In the 2023, 2022 and 2021 Successor Periods, we granted RSUs to employees and non-employee directors under the LTIP, which will vest over a three-year to five-year period and one-year period, respectively. The fair value of RSUs is based on the closing sales price of our common stock on the date of grant, and compensation expense is recognized ratably over the requisite service period. A summary of the changes in unvested RSUs is presented below: Weighted Average (in thousands) Unvested as of February 10, 2021 — $ — Granted (a) 1,202 $ 52.60 Vested (a) (377) $ 65.66 Forfeited (50) $ 44.37 Unvested as of December 31, 2021 775 $ 46.77 Granted 666 $ 81.87 Vested (300) $ 48.11 Forfeited (184) $ 56.54 Unvested as of December 31, 2022 957 $ 68.91 Granted 440 $ 72.25 Vested (329) $ 61.66 Forfeited (128) $ 68.42 Unvested as of December 31, 2023 940 $ 73.08 _________________________________________ (a) Due to the Vine Acquisition, each Vine restricted stock unit was converted into a Company restricted stock unit. As a result, approximately 430 thousand Vine restricted stock units were converted to Company restricted stock units, of which approximately 375 thousand restricted stock units were accelerated. We recognized the accelerated share-based compensation expense related to these awards in other operating expense (income), net on our consolidated statements of operations. The aggregate intrinsic value of RSUs that vested during the 2023, 2022 and 2021 Successor Periods was approximately $25 million, $26 million and $25 million, respectively, based on the stock price at the time of vesting. As of December 31, 2023, there was approximately $45 million of total unrecognized compensation expense related to unvested RSUs. The expense is expected to be recognized over a weighted average period of approximatel y 2.19 years. Performance Share Units. In the 2023, 2022 and 2021 Successor Periods, we granted performance share units (“PSUs”) to senior management under the LTIP, which will generally vest over a three-year period and will be settled in shares. The performance criteria include total shareholder return (“TSR”) and relative TSR (“rTSR”) and could result in a total payout between 0% - 200% of the target units. For the PSUs granted in 2021, the performance criteria also include share price hurdles which could result in a total payout between 0% - 100% of the target units. The fair value of the PSUs was measured on the grant date using a Monte Carlo simulation, and compensation expense is recognized ratably over the requisite service period because these awards depend on a combination of service and market criteria. The following tables present the assumptions used in the valuation of the PSUs granted in the 2023, 2022 and 2021 Successor Periods. 2023 PSU Awards Assumption TSR, rTSR Risk-free interest rate 3.85 % Volatility 64.4 % 2022 PSU Awards Assumption TSR, rTSR Risk-free interest rate 2.00 % Volatility 70.2 % 2021 PSU Awards Assumption TSR, rTSR Share Price Hurdle Risk-free interest rate 0.23 % 0.30 % Volatility 71.4 % 68.4 % A summary of the changes in unvested PSUs is presented below: Unvested Performance Share Units Weighted Average (in thousands) Unvested as of February 10, 2021 — $ — Granted 201 $ 64.41 Vested (9) $ 38.95 Forfeited (9) $ 55.42 Unvested as of December 31, 2021 183 $ 66.12 Granted 133 $ 109.65 Vested — $ — Forfeited (40) $ 57.48 Unvested as of December 31, 2022 276 $ 88.28 Granted 131 $ 78.78 Vested — $ — Forfeited (13) $ 68.77 Unvested as of December 31, 2023 394 $ 85.78 The aggregate intrinsic value of PSUs that vested during the 2021 Successor Period was approximately $0.6 million based on the stock price at the time of vesting. As of December 31, 2023, there was approximatel y $15 million of total unrecognized compensation expense related to unvested PSUs. The expense is expected to be recognized over a weighted average period of approximat ely 1.68 years . Predecessor Share-Based Compensation Our Predecessor share-based compensation program consisted of restricted stock, stock options and PSUs granted to employees and restricted stock granted to non-employee directors under our long-term incentive plans. The restricted stock and stock options were equity-classified awards and the PSUs were liability-classified awards. As discussed in Note 2 , on the Effective Date, our Predecessor common stock was canceled and New Common Stock was issued. Accordingly, our then existing share-based compensation awards were also canceled, which resulted in the recognition of any previously unamortized expense related to the canceled awards on the date of cancellation. Share-based compensation for the Predecessor and Successor Periods is not comparable. RSU and PSU Compensation. We recognized the following compensation costs, net of actual forfeitures, related to RSUs and PSUs for the periods presented: Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 General and administrative expenses $ 29 $ 19 $ 7 $ 3 Natural gas and oil properties 6 4 2 — Production expense 4 3 2 — Total RSU and PSU compensation $ 39 $ 26 $ 11 $ 3 Related income tax benefit $ 7 $ 6 $ — $ —

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Employee Benefit Plans	14. Employee Benefit Plans Our qualified 401(k) profit sharing plan (“401(k) Plan”) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. We match employee contributions dollar for dollar (subject to a maximum contribution of 6% of an employee's base salary and performance bonus) in cash. In April 2021, the 401(k) match was changed from 15% to 6%. In addition to our employer match contributions, in 2022 we commenced a discretionary fixed dollar contribution benefit for all employees, paid quarterly, which is based upon a calculation of 1% of Adjusted Free Cash Flow less the base quarterly dividend. This discretionary fixed dollar contribution is subject to an annual maximum contribution of $15,000 per employee. We contributed $13 million, $22 million, $8 million and $2 million to the 401(k) Plan in the 2023 Successor Period, 2022 Successor Period, 2021 Successor Period and 2021 Predecessor Period, respectively.

Derivative and Hedging Activiti

Derivative and Hedging Activities	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative and Hedging Activities	15. Derivative and Hedging Activities We use derivative instruments to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility. All of our natural gas and oil derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty. None of our open natural gas and oil derivative instruments were designated for hedge accounting as of December 31, 2023 and 2022. As of December 31, 2022, approximately $65 million of derivative liabilities (notional volume of 9.6 Bcf of natural gas and notional volume of 4.8 MMBbls of oil) were classified as liabilities held for sale. These derivative instruments were novated to WildFire Energy I LLC upon completion of the sale of a portion of our Eagle Ford assets on March 20, 2023. See Note 4 for more details. Natural Gas and Oil Derivatives As of December 31, 2023 and 2022, our natural gas and oil derivative instruments consisted of the following types of instruments: • Swaps : We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and swap options. • Options : We have bought and sold call options in exchange for a premium. At the time of settlement, if the market price exceeded the fixed price of the call option, we paid the counterparty the excess on sold call options and received the excess on bought call options. If the market price settled below the fixed price of the call option, no payment was due from either party. • Collars : These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars included the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminated the counterparty’s downside exposure below the second put option strike price. • Basis Protection Swaps : These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity. Contingent Consideration Arrangement In November 2023, we sold the final portion of our Eagle Ford assets to SilverBow. As part of the divestiture agreement, SilverBow has agreed to pay Chesapeake an additional contingent payment of $25 million should WTI NYMEX prices average between $75 and $80 per barrel or $50 million should WTI NYMEX prices average above $80 per barrel during the year following the close of the transaction. All changes in fair value are recognized as a gain or loss in earnings in the period they occur within natural gas and oil derivatives in our consolidated statements of operations. During the 2023 Successor Period, we recorded $9 million of unrealized losses related to the contingent consideration arrangement. The estimated fair values of our natural gas and oil derivative instrument assets (liabilities) as of December 31, 2023 and 2022 are provided below: Successor December 31, 2023 December 31, 2022 Notional Volume Fair Value Notional Volume Fair Value Natural gas (Bcf): Fixed-price swaps 343 $ 188 382 $ (494) Collars 558 497 721 49 Three-way collars — — 4 (2) Call options — — 18 (22) Basis protection swaps 578 2 652 (32) Total natural gas 1,479 687 1,777 (501) Oil (MMBbls): Fixed-price swaps — — 1 (32) Collars — — 2 7 Basis protection swaps — — 6 1 Total oil — — 9 (24) Contingent Consideration: Eagle Ford divestiture 12 — Total estimated fair value $ 699 $ (525) Effect of Derivative Instruments – Consolidated Balance Sheets The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2023 and 2022 on a gross basis and after same-counterparty netting: Gross Fair Value (a) Amounts Netted in the Consolidated Balance Sheets Net Fair Value Presented in the Consolidated Balance Sheets Successor As of December 31, 2023 Commodity Contracts: Short-term derivative asset $ 661 $ (36) $ 625 Long-term derivative asset 101 (27) 74 Short-term derivative liability (39) 36 (3) Long-term derivative liability (36) 27 (9) Contingent Consideration: Short-term derivative asset 12 — 12 Total derivatives $ 699 $ — $ 699 As of December 31, 2022 Commodity Contracts: Short-term derivative asset $ 200 $ (166) $ 34 Long-term derivative asset 87 (40) 47 Short-term derivative liability (598) 166 (432) Long-term derivative liability (214) 40 (174) Total derivatives $ (525) $ — $ (525) ___________________________________________ (a) These financial assets (liabilities) are measured at fair value on a recurring basis utilizing significant other observable inputs; see further discussion on fair value measurements below. Fair Value The fair value of our commodity contracts derivatives is based on third-party pricing models, which utilize inputs that are either readily available in the public market, such as natural gas, oil and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes, and, as such, are classified as Level 2. These values are compared to the values given by our counterparties for reasonableness. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives. The valuation of the contingent consideration is based on an option pricing model using significant Level 2 inputs that include quoted future commodity prices based on active markets. Credit Risk Considerations Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we only enter into commodity contracts derivatives with counterparties that are highly rated or deemed by us to have acceptable credit strength and deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2023, our commodity contracts derivative instruments were spread among 15 counterparties. Hedging Arrangements Certain of our hedging arrangements are with counterparties that were also lenders (or affiliates of lenders) under our New Credit Facility. The contracts entered into with these counterparties are secured by the same collateral that secures the revolving credit facility. The counterparties’ obligations must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us exceed defined thresholds. As of December 31, 2023, we did not have any cash or letters of credit posted as collateral for our commodity derivatives. Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss) A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below: Predecessor Period from January 1, 2021 through February 9, 2021 Before Tax After Tax Balance, beginning of period $ (12) $ 45 Losses reclassified to income (a) 3 3 Fresh start adjustments 9 9 Elimination of tax effects — (57) Balance, end of period $ — $ — ___________________________________________ (a) These losses were included as a component of total natural gas and oil derivatives. Our accumulated other comprehensive loss balance represented the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months had yet to occur. The remaining deferred gain or loss amounts were to be recognized in earnings in the month for which the original contract months were to occur. In connection with our adoption of fresh start accounting, we recorded a fair value adjustment to eliminate the accumulated other comprehensive income related to hedging settlements including the elimination of tax effects. See Note 3 for a discussion of fresh start accounting adjustments. We did not have any changes or items impacting other comprehensive income for the 2023, 2022 or 2021 Successor Periods.

Capitalized Exploratory Well Co

Capitalized Exploratory Well Costs	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Capitalized Exploratory Well Costs	16. Capitalized Exploratory Well Costs A summary of the changes in our capitalized exploratory well costs for the periods presented is detailed below. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Balance, beginning of period $ 10 $ 14 $ — $ — Additions pending the determination of proved reserves — 1 24 — Divestitures and other (10) — — — Reclassifications to proved properties — — (10) — Charges to exploration expense — (5) — — Balance, end of period (a) $ — $ 10 $ 14 $ — ___________________________________________ (a) Our capitalized exploratory well costs balance as of December 31, 2022, consisted of one project for which we had suspended exploratory well costs capitalized for a period greater than one year. During the 2023 Successor Period, this project was divested.

Other Property and Equipment

Other Property and Equipment	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Other Property and Equipment	17. Other Property and Equipment A summary of other property and equipment held for use and the estimated useful lives thereof is as follows: Successor Estimated Useful Life December 31, 2023 December 31, 2022 (in years) Buildings and improvements $ 316 $ 325 10 - 39 Computer equipment 94 92 5 Land 28 32 Other 59 51 5 - 20 Total other property and equipment, at cost 497 500 Less: accumulated depreciation (90) (58) Total other property and equipment, net $ 407 $ 442

Investments

Investments	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Investments	18. Investments Momentum Sustainable Ventures LLC.

Exploration Expense

Exploration Expense	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Exploration Expense	19. Exploration Expense

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	20. Asset Retirement Obligations The components of the change in our asset retirement obligations are shown below: Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Asset retirement obligations, beginning of period $ 335 $ 360 Additions (a) 9 53 Revisions (b) (9) 16 Settlements and disposals (c) (75) (54) Held for sale (d) — (57) Accretion expense 16 17 Asset retirement obligations, end of period 276 335 Less current portion 11 12 Asset retirement obligations, long-term $ 265 $ 323 ___________________________________________ (a) During the 2022 Successor Period, approximately $27 million of additions relate to the Marcellus Acquisition. See Note 4 for further discussion of this transaction. (b) Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties. (c) During the 2023 Successor Period, approximately $64 million of disposals related to the divestitures of our Eagle Ford assets. During the 2022 Successor Period, approximately $47 million of disposals related to the divestiture of our Powder River Basin assets. See Note 4 for further discussion of these transactions. (d) As of December 31, 2022, approximately $57 million of asset retirement obligations associated with the sale of a portion of our Eagle Ford assets were reclassified as other current liabilities held for sale.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2023
Subsequent Events [Abstract]
Subsequent Events	21. Subsequent Events

Supplemental Disclosures About

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited)	Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) Certain reserves and production information was previously disclosed in a per barrel of oil equivalent. As the majority of our production profile consists of natural gas, we have converted this information, including prior periods, from a per barrel of oil equivalent, to a per one thousand cubic feet of natural gas equivalent, referred to, on such a converted basis, as per Mcfe. Net Capitalized Costs Capitalized costs related to our natural gas, oil and NGL producing activities are summarized as follows: Successor December 31, 2023 December 31, 2022 Natural gas and oil properties: Proved $ 11,468 $ 11,096 Unproved 1,806 2,022 Total 13,274 13,118 Less accumulated depreciation, depletion and amortization (3,584) (2,373) Net capitalized costs $ 9,690 $ 10,745 Unproved properties as of December 31, 2023 and 2022, consisted mainly of leasehold acquired through our Vine Acquisition and Marcellus Acquisition. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years. Costs Incurred in Natural Gas and Oil Property Acquisition, Exploration and Development Costs incurred in natural gas and oil property acquisition, exploration and development, including capitalized interest and asset retirement costs, are summarized as follows: Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Acquisition of properties (a) : Proved properties $ 10 $ 2,321 $ 2,183 $ — Unproved properties 52 795 1,121 — Exploratory costs 15 15 31 — Development costs 1,721 1,918 717 58 Costs incurred $ 1,798 $ 5,049 $ 4,052 $ 58 ___________________________________________ (a) Includes $2.31 billion and $0.79 billion of proved and unproved property acquisitions, respectively, related to our Marcellus Acquisition in 2022. Includes $2.18 billion and $1.10 billion of proved and unproved property acquisitions, respectively, related to our Vine Acquisition in 2021. Results of Operations from Natural Gas, Oil and NGL Producing Activities The following table includes revenues and expenses associated directly with our natural gas, oil and NGL producing activities for the periods presented. It does not include any derivative activity, interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas, oil and NGL operations. Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Natural gas, oil and NGL sales $ 3,547 $ 9,892 $ 4,401 $ 398 Production expenses (356) (475) (297) (32) Gathering, processing and transportation expenses (853) (1,059) (780) (102) Severance and ad valorem taxes (167) (242) (158) (18) Exploration (27) (23) (7) (2) Depletion and depreciation (1,478) (1,703) (882) (64) Accretion of asset retirement obligations (16) (17) (11) (1) Imputed income tax provision (a) (152) (1,440) (535) (42) Results of operations from natural gas, oil and NGL producing activities $ 498 $ 4,933 $ 1,731 $ 137 ___________________________________________ (a) The imputed income tax provision is hypothetical (at the statutory tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable). Natural Gas, Oil and NGL Reserve Quantities Our petroleum engineers estimated all of our proved reserves as of December 31, 2023, 2022 and 2021. Independent petroleum engineering firm Netherland, Sewell & Associates, Inc. audited our total proved reserves as of December 31, 2023. Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. The information provided below on our natural gas, oil and NGL reserves is presented in accordance with regulations prescribed by the SEC. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. These changes could be material and could occur in the near term. Presented below is a summary of changes in estimated proved reserves for the periods presented: Natural Gas Oil NGL Total (Bcf) (MMBbl) (MMBbl) (Bcfe) December 31, 2023 Proved reserves, beginning of period (Successor) 11,369 198.4 73.9 13,002 Extensions, discoveries and other additions 415 — — 415 Revisions of previous estimates (325) — — (325) Production (1,266) (7.7) (3.8) (1,335) Sale of reserves-in-place (563) (190.7) (70.1) (2,127) Purchase of reserves-in-place 58 — — 58 Proved reserves, end of period (Successor) 9,688 — — 9,688 Proved developed reserves: Beginning of period (Successor) 7,385 157.2 58.9 8,681 End of period (Successor) 6,363 — — 6,363 Proved undeveloped reserves: Beginning of period (Successor) 3,984 41.2 15.0 4,321 End of period (a) (Successor) 3,325 — — 3,325 December 31, 2022 Proved reserves, beginning of period (Successor) 7,824 209.7 82.0 9,573 Extensions, discoveries and other additions 60 2.1 1.5 82 Revisions of previous estimates 1,989 22.5 5.0 2,155 Production (1,308) (19.4) (6.0) (1,461) Sale of reserves-in-place (122) (16.5) (8.6) (273) Purchase of reserves-in-place 2,926 — — 2,926 Proved reserves, end of period (Successor) 11,369 198.4 73.9 13,002 Proved developed reserves: Beginning of period (Successor) 4,246 165.7 61.7 5,610 End of period (Successor) 7,385 157.2 58.9 8,681 Proved undeveloped reserves: Beginning of period (Successor) 3,578 44.0 20.3 3,963 End of period (a) (Successor) 3,984 41.2 15.0 4,321 Natural Gas Oil NGL Total (Bcf) (MMBbl) (MMBbl) (Bcfe) December 31, 2021 Proved reserves, beginning of period (Predecessor) 3,530 161.3 52.0 4,809 Extensions, discoveries and other additions 1,744 41.0 16.9 2,091 Revisions of previous estimates 1,522 33.3 21.1 1,848 Production (807) (25.9) (8.0) (1,010) Sale of reserves-in-place — — — — Purchase of reserves-in-place 1,835 — — 1,835 Proved reserves, end of period (Successor) 7,824 209.7 82.0 9,573 Proved developed reserves: Beginning of period (Predecessor) 3,196 158.1 51.4 4,452 End of period (Successor) 4,246 165.7 61.7 5,610 Proved undeveloped reserves: Beginning of period (Predecessor) 334 3.2 0.6 357 End of period (a) (Successor) 3,578 44.0 20.3 3,963 ___________________________________________ (a) As of December 31, 2023, 2022 and 2021, there were no PUDs that had remained undeveloped for five years or more. During 2023, we divested 2,127 Bcfe, primarily related to our Eagle Ford divestitures. We recorded extensions and discoveries of 415 Bcfe, primarily related to new PUDs and previously unproved producing wells in the Upper Marcellus and Bossier Shales. We recorded 325 Bcfe of downward revisions of previous estimates, with 1,623 Bcfe of downward revisions due to lower natural gas, oil and NGL prices in 2023, partially offset by 1,298 Bcfe of non-price related positive revisions. The non-price revisions primarily consisted of 1,517 Bcfe from new PUDs and producing wells added in previously proved areas, 469 Bcfe of positive revisions to previously recorded PUD reserves primarily due to expected longer laterals in both Marcellus and Haynesville, partially offset by downward revisions of 451 Bcfe due to development plan and other changes in Marcellus and Haynesville, and a downward revision of 237 Bcfe on proved developed reserves related to aligning forecasts with latest production trends. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2023, were $2.64 per Mcf, $78.22 per Bbl and $28.61 per Bbl, respectively, before basis differential adjustments. During 2022, we acquired 2,926 Bcfe, primarily related to the Marcellus Acquisition. We recorded extensions and discoveries of 82 Bcfe, primarily related to new PUDs and previously unproved producing wells in emerging plays. We recorded 2,155 Bcfe of upward revisions of previous estimates, which consisted of 866 Bcfe of revisions to PUDs, primarily due to development plan optimization through prioritizing longer laterals and multi-well pad development in the Haynesville, 1,156 Bcfe of revisions to existing or new proved developed properties, primarily due to performance and 133 Bcfe of revisions due to higher natural gas, oil and NGL prices in 2022. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2022, were $6.36 per Mcf, $93.67 per Bbl and $43.58 per Bbl, respectively, before basis differential adjustments. During 2021, we acquired 1,835 Bcfe, primarily related to the Vine Acquisition. We recorded extensions and discoveries of 2,091 Bcfe following our emergence from bankruptcy on February 9, 2021, and certainty regarding our ability to finance the development of our proved reserves over a five-year period. We recorded 1,848 Bcfe of upward revisions of previous estimates, which consisted of 1,284 Bcfe due to lateral length adjustments, performance and updates to our five-year development plan and 564 Bcfe due to higher natural gas, oil and NGL prices in 2021. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2021, were $3.60 per Mcf, $66.56 per Bbl and $35.81 per Bbl, respectively, before basis differential adjustments. Standardized Measure of Discounted Future Net Cash Flows Accounting Standards Codification Topic 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed these guidelines which are briefly discussed below. Future cash inflows and future production and development costs as of December 31, 2023, 2022 and 2021 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of natural gas, oil and NGL to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process. The following summary sets forth our future net cash flows relating to proved natural gas, oil and NGL reserves based on the standardized measure: Years Ended December 31, 2023 2022 2021 Future cash inflows $ 14,659 (a) $ 76,626 (b) $ 33,700 (c) Future production costs (3,326) (10,177) (6,735) Future development costs (2,779) (d) (5,343) (e) (3,687) (f) Future income tax provisions (174) (10,440) (2,254) Future net cash flows 8,380 50,666 21,024 Less effect of a 10% discount factor (3,903) (24,361) (8,737) Standardized measure of discounted future net cash flows $ 4,477 $ 26,305 $ 12,287 ___________________________________________ (a) Calculated using prices of $2.64 per Mcf of natural gas, before basis differential adjustments. (b) Calculated using prices of $6.36 per Mcf of natural gas, $93.67 per Bbl of oil and $43.58 per Bbl of NGL, before basis differential adjustments. (c) Calculated using prices of $3.60 per Mcf of natural gas, $66.56 per Bbl of oil and $35.81 per Bbl of NGL, before basis differential adjustments. (d) Included approximately $730 million of future plugging and abandonment costs as of December 31, 2023. (e) Included approximately $979 million of future plugging and abandonment costs as of December 31, 2022. (f) Included approximately $846 million of future plugging and abandonment costs as of December 31, 2021. The principal sources of change in the standardized measure of discounted future net cash flows are as follows: Years Ended December 31, 2023 2022 2021 Standardized measure, beginning of period (a) $ 26,305 $ 12,287 $ 3,086 Sales of natural gas and oil produced, net of production costs and gathering, processing and transportation (b) (2,171) (8,116) (3,414) Net changes in prices and production costs (23,535) 14,256 6,674 Extensions and discoveries, net of production and 182 251 2,834 Changes in estimated future development costs 346 (1,512) (459) Previously estimated development costs incurred during the period 818 690 130 Revisions of previous quantity estimates (205) 6,697 2,034 Purchase of reserves-in-place 77 7,047 2,807 Sales of reserves-in-place (7,158) (402) — Accretion of discount 3,270 1,371 309 Net change in income taxes 6,301 (4,972) (1,423) Changes in production rates and other 247 (1,292) (291) Standardized measure, end of period (a) $ 4,477 $ 26,305 $ 12,287 ___________________________________________ (a) The impact of cash flow hedges has not been included in any of the periods presented. (b) Excludes gains and losses on derivatives. Production costs includes severance and ad valorem taxes.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
Net income	$ 5,383	$ 945	$ 2,419	$ 4,936

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

Basis of Presentation and Sum_2

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements of Chesapeake were prepared in accordance with GAAP and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. This Annual Report on Form 10-K (this “Form 10-K”) relates to the financial position of the Successor as of December 31, 2023 and as of December 31, 2022, and the year ended December 31, 2023 (“2023 Successor Period”), the year ended December 31, 2022 (“2022 Successor Period”), the period of February 10, 2021 through December 31, 2021 (“2021 Successor Period”) and the period of January 1, 2021 through February 9, 2021 (“2021 Predecessor Period”). Accounting During Bankruptcy We have applied Accounting Standards Codification (ASC) 852, Reorganizations,
Accounting Estimates	Accounting Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the related disclosures in the financial statements. Management evaluates its estimates and related assumptions regularly, including those related to the impairment of natural gas and oil properties, natural gas and oil reserves, derivatives, income taxes, impairment of other property and equipment, environmental remediation costs, asset retirement obligations, litigation and regulatory proceedings and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ significantly from these estimates.
Consolidation	Consolidation We consolidate entities in which we have a controlling financial interest and variable interest entities in which we are the primary beneficiary. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights. We use the equity method of accounting to record our net interests where we have the ability to exercise significant influence through our investment but lack a controlling financial interest. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. See Note 18 for further discussion of our investments. Undivided interests in natural gas and oil properties are consolidated on a proportionate basis.
Segments	Segments Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker, who is our Chief Executive Officer, for the purpose of allocating an enterprise’s resources and assessing its operating performance. We have concluded that we have only one reportable operating segment, due to the similar nature of the exploration and production business across Chesapeake and its consolidated subsidiaries and the fact that our marketing activities are ancillary to our operations.
Cash and Cash Equivalents	Cash and Cash Equivalents
Restricted Cash	Restricted Cash
Accounts Receivable	Accounts Receivable
Natural Gas and Oil Properties	Natural Gas and Oil Properties We follow the successful efforts method of accounting for our natural gas and oil properties. Under this method, exploration costs such as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead and similar activities are also expensed as incurred. All property acquisition costs and development costs are capitalized when incurred. Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and oil are capitalized. Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (“UOP”) method based on total estimated proved developed gas and oil reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Proceeds from the sales of individual natural gas and oil properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. When circumstances indicate that the carrying value of proved natural gas and oil properties may not be recoverable, we compare unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820, Fair Value Measurements . If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted average cost of capital. We have classified these fair value measurements as Level 3 in the fair value hierarchy.
Other Property and Equipment	Other Property and Equipment Other property and equipment consists primarily of buildings and improvements, computers and office equipment, land and other assets that support our operations. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. Other property and equipment costs, excluding land, are depreciated on a straight-line basis and recorded within depreciation, depletion and amortization in the consolidated statement of operations.
Assets Held for Sale	Assets Held for Sale
Capitalized Interest	Capitalized Interest Interest from external borrowings is capitalized on significant investments in major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.
Debt Issuance Costs	Debt Issuance Costs
Litigation Contingencies	Litigation Contingencies
Environmental Remediation Costs	Environmental Remediation Costs
Asset Retirement Obligations	Asset Retirement Obligations
Revenue Recognition	Revenue Recognition Revenue from the sale of natural gas, oil and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 days. There are no significant judgments that significantly affect the amount or timing of revenue from contracts with customers. We also generate revenue from other sources, including from a variety of derivative and hedging activities to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility, as well as a variety of natural gas, oil and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments (recorded within marketing revenues in the consolidated statements of operations). In circumstances where we act as an agent rather than a principal, our results of operations related to natural gas, oil and NGL marketing activities are presented on a net basis.
Fair Value Measurements	Fair Value Measurements Certain financial instruments are reported on a recurring basis at fair value on our consolidated balance sheets. We also use fair value measurements on a nonrecurring basis when a qualitative assessment of our assets indicates a potential impairment. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Derivatives	Derivatives Derivative instruments are recorded at fair value, and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. As of December 31, 2023, none of our open derivative instruments were designated as cash flow hedges. Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next 12 months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our commodity derivative instruments are subject to master netting arrangements by contract type which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.
Share-Based Compensation	Share-Based Compensation Our share-based compensation program consists of restricted stock units and performance share units granted to employees and restricted stock units granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of services received in exchange for restricted stock units based on the fair value of the equity instruments as of the grant date. This value is amortized over the vesting period, which is generally three years from the grant date. Forfeitures on our share-based compensation awards are recognized as they occur. Because performance share units are settled in shares, they are classified as equity and are measured at fair value as of the grant date.

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2023
Reorganizations [Abstract]
Schedule of Fresh Start Accounting Adjustments	The following table reconciles the enterprise value to the implied fair value of the Successor’s equity as of the Effective Date: February 9, 2021 Enterprise Value $ 4,851 Plus: Cash and cash equivalents (a) 48 Less: Fair value of debt (1,313) Successor equity value $ 3,586 ____________________________________________ (a) Cash and cash equivalents includes $8 million that was initially classified as restricted cash as of the Effective Date but subsequently released from escrow and returned to the Successor. Restricted cash exclusive of the $8 million is not included in the table above. The following table reconciles the enterprise value to the reorganization value as of the Effective Date: February 9, 2021 Enterprise value $ 4,851 Plus: Cash and cash equivalents (a) 48 Plus: Current liabilities 1,582 Plus: Asset retirement obligations (non-current portion) 236 Plus: Other non-current liabilities 97 Reorganization value of Successor assets $ 6,814 ____________________________________________ (a) Cash and cash equivalents includes $8 million that was initially classified as restricted cash as of the Effective Date but subsequently released from escrow and returned to the Successor. Restricted cash exclusive of the $8 million is not included in the table above. The following consolidated balance sheet is as of February 9, 2021. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Effective Date. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities and warrants. Predecessor Reorganization Adjustments Fresh Start Adjustments Successor Assets Current assets: Cash and cash equivalents $ 243 $ (203) (a) $ — $ 40 Restricted cash — 86 (b) — 86 Accounts receivable, net 861 (18) (c) — 843 Short-term derivative assets — — — — Other current assets 66 (5) (d) — 61 Total current assets 1,170 (140) — 1,030 Property and equipment: Natural gas and oil properties, successful efforts method Proved natural gas and oil properties 25,794 — (21,108) (o) 4,686 Unproved properties 1,546 — (1,063) (o) 483 Other property and equipment 1,755 — (1,256) (o) 499 Total property and equipment 29,095 — (23,427) (o) 5,668 Less: accumulated depreciation, depletion and amortization (23,877) — 23,877 (o) — Property and equipment held for sale, net 9 — (7) (o) 2 Total property and equipment, net 5,227 — 443 (o) 5,670 Other long-term assets 198 — (84) (p) 114 Total assets $ 6,595 $ (140) $ 359 $ 6,814 Predecessor Reorganization Adjustments Fresh Start Adjustments Successor Liabilities and stockholders’ equity (deficit) Current liabilities: Accounts payable $ 391 $ 24 (e) $ — $ 415 Current maturities of long-term debt, net 1,929 (1,929) (f) — — Accrued interest 4 (4) (g) — — Short-term derivative liabilities 398 — — 398 Other current liabilities 645 124 (h) — 769 Total current liabilities 3,367 (1,785) — 1,582 Long-term debt, net — 1,261 (i) 52 (q) 1,313 Long-term derivative liabilities 90 — — 90 Asset retirement obligations, net of current portion 139 — 97 (r) 236 Other long-term liabilities 5 2 (j) — 7 Liabilities subject to compromise 9,574 (9,574) (k) — — Total liabilities 13,175 (10,096) 149 3,228 Contingencies and commitments ( Note 7 ) Stockholders’ equity (deficit): Predecessor preferred stock 1,631 (1,631) (l) — — Predecessor common stock — — — — Predecessor additional paid-in capital 16,940 (16,940) (l) — — Successor common stock — 1 (m) — 1 Successor additional paid-in-capital — 3,585 (m) — 3,585 Accumulated other comprehensive income 48 — (48) (s) — Accumulated deficit (25,199) 24,941 (n) 258 (t) — Total stockholders’ equity (deficit) (6,580) 9,956 210 3,586 Total liabilities and stockholders’ equity (deficit) $ 6,595 $ (140) $ 359 $ 6,814 Reorganization Adjustments (a) The table below reflects the sources and uses of cash on the Effective Date from implementation of the Plan: Sources: Proceeds from issuance of the Notes $ 1,000 Proceeds from Rights Offering 600 Proceeds from refunds of interest deposit for the Notes 5 Total sources of cash $ 1,605 Uses: Payment of roll-up of DIP Facility balance $ (1,179) Payment of Exit Credit Facility - Tranche A Loan (479) Transfers to restricted cash for professional fee reserve (76) Transfers to restricted cash for convenience claim distribution reserve (10) Payment of professional fees (31) Payment of DIP Facility interest and fees (12) Payment of FLLO alternative transaction fee (12) Payment of the Notes fees funded out of escrow (8) Payment of RBL interest and fees (1) Total uses of cash $ (1,808) Net cash used $ (203) (b) Represents the transfer of funds to a restricted cash account for purposes of funding the professional fee reserve and the convenience claim distribution reserve. (c) Reflects the removal of an insurance receivable associated with a discharged legal liability. (d) Reflects the collection of an interest deposit for the senior unsecured notes. (e) Changes in accounts payable include the following: Accrual of professional service provider success fees $ 38 Accrual of convenience claim distribution reserve 10 Accrual of professional service provider fees 5 Reinstatement of accounts payable from liabilities subject to compromise 2 Payment of professional fees (31) Net impact to accounts payable $ 24 (f) Reflects payment of the pre-petition credit facility for $1.179 billion and transfer of the Tranche A and Tranche B Loans to long-term debt for $750 million. (g) Reflects payments of accrued interest and fees on the DIP Facility. (h) Changes in other current liabilities include the following: Reinstatement of other current liabilities from liabilities subject to compromise $ 191 Accrual of the Notes fees 2 Settlement of Put Option Premium through issuance of Successor Common Stock (60) Payment of DIP Facility fees (9) Net impact to other current liabilities $ 124 (i) Changes in long-term debt include the following: Issuance of the Notes $ 1,000 Issuance of Tranche A and Tranche B Loans 750 Payments on Tranche A Loans (479) Debt issuance costs for the Notes (10) Net impact to long-term debt, net $ 1,261 (j) Reflects reinstatement of a long-term lease liability. (k) On the Effective Date, liabilities subject to compromise were settled in accordance with the Plan as follows: Liabilities subject to compromise pre-emergence $ 9,574 To be reinstated on the Effective Date: Accounts payable $ (2) Other current liabilities (191) Other long-term liabilities (2) Total liabilities reinstated $ (195) Consideration provided to settle amounts per the Plan or Reorganization: Issuance of Successor common stock associated with the Rights Offering and Backstop Commitment and settlement of the Put Option Premium $ (2,311) Proceeds from issuance of Successor common stock associated with the Rights Offering and Backstop Commitment 600 Issuance of Successor common stock to FLLO Term Loan holders, incremental to the Rights Offering and Backstop Commitment (783) Issuance of Successor common stock to Second Lien Note holders, incremental to the Rights Offering and Backstop Commitment (124) Issuance of Successor common stock to unsecured note holders (45) Issuance of Successor common stock to General Unsecured Claims (8) Fair value of Class A Warrants (93) Fair value of Class B Warrants (94) Fair value of Class C Warrants (68) Proceeds to holders of general unsecured claims (10) Total consideration provided to settle amounts per the Plan $ (2,936) Gain on settlement of liabilities subject to compromise $ 6,443 (l) Pursuant to the Plan, as of the Effective Date, all equity interests in Predecessor, including Predecessor’s common and preferred stock, were canceled without any distribution. (m) Reflects the Successor equity including the issuance of 97,907,081 shares of New Common Stock, 11,111,111 shares of Class A Warrants, 12,345,679 shares of Class B Warrants and 9,768,527 shares of Class C Warrants pursuant to the Plan. Issuance of Successor equity associated with the Rights Offering and Backstop Commitment $ 2,371 Issuance of Successor equity to holders of the FLLO Term Loan, incremental to the Rights Offering and Backstop Commitment 783 Issuance of Successor equity to holders of the Second Lien Notes, incremental to the Rights Offering and Backstop Commitment 124 Issuance of Successor equity to holders of the unsecured senior notes 45 Issuance of Successor equity to holders of allowed general unsecured claims 8 Fair value of Class A warrants 93 Fair value of Class B warrants 94 Fair value of Class C warrants 68 Total change in Successor common stock and additional paid-in capital 3,586 Less: par value of Successor common stock (1) Change in Successor additional paid-in capital $ 3,585 (n) Reflects the cumulative net impact of the effects on accumulated deficit as follows: Gain on settlement of liabilities subject to compromise $ 6,443 Accrual of professional service provider success fees (38) Accrual of professional service provider fees (5) Surrender of other receivable (18) Payment of FLLO alternative transaction fee (12) Total reorganization items, net 6,370 Cancellation of predecessor equity 18,571 Net impact on accumulated deficit $ 24,941 Fresh Start Adjustments (o) Reflects fair value adjustments to our (i) proved natural gas and oil properties, (ii) unproved properties, (iii) other property and equipment and, (iv) property and equipment held for sale, and the elimination of accumulated depletion, depreciation and amortization. (p) Reflects the fair value adjustment to record historical contracts at their fair values. (q) Reflects the fair value adjustments to the 2026 Notes and 2029 Notes for $22 million and $30 million, respectively. (r) Reflects the adjustment to our asset retirement obligations using assumptions as of the Effective Date, including an inflation factor of 2% and an average credit-adjusted risk-free rate of 5.18%. (s) Reflects the fair value adjustment to eliminate the accumulated other comprehensive income of $9 million related to hedging settlements offset by the elimination of $57 million of income tax effects which has resulted in the recording of an income tax benefit of $57 million. See Note 11 for a discussion of income taxes. (t) Reflects the net cumulative impact of the fresh start adjustments on accumulated deficit as follows: Fresh start adjustments to property and equipment $ 443 Fresh start adjustments to other long-term assets (84) Fresh start adjustments to long-term debt (52) Fresh start adjustments to long-term asset retirement obligations (97) Fresh start adjustments to accumulated other comprehensive income (9) Total fresh start adjustments impacting reorganizations items, net 201 Income tax effects on accumulated other comprehensive income 57 Net impact to accumulated deficit $ 258
Schedule of Reorganization Items	The following table summarizes the components in reorganization items, net included in our consolidated statements of operations: Predecessor Period from January 1, 2021 through February 9, 2021 Gains on the settlement of liabilities subject to compromise $ 6,443 Accrual for allowed claims (1,002) Gain on fresh start adjustments 201 Gain from release of commitment liabilities 55 Professional service provider fees and other (60) Success fees for professional service providers (38) Surrender of other receivable (18) FLLO alternative transaction fee (12) Total reorganization items, net $ 5,569

Natural Gas and Oil Property _2

Natural Gas and Oil Property Transactions (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Schedule of purchase price allocation	We have accounted for the Marcellus Acquisition as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. We finalized the acquisition accounting for this transaction during the 2022 Successor Period, which resulted in measurement period adjustments of $39 million to both restricted cash and current liabilities, to reflect funds restricted for future payment of certain royalties . Purchase Price Allocation Consideration: Cash $ 2,000 Fair value of Chesapeake’s common stock issued in the merger (a) 764 Working capital adjustments 6 Total consideration $ 2,770 Fair Value of Liabilities Assumed: Current liabilities $ 459 Other long-term liabilities 129 Amounts attributable to liabilities assumed $ 588 Fair Value of Assets Acquired: Cash, cash equivalents and restricted cash $ 39 Other current assets 218 Proved natural gas and oil properties 2,309 Unproved properties 788 Other property and equipment 1 Other long-term assets 3 Amounts attributable to assets acquired $ 3,358 Total identifiable net assets $ 2,770 ____________________________________________ (a) We have accounted for the Vine Acquisition as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of Vine to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. We finalized the acquisition accounting for this transaction during the 2022 Successor Period, which resulted in measurement period adjustments of $19 million to both deferred tax liabilities and unproved properties. See Note 11 for additional information regarding the change to deferred tax liabilities. Purchase Price Allocation Consideration: Cash $ 253 Fair value of Chesapeake’s common stock issued in the merger (a) 1,231 Restricted stock unit replacement awards 6 Total consideration $ 1,490 Fair Value of Liabilities Assumed: Current liabilities $ 765 Long-term debt 1,021 Deferred tax liabilities 30 Other long-term liabilities 272 Amounts attributable to liabilities assumed $ 2,088 Fair Value of Assets Acquired: Cash and cash equivalents $ 59 Other current assets 206 Proved natural gas and oil properties 2,181 Unproved properties 1,099 Other property and equipment 1 Other long-term assets 32 Amounts attributable to assets acquired $ 3,578 Total identifiable net assets $ 1,490 ____________________________________________ (a) The fair value of our common stock is a Level 1 input, as our stock price is a quoted price in an active market as of the acquisition date.
Schedule of pro forma financial information	The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including the estimated tax impact of the pro forma adjustments. Successor Year Ended Period from February 10, 2021 through December 31, 2021 Revenues $ 11,743 $ 5,891 Net income (loss) available to common stockholders $ 4,765 $ (5) Earnings (loss) per common share: Basic $ 37.37 $ (0.04) Diluted $ 32.26 $ (0.04)

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The reconciliations between basic and diluted earnings per share are as follows: Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Numerator Net income available to common stockholders, basic and diluted $ 2,419 $ 4,869 $ 945 $ 5,383 Denominator (in thousands) Weighted average common shares outstanding, basic 132,840 125,785 101,754 9,781 Effect of potentially dilutive securities Preferred stock — — — 290 Warrants 9,750 19,734 14,376 — Restricted stock units 338 395 200 — Performance share units 48 47 11 — Weighted average common shares outstanding, diluted 142,976 145,961 116,341 10,071 Earnings per common share: Basic $ 18.21 $ 38.71 $ 9.29 $ 550.35 Diluted $ 16.92 $ 33.36 $ 8.12 $ 534.51

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of long-term debt instruments	Our long-term debt consisted of the following as of December 31, 2023 and 2022: Successor December 31, 2023 December 31, 2022 Carrying Amount Fair Value (a) Carrying Amount Fair Value (a) New Credit Facility $ — $ — $ 1,050 $ 1,050 5.50% senior notes due 2026 500 496 500 485 5.875% senior notes due 2029 500 489 500 475 6.75% senior notes due 2029 (b) 950 958 950 917 Premiums on senior notes 83 — 100 — Debt issuance costs (5) — (7) — Total long-term debt, net $ 2,028 $ 1,943 $ 3,093 $ 2,927 ____________________________________________ (a) The carrying value of borrowings under our New Credit Facility approximates fair value as the interest rates are based on prevailing market rates; therefore, they are a Level 1 fair value measurement. For all other debt, a market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value. (b) On November 1, 2021, we acquired the debt of Vine, which consisted of 6.75% senior notes due 2029. See further discussion below.
Schedule of debt maturities	The table below presents debt maturities as of December 31, 2023, excluding debt issuance costs and premiums: Total 2024 $ — 2025 — 2026 500 2027 — 2028 — Thereafter 1,450 Total long-term debt $ 1,950

Contingencies and Commitments (

Contingencies and Commitments (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Schedule of undiscounted commitments	The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below: Successor December 31, 2023 2024 $ 284 2025 255 2026 235 2027 208 2028 194 2029-2036 956 Total $ 2,132

Other Liabilities (Tables)

Other Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Other current liabilities	Other current liabilities as of December 31, 2023 and 2022 are detailed below: Successor December 31, 2023 December 31, 2022 Revenues and royalties due to others $ 360 $ 734 Accrued drilling and production costs 211 253 Accrued hedging costs 2 109 Accrued compensation and benefits 64 72 Taxes payable 84 84 Operating leases 84 86 Joint interest prepayments received 8 34 Current liabilities held for sale (a) — 144 Other 34 111 Total other current liabilities $ 847 $ 1,627 _________________________________________ (a) As of December 31, 2022, certain liabilities associated with the sale of a portion of our Eagle Ford assets were classified as current liabilities held for sale. See Note 4

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Schedule of ROU assets and lease liabilities	The following table presents our ROU assets and lease liabilities as of December 31, 2023 and 2022. As of December 31, 2023 and 2022, we did not have any finance leases. Successor Operating Leases December 31, 2023 December 31, 2022 ROU assets $ 99 $ 119 Lease liabilities: Current lease liabilities $ 84 $ 86 Long-term lease liabilities 15 33 Total lease liabilities, net $ 99 $ 119
Schedule of operating and financing lease additional information	Additional information for the Company’s operating and finance leases is presented below: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Lease cost: Finance lease cost $ — $ — $ — $ 1 Operating lease cost 107 51 33 3 Short-term lease cost 40 74 13 — Total lease cost $ 147 $ 125 $ 46 $ 4 Other information: Operating cash outflows from operating leases $ 10 $ 15 $ 7 $ — Investing cash outflows from operating leases $ 137 $ 110 $ 39 $ 3 Financing cash outflows from finance lease $ — $ — $ — $ 1 Successor December 31, 2023 December 31, 2022 Weighted average remaining lease term - operating leases 1.24 years 1.54 years Weighted average discount rate - operating leases 7.02 % 6.64 %
Schedule of maturity analysis of operating lease liabilities	Maturity analysis of operating lease liabilities is presented below: Successor December 31, 2023 2024 $ 85 2025 17 2026 1 Total lease payments 103 Less imputed interest (4) Present value of lease liabilities 99 Less current maturities (84) Present value of lease liabilities, less current maturities $ 15

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Disaggregation of revenue	The following tables show revenue disaggregated by operating area and product type, for the periods presented: Successor Year Ended December 31, 2023 Natural Gas Oil NGL Total Marcellus $ 1,483 $ — $ — $ 1,483 Haynesville 1,300 — — 1,300 Eagle Ford 70 596 98 764 Natural gas, oil and NGL revenue $ 2,853 $ 596 $ 98 $ 3,547 Marketing revenue $ 989 $ 1,332 $ 179 $ 2,500 Successor Year Ended December 31, 2022 Natural Gas Oil NGL Total Marcellus $ 4,041 $ — $ — $ 4,041 Haynesville 3,481 — — 3,481 Eagle Ford 261 1,798 212 2,271 Powder River Basin 20 66 13 99 Natural gas, oil and NGL revenue $ 7,803 $ 1,864 $ 225 $ 9,892 Marketing revenue $ 2,455 $ 1,547 $ 229 $ 4,231 Successor Period from February 10, 2021 through December 31, 2021 Natural Gas Oil NGL Total Marcellus $ 1,370 $ — $ — $ 1,370 Haynesville 998 — — 998 Eagle Ford 179 1,354 179 1,712 Powder River Basin 75 202 44 321 Natural gas, oil and NGL revenue $ 2,622 $ 1,556 $ 223 $ 4,401 Marketing revenue $ 908 $ 1,158 $ 197 $ 2,263 Predecessor Period from January 1, 2021 through February 9, 2021 Natural Gas Oil NGL Total Marcellus $ 119 $ — $ — $ 119 Haynesville 53 — — 53 Eagle Ford 17 159 17 193 Powder River Basin 7 20 6 33 Natural gas, oil and NGL revenue $ 196 $ 179 $ 23 $ 398 Marketing revenue $ 78 $ 141 $ 20 $ 239
Schedule of accounts receivable	Accounts receivable as of December 31, 2023 and 2022 are detailed below: Successor December 31, 2023 December 31, 2022 Natural gas, oil and NGL sales $ 406 $ 1,171 Joint interest 180 246 Other 8 24 Allowance for doubtful accounts (1) (3) Total accounts receivable, net $ 593 $ 1,438

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of components of the income tax provision (benefit)	The components of the income tax expense (benefit) for each of the periods presented below are as follows: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Current Federal $ 264 $ 37 $ — $ — State 6 10 — — Current Income Taxes 270 47 — — Deferred Federal 381 (1,112) (45) (54) State 47 (220) (4) (3) Deferred Income Taxes 428 (1,332) (49) (57) Total $ 698 $ (1,285) $ (49) $ (57)
Schedule of effective income tax expense (benefit)	The income tax expense (benefit) reported in our consolidated statement of operations is different from the federal income tax expense (benefit) computed using the federal statutory rate for the following reasons: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Income tax expense (benefit) at the federal statutory rate of 21% $ 655 $ 767 $ 188 $ 1,119 State income taxes (net of federal income tax benefit) 56 75 (86) 238 Change in valuation allowance due to Acquisitions — 19 (49) — Change in valuation allowance excluding impact of Acquisitions (33) (2,147) (179) (1,191) Reorganization items — — 60 (173) Transaction costs — 2 11 — Removal of stranded tax effects in accumulated other comprehensive income — — — (57) Other 20 (1) 6 7 Total $ 698 $ (1,285) $ (49) $ (57)
Schedule of deferred tax assets and liabilities	The tax-effected temporary differences, net operating loss (“NOL”) carryforwards and excess business interest expense carryforwards that comprise our deferred income taxes are as follows: Successor December 31, 2023 December 31, 2022 Deferred tax liabilities: Property, plant and equipment $ (295) $ (253) Derivative instruments (166) — Right of use lease asset (25) (30) Other (4) (5) Deferred tax liabilities (490) (288) Deferred tax assets: Net operating loss carryforwards 848 870 Carrying value of debt 25 29 Excess business interest expense carryforward 646 665 Capital loss carryforwards 78 101 Asset retirement obligations 65 91 Investments 1 11 Future lease payments 25 30 Accrued liabilities 15 21 Derivative instruments — 137 Other 32 29 Deferred tax assets 1,735 1,984 Valuation allowance (312) (345) Deferred tax assets after valuation allowance 1,423 1,639 Net deferred tax asset $ 933 $ 1,351
Schedule of federal NOLs and excess business interest	As of December 31, 2023, and after taking into account each of the foregoing matters, the federal NOLs and excess business interest attributes are as follows: Attributes subject to Section 382 base annual limitation Attributes not subject to Section 382 limitation $54 million $2 million Net operating losses, by year of expiration: 2037 $ 760 $ 24 $ — Indefinitely lived 2,268 102 — Total federal net operating losses $ 3,028 $ 126 $ — Excess business interest expense (indefinitely lived) $ 1,381 $ 75 $ 1,277
Schedule of reconciliation of unrecognized tax benefits	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Unrecognized tax benefits at beginning of period $ 69 $ 74 $ 74 $ 74 Additions based on tax positions related to the current year 3 2 — — Additions to tax positions of prior years 3 2 — — Settlements (5) — — — Expiration of the applicable statute of limitations — — — — Reductions to tax positions of prior years (2) (9) — — Unrecognized tax benefits at end of period $ 68 $ 69 $ 74 $ 74

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Schedule of Dividends	The following table summarizes our dividend payments in the 2023, 2022 and 2021 Successor Periods: Base Variable Rate Per Share Total 2023: First Quarter $ 0.55 $ 0.74 $ 1.29 $ 175 Second Quarter $ 0.55 $ 0.63 $ 1.18 $ 160 Third Quarter $ 0.575 $ — $ 0.575 $ 77 Fourth Quarter $ 0.575 $ — $ 0.575 $ 75 2022: First Quarter $ 0.4375 $ 1.33 $ 1.7675 $ 210 Second Quarter $ 0.50 $ 1.84 $ 2.34 $ 298 Third Quarter $ 0.55 $ 1.77 $ 2.32 $ 280 Fourth Quarter $ 0.55 $ 2.61 $ 3.16 $ 424 2021: Second Quarter $ 0.34375 $ — $ 0.34375 $ 34 Third Quarter $ 0.34375 $ — $ 0.34375 $ 33 Fourth Quarter $ 0.4375 $ — $ 0.4375 $ 52
Schedule of Share Repurchase Program	The table below presents the shares purchased under our share repurchase program. Shares Purchased (thousands) Dollar Value of Shares Purchased Average Price Per Share 2022 First Quarter 1,000 $ 83 $ 82.98 Second Quarter 5,812 $ 515 $ 88.67 Third Quarter 750 $ 69 $ 92.14 Fourth Quarter 4,105 $ 406 $ 98.90 2023 First Quarter 793 $ 60 $ 74.95 Second Quarter 1,444 $ 115 $ 78.77 Third Quarter 1,509 $ 130 $ 86.16 Fourth Quarter 627 $ 52 $ 82.03 Total to date 16,040 $ 1,430
Schedule of Warrants	Warrants Class A Warrants Class B Warrants Class C Warrants (a) Outstanding as of February 10, 2021 11,111,111 12,345,679 9,768,527 Converted into New Common Stock (254,259) (32,406) (10,603) Issued for General Unsecured Claims — — 1,630,447 Outstanding as of December 31, 2021 10,856,852 12,313,273 11,388,371 Converted into New Common Stock (b) (1,609,641) (29,679) (959,247) Converted in warrant exchange offer (b) (4,752,207) (7,879,030) (7,252,004) Issued for General Unsecured Claims — — 829,109 Outstanding as of December 31, 2022 4,495,004 4,404,564 4,006,229 Converted into New Common Stock (b) (247,389) (1,500) (5,581) Issued for General Unsecured Claims — — 22,835 Outstanding as of December 31, 2023 4,247,615 4,403,064 4,023,483 _________________________________________ (a) As of December 31, 2023, we had 1,466,502 of reserved Class C Warrants. (b) During the 2023 Successor Period, we issued 221,952 common shares as a result of Warrant exercises. During the 2022 Successor Period, we issued 18,408,228 common shares as a result of Warrant exercises, inclusive of the shares issued as part of the Warrant exchange offers described below.

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Summary of Changes in Unvested Restricted Stock	A summary of the changes in unvested RSUs is presented below: Weighted Average (in thousands) Unvested as of February 10, 2021 — $ — Granted (a) 1,202 $ 52.60 Vested (a) (377) $ 65.66 Forfeited (50) $ 44.37 Unvested as of December 31, 2021 775 $ 46.77 Granted 666 $ 81.87 Vested (300) $ 48.11 Forfeited (184) $ 56.54 Unvested as of December 31, 2022 957 $ 68.91 Granted 440 $ 72.25 Vested (329) $ 61.66 Forfeited (128) $ 68.42 Unvested as of December 31, 2023 940 $ 73.08 _________________________________________ (a) Due to the Vine Acquisition, each Vine restricted stock unit was converted into a Company restricted stock unit. As a result, approximately 430 thousand Vine restricted stock units were converted to Company restricted stock units, of which approximately 375 thousand restricted stock units were accelerated. We recognized the accelerated share-based compensation expense related to these awards in other operating expense (income), net on our consolidated statements of operations.
Schedule Valuation Assumptions	The following tables present the assumptions used in the valuation of the PSUs granted in the 2023, 2022 and 2021 Successor Periods. 2023 PSU Awards Assumption TSR, rTSR Risk-free interest rate 3.85 % Volatility 64.4 % 2022 PSU Awards Assumption TSR, rTSR Risk-free interest rate 2.00 % Volatility 70.2 % 2021 PSU Awards Assumption TSR, rTSR Share Price Hurdle Risk-free interest rate 0.23 % 0.30 % Volatility 71.4 % 68.4 %
Summary of the Changes in Unvested Performance Share	A summary of the changes in unvested PSUs is presented below: Unvested Performance Share Units Weighted Average (in thousands) Unvested as of February 10, 2021 — $ — Granted 201 $ 64.41 Vested (9) $ 38.95 Forfeited (9) $ 55.42 Unvested as of December 31, 2021 183 $ 66.12 Granted 133 $ 109.65 Vested — $ — Forfeited (40) $ 57.48 Unvested as of December 31, 2022 276 $ 88.28 Granted 131 $ 78.78 Vested — $ — Forfeited (13) $ 68.77 Unvested as of December 31, 2023 394 $ 85.78
Schedule of compensation costs (credit), net of actual forfeitures	We recognized the following compensation costs, net of actual forfeitures, related to RSUs and PSUs for the periods presented: Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 General and administrative expenses $ 29 $ 19 $ 7 $ 3 Natural gas and oil properties 6 4 2 — Production expense 4 3 2 — Total RSU and PSU compensation $ 39 $ 26 $ 11 $ 3 Related income tax benefit $ 7 $ 6 $ — $ —

Derivative and Hedging Activi_2

Derivative and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of estimated fair value of oil, natural gas and NGL derivative instrument asset (liabilities)	The estimated fair values of our natural gas and oil derivative instrument assets (liabilities) as of December 31, 2023 and 2022 are provided below: Successor December 31, 2023 December 31, 2022 Notional Volume Fair Value Notional Volume Fair Value Natural gas (Bcf): Fixed-price swaps 343 $ 188 382 $ (494) Collars 558 497 721 49 Three-way collars — — 4 (2) Call options — — 18 (22) Basis protection swaps 578 2 652 (32) Total natural gas 1,479 687 1,777 (501) Oil (MMBbls): Fixed-price swaps — — 1 (32) Collars — — 2 7 Basis protection swaps — — 6 1 Total oil — — 9 (24) Contingent Consideration: Eagle Ford divestiture 12 — Total estimated fair value $ 699 $ (525)
Schedule of effects of derivative instruments in consolidated balance sheets	The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2023 and 2022 on a gross basis and after same-counterparty netting: Gross Fair Value (a) Amounts Netted in the Consolidated Balance Sheets Net Fair Value Presented in the Consolidated Balance Sheets Successor As of December 31, 2023 Commodity Contracts: Short-term derivative asset $ 661 $ (36) $ 625 Long-term derivative asset 101 (27) 74 Short-term derivative liability (39) 36 (3) Long-term derivative liability (36) 27 (9) Contingent Consideration: Short-term derivative asset 12 — 12 Total derivatives $ 699 $ — $ 699 As of December 31, 2022 Commodity Contracts: Short-term derivative asset $ 200 $ (166) $ 34 Long-term derivative asset 87 (40) 47 Short-term derivative liability (598) 166 (432) Long-term derivative liability (214) 40 (174) Total derivatives $ (525) $ — $ (525) ___________________________________________ (a) These financial assets (liabilities) are measured at fair value on a recurring basis utilizing significant other observable inputs; see further discussion on fair value measurements below.
Schedule of effects of derivative instruments in accumulated other comprehensive income (loss)	A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below: Predecessor Period from January 1, 2021 through February 9, 2021 Before Tax After Tax Balance, beginning of period $ (12) $ 45 Losses reclassified to income (a) 3 3 Fresh start adjustments 9 9 Elimination of tax effects — (57) Balance, end of period $ — $ — ___________________________________________ (a) These losses were included as a component of total natural gas and oil derivatives.

Capitalized Exploratory Well _2

Capitalized Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Summary of changes in capitalized well costs	A summary of the changes in our capitalized exploratory well costs for the periods presented is detailed below. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Balance, beginning of period $ 10 $ 14 $ — $ — Additions pending the determination of proved reserves — 1 24 — Divestitures and other (10) — — — Reclassifications to proved properties — — (10) — Charges to exploration expense — (5) — — Balance, end of period (a) $ — $ 10 $ 14 $ — ___________________________________________ (a) Our capitalized exploratory well costs balance as of December 31, 2022, consisted of one project for which we had suspended exploratory well costs capitalized for a period greater than one year. During the 2023 Successor Period, this project was divested.

Other Property and Equipment (T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Summary of other property and equipment held for use and estimated useful lives	A summary of other property and equipment held for use and the estimated useful lives thereof is as follows: Successor Estimated Useful Life December 31, 2023 December 31, 2022 (in years) Buildings and improvements $ 316 $ 325 10 - 39 Computer equipment 94 92 5 Land 28 32 Other 59 51 5 - 20 Total other property and equipment, at cost 497 500 Less: accumulated depreciation (90) (58) Total other property and equipment, net $ 407 $ 442

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Schedule of asset retirement obligations	The components of the change in our asset retirement obligations are shown below: Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Asset retirement obligations, beginning of period $ 335 $ 360 Additions (a) 9 53 Revisions (b) (9) 16 Settlements and disposals (c) (75) (54) Held for sale (d) — (57) Accretion expense 16 17 Asset retirement obligations, end of period 276 335 Less current portion 11 12 Asset retirement obligations, long-term $ 265 $ 323 ___________________________________________ (a) During the 2022 Successor Period, approximately $27 million of additions relate to the Marcellus Acquisition. See Note 4 for further discussion of this transaction. (b) Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties. (c) During the 2023 Successor Period, approximately $64 million of disposals related to the divestitures of our Eagle Ford assets. During the 2022 Successor Period, approximately $47 million of disposals related to the divestiture of our Powder River Basin assets. See Note 4 for further discussion of these transactions. (d) As of December 31, 2022, approximately $57 million of asset retirement obligations associated with the sale of a portion of our Eagle Ford assets were reclassified as other current liabilities held for sale.

Supplemental Disclosures Abou_2

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Schedule of capitalized costs	Capitalized costs related to our natural gas, oil and NGL producing activities are summarized as follows: Successor December 31, 2023 December 31, 2022 Natural gas and oil properties: Proved $ 11,468 $ 11,096 Unproved 1,806 2,022 Total 13,274 13,118 Less accumulated depreciation, depletion and amortization (3,584) (2,373) Net capitalized costs $ 9,690 $ 10,745
Schedule of exploration expense and cost incurred	Costs incurred in natural gas and oil property acquisition, exploration and development, including capitalized interest and asset retirement costs, are summarized as follows: Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Acquisition of properties (a) : Proved properties $ 10 $ 2,321 $ 2,183 $ — Unproved properties 52 795 1,121 — Exploratory costs 15 15 31 — Development costs 1,721 1,918 717 58 Costs incurred $ 1,798 $ 5,049 $ 4,052 $ 58 ___________________________________________ (a) Includes $2.31 billion and $0.79 billion of proved and unproved property acquisitions, respectively, related to our Marcellus Acquisition in 2022. Includes $2.18 billion and $1.10 billion of proved and unproved property acquisitions, respectively, related to our Vine Acquisition in 2021.
Schedule of revenues and expenses	The following table includes revenues and expenses associated directly with our natural gas, oil and NGL producing activities for the periods presented. It does not include any derivative activity, interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas, oil and NGL operations. Successor Predecessor Year Ended Year Ended Period from February 10, 2021 through December 31, 2021 Period from January 1, 2021 through February 9, 2021 Natural gas, oil and NGL sales $ 3,547 $ 9,892 $ 4,401 $ 398 Production expenses (356) (475) (297) (32) Gathering, processing and transportation expenses (853) (1,059) (780) (102) Severance and ad valorem taxes (167) (242) (158) (18) Exploration (27) (23) (7) (2) Depletion and depreciation (1,478) (1,703) (882) (64) Accretion of asset retirement obligations (16) (17) (11) (1) Imputed income tax provision (a) (152) (1,440) (535) (42) Results of operations from natural gas, oil and NGL producing activities $ 498 $ 4,933 $ 1,731 $ 137 ___________________________________________ (a) The imputed income tax provision is hypothetical (at the statutory tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable).
Schedule of changes in estimated reserves	Presented below is a summary of changes in estimated proved reserves for the periods presented: Natural Gas Oil NGL Total (Bcf) (MMBbl) (MMBbl) (Bcfe) December 31, 2023 Proved reserves, beginning of period (Successor) 11,369 198.4 73.9 13,002 Extensions, discoveries and other additions 415 — — 415 Revisions of previous estimates (325) — — (325) Production (1,266) (7.7) (3.8) (1,335) Sale of reserves-in-place (563) (190.7) (70.1) (2,127) Purchase of reserves-in-place 58 — — 58 Proved reserves, end of period (Successor) 9,688 — — 9,688 Proved developed reserves: Beginning of period (Successor) 7,385 157.2 58.9 8,681 End of period (Successor) 6,363 — — 6,363 Proved undeveloped reserves: Beginning of period (Successor) 3,984 41.2 15.0 4,321 End of period (a) (Successor) 3,325 — — 3,325 December 31, 2022 Proved reserves, beginning of period (Successor) 7,824 209.7 82.0 9,573 Extensions, discoveries and other additions 60 2.1 1.5 82 Revisions of previous estimates 1,989 22.5 5.0 2,155 Production (1,308) (19.4) (6.0) (1,461) Sale of reserves-in-place (122) (16.5) (8.6) (273) Purchase of reserves-in-place 2,926 — — 2,926 Proved reserves, end of period (Successor) 11,369 198.4 73.9 13,002 Proved developed reserves: Beginning of period (Successor) 4,246 165.7 61.7 5,610 End of period (Successor) 7,385 157.2 58.9 8,681 Proved undeveloped reserves: Beginning of period (Successor) 3,578 44.0 20.3 3,963 End of period (a) (Successor) 3,984 41.2 15.0 4,321 Natural Gas Oil NGL Total (Bcf) (MMBbl) (MMBbl) (Bcfe) December 31, 2021 Proved reserves, beginning of period (Predecessor) 3,530 161.3 52.0 4,809 Extensions, discoveries and other additions 1,744 41.0 16.9 2,091 Revisions of previous estimates 1,522 33.3 21.1 1,848 Production (807) (25.9) (8.0) (1,010) Sale of reserves-in-place — — — — Purchase of reserves-in-place 1,835 — — 1,835 Proved reserves, end of period (Successor) 7,824 209.7 82.0 9,573 Proved developed reserves: Beginning of period (Predecessor) 3,196 158.1 51.4 4,452 End of period (Successor) 4,246 165.7 61.7 5,610 Proved undeveloped reserves: Beginning of period (Predecessor) 334 3.2 0.6 357 End of period (a) (Successor) 3,578 44.0 20.3 3,963 ___________________________________________ (a) As of December 31, 2023, 2022 and 2021, there were no PUDs that had remained undeveloped for five years or more.
Schedule of future net cash flows relating to proved natural gas, oil and NGL reserves based on the standardized measure	The following summary sets forth our future net cash flows relating to proved natural gas, oil and NGL reserves based on the standardized measure: Years Ended December 31, 2023 2022 2021 Future cash inflows $ 14,659 (a) $ 76,626 (b) $ 33,700 (c) Future production costs (3,326) (10,177) (6,735) Future development costs (2,779) (d) (5,343) (e) (3,687) (f) Future income tax provisions (174) (10,440) (2,254) Future net cash flows 8,380 50,666 21,024 Less effect of a 10% discount factor (3,903) (24,361) (8,737) Standardized measure of discounted future net cash flows $ 4,477 $ 26,305 $ 12,287 ___________________________________________ (a) Calculated using prices of $2.64 per Mcf of natural gas, before basis differential adjustments. (b) Calculated using prices of $6.36 per Mcf of natural gas, $93.67 per Bbl of oil and $43.58 per Bbl of NGL, before basis differential adjustments. (c) Calculated using prices of $3.60 per Mcf of natural gas, $66.56 per Bbl of oil and $35.81 per Bbl of NGL, before basis differential adjustments. (d) Included approximately $730 million of future plugging and abandonment costs as of December 31, 2023. (e) Included approximately $979 million of future plugging and abandonment costs as of December 31, 2022.
Sources of change in standardized measure of discounted future net cash flow	The principal sources of change in the standardized measure of discounted future net cash flows are as follows: Years Ended December 31, 2023 2022 2021 Standardized measure, beginning of period (a) $ 26,305 $ 12,287 $ 3,086 Sales of natural gas and oil produced, net of production costs and gathering, processing and transportation (b) (2,171) (8,116) (3,414) Net changes in prices and production costs (23,535) 14,256 6,674 Extensions and discoveries, net of production and 182 251 2,834 Changes in estimated future development costs 346 (1,512) (459) Previously estimated development costs incurred during the period 818 690 130 Revisions of previous quantity estimates (205) 6,697 2,034 Purchase of reserves-in-place 77 7,047 2,807 Sales of reserves-in-place (7,158) (402) — Accretion of discount 3,270 1,371 309 Net change in income taxes 6,301 (4,972) (1,423) Changes in production rates and other 247 (1,292) (291) Standardized measure, end of period (a) $ 4,477 $ 26,305 $ 12,287 ___________________________________________ (a) The impact of cash flow hedges has not been included in any of the periods presented. (b) Excludes gains and losses on derivatives. Production costs includes severance and ad valorem taxes.

Basis of Presentation and Sum_3

Basis of Presentation and Summary of Significant Accounting Policies (Details) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2023 USD ($) segment	Dec. 31, 2022 USD ($)
Summary of Significant Accounting Policies [Table] [Line Items]
Number of reportable segments | segment			1
Restricted cash			$ 74	$ 62
Other accounts payable				150
Losses on purchases or exchanges of debt	$ 0	$ 0	$ 0	5
Revenue, payment terms			Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 days.
Credit facility
Summary of Significant Accounting Policies [Table] [Line Items]
Unamortized issuance costs			$ 19
Senior notes
Summary of Significant Accounting Policies [Table] [Line Items]
Unamortized issuance costs			$ 5
Exit credit facility | Credit facility
Summary of Significant Accounting Policies [Table] [Line Items]
Losses on purchases or exchanges of debt				$ 5
Employee
Summary of Significant Accounting Policies [Table] [Line Items]
Vesting period			3 years

Chapter 11 Emergence (Details)

Chapter 11 Emergence (Details) $ in Millions	Feb. 09, 2021 USD ($) boardMember shares
Director
Debt Instrument [Line Items]
Number of individuals elected in Board of Directors (in individuals) | boardMember	7
Non-Employee Directors
Debt Instrument [Line Items]
Number of individuals elected in Board of Directors (in individuals) | boardMember	5
2021 Long Term Incentive Plan
Debt Instrument [Line Items]
Common stock, reserved for future issuance (in shares)	6,800,000
Allowed General Unsecured Claim
Debt Instrument [Line Items]
Pro rata share received by holder | $	$ 10
Allowed General Unsecured Claim | Maximum
Debt Instrument [Line Items]
Percent of convenience claim	5%
New Common Stock
Debt Instrument [Line Items]
Issuance of Successor common stock (in shares)	97,907,081
Common stock, reserved for future issuance (in shares)	2,092,918
New Common Stock | Backstop Parties, Put Option Premium
Debt Instrument [Line Items]
Issuance of Successor common stock (in shares)	6,337,031
New Common Stock | Backstop Parties, Obligations
Debt Instrument [Line Items]
Issuance of Successor common stock (in shares)	442,991
New Common Stock | Rights Offering
Debt Instrument [Line Items]
Issuance of Successor common stock (in shares)	62,927,320
New Common Stock | Class A Warrants
Debt Instrument [Line Items]
Warrants issued (in shares)	11,111,111
New Common Stock | Class B Warrants
Debt Instrument [Line Items]
Warrants issued (in shares)	12,345,679
New Common Stock | Class C Warrants
Debt Instrument [Line Items]
Common stock, reserved for future issuance (in shares)	3,948,893
Warrants issued (in shares)	9,768,527
New Common Stock | FLLO Term Loan Facility
Debt Instrument [Line Items]
Issuance of Successor common stock (in shares)	23,022,420
New Common Stock | Second Lien Notes
Debt Instrument [Line Items]
Issuance of Successor common stock (in shares)	3,635,118
New Common Stock | Second Lien Notes | Class A Warrants
Debt Instrument [Line Items]
Common stock, reserved for future issuance (in shares)	11,111,111
Warrants issued (in shares)	11,111,111
New Common Stock | Second Lien Notes | Class B Warrants
Debt Instrument [Line Items]
Common stock, reserved for future issuance (in shares)	12,345,679
Warrants issued (in shares)	12,345,679
New Common Stock | Second Lien Notes | Class C Warrants
Debt Instrument [Line Items]
Common stock, reserved for future issuance (in shares)	6,858,710
Warrants issued (in shares)	6,858,710
New Common Stock | Allowed Unsecured Notes
Debt Instrument [Line Items]
Issuance of Successor common stock (in shares)	1,311,089
New Common Stock | Allowed Unsecured Notes | Class C Warrants
Debt Instrument [Line Items]
Common stock, reserved for future issuance (in shares)	2,473,757
Warrants issued (in shares)	2,473,757
New Common Stock | Allowed General Unsecured Claim
Debt Instrument [Line Items]
Issuance of Successor common stock (in shares)	231,112
New Common Stock | Allowed General Unsecured Claim | Class C Warrants
Debt Instrument [Line Items]
Common stock, reserved for future issuance (in shares)	436,060
Warrants issued (in shares)	436,060
New Common Stock | Upon Exercise of Warrants
Debt Instrument [Line Items]
Common stock, reserved for future issuance (in shares)	37,174,210

Fresh Start Accounting - Additi

Fresh Start Accounting - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
Reorganization, Chapter 11 [Line Items]
Total assets	$ 14,376	$ 15,468	$ 6,814
Liabilities	$ 3,647	$ 6,344	3,228
Enterprise value			$ 4,851
Maximum
Reorganization, Chapter 11 [Line Items]
Percent of voting shares received by holders			50%
Predecessor
Reorganization, Chapter 11 [Line Items]
Total assets			$ 6,595
Liabilities			13,175
Reorganization, Chapter 11, Fresh-Start Adjustment
Reorganization, Chapter 11 [Line Items]
Total assets			359
Liabilities			149
Reorganization, Chapter 11, Fresh-Start Adjustment | Minimum
Reorganization, Chapter 11 [Line Items]
Enterprise value			3,500
Reorganization, Chapter 11, Fresh-Start Adjustment | Maximum
Reorganization, Chapter 11 [Line Items]
Enterprise value			$ 4,900

Fresh Start Accounting - Succes

Fresh Start Accounting - Successor’s Equity (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 09, 2021	Dec. 31, 2020
Reorganization, Chapter 11 [Line Items]
Enterprise Value				$ 4,851
Plus: Cash and cash equivalents	$ 1,079	$ 130	$ 905	40
Less: Fair value of debt	(1,950)			(1,313)
Successor equity value	$ 10,729	$ 9,124	$ 5,671	3,586	$ (5,341)
Reorganization, Chapter 11, Fresh-Start Adjustment
Reorganization, Chapter 11 [Line Items]
Plus: Cash and cash equivalents				48
Less: Fair value of debt				(52)
Successor equity value				$ 210

Fresh Start Accounting - Enterp

Fresh Start Accounting - Enterprise Value Reconciliation (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 09, 2021
Reorganization, Chapter 11 [Line Items]
Enterprise Value				$ 4,851
Plus: Cash and cash equivalents	$ 1,079	$ 130	$ 905	40
Plus: Current liabilities	1,314	2,704		1,582
Plus: Asset retirement obligations (non-current portion)	265	323		236
Total assets	$ 14,376	$ 15,468		6,814
Restricted cash				86
Reorganization, Chapter 11, Fresh-Start Adjustment
Reorganization, Chapter 11 [Line Items]
Plus: Cash and cash equivalents				48
Plus: Current liabilities				0
Plus: Asset retirement obligations (non-current portion)				97
Plus: Other non-current liabilities				97
Total assets				359
Restricted cash				$ 8

Fresh Start Accounting - Debt a

Fresh Start Accounting - Debt and Warrants (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 09, 2021	Dec. 31, 2023
Debt Instrument [Line Items]
Implied stock price (in dollars per share)	$ 20.52
Expected volatility rate	58%
Expected dividend yield rate	0%
Repayments of long-term debt	$ 1,179
Net impact to long-term debt, net	$ 1,313	$ 1,950
Class A Warrants
Debt Instrument [Line Items]
Warrant, exercise price (in dollars per share)	$ 27.63	$ 23.25
Class B Warrants
Debt Instrument [Line Items]
Warrant, exercise price (in dollars per share)	32.13	27.04
Class C Warrants
Debt Instrument [Line Items]
Warrant, exercise price (in dollars per share)	$ 36.18	$ 30.45
Senior notes | 5.50% senior notes due 2026
Debt Instrument [Line Items]
Debt, principal	$ 500
Interest rate	5.50%	5.50%
Senior notes | 5.875% senior notes due 2029
Debt Instrument [Line Items]
Debt, principal	$ 500
Interest rate	5.875%	5.875%
Secured Debt
Debt Instrument [Line Items]
Net impact to long-term debt, net	$ 750

Fresh Start Accounting - Conden

Fresh Start Accounting - Condensed Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 09, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 1,079	$ 130	$ 905	$ 40
Restricted cash				86
Accounts receivable, net				843
Short-term derivative assets	637	34		0
Other current assets				61
Total current assets	2,609	2,698		1,030
Property and equipment:
Proved natural gas and oil properties	11,468	11,096		4,686
Unproved properties	1,806	2,022		483
Other property and equipment	497	500		499
Total property and equipment	13,771	13,618		5,668
Less: accumulated depreciation, depletion and amortization	(3,674)	(2,431)		0
Property and equipment held for sale, net				2
Total property and equipment, net	10,097	11,187		5,670
Other long-term assets	663	185		114
Total assets	14,376	15,468		6,814
Current liabilities:
Accounts payable	425	603		415
Current maturities of long-term debt, net				0
Accrued interest	39	42		0
Short-term derivative liabilities	3	432		398
Other current liabilities	847	1,627		769
Total current liabilities	1,314	2,704		1,582
Net impact to long-term debt, net	1,950			1,313
Long-term derivative liabilities	9	174		90
Asset retirement obligations, net of current portion	265	323		236
Other long-term liabilities	31	50		7
Liabilities subject to compromise				0
Total liabilities	3,647	6,344		3,228
Contingencies and commitments (Note 7)
Stockholders’ equity (deficit):
Predecessor preferred stock				0
Predecessor additional paid-in capital	5,754	5,724		0
Successor common stock	1	1		1
Successor additional paid-in-capital				3,585
Accumulated other comprehensive income				0
Retained earnings	4,974	3,399		0
Total stockholders' equity	10,729	9,124	$ 5,671	3,586	$ (5,341)
Total liabilities and stockholders' equity	$ 14,376	$ 15,468		6,814
Predecessor
Current assets:
Cash and cash equivalents				243
Restricted cash				0
Accounts receivable, net				861
Short-term derivative assets				0
Other current assets				66
Total current assets				1,170
Property and equipment:
Proved natural gas and oil properties				25,794
Unproved properties				1,546
Other property and equipment				1,755
Total property and equipment				29,095
Less: accumulated depreciation, depletion and amortization				(23,877)
Property and equipment held for sale, net				9
Total property and equipment, net				5,227
Other long-term assets				198
Total assets				6,595
Current liabilities:
Accounts payable				391
Current maturities of long-term debt, net				1,929
Accrued interest				4
Short-term derivative liabilities				398
Other current liabilities				645
Total current liabilities				3,367
Net impact to long-term debt, net				0
Long-term derivative liabilities				90
Asset retirement obligations, net of current portion				139
Other long-term liabilities				5
Liabilities subject to compromise				9,574
Total liabilities				13,175
Contingencies and commitments (Note 7)
Stockholders’ equity (deficit):
Predecessor preferred stock				1,631
Predecessor additional paid-in capital				16,940
Successor common stock				0
Successor additional paid-in-capital				0
Accumulated other comprehensive income				48
Retained earnings				(25,199)
Total stockholders' equity				(6,580)
Total liabilities and stockholders' equity				6,595
Reorganization Adjustments
Current assets:
Cash and cash equivalents				(203)
Restricted cash				86
Accounts receivable, net				(18)
Short-term derivative assets				0
Other current assets				(5)
Total current assets				(140)
Property and equipment:
Proved natural gas and oil properties				0
Unproved properties				0
Other property and equipment				0
Total property and equipment				0
Less: accumulated depreciation, depletion and amortization				0
Property and equipment held for sale, net				0
Total property and equipment, net				0
Other long-term assets				0
Total assets				(140)
Current liabilities:
Accounts payable				24
Current maturities of long-term debt, net				(1,929)
Accrued interest				(4)
Short-term derivative liabilities				0
Other current liabilities				124
Total current liabilities				(1,785)
Net impact to long-term debt, net				1,261
Long-term derivative liabilities				0
Asset retirement obligations, net of current portion				0
Other long-term liabilities				2
Liabilities subject to compromise				(9,574)
Total liabilities				(10,096)
Contingencies and commitments (Note 7)
Stockholders’ equity (deficit):
Predecessor preferred stock				(1,631)
Predecessor additional paid-in capital				(16,940)
Successor common stock				1
Successor additional paid-in-capital				3,585
Accumulated other comprehensive income				0
Retained earnings				24,941
Total stockholders' equity				9,956
Total liabilities and stockholders' equity				(140)
Reorganization, Chapter 11, Fresh-Start Adjustment
Current assets:
Cash and cash equivalents				48
Restricted cash				8
Accounts receivable, net				0
Short-term derivative assets				0
Other current assets				0
Total current assets				0
Property and equipment:
Proved natural gas and oil properties				(21,108)
Unproved properties				(1,063)
Other property and equipment				(1,256)
Total property and equipment				(23,427)
Less: accumulated depreciation, depletion and amortization				23,877
Property and equipment held for sale, net				(7)
Total property and equipment, net				443
Other long-term assets				(84)
Total assets				359
Current liabilities:
Accounts payable				0
Current maturities of long-term debt, net				0
Accrued interest				0
Short-term derivative liabilities				0
Other current liabilities				0
Total current liabilities				0
Net impact to long-term debt, net				52
Long-term derivative liabilities				0
Asset retirement obligations, net of current portion				97
Other long-term liabilities				0
Liabilities subject to compromise				0
Total liabilities				149
Contingencies and commitments (Note 7)
Stockholders’ equity (deficit):
Predecessor preferred stock				0
Predecessor additional paid-in capital				0
Successor common stock				0
Successor additional paid-in-capital				0
Accumulated other comprehensive income				(48)
Retained earnings				258
Total stockholders' equity				210
Total liabilities and stockholders' equity				$ 359

Fresh Start Accounting - Source

Fresh Start Accounting - Sources and Uses of Cash (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Sources:
Proceeds from issuance of the Notes		$ 1,000	$ 0	$ 0	$ 0
Uses:
Payment of roll-up of DIP Facility balance	$ (1,179)
Reorganization Adjustments
Sources:
Proceeds from issuance of the Notes	1,000
Proceeds from Rights Offering	600
Proceeds from refunds of interest deposit for the Notes	5
Total sources of cash	1,605
Uses:
Payment of roll-up of DIP Facility balance	(1,179)
Payment of Exit Credit Facility - Tranche A Loan	(479)
Transfers to restricted cash for professional fee reserve	(76)
Transfers to restricted cash for convenience claim distribution reserve	(10)
Payment of professional fees	(31)
Payment of DIP Facility interest and fees	(12)
Payment of FLLO alternative transaction fee	(12)
Payment of the Notes fees funded out of escrow	(8)
Payment of RBL interest and fees	(1)
Total uses of cash	(1,808)
Net cash used	$ (203)

Fresh Start Accounting - Change

Fresh Start Accounting - Changes in Accounts Payable (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
Reorganization, Chapter 11 [Line Items]
Net impact to accounts payable	$ 425	$ 603	$ 415
Reorganization Adjustments
Reorganization, Chapter 11 [Line Items]
Accrual of professional service provider success fees			38
Accrual of convenience claim distribution reserve			10
Accrual of professional service provider fees			5
Reinstatement of accounts payable from liabilities subject to compromise			2
Payment of professional fees			(31)
Net impact to accounts payable			$ 24

Fresh Start Accounting - Chan_2

Fresh Start Accounting - Changes in Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
Reorganization, Chapter 11 [Line Items]
Net impact to other current liabilities	$ 847	$ 1,627	$ 769
Reorganization Adjustments
Reorganization, Chapter 11 [Line Items]
Reinstatement of other current liabilities from liabilities subject to compromise			191
Accrual of the Notes fees			2
Settlement of Put Option Premium through issuance of Successor Common Stock			(60)
Payment of DIP Facility fees			(9)
Net impact to other current liabilities			$ 124

Fresh Start Accounting - Chan_3

Fresh Start Accounting - Changes in Long-Term Debt (Details) - USD ($) $ in Millions	Feb. 09, 2021	Dec. 31, 2023	Dec. 31, 2022
Reorganization, Chapter 11 [Line Items]
Debt issuance costs for the Notes		$ (5)	$ (7)
Net impact to long-term debt, net	$ 1,313	$ 1,950
Reorganization Adjustments
Reorganization, Chapter 11 [Line Items]
Issuance of the Notes	1,000
Issuance of Tranche A and Tranche B Loans	750
Payments on Tranche A Loans	(479)
Debt issuance costs for the Notes	(10)
Net impact to long-term debt, net	$ 1,261

Fresh Start Accounting - Liabil

Fresh Start Accounting - Liabilities Subject to Compromise (Details) $ in Millions		1 Months Ended
	Feb. 09, 2021 USD ($)	Feb. 09, 2021 USD ($)
Reorganization, Chapter 11 [Line Items]
Liabilities subject to compromise	$ 0	$ 0
Consideration provided to settle amounts per the Plan or Reorganization:
Issuance of Successor common stock to FLLO Term Loan holders, incremental to the Rights Offering and Backstop Commitment	(783)
Issuance of Successor common stock to Second Lien Note holders, incremental to the Rights Offering and Backstop Commitment	(124)
Issuance of Successor common stock to unsecured note holders	(45)
Issuance of Successor common stock to General Unsecured Claims	(8)
Gain on settlement of liabilities subject to compromise		6,443
Class A Warrants
Consideration provided to settle amounts per the Plan or Reorganization:
Warrants	93
Class B Warrants
Consideration provided to settle amounts per the Plan or Reorganization:
Warrants	94
Class C Warrants
Consideration provided to settle amounts per the Plan or Reorganization:
Warrants	68
Predecessor
Reorganization, Chapter 11 [Line Items]
Liabilities subject to compromise	9,574	9,574
To be reinstated on the Effective Date:
Accounts payable	(2)	(2)
Other current liabilities	(191)	(191)
Other long-term liabilities	(2)	(2)
Total liabilities reinstated	(195)	(195)
Consideration provided to settle amounts per the Plan or Reorganization:
Issuance of Successor common stock associated with the Rights Offering and Backstop Commitment and settlement of the Put Option Premium	(2,311)
Proceeds from issuance of Successor common stock associated with the Rights Offering and Backstop Commitment	600
Issuance of Successor common stock to FLLO Term Loan holders, incremental to the Rights Offering and Backstop Commitment	(783)
Issuance of Successor common stock to Second Lien Note holders, incremental to the Rights Offering and Backstop Commitment	(124)
Issuance of Successor common stock to unsecured note holders	(45)
Issuance of Successor common stock to General Unsecured Claims	(8)
Proceeds to holders of general unsecured claims	(10)
Total consideration provided to settle amounts per the Plan	(2,936)	$ (2,936)
Gain on settlement of liabilities subject to compromise	6,443
Predecessor | Class A Warrants
Consideration provided to settle amounts per the Plan or Reorganization:
Warrants	(93)
Predecessor | Class B Warrants
Consideration provided to settle amounts per the Plan or Reorganization:
Warrants	(94)
Predecessor | Class C Warrants
Consideration provided to settle amounts per the Plan or Reorganization:
Warrants	$ (68)

Fresh Start Accounting - Equity

Fresh Start Accounting - Equity Issuance (Details) - New Common Stock	Feb. 09, 2021 shares
Debt Instrument [Line Items]
Issuance of Successor common stock (in shares)	97,907,081
Class A Warrants
Debt Instrument [Line Items]
Warrants issued (in shares)	11,111,111
Class B Warrants
Debt Instrument [Line Items]
Warrants issued (in shares)	12,345,679
Class C Warrants
Debt Instrument [Line Items]
Warrants issued (in shares)	9,768,527

Fresh Start Accounting - Chan_4

Fresh Start Accounting - Change in Successor Additional Paid-in Capital (Details) - USD ($) $ in Millions	Feb. 09, 2021	Dec. 31, 2023	Dec. 31, 2022
Class of Stock [Line Items]
Issuance of Successor equity associated with the Rights Offering and Backstop Commitment	$ 2,371
Issuance of Successor equity to holders of the FLLO Term Loan, incremental to the Rights Offering and Backstop Commitment	783
Issuance of Successor equity to holders of the Second Lien Notes, incremental to the Rights Offering and Backstop Commitment	124
Issuance of Successor equity to holders of the unsecured senior notes	45
Issuance of Successor equity to holders of allowed general unsecured claims	8
Total change in Successor common stock and additional paid-in capital	3,586
Less: par value of Successor common stock	(1)	$ (1)	$ (1)
Change in Successor additional paid-in capital	3,585
Class A Warrants
Class of Stock [Line Items]
Warrants	93
Class B Warrants
Class of Stock [Line Items]
Warrants	94
Class C Warrants
Class of Stock [Line Items]
Warrants	$ 68

Fresh Start Accounting - Cumula

Fresh Start Accounting - Cumulative Net Impact on Accumulated Deficit (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Reorganization, Chapter 11 [Line Items]
Gain on settlement of liabilities subject to compromise		$ 6,443
Surrender of other receivable		18
Total reorganization items, net		(5,569)	$ 0	$ 0	$ 0
Net impact on accumulated deficit	$ 0	0		$ 4,974	$ 3,399
Reorganization Adjustments
Reorganization, Chapter 11 [Line Items]
Gain on settlement of liabilities subject to compromise	6,443
Accrual of professional service provider success fees	(38)	(38)
Accrual of professional service provider fees	(5)	(5)
Surrender of other receivable	(18)
Payment of FLLO alternative transaction fee	(12)
Total reorganization items, net	6,370
Cancellation of predecessor equity	18,571	18,571
Net impact on accumulated deficit	$ 24,941	$ 24,941

Fresh Start Accounting - Fresh

Fresh Start Accounting - Fresh Start Adjustments (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Reorganization, Chapter 11 [Line Items]
Inflation factor	2%	2%
Average credit-adjusted risk-free rate	5.18%	5.18%
Income tax effects on accumulated other comprehensive income	$ 57	$ 57
Income tax benefit	57	57	$ 49	$ (698)	$ 1,285
Reorganization, Chapter 11, Fresh-Start Adjustment
Reorganization, Chapter 11 [Line Items]
Income tax effects on accumulated other comprehensive income	57	57
Accumulated other comprehensive income	9	9
Senior notes
Reorganization, Chapter 11 [Line Items]
Debt, fair value adjustments	22	22
Senior notes
Reorganization, Chapter 11 [Line Items]
Debt, fair value adjustments	$ 30	$ 30

Fresh Start Accounting - Impact

Fresh Start Accounting - Impact on Accumulated Deficit (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
Reorganization, Chapter 11 [Line Items]
Fresh start adjustments to property and equipment	$ 10,097	$ 11,187	$ 5,670
Fresh start adjustments to other long-term assets	663	185	114
Net impact to long-term debt, net	(1,950)		(1,313)
Asset retirement obligations, net of current portion	$ (265)	$ (323)	(236)
Income tax effects on accumulated other comprehensive income			57
Reorganization, Chapter 11, Fresh-Start Adjustment
Reorganization, Chapter 11 [Line Items]
Fresh start adjustments to property and equipment			443
Fresh start adjustments to other long-term assets			(84)
Net impact to long-term debt, net			(52)
Asset retirement obligations, net of current portion			(97)
Fresh start adjustments to accumulated other comprehensive income			(9)
Total fresh start adjustments impacting reorganizations items, net			201
Income tax effects on accumulated other comprehensive income			57
Net impact to accumulated deficit			$ 258

Fresh Start Accounting - Reorga

Fresh Start Accounting - Reorganization Items, Net (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Reorganization, Chapter 11 [Line Items]
Gain on settlement of liabilities subject to compromise		$ 6,443
Accrual for allowed claims		(1,002)
Gain on fresh start adjustments		201
Gain from release of commitment liabilities		55
Professional service provider fees and other		(60)
Success fees for professional service providers		(38)
Surrender of other receivable		(18)
FLLO alternative transaction fee		(12)
Total reorganization items, net		$ 5,569	$ 0	$ 0	$ 0
Reorganization Adjustments
Reorganization, Chapter 11 [Line Items]
Gain on settlement of liabilities subject to compromise	$ 6,443
Surrender of other receivable	18
Total reorganization items, net	$ (6,370)

Natural Gas and Oil Property _3

Natural Gas and Oil Property Transactions - Narrative (Details) shares in Millions, $ in Millions							1 Months Ended		2 Months Ended	9 Months Ended	10 Months Ended	11 Months Ended	12 Months Ended
	Nov. 30, 2023 USD ($)	Apr. 28, 2023 USD ($)	Mar. 20, 2023 USD ($)	Mar. 25, 2022 USD ($)	Mar. 09, 2022 USD ($) shares	Nov. 01, 2021 USD ($) shares	Nov. 30, 2023 USD ($) $ / bbl	Feb. 09, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Aug. 31, 2023 USD ($)	Feb. 28, 2023 USD ($)	Jan. 31, 2023 USD ($)
Business Acquisition [Line Items]
Derivative (gains) losses, net								$ 382				$ 1,127	$ (1,728)	$ 2,680
Costs and expenses								494				4,611	5,579	7,963
Share-based compensation								3				9	33	22
Nonoperating expense								(5,560)				42	25	129
Contingent Consideration
Business Acquisition [Line Items]
Derivative, fair value, net													12
WTI NYMEX Price Average Above $80 per Barrel
Business Acquisition [Line Items]
Average sales price (in usd per unit) | $ / bbl							80
Minimum | WTI NYMEX Price Average $75 to $80 per Barrel
Business Acquisition [Line Items]
Average sales price (in usd per unit) | $ / bbl							75
Maximum | WTI NYMEX Price Average $75 to $80 per Barrel
Business Acquisition [Line Items]
Average sales price (in usd per unit) | $ / bbl							80
Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Gain (loss) on sale of oil and natural gas properties														293
Proceeds from divestitures of property and equipment				$ 450
Disposal group, disposed of by sale, not discontinued operations | Post-Close Adjustments
Business Acquisition [Line Items]
Gain (loss) on sale of oil and natural gas properties										$ 13
Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Consideration received																	$ 1,425
Purchase price			$ 225
Gain (loss) on sale of oil and natural gas properties			337
Property, plant and equipment										811	$ 811			811
Other assets held-for-sale										8	8			8
Derivative liabilities										65	65			65
ARO liabilities										57	57			57
Other liabilities										$ 22	22			22
Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | Short-term derivative asset
Business Acquisition [Line Items]
Deferred consideration reflected with assets													58
Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | Long-term derivative asset
Business Acquisition [Line Items]
Deferred consideration reflected with assets													135
Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | First Three Years
Business Acquisition [Line Items]
Deferred consideration paid in installments			60
Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | Fourth Year
Business Acquisition [Line Items]
Deferred consideration paid in installments			$ 45
Portion Of Remaining Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Consideration received																$ 1,400
Purchase price		$ 225
Gain (loss) on sale of oil and natural gas properties		470
ARO liabilities		53
Portion Of Remaining Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | Short-term derivative asset
Business Acquisition [Line Items]
Deferred consideration reflected with assets													55
Portion Of Remaining Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | Long-term derivative asset
Business Acquisition [Line Items]
Deferred consideration reflected with assets													144
Portion Of Remaining Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | Next Four Years
Business Acquisition [Line Items]
Deferred consideration paid in installments		$ 56
Final Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Consideration received															$ 700
Purchase price															$ 50
Gain (loss) on sale of oil and natural gas properties	$ 140
ARO liabilities	11						$ 11
Final Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | WTI NYMEX Price Average $75 to $80 per Barrel
Business Acquisition [Line Items]
Consideration received	25						25
Final Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | WTI NYMEX Price Average Above $80 per Barrel
Business Acquisition [Line Items]
Consideration received	$ 50						$ 50
Final Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | Short-term derivative asset
Business Acquisition [Line Items]
Deferred consideration reflected with assets													46
Natural gas, oil and NGL
Business Acquisition [Line Items]
Revenues								398				4,401	3,547	9,892
Marketing
Business Acquisition [Line Items]
Revenues								$ 239				2,263	$ 2,500	4,231
6.75% senior notes due 2029 | Senior notes
Business Acquisition [Line Items]
Interest rate						6.75%							6.75%
Liabilities incurred						$ 950
Marcellus
Business Acquisition [Line Items]
Consideration transferred					$ 2,770
Cash					$ 2,000
Issuance of common stock for Acquisition (in shares) | shares					9.4
Acquisition related costs														41
Measurement period adjustments, cash and current liabilities					$ 39
Derivative (gains) losses, net											379
Costs and expenses											483
Marcellus | Natural gas, oil and NGL
Business Acquisition [Line Items]
Revenues											1,331
Marcellus | Marketing
Business Acquisition [Line Items]
Revenues											$ 20
Marcellus | Exit credit facility
Business Acquisition [Line Items]
Revolving credit facility					$ 914
Vine Acquisition
Business Acquisition [Line Items]
Consideration transferred						1,490
Cash						$ 253
Acquisition related costs												59
Revenues									$ 290					1,863
Derivative (gains) losses, net									(144)					624
Costs and expenses									177					924
Common stock issued for acquisition (in shares) | shares						18.7
Cash consideration						$ 90
Extinguishment of debt						163
Premium paid with cash						13
Severance costs												36
Cash severance												15
Non-cash severance												$ 21
Measurement period adjustments, deferred tax liabilities and unproved properties						19
Share-based compensation						$ 6
Nonoperating expense									$ 12					$ 39

Natural Gas and Oil Property _4

Natural Gas and Oil Property Transactions - Purchase Price Allocation (Details) - USD ($) $ in Millions			1 Months Ended	11 Months Ended	12 Months Ended
	Mar. 09, 2022	Nov. 01, 2021	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Consideration:
Restricted stock unit replacement awards			$ 3	$ 9	$ 33	$ 22
Marcellus
Consideration:
Cash	$ 2,000
Fair value of Chesapeake’s common stock issued in the merger	764
Working capital adjustments	6
Total consideration	2,770
Fair Value of Liabilities Assumed:
Current liabilities	459
Other long-term liabilities	129
Amounts attributable to liabilities assumed	588
Fair Value of Assets Acquired:
Cash, cash equivalents and restricted cash	39
Other current assets	218
Proved natural gas and oil properties	2,309
Unproved properties	788
Other property and equipment	1
Other long-term assets	3
Amounts attributable to assets acquired	3,358
Total identifiable net assets	$ 2,770
Vine Acquisition
Consideration:
Cash		$ 253
Fair value of Chesapeake’s common stock issued in the merger		1,231
Restricted stock unit replacement awards		6
Total consideration		1,490
Fair Value of Liabilities Assumed:
Current liabilities		765
Long-term debt		1,021
Deferred tax liabilities		30		$ 49		$ 30
Other long-term liabilities		272
Amounts attributable to liabilities assumed		2,088
Fair Value of Assets Acquired:
Cash and cash equivalents		59
Other current assets		206
Proved natural gas and oil properties		2,181
Unproved properties		1,099
Other property and equipment		1
Other long-term assets		32
Amounts attributable to assets acquired		3,578
Total identifiable net assets		$ 1,490

Natural Gas and Oil Property _5

Natural Gas and Oil Property Transactions - Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	11 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Revenues	$ 5,891	$ 11,743
Net income (loss) available to common stockholders	$ (5)	$ 4,765
Earnings (loss) per common share:
Basic (in dollars per share)	$ (0.04)	$ 37.37
Diluted (in dollars per share)	$ (0.04)	$ 32.26

Earnings Per Share - Reconcilia

Earnings Per Share - Reconciliation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Earnings Per Share [Abstract]
Net income available to common stockholders, basic	$ 5,383	$ 945	$ 2,419	$ 4,869
Net income (loss) available to common stockholders, diluted	$ 5,383	$ 945	$ 2,419	$ 4,869
Weighted average common shares outstanding, basic (in shares)	9,781	101,754	132,840	125,785
Effect of potentially dilutive securities
Preferred stock (in shares)	290	0	0	0
Warrants (in shares)	0	14,376	9,750	19,734
Restricted stock units (in shares)	0	200	338	395
Performance share units (in shares)	0	11	48	47
Weighted average common shares outstanding, diluted (in shares)	10,071	116,341	142,976	145,961
Earnings per common share:
Basic (in dollars per share)	$ 550.35	$ 9.29	$ 18.21	$ 38.71
Diluted (in dollars per share)	$ 534.51	$ 8.12	$ 16.92	$ 33.36

Earnings Per Share - Additional

Earnings Per Share - Additional Information (Details) - shares	11 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
5.50% Convertible Senior Notes Due 2026 | Senior notes
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Interest rate				5.50%
Class C Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	2,318,446	1,466,502	1,489,337
Common Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	1,228,828	777,369	789,458

Debt - Long-Term Debt (Details)

Debt - Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Nov. 01, 2021	Feb. 09, 2021
Long-term Debt [Abstract]
Fair Value	$ 1,943	$ 2,927
Premiums on senior notes	83	100
Debt issuance costs for the Notes	(5)	(7)
Total long-term debt, net	2,028	3,093
Credit facility | New Credit Facility
Long-term Debt [Abstract]
Revolving credit facility	0	1,050
Fair Value	$ 0	1,050
Senior notes
Long-term Debt [Abstract]
Premiums on senior notes				$ 52
Senior notes | 5.50% senior notes due 2026
Long-term Debt [Abstract]
Interest rate	5.50%			5.50%
Outstanding borrowings	$ 500	500
Fair Value	$ 496	485
Senior notes | 5.875% senior notes due 2029
Long-term Debt [Abstract]
Interest rate	5.875%			5.875%
Outstanding borrowings	$ 500	500
Fair Value	$ 489	475
Senior notes | 6.75% senior notes due 2029
Long-term Debt [Abstract]
Interest rate	6.75%		6.75%
Outstanding borrowings	$ 950	950
Fair Value	$ 958	$ 917

Debt - Debt Maturities (Details

Debt - Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Feb. 09, 2021
Debt Disclosure [Abstract]
2024	$ 0
2025	0
2026	500
2027	0
2028	0
Thereafter	1,450
Total long-term debt	$ 1,950	$ 1,313

Debt - Additional Information (

Debt - Additional Information (Details) - USD ($)		12 Months Ended
	Feb. 09, 2021	Dec. 31, 2023	Dec. 31, 2022	Nov. 01, 2021
Debt Instrument [Line Items]
Unamortized premium		$ 83,000,000	$ 100,000,000
Credit facility
Debt Instrument [Line Items]
Average interest rate			8.70%
Credit facility | New Credit Facility
Debt Instrument [Line Items]
Revolving credit, maximum borrowing capacity		3,500,000,000
Revolving credit, current borrowing capacity		2,000,000,000
Borrowing capacity amount		$ 2,000,000,000
Revenue, discount percentage		9%
Credit spread adjustment		0.10%
Credit facility | New Credit Facility | Federal Funds Effective Rate
Debt Instrument [Line Items]
Variable rate percentage		0.50%
Credit facility | New Credit Facility | SOFR One Month Period
Debt Instrument [Line Items]
Variable rate percentage		1%
Credit facility | New Credit Facility | Minimum
Debt Instrument [Line Items]
Percentage of assets given as guarantee		85%
Current ratio		1
Asset coverage ratio		1.50
Variable rate percentage		1.75%
Unused capacity, commitment fee percentage		0.375%
Credit facility | New Credit Facility | Minimum | SOFR One Month Period Additional Applicable Margin
Debt Instrument [Line Items]
Variable rate percentage		0.75%
Credit facility | New Credit Facility | Maximum
Debt Instrument [Line Items]
Leverage ratio		3.50
Variable rate percentage		2.75%
Unused capacity, commitment fee percentage		0.50%
Credit facility | New Credit Facility | Maximum | SOFR One Month Period Additional Applicable Margin
Debt Instrument [Line Items]
Variable rate percentage		1.75%
Credit facility | New Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Revolving credit, maximum borrowing capacity		$ 200,000,000
Credit facility | New Credit Facility | Swingline Loans
Debt Instrument [Line Items]
Revolving credit, maximum borrowing capacity		50,000,000
Credit facility | Exit credit facility
Debt Instrument [Line Items]
Revolving credit, maximum borrowing capacity	$ 2,500,000,000
Unused capacity, commitment fee percentage	0.50%
LIBOR Floor	1%
Credit facility | Exit credit facility | Minimum | Alternative Base Rate
Debt Instrument [Line Items]
Variable rate percentage	2.25%
Credit facility | Exit credit facility | Minimum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Variable rate percentage	3.25%
Credit facility | Exit credit facility | Maximum | Alternative Base Rate
Debt Instrument [Line Items]
Variable rate percentage	3.25%
Credit facility | Exit credit facility | Maximum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Variable rate percentage	4.25%
Credit facility | Exit credit facility | Letter of Credit
Debt Instrument [Line Items]
Revolving credit, maximum borrowing capacity	$ 200,000,000
Credit facility | Exit Credit Facility - Tranche A Loans
Debt Instrument [Line Items]
Revolving credit, maximum borrowing capacity	$ 1,750,000,000
Term	3 years
Credit facility | Exit Credit Facility - Tranche B Loans
Debt Instrument [Line Items]
Revolving credit, maximum borrowing capacity	$ 221,000,000
Term	4 years
Secured debt, other
Debt Instrument [Line Items]
Debt, principal		0
Senior notes
Debt Instrument [Line Items]
Unamortized premium	$ 52,000,000
Senior notes | 6.75% senior notes due 2029
Debt Instrument [Line Items]
Debt, principal		$ 950,000,000
Unamortized premium				$ 71,000,000
Interest rate		6.75%		6.75%
Senior notes | 5.5% Senior Notes due 2026
Debt Instrument [Line Items]
Debt, principal		$ 500,000,000
Senior notes | 5.875% Senior Notes due 2029
Debt Instrument [Line Items]
Debt, principal		$ 500,000,000

Contingencies and Commitments_2

Contingencies and Commitments (Details) - Gathering, Processing and Transportation Agreement $ in Millions	Dec. 31, 2023 USD ($)
Other Commitments [Line Items]
2024	$ 284
2025	255
2026	235
2027	208
2028	194
2029-2036	956
Total	$ 2,132

Other Liabilities (Details)

Other Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
Other Liabilities Disclosure [Abstract]
Revenues and royalties due to others	$ 360	$ 734
Accrued drilling and production costs	211	253
Accrued hedging costs	2	109
Accrued compensation and benefits	64	72
Taxes payable	84	84
Operating leases	84	86
Joint interest prepayments received	8	34
Current liabilities held for sale	0	144
Other	34	111
Net impact to other current liabilities	$ 847	$ 1,627	$ 769

Leases - Narrative (Details)

Leases - Narrative (Details)	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other long-term assets	Other long-term assets
Minimum
Lessee, Lease, Description [Line Items]
Lease, remaining lease term	1 month
Maximum
Lessee, Lease, Description [Line Items]
Lease, remaining lease term	3 years

Leases - ROU Assets and Liabili

Leases - ROU Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Assets and Liabilities, Lessee [Abstract]
ROU assets	$ 99	$ 119
Current lease liabilities	84	86
Long-term lease liabilities	15	33
Present value of lease liabilities	$ 99	$ 119
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Operating Lease, Liability, Statement of Financial Position [Extensible List]	Other Liabilities	Other Liabilities

Leases - Additional information

Leases - Additional information (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Finance lease cost	$ 1	$ 0	$ 0	$ 0
Operating lease cost	3	33	107	51
Short-term lease cost	0	13	40	74
Total lease cost	4	46	147	125
Other information:
Operating cash outflows from operating leases	0	7	10	15
Investing cash outflows from operating leases	3	39	137	110
Financing cash outflows from finance lease	$ 1	$ 0	$ 0	$ 0
Weighted average remaining lease term - operating leases			1 year 2 months 26 days	1 year 6 months 14 days
Weighted average discount rate - operating leases			7.02%	6.64%

Leases - Maturity Analysis of F

Leases - Maturity Analysis of Finance and Operating Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating Leases, After Adoption of 842:
2024	$ 85
2025	17
2026	1
Total lease payments	103
Less imputed interest	(4)
Present value of lease liabilities	99	$ 119
Less current maturities	(84)	(86)
Present value of lease liabilities, less current maturities	$ 15	$ 33

Revenue - Disaggregated Revenue

Revenue - Disaggregated Revenue (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Total
Disaggregation of Revenue [Line Items]
Revenues	$ 398	$ 4,401	$ 3,547	$ 9,892
Total | Marcellus
Disaggregation of Revenue [Line Items]
Revenues	119	1,370	1,483	4,041
Total | Haynesville
Disaggregation of Revenue [Line Items]
Revenues	53	998	1,300	3,481
Total | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues	193	1,712	764	2,271
Total | Powder River Basin
Disaggregation of Revenue [Line Items]
Revenues	33	321		99
Natural Gas
Disaggregation of Revenue [Line Items]
Revenues	196	2,622	2,853	7,803
Natural Gas | Marcellus
Disaggregation of Revenue [Line Items]
Revenues	119	1,370	1,483	4,041
Natural Gas | Haynesville
Disaggregation of Revenue [Line Items]
Revenues	53	998	1,300	3,481
Natural Gas | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues	17	179	70	261
Natural Gas | Powder River Basin
Disaggregation of Revenue [Line Items]
Revenues	7	75		20
Oil
Disaggregation of Revenue [Line Items]
Revenues	179	1,556	596	1,864
Oil | Marcellus
Disaggregation of Revenue [Line Items]
Revenues	0	0	0	0
Oil | Haynesville
Disaggregation of Revenue [Line Items]
Revenues	0	0	0	0
Oil | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues	159	1,354	596	1,798
Oil | Powder River Basin
Disaggregation of Revenue [Line Items]
Revenues	20	202		66
NGL
Disaggregation of Revenue [Line Items]
Revenues	23	223	98	225
NGL | Marcellus
Disaggregation of Revenue [Line Items]
Revenues	0	0	0	0
NGL | Haynesville
Disaggregation of Revenue [Line Items]
Revenues	0	0	0	0
NGL | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues	17	179	98	212
NGL | Powder River Basin
Disaggregation of Revenue [Line Items]
Revenues	6	44		13
Marketing
Disaggregation of Revenue [Line Items]
Revenues	239	2,263	2,500	4,231
Natural Gas
Disaggregation of Revenue [Line Items]
Revenues	78	908	989	2,455
Oil
Disaggregation of Revenue [Line Items]
Revenues	141	1,158	1,332	1,547
NGL
Disaggregation of Revenue [Line Items]
Revenues	$ 20	$ 197	$ 179	$ 229

Revenue - Additional Informatio

Revenue - Additional Information (Details) - Revenue - Customer	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Shell Energy North America
Concentration Risk [Line Items]
Concentration risk, percentage			10%	13%
Valero energy corporation
Concentration Risk [Line Items]
Concentration risk, percentage	19%	14%	17%	10%
Energy Transfer Crude Marketing
Concentration Risk [Line Items]
Concentration risk, percentage		11%

Revenue - Accounts Receivable (

Revenue - Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Allowance for doubtful accounts	$ (1)	$ (3)
Total accounts receivable, net	593	1,438
Natural gas, oil and NGL sales
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	406	1,171
Joint interest
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	180	246
Other
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	$ 8	$ 24

Income Taxes - Income Tax Provi

Income Taxes - Income Tax Provision (Benefit) (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Current
Federal		$ 0	$ 0	$ 264	$ 37
State		0	0	6	10
Current Income Taxes		0	0	270	47
Deferred
Federal		(54)	(45)	381	(1,112)
State		(3)	(4)	47	(220)
Deferred Income Taxes		(57)	(49)	428	(1,332)
Total	$ (57)	$ (57)	$ (49)	$ 698	$ (1,285)

Income Taxes - Effective Income

Income Taxes - Effective Income Tax Expense (Benefit) Table (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax expense (benefit) at the federal statutory rate of 21%		$ 1,119	$ 188	$ 655	$ 767
State income taxes (net of federal income tax benefit)		238	(86)	56	75
Change in valuation allowance due to Acquisitions		0	(49)	0	19
Change in valuation allowance excluding impact of Acquisitions		(1,191)	(179)	(33)	(2,147)
Reorganization items		(173)	60	0	0
Transaction costs		0	11	0	2
Removal of stranded tax effects in accumulated other comprehensive income		(57)	0	0	0
Other		7	6	20	(1)
Total	$ (57)	$ (57)	$ (49)	$ 698	$ (1,285)

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities Table (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred tax liabilities:
Property, plant and equipment	$ (295)	$ (253)
Derivative instruments	(166)	0
Deferred tax liabilities, Right Of Use Lease Asset	(25)	(30)
Other	(4)	(5)
Deferred tax liabilities	(490)	(288)
Deferred tax assets:
Net operating loss carryforwards	848	870
Carrying value of debt	25	29
Excess business interest expense carryforward	646	665
Capital loss carryforwards	78	101
Asset retirement obligations	65	91
Investments	1	11
Future lease payments	25	30
Accrued liabilities	15	21
Derivative instruments	0	137
Other	32	29
Deferred tax assets	1,735	1,984
Valuation allowance	(312)	(345)
Deferred tax assets after valuation allowance	1,423	1,639
Net deferred tax asset	$ 933	$ 1,351

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Nov. 01, 2021	Dec. 31, 2020
Income Taxes Summary [Line Items]
Deferred tax assets				$ 1,735	$ 1,984
Deferred tax assets, valuation allowance				312	345
Deferred tax assets, valuation allowance, increase (decrease)				33
Change in deferred tax assets valuation allowance					1,351
Deferred tax assets, operating loss carryforward, limitations				54
Income tax cancellation of debt income	$ 5,000
Net operating loss carryforwards removed					307
Income tax expense (benefit)	(57)	$ (57)	$ (49)	698	(1,285)
Unrecognized tax benefits	$ 74	$ 74	74	68	69		$ 74
Income taxes receivable				33	168
Tax credit carryforwards				10	4
Uncertain tax positions that would impact effective tax rate				34
State and local
Income Taxes Summary [Line Items]
Operating loss carryforwards				3,712
Income taxes receivable				$ 24	29
Vine Acquisition
Income Taxes Summary [Line Items]
Deferred tax liabilities			$ 49		30	$ 30
Income tax expense (benefit)					$ 19
Operating loss carryforwards, 382 limitation						2
Operating loss carryforwards, 382 limitation, expected increase per year						12
Operating loss carryforwards, 382 limitation, expected increase per year, available utilization						$ 14

Income Taxes - Federal NOLs and

Income Taxes - Federal NOLs and Excess Business Interest (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Income Taxes Summary [Line Items]
Total federal net operating losses	$ 848	$ 870
Attributes subject to Section 382 base annual limitation, 54 million | Excess business interest expense (indefinitely lived)
Income Taxes Summary [Line Items]
Excess business interest expense (indefinitely lived)	1,381
Attributes subject to Section 382 base annual limitation, 54 million | Federal
Income Taxes Summary [Line Items]
Indefinitely lived	2,268
Total federal net operating losses	3,028
Attributes subject to Section 382 base annual limitation, 54 million | 2037 | Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	760
Attributes subject to Section 382 base annual limitation, 2 million | Excess business interest expense (indefinitely lived)
Income Taxes Summary [Line Items]
Excess business interest expense (indefinitely lived)	75
Attributes subject to Section 382 base annual limitation, 2 million | Federal
Income Taxes Summary [Line Items]
Indefinitely lived	102
Total federal net operating losses	126
Attributes subject to Section 382 base annual limitation, 2 million | 2037 | Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	24
Attributes not subject to Section 382 limitation | Excess business interest expense (indefinitely lived)
Income Taxes Summary [Line Items]
Excess business interest expense (indefinitely lived)	1,277
Attributes not subject to Section 382 limitation | Federal
Income Taxes Summary [Line Items]
Indefinitely lived	0
Total federal net operating losses	0
Attributes not subject to Section 382 limitation | 2037 | Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	$ 0

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits at beginning of period	$ 74	$ 74	$ 69	$ 74
Additions based on tax positions related to the current year	0	0	3	2
Additions to tax positions of prior years	0	0	3	2
Settlements	0	0	(5)	0
Expiration of the applicable statute of limitations	0	0	0	0
Reductions to tax positions of prior years	0	0	(2)	(9)
Unrecognized tax benefits at end of period	$ 74	$ 74	$ 68	$ 69

Equity - Additional Information

Equity - Additional Information (Details) $ / shares in Units, $ in Millions					1 Months Ended	11 Months Ended	12 Months Ended
	Oct. 13, 2022 shares	Mar. 09, 2022 shares	Nov. 01, 2021 shares	Feb. 09, 2021 $ / shares shares	Feb. 09, 2021 USD ($) $ / shares shares	Dec. 31, 2021 USD ($) shares	Dec. 31, 2023 USD ($) $ / shares shares	Dec. 31, 2022 USD ($) $ / shares shares	Feb. 20, 2024 $ / shares	Jun. 30, 2022 USD ($)	Dec. 02, 2021 USD ($)
Class of Stock [Line Items]
Common stock, par value (in usd per share) | $ / shares							$ 0.01	$ 0.01
Common stock, shares issued (in shares)							130,789,936	134,715,094
Authorized amount | $							$ 2,000				$ 1,000
Additional authorized amount | $										$ 1,000
Number of shares issuable upon exercise each warrant							1.22
Deemed dividend on warrants | $					$ 0	$ 0	$ 0	$ 67
Class A Warrants
Class of Stock [Line Items]
Warrant, exercise price (in dollars per share) | $ / shares				$ 27.63	$ 27.63		$ 23.25
Number of warrants exchanged for common stock (in shares)	4,752,207
Warrants exchange ratio	0.8636
Class B Warrants
Class of Stock [Line Items]
Warrant, exercise price (in dollars per share) | $ / shares				32.13	32.13		27.04
Number of warrants exchanged for common stock (in shares)	7,879,030
Warrants exchange ratio	0.8224
Class C Warrants
Class of Stock [Line Items]
Warrant, exercise price (in dollars per share) | $ / shares				$ 36.18	36.18		$ 30.45
Number of warrants exchanged for common stock (in shares)	7,252,004
Warrants exchange ratio	0.7890
Subsequent Event
Class of Stock [Line Items]
Dividends payable (in dollars per share) | $ / shares									$ 0.575
Vine Acquisition
Class of Stock [Line Items]
Common stock issued for acquisition (in shares)			18,700,000
New Common Stock
Class of Stock [Line Items]
Issuance of Successor common stock (in shares)				97,907,081
Common stock, par value (in usd per share) | $ / shares				$ 0.01	$ 0.01
Common stock, reserved for future issuance (in shares)				2,092,918	2,092,918
Common stock, shares issued (in shares)						864,090	12,089	439,370
Number of shares initially exercisable for class of warrant or right (in shares)				1	1
Conversion of stock, shares issued (in shares)	16,305,984
New Common Stock | Class C Warrants
Class of Stock [Line Items]
Common stock, reserved for future issuance (in shares)				3,948,893	3,948,893
New Common Stock | Vine Acquisition
Class of Stock [Line Items]
Common stock issued for acquisition (in shares)			18,709,399
New Common Stock | Marcellus
Class of Stock [Line Items]
Common stock issued for acquisition (in shares)		9,442,185

Equity - Schedule of Dividends

Equity - Schedule of Dividends (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021
Equity [Abstract]
Dividends payable, base (in dollars per share)	$ 0.575	$ 0.575	$ 0.55	$ 0.55	$ 0.55	$ 0.55	$ 0.50	$ 0.4375	$ 0.4375	$ 0.34375	$ 0.34375
Dividends payable, variable (in dollars per share)	0	0	0.63	0.74	2.61	1.77	1.84	1.33	0	0	0
Rate Per Share (in dollars per share)	$ 0.575	$ 0.575	$ 1.18	$ 1.29	$ 3.16	$ 2.32	$ 2.34	$ 1.7675	$ 0.4375	$ 0.34375	$ 0.34375
Dividends	$ 75	$ 77	$ 160	$ 175	$ 424	$ 280	$ 298	$ 210	$ 52	$ 33	$ 34

Equity - Schedule of Share Repu

Equity - Schedule of Share Repurchase Program (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended								12 Months Ended		24 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2023	Dec. 02, 2021
Equity [Abstract]
Shares Purchased (in shares)	627	1,509	1,444	793	4,105	750	5,812	1,000			16,040
Dollar Value of Shares Purchased	$ 52	$ 130	$ 115	$ 60	$ 406	$ 69	$ 515	$ 83	$ 358	$ 1,073	$ 1,430
Average Price Per Share (in dollars per share)	$ 82.03	$ 86.16	$ 78.77	$ 74.95	$ 98.90	$ 92.14	$ 88.67	$ 82.98
Authorized amount	$ 2,000								$ 2,000		$ 2,000	$ 1,000

Equity - Schedule of Warrants (

Equity - Schedule of Warrants (Details) - shares	11 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Warrant
Warrants and Rights Outstanding [Roll Forward]
Conversion of stock, shares issued (in shares)		221,952	18,408,228
Class A Warrants
Warrants and Rights Outstanding [Roll Forward]
Outstanding, beginning balance (in shares)	11,111,111	4,495,004	10,856,852
Converted into New Common Stock (in shares)	(254,259)	(247,389)	(1,609,641)
Converted in warrant exchange offer (in shares)			(4,752,207)
Issued for General Unsecured Claim (in shares)	0	0	0
Outstanding, ending balance (in shares)	10,856,852	4,247,615	4,495,004
Class B Warrants
Warrants and Rights Outstanding [Roll Forward]
Outstanding, beginning balance (in shares)	12,345,679	4,404,564	12,313,273
Converted into New Common Stock (in shares)	(32,406)	(1,500)	(29,679)
Converted in warrant exchange offer (in shares)			(7,879,030)
Issued for General Unsecured Claim (in shares)	0	0	0
Outstanding, ending balance (in shares)	12,313,273	4,403,064	4,404,564
Class C Warrants
Warrants and Rights Outstanding [Roll Forward]
Outstanding, beginning balance (in shares)	9,768,527	4,006,229	11,388,371
Converted into New Common Stock (in shares)	(10,603)	(5,581)	(959,247)
Converted in warrant exchange offer (in shares)			(7,252,004)
Issued for General Unsecured Claim (in shares)	1,630,447	22,835	829,109
Outstanding, ending balance (in shares)	11,388,371	4,023,483	4,006,229
Warrants reserved for future issuance (in shares)		1,466,502

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) - USD ($) $ in Millions	11 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value, vested	$ 25	$ 25	$ 26
Unrecognized compensation expense		$ 45
Share-based compensation expense, weighted average period for recognition		2 years 2 months 8 days
Restricted Stock Units (RSUs) | Employee | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years	3 years	3 years
Restricted Stock Units (RSUs) | Employee | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	5 years	5 years	5 years
Restricted Stock Units (RSUs) | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	1 year	1 year	1 year
Performance shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value, vested	$ 0.6
Unrecognized compensation expense		$ 15
Share-based compensation expense, weighted average period for recognition		1 year 8 months 4 days
Performance shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shareholder return and relative total shareholder return, percent of payout of target units	0%	0%	0%
Share price hurdle, percent of payout of target units	0%
Performance shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shareholder return and relative total shareholder return, percent of payout of target units	200%	200%	200%
Share price hurdle, percent of payout of target units	100%
Performance shares | Management
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years	3 years	3 years
2021 Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, reserved for future issuance (in shares)				6,800,000

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock (Details) - Restricted Stock Units (RSUs) - $ / shares shares in Thousands	11 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Unvested Restricted Stock Units
Unvested restricted stock, beginning balance (in shares)	0	957	775
Granted (in shares)	1,202	440	666
Vested (in shares)	(377)	(329)	(300)
Forfeited/canceled (in shares)	(50)	(128)	(184)
Unvested restricted stock, ending balance (in shares)	775	940	957
Weighted Average Grant Date Fair Value Per Share
Unvested restricted stock, beginning balance (in usd per share)	$ 0	$ 68.91	$ 46.77
Granted (in usd per share)	52.60	72.25	81.87
Vested (in usd per share)	65.66	61.66	48.11
Forfeited/canceled (in usd per share)	44.37	68.42	56.54
Unvested restricted stock, ending balance (in usd per share)	$ 46.77	$ 73.08	$ 68.91
Vine Acquisition
Unvested Restricted Stock Units
Granted (in shares)	430
Weighted Average Grant Date Fair Value Per Share
Number of accelerated vesting units (in shares)	375

Share-Based Compensation - Assu

Share-Based Compensation - Assumptions (Details) - Performance shares	11 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
TSR, rTSR
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	0.23%	3.85%	2%
Volatility	71.40%	64.40%	70.20%
Share Price Hurdle
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	0.30%
Volatility	68.40%

Share-Based Compensation - Perf

Share-Based Compensation - Performance Share (Details) - Performance shares - $ / shares shares in Thousands	11 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Unvested Performance Share Units
Unvested restricted stock, beginning balance (in shares)	0	276	183
Granted (in shares)	201	131	133
Vested (in shares)	(9)	0	0
Forfeited/canceled (in shares)	(9)	(13)	(40)
Unvested restricted stock, ending balance (in shares)	183	394	276
Weighted Average Grant Date Fair Value Per Share
Unvested restricted stock, beginning balance (in usd per share)	$ 0	$ 88.28	$ 66.12
Granted (in usd per share)	64.41	78.78	109.65
Vested (in usd per share)	38.95	0	0
Forfeited/canceled (in usd per share)	55.42	68.77	57.48
Unvested restricted stock, ending balance (in usd per share)	$ 66.12	$ 85.78	$ 88.28

Share-Based Compensation - Comp

Share-Based Compensation - Compensation Expense (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	$ 3	$ 11	$ 39	$ 26
Related income tax benefit	0	0	7	6
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	3	7	29	19
Natural gas and oil properties
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	0	2	6	4
Production expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	$ 0	$ 2	$ 4	$ 3

Employee Benefit Plans (Details

Employee Benefit Plans (Details) - USD ($)	1 Months Ended		11 Months Ended	12 Months Ended		32 Months Ended
	Apr. 30, 2021	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2023
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discretionary contribution, percent of adjusted free cash flow				1%
Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer annual maximum contribution amount				$ 15,000
Chesapeake energy corporation savings and incentive stock bonus plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contribution amount		$ 2,000,000	$ 8,000,000	$ 13,000,000	$ 22,000,000
Chesapeake energy corporation savings and incentive stock bonus plan | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution	15%			6%		6%

Derivative and Hedging Activi_3

Derivative and Hedging Activities - Narrative (Details) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2023 USD ($) $ / bbl	Dec. 31, 2023 USD ($) derivative counterparty Bcf	Dec. 31, 2022 USD ($) derivative Bcf	Dec. 31, 2022 USD ($) derivative MMBbls	Aug. 31, 2023 USD ($)
Derivative [Line Items]
Derivative liability, held for sale			$ 65	$ 65
Unrealized loss		$ 9
WTI NYMEX Price Average Above $80 per Barrel
Derivative [Line Items]
Average sales price (in usd per unit) | $ / bbl	80
Minimum | WTI NYMEX Price Average $75 to $80 per Barrel
Derivative [Line Items]
Average sales price (in usd per unit) | $ / bbl	75
Maximum | WTI NYMEX Price Average $75 to $80 per Barrel
Derivative [Line Items]
Average sales price (in usd per unit) | $ / bbl	80
Final Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations
Derivative [Line Items]
Consideration received					$ 700
Final Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | WTI NYMEX Price Average $75 to $80 per Barrel
Derivative [Line Items]
Consideration received	$ 25
Final Portion of Eagle Ford Assets | Disposal group, disposed of by sale, not discontinued operations | WTI NYMEX Price Average Above $80 per Barrel
Derivative [Line Items]
Consideration received	$ 50
Energy related derivative | Natural Gas
Derivative [Line Items]
Notional Volume | Bcf		1,479	1,777
Energy related derivative | Eagle Ford
Derivative [Line Items]
Notional Volume			9.6	4.8
Credit risk
Derivative [Line Items]
Number of counterparties in hedge facility | counterparty		15
Designated as hedging instrument
Derivative [Line Items]
Number of derivative instruments | derivative		0	0	0

Derivative and Hedging Activi_4

Derivative and Hedging Activities - Derivative Instruments (Details) - Energy related derivative $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Bcf MMBbls	Dec. 31, 2022 USD ($) MMBbls Bcf
Derivative [Line Items]
Fair Value	$ 699	$ (525)
Eagle Ford divestiture
Derivative [Line Items]
Fair Value	$ 12	$ 0
Natural Gas
Derivative [Line Items]
Notional Volume | Bcf	1,479	1,777
Fair Value	$ 687	$ (501)
Natural Gas | Fixed-price swaps
Derivative [Line Items]
Notional Volume | Bcf	343	382
Fair Value	$ 188	$ (494)
Natural Gas | Collars
Derivative [Line Items]
Notional Volume | Bcf	558	721
Fair Value	$ 497	$ 49
Natural Gas | Three-way collars
Derivative [Line Items]
Notional Volume | Bcf	0	4
Fair Value	$ 0	$ (2)
Natural Gas | Call options
Derivative [Line Items]
Notional Volume | Bcf	0	18
Fair Value	$ 0	$ (22)
Natural Gas | Basis protection swaps
Derivative [Line Items]
Notional Volume | Bcf	578	652
Fair Value	$ 2	$ (32)
Oil
Derivative [Line Items]
Notional Volume | MMBbls	0	9
Fair Value	$ 0	$ (24)
Oil | Fixed-price swaps
Derivative [Line Items]
Notional Volume | MMBbls	0	1
Fair Value	$ 0	$ (32)
Oil | Collars
Derivative [Line Items]
Notional Volume | MMBbls	0	2
Fair Value	$ 0	$ 7
Oil | Basis protection swaps
Derivative [Line Items]
Notional Volume | MMBbls	0	6
Fair Value	$ 0	$ 1

Derivative and Hedging Activi_5

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
Derivatives, Fair Value [Line Items]
Short-term derivative asset	$ 637	$ 34	$ 0
Long-term derivative asset	74	47
Short-term derivative liability	(3)	(432)	(398)
Long-term derivative liability	(9)	(174)	$ (90)
Not designated as hedging instrument
Derivatives, Fair Value [Line Items]
Short-term derivative asset	12
Not designated as hedging instrument | Short-term derivative asset
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	12
Derivative asset, fair value, gross liability, netted	0
Not designated as hedging instrument | Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative asset (liability), fair value, gross asset (liability)	699	(525)
Derivative asset (liability) fair value, net asset (liability), netted	0	0
Short-term derivative asset	625	34
Long-term derivative asset	74	47
Short-term derivative liability	(3)	(432)
Long-term derivative liability	(9)	(174)
Total derivatives	(699)	525
Not designated as hedging instrument | Commodity contracts | Short-term derivative asset
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	661	200
Derivative asset, fair value, gross liability, netted	(36)	(166)
Not designated as hedging instrument | Commodity contracts | Long-term derivative asset
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	101	87
Derivative asset, fair value, gross liability, netted	(27)	(40)
Not designated as hedging instrument | Commodity contracts | Short-term derivative liability
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(39)	(598)
Derivative liability, fair value, gross asset, netted	36	166
Not designated as hedging instrument | Commodity contracts | Long-term derivative liability
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(36)	(214)
Derivative liability, fair value, gross asset, netted	$ 27	$ 40

Derivative and Hedging Activi_6

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
		Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
AOCI Attributable to Parent, Net of Tax [Roll Forward]
AOCI, after tax, beginning of period			$ 0
Losses reclassified to income, after tax	[1]	$ 3	0	$ 0	$ 0
AOCI, after tax, end of period		0
Cash flow hedging
AOCI Attributable to Parent, Net of Tax [Roll Forward]
AOCI, before tax, beginning of period		(12)	0
AOCI, after tax, beginning of period		45	$ 0
Losses reclassified to income, before tax		3
Losses reclassified to income, after tax		3
Fresh start adjustments, before tax		9
Fresh start adjustments, after tax		9
Elimination of tax effects, before tax		0
Elimination of tax effects, after tax		(57)
AOCI, before tax, end of period		0
AOCI, after tax, end of period		$ 0
[1] Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Capitalized Exploratory Well _3

Capitalized Exploratory Well Costs - Changes In Capitalized Well Costs (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Changes in Capitalized Well Costs
Balance, beginning of period	$ 0	$ 0	$ 10	$ 14
Additions pending the determination of proved reserves	0	24	0	1
Divestitures and other	0	0	(10)	0
Reclassifications to proved properties	0	(10)	0	0
Charges to exploration expense	0	0	0	(5)
Balance, end of period	$ 0	$ 14	$ 0	$ 10

Other Property and Equipment (D

Other Property and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 497	$ 500	$ 499
Less: accumulated depreciation	(90)	(58)
Total other property and equipment, net	407	442
Buildings and improvements
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 316	325
Buildings and improvements | Minimum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	10 years
Buildings and improvements | Maximum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	39 years
Computer equipment
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 94	92
Estimated Useful Life	5 years
Land
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 28	32
Other
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 59	$ 51
Other | Minimum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	5 years
Other | Maximum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	20 years

Investments (Details)

Investments (Details) $ in Millions	Dec. 31, 2023 USD ($) billionOfCubicFeetPerDay MT	Dec. 31, 2022 USD ($)
Momentum Sustainable Ventures LLC | Plan
Schedule of Equity Method Investments [Line Items]
Initial capacity | billionOfCubicFeetPerDay	1.7
Expandable capacity | billionOfCubicFeetPerDay	2.2
Sequester of CO2 | MT	2
Momentum Sustainable Ventures LLC
Schedule of Equity Method Investments [Line Items]
Investment, ownership percentage	35%
Contractual obligation | $	$ 112
Equity method investments | $	$ 238	$ 18

Exploration Expense (Details)

Exploration Expense (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Exploration expense	$ 2	$ 7	$ 27	$ 23
Noncash project abandonment costs			12	8
Geological and geophysical expense and other			$ 11	6
Dry hole expense				$ 6
Exploration expenses	$ 0	$ 0

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Feb. 09, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 335	$ 360
Additions	9	53
Revisions	(9)	16
Settlements and disposals	(75)	(54)
Held for sale	0	(57)
Accretion expense	16	17
Asset retirement obligations, end of period	276	335
Asset retirement obligation	276	335
Less current portion	11	12
Asset retirement obligations, long-term	265	323	$ 236
Business Acquisition [Line Items]
Additions	9	53
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposals	75	54
Held for sale	0	57
Powder River Basin
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Settlements and disposals		(47)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposals		47
Eagle Ford
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Settlements and disposals	(64)
Held for sale		(57)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposals	$ 64
Held for sale		57
Marcellus
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Additions		27
Business Acquisition [Line Items]
Additions		$ 27

Subsequent Events (Details)

Subsequent Events (Details)	Jan. 10, 2024
Subsequent Event | Southwestern
Subsequent Event [Line Items]
Share conversion ratio	0.0867

Supplemental Disclosures Abou_3

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Proved	$ 11,468	$ 11,096
Unproved	1,806	2,022
Total	13,274	13,118
Less accumulated depreciation, depletion and amortization	(3,584)	(2,373)
Net capitalized costs	$ 9,690	$ 10,745

Supplemental Disclosures Abou_4

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Exploration Expense and Cost Incurred (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Acquisition of properties
Proved properties	$ 0	$ 2,183	$ 10	$ 2,321
Unproved properties	0	1,121	52	795
Exploratory costs	0	31	15	15
Development costs	58	717	1,721	1,918
Costs incurred	$ 58	4,052	$ 1,798	5,049
Marcellus
Acquisition of properties
Proved properties				2,310
Unproved properties				$ 790
Vine Acquisition
Acquisition of properties
Proved properties		2,180
Unproved properties		$ 1,100

Supplemental Disclosures Abou_5

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Revenues and Expenses (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Natural gas, oil and NGL sales	$ 398	$ 4,401	$ 3,547	$ 9,892
Production expenses	(32)	(297)	(356)	(475)
Gathering, processing and transportation expenses	(102)	(780)	(853)	(1,059)
Severance and ad valorem taxes	(18)	(158)	(167)	(242)
Exploration	(2)	(7)	(27)	(23)
Depletion and depreciation	(64)	(882)	(1,478)	(1,703)
Accretion of asset retirement obligations	(1)	(11)	(16)	(17)
Imputed income tax provision	(42)	(535)	(152)	(1,440)
Results of operations from natural gas, oil and NGL producing activities	$ 137	$ 1,731	$ 498	$ 4,933

Supplemental Disclosures Abou_6

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Changes in Estimated Reserves (Details)	12 Months Ended
	Dec. 31, 2023 Bcfe Bcf MMBbls	Dec. 31, 2022 Bcfe Bcf MMBbls	Dec. 31, 2021 Bcfe Bcf MMBbls
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning of period (Energy) | Bcfe	13,002	9,573	4,809
Extensions, discoveries and other additions | Bcfe	415	82	2,091
Revisions of previous estimates | Bcfe	(325)	2,155	1,848
Production | Bcfe	(1,335)	(1,461)	(1,010)
Sale of reserves-in-place | Bcfe	(2,127)	(273)	0
Purchase of reserves-in-place | Bcfe	58	2,926	1,835
Proved reserves, ending of period (Energy) | Bcfe	9,688	13,002	9,573
Proved developed reserves, Beginning of period (Energy) | Bcfe	8,681	5,610	4,452
Proved developed reserves, Ending of period (Energy) | Bcfe	6,363	8,681	5,610
Proved undeveloped reserves, Beginning of period (Energy) | Bcfe	4,321	3,963	357
Proved undeveloped reserves, Ending of period (Energy) | Bcfe	3,325	4,321	3,963
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of period | Bcf	11,369	7,824	3,530
Extensions, discoveries and other additions | Bcf	415	60	1,744
Revisions of previous estimates | Bcf	(325)	1,989	1,522
Production | Bcf	(1,266)	(1,308)	(807)
Sale of reserves-in-place | Bcf	(563)	(122)	0
Purchase of reserves-in-place | Bcf	58	2,926	1,835
Proved reserves, ending of period | Bcf	9,688	11,369	7,824
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved developed reserves, Beginning of period | Bcf	7,385	4,246	3,196
Proved developed reserves, Ending of period | Bcf	6,363	7,385	4,246
Proved undeveloped reserves, Beginning of period | Bcf	3,984	3,578	334
Proved undeveloped reserves, Ending of period | Bcf	3,325	3,984	3,578
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of period	198.4	209.7	161.3
Extensions, discoveries and other additions	0	2.1	41
Revisions of previous estimates	0	22.5	33.3
Production	(7.7)	(19.4)	(25.9)
Sale of reserves-in-place	(190.7)	(16.5)	0
Purchase of reserves-in-place	0	0	0
Proved reserves, ending of period	0	198.4	209.7
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved developed reserves, Beginning of period	157.2	165.7	158.1
Proved developed reserves, Ending of period	0	157.2	165.7
Proved undeveloped reserves, Beginning of period	41.2	44	3.2
Proved undeveloped reserves, Ending of period	0	41.2	44
NGL
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning of period	73.9	82	52
Extensions, discoveries and other additions	0	1.5	16.9
Revisions of previous estimates	0	5	21.1
Production	(3.8)	(6)	(8)
Sale of reserves-in-place	(70.1)	(8.6)	0
Purchase of reserves-in-place	0	0	0
Proved reserves, ending of period	0	73.9	82
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved developed reserves, Beginning of period	58.9	61.7	51.4
Proved developed reserves, Ending of period	0	58.9	61.7
Proved undeveloped reserves, Beginning of period	15	20.3	0.6
Proved undeveloped reserves, Ending of period	0	15	20.3

Supplemental Disclosures Abou_7

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 Bcfe $ / Mcf $ / bbl	Dec. 31, 2022 Bcfe $ / bbl	Dec. 31, 2021 Bcfe $ / bbl	Dec. 31, 2022 $ / Mcf	Dec. 31, 2022 $ / bbl	Dec. 31, 2021 $ / Mcf	Dec. 31, 2021 $ / bbl
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Sale of reserves-in-place	2,127	273	0
Extensions, discoveries and other additions	415	82	2,091
Revisions of previous estimates	(325)	2,155	1,848
Purchase of reserves-in-place	58	2,926	1,835
Revisions Due To Development Plan Optimization
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	(451)	866
Revisions Due To Performance
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	(237)	1,156
Revisions Due To Lateral Length Adjustments
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	469		1,284
Price Adjustment
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	(1,623)	133	564
Non-Price Related Revisions
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	1,298
New PUDs and Producing Wells Added In Previously Proved Areas
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	1,517
Natural Gas
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Price used in computing estimated future cash inflows | $ / Mcf	2.64			6.36		3.60
Oil
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Price used in computing estimated future cash inflows	78.22	93.67	66.56		93.67		66.56
NGL
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Price used in computing estimated future cash inflows	28.61	43.58	35.81		43.58		35.81

Supplemental Disclosures Abou_8

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Future Net Cash Flows Relating to Proved Reserves Based on Standardized Measure (Details) $ in Millions	Dec. 31, 2023 USD ($) $ / Mcf $ / bbl	Dec. 31, 2022 $ / bbl	Dec. 31, 2022 $ / Mcf	Dec. 31, 2022 USD ($)	Dec. 31, 2022 $ / bbl	Dec. 31, 2021 $ / bbl	Dec. 31, 2021 $ / Mcf	Dec. 31, 2021 USD ($)	Dec. 31, 2021 $ / bbl	Dec. 31, 2020 USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 14,659			$ 76,626				$ 33,700
Future production costs	(3,326)			(10,177)				(6,735)
Future development costs	(2,779)			(5,343)				(3,687)
Future income tax provisions	(174)			(10,440)				(2,254)
Future net cash flows	8,380			50,666				21,024
Less effect of a 10% discount factor	(3,903)			(24,361)				(8,737)
Standardized measure of discounted future net cash flows	4,477			26,305				12,287		$ 3,086
Future Development Costs
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future plugging and abandonment costs	$ 730			$ 979				$ 846
Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price used in computing estimated future cash inflows | $ / Mcf	2.64		6.36				3.60
Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price used in computing estimated future cash inflows	78.22	93.67			93.67	66.56			66.56
NGL
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price used in computing estimated future cash inflows	28.61	43.58			43.58	35.81			35.81

Supplemental Disclosures Abou_9

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Sources of Change in Standardized Measure of Discounted Future Net Cash Flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Standardized measure, beginning balance	$ 26,305	$ 12,287	$ 3,086
Sales of natural gas and oil produced, net of production costs and gathering processing and transportation	(2,171)	(8,116)	(3,414)
Net changes in prices and production costs	(23,535)	14,256	6,674
Extensions and discoveries, net of production and development costs	182	251	2,834
Changes in estimated future development costs	346	(1,512)	(459)
Previously estimated development costs incurred during the period	818	690	130
Revisions of previous quantity estimates	(205)	6,697	2,034
Purchase of reserves-in-place	77	7,047	2,807
Sales of reserves-in-place	(7,158)	(402)	0
Accretion of discount	3,270	1,371	309
Net change in income taxes	6,301	(4,972)	(1,423)
Changes in production rates and other	247	(1,292)	(291)
Standardized measure, ending balance	$ 4,477	$ 26,305	$ 12,287