Expand Energy (EXE) 10-K 27 Feb 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 19, 2020	Jun. 28, 2019
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-13726
Entity Registrant Name	CHESAPEAKE ENERGY CORPORATION
Amendment Flag	false
Entity Central Index Key	0000895126
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
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
Entity Shell Company	false
Entity Public Float			$ 2.2
Entity Common Stock, Shares Outstanding		1,954,583,780
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE Portions of the proxy statement for the 2020 Annual Meeting of Shareholders are incorporated by reference in Part III.
Common Stock, par value $0.01
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, par value $0.01
Trading Symbol	CHK
Security Exchange Name	NYSE
6.625% senior notes due 2020
Entity Information [Line Items]
Title of 12(b) Security	6.625% Senior Notes due 2020
Trading Symbol	CHK20A
Security Exchange Name	NYSE
6.875% senior notes due 2020
Entity Information [Line Items]
Title of 12(b) Security	6.875% Senior Notes due 2020
Trading Symbol	CHK20
Security Exchange Name	NYSE
6.125% Senior Notes due 2021
Entity Information [Line Items]
Title of 12(b) Security	6.125% Senior Notes due 2021
Trading Symbol	CHK21
Security Exchange Name	NYSE
5.375% Senior Notes due 2021
Entity Information [Line Items]
Title of 12(b) Security	5.375% Senior Notes due 2021
Trading Symbol	CHK21A
Security Exchange Name	NYSE
4.875% Senior Notes due 2022
Entity Information [Line Items]
Title of 12(b) Security	4.875% Senior Notes due 2022
Trading Symbol	CHK22
Security Exchange Name	NYSE
5.75% Senior Notes due 2023
Entity Information [Line Items]
Title of 12(b) Security	5.75% Senior Notes due 2023
Trading Symbol	CHK23
Security Exchange Name	NYSE
4.5% Cumulative Convertible Preferred Stock
Entity Information [Line Items]
Title of 12(b) Security	4.5% Cumulative Convertible Preferred Stock
Trading Symbol	CHK Pr D
Security Exchange Name	NYSE

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
CURRENT ASSETS:
Cash and cash equivalents ($2 and $1 attributable to our VIE)	$ 6	$ 4
Accounts receivable, net	990	1,247
Short-term derivative assets	134	209
Other current assets	121	138
Total Current Assets	1,251	1,598
Oil and natural gas properties, at cost based on successful efforts accounting:
Proved oil and natural gas properties ($755 and $755 attributable to our VIE)	30,765	25,407
Unproved properties	2,173	1,561
Other property and equipment	1,810	1,721
Total Property and Equipment, at Cost	34,748	28,689
Less: accumulated depreciation, depletion and amortization (($713) and ($707) attributable to our VIE)	(20,002)	(17,886)
Property and equipment held for sale, net	10	15
Total Property and Equipment, Net	14,756	10,818
LONG-TERM ASSETS:
Long-term derivative assets	0	76
Other long-term assets	186	243
TOTAL ASSETS	16,193	12,735
CURRENT LIABILITIES:
Accounts payable	498	763
Current maturities of long-term debt, net	385	381
Accrued interest	75	141
Short-term derivative liabilities	2	3
Other current liabilities ($1 and $2 attributable to our VIE)	1,432	1,599
Total Current Liabilities	2,392	2,887
LONG-TERM LIABILITIES:
Long-term debt, net	9,073	7,341
Long-term derivative liabilities	2	0
Asset retirement obligations, net of current portion	200	155
Other long-term liabilities	125	219
Total Long-Term Liabilities	9,400	7,715
CONTINGENCIES AND COMMITMENTS (Note 6)
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 5,563,458 and 5,603,458 shares outstanding	1,631	1,671
Common stock, $0.01 par value, 3,000,000,000 and 2,000,000,000 shares authorized: 1,954,558,617 and 913,715,512 shares issued	19	9
Additional paid-in capital	16,954	14,378
Accumulated deficit	(14,220)	(13,912)
Accumulated other comprehensive income (loss)	12	(23)
Less: treasury stock, at cost; 5,244,992 and 3,246,553 common shares	(32)	(31)
Total Chesapeake Stockholders’ Equity	4,364	2,092
Noncontrolling interests	37	41
Total Equity	4,401	2,133
TOTAL LIABILITIES AND EQUITY	$ 16,193	$ 12,735

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Preferred stock, par value (in usd per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (in shares)	20,000,000	20,000,000
Preferred stock, shares outstanding (in shares)	5,563,458	5,603,458
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	3,000,000,000	2,000,000,000
Common stock, shares issued (in shares)	1,954,558,617	913,715,512
Treasury stock, common shares (in shares)	5,244,992	3,246,553
Cash and cash equivalents ($2 and $1 attributable to our VIE)	$ 6	$ 4
Proved oil and natural gas properties ($755 and $755 attributable to our VIE)	30,765	25,407
Less: accumulated depreciation, depletion and amortization (($713) and ($707) attributable to our VIE)	(20,002)	(17,886)
Other current liabilities ($1 and $2 attributable to our VIE)	1,432	1,599
Variable Interest Entities, Primary Beneficiary
Cash and cash equivalents ($2 and $1 attributable to our VIE)	2	1
Proved oil and natural gas properties ($755 and $755 attributable to our VIE)	755	755
Less: accumulated depreciation, depletion and amortization (($713) and ($707) attributable to our VIE)	(713)	(707)
Other current liabilities ($1 and $2 attributable to our VIE)	$ 1	$ 2

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
REVENUES AND OTHER:
Revenues	$ 8,595	$ 10,030	$ 10,039
Gains (losses) on sales of assets	43	(264)	476
OPERATING EXPENSES:
Severance and ad valorem taxes	224	189	134
General and administrative	315	335	333
Restructuring and other termination costs	12	38	0
Provision for legal contingencies, net	19	26	(38)
Depreciation, depletion and amortization	2,264	1,737	1,697
Impairments	11	131	814
Other operating expense	92	0	416
Total Operating Expenses	8,626	9,648	10,177
INCOME (LOSS) FROM OPERATIONS	(31)	382	(138)
OTHER INCOME (EXPENSE):
Interest expense	(651)	(633)	(601)
Gains (losses) on investments	(71)	139	0
Gains on purchases or exchanges of debt	75	263	233
Other income	39	67	6
Total Other Expense	(608)	(164)	(362)
INCOME (LOSS) BEFORE INCOME TAXES	(639)	218	(500)
Current income taxes	(26)	0	(9)
Deferred income taxes	(305)	(10)	11
Total Income Tax Expense (Benefit)	(331)	(10)	2
NET INCOME (LOSS)	(308)	228	(502)
Net income attributable to noncontrolling interests	0	(2)	(3)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(308)	226	(505)
Preferred stock dividends	(91)	(92)	(85)
Loss on exchange of preferred stock	(17)	0	(41)
Earnings allocated to participating securities	0	(1)	0
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$ (416)	$ 133	$ (631)
EARNINGS (LOSS) PER COMMON SHARE:
Basic (in usd per share)	$ (0.25)	$ 0.15	$ (0.70)
Diluted (in usd per share)	$ (0.25)	$ 0.15	$ (0.70)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic (in shares)	1,665	909	906
Diluted (in shares)	1,665	909	906
Oil, Natural Gas and NGL
REVENUES AND OTHER:
Revenues	$ 4,522	$ 5,155	$ 4,985
Oil, natural gas and NGL production
OPERATING EXPENSES:
Cost of goods and services	520	474	517
Oil, natural gas and NGL gathering, processing and transportation
OPERATING EXPENSES:
Cost of goods and services	1,082	1,398	1,471
Marketing
REVENUES AND OTHER:
Revenues	3,967	5,076	4,511
OPERATING EXPENSES:
Cost of goods and services	4,003	5,158	4,598
Oil, Natural gas and NGL and Marketing
REVENUES AND OTHER:
Revenues	8,489	10,231	9,496
Other
REVENUES AND OTHER:
Revenues	63	63	67
Exploration
OPERATING EXPENSES:
Cost of goods and services	$ 84	$ 162	$ 235

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Statement of Comprehensive Income [Abstract]
NET INCOME (LOSS)	$ (308)
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains (losses) on derivative instruments, net of income tax benefit of $0, $0, and $0	0
Unrealized gains (losses) on derivative instruments, net of income tax benefit of $0, $0, and $0	0
Reclassification of losses on settled derivative instruments, net of income tax expense of $0, $0 and $0	35
Other Comprehensive Income	35
COMPREHENSIVE INCOME (LOSS)	(273)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$ (273)

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Unrealized gains (losses) on derivative instruments, net of income tax benefit of $__, $0, and $0	$ 0
Unrealized gains (losses) on derivative instruments, net of income tax benefit of $__, $0, and $0		$ 0	$ 0
Reclassification of losses on settled derivative instruments, net of income tax expense of $__, $0 and $0	$ 0
Reclassification of losses on settled derivative instruments, net of income tax expense of $__, $0 and $0		$ 0	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ (308)	$ 228	$ (502)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	2,264	1,737	1,697
Deferred income tax expense (benefit)	(305)	(10)	11
Derivative (gains) losses, net	(3)	26	(409)
Cash receipts (payments) on derivative settlements, net	202	(345)	(18)
Stock-based compensation	30	32	49
(Gains) losses on sales of assets	(43)	264	(476)
Impairments	11	131	814
Exploration	49	96	214
(Gains) losses on investments	63	(139)	0
Gains on purchases or exchanges of debt	(79)	(263)	(235)
Other	(4)	(118)	(132)
(Increase) decrease in accounts receivable and other assets	376	16	(163)
(Decrease) increase in accounts payable, accrued liabilities and other	(630)	75	(375)
Net Cash Provided By Operating Activities	1,623	1,730	475
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(2,180)	(1,848)	(2,113)
Business combination, net	(353)	0	0
Acquisitions of proved and unproved properties	(35)	(128)	(88)
Proceeds from divestitures of proved and unproved properties	130	2,231	1,249
Additions to other property and equipment	(48)	(21)	(21)
Proceeds from sales of other property and equipment	6	147	55
Proceeds from sales of investments	0	74	0
Net Cash Provided By (Used In) Investing Activities	(2,480)	455	(918)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	10,676	11,697	7,771
Payments on revolving credit facility borrowings	(10,180)	(12,059)	(6,990)
Proceeds from issuance of senior notes, net	108		1,585
Proceeds from issuance of term loan, net	1,455	0	0
Cash paid to purchase debt	(1,073)	(2,813)	(2,592)
Extinguishment of other financing	0	(122)	0
Cash paid for preferred stock dividends	(91)	(92)	(183)
Distributions to noncontrolling interest owners	(4)	(6)	(8)
Other	(32)	(27)	(17)
Net Cash Provided By (Used In) Financing Activities	859	(2,186)	(434)
Net increase (decrease) in cash and cash equivalents	2	(1)	(877)
Cash and cash equivalents, beginning of period	4	5	882
Cash and cash equivalents, end of period	6	4	5
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	691	664	667
Income taxes paid, net of refunds received	(6)	(3)	(16)
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Common stock issued for business combination	2,037	0	0
Debt exchanged for common stock	693	0	0
Preferred stock exchanged for common stock	40	0	0
Change in senior notes exchanged	971	0	0
Acquisition of other property and equipment including assets under finance lease	0	27	0
Change In Accrued Drilling And Completion Costs
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs	$ (19)	$ 174	$ 14

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Preferred stock	Common Stock	Additional Paid-in Capital	Additional Paid-in CapitalContingent convertible senior notes exchanged for shares of common stock	Additional Paid-in CapitalSenior notes exchanged for shares of common stock	Additional Paid-in CapitalPreferred stock, exchanged for shares of common stock	Retained earnings	Accumulated Other Comprehensive Loss	Treasury Stock - Common	Parent	Noncontrolling Interest
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2016		$ 1,771	$ 9	$ 14,486				$ (13,625)	$ (96)	$ (27)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Exchange/conversions of 40,000, 0 and 236,048 shares of preferred stock for common stock		(100)
Common shares issued for WildHorse Merger			0	0
Exchange of senior notes and convertible notes			0
Stock-based compensation				54
Convertible notes exchanged, value					$ 0	$ 0
Exchange of preferred stock for 10,367,950, 0, and 9,965,835 shares of common stock							$ 100
Equity component of contingent convertible notes repurchased				(20)
Dividends on preferred stock				(183)
Net income (loss) attributable to Chesapeake	$ (505)							(505)
Reclassification of losses on settled derivative instruments, net of income tax expense of $0, $0 and $0	34								39
Purchase of 2,878,234, 1,510,022, and 1,206,419 shares for company benefit plans										(7)
Release of 879,795, 503,863 and 186,529 shares from company benefit plans										3
Chesapeake stockholders’ equity, end of period at Dec. 31, 2017		1,671	9	14,437				(14,130)	(57)	(31)	$ 1,899
Stockholders' equity attributable to noncontrolling interest, beginning of period at Dec. 31, 2016												$ 49
Increase (Decrease) in Stockholders' Equity [Roll Forward]
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(3)											3
Distributions to noncontrolling interest owners												(8)
Stockholders' equity attributable to noncontrolling interest, end of period at Dec. 31, 2017												44
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	1,943
Exchange/conversions of 40,000, 0 and 236,048 shares of preferred stock for common stock		0
Common shares issued for WildHorse Merger			0	0
Exchange of senior notes and convertible notes			0
Stock-based compensation				33
Convertible notes exchanged, value					0	0
Exchange of preferred stock for 10,367,950, 0, and 9,965,835 shares of common stock							0
Equity component of contingent convertible notes repurchased				0
Dividends on preferred stock				(92)
Net income (loss) attributable to Chesapeake	226							226
Reclassification of losses on settled derivative instruments, net of income tax expense of $0, $0 and $0	34								34
Purchase of 2,878,234, 1,510,022, and 1,206,419 shares for company benefit plans										(4)
Release of 879,795, 503,863 and 186,529 shares from company benefit plans										4
Chesapeake stockholders’ equity, end of period at Dec. 31, 2018	2,092	1,671	9	14,378				(13,912)	(23)	(31)	2,092
Increase (Decrease) in Stockholders' Equity [Roll Forward]
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(2)											2
Distributions to noncontrolling interest owners												(5)
Stockholders' equity attributable to noncontrolling interest, end of period at Dec. 31, 2018	41											41
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	2,133
Exchange/conversions of 40,000, 0 and 236,048 shares of preferred stock for common stock		(40)
Common shares issued for WildHorse Merger			7	2,030
Exchange of senior notes and convertible notes			3
Stock-based compensation				27
Convertible notes exchanged, value					$ 134	$ 438
Exchange of preferred stock for 10,367,950, 0, and 9,965,835 shares of common stock							$ 40
Equity component of contingent convertible notes repurchased				(2)
Dividends on preferred stock				(91)
Net income (loss) attributable to Chesapeake	(308)							(308)
Hedging activity	35								35
Purchase of 2,878,234, 1,510,022, and 1,206,419 shares for company benefit plans										(7)
Release of 879,795, 503,863 and 186,529 shares from company benefit plans										6
Chesapeake stockholders’ equity, end of period at Dec. 31, 2019	4,364	$ 1,631	$ 19	$ 16,954				$ (14,220)	$ 12	$ (32)	$ 4,364
Increase (Decrease) in Stockholders' Equity [Roll Forward]
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	0											0
Distributions to noncontrolling interest owners												(4)
Stockholders' equity attributable to noncontrolling interest, end of period at Dec. 31, 2019	37											$ 37
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	$ 4,401

CONSOLIDATED STATEMENTS OF ST_2

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Treasury Stock - Common
Purchase of shares for company benefit plans (in shares)	2,878,234	1,510,022	1,206,419
Release of shares from company benefit plans (in shares)	879,795	503,863	186,529
Preferred stock exchanged for shares of common stock | Preferred stock
Preferred stock conversions/exchanges (in shares)	40,000	0	236,048
Preferred stock exchanged for shares of common stock | Additional Paid-in Capital
Stock issued, conversion (in shares)	10,367,950	0	9,965,835
Convertible notes exchanged for shares of common stock | Additional Paid-in Capital
Stock issued, conversion (in shares)	73,389,094	0	0
Senior notes exchanged for shares of common stock | Additional Paid-in Capital
Stock issued, conversion (in shares)	235,563,519	0	0

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation and Summary of Significant Accounting Policies	Basis of Presentation and Summary of Significant Accounting Policies Description of Company Chesapeake Energy Corporation ("Chesapeake", “we,” “our”, “us” or the "Company") is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and natural gas liquids (NGL) from underground reservoirs. Our operations are located onshore in the United States. 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. Recast Financial Information for Change in Accounting Principle In the first quarter of 2019, we voluntarily changed our method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods presented herein has been recast to reflect retrospective application of the successful efforts method. Although the full cost method of accounting for oil and natural gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the generally preferred method of the SEC and, because it is more widely used in the industry, we expect the change to improve the comparability of our financial statements to our peers. We also believe the successful efforts method provides a more representational depiction of assets and operating results and provides for our investments in oil and natural gas properties to be assessed for impairment in accordance with Accounting Standards Codification (ASC) Topic 360, Property Plant and Equipment, rather than valuations based on prices and costs prescribed under the full cost method as of the balance sheet date. For detailed information regarding the effects of the change to the successful efforts method, see Note 2 . 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 oil and natural gas properties, oil and natural gas reserves, derivatives, income taxes, unevaluated properties not subject to evaluation, 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. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which we are the primary beneficiary. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. We continually monitor our consolidated VIE to determine if any events have occurred that could cause the primary beneficiary to change. See Note 11 for further discussion of our VIE. 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. Undivided interests in oil and natural gas 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 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, which is exploration and production because our marketing activities are ancillary to our operations. Noncontrolling Interests Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 11 for further discussion of noncontrolling interests. 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. Accounts Receivable Our accounts receivable are primarily from purchasers of oil, natural gas 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 9 for further discussion of our accounts receivable. Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas 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 oil and natural gas 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 oil and gas 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 oil and natural gas 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 oil and natural gas 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 crude oil and natural gas 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 future production volumes, commodity prices, operating costs, and capital investment plans, 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 discount rate believed to be consistent with those applied by market participants. 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, land, vehicles, computers, sand mine, natural gas compressors under finance lease and office equipment. 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. Natural gas compressors under finance lease are depreciated over the shorter of their estimated useful lives or the term of the related lease. 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. 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, 2019 and 2018 are liabilities of approximately $57 million and $104 million , respectively, 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 Included in other long-term assets are costs associated with the issuance and amendments of the Chesapeake revolving credit facility. The remaining unamortized issuance costs as of December 31, 2019 and 2018 , totaled $27 million and $30 million , respectively, and are being amortized over the life of the Chesapeake revolving credit facility using the straight-line method. Included in long-term debt are costs associated with the issuance of our senior notes. The remaining unamortized issuance costs as of December 31, 2019 and 2018 , totaled $44 million and $53 million , respectively, and are being amortized over the life of the senior notes using the effective interest method. 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. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 6 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 6 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 oil and natural gas properties, this is the period in which an oil or natural gas 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 oil and natural gas properties. See Note 22 for further discussion of asset retirement obligations. Revenue Recognition Revenue from the sale of oil, natural gas and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Prior to the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018, revenue from the sale of oil, natural gas and NGL was recognized when title passed 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 oil, natural gas and NGL production (recorded as oil, natural gas 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 oil, natural gas 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. 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 earn 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, (recorded within oil, natural gas and NGL revenues in the consolidated statements of operations) as well as a variety of oil, natural gas 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 oil, natural gas and NGL marketing activities are presented on a net basis. See Note 9 for further discussion of revenue recognition. 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 Note 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, 2019 , 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 twelve 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 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 14 for further discussion of our derivative instruments. Share-Based Compensation Our share-based compensation program consists of restricted stock, stock options, performance share units and cash restricted stock units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three years from the grant date. For directors, although restricted stock grants vest over three years , this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units are settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as general and administrative expense in the consolidated statements of operations. To the extent compensation expense relates to employees directly involved in the acquisition of oil and natural gas leasehold and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expense, oil, natural gas and NGL production expense, exploration expense, or marketing expense, based on the employees involved in those activities. See Note 12 for further discussion of share-based compensation. Recently Issued Accounting Standards In December 2019, the FASB issued Accounting Standards Update (ASU) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (ASU 2019-12) as part of its initiative to reduce complexity in the accounting standards. The amendments in ASU 2019-12 remove certain exceptions related to the incremental approach for intraperiod tax allocation, the general methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. ASU 2019-12 also clarifies and simplifies other aspects of accounting for income taxes. The amendments in ASU 2019-12 become effective for us for the calendar year ending December 31, 2021; however, early adoption is permissible for periods for which financial statements have not yet been issued. We have decided to early adopt ASU 2019-12 for the calendar year ended December 31, 2019, which will be in effect from the beginning of the 2019 annual period. The early adoption of ASU 2019-12 did not result in a material impact to our balance sheet, results of operations or cash flows. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASC 842”) , which requires lessees to recognize a lease liability and a right-of-use (ROU) asset on the balance sheet for all leases, including operating leases, with terms in excess of 12 months. As the implicit rate of the lease is not always readily determinable, the company uses its incremental borrowing rate to calculate the present value of lease payments based on information available at the commencement date. Operating ROU assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet. Finance ROU assets are reflected in total property and equipment, net, while finance lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet. ASC 842 does not apply to our leases of mineral rights to explore for or use oil and natural gas resources, including the intangible rights to explore for those natural resources and rights to use the land in which those natural resources are contained. We adopted the new standard on January 1, 2019 and as permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements , we did not adjust comparative-period financial statements and continued to apply the guidance in Topic 840, including its disclosure requirements, in the comparative periods presented prior to adoption. No cumulative-effect adjustment to retained earnings was required as a result of the modified retrospective approach. Upon adoption of ASC 842, we made certain elections permitting us to not reassess: (1) whether any expired or existing contracts contained leases (2) the lease classification for any expired or existing leases, and (3) initial direct costs for any existing leases. Upon adoption of ASC 842, we also made an election permitting us to continue applying our current policy for land easements. The adoption of ASC 842 did not result in a material impact on our balance sheet, results of operations or cash flows. Short-term leases will not be recognized on the balance sheet as an asset or a liability, and the related rental expense will be expensed as incurred. We have short-term lease agreements related to most of our drilling rig arrangements and some of our compressor rental arrangements. See Note 8 for further information regarding leases. Reclassifications Certain reclassifications have been made to the consolidated financial statements for 2018 and 2017 to conform to the presentation used for the 2019 consolidated financial statements. In 2019, we have reclassified our presentation of ad valorem taxes to report the costs as a component of severance and ad valorem taxes in the accompanying consolidated statements of operations. Previously these costs were reflected as oil, natural gas and NGL production expenses. The net effect of this reclassification did not impact our previously reported net income, stockholders’ equity or cash flows. The following table reflects the reclassifications made: Years Ended December 31, 2018 2017 $ in millions Oil, natural gas and NGL production, previously reported $ 539 $ 562 Reclassification of ad valorem taxes (65 ) (45 ) Oil, natural gas and NGL production, as currently reported $ 474 $ 517 The corresponding amounts have been reflected in severance and ad valorem taxes for 2018 and 2017 as shown below: Years Ended December 31, 2018 2017 $ in millions Production taxes, previously reported $ 124 $ 89 Reclassification of ad valorem taxes 65 45 Severance and ad valorem taxes, as currently reported $ 189 $ 134

Change in Accounting Principle

Change in Accounting Principle	12 Months Ended
	Dec. 31, 2019
Accounting Changes and Error Corrections [Abstract]
Change in Accounting Principle	Change in Accounting Principle In the first quarter of 2019, we voluntarily changed our method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods presented herein has been recast to reflect retrospective application of the successful efforts method. In general, under the successful efforts method, exploration costs such as exploratory dry holes, exploratory geophysical and geological costs, delay rentals, unproved leasehold impairments and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential property impairments by comparing the net carrying value of oil and natural gas properties to associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Under the full cost method of accounting, a write-down would be required if the net carrying value of oil and natural gas properties exceeds a full cost ceiling using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the disposition of oil and natural gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the assets remaining under the full cost method. Our consolidated financial statements have been recast to reflect these differences. The following tables present the effects of the change to the successful efforts method of accounting in the consolidated balance sheets: December 31, 2019 CONSOLIDATED BALANCE SHEETS Under Full Cost Adjustment As Reported Under Successful Efforts ($ in millions except per share data) Proved oil and natural gas properties ($488 and $755 attributable to our VIE) $ 75,148 $ (44,383 ) $ 30,765 Unproved properties $ 3,203 $ (1,030 ) $ 2,173 Total Property and Equipment, at Cost $ 80,161 $ (45,413 ) $ 34,748 Less: accumulated depreciation, depletion and amortization (($468) and ($713) attributable to our VIE) $ (66,626 ) $ 46,624 $ (20,002 ) Total Property and Equipment, Net $ 13,545 $ 1,211 $ 14,756 Total Assets $ 14,982 $ 1,211 $ 16,193 Other current liabilities $ 1,377 $ 55 $ 1,432 Total Current Liabilities $ 2,337 $ 55 $ 2,392 Other long-term liabilities $ 116 $ 9 $ 125 Total Long-Term Liabilities $ 9,391 $ 9 $ 9,400 Accumulated deficit $ (15,451 ) $ 1,231 $ (14,220 ) Total Chesapeake Stockholders’ Equity $ 3,133 $ 1,231 $ 4,364 Noncontrolling interests $ 121 $ (84 ) $ 37 Total Equity $ 3,254 $ 1,147 $ 4,401 Total Liabilities and Equity $ 14,982 $ 1,211 $ 16,193 December 31, 2018 CONSOLIDATED BALANCE SHEETS As Reported Under Full Cost Adjustment As Reported Under Successful Efforts ($ in millions except per share data) Proved oil and natural gas properties ($488 and $755 attributable to our VIE) $ 69,642 $ (44,235 ) $ 25,407 Unproved properties $ 2,337 $ (776 ) $ 1,561 Total Property and Equipment, at Cost $ 73,700 $ (45,011 ) $ 28,689 Less: accumulated depreciation, depletion and amortization (($461) and ($707) attributable to our VIE) $ (64,685 ) $ 46,799 $ (17,886 ) Total Property and Equipment, Net $ 9,030 $ 1,788 $ 10,818 Total Assets $ 10,947 $ 1,788 $ 12,735 Other current liabilities $ 1,540 $ 59 $ 1,599 Total Current Liabilities $ 2,828 $ 59 $ 2,887 Other long-term liabilities $ 156 $ 63 $ 219 Total Long-Term Liabilities $ 7,652 $ 63 $ 7,715 Accumulated deficit $ (15,660 ) $ 1,748 $ (13,912 ) Total Chesapeake Stockholders’ Equity $ 344 $ 1,748 $ 2,092 Noncontrolling interests $ 123 $ (82 ) $ 41 Total Equity $ 467 $ 1,666 $ 2,133 Total Liabilities and Equity $ 10,947 $ 1,788 $ 12,735 The following tables present the effects of the change to the successful efforts method of accounting in the consolidated statements of operations: Year Ended December 31, 2019 CONSOLIDATED STATEMENTS OF OPERATIONS Under Full Cost Adjustment As ($ in millions except per share data) Other revenues $ — $ 63 $ 63 Gain on sale of assets $ — $ 43 $ 43 Total revenues $ 8,489 $ 106 $ 8,595 Exploration expense $ — $ 84 $ 84 General and administrative $ 258 $ 57 $ 315 Depreciation, depletion and amortization $ 1,616 $ 648 $ 2,264 Gain on sale of oil and natural gas properties $ (15 ) $ 15 $ — Impairments $ 344 $ (333 ) $ 11 Other operating expense $ 94 $ (2 ) $ 92 Total operating expenses $ 8,157 $ 469 $ 8,626 Income (loss) from operations $ 332 $ (363 ) $ (31 ) Interest expense $ (487 ) $ (164 ) $ (651 ) Other income $ 31 $ 8 $ 39 Total other expense $ (452 ) $ (156 ) $ (608 ) Loss before income taxes $ (120 ) $ (519 ) $ (639 ) Net income (loss) $ 211 $ (519 ) $ (308 ) Net income attributable to noncontrolling interest $ (2 ) $ 2 $ — Net income (loss) attributable to Chesapeake $ 209 $ (517 ) $ (308 ) Net income (loss) available to common stockholders $ 101 $ (517 ) $ (416 ) Earnings (loss) per common share basic $ 0.06 $ (0.31 ) $ (0.25 ) Earnings (loss) per common share diluted $ 0.06 $ (0.31 ) $ (0.25 ) Year Ended December 31, 2018 CONSOLIDATED STATEMENTS OF OPERATIONS As Adjustment As ($ in millions except per share data) Other revenues $ — $ 63 $ 63 Loss on sale of assets $ — $ (264 ) $ (264 ) Total revenues $ 10,231 $ (201 ) $ 10,030 Exploration expense $ — $ 162 $ 162 General and administrative $ 280 $ 55 $ 335 Depreciation, depletion and amortization $ 1,145 $ 592 $ 1,737 Loss on sale of oil and natural gas properties $ 578 $ (578 ) $ — Impairments $ 53 $ 78 $ 131 Other operating expenses $ 10 $ (10 ) $ — Total operating expenses $ 9,349 $ 299 $ 9,648 Income from operations $ 882 $ (500 ) $ 382 Interest expense $ (487 ) $ (146 ) $ (633 ) Other income $ 70 $ (3 ) $ 67 Total other expense $ (15 ) $ (149 ) $ (164 ) Income before income taxes $ 867 $ (649 ) $ 218 Net income $ 877 $ (649 ) $ 228 Net income attributable to noncontrolling interest $ (4 ) $ 2 $ (2 ) Net income attributable to Chesapeake $ 873 $ (647 ) $ 226 Earnings allocated to participating securities $ (6 ) $ 5 $ (1 ) Net income available to common stockholders $ 775 $ (642 ) $ 133 Earnings per common share basic $ 0.85 $ (0.70 ) $ 0.15 Earnings per common share diluted $ 0.85 $ (0.70 ) $ 0.15 Year Ended December 31, 2017 CONSOLIDATED STATEMENTS OF OPERATIONS As Adjustment As ($ in millions except per share data) Other revenues $ — $ 67 $ 67 Gain on sales of assets $ — $ 476 $ 476 Total revenues $ 9,496 $ 543 $ 10,039 Exploration expense $ — $ 235 $ 235 General and administrative $ 262 $ 71 $ 333 Depreciation, depletion and amortization $ 995 $ 702 $ 1,697 Impairments $ 5 $ 809 $ 814 Other operating expenses $ 413 $ 3 $ 416 Total operating expenses $ 8,357 $ 1,820 $ 10,177 Income (loss) from operations $ 1,139 $ (1,277 ) $ (138 ) Interest expense $ (426 ) $ (175 ) $ (601 ) Other income $ 9 $ (3 ) $ 6 Total other expense $ (184 ) $ (178 ) $ (362 ) Income (loss) before income taxes $ 955 $ (1,455 ) $ (500 ) Net income (loss) $ 953 $ (1,455 ) $ (502 ) Net income attributable to noncontrolling interest $ (4 ) $ 1 $ (3 ) Net income (loss) attributable to Chesapeake $ 949 $ (1,454 ) $ (505 ) Earnings allocated to participating securities $ (10 ) $ 10 $ — Net income (loss) available to common stockholders $ 813 $ (1,444 ) $ (631 ) Earnings (loss) per common share basic $ 0.90 $ (1.60 ) $ (0.70 ) Earnings (loss) per common share diluted $ 0.90 $ (1.60 ) $ (0.70 ) The following tables present the effects of the change to the successful efforts method of accounting in the consolidated statements of comprehensive income: Year Ended December 31, 2019 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Under Full Cost Adjustment As ($ in millions except per share data) Net income (loss) $ 211 $ (519 ) $ (308 ) Comprehensive income (loss) $ 246 $ (519 ) $ (273 ) Comprehensive income attributable to noncontrolling interests $ (2 ) $ 2 $ — Comprehensive income (loss) attributable to Chesapeake $ 244 $ (517 ) $ (273 ) Year Ended December 31, 2018 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME As Adjustment As ($ in millions except per share data) Net income $ 877 $ (649 ) $ 228 Comprehensive income $ 911 $ (649 ) $ 262 Comprehensive income attributable to noncontrolling interests $ (4 ) $ 2 $ (2 ) Comprehensive income attributable to Chesapeake $ 907 $ (647 ) $ 260 Year Ended December 31, 2017 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME As Adjustment As ($ in millions except per share data) Net income (loss) $ 953 $ (1,455 ) $ (502 ) Comprehensive income (loss) $ 992 $ (1,455 ) $ (463 ) Comprehensive income attributable to noncontrolling interests $ (4 ) $ 1 $ (3 ) Comprehensive income (loss) attributable to Chesapeake $ 988 $ (1,454 ) $ (466 ) The following tables present the effects of the change to the successful efforts method of accounting in the consolidated statements of cash flows: Year Ended December 31, 2019 CONSOLIDATED STATEMENTS OF CASH FLOWS Under Full Cost Adjustment As ($ in millions except per share data) Net income (loss) $ 211 $ (519 ) $ (308 ) Depreciation, depletion and amortization $ 1,616 $ 648 $ 2,264 Gain on sale of oil and gas properties $ (15 ) $ 15 $ — Gain on sales of assets $ — $ (43 ) $ (43 ) Impairments $ 344 $ (333 ) $ 11 Exploratory dry hole expense and leasehold impairments $ — $ 49 $ 49 Other $ (2 ) $ (2 ) $ (4 ) (Decrease) increase in accounts payable, accrued liabilities and other $ (567 ) $ (63 ) $ (630 ) Net cash provided by operating activities $ 1,871 $ (248 ) $ 1,623 Drilling and completion costs $ (2,260 ) $ 80 $ (2,180 ) Acquisition of proved and unproved properties $ (203 ) $ 168 $ (35 ) Net cash used by investing activities $ (2,728 ) $ 248 $ (2,480 ) Year Ended December 31, 2018 CONSOLIDATED STATEMENTS OF CASH FLOWS As Adjustment As ($ in millions except per share data) Net income $ 877 $ (649 ) $ 228 Depreciation, depletion and amortization $ 1,145 $ 592 $ 1,737 Loss on sale of oil and gas properties $ 578 $ (578 ) $ — Losses on sales of assets $ — $ 264 $ 264 Impairments $ 53 $ 78 $ 131 Exploratory dry hole expense and leasehold impairments $ — $ 96 $ 96 Other $ (108 ) $ (10 ) $ (118 ) Increase in accounts payable, accrued liabilities and other $ 138 $ (63 ) $ 75 Net cash provided by operating activities $ 2,000 $ (270 ) $ 1,730 Drilling and completion costs $ (1,958 ) $ 110 $ (1,848 ) Acquisition of proved and unproved properties $ (288 ) $ 160 $ (128 ) Net cash provided by investing activities $ 185 $ 270 $ 455 Year Ended December 31, 2017 CONSOLIDATED STATEMENTS OF CASH FLOWS As Adjustment As ($ in millions except per share data) Net income (loss) $ 953 $ (1,455 ) $ (502 ) Depreciation, depletion and amortization $ 995 $ 702 $ 1,697 Gains on sales of assets $ — $ (476 ) $ (476 ) Impairments $ 5 $ 809 $ 814 Exploratory dry hole expense and leasehold impairments $ — $ 214 $ 214 Other $ (135 ) $ 3 $ (132 ) Decrease in accounts payable, accrued liabilities and other $ (308 ) $ (67 ) $ (375 ) Net cash provided by operating activities $ 745 $ (270 ) $ 475 Drilling and completion costs $ (2,186 ) $ 73 $ (2,113 ) Acquisition of proved and unproved properties $ (285 ) $ 197 $ (88 ) Net cash used in investing activities $ (1,188 ) $ 270 $ (918 ) The following tables present the effects of the change to the successful efforts method of accounting in the consolidated statements of stockholders’ equity: Year Ended December 31, 2019 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY Under Full Cost Adjustment As ($ in millions except per share data) Accumulated deficit, beginning of period $ (15,660 ) $ 1,748 $ (13,912 ) Net income (loss) attributable to Chesapeake $ 209 $ (517 ) $ (308 ) Accumulated deficit, end of period $ (15,451 ) $ 1,231 $ (14,220 ) Total Chesapeake stockholders’ equity $ 3,133 $ 1,231 $ 4,364 Noncontrolling interests, beginning of period $ 123 $ (82 ) $ 41 Net income attributable to noncontrolling interests $ 2 $ (2 ) $ — Noncontrolling interests, end of period $ 121 $ (84 ) $ 37 Total equity $ 3,254 $ 1,147 $ 4,401 Year Ended December 31, 2018 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY As As ($ in millions except per share data) Accumulated deficit, beginning of period $ (16,525 ) $ 2,395 $ (14,130 ) Net income attributable to Chesapeake $ 873 $ (647 ) $ 226 Accumulated deficit, end of period $ (15,660 ) $ 1,748 $ (13,912 ) Total Chesapeake stockholders’ equity $ 344 $ 1,748 $ 2,092 Noncontrolling interests, beginning of period $ 124 $ (80 ) $ 44 Net income attributable to noncontrolling interests $ 4 $ (2 ) $ 2 Noncontrolling interests, end of period $ 123 $ (82 ) $ 41 Total equity $ 467 $ 1,666 $ 2,133 Year Ended December 31, 2017 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY As Adjustment As ($ in millions except per share data) Accumulated deficit, beginning of period $ (17,474 ) $ 3,849 $ (13,625 ) Net income (loss) attributable to Chesapeake $ 949 $ (1,454 ) $ (505 ) Accumulated deficit, end of period $ (16,525 ) $ 2,395 $ (14,130 ) Total Chesapeake stockholders’ equity (deficit) $ (496 ) $ 2,395 $ 1,899 Noncontrolling interests, beginning of period $ 128 $ (79 ) $ 49 Net income attributable to noncontrolling interests $ 4 $ (1 ) $ 3 Noncontrolling interests, end of period $ 124 $ (80 ) $ 44 Total equity (deficit) $ (372 ) $ 2,315 $ 1,943

Oil and Natural Gas Property Tr

Oil and Natural Gas Property Transactions	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Oil and Natural Gas Property Transactions	Oil and Natural Gas Property Transactions WildHorse Acquisition On February 1, 2019, we acquired WildHorse Resource Development Corporation (“WildHorse”), an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas for approximately 717.4 million shares of our common stock and $381 million in cash. We funded the cash portion of the consideration through borrowings under the Chesapeake revolving credit facility. In connection with the closing, we acquired all of WildHorse’s debt. See Note 5 for additional information on the acquired debt. Purchase Price Allocation We have accounted for the acquisition of WildHorse and its corresponding merger (the “Merger”) with and into our wholly owned subsidiary, Brazos Valley Longhorn, L.L.C. (“Brazos Valley Longhorn” or “BVL”), as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price of WildHorse to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. Purchase Price Allocation ($ in millions) Consideration: Cash $ 381 Fair value of Chesapeake’s common stock issued in the Merger (a) 2,037 Total consideration $ 2,418 Fair Value of Liabilities Assumed: Current liabilities $ 166 Long-term debt 1,379 Deferred tax liabilities 314 Other long-term liabilities 36 Amounts attributable to liabilities assumed $ 1,895 Fair Value of Assets Acquired: Cash and cash equivalents $ 28 Other current assets 128 Proved oil and natural gas properties 3,264 Unproved properties 756 Other property and equipment 77 Other long-term assets 60 Amounts attributable to assets acquired $ 4,313 Total identifiable net assets $ 2,418 ___________________________________________ (a) Based on 717,376,170 Chesapeake common shares issued at closing at $2.84 per share (closing price as of February 1, 2019). The fair values of assets acquired and liabilities assumed were based on the following key inputs: Oil and Natural Gas Properties For the acquisition of WildHorse, 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 oil and natural gas properties as of the acquisition date was based on estimated oil and natural gas 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 a combination of the NYMEX strip pricing and consensus pricing to value the reserves. Our estimates of commodity prices for purposes of determining discounted cash flows ranged from a 2019 price of $56.33 per barrel of oil increasing to a 2023 price of $61.17 per barrel of oil. Similarly, natural gas prices ranged from a 2019 price of $2.82 per mmbtu then increasing to a 2023 price of $3.00 per mmbtu. Both oil and natural gas commodity prices were held flat after 2023 and adjusted for inflation. 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 oil and natural gas properties acquired. Additionally, the estimated fair value estimate of proved and unproved oil and natural gas properties was corroborated by utilizing the market approach which considers recent comparable transactions for similar assets. The inputs used to value oil and natural gas 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. Deferred Income Taxes For federal income tax purposes, the WildHorse acquisition qualified as a tax-free merger, as a result, we acquired carryover tax basis in WildHorse’s assets and liabilities. Deferred tax liabilities and assets were recorded for differences between the purchase price allocated to the assets acquired and liabilities assumed based on the fair value and the carryover tax basis. See Note 10 for further discussion of deferred income taxes. WildHorse Revenues and Expenses Subsequent to Acquisition We included in our consolidated statements of operations revenues of $752 million , direct operating expenses of $810 million , including depreciation, depletion and amortization, and other expense of $83 million related to the WildHorse business for the period from February 1, 2019 to December 31, 2019. Pro Forma Financial Information The following unaudited pro forma financial information for the years ended December 31, 2019 and 2018, respectively, is based on our historical consolidated financial statements adjusted to reflect as if the WildHorse acquisition had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including adjustments to conform the classification of expenses in WildHorse’s statements of operations to our classification for similar expenses and the estimated tax impact of pro forma adjustments. Years Ended December 31, 2019 2018 ($ in millions except per share data) Revenues $ 8,587 $ 11,211 Net income (loss) available to common stockholders $ (431 ) $ 195 Earnings (loss) per common share: Basic $ (0.26 ) $ 0.12 Diluted $ (0.26 ) $ 0.12 This unaudited pro forma information has been derived from historical information. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the periods presented, nor is it necessarily indicative of future results. 2019 Transactions In 2019, we received proceeds of approximately $130 million , net of post-closing adjustments, and recognized a gain of approximately $46 million , primarily for the sale of non-core oil and natural gas properties. 2018 Transactions We sold all of our approximately 1,500,000 gross ( 900,000 net) acres in Ohio, of which approximately 320,000 net acres are prospective for the Utica Shale with approximately 920 producing wells, along with related property and equipment for net proceeds of $1.868 billion to Encino, with additional contingent payments to us of up to $100 million comprised of $50 million in consideration in each case if, on or prior to December 31, 2019, there is a period of twenty ( 20 ) trading days out of a period of thirty ( 30 ) consecutive trading days where (i) the average of the NYMEX natural gas strip prices for the months comprising the year 2022 equals or exceeds $3.00 /mmbtu as calculated pursuant to the purchase agreement, and (ii) the average of the NYMEX natural gas strip prices for the months comprising the year 2023 equals or exceeds $3.25 /mmbtu as calculated pursuant to the purchase agreement. We recognized a loss of approximately $273 million associated with the transaction. In 2018, we sold portions of our acreage, producing properties and other related property and equipment in the Mid-Continent, including our Mississippian Lime assets, for approximately $491 million , subject to certain customary closing adjustments. Included in the sales were approximately 238,500 net acres and interests in approximately 3,200 wells. We recognized a gain of approximately $12 million associated with the transactions. Also, in 2018, we received proceeds of approximately $37 million subject to customary closing adjustments, for the sale of other oil and natural gas properties covering various operating areas. 2017 Transactions We sold portions of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $915 million , subject to certain customary closing adjustments, and recognized a gain of approximately $326 million . Included in the sales were approximately 119,500 net acres and interests in 576 wells that were producing approximately 80 mmcf of gas per day at the time of closing. Also, in 2017, we received proceeds of approximately $350 million , net of post-closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights. Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For all periods presented, our convertible senior notes did not have a dilutive effect and, therefore, were excluded from the calculation of diluted EPS. Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive. Years Ended December 31, 2019 2018 2017 (in millions) Common stock equivalent of our preferred stock outstanding 58 60 60 Common stock equivalent of our convertible senior notes outstanding 124 146 146 Common stock equivalent of our preferred stock outstanding prior to exchange 1 — 1 Participating securities — 1 1

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	Debt Our long-term debt consisted of the following as of December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 Principal Amount Carrying Principal Carrying ($ in millions) Revolving credit facility $ 1,590 $ 1,590 $ 419 $ 419 Term loan due 2024 1,500 1,470 — — 11.5% senior secured second lien notes due 2025 2,330 3,248 — — Floating rate senior notes due 2019 — — 380 380 6.625% senior notes due 2020 (a) 208 208 437 437 6.875% senior notes due 2020 93 93 227 227 6.125% senior notes due 2021 167 167 548 548 5.375% senior notes due 2021 127 127 267 267 4.875% senior notes due 2022 (a) 338 338 451 451 5.75% senior notes due 2023 (a) 209 209 338 338 7.00% senior notes due 2024 624 624 850 850 6.875% senior notes due 2025 (b) 2 2 — — 8.00% senior notes due 2025 246 245 1,300 1,291 5.5% convertible senior notes due 2026 (c)(d)(e) 1,064 765 1,250 866 7.5% senior notes due 2026 119 119 400 400 8.00% senior notes due 2026 46 44 — — 8.00% senior notes due 2027 253 253 1,300 1,299 2.25% contingent convertible senior notes due 2038 (c) — — 1 1 Debt issuance costs — (44 ) — (53 ) Interest rate derivatives — — — 1 Total debt, net 8,916 9,458 8,168 7,722 Less current maturities of long-term debt, net (f) (385 ) (385 ) (381 ) (381 ) Total long-term debt, net $ 8,531 $ 9,073 $ 7,787 $ 7,341 ___________________________________________ (a) In December 2019, we entered into a purchase and sale agreement to acquire $101 million principal amount of our 6.625% Senior Notes due 2020, 4.875% Senior Notes due 2022 and 5.75% Senior Notes due 2023. During the first quarter of 2020, we repurchased the senior notes. (b) On February 1, 2019, we acquired the debt of WildHorse which consisted of 6.875% Senior Notes due 2025 and a revolving credit facility and in December 2019 we extinguished the debt with proceeds from a term loan issuance. See further discussion below. (c) We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense through the first demand repurchase date, as applicable, at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 5.5% Convertible Senior Notes due 2026 and our 2.25% Contingent Convertible Senior Notes due 2038 are 11.5% and 8.0% , respectively. (d) The conversion and redemption provisions of our convertible senior notes are as follows: Optional Conversion by Holders . Prior to maturity under certain circumstances and at the holder’s option, the notes are convertible. The notes may be converted into cash, our common stock, or a combination of cash and common stock, at our election. One triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the fourth quarter of 2019, the price of our common stock was below the threshold level and, as a result, the holders do not have the option to convert their notes in the first quarter of 2020 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the year ended December 31, 2019 . Upon conversion of a convertible senior note, the holder will receive cash, common stock or a combination of cash and common stock, at our election, according to the conversion rate specified in the indenture. The common stock price conversion threshold amount for the convertible senior notes is 130% of the conversion price of $8.568 . Optional Redemption by the Company . We may redeem the convertible senior notes for cash on or after September 15, 2019 , if the price of our common stock exceeds 130% of the conversion price during a specified period at a redemption price of 100% of the principal amount of the notes. Holders’ Demand Repurchase Rights. The holders of our convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes upon certain defined fundamental changes. (e) The carrying amounts as of December 31, 2019 and 2018, are reflected net of discounts of $299 million and $384 million , respectively, associated with the equity component of our convertible senior notes. This amount is being amortized based on the effective yield method through the first demand repurchase date as applicable. (f) As of December 31, 2019 , net current maturities of long-term debt includes our 6.625% Senior Notes due August 2020 and our 6.875% Senior Notes due November 2020. As of December 31, 2018, net current maturities of long-term debt includes our Floating Rate Senior Notes due April 2019 and our 2.25% Contingent Convertible Senior Notes due 2038. Debt maturities for the next five years and thereafter are as follows: Principal Amount of Debt Securities ($ in millions) 2020 $ 385 2021 294 2022 289 2023 1,764 2024 2,124 Thereafter 4,060 Total $ 8,916 Debt Issuances and Retirements 2019 Term Loan. In December 2019, we entered into a secured 4.5 -year term loan facility in an aggregate principal amount of $1.5 billion for net proceeds of approximately $1.455 billion . Our obligations under the new facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee our revolving credit facility and second lien notes (including BVL and its subsidiaries) and are secured by first-priority liens on the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 8.00% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 7.00% per annum, subject to a 2.00% ABR floor, at our option. The loan was made at 98% of par. We used the net proceeds to finance tender offers for our unsecured BVL senior notes and to repay amounts outstanding under our BVL revolving credit facility. We recorded an aggregate net gain of approximately $4 million associated with the retirement of our BVL senior notes and the BVL revolving credit facility. The term loan matures in June 2024 and voluntary prepayments are subject to a make-whole premium prior to the 18-month anniversary of the closing of the term loan, a premium to par of 5.00% from the 18-month anniversary until but excluding the 30-month anniversary, a premium to par of 2.5% from the 30-month anniversary until but excluding the 42-month anniversary and at par beginning on the 42-month anniversary. The term loan may be subject to mandatory prepayments and offers to prepay with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control. The term loan contains covenants limiting our ability to incur additional indebtedness, incur liens, consummate mergers and similar fundamental changes, make restricted payments, sell collateral and use proceeds from such sales, make investments, repay certain subordinate, unsecured or junior lien indebtedness, and enter into transactions with affiliates. Events of default under the term loan include, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to other indebtedness with an outstanding principal balance of $125 million or more; bankruptcy; judgments involving liability of $125 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods. Senior Secured Second Lien Notes . In December 2019, we completed private offers to exchange newly issued 11.5% Senior Secured Second Lien Notes due 2025 (the “Second Lien Notes”) for the following outstanding senior unsecured notes (the “Existing Notes”): Notes Exchanged ($ in millions) 7.00% senior notes due 2024 $ 226 8.00% senior notes due 2025 999 8.00% senior notes due 2026 873 7.5% senior notes due 2026 281 8.00% senior notes due 2027 837 Total $ 3,216 The Second Lien Notes are secured second lien obligations and are contractually junior to our current and future secured first lien indebtedness, including indebtedness incurred under our revolving credit facility and term loan facility, to the extent of the value of the collateral securing such indebtedness, effectively senior to all of our existing and future unsecured indebtedness, including our outstanding senior notes, to the extent of the value of the collateral, and senior to any future subordinated indebtedness that we may incur. We have the option to redeem the Second Lien Notes, in whole or in part, at specified make-whole or redemption prices. Our Second Lien Notes are governed by an indenture containing covenants that may limit our ability and our subsidiaries’ ability to create liens securing certain indebtedness, make certain restricted payments, enter into certain sale-leaseback transactions, consolidate, merge or transfer assets and dispose of certain collateral and use proceeds from dispositions of certain collateral. As a holding company, Chesapeake owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the Second Lien Notes are jointly and severally, fully and unconditionally guaranteed by the same subsidiaries that guarantee our revolving credit facility and term loan facility (including BVL and its subsidiaries). See Note 25 for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries. The exchanges of the Existing Notes (with a carrying value of $3.152 billion ) for $2.210 billion of Second Lien Notes, were accounted for as a troubled debt restructuring (“TDR”). For the majority of the notes in this exchange, the future undiscounted cash flows were greater than the net carrying value of the original debt, no gain was recognized and a new effective interest rate was established based on the carrying value of the original debt. The amount of the extinguished debt will be amortized over the life of the notes as a reduction to interest expense. As a result, our reported interest expense will be significantly less than the contractual interest payments throughout the term of the Second Lien Notes. In a subsequent transaction in December 2019, we issued an additional $120 million of 11.5% Senior Secured Second Lien Notes due 2025 pursuant to a private offering, at 89.75% of par. Additionally, in December 2019, we entered into a purchase and sale agreement with the same counterparty to acquire $101 million principal amount of our 6.625% Senior Notes due 2020, 4.875% Senior Notes due 2022 and 5.75% Senior Notes due 2023 at a discount. During the first quarter of 2020, we repurchased the senior notes. Exchanges of Senior Notes for Common Stock. We privately negotiated exchanges of approximately $507 million principal amount of our outstanding senior notes for 235,563,519 shares of common stock and $186 million principal amount of our outstanding convertible senior notes for 73,389,094 shares of common stock. We recorded an aggregate net gain of approximately $64 million associated with the exchanges. We issued at par approximately $919 million of 8.00% Senior Notes due 2026 (“2026 notes”) pursuant to a private exchange offer for the following outstanding senior unsecured notes: Notes Exchanged ($ in millions) 6.625% senior notes due 2020 $ 229 6.875% senior notes due 2020 134 6.125% senior notes due 2021 381 5.375% senior notes due 2021 140 Total $ 884 We may redeem some or all of the 2026 notes at any time prior to March 15, 2022 at a price equal to 100% of the principal amount of the notes to be redeemed plus a “make-whole” premium. At any time prior to March 15, 2022, we also may redeem up to 35% of the aggregate principal amount of each series of notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a specified redemption price. In addition, we may redeem some or all of the 2026 notes at any time on or after March 15, 2022 at the redemption prices in accordance with the terms of the notes, the indenture and supplemental indenture governing the notes. These senior notes are unsecured obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes are jointly and severally, fully and unconditionally guaranteed by all of our wholly owned subsidiaries that guarantee the Chesapeake revolving credit facility and certain other unsecured senior notes. We accounted for the exchange as a modification to existing debt and no gain or loss was recognized. We repaid upon maturity $380 million principal amount of our Floating Rate Senior Notes due April 2019 with borrowings from our Chesapeake revolving credit facility. Debt Issuances and Retirements 2018 We issued at par $850 million of 7.00% Senior Notes due 2024 (“2024 notes”) and $400 million of 7.50% Senior Notes due 2026 (“2026 notes”) pursuant to a public offering for net proceeds of approximately $1.236 billion . We may redeem some or all of the 2024 notes at any time prior to April 1, 2021 and some or all of the 2026 notes at any time prior to October 1, 2021, in each case at a price equal to 100% of the principal amount of the notes to be redeemed plus a “make-whole” premium. At any time prior to April 1, 2021, with respect to the 2024 notes, and October 1, 2021, with respect to the 2026 notes, we also may redeem up to 35% of the aggregate principal amount of each series of notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a specified redemption price. In addition, we may redeem some or all of the 2024 notes at any time on or after April 1, 2021 and some or all of the 2026 notes at any time on or after October 1, 2021, in each case at the redemption prices in accordance with the terms of the notes and the indenture and supplemental indenture governing the notes. These senior notes are unsecured obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries. We used the net proceeds from the 2024 and 2026 notes, together with cash on hand and borrowings under the Chesapeake revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021 for $1.285 billion , which included a $52 million make-whole premium. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the make-whole premium and the write-off of $13 million of associated deferred charges. We used a portion of the proceeds from the sale of our Utica Shale assets in Ohio to redeem all of the $1.416 billion aggregate principal amount outstanding of our 8.00% Senior Secured Second Lien Notes due 2022 for $1.477 billion . We recorded a gain of approximately $331 million associated with the redemption, including the realization of the remaining $391 million difference in principal and book value due to troubled debt restructuring accounting in 2015, offset by the make-whole premium of $60 million . We repaid upon maturity $44 million principal amount of our 7.25% Senior Notes due 2018. As required by the terms of the indenture for our 2.25% Contingent Convertible Senior Notes due 2038 (“2038 notes”), the holders were provided the option to require us to purchase on December 15, 2018, all or a portion of the holders’ 2038 notes at par plus accrued and unpaid interest up to, but excluding, December 15, 2018. On December 17, 2018, we paid an aggregate of approximately $8 million to purchase all of the 2038 notes that were tendered and not withdrawn. An aggregate of $1 million principal amount of the 2038 notes remained outstanding as of December 31, 2018. Subsequent to December 31, 2018, we redeemed these notes at par and discharged the related indenture. Senior Notes and Convertible Senior Notes Our senior notes and our convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes and the convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries. See Note 25 for consolidating financial information regarding our guarantor and non-guarantor subsidiaries. We may redeem the senior notes, other than the convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the convertible senior notes do not have any financial or restricted payment covenants. Indentures for the senior notes and convertible senior notes have cross default provisions that apply to other indebtedness Chesapeake or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million , depending on the indenture. Revolving Credit Facility Our revolving credit facility matures in September 2023 and the current aggregate commitment of the lenders and borrowing base under the facility is $3.0 billion . The revolving credit facility provides for an accordion feature, pursuant to which the aggregate commitments thereunder may be increased to up to $4.0 billion from time to time, subject to agreement of the participating lenders and certain other customary conditions. Scheduled borrowing base redeterminations will continue to occur semiannually. Our next borrowing base redetermination is scheduled for the second quarter of 2020. As of December 31, 2019 , we had outstanding borrowings of $1.590 billion under our revolving credit facility and had used $59 million for various letters of credit. Borrowings under our revolving credit facility bear interest at an alternative base rate (ABR) or LIBOR, at our election, plus an applicable margin ranging from 1.50% - 2.50% per annum for ABR loans and 2.50% - 3.50% per annum for LIBOR loans, depending on the percentage of the borrowing base then being utilized. Our revolving credit facility is subject to various financial and other covenants. The terms of the revolving credit facility include covenants limiting, among other things, our ability to incur additional indebtedness, make investments or loans, incur liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. On December 3, 2019, we entered into the second amendment to our credit agreement. Among other things, the amendment (i) permitted the issuance of certain secured indebtedness with a lien priority or proceeds recovery behind the obligations under the credit agreement without a corresponding 25% reduction in the borrowing base under the credit agreement, if issued by the next scheduled redetermination of the borrowing base, (ii) increased the amount of indebtedness that can be secured on a pari passu first-lien basis with (and with recovery proceeds behind) the obligations under the credit agreement from $1 billion to $1.5 billion , (iii) increased the applicable margin as defined in the credit agreement on borrowings under the credit agreement by 100 basis points, (iv) requires liquidity of at least $250 million at all times, (v) for each fiscal quarter commencing with the fiscal quarter ending December 31, 2019, replaced the secured leverage ratio financial covenant with a requirement that the first lien secured leverage ratio not exceed 2.50 to 1 as of the end of such fiscal quarter, (vi) increased the maximum permitted leverage ratio as of the end of each fiscal quarter to 4.50 to1 through the fiscal quarter ending December 31, 2021, with step-downs to 4.25 to 1 for the fiscal quarter ending March 31, 2022 and to 4.00 to 1 for each fiscal quarter ending thereafter, and (vii) required that we use the aggregate net cash proceeds of certain asset sales in excess of $50 million to prepay certain indebtedness and/or reduce commitments under our credit agreement, until the retirement of all of our senior notes maturing before September 12, 2023. On December 26, 2019, we entered into the third amendment to our credit agreement, which, among other things, permitted the issuance of certain secured indebtedness with a lien priority behind the obligations under the credit agreement without a corresponding 25% reduction in the borrowing base under the credit agreement, if issued by December 31, 2019 and issued in exchange for, or the proceeds used to refinance, our senior notes . As of December 31, 2019 , we were in compliance with all applicable financial covenants under the credit agreement and we were able to borrow up to the full availability under our revolving credit facility. Phase-Out of LIBOR In July 2017, the UK's Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR as a benchmark by the end of 2021. At the present time, our revolving credit facility and our term loan have terms that extend beyond 2021. Our revolving credit facility and our term loan each provide for a mechanism to amend the underlying agreements to reflect the establishment of an alternate rate of interest upon the occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to our revolving credit facility or term loan to address this matter. We are currently evaluating the potential impact of the eventual replacement of the LIBOR interest rate. Fair Value of Debt We estimate the fair value of our senior notes based on the market value of our publicly traded debt as determined based on the yield of our senior notes (Level 1). The fair value of all other debt is based on a market approach using estimates provided by an independent investment financial data services firm (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below: December 31, 2019 December 31, 2018 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 385 $ 360 $ 381 $ 379 Long-term debt (Level 1) $ 753 $ 622 $ 3,495 $ 3,173 Long-term debt (Level 2) $ 8,320 $ 6,085 $ 3,846 $ 3,644

Contingencies and Commitments

Contingencies and Commitments	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Contingencies and Commitments	Contingencies and Commitments Contingencies Litigation and Regulatory Proceedings We are involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. 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. Business Operations. We are 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. We and other natural gas producers have been named in various lawsuits alleging underpayment of royalties and other shares of the proceeds of production. The lawsuits against us allege, among other things, that we used below-market prices, made improper deductions, utilized improper measurement techniques, entered into arrangements with affiliates that resulted in underpayment of amounts owed in connection with the production and sale of natural gas and NGL, or similar theories. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The lawsuits seek compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our payment practices, pre-and post-judgment interest, and attorney’s fees and costs. Plaintiffs have varying provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations. We have resolved a number of these claims through negotiated settlements of past and future royalty obligations and have prevailed in various other lawsuits. We are currently defending numerous lawsuits seeking damages with respect to underpayment of royalties or other shares of the proceeds of production in multiple states where we have operated, including those discussed below. On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that we violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit includes other UTPCPL claims and antitrust claims, including that a joint exploration agreement to which we are a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as a temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid, and a permanent injunction from further violations of the UTPCPL. We intend to vigorously defend these claims. Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the divestiture of substantially all of our midstream business and most of our gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights, intentional interference with contractual relations, and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources. These lawsuits seek in aggregate compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. On December 20, 2017 and August 9, 2018, we reached tentative settlements to resolve substantially all Pennsylvania civil royalty cases for a total of approximately $36 million . We believe losses are reasonably possible in certain of the pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years. On July 24, 2018, Healthcare of Ontario Pension Plan (HOOPP) filed a demand for arbitration with the American Arbitration Association regarding HOOPP’s purchase of our interest in Chaparral Energy, Inc. stock for $215 million on January 5, 2014. HOOPP claims that we engaged in material misrepresentations and fraud, and that we violated the Exchange Act and Oklahoma Uniform Securities Act. HOOPP seeks either rescission or $215 million in monetary damages, and in either case, interest, attorney’s fees, disgorgement and punitive damages. We intend to vigorously defend these claims. In February 2019, a putative class action lawsuit in the District Court of Dallas County, Texas was filed against FTS International, Inc. (“FTSI”), certain investment banks, FTSI’s directors including certain of our officers and certain shareholders of FTSI including us. The lawsuit alleges various violations of Sections 11 (with respect to certain of our officers in their capacities as directors of FTSI) and 15 (with respect to such officers and us) of the Securities Act of 1933 in connection with public disclosure made during the initial public offering of FTSI. The suit seeks damages in excess of $1,000,000 and attorneys’ fees and other expenses. We intend to vigorously defend these claims. Environmental Contingencies The nature of the oil and gas 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. We are named as a defendant in numerous lawsuits in Oklahoma alleging that we and other companies have engaged in activities that have caused earthquakes. These lawsuits seek compensation for injury to real and personal property, diminution of property value, economic losses due to business interruption, interference with the use and enjoyment of property, annoyance and inconvenience, personal injury and emotional distress. In addition, they seek the reimbursement of insurance premiums and the award of punitive damages, attorneys’ fees, costs, expenses and interest. We intend to vigorously defend these claims. We previously disclosed ongoing discussions between our subsidiary, Chesapeake Appalachia, L.L.C. ( “ CALLC ” ) and the Pennsylvania Department of Environmental Protection related to gas migration in the vicinity of certain of our wells in Bradford County. Those concerns were resolved by the parties on August 28, 2019. Pursuant to the settlement, CALLC paid a civil penalty of less than $100,000 . Other Matters Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates. Commitments Gathering, Processing and Transportation Agreements We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in our estimates of proved reserves. The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below: December 31, ($ in millions) 2020 $ 1,136 2021 1,033 2022 913 2023 789 2024 690 2025 – 2034 3,479 Total $ 8,040 In addition, we have entered into 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. Service Contract We have contracts with third-party contractors to provide maintenance and other services to generators and natural gas compressors. These commitments are not recorded as an obligation in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future payments under these service contracts are detailed below. December 31, 2019 ($ in millions) 2020 $ 7 2021 7 2022 2 Total $ 16 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 oil and natural gas 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. While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity.

Other Liabilities

Other Liabilities	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Other Liabilities	Other Liabilities Other current liabilities as of December 31, 2019 and 2018 are detailed below: December 31, 2019 2018 ($ in millions) Revenues and royalties due others $ 516 $ 687 Accrued drilling and production costs 326 258 Joint interest prepayments received 52 73 VPP deferred revenue (a) 55 59 Accrued compensation and benefits 156 202 Other accrued taxes 150 108 Other 177 212 Total other current liabilities $ 1,432 $ 1,599 Other long-term liabilities as of December 31, 2019 and 2018 are detailed below: December 31, 2019 2018 ($ in millions) VPP deferred revenue (a) $ 9 $ 63 Unrecognized tax benefits (b) — 53 Other 116 103 Total other long-term liabilities $ 125 $ 219 ____________________________________________ (a) At the inception of our volumetric production payment (VPP) agreements, we (i) removed the proved reserves associated with the VPP, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to other revenue over the term of the VPP, (iii) retained responsibility for the production costs and capital costs related to VPP interests and (iv) ceased recognizing production associated with the VPP volumes. The remaining deferred revenue balance will be recognized in other revenues in the consolidated statement of operations through February 2021, assuming the related VPP production volumes are delivered as scheduled. (b) The liability for unrecognized tax benefits was eliminated during the fourth quarter of 2019 as a result of a settlement.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Leases We are a lessee under various agreements for compressors, office space, vehicles and other equipment. As of December 31, 2019 , these leases have remaining terms ranging from one month to seven 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 ROU asset and lease liability balances. Upon adoption of ASC 842 on January 1, 2019, we recognized a nominal operating lease liability and a nominal related ROU asset related to vehicles we lease. On February 1, 2019, we acquired WildHorse and, as part of the purchase price allocation, we recognized additional operating lease liabilities of $40 million , a related ROU asset of $38 million , and lease incentives of $2 million related to two office space leases, a long-term hydraulic fracturing agreement and other equipment leases. Regarding our long-term hydraulic fracturing agreements, we made a policy election to treat both lease and non-lease components as a single lease component. In 2018, we sold our wholly owned subsidiary, Midcon Compression, L.L.C., to a third party and subsequently leased back some natural gas compressors for 38 months . The lease is accounted for as a finance lease liability. The following table presents our ROU assets and lease liabilities as of December 31, 2019 . Finance Operating ($ in millions) ROU assets $ 17 $ 22 Lease liabilities: Current lease liabilities $ 9 $ 9 Long-term lease liabilities 9 16 Total lease liabilities $ 18 $ 25 Additional information for the Company’s operating and finance leases is presented below: Year Ended Lease cost: ($ in millions) Amortization of ROU assets $ 8 Interest on lease liability 2 Finance lease cost 10 Operating lease cost 26 Short-term lease cost 112 Total lease cost $ 148 Other information: Operating cash outflows from finance lease $ 2 Operating cash outflows from operating leases $ 11 Investing cash outflows from operating leases $ 127 Financing cash outflows from finance lease $ 8 Weighted average remaining lease term - finance lease 2.00 years Weighted average remaining lease term - operating leases 4.65 years Weighted average discount rate - finance lease 7.50 % Weighted average discount rate - operating leases 4.85 % Maturity analysis of finance lease liabilities and operating lease liabilities are presented below: December 31, 2019 Finance Lease Operating Leases ($ in millions) 2020 $ 10 $ 10 2021 10 5 2022 — 4 2023 — 2 2024 — 2 Thereafter — 5 Total lease payments 20 28 Less imputed interest (2 ) (3 ) Present value of lease liabilities 18 25 Less current maturities (9 ) (9 ) Present value of lease liabilities, less current maturities $ 9 $ 16 The aggregate undiscounted minimum future lease payments under previous lease accounting standard, ASC 840, are presented below: December 31, 2018 Capital Lease Operating Leases ($ in millions) 2019 $ 10 $ 3 2020 10 1 2021 10 — Total minimum lease payments $ 30 $ 4
Leases	Leases We are a lessee under various agreements for compressors, office space, vehicles and other equipment. As of December 31, 2019 , these leases have remaining terms ranging from one month to seven 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 ROU asset and lease liability balances. Upon adoption of ASC 842 on January 1, 2019, we recognized a nominal operating lease liability and a nominal related ROU asset related to vehicles we lease. On February 1, 2019, we acquired WildHorse and, as part of the purchase price allocation, we recognized additional operating lease liabilities of $40 million , a related ROU asset of $38 million , and lease incentives of $2 million related to two office space leases, a long-term hydraulic fracturing agreement and other equipment leases. Regarding our long-term hydraulic fracturing agreements, we made a policy election to treat both lease and non-lease components as a single lease component. In 2018, we sold our wholly owned subsidiary, Midcon Compression, L.L.C., to a third party and subsequently leased back some natural gas compressors for 38 months . The lease is accounted for as a finance lease liability. The following table presents our ROU assets and lease liabilities as of December 31, 2019 . Finance Operating ($ in millions) ROU assets $ 17 $ 22 Lease liabilities: Current lease liabilities $ 9 $ 9 Long-term lease liabilities 9 16 Total lease liabilities $ 18 $ 25 Additional information for the Company’s operating and finance leases is presented below: Year Ended Lease cost: ($ in millions) Amortization of ROU assets $ 8 Interest on lease liability 2 Finance lease cost 10 Operating lease cost 26 Short-term lease cost 112 Total lease cost $ 148 Other information: Operating cash outflows from finance lease $ 2 Operating cash outflows from operating leases $ 11 Investing cash outflows from operating leases $ 127 Financing cash outflows from finance lease $ 8 Weighted average remaining lease term - finance lease 2.00 years Weighted average remaining lease term - operating leases 4.65 years Weighted average discount rate - finance lease 7.50 % Weighted average discount rate - operating leases 4.85 % Maturity analysis of finance lease liabilities and operating lease liabilities are presented below: December 31, 2019 Finance Lease Operating Leases ($ in millions) 2020 $ 10 $ 10 2021 10 5 2022 — 4 2023 — 2 2024 — 2 Thereafter — 5 Total lease payments 20 28 Less imputed interest (2 ) (3 ) Present value of lease liabilities 18 25 Less current maturities (9 ) (9 ) Present value of lease liabilities, less current maturities $ 9 $ 16 The aggregate undiscounted minimum future lease payments under previous lease accounting standard, ASC 840, are presented below: December 31, 2018 Capital Lease Operating Leases ($ in millions) 2019 $ 10 $ 3 2020 10 1 2021 10 — Total minimum lease payments $ 30 $ 4

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition The FASB issued Revenue from Contracts with Customers (Topic 606) superseding virtually all existing revenue recognition guidance. We adopted this new standard in the first quarter of 2018 using the modified retrospective approach. We applied the new standard to all contracts that were not completed as of January 1, 2018 and reflected the aggregate effect of all modifications in determining and allocating the transaction price. The cumulative effect of adoption of $8 million did not have a material impact on our consolidated financial statements. The following table shows revenue disaggregated by operating area and product type, for the years ended December 31, 2019 and 2018 : Year Ended December 31, 2019 Oil Natural Gas NGL Total ($ in millions) Marcellus $ — $ 856 $ — $ 856 Haynesville — 620 — 620 Eagle Ford 1,289 153 119 1,561 Brazos Valley 721 32 16 769 Powder River Basin 369 77 32 478 Mid-Continent 164 44 25 233 Revenue from contracts with customers 2,543 1,782 192 4,517 Gains (losses) on oil, natural gas and NGL derivatives (212 ) 217 — 5 Oil, natural gas and NGL revenue $ 2,331 $ 1,999 $ 192 $ 4,522 Marketing revenue from contracts with customers $ 2,473 $ 900 $ 246 $ 3,619 Other marketing revenue 311 41 — 352 Losses on marketing derivatives — (4 ) — (4 ) Marketing revenue $ 2,784 $ 937 $ 246 $ 3,967 Year Ended December 31, 2018 Oil Natural Gas NGL Total ($ in millions) Marcellus $ — $ 924 $ — $ 924 Haynesville 2 836 — 838 Eagle Ford 1,514 173 185 1,872 Powder River Basin 244 68 38 350 Mid-Continent 246 84 55 385 Utica 195 401 224 820 Revenue from contracts with customers 2,201 2,486 502 5,189 Gains (losses) on oil, natural gas and NGL derivatives 124 (147 ) (11 ) (34 ) Oil, natural gas and NGL revenue $ 2,325 $ 2,339 $ 491 $ 5,155 Marketing revenue from contracts with customers $ 2,740 $ 1,194 $ 456 $ 4,390 Other marketing revenue 457 222 — 679 Gains on marketing derivatives — 7 — 7 Marketing revenue $ 3,197 $ 1,423 $ 456 $ 5,076 Accounts Receivable Accounts receivable as of December 31, 2019 and 2018 are detailed below: December 31, 2019 2018 ($ in millions) Oil, natural gas and NGL sales $ 737 $ 976 Joint interest billings 200 211 Other 74 77 Allowance for doubtful accounts (21 ) (17 ) Total accounts receivable, net $ 990 $ 1,247

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of the income tax provision (benefit) for each of the periods presented below are as follows: Years Ended December 31, 2019 2018 2017 ($ in millions) Current Federal $ — $ — $ (14 ) State (26 ) — 5 Current Income Taxes (26 ) — (9 ) Deferred Federal (297 ) 3 13 State (8 ) (13 ) (2 ) Deferred Income Taxes (305 ) (10 ) 11 Total $ (331 ) $ (10 ) $ 2 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: Years Ended December 31, 2019 2018 2017 ($ in millions) Income tax expense (benefit) at the federal statutory rate (21%, 21%, 35%) $ (134 ) $ 45 $ (175 ) State income taxes (net of federal income tax benefit) (21 ) 27 5 Partial release of valuation allowance due to the WildHorse Merger (314 ) — — Remeasurement of deferred tax assets and liabilities — — 931 Change in valuation allowance excluding impact of WildHorse Merger 114 (97 ) (771 ) Other 24 15 12 Total $ (331 ) $ (10 ) $ 2 We applied the guidance in SAB 118 when accounting for the enactment-date effect of the tax reform legislation commonly known as the Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 (the “Tax Act”). At December 31, 2017, we had not completed our accounting for all of the enactment-date income tax effects of the Tax Act under ASC 740, Income Taxes, for certain items as we were waiting on additional guidance to be issued. At December 31, 2018, we had completed our accounting for all of the enactment-date income tax effects of the Tax Act. The adjustments made during 2018 were considered immaterial but nevertheless are included as a component of income tax expense (benefit) in our consolidated statement of operations for the year ended December 31, 2018, which is fully offset with an adjustment to the valuation allowance against our net deferred tax asset position. We reassessed the realizability of our deferred tax assets and continue to maintain a full valuation allowance against our net deferred tax asset positions for federal and state purposes with the exception of Texas. Texas is currently in a net deferred tax liability position. Of the $206 million net decrease in our valuation allowance, $200 million is reflected as a component of income tax benefit in our consolidated statement of operations for the year ended December 31, 2019. This decrease in the valuation allowance is primarily due to the partial release of the valuation allowance associated with the WildHorse Merger. Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences, NOL carryforwards and disallowed business interest carryforwards that comprise our deferred income taxes are as follows: December 31, 2019 2018 ($ in millions) Deferred tax liabilities: Property, plant and equipment $ (546 ) $ (976 ) Volumetric production payments (89 ) (86 ) Carrying value of debt — (95 ) Derivative instruments (14 ) (56 ) Other (5 ) (7 ) Deferred tax liabilities (654 ) (1,220 ) Deferred tax assets: Net operating loss carryforwards 1,971 2,737 Carrying value of debt 169 — Disallowed business interest carryforward 25 194 Asset retirement obligations 50 40 Investments 83 111 Accrued liabilities 64 89 Other 87 60 Deferred tax assets 2,449 3,231 Valuation allowance (1,805 ) (2,011 ) Deferred tax assets after valuation allowance 644 1,220 Net deferred tax liability $ (10 ) $ — As of December 31, 2019 , we had federal NOL carryforwards of approximately $7.582 billion and state NOL carryforwards of approximately $6.844 billion . The associated deferred tax assets related to these federal and state NOL carryforwards were $1.592 billion and $379 million , respectively. The federal NOL carryforwards generated in tax years prior to 2018 expire between 2033 and 2037. As a result of the Tax Act, the 2018 federal NOL carryforward has no expiration. The value of all of these carryforwards depends on our ability to generate future taxable income. As of December 31, 2019 , and 2018 , we had deferred tax assets of $2.449 billion and $3.231 billion upon which we had a valuation allowance of $1.805 billion and $2.011 billion , respectively. Of the net change in the valuation allowance of $206 million for both federal and state deferred tax assets, $200 million is reflected as a component of income tax benefit in the consolidated statement of operations and the remainder is reflected in components of stockholders’ equity. 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. A significant piece of objectively verifiable negative evidence is the cumulative loss incurred over the three-year period ended December 31, 2019 . Such objective negative evidence limits our ability to consider various forms of subjective positive evidence, such as any projections for future income. Accordingly, management has not changed its judgment for the period ended December 31, 2019 with respect to the need for a full valuation allowance against our net deferred tax asset positions for federal and state purposes with the exception of Texas. Texas is currently in a net deferred tax liability position. The amount of the deferred tax assets considered realizable could be adjusted if projections of future taxable income are increased and/or if objective negative evidence in the form of cumulative losses is no longer present. Should we return to a level of sustained profitability, consideration will need to be given to future projections of taxable income to determine whether such projections provide an adequate source of taxable income for the realization of our deferred tax assets, namely federal NOL carryforwards and disallowed business interest carryforwards. If so, then all or a portion of the valuation allowance could possibly be released. On February 1, 2019, we completed the acquisition of WildHorse. 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 WildHorse’s assets and liabilities. We recorded a net deferred tax liability of $314 million as part of the business combination accounting for WildHorse. As a consequence of maintaining a full valuation allowance against our net deferred tax asset positions (federal and state), a partial release of the valuation allowance was recorded as a discrete income tax benefit of $314 million through the consolidated statement of operations in the first quarter of 2019. The net deferred tax liability determined through business combination accounting includes deferred tax liabilities on plant, property and equipment and prepaid compensation totaling $401 million , partially offset by deferred tax assets totaling $87 million relating to federal NOL carryforwards, disallowed business interest carryforwards and certain other deferred tax assets. These carryforwards will be subject to an annual limitation under Section 382 of the Code of approximately $61 million . We determined that no separate valuation allowances were required to be established through business combination accounting against any of the individual deferred tax assets acquired. Our ability to utilize NOL carryforwards, disallowed business interest carryforwards, and possibly other tax attributes to reduce future federal taxable income and federal income tax is subject to various limitations under Section 382 of the Code. The utilization of these attributes may be subject to an annual limitation under Section 382 of the Code should transactions involving our equity, including issuances of our stock or the sale or exchange of our stock by certain shareholders, result in an Ownership Change. (For this purpose, “stock” includes certain preferred stock). Some states impose similar limitations on tax attribute utilization upon experiencing an Ownership Change. As of December 31, 2019, we do not believe that an Ownership Change has occurred that would subject us to an annual limitation on the utilization of our NOL carryforwards, disallowed business interest carryforwards and other tax attributes. After taking into account the exchanges of our common stock for certain outstanding senior notes that occurred during the quarter ended September 30, 2019 (see Note 5 for further details of the debt exchanges) and the exchange of our common stock for certain Cumulative Convertible Preferred Stock which also occurred during the quarter ended September 30, 2019 (see Note 11 for further details of the stock exchange), our cumulative shift remains under 50% but has increased to a level of over 40% . Therefore, with the exception of the NOL carryforwards and disallowed business interest carryforwards acquired upon the WildHorse Merger, we do not believe we have a limitation on the ability to utilize our carryforwards and other tax attributes under Section 382 of the Code as of December 31, 2019. However, future transactions involving our equity, including relatively small transactions and transactions beyond our control, could cause an Ownership Change and therefore an annual limitation on the utilization of NOL carryforwards, disallowed business interest carryforwards and possibly other tax attributes. Further, the Proposed Regulations would, if finalized in their current form, significantly reduce our annual limitation should we experience an Ownership Change on or after the date the Proposed Regulations become final and we are in a net unrealized built-in gain position. Among other changes, the Proposed Regulations would, if finalized in their current form, limit the potential increases to the annual limitation amount associated with certain built-in gains existing at the time of an Ownership Change, thereby significantly reducing the ability to utilize tax attributes. As a result, certain NOL carryforwards, disallowed business interest carryforwards and other tax attributes may need to be written off or have a valuation allowance maintained against them possibly leading to a material charge to income tax expense. 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 de-recognition, classification and disclosure of uncertain tax positions. As of December 31, 2019 , and 2018 , the amount of unrecognized tax benefits related to NOL carryforwards and tax liabilities associated with uncertain tax positions was $74 million and $79 million , respectively. Of the 2019 amount, $29 million is related to state tax receivables not expected to be recovered and the remainder is related to NOL carryforwards. Of the 2018 amount, $32 million is related to state tax liabilities, $29 million is related to state tax receivables not expected to be recovered and the remainder is related to NOL carryforwards. If recognized, $29 million of the uncertain tax positions identified would have an effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of December 31, 2019 , we had no amounts accrued for interest related to these uncertain tax positions. As of December 31, 2018 , we had accrued liabilities of $20 million for interest. We recognize interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: 2019 2018 2017 ($ in millions) Unrecognized tax benefits at beginning of period $ 79 $ 106 $ 202 Additions based on tax positions related to the current year — — — Additions to tax positions of prior years 27 — 4 Settlements (32 ) — (100 ) Expiration of the applicable statute of limitations — (23 ) — Reductions to tax positions of prior years — (4 ) — Unrecognized tax benefits at end of period $ 74 $ 79 $ 106 Our federal and state income tax returns are subject to examination by federal and state tax authorities. Federal examination cycles 2010 through 2013 and 2014 through 2015 were settled with the Internal Revenue Service (IRS) during the first and third quarters of 2018, respectively. However, certain of these tax years remain open for purposes of adjusting federal NOL carryforwards upon utilization. Our tax years 2016 through 2018 remain open for all purposes of examination by the IRS. With respect to WildHorse, the federal income tax returns for tax years 2016 through 2018 as well as the short period return January 1, 2019 through February 1, 2019, remain open for examination by the IRS. The IRS has notified us that our 2016 income tax return as well as the WildHorse 2017 income tax return will be audited. In addition, tax years 2016 through 2018 as well as certain earlier years remain open for examination by state tax authorities including the WildHorse state income tax returns for such periods along with the WildHorse 2019 short period return. Currently, several state examinations are in progress of various years. We do not anticipate that the outcome of any state audit will have a significant impact on our financial position or results of operations.

Equity

Equity	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Equity	Equity Common Stock A summary of the changes in our common shares issued for the years ended December 31, 2019 , 2018 and 2017 is detailed below: Years Ended December 31, 2019 2018 2017 (in thousands) Shares issued as of January 1 913,716 908,733 896,279 Common shares issued for WildHorse Merger (a) 717,376 — — Exchange of senior notes (b) 235,564 — — Exchange of convertible notes (b) 73,389 — — Exchange of preferred stock 10,368 — 9,966 Restricted stock issuances (net of forfeitures and cancellations) (c) 4,146 4,983 2,488 Shares issued as of December 31 1,954,559 913,716 908,733 ___________________________________________ (a) See Note 3 for discussion of WildHorse Merger. (b) See Note 5 for discussion of debt exchanges. (c) See Note 12 for discussion of restricted stock. During the year ended December 31, 2019, our shareholders approved a proposal to amend our restated certificate of incorporation to increase the number of authorized shares of our common stock from 2,000,000,000 shares to 3,000,000,000 shares. Preferred Stock Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2019: Preferred Stock Series Issue Date Liquidation Preference per Share Holder's Conversion Right Conversion Rate Conversion Price Company's Conversion Right From Company's Market Conversion Trigger (a) 5.75% cumulative convertible non-voting May and June 2010 $ 1,000 Any time 39.6858 $ 25.1979 May 17, 2015 $ 32.7573 5.75% (series A) cumulative convertible non-voting May 2010 $ 1,000 Any time 38.3508 $ 26.0751 May 17, 2015 $ 33.8976 4.50% cumulative convertible September 2005 $ 100 Any time 2.4561 $ 40.7152 September 15, 2010 $ 52.9298 5.00% cumulative convertible (series 2005B) November 2005 $ 100 Any time 2.7745 $ 36.0431 November 15, 2010 $ 46.8560 ___________________________________________ (a) Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding. Outstanding shares of our preferred stock for the years ended December 31, 2019, 2018 and 2017 are detailed below: 5.75% 5.75% (Series A) 4.50% 5.00% (Series 2005B) (in thousands) Shares outstanding as of January 1, 2019 770 463 2,559 1,811 Preferred stock exchanges (a) — (40 ) — — Shares outstanding as of December 31, 2019 770 423 2,559 1,811 Shares outstanding as of January 1, 2018 770 463 2,559 1,811 Shares outstanding as of January 1, 2017 843 476 2,559 1,962 Preferred stock exchanges (b) (73 ) (13 ) — (151 ) Shares outstanding as of December 31, 2017 770 463 2,559 1,811 ____________________________________________ (a) During 2019, we exchanged 10,367,950 shares of common stock for 40,000 shares of our 5.75% (Series A) Cumulative Convertible Preferred Stock. In connection with the exchange, we recognized a loss equal to the excess of the fair value of all common stock issued in exchange for the preferred stock over the fair value of the common stock issuable pursuant to the original terms of the preferred stock. The loss of $17 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share. (b) During 2017, holders of our 5.75% Cumulative Convertible Preferred Stock exchanged 72,600 shares into 7,442,156 shares of common stock, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock exchanged 12,500 shares into 1,205,923 shares of common stock and holders of our 5.00% (Series 2005B) Cumulative Convertible Preferred Stock exchanged 150,948 shares into 1,317,756 shares of common stock. In connection with the exchanges, we recognized a loss equal to the excess of the fair value of all common stock issued in exchange for the preferred stock over the fair value of the common stock issuable pursuant to the original terms of the preferred stock. The loss of $41 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share. Dividends Dividends declared on our preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, payments are reflected in our financial statements as a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital. Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash. In January 2016, we suspended dividend payments on our convertible preferred stock to provide additional liquidity in the depressed commodity price environment. In the first quarter of 2017, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock and paid our dividends in arrears. Accumulated Other Comprehensive Income (Loss) For the years ended December 31, 2019 and 2018, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below: Years Ended December 31, 2019 2018 ($ in millions) Balance, as of January 1 $ (23 ) $ (57 ) Amounts reclassified from accumulated other comprehensive income (a) 35 34 Balance, as of December 31 $ 12 $ (23 ) ___________________________________________ (a) Net losses on cash flow hedges for commodity contracts reclassified from accumulated other comprehensive income (loss), net of tax, to oil, natural gas and NGL revenues in the consolidated statements of operations. Noncontrolling Interests Chesapeake Granite Wash Trust. We own 23,750,000 common units in the Chesapeake Granite Wash Trust (the Trust) representing a 51% beneficial interest. We have determined that the Trust is a VIE and that we are the primary beneficiary. As a result, the Trust is included in our consolidated financial statements. As of December 31, 2019, and 2018, we had $37 million and $41 million , respectively, of noncontrolling interests on our consolidated balance sheets attributable to the Trust. There was no minal net income attributable to the Trust’s noncontrolling interest in 2019. Net income attributable to the Trust’s noncontrolling interest was $2 million and $3 million for the years ended December 31, 2018 and 2017, respectively. The Trust’s legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake. We have presented parenthetically on the face of the consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Share-Based Compensation	Share-Based Compensation Our share-based compensation program consists of restricted stock, stock options, performance share units (PSUs) and cash restricted stock units (CRSUs) granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. The restricted stock and stock options are equity-classified awards and the PSUs and CRSUs are liability-classified awards. Share-Based Compensation Plans 2014 Long Term Incentive Plan . Our 2014 Long Term Incentive Plan (2014 LTIP), which is administered by the Compensation Committee of our Board of Directors, became effective on June 13, 2014 after it was approved by shareholders at our 2014 Annual Meeting. The 2014 LTIP replaced our Amended and Restated Long Term Incentive Plan which was adopted in 2005. The 2014 LTIP provides for up to 71,600,000 shares of common stock that may be issued as long-term incentive compensation to our employees and non-employee directors; provided, however, that the 2014 LTIP uses a fungible share pool under which (i) each share issued pursuant to a stock option or stock appreciation right (SAR) reduces the number of shares available under the 2014 LTIP by 1.0 share; (ii) each share issued pursuant to awards other than options and SARs reduces the number of shares available by 2.12 shares; (iii) if any awards of restricted stock under the 2014 LTIP, or its predecessor plan, are forfeited, expire, are settled for cash, or are tendered by the participant or withheld by us to satisfy any tax withholding obligation, then the shares subject to the award may be used again for awards; and (iv) PSUs and other performance awards which are payable solely in cash are not counted against the aggregate number of shares issuable. In addition, the 2014 LTIP prohibits the reuse of shares withheld or delivered to satisfy the exercise price of, or to satisfy tax withholding requirements for, an option or SAR. The 2014 LTIP also prohibits “net share counting” upon the exercise of options or SARs. The 2014 LTIP authorizes the issuance of the following types of awards: (i) nonqualified and incentive stock options; (ii) SARs; (iii) restricted stock; (iv) performance awards, including PSUs; and (v) other stock-based awards. For both stock options and SARs, the exercise price may not be less than the fair market value of our common stock on the date of grant and the maximum exercise period may not exceed ten years from the date of grant. Awards granted under the plan vest at specified dates and/or upon the satisfaction of certain performance or other criteria, as determined by the Compensation Committee. As of December 31, 2019 , 29,865,514 shares of common stock remained issuable under the 2014 LTIP. Equity-Classified Awards Restricted Stock. We grant restricted stock to employees and non-employee directors. A summary of the changes in unvested restricted stock during 2019 , 2018 and 2017 is presented below: Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Unvested restricted stock as of January 1, 2019 11,858 $ 4.43 Granted 5,908 $ 2.65 Vested (5,944 ) $ 4.38 Forfeited (1,380 ) $ 3.72 Unvested restricted stock as of December 31, 2019 10,442 $ 3.55 Unvested restricted stock as of January 1, 2018 13,178 $ 6.37 Granted 6,067 $ 3.73 Vested (5,808 ) $ 7.67 Forfeited (1,579 ) $ 6.02 Unvested restricted stock as of December 31, 2018 11,858 $ 4.43 Unvested restricted stock as of January 1, 2017 9,092 $ 11.39 Granted 9,872 $ 5.40 Vested (4,573 ) $ 13.73 Forfeited (1,213 ) $ 8.32 Unvested restricted stock as of December 31, 2017 13,178 $ 6.37 The aggregate intrinsic value of restricted stock that vested during 2019 was approximately $15 million based on the stock price at the time of vesting. As of December 31, 2019 , there was approximately $19 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 1.92 years. Stock Options. In 2019 , 2018 and 2017 , we granted members of management stock options that vest ratably over a three-year period. Each stock option award has an exercise price equal to the closing price of our common stock on the grant date. Outstanding options expire seven years to ten years from the date of grant. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method. Volatility assumptions are estimated based on the average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account our dividend policy, over the expected life of the option. We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2019: Expected option life – years 6.0 Volatility 65.61 % Risk-free interest rate 2.47 % Dividend yield — % The following table provides information related to stock option activity for 2019 , 2018 and 2017 : Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Contract Life in Years Aggregate Intrinsic Value (a) (in thousands) ($ in millions) Outstanding as of January 1, 2019 18,096 $ 7.20 7.15 $ — Granted 1,000 $ 2.97 Exercised — $ — $ — Expired (553 ) $ 6.36 Forfeited (609 ) $ 3.97 Outstanding as of December 31, 2019 17,934 $ 7.10 5.70 $ — Exercisable as of December 31, 2019 13,092 $ 8.28 4.86 $ — Outstanding as of January 1, 2018 16,285 $ 8.25 7.73 $ 1 Granted 3,611 $ 3.01 Exercised — $ — $ — Expired (602 ) $ 13.83 Forfeited (1,198 ) $ 5.45 Outstanding as of December 31, 2018 18,096 $ 7.20 7.15 $ — Exercisable as of December 31, 2018 8,250 $ 10.73 5.73 $ — Outstanding as of January 1, 2017 8,593 $ 11.88 7.22 $ 14 Granted 9,226 $ 5.45 Exercised — $ — $ — Expired (435 ) $ 18.50 Forfeited (1,099 ) $ 9.12 Outstanding as of December 31, 2017 16,285 $ 8.25 7.73 $ 1 Exercisable as of December 31, 2017 4,474 $ 15.15 5.26 $ — ___________________________________________ (a) The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option. As of December 31, 2019 , there was $5 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.23 years , net of actual forfeitures. Restricted Stock and Stock Option Compensation. We recognized the following compensation costs, net of actual forfeitures, related to restricted stock and stock options for the years ended December 31, 2019 , 2018 and 2017 : Years Ended December 31, 2019 2018 2017 ($ in millions) General and administrative expenses $ 26 $ 31 $ 43 Oil and natural gas properties 2 2 5 Oil, natural gas and NGL production expenses 3 5 12 Exploration expenses 1 1 1 Total restricted stock and stock option compensation $ 32 $ 39 $ 61 Liability-Classified Awards Performance Share Units. We granted PSUs to senior management that vest ratably over a three-year performance period and are settled in cash. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors. Compensation expense associated with PSU awards is recognized over the service period based on the graded-vesting method. The value of the PSU awards at the end of each reporting period is dependent upon our estimates of the underlying performance measures. For PSUs granted in 2017, performance metrics include a total shareholder return (TSR) component, which can range from 0% to 100% and an operational performance component based on finding and development costs, which can range from 0% to 100% , resulting in a maximum payout of 200% . The payout percentage for the 2017 PSU awards is capped at 100% if our absolute TSR is less than zero . The PSUs are settled in cash on the third anniversary of the awards. The performance period for the 2017 awards ended on December 31, 2019. For PSUs granted in 2018 and 2019, performance metrics include an operational performance component based on a ratio of cumulative earnings before interest expense, income taxes, and depreciation, depletion and amortization expense (EBITDA) to capital expenditures, for which payout can range from 0% to 200% . For the 2019 award, EBITDA and capital expenditures will be adjusted for changes resulting from our conversion from the full cost method of accounting to the successful efforts method. The vested PSUs are settled in cash on each of the three annual vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the PSUs. The PSU liability will be adjusted quarterly, based on changes in our stock price and expected satisfaction of performance metrics, through the end of each performance period. Cash Restricted Stock Units . In 2018, we granted CRSUs to employees that vest straight-line over a three-year period and are settled in cash on each of the three annual vesting dates. The ultimate amount earned is based on the closing price of our common stock on each of the vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the CRSUs. The CRSU liability will be adjusted quarterly, based on changes in our stock price, through the end of the vesting period. The following table presents a summary of our liability-classified awards: Grant Date Fair Value December 31, 2019 Units Fair Value Vested Liability ($ in millions) ($ in millions) 2019 PSU Awards: Payable 2020, 2021 and 2022 4,674,503 $ 14 $ 4 $ — 2018 PSU Awards: Payable 2020 and 2021 2,340,157 $ 7 $ 2 $ — 2017 PSU Awards: Payable 2020 1,174,973 $ 8 $ 1 $ — 2018 CRSU Awards: Payable 2020 and 2021 8,233,207 $ 25 $ 7 $ — We recognized the following compensation costs (credits), net of actual forfeitures, related to our liability-classified awards for the years ended December 31, 2019 , 2018 and 2017 : Years Ended December 31, 2019 2018 2017 ($ in millions) General and administrative expenses $ 5 $ 9 $ (4 ) Oil and natural gas properties 1 1 — Oil, natural gas and NGL production expenses 3 2 — Restructuring and other termination costs 1 — — Total liability-classified awards compensation $ 10 $ 12 $ (4 )

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Employee Benefit Plans	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 15% of an employee's base salary and performance bonus) in cash. We contributed $29 million , $31 million and $35 million to the 401(k) Plan in 2019 , 2018 and 2017 , respectively. We also maintained a nonqualified deferred compensation plan (DC Plan) which we terminated in January 2020 in accordance with its terms. To be eligible to participate in the DC Plan, an active employee must have had a base salary of at least $150,000 , had a hire date on or before December 1, immediately preceding the year in which the employee was able to participate, or be designated as eligible to participate. We matched 100% of employee contributions up to 15% of base salary and performance bonus in the aggregate for the DC Plan with Chesapeake common stock, and an employee who was at least age 55 may have elected for the matching contributions to be made in any one of the DC Plan’s investment options. The maximum compensation that could have been deferred by employees under all of our deferred compensation plans, including the Chesapeake 401(k) Plan, was a total of 75% of base salary and 75% of performance bonus. The participant chose separate deferral election percentages for both plans. We contributed $7 million , $7 million and $8 million to the DC Plan during 2019 , 2018 and 2017 , respectively, to fund the match. The deferred compensation company match of 15% had a five-year vesting schedule based on years of service. Any participant who was active on December 31 of the plan year received the deferred compensation company match which was awarded on an annual basis.

Derivative and Hedging Activiti

Derivative and Hedging Activities	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative and Hedging Activities	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 oil, natural gas and NGL 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 oil, natural gas and NGL derivative instruments were designated for hedge accounting as of December 31, 2019 and 2018 . Oil, Natural Gas and NGL Derivatives As of December 31, 2019 , and 2018 , our oil, natural gas and NGL 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 call swaptions. • Options : We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party. • Call Swaptions : We sell call swaptions to counterparties in exchange for a premium. Swaptions allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap. • 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 include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates 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. The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of December 31, 2019 and 2018 are provided below: December 31, 2019 December 31, 2018 Notional Volume Fair Value Notional Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 24 $ (7 ) 12 $ 157 Collars 2 14 8 98 Basis protection swaps 8 (2 ) 7 5 Total oil 34 5 27 260 Natural gas (bcf): Fixed-price swaps 265 125 623 26 Three-way collars — — 88 1 Collars — — 55 (3 ) Call options 22 — 44 — Call swaptions 29 (2 ) 106 (9 ) Basis protection swaps 30 2 50 — Total natural gas 346 125 966 15 Contingent Consideration: Utica divestiture — 7 Total estimated fair value $ 130 $ 282 We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. See further discussion below under Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss) . Contingent Consideration Arrangements In 2018, we sold our Utica Shale position to Encino. The agreement includes additional contingent payments to us of up to $100 million comprised of $50 million in consideration in each case if, on or prior to December 31, 2019, there is a period of twenty ( 20 ) trading days out of a period of thirty ( 30 ) consecutive trading days where (i) the average of the NYMEX natural gas strip prices for the months comprising the year 2022 equals or exceeds $3.00 /mmbtu as calculated pursuant to the purchase agreement, and (ii) the average of the NYMEX natural gas strip price for the months comprising the year 2023 equals or exceeds $3.25 /mmbtu as calculated pursuant to the purchase agreement. The contingent consideration expired on December 31, 2019 with no value attributed to the arrangement. See Note 3 for further details regarding the transaction. Foreign Currency Derivatives During 2017, both our 6.25% Euro-denominated Senior Notes due 2017 and cross currency swaps for the same principal amount matured. Upon maturity of the notes, the counterparties paid us €246 million and we paid the counterparties $327 million . The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. The swaps were designated as cash flow hedges and, because they were entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value did not impact earnings. Effect of Derivative Instruments – Consolidated Balance Sheets The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2019 , and 2018 on a gross basis and after same-counterparty netting: Balance Sheet Classification Gross Fair Value Amounts Netted in the Consolidated Balance Sheets Net Fair Value Presented in the Consolidated Balance Sheets ($ in millions) As of December 31, 2019 Commodity Contracts: Short-term derivative asset $ 174 $ (40 ) $ 134 Short-term derivative liability (42 ) 40 (2 ) Long-term derivative liability (2 ) — (2 ) Total derivatives $ 130 $ — $ 130 As of December 31, 2018 Commodity Contracts: Short-term derivative asset $ 306 $ (104 ) $ 202 Long-term derivative asset 117 (41 ) 76 Short-term derivative liability (107 ) 104 (3 ) Long-term derivative liability (41 ) 41 — Contingent Consideration: Short-term derivative asset 7 — 7 Total derivatives $ 282 $ — $ 282 As of December 31, 2019 and 2018 , we did no t have any cash collateral balances for these derivatives. Effect of Derivative Instruments – Consolidated Statements of Operations The components of oil, natural gas and NGL revenues for the years ended December 31, 2019 , 2018 and 2017 are presented below: Years Ended December 31, 2019 2018 2017 ($ in millions) Oil, natural gas and NGL revenues $ 4,517 $ 5,189 $ 4,574 Gains on undesignated oil, natural gas and NGL derivatives 40 — 445 Losses on terminated cash flow hedges (35 ) (34 ) (34 ) Total oil, natural gas and NGL revenues $ 4,522 $ 5,155 $ 4,985 The components of marketing revenues for the years ended December 31, 2019 , 2018 and 2017 are presented below: Years Ended December 31, 2019 2018 2017 ($ in millions) Marketing revenues $ 3,971 $ 5,069 $ 4,511 Gains (losses) on undesignated marketing natural gas derivatives (4 ) 7 — Total marketing revenues $ 3,967 $ 5,076 $ 4,511 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: Years Ended December 31, 2019 2018 2017 Before After Before After Before After ($ in millions) Balance, beginning of period $ (80 ) $ (23 ) $ (114 ) $ (57 ) $ (153 ) $ (96 ) Net change in fair value — — — — 5 5 Losses reclassified to income 35 35 34 34 34 34 Balance, end of period $ (45 ) $ 12 $ (80 ) $ (23 ) $ (114 ) $ (57 ) The accumulated other comprehensive loss as of December 31, 2019 represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. Remaining deferred gain or loss amounts will be recognized in earnings in the month for which the original contract months are to occur. As we early adopted ASU 2019-12 in the current period, the tax effect will be recognized in earnings in the year ended December 31, 2022. As of December 31, 2019 , we expect to transfer approximately $33 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022. Credit Risk Considerations Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only 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, 2019 , our oil, natural gas and NGL derivative instruments were spread among 10 counterparties. Hedging Arrangements Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under the Chesapeake revolving credit facility. The contracts entered into with these counterparties are secured by the same collateral that secures the Chesapeake revolving credit facility. In addition, we enter into bilateral hedging agreements with other counterparties. The counterparties’ and our obligations under the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds. As of December 31, 2019 , we did not have any cash or letters of credit posted as collateral for our commodity derivatives. Fair Value The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil, natural gas and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas and NGL swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. 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 following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2019 and 2018 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2019 Derivative Assets (Liabilities): Commodity assets $ — $ 160 $ 14 $ 174 Commodity liabilities — (42 ) (2 ) (44 ) Total derivatives $ — $ 118 $ 12 $ 130 As of December 31, 2018 Derivative Assets (Liabilities): Commodity assets $ — $ 319 $ 103 $ 422 Commodity liabilities — (131 ) (16 ) (147 ) Utica divestiture contingent consideration — — 7 7 Total derivatives $ — $ 188 $ 94 $ 282 A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during 2019 and 2018 is presented below: Commodity Derivatives Utica Contingent Consideration ($ in millions) Balance, as of January 1, 2019 $ 87 $ 7 Total gains (losses) (realized/unrealized): Included in earnings (a) (59 ) (7 ) Total purchases, issuances, sales and settlements: Settlements (16 ) — Balance, as of December 31, 2019 $ 12 $ — Balance, as of January 1, 2018 $ (15 ) $ — Total gains (losses) (realized/unrealized): Included in earnings (a) 77 7 Total purchases, issuances, sales and settlements: Settlements 25 — Balance, as of December 31, 2018 $ 87 $ 7 ___________________________________________ (a) Commodity Derivatives Utica Contingent Consideration 2019 2018 2019 2018 ($ in millions) Total gains (losses) included in earnings for the period $ (59 ) $ 77 $ (7 ) $ 7 Change in unrealized gains (losses) related to assets still held at reporting date $ (19 ) $ 86 $ — $ 7 Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements The significant unobservable inputs for Level 3 derivative contracts include market volatility. Changes in market volatility impact the fair value measurement of our derivative contracts, which is based on an estimate derived from option models. For example, an increase or decrease in the forward prices and volatility of oil and natural gas prices decreases or increases the fair value of oil and natural gas derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts as of December 31, 2019 : Instrument Type Unobservable Input Range Weighted Average Fair Value ($ in millions) Oil trades Oil price volatility curves 20.71% – 67.28% 25.62% $ 14 Natural gas trades Natural gas price volatility curves 16.93% – 171.49% 39.67% $ (2 )

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Recurring Fair Value Measurements Other Current Assets. Assets related to our deferred compensation plan are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities. Other Current Liabilities . Liabilities related to our deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds. Financial Assets (Liabilities) . The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2019 and 2018: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2019 Financial Assets (Liabilities): Other current assets $ 42 $ — $ — $ 42 Other current liabilities (43 ) — — (43 ) Total $ (1 ) $ — $ — $ (1 ) As of December 31, 2018 Financial Assets (Liabilities): Other current assets $ 50 $ — $ — $ 50 Other current liabilities (51 ) — — (51 ) Total $ (1 ) $ — $ — $ (1 ) See Note 5 for information regarding fair value measurement of our debt instruments. See Note 14 for information regarding fair value measurement of our derivatives.

Capitalized Exploratory Well Co

Capitalized Exploratory Well Costs	12 Months Ended
	Dec. 31, 2019
Extractive Industries [Abstract]
Capitalized Exploratory Well Costs	Capitalized Exploratory Well Costs A summary of the changes in our capitalized well costs for the years ended December 31, 2019 , 2018 and 2017 is detailed below. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. 2019 2018 2017 (in millions) Balance as of January 1 $ 36 $ 36 $ 41 Additions pending the determination of proved reserves 7 74 14 Divestitures and other (3 ) — — Reclassifications to proved properties (17 ) (40 ) (19 ) Charges to exploration expense (16 ) (34 ) — Balance as of December 31 $ 7 $ 36 $ 36 The following table provides an aging of capitalized costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. 2019 2018 2017 (in millions) Exploratory well costs capitalized for a period of one year or less $ 7 $ 34 $ 4 Exploratory well costs capitalized for a period greater than one year — 2 32 Balance as of December 31 $ 7 $ 36 $ 36 Number of projects with exploratory well costs capitalized for a period greater than one year — 7 6

Other Property and Equipment

Other Property and Equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Other Property and Equipment	Other Property and Equipment Other Property and Equipment A summary of other property and equipment held for use and the estimated useful lives thereof is as follows: December 31, Estimated Useful Life 2019 2018 ($ in millions) (in years) Buildings and improvements $ 1,058 $ 1,053 10 – 39 Computer equipment 355 353 5 Sand mine 78 — 10 – 30 Natural gas compressors (a) 48 48 3 – 20 Land 115 106 Other 156 161 5 – 20 Total other property and equipment, at cost 1,810 1,721 Less: accumulated depreciation (692 ) (630 ) Total other property and equipment, net $ 1,118 $ 1,091 ___________________________________________ (a) Includes assets under finance lease of $27 million , less accumulated depreciation of $10 million and $1 million , as of December 31, 2019 and 2018 , respectively. The related amortization expense for assets under finance lease is included in depreciation, depletion and amortization expense on our consolidated statement of operations.

Investments

Investments	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Investments	Investments FTS International, Inc. (NYSE: FTSI) . In 2018, FTS International, Inc. completed an initial public offering. Due to the offering, the ownership percentage of our equity method investment in FTSI decreased from approximately 29% to 24% and resulted in a gain of $78 million . In addition, we sold approximately 4.3 million shares of FTSI in the offering for net proceeds of approximately $74 million and recognized a gain of $61 million decreasing our ownership percentage to approximately 20% . We continue to hold approximately 22.0 million shares in the publicly traded company. In 2019, the hydraulic fracturing industry experienced challenging operating conditions resulting in the current fair value of our investment in FTSI falling below book value of $65 million and remaining below that amount as of the end of the year. Based on FTSI’s 2019 operating results and FTSI’s share price of $1.04 per share as of December 31, 2019, we determined that the reduction in fair value is other-than-temporary, and recognized an impairment of our investment in FTSI of approximately $43 million . We will continue to monitor the hydraulic fracturing industry, FTSI operating results and FTSI share price for indicators that the reduction in fair value is other-than-temporary, which could result in an additional impairment of our investment in FTSI. JWH Midstream LLC (JWH). In 2019, in connection with the acquisition of WildHorse, we obtained a 50% membership interest in JWH Midstream LLC (JWH). The carrying value of our investment in JWH, which was being accounted for as an equity method investment, was approximately $17 million . In 2019, we paid approximately $7 million to terminate our involvement in the partnership. This removed us from any future obligations related to this joint venture and, therefore, we impaired the full value of the investment and recognized approximately $24 million of impairment expense in 2019.

Impairments

Impairments	12 Months Ended
	Dec. 31, 2019
Asset Impairment Charges [Abstract]
Impairments	Impairments Impairments of Oil and Natural Gas Properties A summary of our impairments of oil and natural gas properties for the years ended December 31, 2019 , 2018 and 2017 is as follows: Years Ended December 31, 2019 2018 2017 ($ in millions) Impairments due to lower forecasted commodity prices $ 8 $ 23 $ 27 Impairments due to reduction in future development (a) — — 560 Impairments due to anticipated sale — 55 222 Total impairments of oil and natural gas properties $ 8 $ 78 $ 809 ____________________________________________ (a) The impairment was the result of an updated development plan in 2017, which included a removal of PUDs from properties in the process of being divested in the Mid-Continent operating area. Impairments of Fixed Assets A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2019 , 2018 and 2017 is as follows: Years Ended December 31, 2019 2018 2017 ($ in millions) Natural gas compressors (a) $ — $ 45 $ — Buildings and land 1 4 5 Other 2 4 — Total impairments of fixed assets and other $ 3 $ 53 $ 5 ____________________________________________ (a) In 2018, we recorded a $45 million impairment related to 890 compressors for the difference between carrying value and the fair value of the assets.

Other Operating Expense

Other Operating Expense	12 Months Ended
	Dec. 31, 2019
Asset Impairment Charges [Abstract]
Other Operating Expense	Other Operating Expense In 2019, we recorded approximately $37 million of costs related to our acquisition of WildHorse which consisted of consulting fees, financial advisory fees, legal fees and travel and lodging expenses. In addition, we recorded approximately $38 million of severance expense as a result of the acquisition of WildHorse. A majority of the WildHorse executives and employees were terminated on the date of acquisition. These executives and employees were entitled to severance benefits in accordance with existing employment agreements. In 2017, we terminated future natural gas transportation commitments related to divested assets for cash payments of $126 million . Also, in 2017, we paid $290 million

Restructuring and Other Termina

Restructuring and Other Termination Costs	12 Months Ended
	Dec. 31, 2019
Restructuring and Related Activities [Abstract]
Restructuring and Other Termination Costs	Restructuring and Other Termination Costs Workforce Reductions In 2019, we incurred a charge of $12 million related to one-time termination benefits for certain employees. In 2018, we underwent a reduction in workforce impacting approximately 13% of employees across all functions, primarily on our Oklahoma City campus. In connection with the reduction, we incurred a total charge of approximately $38 million

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The components of the change in our asset retirement obligations are shown below: Years Ended December 31, 2019 2018 ($ in millions) Asset retirement obligations, beginning of period $ 166 $ 177 Additions (a) 21 3 Revisions 18 11 Settlements and disposals (5 ) (35 ) Accretion expense 11 10 Asset retirement obligations, end of period 211 166 Less current portion 11 11 Asset retirement obligation, long-term $ 200 $ 155 ___________________________________________ (a) During 2019, approximately $17 million of additions relate to the acquisition of WildHorse.

Major Customers

Major Customers	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Major Customers	Major Customers Sales to Valero Energy Corporation constituted approximately 12% and 10% of total revenues (before the effects hedging for the years ended December 31, 2019 and 2018, respectively. Sales to Royal Dutch Shell PLC constituted approximately 10% of total revenues (before the effects of hedging) for the year ended December 31, 2017. No other purchasers accounted for more than 10% of our total revenues in 2019, 2018 or 2017.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Our equity method investees are considered related parties. Hydraulic fracturing and other services are provided to us in the ordinary course of business by our equity affiliate FTSI. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs. For the years ended December 31, 2019, 2018 and 2017, our expenditures for hydraulic fracturing services with FTSI were nominal , $93 million and $111 million , respectively.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Condensed Consolidating Financial Information	Condensed Consolidating Financial Information Chesapeake Energy Corporation is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under the revolving credit facility, term loan, senior secured second lien notes, and outstanding senior unsecured notes and convertible senior notes listed in Note 5 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries. Our BVL subsidiaries are guarantors of our obligations under the revolving credit facility, term loan and senior secured second lien notes, but are not guarantors of our obligations under our outstanding senior unsecured notes or convertible senior notes as of December 31, 2019. Chesapeake has an obligation and intends to add our BVL subsidiaries as guarantors of our obligations under such notes on or before June 20, 2020 in accordance with the various indentures governing the same. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors. The tables below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries, including BVL subsidiaries, as of December 31, 2019 and 2018 and for the years ended December 31, 2019 , 2018 and 2017 . This financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities. CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2019 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 16 $ 1 $ 5 $ (16 ) $ 6 Other current assets 51 1,090 104 — 1,245 Intercompany receivable, net 7,702 — — (7,702 ) — Total Current Assets 7,769 1,091 109 (7,718 ) 1,251 PROPERTY AND EQUIPMENT: Oil and natural gas properties at cost, based on successful efforts accounting, net — 9,440 4,188 — 13,628 Other property and equipment, net — 1,030 88 — 1,118 Property and equipment held for sale, net — 10 — — 10 Total Property and Equipment, Net — 10,480 4,276 — 14,756 LONG-TERM ASSETS: Other long-term assets 41 125 19 1 186 Investments in subsidiaries and intercompany advances 6,101 4,171 — (10,272 ) — TOTAL ASSETS $ 13,911 $ 15,867 $ 4,404 $ (17,989 ) $ 16,193 CURRENT LIABILITIES: Current liabilities $ 466 $ 1,765 $ 176 $ (15 ) $ 2,392 Intercompany payable, net — 7,702 — (7,702 ) — Total Current Liabilities 466 9,467 176 (7,717 ) 2,392 LONG-TERM LIABILITIES: Long-term debt, net 9,071 — 2 — 9,073 Deferred income tax liabilities 10 — — — 10 Other long-term liabilities — 299 18 — 317 Total Long-Term Liabilities 9,081 299 20 — 9,400 EQUITY: Chesapeake stockholders’ equity 4,364 6,101 4,171 (10,272 ) 4,364 Noncontrolling interests — — 37 — 37 Total Equity 4,364 6,101 4,208 (10,272 ) 4,401 TOTAL LIABILITIES AND EQUITY $ 13,911 $ 15,867 $ 4,404 $ (17,989 ) $ 16,193 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2018 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 4 $ 1 $ 1 $ (2 ) $ 4 Other current assets 60 1,532 2 — 1,594 Intercompany receivable, net 6,671 — — (6,671 ) — Total Current Assets 6,735 1,533 3 (6,673 ) 1,598 PROPERTY AND EQUIPMENT: Oil and natural gas properties at cost, based on successful efforts accounting, net — 9,664 48 — 9,712 Other property and equipment, net — 1,091 — — 1,091 Property and equipment held for sale, net — 15 — — 15 Total Property and Equipment, Net — 10,770 48 — 10,818 LONG-TERM ASSETS: Other long-term assets 26 293 — — 319 Investments in subsidiaries and intercompany advances 3,248 9 — (3,257 ) — TOTAL ASSETS $ 10,009 $ 12,605 $ 51 $ (9,930 ) $ 12,735 CURRENT LIABILITIES: Current liabilities $ 523 $ 2,365 $ 1 $ (2 ) $ 2,887 Intercompany payable, net — 6,671 — (6,671 ) — Total Current Liabilities 523 9,036 1 (6,673 ) 2,887 LONG-TERM LIABILITIES: Long-term debt, net 7,341 — — — 7,341 Other long-term liabilities 53 321 — — 374 Total Long-Term Liabilities 7,394 321 — — 7,715 EQUITY: Chesapeake stockholders’ equity 2,092 3,248 9 (3,257 ) 2,092 Noncontrolling interests — — 41 — 41 Total Equity 2,092 3,248 50 (3,257 ) 2,133 TOTAL LIABILITIES AND EQUITY $ 10,009 $ 12,605 $ 51 $ (9,930 ) $ 12,735 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2019 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES AND OTHER: Oil, natural gas and NGL $ — $ 3,760 $ 762 $ — $ 4,522 Marketing — 3,967 — — 3,967 Total Revenues — 7,727 762 — 8,489 Other — 60 3 — 63 Gains on sales of assets — 43 — — 43 Total Revenues and Other — 7,830 765 — 8,595 OPERATING EXPENSES: Oil, natural gas and NGL production — 436 84 — 520 Oil, natural gas and NGL gathering, processing and transportation — 1,062 20 — 1,082 Severance and ad valorem taxes — 174 50 — 224 Exploration — 77 7 — 84 Marketing — 4,003 — — 4,003 General and administrative 1 237 77 — 315 Restructuring and other termination costs — 12 — — 12 Provision for legal contingencies, net — 19 — — 19 Depreciation, depletion and amortization — 1,719 545 — 2,264 Impairments — 11 — — 11 Other operating expense — 52 40 — 92 Total Operating Expenses 1 7,802 823 — 8,626 INCOME (LOSS) FROM OPERATIONS (1 ) 28 (58 ) — (31 ) OTHER INCOME (EXPENSE): Interest income (expense) (598 ) 16 (69 ) — (651 ) Losses on investments — (47 ) (24 ) — (71 ) Gains on purchases or exchanges of debt 65 — 10 — 75 Other income — 39 — — 39 Equity in net earnings (losses) of subsidiary (105 ) (141 ) — 246 — Total Other Expense (638 ) (133 ) (83 ) 246 (608 ) LOSS BEFORE INCOME TAXES (639 ) (105 ) (141 ) 246 (639 ) INCOME TAX BENEFIT (331 ) — — — (331 ) NET LOSS (308 ) (105 ) (141 ) 246 (308 ) Net income attributable to noncontrolling interests — — — — — NET LOSS ATTRIBUTABLE TO CHESAPEAKE (308 ) (105 ) (141 ) 246 (308 ) Other comprehensive income — 35 — — 35 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (308 ) $ (70 ) $ (141 ) $ 246 $ (273 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2018 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES AND OTHER: Oil, natural gas and NGL $ — $ 5,136 $ 19 $ — $ 5,155 Marketing — 5,076 — — 5,076 Total Revenues — 10,212 19 — 10,231 Other — 63 — — 63 Losses on sales of assets — (264 ) — — (264 ) Total Revenues and Other — 10,011 19 — 10,030 OPERATING EXPENSES: Oil, natural gas and NGL production — 474 — — 474 Oil, natural gas and NGL gathering, processing and transportation — 1,391 7 — 1,398 Severance and ad valorem taxes — 188 1 — 189 Exploration — 162 — — 162 Marketing — 5,158 — — 5,158 General and administrative 2 332 1 — 335 Restructuring and other termination costs — 38 — — 38 Provision for legal contingencies, net — 26 — — 26 Depreciation, depletion and amortization — 1,730 7 — 1,737 Impairments — 131 — — 131 Total Operating Expenses 2 9,630 16 — 9,648 INCOME (LOSS) FROM OPERATIONS (2 ) 381 3 — 382 OTHER INCOME (EXPENSE): Interest expense (631 ) (2 ) — — (633 ) Gains on investments — 139 — — 139 Gains on purchases or exchanges of debt 263 — — — 263 Other income 3 64 — — 67 Equity in net earnings of subsidiary 583 1 — (584 ) — Total Other Income (Expense) 218 202 — (584 ) (164 ) INCOME BEFORE INCOME TAXES 216 583 3 (584 ) 218 INCOME TAX BENEFIT (10 ) — — — (10 ) NET INCOME 226 583 3 (584 ) 228 Net income attributable to noncontrolling interests — — (2 ) — (2 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 226 583 1 (584 ) 226 Other comprehensive income — 34 — — 34 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 226 $ 617 $ 1 $ (584 ) $ 260 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES AND OTHER: Oil, natural gas and NGL $ — $ 4,962 $ 23 $ — $ 4,985 Marketing — 4,511 — — 4,511 Total Revenues — 9,473 23 — 9,496 Other — 67 — — 67 Gains on sales of assets — 476 — — 476 Total Revenues and Other — 10,016 23 — 10,039 OPERATING EXPENSES: Oil, natural gas and NGL production — 517 — — 517 Oil, natural gas and NGL gathering, processing and transportation — 1,463 8 — 1,471 Severance and ad valorem taxes — 133 1 — 134 Exploration — 235 — — 235 Marketing — 4,598 — — 4,598 General and administrative 1 330 2 — 333 Provision for legal contingencies, net (79 ) 41 — — (38 ) Depreciation, depletion and amortization — 1,688 9 — 1,697 Impairments — 814 — — 814 Other operating expense — 416 — — 416 Total Operating (Income) Expenses (78 ) 10,235 20 — 10,177 INCOME (LOSS) FROM OPERATIONS 78 (219 ) 3 — (138 ) OTHER INCOME (EXPENSE): Interest expense (599 ) (2 ) — — (601 ) Gains on purchases or exchanges of debt 233 — — — 233 Other income 1 5 — — 6 Equity in net losses of subsidiary (216 ) — — 216 — Total Other Income (Expense) (581 ) 3 — 216 (362 ) INCOME (LOSS) BEFORE INCOME TAXES (503 ) (216 ) 3 216 (500 ) INCOME TAX EXPENSE 2 — — — 2 NET INCOME (LOSS) (505 ) (216 ) 3 216 (502 ) Net income attributable to noncontrolling interests — — (3 ) — (3 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (505 ) (216 ) — 216 (505 ) Other comprehensive income — 39 — — 39 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (505 ) $ (177 ) $ — $ 216 $ (466 ) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2019 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 1 $ 1,270 $ 356 $ (4 ) $ 1,623 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,548 ) (632 ) — (2,180 ) Business combination, net — (381 ) 28 — (353 ) Acquisitions of proved and unproved properties — (35 ) — — (35 ) Proceeds from divestitures of proved and unproved properties — 130 — — 130 Additions to other property and equipment — (32 ) (16 ) — (48 ) Proceeds from sales of other property and equipment — 6 — — 6 Net Cash Used In Investing Activities — (1,860 ) (620 ) — (2,480 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 9,839 — 837 — 10,676 Payments on revolving credit facility borrowings (8,668 ) — (1,512 ) — (10,180 ) Proceeds from issuance of senior notes, net 108 — — — 108 Proceeds from issuance of term loan, net 1,455 — — — 1,455 Cash paid to purchase debt (380 ) — (693 ) — (1,073 ) Cash paid for preferred stock dividends (91 ) — — — (91 ) Contribution from parent (1,644 ) — 1,644 — — Other financing activities (24 ) (8 ) (8 ) 4 (36 ) Intercompany advances, net (713 ) 713 — — — Net Cash Provided By (Used In) Financing Activities (118 ) 705 268 4 859 Net increase (decrease) in cash and cash equivalents (117 ) 115 4 — 2 Cash and cash equivalents, beginning of period 4 1 1 (2 ) 4 Cash and cash equivalents, end of period $ (113 ) $ 116 $ 5 $ (2 ) $ 6 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2018 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 85 $ 1,642 $ 10 $ (7 ) $ 1,730 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,848 ) — — (1,848 ) Acquisitions of proved and unproved properties — (128 ) — — (128 ) Proceeds from divestitures of proved and unproved properties — 2,231 — — 2,231 Additions to other property and equipment — (21 ) — — (21 ) Proceeds from sales of other property and equipment — 147 — — 147 Proceeds from sales of investments — 74 — — 74 Net Cash Provided by Investing Activities — 455 — — 455 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 11,697 — — — 11,697 Payments on revolving credit facility borrowings (12,059 ) — — — (12,059 ) Proceeds from issuance of senior notes, net 1,236 — — — 1,236 Cash paid to purchase debt (2,813 ) — — — (2,813 ) Cash paid for preferred stock dividends (92 ) — — — (92 ) Other financing activities (26 ) (123 ) (13 ) 7 (155 ) Intercompany advances, net 1,971 (1,974 ) 2 1 — Net Cash Used In Financing Activities (86 ) (2,097 ) (11 ) 8 (2,186 ) Net decrease in cash and cash equivalents (1 ) — (1 ) 1 (1 ) Cash and cash equivalents, beginning of period 5 1 2 (3 ) 5 Cash and cash equivalents, end of period $ 4 $ 1 $ 1 $ (2 ) $ 4 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 5 $ 466 $ 14 $ (10 ) $ 475 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (2,113 ) — — (2,113 ) Acquisitions of proved and unproved properties — (88 ) — — (88 ) Proceeds from divestitures of proved and unproved properties — 1,249 — — 1,249 Additions to other property and equipment — (21 ) — — (21 ) Other investing activities — 55 — — 55 Net Cash Used In Investing Activities — (918 ) — — (918 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 7,771 — — — 7,771 Payments on revolving credit facility borrowings (6,990 ) — — — (6,990 ) Proceeds from issuance of senior notes, net 1,585 — — — 1,585 Cash paid to purchase debt (2,592 ) — — — (2,592 ) Cash paid for preferred stock dividends (183 ) — — — (183 ) Other financing activities (39 ) (5 ) (13 ) 32 (25 ) Intercompany advances, net (456 ) 456 — — — Net Cash Provided by (Used In) Financing Activities (904 ) 451 (13 ) 32 (434 ) Net increase (decrease) in cash and cash equivalents (899 ) (1 ) 1 22 (877 ) Cash and cash equivalents, beginning of period 904 2 1 (25 ) 882 Cash and cash equivalents, end of period $ 5 $ 1 $ 2 $ (3 ) $ 5

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On February 24, 2020, we executed agreements to terminate certain gathering, processing and transportation contracts in exchange for consideration of approximately $70 million , comprised of $54 million in cash and $16 million of linefill inventory. During the first quarter of 2020, we will recognize a non-recurring $70 million expense related to the contract termination. Additionally, the contract termination will remove approximately $169 million of future commitments related to gathering, processing and transportation agreements. See Note 6 for further discussion of contingencies and commitments.

Basis of Presentation and Sum_2

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
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.
Recast Financial Information for Change in Accounting Principle	Recast Financial Information for Change in Accounting Principle In the first quarter of 2019, we voluntarily changed our method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods presented herein has been recast to reflect retrospective application of the successful efforts method. Although the full cost method of accounting for oil and natural gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the generally preferred method of the SEC and, because it is more widely used in the industry, we expect the change to improve the comparability of our financial statements to our peers. We also believe the successful efforts method provides a more representational depiction of assets and operating results and provides for our investments in oil and natural gas properties to be assessed for impairment in accordance with Accounting Standards Codification (ASC) Topic 360, Property Plant and Equipment, rather than valuations based on prices and costs prescribed under the full cost method as of the balance sheet date. For detailed information regarding the effects of the change to the successful efforts method, see Note 2 .
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 oil and natural gas properties, oil and natural gas reserves, derivatives, income taxes, unevaluated properties not subject to evaluation, 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. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which we are the primary beneficiary. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. We continually monitor our consolidated VIE to determine if any events have occurred that could cause the primary beneficiary to change. See Note 11 for further discussion of our VIE. 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. Undivided interests in oil and natural gas 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 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, which is exploration and production because our marketing activities are ancillary to our operations.
Noncontrolling Interests	Noncontrolling Interests
Cash and Cash Equivalents and Accounts Payable	Accounts Payable Included in accounts payable as of December 31, 2019 and 2018 are liabilities of approximately $57 million and $104 million , respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Cash and Cash Equivalents
Accounts Receivable	Accounts Receivable
Oil and Gas Natural Properties	Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas 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 oil and natural gas 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 oil and gas 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 oil and natural gas 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 oil and natural gas 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 crude oil and natural gas 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 future production volumes, commodity prices, operating costs, and capital investment plans, 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 discount rate believed to be consistent with those applied by market participants. 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, land, vehicles, computers, sand mine, natural gas compressors under finance lease and office equipment. 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. Natural gas compressors under finance lease are depreciated over the shorter of their estimated useful lives or the term of the related lease.
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 Included in other long-term assets are costs associated with the issuance and amendments of the Chesapeake revolving credit facility. The remaining unamortized issuance costs as of December 31, 2019 and 2018 , totaled $27 million and $30 million , respectively, and are being amortized over the life of the Chesapeake revolving credit facility using the straight-line method. Included in long-term debt are costs associated with the issuance of our senior notes. The remaining unamortized issuance costs as of December 31, 2019 and 2018 , totaled $44 million and $53 million , respectively, and are being amortized over the life of the senior notes using the effective interest method.
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 oil, natural gas and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Prior to the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018, revenue from the sale of oil, natural gas and NGL was recognized when title passed 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 oil, natural gas and NGL production (recorded as oil, natural gas 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 oil, natural gas 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. 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 earn 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, (recorded within oil, natural gas and NGL revenues in the consolidated statements of operations) as well as a variety of oil, natural gas 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).
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, 2019 , 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 twelve 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 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, stock options, performance share units and cash restricted stock units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three years from the grant date. For directors, although restricted stock grants vest over three years , this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units are settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as general and administrative expense in the consolidated statements of operations.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In December 2019, the FASB issued Accounting Standards Update (ASU) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (ASU 2019-12) as part of its initiative to reduce complexity in the accounting standards. The amendments in ASU 2019-12 remove certain exceptions related to the incremental approach for intraperiod tax allocation, the general methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. ASU 2019-12 also clarifies and simplifies other aspects of accounting for income taxes. The amendments in ASU 2019-12 become effective for us for the calendar year ending December 31, 2021; however, early adoption is permissible for periods for which financial statements have not yet been issued. We have decided to early adopt ASU 2019-12 for the calendar year ended December 31, 2019, which will be in effect from the beginning of the 2019 annual period. The early adoption of ASU 2019-12 did not result in a material impact to our balance sheet, results of operations or cash flows. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASC 842”) , which requires lessees to recognize a lease liability and a right-of-use (ROU) asset on the balance sheet for all leases, including operating leases, with terms in excess of 12 months. As the implicit rate of the lease is not always readily determinable, the company uses its incremental borrowing rate to calculate the present value of lease payments based on information available at the commencement date. Operating ROU assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet. Finance ROU assets are reflected in total property and equipment, net, while finance lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet. ASC 842 does not apply to our leases of mineral rights to explore for or use oil and natural gas resources, including the intangible rights to explore for those natural resources and rights to use the land in which those natural resources are contained. We adopted the new standard on January 1, 2019 and as permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements , we did not adjust comparative-period financial statements and continued to apply the guidance in Topic 840, including its disclosure requirements, in the comparative periods presented prior to adoption. No cumulative-effect adjustment to retained earnings was required as a result of the modified retrospective approach. Upon adoption of ASC 842, we made certain elections permitting us to not reassess: (1) whether any expired or existing contracts contained leases (2) the lease classification for any expired or existing leases, and (3) initial direct costs for any existing leases. Upon adoption of ASC 842, we also made an election permitting us to continue applying our current policy for land easements. The adoption of ASC 842 did not result in a material impact on our balance sheet, results of operations or cash flows. Short-term leases will not be recognized on the balance sheet as an asset or a liability, and the related rental expense will be expensed as incurred. We have short-term lease agreements related to most of our drilling rig arrangements and some of our compressor rental arrangements.
Reclassifications	Reclassifications Certain reclassifications have been made to the consolidated financial statements for 2018 and 2017 to conform to the presentation used for the 2019

Basis of Presentation and Sum_3

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Reclassifications	The following table reflects the reclassifications made: Years Ended December 31, 2018 2017 $ in millions Oil, natural gas and NGL production, previously reported $ 539 $ 562 Reclassification of ad valorem taxes (65 ) (45 ) Oil, natural gas and NGL production, as currently reported $ 474 $ 517 The corresponding amounts have been reflected in severance and ad valorem taxes for 2018 and 2017 as shown below: Years Ended December 31, 2018 2017 $ in millions Production taxes, previously reported $ 124 $ 89 Reclassification of ad valorem taxes 65 45 Severance and ad valorem taxes, as currently reported $ 189 $ 134

Change in Accounting Principle

Change in Accounting Principle (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Changes and Error Corrections [Abstract]
Schedule of changes in accounting principles	The following tables present the effects of the change to the successful efforts method of accounting in the consolidated balance sheets: December 31, 2019 CONSOLIDATED BALANCE SHEETS Under Full Cost Adjustment As Reported Under Successful Efforts ($ in millions except per share data) Proved oil and natural gas properties ($488 and $755 attributable to our VIE) $ 75,148 $ (44,383 ) $ 30,765 Unproved properties $ 3,203 $ (1,030 ) $ 2,173 Total Property and Equipment, at Cost $ 80,161 $ (45,413 ) $ 34,748 Less: accumulated depreciation, depletion and amortization (($468) and ($713) attributable to our VIE) $ (66,626 ) $ 46,624 $ (20,002 ) Total Property and Equipment, Net $ 13,545 $ 1,211 $ 14,756 Total Assets $ 14,982 $ 1,211 $ 16,193 Other current liabilities $ 1,377 $ 55 $ 1,432 Total Current Liabilities $ 2,337 $ 55 $ 2,392 Other long-term liabilities $ 116 $ 9 $ 125 Total Long-Term Liabilities $ 9,391 $ 9 $ 9,400 Accumulated deficit $ (15,451 ) $ 1,231 $ (14,220 ) Total Chesapeake Stockholders’ Equity $ 3,133 $ 1,231 $ 4,364 Noncontrolling interests $ 121 $ (84 ) $ 37 Total Equity $ 3,254 $ 1,147 $ 4,401 Total Liabilities and Equity $ 14,982 $ 1,211 $ 16,193 December 31, 2018 CONSOLIDATED BALANCE SHEETS As Reported Under Full Cost Adjustment As Reported Under Successful Efforts ($ in millions except per share data) Proved oil and natural gas properties ($488 and $755 attributable to our VIE) $ 69,642 $ (44,235 ) $ 25,407 Unproved properties $ 2,337 $ (776 ) $ 1,561 Total Property and Equipment, at Cost $ 73,700 $ (45,011 ) $ 28,689 Less: accumulated depreciation, depletion and amortization (($461) and ($707) attributable to our VIE) $ (64,685 ) $ 46,799 $ (17,886 ) Total Property and Equipment, Net $ 9,030 $ 1,788 $ 10,818 Total Assets $ 10,947 $ 1,788 $ 12,735 Other current liabilities $ 1,540 $ 59 $ 1,599 Total Current Liabilities $ 2,828 $ 59 $ 2,887 Other long-term liabilities $ 156 $ 63 $ 219 Total Long-Term Liabilities $ 7,652 $ 63 $ 7,715 Accumulated deficit $ (15,660 ) $ 1,748 $ (13,912 ) Total Chesapeake Stockholders’ Equity $ 344 $ 1,748 $ 2,092 Noncontrolling interests $ 123 $ (82 ) $ 41 Total Equity $ 467 $ 1,666 $ 2,133 Total Liabilities and Equity $ 10,947 $ 1,788 $ 12,735 The following tables present the effects of the change to the successful efforts method of accounting in the consolidated statements of operations: Year Ended December 31, 2019 CONSOLIDATED STATEMENTS OF OPERATIONS Under Full Cost Adjustment As ($ in millions except per share data) Other revenues $ — $ 63 $ 63 Gain on sale of assets $ — $ 43 $ 43 Total revenues $ 8,489 $ 106 $ 8,595 Exploration expense $ — $ 84 $ 84 General and administrative $ 258 $ 57 $ 315 Depreciation, depletion and amortization $ 1,616 $ 648 $ 2,264 Gain on sale of oil and natural gas properties $ (15 ) $ 15 $ — Impairments $ 344 $ (333 ) $ 11 Other operating expense $ 94 $ (2 ) $ 92 Total operating expenses $ 8,157 $ 469 $ 8,626 Income (loss) from operations $ 332 $ (363 ) $ (31 ) Interest expense $ (487 ) $ (164 ) $ (651 ) Other income $ 31 $ 8 $ 39 Total other expense $ (452 ) $ (156 ) $ (608 ) Loss before income taxes $ (120 ) $ (519 ) $ (639 ) Net income (loss) $ 211 $ (519 ) $ (308 ) Net income attributable to noncontrolling interest $ (2 ) $ 2 $ — Net income (loss) attributable to Chesapeake $ 209 $ (517 ) $ (308 ) Net income (loss) available to common stockholders $ 101 $ (517 ) $ (416 ) Earnings (loss) per common share basic $ 0.06 $ (0.31 ) $ (0.25 ) Earnings (loss) per common share diluted $ 0.06 $ (0.31 ) $ (0.25 ) Year Ended December 31, 2018 CONSOLIDATED STATEMENTS OF OPERATIONS As Adjustment As ($ in millions except per share data) Other revenues $ — $ 63 $ 63 Loss on sale of assets $ — $ (264 ) $ (264 ) Total revenues $ 10,231 $ (201 ) $ 10,030 Exploration expense $ — $ 162 $ 162 General and administrative $ 280 $ 55 $ 335 Depreciation, depletion and amortization $ 1,145 $ 592 $ 1,737 Loss on sale of oil and natural gas properties $ 578 $ (578 ) $ — Impairments $ 53 $ 78 $ 131 Other operating expenses $ 10 $ (10 ) $ — Total operating expenses $ 9,349 $ 299 $ 9,648 Income from operations $ 882 $ (500 ) $ 382 Interest expense $ (487 ) $ (146 ) $ (633 ) Other income $ 70 $ (3 ) $ 67 Total other expense $ (15 ) $ (149 ) $ (164 ) Income before income taxes $ 867 $ (649 ) $ 218 Net income $ 877 $ (649 ) $ 228 Net income attributable to noncontrolling interest $ (4 ) $ 2 $ (2 ) Net income attributable to Chesapeake $ 873 $ (647 ) $ 226 Earnings allocated to participating securities $ (6 ) $ 5 $ (1 ) Net income available to common stockholders $ 775 $ (642 ) $ 133 Earnings per common share basic $ 0.85 $ (0.70 ) $ 0.15 Earnings per common share diluted $ 0.85 $ (0.70 ) $ 0.15 Year Ended December 31, 2017 CONSOLIDATED STATEMENTS OF OPERATIONS As Adjustment As ($ in millions except per share data) Other revenues $ — $ 67 $ 67 Gain on sales of assets $ — $ 476 $ 476 Total revenues $ 9,496 $ 543 $ 10,039 Exploration expense $ — $ 235 $ 235 General and administrative $ 262 $ 71 $ 333 Depreciation, depletion and amortization $ 995 $ 702 $ 1,697 Impairments $ 5 $ 809 $ 814 Other operating expenses $ 413 $ 3 $ 416 Total operating expenses $ 8,357 $ 1,820 $ 10,177 Income (loss) from operations $ 1,139 $ (1,277 ) $ (138 ) Interest expense $ (426 ) $ (175 ) $ (601 ) Other income $ 9 $ (3 ) $ 6 Total other expense $ (184 ) $ (178 ) $ (362 ) Income (loss) before income taxes $ 955 $ (1,455 ) $ (500 ) Net income (loss) $ 953 $ (1,455 ) $ (502 ) Net income attributable to noncontrolling interest $ (4 ) $ 1 $ (3 ) Net income (loss) attributable to Chesapeake $ 949 $ (1,454 ) $ (505 ) Earnings allocated to participating securities $ (10 ) $ 10 $ — Net income (loss) available to common stockholders $ 813 $ (1,444 ) $ (631 ) Earnings (loss) per common share basic $ 0.90 $ (1.60 ) $ (0.70 ) Earnings (loss) per common share diluted $ 0.90 $ (1.60 ) $ (0.70 ) The following tables present the effects of the change to the successful efforts method of accounting in the consolidated statements of comprehensive income: Year Ended December 31, 2019 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Under Full Cost Adjustment As ($ in millions except per share data) Net income (loss) $ 211 $ (519 ) $ (308 ) Comprehensive income (loss) $ 246 $ (519 ) $ (273 ) Comprehensive income attributable to noncontrolling interests $ (2 ) $ 2 $ — Comprehensive income (loss) attributable to Chesapeake $ 244 $ (517 ) $ (273 ) Year Ended December 31, 2018 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME As Adjustment As ($ in millions except per share data) Net income $ 877 $ (649 ) $ 228 Comprehensive income $ 911 $ (649 ) $ 262 Comprehensive income attributable to noncontrolling interests $ (4 ) $ 2 $ (2 ) Comprehensive income attributable to Chesapeake $ 907 $ (647 ) $ 260 Year Ended December 31, 2017 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME As Adjustment As ($ in millions except per share data) Net income (loss) $ 953 $ (1,455 ) $ (502 ) Comprehensive income (loss) $ 992 $ (1,455 ) $ (463 ) Comprehensive income attributable to noncontrolling interests $ (4 ) $ 1 $ (3 ) Comprehensive income (loss) attributable to Chesapeake $ 988 $ (1,454 ) $ (466 ) The following tables present the effects of the change to the successful efforts method of accounting in the consolidated statements of cash flows: Year Ended December 31, 2019 CONSOLIDATED STATEMENTS OF CASH FLOWS Under Full Cost Adjustment As ($ in millions except per share data) Net income (loss) $ 211 $ (519 ) $ (308 ) Depreciation, depletion and amortization $ 1,616 $ 648 $ 2,264 Gain on sale of oil and gas properties $ (15 ) $ 15 $ — Gain on sales of assets $ — $ (43 ) $ (43 ) Impairments $ 344 $ (333 ) $ 11 Exploratory dry hole expense and leasehold impairments $ — $ 49 $ 49 Other $ (2 ) $ (2 ) $ (4 ) (Decrease) increase in accounts payable, accrued liabilities and other $ (567 ) $ (63 ) $ (630 ) Net cash provided by operating activities $ 1,871 $ (248 ) $ 1,623 Drilling and completion costs $ (2,260 ) $ 80 $ (2,180 ) Acquisition of proved and unproved properties $ (203 ) $ 168 $ (35 ) Net cash used by investing activities $ (2,728 ) $ 248 $ (2,480 ) Year Ended December 31, 2018 CONSOLIDATED STATEMENTS OF CASH FLOWS As Adjustment As ($ in millions except per share data) Net income $ 877 $ (649 ) $ 228 Depreciation, depletion and amortization $ 1,145 $ 592 $ 1,737 Loss on sale of oil and gas properties $ 578 $ (578 ) $ — Losses on sales of assets $ — $ 264 $ 264 Impairments $ 53 $ 78 $ 131 Exploratory dry hole expense and leasehold impairments $ — $ 96 $ 96 Other $ (108 ) $ (10 ) $ (118 ) Increase in accounts payable, accrued liabilities and other $ 138 $ (63 ) $ 75 Net cash provided by operating activities $ 2,000 $ (270 ) $ 1,730 Drilling and completion costs $ (1,958 ) $ 110 $ (1,848 ) Acquisition of proved and unproved properties $ (288 ) $ 160 $ (128 ) Net cash provided by investing activities $ 185 $ 270 $ 455 Year Ended December 31, 2017 CONSOLIDATED STATEMENTS OF CASH FLOWS As Adjustment As ($ in millions except per share data) Net income (loss) $ 953 $ (1,455 ) $ (502 ) Depreciation, depletion and amortization $ 995 $ 702 $ 1,697 Gains on sales of assets $ — $ (476 ) $ (476 ) Impairments $ 5 $ 809 $ 814 Exploratory dry hole expense and leasehold impairments $ — $ 214 $ 214 Other $ (135 ) $ 3 $ (132 ) Decrease in accounts payable, accrued liabilities and other $ (308 ) $ (67 ) $ (375 ) Net cash provided by operating activities $ 745 $ (270 ) $ 475 Drilling and completion costs $ (2,186 ) $ 73 $ (2,113 ) Acquisition of proved and unproved properties $ (285 ) $ 197 $ (88 ) Net cash used in investing activities $ (1,188 ) $ 270 $ (918 ) The following tables present the effects of the change to the successful efforts method of accounting in the consolidated statements of stockholders’ equity: Year Ended December 31, 2019 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY Under Full Cost Adjustment As ($ in millions except per share data) Accumulated deficit, beginning of period $ (15,660 ) $ 1,748 $ (13,912 ) Net income (loss) attributable to Chesapeake $ 209 $ (517 ) $ (308 ) Accumulated deficit, end of period $ (15,451 ) $ 1,231 $ (14,220 ) Total Chesapeake stockholders’ equity $ 3,133 $ 1,231 $ 4,364 Noncontrolling interests, beginning of period $ 123 $ (82 ) $ 41 Net income attributable to noncontrolling interests $ 2 $ (2 ) $ — Noncontrolling interests, end of period $ 121 $ (84 ) $ 37 Total equity $ 3,254 $ 1,147 $ 4,401 Year Ended December 31, 2018 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY As As ($ in millions except per share data) Accumulated deficit, beginning of period $ (16,525 ) $ 2,395 $ (14,130 ) Net income attributable to Chesapeake $ 873 $ (647 ) $ 226 Accumulated deficit, end of period $ (15,660 ) $ 1,748 $ (13,912 ) Total Chesapeake stockholders’ equity $ 344 $ 1,748 $ 2,092 Noncontrolling interests, beginning of period $ 124 $ (80 ) $ 44 Net income attributable to noncontrolling interests $ 4 $ (2 ) $ 2 Noncontrolling interests, end of period $ 123 $ (82 ) $ 41 Total equity $ 467 $ 1,666 $ 2,133 Year Ended December 31, 2017 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY As Adjustment As ($ in millions except per share data) Accumulated deficit, beginning of period $ (17,474 ) $ 3,849 $ (13,625 ) Net income (loss) attributable to Chesapeake $ 949 $ (1,454 ) $ (505 ) Accumulated deficit, end of period $ (16,525 ) $ 2,395 $ (14,130 ) Total Chesapeake stockholders’ equity (deficit) $ (496 ) $ 2,395 $ 1,899 Noncontrolling interests, beginning of period $ 128 $ (79 ) $ 49 Net income attributable to noncontrolling interests $ 4 $ (1 ) $ 3 Noncontrolling interests, end of period $ 124 $ (80 ) $ 44 Total equity (deficit) $ (372 ) $ 2,315 $ 1,943

Oil and Natural Gas Property _2

Oil and Natural Gas Property Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of preliminary allocation of the total purchase price	The following table represents the final allocation of the total purchase price of WildHorse to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. Purchase Price Allocation ($ in millions) Consideration: Cash $ 381 Fair value of Chesapeake’s common stock issued in the Merger (a) 2,037 Total consideration $ 2,418 Fair Value of Liabilities Assumed: Current liabilities $ 166 Long-term debt 1,379 Deferred tax liabilities 314 Other long-term liabilities 36 Amounts attributable to liabilities assumed $ 1,895 Fair Value of Assets Acquired: Cash and cash equivalents $ 28 Other current assets 128 Proved oil and natural gas properties 3,264 Unproved properties 756 Other property and equipment 77 Other long-term assets 60 Amounts attributable to assets acquired $ 4,313 Total identifiable net assets $ 2,418 ___________________________________________ (a) Based on 717,376,170 Chesapeake common shares issued at closing at $2.84 per share (closing price as of February 1, 2019).
Schedule of pro forma financial information	The following unaudited pro forma financial information for the years ended December 31, 2019 and 2018, respectively, is based on our historical consolidated financial statements adjusted to reflect as if the WildHorse acquisition had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including adjustments to conform the classification of expenses in WildHorse’s statements of operations to our classification for similar expenses and the estimated tax impact of pro forma adjustments. Years Ended December 31, 2019 2018 ($ in millions except per share data) Revenues $ 8,587 $ 11,211 Net income (loss) available to common stockholders $ (431 ) $ 195 Earnings (loss) per common share: Basic $ (0.26 ) $ 0.12 Diluted $ (0.26 ) $ 0.12

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Schedule of dilutive securities excluded from calculation of diluted EPS	Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive. Years Ended December 31, 2019 2018 2017 (in millions) Common stock equivalent of our preferred stock outstanding 58 60 60 Common stock equivalent of our convertible senior notes outstanding 124 146 146 Common stock equivalent of our preferred stock outstanding prior to exchange 1 — 1 Participating securities — 1 1

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of long-term debt	Our long-term debt consisted of the following as of December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 Principal Amount Carrying Principal Carrying ($ in millions) Revolving credit facility $ 1,590 $ 1,590 $ 419 $ 419 Term loan due 2024 1,500 1,470 — — 11.5% senior secured second lien notes due 2025 2,330 3,248 — — Floating rate senior notes due 2019 — — 380 380 6.625% senior notes due 2020 (a) 208 208 437 437 6.875% senior notes due 2020 93 93 227 227 6.125% senior notes due 2021 167 167 548 548 5.375% senior notes due 2021 127 127 267 267 4.875% senior notes due 2022 (a) 338 338 451 451 5.75% senior notes due 2023 (a) 209 209 338 338 7.00% senior notes due 2024 624 624 850 850 6.875% senior notes due 2025 (b) 2 2 — — 8.00% senior notes due 2025 246 245 1,300 1,291 5.5% convertible senior notes due 2026 (c)(d)(e) 1,064 765 1,250 866 7.5% senior notes due 2026 119 119 400 400 8.00% senior notes due 2026 46 44 — — 8.00% senior notes due 2027 253 253 1,300 1,299 2.25% contingent convertible senior notes due 2038 (c) — — 1 1 Debt issuance costs — (44 ) — (53 ) Interest rate derivatives — — — 1 Total debt, net 8,916 9,458 8,168 7,722 Less current maturities of long-term debt, net (f) (385 ) (385 ) (381 ) (381 ) Total long-term debt, net $ 8,531 $ 9,073 $ 7,787 $ 7,341 ___________________________________________ (a) In December 2019, we entered into a purchase and sale agreement to acquire $101 million principal amount of our 6.625% Senior Notes due 2020, 4.875% Senior Notes due 2022 and 5.75% Senior Notes due 2023. During the first quarter of 2020, we repurchased the senior notes. (b) On February 1, 2019, we acquired the debt of WildHorse which consisted of 6.875% Senior Notes due 2025 and a revolving credit facility and in December 2019 we extinguished the debt with proceeds from a term loan issuance. See further discussion below. (c) We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense through the first demand repurchase date, as applicable, at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 5.5% Convertible Senior Notes due 2026 and our 2.25% Contingent Convertible Senior Notes due 2038 are 11.5% and 8.0% , respectively. (d) The conversion and redemption provisions of our convertible senior notes are as follows: Optional Conversion by Holders . Prior to maturity under certain circumstances and at the holder’s option, the notes are convertible. The notes may be converted into cash, our common stock, or a combination of cash and common stock, at our election. One triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the fourth quarter of 2019, the price of our common stock was below the threshold level and, as a result, the holders do not have the option to convert their notes in the first quarter of 2020 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the year ended December 31, 2019 . Upon conversion of a convertible senior note, the holder will receive cash, common stock or a combination of cash and common stock, at our election, according to the conversion rate specified in the indenture. The common stock price conversion threshold amount for the convertible senior notes is 130% of the conversion price of $8.568 . Optional Redemption by the Company . We may redeem the convertible senior notes for cash on or after September 15, 2019 , if the price of our common stock exceeds 130% of the conversion price during a specified period at a redemption price of 100% of the principal amount of the notes. Holders’ Demand Repurchase Rights. The holders of our convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes upon certain defined fundamental changes. (e) The carrying amounts as of December 31, 2019 and 2018, are reflected net of discounts of $299 million and $384 million , respectively, associated with the equity component of our convertible senior notes. This amount is being amortized based on the effective yield method through the first demand repurchase date as applicable. (f) As of December 31, 2019 , net current maturities of long-term debt includes our 6.625% Senior Notes due August 2020 and our 6.875% Senior Notes due November 2020. As of December 31, 2018, net current maturities of long-term debt includes our Floating Rate Senior Notes due April 2019 and our 2.25% Contingent Convertible Senior Notes due 2038.
Schedule of debt maturities	Debt maturities for the next five years and thereafter are as follows: Principal Amount of Debt Securities ($ in millions) 2020 $ 385 2021 294 2022 289 2023 1,764 2024 2,124 Thereafter 4,060 Total $ 8,916
Schedule of private exchange offer for outstanding senior unsecured notes	We issued at par approximately $919 million of 8.00% Senior Notes due 2026 (“2026 notes”) pursuant to a private exchange offer for the following outstanding senior unsecured notes: Notes Exchanged ($ in millions) 6.625% senior notes due 2020 $ 229 6.875% senior notes due 2020 134 6.125% senior notes due 2021 381 5.375% senior notes due 2021 140 Total $ 884
Schedule of fair value of debt	Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below: December 31, 2019 December 31, 2018 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 385 $ 360 $ 381 $ 379 Long-term debt (Level 1) $ 753 $ 622 $ 3,495 $ 3,173 Long-term debt (Level 2) $ 8,320 $ 6,085 $ 3,846 $ 3,644

Contingencies and Commitments (

Contingencies and Commitments (Tables)	12 Months Ended
	Dec. 31, 2019
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: December 31, ($ in millions) 2020 $ 1,136 2021 1,033 2022 913 2023 789 2024 690 2025 – 2034 3,479 Total $ 8,040 December 31, 2019 ($ in millions) 2020 $ 7 2021 7 2022 2 Total $ 16

Other Liabilities (Tables)

Other Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Other current liabilities	Other current liabilities as of December 31, 2019 and 2018 are detailed below: December 31, 2019 2018 ($ in millions) Revenues and royalties due others $ 516 $ 687 Accrued drilling and production costs 326 258 Joint interest prepayments received 52 73 VPP deferred revenue (a) 55 59 Accrued compensation and benefits 156 202 Other accrued taxes 150 108 Other 177 212 Total other current liabilities $ 1,432 $ 1,599
Other long-term liabilities	Other long-term liabilities as of December 31, 2019 and 2018 are detailed below: December 31, 2019 2018 ($ in millions) VPP deferred revenue (a) $ 9 $ 63 Unrecognized tax benefits (b) — 53 Other 116 103 Total other long-term liabilities $ 125 $ 219 ____________________________________________ (a) At the inception of our volumetric production payment (VPP) agreements, we (i) removed the proved reserves associated with the VPP, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to other revenue over the term of the VPP, (iii) retained responsibility for the production costs and capital costs related to VPP interests and (iv) ceased recognizing production associated with the VPP volumes. The remaining deferred revenue balance will be recognized in other revenues in the consolidated statement of operations through February 2021, assuming the related VPP production volumes are delivered as scheduled. (b) The liability for unrecognized tax benefits was eliminated during the fourth quarter of 2019 as a result of a settlement.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Schedule of ROU assets and lease liabilities	The following table presents our ROU assets and lease liabilities as of December 31, 2019 . Finance Operating ($ in millions) ROU assets $ 17 $ 22 Lease liabilities: Current lease liabilities $ 9 $ 9 Long-term lease liabilities 9 16 Total lease liabilities $ 18 $ 25
Schedule of operating and financing lease additional information	Additional information for the Company’s operating and finance leases is presented below: Year Ended Lease cost: ($ in millions) Amortization of ROU assets $ 8 Interest on lease liability 2 Finance lease cost 10 Operating lease cost 26 Short-term lease cost 112 Total lease cost $ 148 Other information: Operating cash outflows from finance lease $ 2 Operating cash outflows from operating leases $ 11 Investing cash outflows from operating leases $ 127 Financing cash outflows from finance lease $ 8 Weighted average remaining lease term - finance lease 2.00 years Weighted average remaining lease term - operating leases 4.65 years Weighted average discount rate - finance lease 7.50 % Weighted average discount rate - operating leases 4.85 %
Schedule of maturity analysis of operating lease liabilities	Maturity analysis of finance lease liabilities and operating lease liabilities are presented below: December 31, 2019 Finance Lease Operating Leases ($ in millions) 2020 $ 10 $ 10 2021 10 5 2022 — 4 2023 — 2 2024 — 2 Thereafter — 5 Total lease payments 20 28 Less imputed interest (2 ) (3 ) Present value of lease liabilities 18 25 Less current maturities (9 ) (9 ) Present value of lease liabilities, less current maturities $ 9 $ 16
Schedule of maturity analysis of finance lease liabilities	Maturity analysis of finance lease liabilities and operating lease liabilities are presented below: December 31, 2019 Finance Lease Operating Leases ($ in millions) 2020 $ 10 $ 10 2021 10 5 2022 — 4 2023 — 2 2024 — 2 Thereafter — 5 Total lease payments 20 28 Less imputed interest (2 ) (3 ) Present value of lease liabilities 18 25 Less current maturities (9 ) (9 ) Present value of lease liabilities, less current maturities $ 9 $ 16
Schedule of minimum future lease payments	The aggregate undiscounted minimum future lease payments under previous lease accounting standard, ASC 840, are presented below: December 31, 2018 Capital Lease Operating Leases ($ in millions) 2019 $ 10 $ 3 2020 10 1 2021 10 — Total minimum lease payments $ 30 $ 4
Schedule of minimum future lease payments	The aggregate undiscounted minimum future lease payments under previous lease accounting standard, ASC 840, are presented below: December 31, 2018 Capital Lease Operating Leases ($ in millions) 2019 $ 10 $ 3 2020 10 1 2021 10 — Total minimum lease payments $ 30 $ 4

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of revenue	The following table shows revenue disaggregated by operating area and product type, for the years ended December 31, 2019 and 2018 : Year Ended December 31, 2019 Oil Natural Gas NGL Total ($ in millions) Marcellus $ — $ 856 $ — $ 856 Haynesville — 620 — 620 Eagle Ford 1,289 153 119 1,561 Brazos Valley 721 32 16 769 Powder River Basin 369 77 32 478 Mid-Continent 164 44 25 233 Revenue from contracts with customers 2,543 1,782 192 4,517 Gains (losses) on oil, natural gas and NGL derivatives (212 ) 217 — 5 Oil, natural gas and NGL revenue $ 2,331 $ 1,999 $ 192 $ 4,522 Marketing revenue from contracts with customers $ 2,473 $ 900 $ 246 $ 3,619 Other marketing revenue 311 41 — 352 Losses on marketing derivatives — (4 ) — (4 ) Marketing revenue $ 2,784 $ 937 $ 246 $ 3,967 Year Ended December 31, 2018 Oil Natural Gas NGL Total ($ in millions) Marcellus $ — $ 924 $ — $ 924 Haynesville 2 836 — 838 Eagle Ford 1,514 173 185 1,872 Powder River Basin 244 68 38 350 Mid-Continent 246 84 55 385 Utica 195 401 224 820 Revenue from contracts with customers 2,201 2,486 502 5,189 Gains (losses) on oil, natural gas and NGL derivatives 124 (147 ) (11 ) (34 ) Oil, natural gas and NGL revenue $ 2,325 $ 2,339 $ 491 $ 5,155 Marketing revenue from contracts with customers $ 2,740 $ 1,194 $ 456 $ 4,390 Other marketing revenue 457 222 — 679 Gains on marketing derivatives — 7 — 7 Marketing revenue $ 3,197 $ 1,423 $ 456 $ 5,076
Accounts receivable	Accounts receivable as of December 31, 2019 and 2018 are detailed below: December 31, 2019 2018 ($ in millions) Oil, natural gas and NGL sales $ 737 $ 976 Joint interest billings 200 211 Other 74 77 Allowance for doubtful accounts (21 ) (17 ) Total accounts receivable, net $ 990 $ 1,247

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of components of the income tax provision (benefit)	The components of the income tax provision (benefit) for each of the periods presented below are as follows: Years Ended December 31, 2019 2018 2017 ($ in millions) Current Federal $ — $ — $ (14 ) State (26 ) — 5 Current Income Taxes (26 ) — (9 ) Deferred Federal (297 ) 3 13 State (8 ) (13 ) (2 ) Deferred Income Taxes (305 ) (10 ) 11 Total $ (331 ) $ (10 ) $ 2
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: Years Ended December 31, 2019 2018 2017 ($ in millions) Income tax expense (benefit) at the federal statutory rate (21%, 21%, 35%) $ (134 ) $ 45 $ (175 ) State income taxes (net of federal income tax benefit) (21 ) 27 5 Partial release of valuation allowance due to the WildHorse Merger (314 ) — — Remeasurement of deferred tax assets and liabilities — — 931 Change in valuation allowance excluding impact of WildHorse Merger 114 (97 ) (771 ) Other 24 15 12 Total $ (331 ) $ (10 ) $ 2
Schedule of deferred tax assets and liabilities	The tax-effected temporary differences, NOL carryforwards and disallowed business interest carryforwards that comprise our deferred income taxes are as follows: December 31, 2019 2018 ($ in millions) Deferred tax liabilities: Property, plant and equipment $ (546 ) $ (976 ) Volumetric production payments (89 ) (86 ) Carrying value of debt — (95 ) Derivative instruments (14 ) (56 ) Other (5 ) (7 ) Deferred tax liabilities (654 ) (1,220 ) Deferred tax assets: Net operating loss carryforwards 1,971 2,737 Carrying value of debt 169 — Disallowed business interest carryforward 25 194 Asset retirement obligations 50 40 Investments 83 111 Accrued liabilities 64 89 Other 87 60 Deferred tax assets 2,449 3,231 Valuation allowance (1,805 ) (2,011 ) Deferred tax assets after valuation allowance 644 1,220 Net deferred tax liability $ (10 ) $ —
Reconciliation of unrecognized tax benefits	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: 2019 2018 2017 ($ in millions) Unrecognized tax benefits at beginning of period $ 79 $ 106 $ 202 Additions based on tax positions related to the current year — — — Additions to tax positions of prior years 27 — 4 Settlements (32 ) — (100 ) Expiration of the applicable statute of limitations — (23 ) — Reductions to tax positions of prior years — (4 ) — Unrecognized tax benefits at end of period $ 74 $ 79 $ 106

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Schedule of changes in common shares issued	A summary of the changes in our common shares issued for the years ended December 31, 2019 , 2018 and 2017 is detailed below: Years Ended December 31, 2019 2018 2017 (in thousands) Shares issued as of January 1 913,716 908,733 896,279 Common shares issued for WildHorse Merger (a) 717,376 — — Exchange of senior notes (b) 235,564 — — Exchange of convertible notes (b) 73,389 — — Exchange of preferred stock 10,368 — 9,966 Restricted stock issuances (net of forfeitures and cancellations) (c) 4,146 4,983 2,488 Shares issued as of December 31 1,954,559 913,716 908,733 ___________________________________________ (a) See Note 3 for discussion of WildHorse Merger. (b) See Note 5 for discussion of debt exchanges. (c) See Note 12 for discussion of restricted stock.
Summary of preferred stock	Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2019: Preferred Stock Series Issue Date Liquidation Preference per Share Holder's Conversion Right Conversion Rate Conversion Price Company's Conversion Right From Company's Market Conversion Trigger (a) 5.75% cumulative convertible non-voting May and June 2010 $ 1,000 Any time 39.6858 $ 25.1979 May 17, 2015 $ 32.7573 5.75% (series A) cumulative convertible non-voting May 2010 $ 1,000 Any time 38.3508 $ 26.0751 May 17, 2015 $ 33.8976 4.50% cumulative convertible September 2005 $ 100 Any time 2.4561 $ 40.7152 September 15, 2010 $ 52.9298 5.00% cumulative convertible (series 2005B) November 2005 $ 100 Any time 2.7745 $ 36.0431 November 15, 2010 $ 46.8560 ___________________________________________ (a) Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding. Outstanding shares of our preferred stock for the years ended December 31, 2019, 2018 and 2017 are detailed below: 5.75% 5.75% (Series A) 4.50% 5.00% (Series 2005B) (in thousands) Shares outstanding as of January 1, 2019 770 463 2,559 1,811 Preferred stock exchanges (a) — (40 ) — — Shares outstanding as of December 31, 2019 770 423 2,559 1,811 Shares outstanding as of January 1, 2018 770 463 2,559 1,811 Shares outstanding as of January 1, 2017 843 476 2,559 1,962 Preferred stock exchanges (b) (73 ) (13 ) — (151 ) Shares outstanding as of December 31, 2017 770 463 2,559 1,811 ____________________________________________ (a) During 2019, we exchanged 10,367,950 shares of common stock for 40,000 shares of our 5.75% (Series A) Cumulative Convertible Preferred Stock. In connection with the exchange, we recognized a loss equal to the excess of the fair value of all common stock issued in exchange for the preferred stock over the fair value of the common stock issuable pursuant to the original terms of the preferred stock. The loss of $17 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share. (b) During 2017, holders of our 5.75% Cumulative Convertible Preferred Stock exchanged 72,600 shares into 7,442,156 shares of common stock, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock exchanged 12,500 shares into 1,205,923 shares of common stock and holders of our 5.00% (Series 2005B) Cumulative Convertible Preferred Stock exchanged 150,948 shares into 1,317,756 shares of common stock. In connection with the exchanges, we recognized a loss equal to the excess of the fair value of all common stock issued in exchange for the preferred stock over the fair value of the common stock issuable pursuant to the original terms of the preferred stock. The loss of $41 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share.
Schedule of Accumulated Other Comprehensive Income (Loss)	For the years ended December 31, 2019 and 2018, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below: Years Ended December 31, 2019 2018 ($ in millions) Balance, as of January 1 $ (23 ) $ (57 ) Amounts reclassified from accumulated other comprehensive income (a) 35 34 Balance, as of December 31 $ 12 $ (23 ) ___________________________________________ (a) Net losses on cash flow hedges for commodity contracts reclassified from accumulated other comprehensive income (loss), net of tax, to oil, natural gas and NGL revenues in the consolidated statements of operations.

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Summary of changes in unvested restricted stock	A summary of the changes in unvested restricted stock during 2019 , 2018 and 2017 is presented below: Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Unvested restricted stock as of January 1, 2019 11,858 $ 4.43 Granted 5,908 $ 2.65 Vested (5,944 ) $ 4.38 Forfeited (1,380 ) $ 3.72 Unvested restricted stock as of December 31, 2019 10,442 $ 3.55 Unvested restricted stock as of January 1, 2018 13,178 $ 6.37 Granted 6,067 $ 3.73 Vested (5,808 ) $ 7.67 Forfeited (1,579 ) $ 6.02 Unvested restricted stock as of December 31, 2018 11,858 $ 4.43 Unvested restricted stock as of January 1, 2017 9,092 $ 11.39 Granted 9,872 $ 5.40 Vested (4,573 ) $ 13.73 Forfeited (1,213 ) $ 8.32 Unvested restricted stock as of December 31, 2017 13,178 $ 6.37
Schedule of share-based payment assumptions	We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2019: Expected option life – years 6.0 Volatility 65.61 % Risk-free interest rate 2.47 % Dividend yield — %
Schedule of information related to stock option activity	The following table provides information related to stock option activity for 2019 , 2018 and 2017 : Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Contract Life in Years Aggregate Intrinsic Value (a) (in thousands) ($ in millions) Outstanding as of January 1, 2019 18,096 $ 7.20 7.15 $ — Granted 1,000 $ 2.97 Exercised — $ — $ — Expired (553 ) $ 6.36 Forfeited (609 ) $ 3.97 Outstanding as of December 31, 2019 17,934 $ 7.10 5.70 $ — Exercisable as of December 31, 2019 13,092 $ 8.28 4.86 $ — Outstanding as of January 1, 2018 16,285 $ 8.25 7.73 $ 1 Granted 3,611 $ 3.01 Exercised — $ — $ — Expired (602 ) $ 13.83 Forfeited (1,198 ) $ 5.45 Outstanding as of December 31, 2018 18,096 $ 7.20 7.15 $ — Exercisable as of December 31, 2018 8,250 $ 10.73 5.73 $ — Outstanding as of January 1, 2017 8,593 $ 11.88 7.22 $ 14 Granted 9,226 $ 5.45 Exercised — $ — $ — Expired (435 ) $ 18.50 Forfeited (1,099 ) $ 9.12 Outstanding as of December 31, 2017 16,285 $ 8.25 7.73 $ 1 Exercisable as of December 31, 2017 4,474 $ 15.15 5.26 $ — ___________________________________________ (a) The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
Schedule of compensation costs (credit), net of actual forfeitures	We recognized the following compensation costs (credits), net of actual forfeitures, related to our liability-classified awards for the years ended December 31, 2019 , 2018 and 2017 : Years Ended December 31, 2019 2018 2017 ($ in millions) General and administrative expenses $ 5 $ 9 $ (4 ) Oil and natural gas properties 1 1 — Oil, natural gas and NGL production expenses 3 2 — Restructuring and other termination costs 1 — — Total liability-classified awards compensation $ 10 $ 12 $ (4 ) December 31, 2019 , 2018 and 2017 : Years Ended December 31, 2019 2018 2017 ($ in millions) General and administrative expenses $ 26 $ 31 $ 43 Oil and natural gas properties 2 2 5 Oil, natural gas and NGL production expenses 3 5 12 Exploration expenses 1 1 1 Total restricted stock and stock option compensation $ 32 $ 39 $ 61
Summary of liability-classified awards	The following table presents a summary of our liability-classified awards: Grant Date Fair Value December 31, 2019 Units Fair Value Vested Liability ($ in millions) ($ in millions) 2019 PSU Awards: Payable 2020, 2021 and 2022 4,674,503 $ 14 $ 4 $ — 2018 PSU Awards: Payable 2020 and 2021 2,340,157 $ 7 $ 2 $ — 2017 PSU Awards: Payable 2020 1,174,973 $ 8 $ 1 $ — 2018 CRSU Awards: Payable 2020 and 2021 8,233,207 $ 25 $ 7 $ —

Derivative and Hedging Activi_2

Derivative and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2019
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 oil, natural gas and NGL derivative instrument assets (liabilities) as of December 31, 2019 and 2018 are provided below: December 31, 2019 December 31, 2018 Notional Volume Fair Value Notional Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 24 $ (7 ) 12 $ 157 Collars 2 14 8 98 Basis protection swaps 8 (2 ) 7 5 Total oil 34 5 27 260 Natural gas (bcf): Fixed-price swaps 265 125 623 26 Three-way collars — — 88 1 Collars — — 55 (3 ) Call options 22 — 44 — Call swaptions 29 (2 ) 106 (9 ) Basis protection swaps 30 2 50 — Total natural gas 346 125 966 15 Contingent Consideration: Utica divestiture — 7 Total estimated fair value $ 130 $ 282
Schedule of effects of dividend 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, 2019 , and 2018 on a gross basis and after same-counterparty netting: Balance Sheet Classification Gross Fair Value Amounts Netted in the Consolidated Balance Sheets Net Fair Value Presented in the Consolidated Balance Sheets ($ in millions) As of December 31, 2019 Commodity Contracts: Short-term derivative asset $ 174 $ (40 ) $ 134 Short-term derivative liability (42 ) 40 (2 ) Long-term derivative liability (2 ) — (2 ) Total derivatives $ 130 $ — $ 130 As of December 31, 2018 Commodity Contracts: Short-term derivative asset $ 306 $ (104 ) $ 202 Long-term derivative asset 117 (41 ) 76 Short-term derivative liability (107 ) 104 (3 ) Long-term derivative liability (41 ) 41 — Contingent Consideration: Short-term derivative asset 7 — 7 Total derivatives $ 282 $ — $ 282
Schedule of effects of derivative instruments in consolidated statements of operations	The components of oil, natural gas and NGL revenues for the years ended December 31, 2019 , 2018 and 2017 are presented below: Years Ended December 31, 2019 2018 2017 ($ in millions) Oil, natural gas and NGL revenues $ 4,517 $ 5,189 $ 4,574 Gains on undesignated oil, natural gas and NGL derivatives 40 — 445 Losses on terminated cash flow hedges (35 ) (34 ) (34 ) Total oil, natural gas and NGL revenues $ 4,522 $ 5,155 $ 4,985 The components of marketing revenues for the years ended December 31, 2019 , 2018 and 2017 are presented below: Years Ended December 31, 2019 2018 2017 ($ in millions) Marketing revenues $ 3,971 $ 5,069 $ 4,511 Gains (losses) on undesignated marketing natural gas derivatives (4 ) 7 — Total marketing revenues $ 3,967 $ 5,076 $ 4,511
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: Years Ended December 31, 2019 2018 2017 Before After Before After Before After ($ in millions) Balance, beginning of period $ (80 ) $ (23 ) $ (114 ) $ (57 ) $ (153 ) $ (96 ) Net change in fair value — — — — 5 5 Losses reclassified to income 35 35 34 34 34 34 Balance, end of period $ (45 ) $ 12 $ (80 ) $ (23 ) $ (114 ) $ (57 )
Schedule of fair value measurement of financial assets (liabilities) measured at fair value on a recurring basis	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2019 and 2018 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2019 Derivative Assets (Liabilities): Commodity assets $ — $ 160 $ 14 $ 174 Commodity liabilities — (42 ) (2 ) (44 ) Total derivatives $ — $ 118 $ 12 $ 130 As of December 31, 2018 Derivative Assets (Liabilities): Commodity assets $ — $ 319 $ 103 $ 422 Commodity liabilities — (131 ) (16 ) (147 ) Utica divestiture contingent consideration — — 7 7 Total derivatives $ — $ 188 $ 94 $ 282 A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during 2019 and 2018 is presented below: Commodity Derivatives Utica Contingent Consideration ($ in millions) Balance, as of January 1, 2019 $ 87 $ 7 Total gains (losses) (realized/unrealized): Included in earnings (a) (59 ) (7 ) Total purchases, issuances, sales and settlements: Settlements (16 ) — Balance, as of December 31, 2019 $ 12 $ — Balance, as of January 1, 2018 $ (15 ) $ — Total gains (losses) (realized/unrealized): Included in earnings (a) 77 7 Total purchases, issuances, sales and settlements: Settlements 25 — Balance, as of December 31, 2018 $ 87 $ 7 ___________________________________________ (a) Commodity Derivatives Utica Contingent Consideration 2019 2018 2019 2018 ($ in millions) Total gains (losses) included in earnings for the period $ (59 ) $ 77 $ (7 ) $ 7 Change in unrealized gains (losses) related to assets still held at reporting date $ (19 ) $ 86 $ — $ 7 December 31, 2019 and 2018: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2019 Financial Assets (Liabilities): Other current assets $ 42 $ — $ — $ 42 Other current liabilities (43 ) — — (43 ) Total $ (1 ) $ — $ — $ (1 ) As of December 31, 2018 Financial Assets (Liabilities): Other current assets $ 50 $ — $ — $ 50 Other current liabilities (51 ) — — (51 ) Total $ (1 ) $ — $ — $ (1 )
Schedule of quantitative information about Level 3 inputs used in fair value measurement of commodity contracts	The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts as of December 31, 2019 : Instrument Type Unobservable Input Range Weighted Average Fair Value ($ in millions) Oil trades Oil price volatility curves 20.71% – 67.28% 25.62% $ 14 Natural gas trades Natural gas price volatility curves 16.93% – 171.49% 39.67% $ (2 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of fair value measurement of financial assets (liabilities) measured at fair value on a recurring basis	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2019 and 2018 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2019 Derivative Assets (Liabilities): Commodity assets $ — $ 160 $ 14 $ 174 Commodity liabilities — (42 ) (2 ) (44 ) Total derivatives $ — $ 118 $ 12 $ 130 As of December 31, 2018 Derivative Assets (Liabilities): Commodity assets $ — $ 319 $ 103 $ 422 Commodity liabilities — (131 ) (16 ) (147 ) Utica divestiture contingent consideration — — 7 7 Total derivatives $ — $ 188 $ 94 $ 282 A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during 2019 and 2018 is presented below: Commodity Derivatives Utica Contingent Consideration ($ in millions) Balance, as of January 1, 2019 $ 87 $ 7 Total gains (losses) (realized/unrealized): Included in earnings (a) (59 ) (7 ) Total purchases, issuances, sales and settlements: Settlements (16 ) — Balance, as of December 31, 2019 $ 12 $ — Balance, as of January 1, 2018 $ (15 ) $ — Total gains (losses) (realized/unrealized): Included in earnings (a) 77 7 Total purchases, issuances, sales and settlements: Settlements 25 — Balance, as of December 31, 2018 $ 87 $ 7 ___________________________________________ (a) Commodity Derivatives Utica Contingent Consideration 2019 2018 2019 2018 ($ in millions) Total gains (losses) included in earnings for the period $ (59 ) $ 77 $ (7 ) $ 7 Change in unrealized gains (losses) related to assets still held at reporting date $ (19 ) $ 86 $ — $ 7 December 31, 2019 and 2018: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2019 Financial Assets (Liabilities): Other current assets $ 42 $ — $ — $ 42 Other current liabilities (43 ) — — (43 ) Total $ (1 ) $ — $ — $ (1 ) As of December 31, 2018 Financial Assets (Liabilities): Other current assets $ 50 $ — $ — $ 50 Other current liabilities (51 ) — — (51 ) Total $ (1 ) $ — $ — $ (1 )

Capitalized Exploratory Well _2

Capitalized Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2019
Extractive Industries [Abstract]
Summary of changes in capitalized well costs	A summary of the changes in our capitalized well costs for the years ended December 31, 2019 , 2018 and 2017 is detailed below. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. 2019 2018 2017 (in millions) Balance as of January 1 $ 36 $ 36 $ 41 Additions pending the determination of proved reserves 7 74 14 Divestitures and other (3 ) — — Reclassifications to proved properties (17 ) (40 ) (19 ) Charges to exploration expense (16 ) (34 ) — Balance as of December 31 $ 7 $ 36 $ 36
Schedule of aging of capitalize costs and the number of projects for which exploratory well costs have been capitalized	The following table provides an aging of capitalized costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. 2019 2018 2017 (in millions) Exploratory well costs capitalized for a period of one year or less $ 7 $ 34 $ 4 Exploratory well costs capitalized for a period greater than one year — 2 32 Balance as of December 31 $ 7 $ 36 $ 36 Number of projects with exploratory well costs capitalized for a period greater than one year — 7 6

Other Property and Equipment (T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
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: December 31, Estimated Useful Life 2019 2018 ($ in millions) (in years) Buildings and improvements $ 1,058 $ 1,053 10 – 39 Computer equipment 355 353 5 Sand mine 78 — 10 – 30 Natural gas compressors (a) 48 48 3 – 20 Land 115 106 Other 156 161 5 – 20 Total other property and equipment, at cost 1,810 1,721 Less: accumulated depreciation (692 ) (630 ) Total other property and equipment, net $ 1,118 $ 1,091 ___________________________________________ (a) Includes assets under finance lease of $27 million , less accumulated depreciation of $10 million and $1 million , as of December 31, 2019 and 2018 , respectively. The related amortization expense for assets under finance lease is included in depreciation, depletion and amortization expense on our consolidated statement of operations.

Impairments (Tables)

Impairments (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Impairment Charges [Abstract]
Summary of impairments	A summary of our impairments of oil and natural gas properties for the years ended December 31, 2019 , 2018 and 2017 is as follows: Years Ended December 31, 2019 2018 2017 ($ in millions) Impairments due to lower forecasted commodity prices $ 8 $ 23 $ 27 Impairments due to reduction in future development (a) — — 560 Impairments due to anticipated sale — 55 222 Total impairments of oil and natural gas properties $ 8 $ 78 $ 809 ____________________________________________ (a) The impairment was the result of an updated development plan in 2017, which included a removal of PUDs from properties in the process of being divested in the Mid-Continent operating area. A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2019 , 2018 and 2017 is as follows: Years Ended December 31, 2019 2018 2017 ($ in millions) Natural gas compressors (a) $ — $ 45 $ — Buildings and land 1 4 5 Other 2 4 — Total impairments of fixed assets and other $ 3 $ 53 $ 5

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Schedule of asset retirement obligations	The components of the change in our asset retirement obligations are shown below: Years Ended December 31, 2019 2018 ($ in millions) Asset retirement obligations, beginning of period $ 166 $ 177 Additions (a) 21 3 Revisions 18 11 Settlements and disposals (5 ) (35 ) Accretion expense 11 10 Asset retirement obligations, end of period 211 166 Less current portion 11 11 Asset retirement obligation, long-term $ 200 $ 155 ___________________________________________ (a) During 2019, approximately $17 million of additions relate to the acquisition of WildHorse.

Condensed Consolidating Finan_2

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Condensed consolidated balance sheets	CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2019 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 16 $ 1 $ 5 $ (16 ) $ 6 Other current assets 51 1,090 104 — 1,245 Intercompany receivable, net 7,702 — — (7,702 ) — Total Current Assets 7,769 1,091 109 (7,718 ) 1,251 PROPERTY AND EQUIPMENT: Oil and natural gas properties at cost, based on successful efforts accounting, net — 9,440 4,188 — 13,628 Other property and equipment, net — 1,030 88 — 1,118 Property and equipment held for sale, net — 10 — — 10 Total Property and Equipment, Net — 10,480 4,276 — 14,756 LONG-TERM ASSETS: Other long-term assets 41 125 19 1 186 Investments in subsidiaries and intercompany advances 6,101 4,171 — (10,272 ) — TOTAL ASSETS $ 13,911 $ 15,867 $ 4,404 $ (17,989 ) $ 16,193 CURRENT LIABILITIES: Current liabilities $ 466 $ 1,765 $ 176 $ (15 ) $ 2,392 Intercompany payable, net — 7,702 — (7,702 ) — Total Current Liabilities 466 9,467 176 (7,717 ) 2,392 LONG-TERM LIABILITIES: Long-term debt, net 9,071 — 2 — 9,073 Deferred income tax liabilities 10 — — — 10 Other long-term liabilities — 299 18 — 317 Total Long-Term Liabilities 9,081 299 20 — 9,400 EQUITY: Chesapeake stockholders’ equity 4,364 6,101 4,171 (10,272 ) 4,364 Noncontrolling interests — — 37 — 37 Total Equity 4,364 6,101 4,208 (10,272 ) 4,401 TOTAL LIABILITIES AND EQUITY $ 13,911 $ 15,867 $ 4,404 $ (17,989 ) $ 16,193 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2018 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 4 $ 1 $ 1 $ (2 ) $ 4 Other current assets 60 1,532 2 — 1,594 Intercompany receivable, net 6,671 — — (6,671 ) — Total Current Assets 6,735 1,533 3 (6,673 ) 1,598 PROPERTY AND EQUIPMENT: Oil and natural gas properties at cost, based on successful efforts accounting, net — 9,664 48 — 9,712 Other property and equipment, net — 1,091 — — 1,091 Property and equipment held for sale, net — 15 — — 15 Total Property and Equipment, Net — 10,770 48 — 10,818 LONG-TERM ASSETS: Other long-term assets 26 293 — — 319 Investments in subsidiaries and intercompany advances 3,248 9 — (3,257 ) — TOTAL ASSETS $ 10,009 $ 12,605 $ 51 $ (9,930 ) $ 12,735 CURRENT LIABILITIES: Current liabilities $ 523 $ 2,365 $ 1 $ (2 ) $ 2,887 Intercompany payable, net — 6,671 — (6,671 ) — Total Current Liabilities 523 9,036 1 (6,673 ) 2,887 LONG-TERM LIABILITIES: Long-term debt, net 7,341 — — — 7,341 Other long-term liabilities 53 321 — — 374 Total Long-Term Liabilities 7,394 321 — — 7,715 EQUITY: Chesapeake stockholders’ equity 2,092 3,248 9 (3,257 ) 2,092 Noncontrolling interests — — 41 — 41 Total Equity 2,092 3,248 50 (3,257 ) 2,133 TOTAL LIABILITIES AND EQUITY $ 10,009 $ 12,605 $ 51 $ (9,930 ) $ 12,735
Condensed consolidated income statements	Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES AND OTHER: Oil, natural gas and NGL $ — $ 3,760 $ 762 $ — $ 4,522 Marketing — 3,967 — — 3,967 Total Revenues — 7,727 762 — 8,489 Other — 60 3 — 63 Gains on sales of assets — 43 — — 43 Total Revenues and Other — 7,830 765 — 8,595 OPERATING EXPENSES: Oil, natural gas and NGL production — 436 84 — 520 Oil, natural gas and NGL gathering, processing and transportation — 1,062 20 — 1,082 Severance and ad valorem taxes — 174 50 — 224 Exploration — 77 7 — 84 Marketing — 4,003 — — 4,003 General and administrative 1 237 77 — 315 Restructuring and other termination costs — 12 — — 12 Provision for legal contingencies, net — 19 — — 19 Depreciation, depletion and amortization — 1,719 545 — 2,264 Impairments — 11 — — 11 Other operating expense — 52 40 — 92 Total Operating Expenses 1 7,802 823 — 8,626 INCOME (LOSS) FROM OPERATIONS (1 ) 28 (58 ) — (31 ) OTHER INCOME (EXPENSE): Interest income (expense) (598 ) 16 (69 ) — (651 ) Losses on investments — (47 ) (24 ) — (71 ) Gains on purchases or exchanges of debt 65 — 10 — 75 Other income — 39 — — 39 Equity in net earnings (losses) of subsidiary (105 ) (141 ) — 246 — Total Other Expense (638 ) (133 ) (83 ) 246 (608 ) LOSS BEFORE INCOME TAXES (639 ) (105 ) (141 ) 246 (639 ) INCOME TAX BENEFIT (331 ) — — — (331 ) NET LOSS (308 ) (105 ) (141 ) 246 (308 ) Net income attributable to noncontrolling interests — — — — — NET LOSS ATTRIBUTABLE TO CHESAPEAKE (308 ) (105 ) (141 ) 246 (308 ) Other comprehensive income — 35 — — 35 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (308 ) $ (70 ) $ (141 ) $ 246 $ (273 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2018 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES AND OTHER: Oil, natural gas and NGL $ — $ 5,136 $ 19 $ — $ 5,155 Marketing — 5,076 — — 5,076 Total Revenues — 10,212 19 — 10,231 Other — 63 — — 63 Losses on sales of assets — (264 ) — — (264 ) Total Revenues and Other — 10,011 19 — 10,030 OPERATING EXPENSES: Oil, natural gas and NGL production — 474 — — 474 Oil, natural gas and NGL gathering, processing and transportation — 1,391 7 — 1,398 Severance and ad valorem taxes — 188 1 — 189 Exploration — 162 — — 162 Marketing — 5,158 — — 5,158 General and administrative 2 332 1 — 335 Restructuring and other termination costs — 38 — — 38 Provision for legal contingencies, net — 26 — — 26 Depreciation, depletion and amortization — 1,730 7 — 1,737 Impairments — 131 — — 131 Total Operating Expenses 2 9,630 16 — 9,648 INCOME (LOSS) FROM OPERATIONS (2 ) 381 3 — 382 OTHER INCOME (EXPENSE): Interest expense (631 ) (2 ) — — (633 ) Gains on investments — 139 — — 139 Gains on purchases or exchanges of debt 263 — — — 263 Other income 3 64 — — 67 Equity in net earnings of subsidiary 583 1 — (584 ) — Total Other Income (Expense) 218 202 — (584 ) (164 ) INCOME BEFORE INCOME TAXES 216 583 3 (584 ) 218 INCOME TAX BENEFIT (10 ) — — — (10 ) NET INCOME 226 583 3 (584 ) 228 Net income attributable to noncontrolling interests — — (2 ) — (2 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 226 583 1 (584 ) 226 Other comprehensive income — 34 — — 34 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 226 $ 617 $ 1 $ (584 ) $ 260 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES AND OTHER: Oil, natural gas and NGL $ — $ 4,962 $ 23 $ — $ 4,985 Marketing — 4,511 — — 4,511 Total Revenues — 9,473 23 — 9,496 Other — 67 — — 67 Gains on sales of assets — 476 — — 476 Total Revenues and Other — 10,016 23 — 10,039 OPERATING EXPENSES: Oil, natural gas and NGL production — 517 — — 517 Oil, natural gas and NGL gathering, processing and transportation — 1,463 8 — 1,471 Severance and ad valorem taxes — 133 1 — 134 Exploration — 235 — — 235 Marketing — 4,598 — — 4,598 General and administrative 1 330 2 — 333 Provision for legal contingencies, net (79 ) 41 — — (38 ) Depreciation, depletion and amortization — 1,688 9 — 1,697 Impairments — 814 — — 814 Other operating expense — 416 — — 416 Total Operating (Income) Expenses (78 ) 10,235 20 — 10,177 INCOME (LOSS) FROM OPERATIONS 78 (219 ) 3 — (138 ) OTHER INCOME (EXPENSE): Interest expense (599 ) (2 ) — — (601 ) Gains on purchases or exchanges of debt 233 — — — 233 Other income 1 5 — — 6 Equity in net losses of subsidiary (216 ) — — 216 — Total Other Income (Expense) (581 ) 3 — 216 (362 ) INCOME (LOSS) BEFORE INCOME TAXES (503 ) (216 ) 3 216 (500 ) INCOME TAX EXPENSE 2 — — — 2 NET INCOME (LOSS) (505 ) (216 ) 3 216 (502 ) Net income attributable to noncontrolling interests — — (3 ) — (3 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (505 ) (216 ) — 216 (505 ) Other comprehensive income — 39 — — 39 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (505 ) $ (177 ) $ — $ 216 $ (466 )
Condensed consolidated cash flow statements	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2019 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 1 $ 1,270 $ 356 $ (4 ) $ 1,623 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,548 ) (632 ) — (2,180 ) Business combination, net — (381 ) 28 — (353 ) Acquisitions of proved and unproved properties — (35 ) — — (35 ) Proceeds from divestitures of proved and unproved properties — 130 — — 130 Additions to other property and equipment — (32 ) (16 ) — (48 ) Proceeds from sales of other property and equipment — 6 — — 6 Net Cash Used In Investing Activities — (1,860 ) (620 ) — (2,480 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 9,839 — 837 — 10,676 Payments on revolving credit facility borrowings (8,668 ) — (1,512 ) — (10,180 ) Proceeds from issuance of senior notes, net 108 — — — 108 Proceeds from issuance of term loan, net 1,455 — — — 1,455 Cash paid to purchase debt (380 ) — (693 ) — (1,073 ) Cash paid for preferred stock dividends (91 ) — — — (91 ) Contribution from parent (1,644 ) — 1,644 — — Other financing activities (24 ) (8 ) (8 ) 4 (36 ) Intercompany advances, net (713 ) 713 — — — Net Cash Provided By (Used In) Financing Activities (118 ) 705 268 4 859 Net increase (decrease) in cash and cash equivalents (117 ) 115 4 — 2 Cash and cash equivalents, beginning of period 4 1 1 (2 ) 4 Cash and cash equivalents, end of period $ (113 ) $ 116 $ 5 $ (2 ) $ 6 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2018 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 85 $ 1,642 $ 10 $ (7 ) $ 1,730 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,848 ) — — (1,848 ) Acquisitions of proved and unproved properties — (128 ) — — (128 ) Proceeds from divestitures of proved and unproved properties — 2,231 — — 2,231 Additions to other property and equipment — (21 ) — — (21 ) Proceeds from sales of other property and equipment — 147 — — 147 Proceeds from sales of investments — 74 — — 74 Net Cash Provided by Investing Activities — 455 — — 455 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 11,697 — — — 11,697 Payments on revolving credit facility borrowings (12,059 ) — — — (12,059 ) Proceeds from issuance of senior notes, net 1,236 — — — 1,236 Cash paid to purchase debt (2,813 ) — — — (2,813 ) Cash paid for preferred stock dividends (92 ) — — — (92 ) Other financing activities (26 ) (123 ) (13 ) 7 (155 ) Intercompany advances, net 1,971 (1,974 ) 2 1 — Net Cash Used In Financing Activities (86 ) (2,097 ) (11 ) 8 (2,186 ) Net decrease in cash and cash equivalents (1 ) — (1 ) 1 (1 ) Cash and cash equivalents, beginning of period 5 1 2 (3 ) 5 Cash and cash equivalents, end of period $ 4 $ 1 $ 1 $ (2 ) $ 4 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 5 $ 466 $ 14 $ (10 ) $ 475 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (2,113 ) — — (2,113 ) Acquisitions of proved and unproved properties — (88 ) — — (88 ) Proceeds from divestitures of proved and unproved properties — 1,249 — — 1,249 Additions to other property and equipment — (21 ) — — (21 ) Other investing activities — 55 — — 55 Net Cash Used In Investing Activities — (918 ) — — (918 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 7,771 — — — 7,771 Payments on revolving credit facility borrowings (6,990 ) — — — (6,990 ) Proceeds from issuance of senior notes, net 1,585 — — — 1,585 Cash paid to purchase debt (2,592 ) — — — (2,592 ) Cash paid for preferred stock dividends (183 ) — — — (183 ) Other financing activities (39 ) (5 ) (13 ) 32 (25 ) Intercompany advances, net (456 ) 456 — — — Net Cash Provided by (Used In) Financing Activities (904 ) 451 (13 ) 32 (434 ) Net increase (decrease) in cash and cash equivalents (899 ) (1 ) 1 22 (877 ) Cash and cash equivalents, beginning of period 904 2 1 (25 ) 882 Cash and cash equivalents, end of period $ 5 $ 1 $ 2 $ (3 ) $ 5

Basis of Presentation and Sum_4

Basis of Presentation and Summary of Significant Accounting Policies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)segment	Dec. 31, 2018USD ($)
Summary of Significant Accounting Policies [Table] [Line Items]
Number of reportable segments | segment	1
Bank overdrafts	$ 57	$ 104
Unamortized issuance costs, senior notes	$ 44	53
Revenue, payment terms	P30D
Employee
Summary of Significant Accounting Policies [Table] [Line Items]
Vesting period	3 years
Director
Summary of Significant Accounting Policies [Table] [Line Items]
Vesting period	3 years
Other noncurrent assets
Summary of Significant Accounting Policies [Table] [Line Items]
Unamortized issuance costs	$ 27	$ 30

Basis of Presentation and Sum_5

Basis of Presentation and Summary of Significant Accounting Policies - Oil, Natural Gas and NGL Transportation and Other Expenses Restated Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Summary of Significant Accounting Policies [Table] [Line Items]
Oil, natural gas and NGL	$ 474	$ 517
Severance and ad valorem taxes	189	134
Previously reported
Summary of Significant Accounting Policies [Table] [Line Items]
Oil, natural gas and NGL	539	562
Severance and ad valorem taxes	124	89
Restatement adjustment
Summary of Significant Accounting Policies [Table] [Line Items]
Oil, natural gas and NGL	(65)	(45)
Severance and ad valorem taxes	$ 65	$ 45

Change in Accounting Principl_2

Change in Accounting Principle - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Proved oil and natural gas properties	$ 30,765	$ 25,407
Unproved properties	2,173	1,561
Total Property and Equipment, at Cost	34,748	28,689
VIE. accumulated depreciation, depletion and amortization	(20,002)	(17,886)
Total Property and Equipment, Net	14,756	10,818
TOTAL ASSETS	16,193	12,735
Other current liabilities	1,432	1,599
Total Current Liabilities	2,392	2,887
Other long-term liabilities	125	219
Total Long-Term Liabilities	9,400	7,715
Accumulated deficit	(14,220)	(13,912)
Total Chesapeake Stockholders’ Equity	4,364	2,092
Noncontrolling interests	37	41
Total Equity	4,401	2,133	$ 1,943
TOTAL LIABILITIES AND EQUITY	16,193	12,735
As Previously Reported Under Full Cost
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Proved oil and natural gas properties	75,148	69,642
Unproved properties	3,203	2,337
Total Property and Equipment, at Cost	80,161	73,700
VIE. accumulated depreciation, depletion and amortization	(66,626)	(64,685)
Total Property and Equipment, Net	13,545	9,030
TOTAL ASSETS	14,982	10,947
Other current liabilities	1,377	1,540
Total Current Liabilities	2,337	2,828
Other long-term liabilities	116	156
Total Long-Term Liabilities	9,391	7,652
Accumulated deficit	(15,451)	(15,660)
Total Chesapeake Stockholders’ Equity	3,133	344
Noncontrolling interests	121	123
Total Equity	3,254	467	(372)
TOTAL LIABILITIES AND EQUITY	14,982	10,947
Successful Efforts Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Proved oil and natural gas properties	(44,383)	(44,235)
Unproved properties	(1,030)	(776)
Total Property and Equipment, at Cost	(45,413)	(45,011)
VIE. accumulated depreciation, depletion and amortization	46,624	46,799
Total Property and Equipment, Net	1,211	1,788
TOTAL ASSETS	1,211	1,788
Other current liabilities	55	59
Total Current Liabilities	55	59
Other long-term liabilities	9	63
Total Long-Term Liabilities	9	63
Accumulated deficit	1,231	1,748
Total Chesapeake Stockholders’ Equity	1,231	1,748
Noncontrolling interests	(84)	(82)
Total Equity	1,147	1,666	$ 2,315
TOTAL LIABILITIES AND EQUITY	$ 1,211	$ 1,788

Change in Accounting Principl_3

Change in Accounting Principle - Statements of Operations (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Income Statements, Captions [Line Items]
Revenues	$ 8,595	$ 10,030	$ 10,039
Gains (losses) on sales of assets	43	(264)	476
General and administrative	315	335	333
Depreciation, depletion and amortization	2,264	1,737	1,697
Gain on sale of oil and natural gas properties	0	0
Impairments	11	131	814
Other operating expense	92	0	416
Total Operating Expenses	8,626	9,648	10,177
Income from operations	(31)	382	(138)
Interest expense	(651)	(633)	(601)
Other income	39	67	6
Total Other Expense	(608)	(164)	(362)
INCOME (LOSS) BEFORE INCOME TAXES	(639)	218	(500)
NET INCOME (LOSS)	(308)	228	(502)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	0	(2)	(3)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(308)	226	(505)
Earnings allocated to participating securities	0	(1)	0
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$ (416)	$ 133	$ (631)
Earnings (loss) per common share basic (in usd per share)	$ (0.25)	$ 0.15	$ (0.70)
Earnings (loss) per common share diluted (in usd per share)	$ (0.25)	$ 0.15	$ (0.70)
Other
Condensed Income Statements, Captions [Line Items]
Revenues	$ 63	$ 63	$ 67
Exploration
Condensed Income Statements, Captions [Line Items]
Cost of goods and services	84	162	235
As Previously Reported Under Full Cost
Condensed Income Statements, Captions [Line Items]
Revenues	8,489	10,231	9,496
Gains (losses) on sales of assets	0	0	0
General and administrative	258	280	262
Depreciation, depletion and amortization	1,616	1,145	995
Gain on sale of oil and natural gas properties	(15)	578
Impairments	344	53	5
Other operating expense	94	10	413
Total Operating Expenses	8,157	9,349	8,357
Income from operations	332	882	1,139
Interest expense	(487)	(487)	(426)
Other income	31	70	9
Total Other Expense	(452)	(15)	(184)
INCOME (LOSS) BEFORE INCOME TAXES	(120)	867	955
NET INCOME (LOSS)	211	877	953
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(2)	(4)	(4)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	209	873	949
Earnings allocated to participating securities		(6)	(10)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$ 101	$ 775	$ 813
Earnings (loss) per common share basic (in usd per share)	$ 0.06	$ 0.85	$ 0.90
Earnings (loss) per common share diluted (in usd per share)	$ 0.06	$ 0.85	$ 0.90
As Previously Reported Under Full Cost | Other
Condensed Income Statements, Captions [Line Items]
Revenues	$ 0	$ 0	$ 0
As Previously Reported Under Full Cost | Exploration
Condensed Income Statements, Captions [Line Items]
Cost of goods and services	0	0	0
Successful Efforts Adjustment
Condensed Income Statements, Captions [Line Items]
Revenues	106	(201)	543
Gains (losses) on sales of assets	43	(264)	476
General and administrative	57	55	71
Depreciation, depletion and amortization	648	592	702
Gain on sale of oil and natural gas properties	15	(578)
Impairments	(333)	78	809
Other operating expense	(2)	(10)	3
Total Operating Expenses	469	299	1,820
Income from operations	(363)	(500)	(1,277)
Interest expense	(164)	(146)	(175)
Other income	8	(3)	(3)
Total Other Expense	(156)	(149)	(178)
INCOME (LOSS) BEFORE INCOME TAXES	(519)	(649)	(1,455)
NET INCOME (LOSS)	(519)	(649)	(1,455)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	2	2	1
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(517)	(647)	(1,454)
Earnings allocated to participating securities		5	10
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$ (517)	$ (642)	$ (1,444)
Earnings (loss) per common share basic (in usd per share)	$ (0.31)	$ (0.70)	$ (1.60)
Earnings (loss) per common share diluted (in usd per share)	$ (0.31)	$ (0.70)	$ (1.60)
Successful Efforts Adjustment | Other
Condensed Income Statements, Captions [Line Items]
Revenues	$ 63	$ 63	$ 67
Successful Efforts Adjustment | Exploration
Condensed Income Statements, Captions [Line Items]
Cost of goods and services	$ 84	$ 162	$ 235

Change in Accounting Principl_4

Change in Accounting Principle - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net income (loss)	$ (308)	$ 228	$ (502)
Comprehensive income (loss)	(273)	262	(463)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	0	(2)	(3)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(273)	260	(466)
As Previously Reported Under Full Cost
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net income (loss)	211	877	953
Comprehensive income (loss)	246	911	992
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(2)	(4)	(4)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	244	907	988
Successful Efforts Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net income (loss)	(519)	(649)	(1,455)
Comprehensive income (loss)	(519)	(649)	(1,455)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	2	2	1
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$ (517)	$ (647)	$ (1,454)

Change in Accounting Principl_5

Change in Accounting Principle - Statements of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Net income (loss)	$ (308)	$ 228	$ (502)
Depreciation, depletion and amortization	2,264	1,737	1,697
Loss on sale of oil and gas properties	0	0
(Gains) losses on sales of assets	(43)	264	(476)
Impairments	11	131	814
Exploration	49	96	214
Other	(4)	(118)	(132)
(Decrease) increase in accounts payable, accrued liabilities and other	(630)	75	(375)
Net Cash Provided By Operating Activities	1,623	1,730	475
Drilling and completion costs	(2,180)	(1,848)	(2,113)
Acquisitions of proved and unproved properties	(35)	(128)	(88)
Net Cash Provided By (Used In) Investing Activities	(2,480)	455	(918)
As Previously Reported Under Full Cost
Condensed Cash Flow Statements, Captions [Line Items]
Net income (loss)	211	877	953
Depreciation, depletion and amortization	1,616	1,145	995
Loss on sale of oil and gas properties	(15)	578
(Gains) losses on sales of assets	0	0	0
Impairments	344	53	5
Exploration	0	0	0
Other	(2)	(108)	(135)
(Decrease) increase in accounts payable, accrued liabilities and other	(567)	138	(308)
Net Cash Provided By Operating Activities	1,871	2,000	745
Drilling and completion costs	(2,260)	(1,958)	(2,186)
Acquisitions of proved and unproved properties	(203)	(288)	(285)
Net Cash Provided By (Used In) Investing Activities	(2,728)	185	(1,188)
Successful Efforts Adjustment
Condensed Cash Flow Statements, Captions [Line Items]
Net income (loss)	(519)	(649)	(1,455)
Depreciation, depletion and amortization	648	592	702
Loss on sale of oil and gas properties	15	(578)
(Gains) losses on sales of assets	(43)	264	(476)
Impairments	(333)	78	809
Exploration	49	96	214
Other	(2)	(10)	3
(Decrease) increase in accounts payable, accrued liabilities and other	(63)	(63)	(67)
Net Cash Provided By Operating Activities	(248)	(270)	(270)
Drilling and completion costs	80	110	73
Acquisitions of proved and unproved properties	168	160	197
Net Cash Provided By (Used In) Investing Activities	$ 248	$ 270	$ 270

Change in Accounting Principl_6

Change in Accounting Principle - Statements of Shareholders' Equity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Chesapeake stockholders’ equity, beginning of period	$ 2,092
Net income (loss) attributable to Chesapeake	(308)	$ 226	$ (505)
Chesapeake stockholders’ equity, end of period	4,364	2,092
Stockholders' equity attributable to noncontrolling interest, beginning of period	41
Net income attributable to noncontrolling interests	0	(2)	(3)
Stockholders' equity attributable to noncontrolling interest, end of period	37	41
TOTAL EQUITY	4,401	2,133	1,943
As Previously Reported Under Full Cost
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Chesapeake stockholders’ equity, beginning of period	344
Net income (loss) attributable to Chesapeake	209	873	949
Chesapeake stockholders’ equity, end of period	3,133	344
Stockholders' equity attributable to noncontrolling interest, beginning of period	123
Net income attributable to noncontrolling interests	(2)	(4)	(4)
Stockholders' equity attributable to noncontrolling interest, end of period	121	123
TOTAL EQUITY	3,254	467	(372)
Successful Efforts Adjustment
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Chesapeake stockholders’ equity, beginning of period	1,748
Net income (loss) attributable to Chesapeake	(517)	(647)	(1,454)
Chesapeake stockholders’ equity, end of period	1,231	1,748
Stockholders' equity attributable to noncontrolling interest, beginning of period	(82)
Net income attributable to noncontrolling interests	2	2	1
Stockholders' equity attributable to noncontrolling interest, end of period	(84)	(82)
TOTAL EQUITY	1,147	1,666	2,315
Retained earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Chesapeake stockholders’ equity, beginning of period	(13,912)	(14,130)	(13,625)
Net income (loss) attributable to Chesapeake	(308)	226	(505)
Chesapeake stockholders’ equity, end of period	(14,220)	(13,912)	(14,130)
Retained earnings | As Previously Reported Under Full Cost
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Chesapeake stockholders’ equity, beginning of period	(15,660)	(16,525)	(17,474)
Net income (loss) attributable to Chesapeake	209	873	949
Chesapeake stockholders’ equity, end of period	(15,451)	(15,660)	(16,525)
Retained earnings | Successful Efforts Adjustment
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Chesapeake stockholders’ equity, beginning of period	1,748	2,395	3,849
Net income (loss) attributable to Chesapeake	(517)	(647)	(1,454)
Chesapeake stockholders’ equity, end of period	1,231	1,748	2,395
Parent
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Chesapeake stockholders’ equity, beginning of period	2,092	1,899
Chesapeake stockholders’ equity, end of period	4,364	2,092	1,899
Parent | As Previously Reported Under Full Cost
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Chesapeake stockholders’ equity, beginning of period	344	(496)
Chesapeake stockholders’ equity, end of period	3,133	344	(496)
Parent | Successful Efforts Adjustment
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Chesapeake stockholders’ equity, beginning of period	1,748	2,395
Chesapeake stockholders’ equity, end of period	1,231	1,748	2,395
Noncontrolling Interest
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' equity attributable to noncontrolling interest, beginning of period	41	44	49
Net income attributable to noncontrolling interests	0	2	3
Stockholders' equity attributable to noncontrolling interest, end of period	37	41	44
Noncontrolling Interest | As Previously Reported Under Full Cost
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' equity attributable to noncontrolling interest, beginning of period	123	124	128
Net income attributable to noncontrolling interests	2	4	4
Stockholders' equity attributable to noncontrolling interest, end of period	121	123	124
Noncontrolling Interest | Successful Efforts Adjustment
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' equity attributable to noncontrolling interest, beginning of period	(82)	(80)	(79)
Net income attributable to noncontrolling interests	(2)	(2)	(1)
Stockholders' equity attributable to noncontrolling interest, end of period	$ (84)	$ (82)	$ (80)

Oil and Natural Gas Property _3

Oil and Natural Gas Property Transactions - Narrative (Details) shares in Millions, $ / Mcf in Millions, $ in Millions	Feb. 01, 2019USD ($)shares	Dec. 31, 2019USD ($)awell	Dec. 31, 2019USD ($)awellday$ / BTU$ / bbl	Dec. 31, 2018USD ($)awellday$ / BTU	Dec. 31, 2017USD ($)awell$ / Mcf
Business Acquisition [Line Items]
Revenues			$ 8,595	$ 10,030	$ 10,039
Proceeds from divestitures of proved and unproved properties			130	2,231	1,249
Gain (loss) on sale of oil and natural gas properties			$ 0	0
Consecutive trading days | day			5
Natural gas
Business Acquisition [Line Items]
Average sales price (in usd per unit) | $ / BTU			2.82
Mid-Continent
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				491
Gain (loss) on sale of oil and natural gas properties				$ 12
Area of land, net (in acres) | a				238,500
Productive gas wells, number of wells, net | well				3,200
Other properties
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				$ 37	350
Haynesville shale
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties					915
Gain (loss) on sale of oil and natural gas properties					$ 326
Area of land, net (in acres) | a					119,500
Productive gas wells, number of wells, net | well					576
Haynesville shale | Natural gas
Business Acquisition [Line Items]
Proved developed reserves (volume) | $ / Mcf					80
Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			$ 130
Gain (loss) on sale of oil and natural gas properties			$ 46
Utica shale | Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Area of land, gross (in acres) | a		1,500,000	1,500,000
Area of land, net (in acres) | a		900,000	900,000
Productive gas wells, number of wells, net | well		920	920
Consideration received		$ 1,868	$ 1,868
Utica shale | Disposal group, disposed of by sale, not discontinued operations | Synthetic gas
Business Acquisition [Line Items]
Net rentable area (in acres) | a		320,000	320,000
Future natural gas prices 2023 | Natural gas
Business Acquisition [Line Items]
Average sales price (in usd per unit) | $ / BTU			3
Future natural gas prices | Utica shale | Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Consideration received				$ 100
Period of trading days | day				20
Consecutive trading days | day				30
2022 NYMEX natural gas | Future natural gas prices 2023 | Utica shale | Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Average sales price (in usd per unit) | $ / BTU				3.25
2022 NYMEX natural gas | Future natural gas prices | Utica shale | Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Gain (loss) on sale of oil and natural gas properties			$ (273)
Consideration received				$ 50
2022 NYMEX natural gas | Future natural gas prices 2022 | Utica shale | Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Average sales price (in usd per unit) | $ / BTU				3
Wildhorse resource development corporation
Business Acquisition [Line Items]
Common stock issued in the merger (in shares) | shares	717.4
Cash	$ 381
Revenues		$ 752
Operating expenses		810
Other expenses		$ 83
Energy related derivative | Oil
Business Acquisition [Line Items]
Average sales price (in usd per unit) | $ / bbl			56.33
Energy related derivative | Future NYMEX oil prices 2023 | Oil
Business Acquisition [Line Items]
Average sales price (in usd per unit) | $ / bbl			61.17

Oil and Natural Gas Property _4

Oil and Natural Gas Property Transactions - Purchase Price Allocation (Details) $ / shares in Units, $ in Millions	Feb. 01, 2019USD ($)$ / sharesshares
Fair Value of Assets Acquired:
Common shares, outstanding (in shares) | shares	717,376,170
Share price (in usd per share) | $ / shares	$ 2.84
Wildhorse resource development corporation
Consideration:
Cash	$ 381
Fair value of Chesapeake’s common stock issued in the Merger	2,037
Total consideration	2,418
Fair Value of Liabilities Assumed:
Current liabilities	166
Long-term debt	1,379
Deferred tax liabilities	314
Other long-term liabilities	36
Amounts attributable to liabilities assumed	1,895
Fair Value of Assets Acquired:
Cash and cash equivalents	28
Other current assets	128
Proved oil and natural gas properties	3,264
Unproved properties	756
Other property and equipment	77
Other long-term assets	60
Amounts attributable to assets acquired	4,313
Total identifiable net assets	$ 2,418

Oil and Natural Gas Property _5

Oil and Natural Gas Property Transactions - Pro Forma Financial Information (Details) - Wildhorse resource development corporation - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Revenues	$ 8,587	$ 11,211
Net income (loss) available to common stockholders	$ (431)	$ 195
Earnings per common share, basic (in usd per share)	$ (0.26)	$ 0.12
Earnings per common share, diluted (in usd per share)	$ (0.26)	$ 0.12

Earnings Per Share - Antidiluti

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Convertible preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	1	0	1
Convertible debt securities
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	124	146	146
Restricted stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	0	1	1
Preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	58	60	60

Debt - Long-Term Debt (Details)

Debt - Long-Term Debt (Details)	12 Months Ended
	Dec. 31, 2019USD ($)day$ / shares	Dec. 31, 2018USD ($)	Feb. 01, 2019
Long-term Debt [Abstract]
Principal Amount	$ 8,916,000,000	$ 8,168,000,000
Carrying Amount	9,458,000,000	7,722,000,000
Debt issuance costs	(44,000,000)	(53,000,000)
Current maturities of long-term debt, gross	(385,000,000)	(381,000,000)
Current maturities of long-term debt, net	(385,000,000)	(381,000,000)
Long-term debt, net	8,531,000,000	7,787,000,000
Long-term debt, net	$ 9,073,000,000	7,341,000,000
Consecutive trading days | day	5
Interest Rate Contract
Long-term Debt [Abstract]
Principal Amount	$ 0	0
Interest rate derivatives	0	1,000,000
6.625% Senior Notes Due 2020, 4.875% Senior Notes Due 2022, and 5.75% Senior Notes Due 2023
Long-term Debt [Abstract]
Principal Amount	101,000,000
Revolving credit facility | Chesapeake revolving credit facility
Long-term Debt [Abstract]
Principal Amount	1,590,000,000	419,000,000
Revolving credit facility	1,590,000,000	419,000,000
Term loan
Long-term Debt [Abstract]
Principal Amount	1,500,000,000	0
Carrying Amount	$ 1,470,000,000	0
Debt issuance costs		$ (13,000,000)
Senior notes
Long-term Debt [Abstract]
Redemption price percentage	35.00%	35.00%
Percentage of principal amount redeemed	100.00%	100.00%
Senior notes | 11.5% senior secured second lien notes due 2025
Long-term Debt [Abstract]
Principal Amount	$ 2,330,000,000	$ 0
Carrying Amount	$ 3,248,000,000	0
Interest rate, stated percentage	11.50%
Senior notes | Floating rate senior notes due 2019
Long-term Debt [Abstract]
Principal Amount	$ 0	380,000,000
Carrying Amount	0	380,000,000
Senior notes | 6.625% senior notes due 2020
Long-term Debt [Abstract]
Principal Amount	208,000,000	437,000,000
Carrying Amount	$ 208,000,000	437,000,000
Interest rate, stated percentage	6.625%
Senior notes | 6.875% senior notes due 2020
Long-term Debt [Abstract]
Principal Amount	$ 93,000,000	227,000,000
Carrying Amount	$ 93,000,000	227,000,000
Interest rate, stated percentage	6.875%
Senior notes | 6.125% senior notes due 2021
Long-term Debt [Abstract]
Principal Amount	$ 167,000,000	548,000,000
Carrying Amount	$ 167,000,000	548,000,000
Interest rate, stated percentage	6.125%
Senior notes | 5.375% senior notes due 2021
Long-term Debt [Abstract]
Principal Amount	$ 127,000,000	267,000,000
Carrying Amount	$ 127,000,000	267,000,000
Interest rate, stated percentage	5.375%
Senior notes | 4.875% Senior Notes due 2022
Long-term Debt [Abstract]
Principal Amount	$ 338,000,000	451,000,000
Carrying Amount	$ 338,000,000	451,000,000
Interest rate, stated percentage	4.875%
Senior notes | 5.75% Senior Notes due 2023
Long-term Debt [Abstract]
Principal Amount	$ 209,000,000	338,000,000
Carrying Amount	$ 209,000,000	338,000,000
Interest rate, stated percentage	5.75%
Senior notes | 7.00% senior notes due 2024
Long-term Debt [Abstract]
Principal Amount	$ 624,000,000	850,000,000
Carrying Amount	$ 624,000,000	$ 850,000,000
Interest rate, stated percentage	7.00%	7.00%
Senior notes | 6.875% senior notes due 2025
Long-term Debt [Abstract]
Principal Amount	$ 2,000,000	$ 0
Carrying Amount	$ 2,000,000	0
Interest rate, stated percentage	6.875%		6.875%
Senior notes | 8.00% senior notes due 2025
Long-term Debt [Abstract]
Principal Amount	$ 246,000,000	1,300,000,000
Carrying Amount	$ 245,000,000	1,291,000,000
Interest rate, stated percentage	8.00%
Senior notes | 7.5% senior notes due 2026
Long-term Debt [Abstract]
Principal Amount	$ 119,000,000	400,000,000
Carrying Amount	$ 119,000,000	$ 400,000,000
Interest rate, stated percentage	7.50%	7.50%
Senior notes | 8.00% senior notes due 2026
Long-term Debt [Abstract]
Principal Amount	$ 46,000,000	$ 0
Carrying Amount	44,000,000	0
Revolving credit facility	$ 919,000,000
Interest rate, stated percentage	8.00%
Senior notes | 8.00% senior notes due 2027
Long-term Debt [Abstract]
Principal Amount	$ 253,000,000	1,300,000,000
Carrying Amount	$ 253,000,000	1,299,000,000
Interest rate, stated percentage	8.00%
Convertible debt | 5.5% convertible senior notes due 2026
Long-term Debt [Abstract]
Principal Amount	$ 1,064,000,000	1,250,000,000
Carrying Amount	$ 765,000,000	866,000,000
Interest rate, stated percentage	5.50%
Interest rate, effective percentage	11.50%
Convertible debt | 5.5% convertible senior notes due 2026 | Optional Conversion by Holders
Long-term Debt [Abstract]
Threshold percentage of stock price trigger	130.00%
Conversion price (in usd per share) | $ / shares	$ 8.568
Percentage of principal amount redeemed	100.00%
Convertible debt | 5.5% convertible senior notes due 2026 | Optional Redemption by the Company
Long-term Debt [Abstract]
Threshold percentage of stock price trigger	130.00%
Redemption price percentage	100.00%
Convertible debt | 2.25% contingent convertible senior notes due 2038
Long-term Debt [Abstract]
Principal Amount	$ 0	1,000,000
Carrying Amount	$ 0	1,000,000
Interest rate, stated percentage	2.25%
Interest rate, effective percentage	8.00%
Convertible debt | All convertible and all contingent convertible debt
Long-term Debt [Abstract]
Unamortized discount	$ 299,000,000	$ 384,000,000

Debt - Debt Maturities (Details

Debt - Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Long-term Debt, Fiscal Year Maturity [Abstract]
2020	$ 385
2021	294
2022	289
2023	1,764
2024	2,124
Thereafter	4,060
Principal Amount	$ 8,916	$ 8,168

Debt - Debt Issuances and Retir

Debt - Debt Issuances and Retirements (Details) - USD ($)	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2015	Dec. 17, 2018
Debt Instrument [Line Items]
Debt, principal	$ 8,916,000,000	$ 8,916,000,000	$ 8,916,000,000	$ 8,168,000,000
Gains (losses) on purchases or exchanges of debt			79,000,000	263,000,000	$ 235,000,000
Cash paid to purchase debt			1,073,000,000	2,813,000,000	2,592,000,000
Deferred charges	44,000,000	44,000,000	44,000,000	53,000,000
Gains (losses) on debt restructuring			75,000,000	$ 263,000,000	$ 233,000,000
Chesapeake senior notes
Debt Instrument [Line Items]
Gains (losses) on purchases or exchanges of debt		64,000,000
6.625% Senior Notes Due 2020, 4.875% Senior Notes Due 2022, and 5.75% Senior Notes Due 2023
Debt Instrument [Line Items]
Debt, principal	101,000,000	101,000,000	101,000,000
BVL Revolving Credit Facility
Debt Instrument [Line Items]
Gains (losses) on purchases or exchanges of debt			4,000,000
Existing Notes
Debt Instrument [Line Items]
Notes			3,152,000,000
Second Lien Notes
Debt Instrument [Line Items]
Notes			2,210,000,000
11.5% Senior Secured Second Lien Notes Due 2025
Debt Instrument [Line Items]
Debt, principal	$ 120,000,000	$ 120,000,000	$ 120,000,000
Debt, percent of par	89.75%
Interest rate, stated percentage	11.50%	11.50%	11.50%
Senior notes
Debt Instrument [Line Items]
Percentage of principal amount redeemed			100.00%	100.00%
Redemption price percentage			35.00%	35.00%
Repayments of senior debt		$ 380,000,000
Senior notes | 7.00% senior notes due 2024 and 7.50% senior notes due 2026
Debt Instrument [Line Items]
Proceeds from debt, net				$ 1,236,000,000
Senior notes | 7.00% senior notes due 2024
Debt Instrument [Line Items]
Debt, principal	$ 624,000,000	$ 624,000,000	$ 624,000,000	$ 850,000,000
Interest rate, stated percentage	7.00%	7.00%	7.00%	7.00%
Notes			$ 226,000,000
Senior notes | 7.5% senior notes due 2026
Debt Instrument [Line Items]
Debt, principal	$ 119,000,000	$ 119,000,000	$ 119,000,000	$ 400,000,000
Interest rate, stated percentage	7.50%	7.50%	7.50%	7.50%
Notes			$ 281,000,000
Senior notes | 8.00% senior secured second lien notes due 2022
Debt Instrument [Line Items]
Debt, principal				$ 1,416,000,000
Interest rate, stated percentage	8.00%	8.00%	8.00%
Debt repurchased amount	$ 1,477,000,000	$ 1,477,000,000	$ 1,477,000,000
Premium						$ 60,000,000
Gains (losses) on repurchases of debt						331,000,000
Gains (losses) on debt restructuring						$ 391,000,000
Senior notes | 7.25% senior notes due 2018
Debt Instrument [Line Items]
Interest rate, stated percentage	7.25%	7.25%	7.25%
Debt repurchased amount	$ 44,000,000	$ 44,000,000	$ 44,000,000
Senior notes | Chesapeake senior notes
Debt Instrument [Line Items]
Revolving credit facility	507,000,000	$ 507,000,000	507,000,000
Conversation of common stock shares outstanding (in shares)		235,563,519
Senior notes | 8.00% senior notes due 2026
Debt Instrument [Line Items]
Debt, principal	$ 46,000,000	$ 46,000,000	$ 46,000,000	0
Interest rate, stated percentage	8.00%	8.00%	8.00%
Notes			$ 873,000,000
Revolving credit facility	$ 919,000,000	$ 919,000,000	919,000,000
Senior notes | 6.625% senior notes due 2020
Debt Instrument [Line Items]
Debt, principal	$ 208,000,000	$ 208,000,000	$ 208,000,000	437,000,000
Interest rate, stated percentage	6.625%	6.625%	6.625%
Notes			$ 229,000,000
Senior notes | 4.875% Senior Notes due 2022
Debt Instrument [Line Items]
Debt, principal	$ 338,000,000	$ 338,000,000	$ 338,000,000	451,000,000
Interest rate, stated percentage	4.875%	4.875%	4.875%
Senior notes | 5.75% Senior Notes due 2023
Debt Instrument [Line Items]
Debt, principal	$ 209,000,000	$ 209,000,000	$ 209,000,000	338,000,000
Interest rate, stated percentage	5.75%	5.75%	5.75%
Convertible debt | 2.25% contingent convertible senior notes due 2038
Debt Instrument [Line Items]
Debt, principal	$ 0	$ 0	$ 0	1,000,000
Interest rate, stated percentage	2.25%	2.25%	2.25%
Debt repurchased amount							$ 8,000,000
Convertible debt | Chesapeake senior notes
Debt Instrument [Line Items]
Revolving credit facility	$ 186,000,000	$ 186,000,000	$ 186,000,000
Conversation of common stock shares outstanding (in shares)		73,389,094
Term loan
Debt Instrument [Line Items]
Debt term	4 years 6 months
Debt, principal	$ 1,500,000,000	$ 1,500,000,000	$ 1,500,000,000	0
Proceeds from debt, net	$ 1,455,000,000
Debt repurchased amount				1,233,000,000
Cash paid to purchase debt				1,285,000,000
Premium				52,000,000
Gains (losses) on repurchases of debt				(65,000,000)
Deferred charges				$ 13,000,000
Term loan | London interbank offered rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate	8.00%
Term loan | LIBOR Floor
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
Term loan | Alternative base rate (ABR)
Debt Instrument [Line Items]
Basis spread on variable rate	7.00%
Debt, percent of par	98.00%
Debt, premium of par	5.00%	5.00%	5.00%
Debt, premium of par	2.50%	2.50%	2.50%
Debt Instrument, Covenant, Principal Balance	$ 125,000,000	$ 125,000,000	$ 125,000,000
Term loan | Alternative Base Rate (ABR) Floor
Debt Instrument [Line Items]
Basis spread on variable rate	2.00%

Debt - Conversion (Details)

Debt - Conversion (Details) - Senior notes - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
7.00% Senior Notes Due 2024, 8.00% Senior Notes Due 2025, 8.00% Senior Notes Due 2026, 7.5% Senior Notes Due 2026, and 8.00% Senior Notes Due 2027
Debt Instrument [Line Items]
Notes	$ 3,216
7.00% senior notes due 2024
Debt Instrument [Line Items]
Interest rate, stated percentage	7.00%	7.00%
Notes	$ 226
8.00% senior notes due 2025
Debt Instrument [Line Items]
Notes	$ 999
8.00% senior notes due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage	8.00%
Notes	$ 873
7.5% senior notes due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage	7.50%	7.50%
Notes	$ 281
8.00% senior notes due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	8.00%
Notes	$ 837
6.625% Senior Notes Due 2020, 6.875% Senior Notes Due 2020, 6.125% Senior Notes Due 2021, And 5.375% Senior Notes Due 2021
Debt Instrument [Line Items]
Notes	$ 884
6.625% senior notes due 2020
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%
Notes	$ 229
6.875% senior notes due 2020
Debt Instrument [Line Items]
Interest rate, stated percentage	6.875%
Notes	$ 134
6.125% senior notes due 2021
Debt Instrument [Line Items]
Interest rate, stated percentage	6.125%
Notes	$ 381
5.375% senior notes due 2021
Debt Instrument [Line Items]
Interest rate, stated percentage	5.375%
Notes	$ 140

Debt - Senior Notes and Convert

Debt - Senior Notes and Convertible Senior Notes (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Debt, principal	$ 8,916,000,000	$ 8,168,000,000
Minimum | Convertible debt
Debt Instrument [Line Items]
Debt, principal	50,000,000
Maximum | Convertible debt
Debt Instrument [Line Items]
Debt, principal	$ 75,000,000

Debt - Revolving Credit Facilit

Debt - Revolving Credit Facility (Details)	Dec. 03, 2019USD ($)	Dec. 31, 2019USD ($)	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Dec. 02, 2019USD ($)	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
Debt, principal		$ 8,916,000,000					$ 8,168,000,000
Chesapeake revolving credit facility
Debt Instrument [Line Items]
Revolving credit, current borrowing capacity		3,000,000,000
Revolving credit, maximum borrowing capacity		4,000,000,000
Revolving credit, outstanding		59,000,000
Chesapeake revolving credit facility | Revolving credit facility
Debt Instrument [Line Items]
Debt, principal		$ 1,590,000,000					$ 419,000,000
Alternative base rate (ABR) | Chesapeake revolving credit facility | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate		2.50%
Alternative base rate (ABR) | Chesapeake revolving credit facility | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate		1.50%
London interbank offered rate (LIBOR) | Chesapeake revolving credit facility | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate		3.50%
London interbank offered rate (LIBOR) | Chesapeake revolving credit facility | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate		2.50%
Chesapeake Revolving Credit Facility | Chesapeake revolving credit facility
Debt Instrument [Line Items]
Revolving credit, maximum borrowing capacity	$ 1,500,000,000					$ 1,000,000,000
Reduction in borrowing rate	25.00%
Applicable margin increase	0.01
Required liquidity	$ 250,000,000
Leverage ratio	2.50
Asset sales excess, threshold	$ 50,000,000
Forecast | Chesapeake Revolving Credit Facility | Chesapeake revolving credit facility
Debt Instrument [Line Items]
Leverage ratio			4	4.25	4.50

Debt - Fair Value of Debt (Deta

Debt - Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 8,531	$ 7,787
Carrying amount | Fair value, inputs, level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term debt	385	381
Long-term debt	753	3,495
Carrying amount | Fair value, inputs, level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	8,320	3,846
Estimated fair value | Fair value, inputs, level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term debt	360	379
Long-term debt	622	3,173
Estimated fair value | Fair value, inputs, level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 6,085	$ 3,644

Contingencies and Commitments -

Contingencies and Commitments - Narrative (Details) - USD ($)	Aug. 28, 2019	Feb. 28, 2019	Jul. 24, 2018	Aug. 09, 2018
Loss Contingencies [Line Items]
Settlement amount				$ 36,000,000
Chaparral energy, inc. | Healthcare of ontario pension plan (HOOPP) | Pending litigation
Loss Contingencies [Line Items]
Damages sought, value			$ 215,000,000
FTS international, inc. | FTS International, Inc. Case | Pending litigation
Loss Contingencies [Line Items]
Damages sought, value		$ 1,000,000
Chesapeake Appalachia, L.L.C. | Pennsylvania Department of Environmental Protection | Settled Litigation
Loss Contingencies [Line Items]
Settlement amount	$ 100,000

Contingencies and Commitments_2

Contingencies and Commitments - Gathering, Processing and Transportation Agreements and Service Contract (Details) $ in Millions	Dec. 31, 2019USD ($)
Gathering, Processing and Transportation Agreement
Other Commitment, Fiscal Year Maturity [Abstract]
2020	$ 1,136
2021	1,033
2022	913
2023	789
2024	690
2025 – 2034	3,479
Total	8,040
Service Contract
Other Commitment, Fiscal Year Maturity [Abstract]
2020	7
2021	7
2022	2
Total	$ 16

Other Liabilities - Current Tab

Other Liabilities - Current Table (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
Revenues and royalties due others	$ 516	$ 687
Accrued drilling and production costs	326	258
Joint interest prepayments received	52	73
VPP deferred revenue	55	59
Accrued compensation and benefits	156	202
Other accrued taxes	150	108
Other	177	212
Total other current liabilities	$ 1,432	$ 1,599

Other Liabilities - Long-Term T

Other Liabilities - Long-Term Table (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
VPP deferred revenue	$ 9	$ 63
Unrecognized tax benefits(b)	0	53
Other	116	103
Total other long-term liabilities	$ 125	$ 219

Leases - Narrative (Details)

Leases - Narrative (Details) $ in Millions	Feb. 01, 2019USD ($)contract	Dec. 31, 2019USD ($)	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Operating lease liability		$ 25
Operating lease, right-of-use asset		$ 22
Compressor | Midcon Compression, L.L.C.
Lessee, Lease, Description [Line Items]
Lease terms			38 months
Wildhorse resource development corporation
Lessee, Lease, Description [Line Items]
Operating lease liability	$ 40
Operating lease, right-of-use asset	38
Lease incentive	$ 2
Number of leases | contract	2
Minimum
Lessee, Lease, Description [Line Items]
Lease, remaining lease term		1 month
Maximum
Lessee, Lease, Description [Line Items]
Lease, remaining lease term		7 years

Leases - ROU Assets and Liabili

Leases - ROU Assets and Liabilities (Details) $ in Millions	Dec. 31, 2019USD ($)
Assets and Liabilities, Lessee [Abstract]
Finance, ROU assets	$ 17
Finance, current lease liabilities	9
Finance, long-term lease liabilities	9
Finance, present value of lease liabilities	18
Operating, ROU assets	22
Operating, current lease liabilities	9
Operating, long-term lease liabilities	16
Operating, present value of lease liabilities	$ 25

Leases - Additional information

Leases - Additional information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Amortization of ROU assets	$ 8
Interest on lease liability	2
Finance lease cost	10
Operating lease cost	26
Short-term lease cost	112
Total lease cost	148
Other information:
Operating cash outflows from finance lease	2
Operating cash outflows from operating leases	11
Investing cash outflows from operating leases	127
Financing cash outflows from finance lease	$ 8
Weighted average remaining lease term - finance lease	2 years
Weighted average remaining lease term - operating leases	4 years 7 months 24 days
Weighted average discount rate - finance lease	7.50%
Weighted average discount rate - operating leases	4.85%

Leases - Maturity Analysis of F

Leases - Maturity Analysis of Finance and Operating Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Finance Leases, After Adoption of 842:
2020	$ 10
2021	10
2022	0
2023	0
2024	0
Thereafter	0
Total lease payments	20
Less imputed interest	(2)
Finance, present value of lease liabilities	18
Less current maturities	(9)
Present value of lease liabilities, less current maturities	9
Operating Leases, After Adoption of 842:
2020	10
2021	5
2022	4
2023	2
2024	2
Thereafter	5
Total lease payments	28
Less imputed interest	(3)
Operating, present value of lease liabilities	25
Less current maturities	(9)
Present value of lease liabilities, less current maturities	$ 16
Capital Leases, Before Adoption of 842:
2019		$ 10
2020		10
2021		10
Total minimum lease payments		30
Operating Leases, After Adoption of 842:
2019		3
2020		1
2021		0
Total minimum lease payments		$ 4

Revenue Recognition - Additiona

Revenue Recognition - Additional Information (Details) - Retained earnings - USD ($) $ in Millions	Jan. 01, 2019	Jan. 01, 2018	Jan. 01, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cumulative effect of change in accounting principle	$ 0	$ 8	$ 0
ASU 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cumulative effect of change in accounting principle		$ 8

Revenue Recognition - Disaggreg

Revenue Recognition - Disaggregated Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 4,517	$ 5,189
Gains (losses) on oil, natural gas and NGL derivatives	5	(34)
Total oil, natural gas and NGL revenues	8,595	10,030	$ 10,039
Marcellus
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	856	924
Haynesville
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	620	838
Eagle Ford
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,561	1,872
Brazos valley
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	769
Powder River Basin
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	478	350
Mid-Continent
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	233	385
Utica
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		820
Oil
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,543	2,201
Gains (losses) on oil, natural gas and NGL derivatives	(212)	124
Oil | Marcellus
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Oil | Haynesville
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	2
Oil | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,289	1,514
Oil | Brazos valley
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	721
Oil | Powder River Basin
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	369	244
Oil | Mid-Continent
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	164	246
Oil | Utica
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		195
Natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,782	2,486
Gains (losses) on oil, natural gas and NGL derivatives	217	(147)
Natural gas | Marcellus
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	856	924
Natural gas | Haynesville
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	620	836
Natural gas | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	153	173
Natural gas | Brazos valley
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	32
Natural gas | Powder River Basin
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	77	68
Natural gas | Mid-Continent
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	44	84
Natural gas | Utica
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		401
NGL
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	192	502
Gains (losses) on oil, natural gas and NGL derivatives	0	(11)
NGL | Marcellus
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
NGL | Haynesville
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
NGL | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	119	185
NGL | Brazos valley
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	16
NGL | Powder River Basin
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	32	38
NGL | Mid-Continent
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	25	55
NGL | Utica
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		224
Oil, Natural Gas and NGL
Disaggregation of Revenue [Line Items]
Total oil, natural gas and NGL revenues	4,522	5,155	$ 4,985
Oil, Natural Gas and NGL | Oil
Disaggregation of Revenue [Line Items]
Total oil, natural gas and NGL revenues	2,331	2,325
Oil, Natural Gas and NGL | Natural gas
Disaggregation of Revenue [Line Items]
Total oil, natural gas and NGL revenues	1,999	2,339
Oil, Natural Gas and NGL | NGL
Disaggregation of Revenue [Line Items]
Total oil, natural gas and NGL revenues	192	491
Marketing
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	3,619	4,390
Gains (losses) on oil, natural gas and NGL derivatives	(4)	7
Total oil, natural gas and NGL revenues	3,967	5,076
Marketing | Oil
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,473	2,740
Gains (losses) on oil, natural gas and NGL derivatives	0	0
Total oil, natural gas and NGL revenues	2,784	3,197
Marketing | Natural gas
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	900	1,194
Gains (losses) on oil, natural gas and NGL derivatives	(4)	7
Total oil, natural gas and NGL revenues	937	1,423
Marketing | NGL
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	246	456
Gains (losses) on oil, natural gas and NGL derivatives	0	0
Total oil, natural gas and NGL revenues	246	456
Other marketing revenue
Disaggregation of Revenue [Line Items]
Total oil, natural gas and NGL revenues	352	679
Other marketing revenue | Oil
Disaggregation of Revenue [Line Items]
Total oil, natural gas and NGL revenues	311	457
Other marketing revenue | Natural gas
Disaggregation of Revenue [Line Items]
Total oil, natural gas and NGL revenues	41	222
Other marketing revenue | NGL
Disaggregation of Revenue [Line Items]
Total oil, natural gas and NGL revenues	$ 0	$ 0

Revenue Recognition - Accounts

Revenue Recognition - Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Allowance for doubtful accounts	$ (21)	$ (17)
Total accounts receivable, net	990	1,247
Oil, natural gas and NGL sales
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	737	976
Joint interest billings
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	200	211
Other
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	$ 74	$ 77

Income Taxes - Income Tax Prov

Income Taxes - Income Tax Provision (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current
Federal	$ 0	$ 0	$ (14)
State	(26)	0	5
Current Income Taxes	(26)	0	(9)
Deferred
Federal	(297)	3	13
State	(8)	(13)	(2)
Deferred Income Taxes	(305)	(10)	11
Total Income Tax Expense (Benefit)	$ (331)	$ (10)	$ 2

Income Taxes - Effective Income

Income Taxes - Effective Income Tax Expense (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Federal statutory rate	21.00%	21.00%	35.00%
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax expense (benefit) at the federal statutory rate (21%, 21%, 35%)	$ (134)	$ 45	$ (175)
State income taxes (net of federal income tax benefit)	(21)	27	5
Partial release of valuation allowance due to the WildHorse Merger	(314)	0	0
Remeasurement of deferred tax assets and liabilities	0	0	931
Change in valuation allowance excluding impact of WildHorse Merger	114	(97)	(771)
Other	24	15	12
Total Income Tax Expense (Benefit)	$ (331)	$ (10)	$ 2

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Feb. 01, 2019	Dec. 31, 2016
Income Taxes Summary [Line Items]
Deferred tax assets, valuation allowance, increase (decrease)		$ 206
Change in valuation allowance		200
Net operating loss carryforwards		1,971	$ 2,737
Deferred tax assets		2,449	3,231
Deferred tax assets, valuation allowance		1,805	2,011
Income tax benefit		(331)	(10)	$ 2
Unrecognized tax benefits		74	79	106		$ 202
Unrecognized tax benefits, liabilities with taxing authorities		32	0	$ 100
Uncertain tax positions that would impact effective tax rate		29
Unrecognized tax benefits, accrued liabilities			20
Federal
Income Taxes Summary [Line Items]
NOL carryforward		7,582
Net operating loss carryforwards		1,592
State and local
Income Taxes Summary [Line Items]
NOL carryforward		6,844
Net operating loss carryforwards		379
Unrecognized tax benefits, receivables with taxing authorities		29	29
Unrecognized tax benefits, liabilities with taxing authorities			$ 32
Wildhorse resource development corporation
Income Taxes Summary [Line Items]
Deferred tax liabilities					$ 314
Income tax benefit	$ 314
Deferred tax liability, plant, property and equipment and prepaid compensation	401
Deferred tax assets, operating loss carryforward, limitations		61
Wildhorse resource development corporation | Federal
Income Taxes Summary [Line Items]
Net operating loss carryforwards	$ 87
Income tax expense (benefit)
Income Taxes Summary [Line Items]
Change in valuation allowance		$ 200

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities Table (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred tax liabilities:
Property, plant and equipment	$ (546)	$ (976)
Volumetric production payments	(89)	(86)
Carrying value of debt	0	(95)
Derivative instruments	(14)	(56)
Other	(5)	(7)
Deferred tax liabilities	(654)	(1,220)
Deferred tax assets:
Net operating loss carryforwards	1,971	2,737
Carrying value of debt	169	0
Disallowed business interest carryforward	25	194
Asset retirement obligations	50	40
Investments	83	111
Accrued liabilities	64	89
Other	87	60
Deferred tax assets	2,449	3,231
Valuation allowance	(1,805)	(2,011)
Deferred tax assets after valuation allowance	644	1,220
Net deferred tax liability	$ (10)	$ 0

Income Taxes - Unrecognized Ta

Income Taxes - Unrecognized Tax Benefits Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits at beginning of period	$ 79	$ 106	$ 202
Additions based on tax positions related to the current year	0	0	0
Additions to tax positions of prior years	27	0	4
Settlements	(32)	0	(100)
Expiration of the applicable statute of limitations	0	(23)	0
Reductions to tax positions of prior years	0	(4)	0
Unrecognized tax benefits at end of period	$ 74	$ 79	$ 106

Equity - Common Stock (Details)

Equity - Common Stock (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common stock, shares issued, beginning of period (in shares)	913,715,512	908,733,000	896,279,000
Restricted stock issuances (net of forfeitures and cancellations) (in shares)	4,146,000	4,983,000	2,488,000
Common stock, shares issued, end of period (in shares)	1,954,558,617	913,715,512	908,733,000
Common stock, shares authorized (in shares)	3,000,000,000	2,000,000,000
Common Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common shares issued for WildHorse Merger (in shares)	$ 7,000	$ 0	$ 0
Common Stock | Senior notes exchanged for shares of common stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock issued, conversion (in shares)	235,564,000	0	0
Common Stock | Convertible notes exchanged for shares of common stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock issued, conversion (in shares)	73,389,000	0	0
Common Stock | Preferred stock exchanged for shares of common stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock issued, conversion (in shares)	10,367,950	0	9,966,000
Wildhorse resource development corporation
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common shares issued for WildHorse Merger (in shares)	$ 717,376	$ 0	$ 0

Equity - Preferred Stock Conver

Equity - Preferred Stock Conversion Terms (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2017
5.75% cumulative convertible preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate	5.75%	5.75%
5.75% cumulative convertible preferred stock series A
Class of Stock [Line Items]
Preferred stock, dividend rate	5.75%	5.75%
4.50% cumulative convertible preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate	4.50%
5.00% cumulative convertible preferred stock series 2005 B
Class of Stock [Line Items]
Preferred stock, dividend rate	5.00%	5.00%
Preferred stock | 5.75% cumulative convertible preferred stock
Class of Stock [Line Items]
Liquidation Preference per Share (in usd per share)	$ 1,000
Conversion Rate	39.6858%
Conversion Price (in usd per share)	$ 25.1979
Company's Market Conversion Trigger (in usd per share)	32.7573
Preferred stock | 5.75% cumulative convertible preferred stock series A
Class of Stock [Line Items]
Liquidation Preference per Share (in usd per share)	$ 1,000
Conversion Rate	38.3508%
Conversion Price (in usd per share)	$ 26.0751
Company's Market Conversion Trigger (in usd per share)	$ 33.8976
Preferred stock, dividend rate	5.75%
Preferred stock | 4.50% cumulative convertible preferred stock
Class of Stock [Line Items]
Liquidation Preference per Share (in usd per share)	$ 100
Conversion Rate	2.4561%
Conversion Price (in usd per share)	$ 40.7152
Company's Market Conversion Trigger (in usd per share)	52.9298
Preferred stock | 5.00% cumulative convertible preferred stock series 2005 B
Class of Stock [Line Items]
Liquidation Preference per Share (in usd per share)	$ 100
Conversion Rate	2.7745%
Conversion Price (in usd per share)	$ 36.0431
Company's Market Conversion Trigger (in usd per share)	$ 46.8560
Preferred stock | Minimum | 4.50% or 5.00% (series 2005B) cumulative convertible preferred stock
Class of Stock [Line Items]
Conversion of stock, market trigger (in shares)	250,000
Preferred stock | Minimum | 5.75% or 5.75% (Series A) preferred stock
Class of Stock [Line Items]
Conversion of stock, market trigger (in shares)	25,000

Equity - Preferred Stock and Di

Equity - Preferred Stock and Dividends (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock, shares outstanding, beginning of period (in shares)	5,603,458
Preferred stock, shares outstanding, end of period (in shares)	5,563,458	5,603,458
Loss on exchange of preferred stock	$ 17	$ 0	$ 41
5.75% cumulative convertible preferred stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock, shares outstanding, beginning of period (in shares)	770,000	770,000	843,000
Preferred stock, shares outstanding, end of period (in shares)	770,000	770,000	770,000
Preferred stock, dividend rate	5.75%		5.75%
5.75% cumulative convertible preferred stock series A
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock, shares outstanding, beginning of period (in shares)	463,000	463,000	476,000
Preferred stock, shares outstanding, end of period (in shares)	423,000	463,000	463,000
Preferred stock, dividend rate	5.75%		5.75%
4.50% cumulative convertible preferred stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock, shares outstanding, beginning of period (in shares)	2,559,000	2,559,000	2,559,000
Preferred stock, shares outstanding, end of period (in shares)	2,559,000	2,559,000	2,559,000
Preferred stock, dividend rate	4.50%
5.00% cumulative convertible preferred stock series 2005 B
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock, shares outstanding, beginning of period (in shares)	1,811,000	1,811,000	1,962,000
Preferred stock, shares outstanding, end of period (in shares)	1,811,000	1,811,000	1,811,000
Preferred stock, dividend rate	5.00%		5.00%
Preferred stock | 5.75% cumulative convertible preferred stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock, shares outstanding, beginning of period (in shares)		770,000
Preferred stock exchanges (in shares)	0		(72,600)
Preferred stock, shares outstanding, end of period (in shares)			770,000
Preferred stock | 5.75% cumulative convertible preferred stock series A
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock, shares outstanding, beginning of period (in shares)		463,000
Preferred stock exchanges (in shares)	(40,000)		(12,500)
Preferred stock, shares outstanding, end of period (in shares)			463,000
Stock issued, conversion (in shares)	40,000
Preferred stock, dividend rate	5.75%
Preferred stock | 4.50% cumulative convertible preferred stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock, shares outstanding, beginning of period (in shares)		2,559,000
Preferred stock exchanges (in shares)	0		0
Preferred stock, shares outstanding, end of period (in shares)			2,559,000
Preferred stock | 5.00% cumulative convertible preferred stock series 2005 B
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock, shares outstanding, beginning of period (in shares)		1,811,000
Preferred stock exchanges (in shares)	0		(150,948)
Preferred stock, shares outstanding, end of period (in shares)			1,811,000
Common Stock | 5.75% cumulative convertible preferred stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock issued, conversion (in shares)			7,442,156
Common Stock | 5.75% cumulative convertible preferred stock series A
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock issued, conversion (in shares)			1,205,923
Common Stock | 5.00% cumulative convertible preferred stock series 2005 B
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock issued, conversion (in shares)			1,317,756
Preferred stock exchanged for shares of common stock | Preferred stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Preferred stock exchanges (in shares)	(40,000)	0	(236,048)
Preferred stock exchanged for shares of common stock | Common Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock issued, conversion (in shares)	10,367,950	0	9,966,000

Equity - Dividends (Details)

Equity - Dividends (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2017
5.00% cumulative convertible preferred stock series 2005 B
Class of Stock [Line Items]
Preferred stock, dividend rate	5.00%	5.00%
4.50% cumulative convertible preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate	4.50%
5.75% cumulative convertible preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate	5.75%	5.75%

Equity - AOCI Changes Net of Ta

Equity - AOCI Changes Net of Tax Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), beginning balance	$ 2,133	$ 1,943
Accumulated other comprehensive income (loss), ending balance	4,401	2,133
Accumulated net gain (loss) from cash flow hedges
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), beginning balance	(23)	(57)
Amounts reclassified from accumulated other comprehensive income	35	34
Accumulated other comprehensive income (loss), ending balance	$ 12	$ (23)

Equity - Noncontrolling Interes

Equity - Noncontrolling Interests Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Noncontrolling Interest [Line Items]
Noncontrolling interests	$ 37	$ 41
Net income attributable to noncontrolling interests	$ 0	$ 2	$ 3
Noncontrolling interest, chesapeake granite wash trust
Noncontrolling Interest [Line Items]
Common unit, outstanding (in units)	23,750,000
Beneficial interest percent	51.00%

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)vesting_periodshares	Dec. 31, 2018vesting_periodshares	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares authorized (in shares)	3,000,000,000	2,000,000,000
Restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value, vested | $	$ 15
Unrecognized compensation expense | $	$ 19
Unrecognized compensation expense, weighted average period of recognition	1 year 11 months 1 day
Share-based payment arrangement, option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense, weighted average period of recognition	1 year 2 months 23 days
Unrecognized compensation, stock options | $	$ 5
Share-based payment arrangement, option | Management
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years	3 years	3 years
Share-based payment arrangement, option | Management | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options expiration	7 years
Share-based payment arrangement, option | Management | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options expiration	10 years
Performance shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Performance shares | 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Number of vesting periods | vesting_period	3	3
Performance shares | 2018 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage	0.00%
Performance shares | 2018 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage	200.00%
Performance shares | Management | 2017 and 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance share units maximum payout percentage	200.00%
PSU awards capped payout percentage	100.00%
TSR, terms of award	less than zero
Performance shares | Management | 2017 and 2016 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR component, performance metrics	0.00%
Optional component, performance metrics	0.00%
Performance shares | Management | 2017 and 2016 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR component, performance metrics	100.00%
Optional component, performance metrics	100.00%
2014 long term incentive plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Reduction due to issuance of stock option or SAR (in shares)	1
Reduction due to award other than stock option or SAR (in shares)	2.12
Vesting period	10 years
Common stock, reserved for future issuance (in shares)	29,865,514
2014 long term incentive plan | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares authorized (in shares)	71,600,000

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock (Details) - Restricted stock - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Shares of Unvested Restricted Stock
Unvested restricted stock, beginning balance (in shares)	11,858	13,178	9,092
Granted (in shares)	5,908	6,067	9,872
Vested (in shares)	(5,944)	(5,808)	(4,573)
Forfeited (in shares)	(1,380)	(1,579)	(1,213)
Unvested restricted stock, ending balance (in shares)	10,442	11,858	13,178
Weighted Average Grant Date Fair Value
Unvested restricted stock, beginning balance (in usd per share)	$ 4.43	$ 6.37	$ 11.39
Granted (in usd per share)	2.65	3.73	5.40
Vested (in usd per share)	4.38	7.67	13.73
Forfeited (in usd per share)	3.72	6.02	8.32
Unvested restricted stock, ending balance (in usd per share)	$ 3.55	$ 4.43	$ 6.37

Share-Based Compensation - Equi

Share-Based Compensation - Equity-Classified Valuation (Details) - Share-based payment arrangement, option	12 Months Ended
	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected option life – years	6 years
Volatility	65.61%
Risk-free interest rate	2.47%
Dividend yield	0.00%

Share-Based Compensation - Stoc

Share-Based Compensation - Stock Option Activity (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, beginning balance (in shares)	18,096	16,285	8,593
Granted (in shares)	1,000	3,611	9,226
Exercised (in shares)	0	0	0
Expired (in shares)	(553)	(602)	(435)
Forfeited (in shares)	(609)	(1,198)	(1,099)
Outstanding, ending balance (in shares)	17,934	18,096	16,285	8,593
Options exercisable, shares underlying options (in shares)	13,092	8,250	4,474
Weighted Average Exercise Price Per Share
Outstanding, beginning balance (in usd per share)	$ 7.20	$ 8.25	$ 11.88
Granted (in usd per share)	2.97	3.01	5.45
Exercised (in usd per share)	0	0	0
Expired (in usd per share)	6.36	13.83	18.50
Forfeited (in usd per share)	3.97	5.45	9.12
Outstanding, ending balance (in usd per share)	7.10	7.20	8.25	$ 11.88
Options exercisable, average exercise price per share (in usd per share)	$ 8.28	$ 10.73	$ 15.15
Options outstanding, weighted average contract life	5 years 8 months 12 days	7 years 1 month 24 days	7 years 8 months 23 days	7 years 2 months 19 days
Options outstanding, aggregate intrinsic value	$ 0	$ 0	$ 1	$ 14
Options exercised, aggregate intrinsic value	$ 0	$ 0	$ 0
Options exercisable, weighted average contract life	4 years 10 months 9 days	5 years 8 months 23 days	5 years 3 months 3 days
Options exercisable, aggregate intrinsic value	$ 0	$ 0	$ 0

Share-Based Compensation - Eq_2

Share-Based Compensation - Equity-Classified Compensation (Details) - Restricted stock and stock options - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 32	$ 39	$ 61
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	26	31	43
Oil and natural gas properties
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	2	2	5
Oil, natural gas and NGL production expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	3	5	12
Exploration expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1	$ 1	$ 1

Share-Based Compensation - Liab

Share-Based Compensation - Liability-Classified Awards (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018	Dec. 31, 2017
Performance shares | Award year 2019, payable 2020, 2021 and 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units (in shares)	4,674,503
Fair value	$ 4	$ 14
Vested Liability	$ 0
Performance shares | Award Year 2018, Payable 2020 and 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units (in shares)	2,340,157
Fair value	$ 2		$ 7
Vested Liability	$ 0
Performance shares | Award year 2017, payable 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units (in shares)	1,174,973
Fair value	$ 1			$ 8
Vested Liability	$ 0
Cash restricted stock units | Award Year 2018, Payable 2020 and 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units (in shares)	8,233,207
Fair value	$ 7		$ 25
Vested Liability	$ 0

Share-Based Compensation - Li_2

Share-Based Compensation - Liability-Classified Compensation (Details) - Performance shares - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 10	$ 12	$ (4)
General and administrative expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	5	9	(4)
Oil and natural gas properties
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	1	1	0
Oil, natural gas and NGL production expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	3	2	0
Restructuring and other termination costs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1	$ 0	$ 0

Employee Benefit Plans - Narrat

Employee Benefit Plans - Narrative (Details)	12 Months Ended
	Dec. 31, 2019USD ($)age	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Annual contributions per employee, maximum	75.00%
Performance bonus
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Annual contributions per employee, maximum	75.00%
Chesapeake energy corporation savings and incentive stock bonus plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution	15.00%
Employer contribution amount	$ 29,000,000	$ 31,000,000	$ 35,000,000
Nonqualified deferred compensation plan (DC Plan)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution	15.00%
Employer contribution amount	$ 7,000,000	$ 7,000,000	$ 8,000,000
Base salary threshold to participate in plan	$ 150,000
Employer matching, percent of employees gross pay	100.00%
Age threshold to elect for matching contributions | age	55
Vesting period based on years of service	5 years

Derivative and Hedging Activi_3

Derivative and Hedging Activities - Narrative (Details) € in Millions	12 Months Ended
	Dec. 31, 2019USD ($)daycounterpartyderivative	Dec. 31, 2018USD ($)dayderivative$ / BTU	Dec. 31, 2017USD ($)$ / €	Dec. 31, 2017EUR (€)$ / €
Derivative [Line Items]
Consecutive trading days | day	5
Cash collateral for borrowed securities	$ 0	$ 0
Gain (loss) included in accumulated other comprehensive income to net income (loss) during the next 12 months	$ (33,000,000)
Cross currency interest rate contract | 6.25% euro-denominated senior notes due 2017 | Senior notes
Derivative [Line Items]
Interest rate, stated percentage			6.25%	6.25%
Semi annual interest rate swap payments by counterparty | €				€ 246
Semi annual interest rate swap payments by Chesapeake			$ 327,000,000
Exchange rate (in usd per euro) | $ / €			1.3325	1.3325
Credit risk
Derivative [Line Items]
Number of counterparties in hedge facility | counterparty	10
Utica shale | Disposal group, disposed of by sale, not discontinued operations
Derivative [Line Items]
Consideration received	$ 1,868,000,000
Utica shale | Disposal group, disposed of by sale, not discontinued operations | Future natural gas prices
Derivative [Line Items]
Consideration received		$ 100,000,000
Period of trading days | day		20
Consecutive trading days | day		30
2022 NYMEX natural gas | Utica shale | Disposal group, disposed of by sale, not discontinued operations | Future natural gas prices
Derivative [Line Items]
Consideration received		$ 50,000,000
2022 NYMEX natural gas | Utica shale | Disposal group, disposed of by sale, not discontinued operations | Future natural gas prices 2022
Derivative [Line Items]
Average sales price (in usd per unit) | $ / BTU		3
2022 NYMEX natural gas | Utica shale | Disposal group, disposed of by sale, not discontinued operations | Future natural gas prices 2023
Derivative [Line Items]
Average sales price (in usd per unit) | $ / BTU		3.25
Designated as hedging instrument
Derivative [Line Items]
Number of derivative instruments | derivative	0	0

Derivative and Hedging Activi_4

Derivative and Hedging Activities - Derivative Instruments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)BcfMMBbls	Dec. 31, 2018USD ($)BcfMMBbls
Derivative [Line Items]
Total derivatives	$ 130	$ 282
Energy related derivative
Derivative [Line Items]
Total derivatives	130	282
Energy related derivative | Utica shale | Future natural gas prices
Derivative [Line Items]
Total derivatives	$ 0	$ 7
Energy related derivative | Oil
Derivative [Line Items]
Notional, volume | MMBbls	34	27
Total derivatives	$ 5	$ 260
Energy related derivative | Oil | Fixed-price swaps
Derivative [Line Items]
Notional, volume | MMBbls	24	12
Total derivatives	$ (7)	$ 157
Energy related derivative | Oil | Collars
Derivative [Line Items]
Notional, volume | MMBbls	2	8
Total derivatives	$ 14	$ 98
Energy related derivative | Oil | Basis protection swaps
Derivative [Line Items]
Notional, volume | MMBbls	8	7
Total derivatives	$ (2)	$ 5
Energy related derivative | Natural gas
Derivative [Line Items]
Notional, volume | Bcf	346	966
Total derivatives	$ 125	$ 15
Energy related derivative | Natural gas | Fixed-price swaps
Derivative [Line Items]
Notional, volume | Bcf	265	623
Total derivatives	$ 125	$ 26
Energy related derivative | Natural gas | Collars
Derivative [Line Items]
Notional, volume | Bcf	0	55
Total derivatives	$ 0	$ (3)
Energy related derivative | Natural gas | Three-way collars
Derivative [Line Items]
Notional, volume | Bcf	0	88
Total derivatives	$ 0	$ 1
Energy related derivative | Natural gas | Call options
Derivative [Line Items]
Notional, volume | Bcf	22	44
Total derivatives	$ 0	$ 0
Energy related derivative | Natural gas | Call swaptions
Derivative [Line Items]
Notional, volume | Bcf	29	106
Total derivatives	$ (2)	$ (9)
Energy related derivative | Natural gas | Basis protection swaps
Derivative [Line Items]
Notional, volume | Bcf	30	50
Total derivatives	$ 2	$ 0

Derivative and Hedging Activi_5

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Total derivatives	$ 130	$ 282
Energy related derivative
Derivatives, Fair Value [Line Items]
Total derivatives	130	282
Not designated as hedging instrument
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	130
Derivative liability, fair value, gross asset	0
Total derivatives	130
Not designated as hedging instrument | Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability		282
Derivative liability, fair value, gross asset		0
Total derivatives		282
Short-term derivative asset | Not designated as hedging instrument | Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	174	306
Derivative asset, fair value, gross liability	(40)	(104)
Total derivatives	134	202
Long-term derivative asset | Not designated as hedging instrument | Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset		117
Derivative asset, fair value, gross liability		(41)
Total derivatives		76
Short-term derivative liability | Not designated as hedging instrument | Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(42)	(107)
Derivative liability, fair value, gross asset	40	104
Total derivatives	(2)	(3)
Long-term derivative liability | Not designated as hedging instrument | Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(2)	(41)
Derivative liability, fair value, gross asset	0	41
Total derivatives	$ (2)	0
Future natural gas prices | Short-term derivative asset | Not designated as hedging instrument | Energy related derivative
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset		7
Derivative asset, fair value, gross liability		0
Total derivatives		$ 7

Derivative and Hedging Activi_6

Derivative and Hedging Activities - Oil, Natural Gas and NGL Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Gains on undesignated oil, natural gas and NGL derivatives	$ 5	$ (34)
Total oil, natural gas and NGL revenues	8,595	10,030	$ 10,039
Oil, natural gas and NGL sales
Derivative [Line Items]
Losses on terminated cash flow hedges	(35)	(34)	(34)
Oil, Natural Gas and NGL
Derivative [Line Items]
Oil, natural gas and NGL revenues	4,517	5,189	4,574
Total oil, natural gas and NGL revenues	4,522	5,155	4,985
Not designated as hedging instrument | Oil, natural gas and NGL sales | Commodity contracts
Derivative [Line Items]
Gains on undesignated oil, natural gas and NGL derivatives	$ 40	$ 0	$ 445

Derivative and Hedging Activi_7

Derivative and Hedging Activities - Marketing, Gathering and Compression Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Gains on undesignated oil, natural gas and NGL derivatives	$ 5	$ (34)
Total oil, natural gas and NGL revenues	8,595	10,030	$ 10,039
Marketing, gathering and compression | Supply contract
Derivative [Line Items]
Gains on undesignated oil, natural gas and NGL derivatives	(4)	7	0
Marketing
Derivative [Line Items]
Total oil, natural gas and NGL revenues	3,967	5,076	4,511
Marketing | Marketing, gathering and compression
Derivative [Line Items]
Revenues	$ 3,971	$ 5,069	$ 4,511

Derivative and Hedging Activi_8

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), beginning balance	$ (23)
Accumulated other comprehensive income (loss), net change in fair value, before tax			$ 5
Accumulated other comprehensive income (loss), net change in fair value, after tax	0	$ 0	5
Accumulated other comprehensive income (loss), losses reclassified to income, after tax		34	34
Accumulated other comprehensive income (loss), ending balance	12	(23)
Cash flow hedging
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), before tax, beginning of period	(80)	(114)	(153)
Accumulated other comprehensive income (loss), beginning balance	(23)	(57)	(96)
Accumulated other comprehensive income (loss), net change in fair value, before tax	0	0
Accumulated other comprehensive income (loss), losses reclassified to income, before tax	35	34	34
Accumulated other comprehensive income (loss), losses reclassified to income, after tax	35	34	34
Accumulated other comprehensive income (loss), before tax, end of period	(45)	(80)	(114)
Accumulated other comprehensive income (loss), ending balance	$ 12	$ (23)	$ (57)

Derivative and Hedging Activi_9

Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total derivatives	$ 130	$ 282
Commodity contracts
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset	174	422
Derivative liability	(44)	(147)
Energy related derivative
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total derivatives	130	282
Energy related derivative | Future natural gas prices | Utica shale
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset		7
Total derivatives	0	7
Fair value, inputs, level 1
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total derivatives	0	0
Fair value, inputs, level 1 | Commodity contracts
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset	0	0
Derivative liability	0	0
Fair value, inputs, level 1 | Energy related derivative | Future natural gas prices | Utica shale
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset		0
Fair value, inputs, level 2
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total derivatives	118	188
Fair value, inputs, level 2 | Commodity contracts
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset	160	319
Derivative liability	(42)	(131)
Fair value, inputs, level 2 | Energy related derivative | Future natural gas prices | Utica shale
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset		0
Fair value, inputs, level 3
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total derivatives	12	94
Fair value, inputs, level 3 | Commodity contracts
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset	14	103
Derivative liability	(2)	(16)
Total derivatives	12	87	$ (15)
Fair value, inputs, level 3 | Energy related derivative | Future natural gas prices | Utica shale
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset		7
Total derivatives	$ 0	$ 7	$ 0

Derivative and Hedging Activ_10

Derivative and Hedging Activities - Fair Value Level 3 Measurements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of period	$ 282
Balance, end of period	130	$ 282
Energy related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of period	282
Balance, end of period	130	282
Energy related derivative | Future natural gas prices | Utica shale
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of period	7
Balance, end of period	0	7
Fair value, inputs, level 3
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of period	94
Balance, end of period	12	94
Fair value, inputs, level 3 | Commodity contracts
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of period	87	(15)
Total gains (losses) (realized/unrealized): Included in earnings	(59)	77
Total purchases, issuances, sales and settlements: Settlements	(16)	25
Balance, end of period	12	87
Fair value, inputs, level 3 | Energy related derivative | Future natural gas prices | Utica shale
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of period	7	0
Total gains (losses) (realized/unrealized): Included in earnings	(7)	7
Total purchases, issuances, sales and settlements: Settlements	0	0
Balance, end of period	0	7
Oil, natural gas and NGL sales | Fair value, inputs, level 3 | Commodity contracts
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Total gains (losses) (realized/unrealized): Included in earnings	(59)	77
Change in unrealized gains (losses) related to assets still held at reporting date	(19)	86
Oil, natural gas and NGL sales | Fair value, inputs, level 3 | Energy related derivative | Future natural gas prices | Utica shale
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Total gains (losses) (realized/unrealized): Included in earnings	(7)	7
Change in unrealized gains (losses) related to assets still held at reporting date	$ 0	$ 7

Derivative and Hedging Activ_11

Derivative and Hedging Activities - Quantitative Disclosures Level 3 (Details) - Energy related derivative $ in Millions	Dec. 31, 2019USD ($)
Oil
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Fair value, asset	$ 14
Natural gas
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Fair value, liability	$ (2)
Weighted average | Measurement input, price volatility | Oil
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.2562
Weighted average | Measurement input, price volatility | Natural gas
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.3967
Minimum | Measurement input, price volatility | Oil
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.2071
Minimum | Measurement input, price volatility | Natural gas
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.1693
Maximum | Measurement input, price volatility | Oil
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.6728
Maximum | Measurement input, price volatility | Natural gas
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	1.7149

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Table (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	$ (1)	$ (1)
Short-term derivative asset
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	42	50
Short-term derivative liability
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	(43)	(51)
Fair value, inputs, level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	(1)	(1)
Fair value, inputs, level 1 | Short-term derivative asset
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	42	50
Fair value, inputs, level 1 | Short-term derivative liability
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	(43)	(51)
Fair value, inputs, level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	0	0
Fair value, inputs, level 2 | Short-term derivative asset
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	0	0
Fair value, inputs, level 2 | Short-term derivative liability
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	0	0
Fair value, inputs, level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	0	0
Fair value, inputs, level 3 | Short-term derivative asset
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	0	0
Fair value, inputs, level 3 | Short-term derivative liability
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	$ 0	$ 0

Capitalized Exploratory Well _3

Capitalized Exploratory Well Costs - Changes In Capitalized Well Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in Capitalized Well Costs
Beginning balance	$ 36	$ 36	$ 41
Additions pending the determination of proved reserves	7	74	14
Divestitures and other	(3)	0	0
Reclassifications to proved properties	(17)	(40)	(19)
Charges to exploration expense	(16)	(34)	0
Ending balance	$ 7	$ 36	$ 36

Capitalized Exploratory Well _4

Capitalized Exploratory Well Costs - Aging of Capitalized Costs (Details) $ in Millions	Dec. 31, 2019USD ($)project	Dec. 31, 2018USD ($)project	Dec. 31, 2017USD ($)project	Dec. 31, 2016USD ($)
Extractive Industries [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 7	$ 34	$ 4
Exploratory well costs capitalized for a period greater than one year	0	2	32
Exploratory well costs capitalized	$ 7	$ 36	$ 36	$ 41
Number of projects with exploratory well costs capitalized for a period greater than one year | project	0	7	6

Other Property and Equipment -

Other Property and Equipment - Held for Use and Estimated Useful Lives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 1,810	$ 1,721
Total other property and equipment, at cost	1,810
Less: accumulated depreciation	(692)
Less: accumulated depreciation		(630)
Total other property and equipment, net		1,091
Total other property and equipment, net	1,118
Accumulated amortization	10
Accumulated depreciation		630
Buildings and improvements
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 1,058	1,053
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	$ 355	353
Estimated useful life	5 years
Sand mine
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 78	0
Sand mine | Minimum
Property, Plant and Equipment [Abstract]
Estimated useful life	10 years
Sand mine | Maximum
Property, Plant and Equipment [Abstract]
Estimated useful life	30 years
Compressor
Property, Plant and Equipment [Line Items]
Finance Lease, Right-of-Use Asset, before Accumulated Amortization	$ 27
Property, Plant and Equipment [Abstract]
Other property and equipment		48
Total other property and equipment, at cost	$ 48
Compressor | Minimum
Property, Plant and Equipment [Abstract]
Estimated useful life	3 years
Compressor | Maximum
Property, Plant and Equipment [Abstract]
Estimated useful life	20 years
Natural gas compressors
Property, Plant and Equipment [Abstract]
Other property and equipment		27
Less: accumulated depreciation		(1)
Accumulated depreciation		1
Land
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 115	106
Other
Property, Plant and Equipment [Abstract]
Other property and equipment	$ 156	$ 161
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 - Narrative (Detail

Investments - Narrative (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Mar. 31, 2019	Feb. 01, 2019
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments	$ 0	$ 74	$ 0
Share price (in usd per share)					$ 2.84
JWH midstream LLC (JWH)
Schedule of Equity Method Investments [Line Items]
Business acquisition, percent acquired	50.00%
Equity method investments				$ 17
Payments to terminate involvement in partnership	$ 7
Impairment expense	24
FTS international, inc.
Schedule of Equity Method Investments [Line Items]
Investment, ownership percentage		20.00%	29.00%
Investment, realized gain (loss)		$ 61
Number of shares sold (in shares)		4.3
Proceeds from sales of investments		$ 74
Shares owned (in shares)		22
Equity securities, cost	$ 65
Share price (in usd per share)	$ 1.04
Impairments of investments	$ 43
FTS international, inc. | IPO
Schedule of Equity Method Investments [Line Items]
Investment, ownership percentage		24.00%
Investment, realized gain (loss)		$ 78

Impairments - Impairments of Oi

Impairments - Impairments of Oil and Natural Gas Properties (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Total impairments of oil and natural gas properties	$ 8	$ 78	$ 809
Impairments due to lower forecasted commodity prices
Property, Plant and Equipment [Line Items]
Total impairments of oil and natural gas properties	8	23	27
Impairments due to reduction in future development
Property, Plant and Equipment [Line Items]
Total impairments of oil and natural gas properties	0	0	560
Impairments due to anticipated sale
Property, Plant and Equipment [Line Items]
Total impairments of oil and natural gas properties	$ 0	$ 55	$ 222

Impairments - Fixed Assets and

Impairments - Fixed Assets and Other Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Asset impairment	$ 3	$ 53	$ 5
Natural gas compressors(a)
Property, Plant and Equipment [Line Items]
Asset impairment	0	45	0
Buildings and land
Property, Plant and Equipment [Line Items]
Asset impairment	1	4	5
Other
Property, Plant and Equipment [Line Items]
Asset impairment	$ 2	$ 4	$ 0

Impairments - Narrative (Detail

Impairments - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)compressor	Dec. 31, 2017USD ($)
Property, Plant and Equipment [Line Items]
Asset impairment	$ 3	$ 53	$ 5
Natural gas compressors, difference between carrying value and fair value
Property, Plant and Equipment [Line Items]
Asset impairment		$ 45
Equipment, number of units | compressor		890

Other Operating Expense - Narra

Other Operating Expense - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2017
Transportation equipment | Natural gas
Property, Plant and Equipment [Line Items]
Loss on contract termination		$ 126
Transportation equipment | Oil
Property, Plant and Equipment [Line Items]
Loss on contract termination		$ 290
Wildhorse resource development corporation
Property, Plant and Equipment [Line Items]
Business acquisition transaction costs	$ 37
Severance costs	$ 38

Restructuring and Other Termi_2

Restructuring and Other Termination Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs	$ 12	$ 38	$ 0
Restructuring and other termination costs, number of positions eliminated, period percent		13.00%
One-time termination benefits
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs	$ 12	$ 38

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 166	$ 177
Additions(a)	21	3
Revisions	18	11
Settlements and disposals	(5)	(35)
Accretion expense	11	10
Asset retirement obligations, end of period	211	166
Less current portion	11	11
Asset retirement obligation, long-term	200	155
Business Acquisition [Line Items]
Additions	21	$ 3
Wildhorse resource development corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Additions(a)	17
Business Acquisition [Line Items]
Additions	$ 17

Major Customers - Narrative (De

Major Customers - Narrative (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Valero energy corporation
Revenue, Major Customer [Line Items]
Concentration risk, percentage	12.00%	10.00%
Royal dutch shell PLC
Revenue, Major Customer [Line Items]
Concentration risk, percentage			10.00%

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
FTS international, inc.
Related Party Transaction [Line Items]
Related party transaction, expenses	$ 0	$ 93	$ 111

Condensed Consolidating Finan_3

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 6	$ 4
Other current assets	1,245	1,594
Intercompany receivable, net	0	0
Total Current Assets	1,251	1,598
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	13,628	9,712
Other property and equipment, net		1,091
Property, Plant, and Equipment and Finance Lease Right-of-Use Asset, after Accumulated Depreciation and Amortization	1,118
Property and equipment held for sale, net	10	15
Total Property and Equipment, Net	14,756	10,818
LONG-TERM ASSETS:
Other long-term assets	186	319
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	16,193	12,735
CURRENT LIABILITIES:
Current liabilities	2,392	2,887
Intercompany payable, net	0	0
Total Current Liabilities	2,392	2,887
LONG-TERM LIABILITIES:
Long-term debt, net	9,073	7,341
Deferred income tax liabilities	10
Other long-term liabilities	317	374
Total Long-Term Liabilities	9,400	7,715
EQUITY:
Chesapeake stockholders’ equity	4,364	2,092
Noncontrolling interests	37	41
Total Equity	4,401	2,133	$ 1,943
TOTAL LIABILITIES AND EQUITY	16,193	12,735
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	(16)	(2)
Other current assets	0	0
Intercompany receivable, net	(7,702)	(6,671)
Total Current Assets	(7,718)	(6,673)
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	0	0
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	0	0
LONG-TERM ASSETS:
Other long-term assets	1	0
Investments in subsidiaries and intercompany advances	(10,272)	(3,257)
TOTAL ASSETS	(17,989)	(9,930)
CURRENT LIABILITIES:
Current liabilities	(15)	(2)
Intercompany payable, net	(7,702)	(6,671)
Total Current Liabilities	(7,717)	(6,673)
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	0
Other long-term liabilities	0	0
Total Long-Term Liabilities	0	0
EQUITY:
Chesapeake stockholders’ equity	(10,272)	(3,257)
Noncontrolling interests	0	0
Total Equity	(10,272)	(3,257)
TOTAL LIABILITIES AND EQUITY	(17,989)	(9,930)
Parent | Reportable legal entities
CURRENT ASSETS:
Cash and cash equivalents	16	4
Other current assets	51	60
Intercompany receivable, net	7,702	6,671
Total Current Assets	7,769	6,735
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	0	0
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	0	0
LONG-TERM ASSETS:
Other long-term assets	41	26
Investments in subsidiaries and intercompany advances	6,101	3,248
TOTAL ASSETS	13,911	10,009
CURRENT LIABILITIES:
Current liabilities	466	523
Intercompany payable, net	0	0
Total Current Liabilities	466	523
LONG-TERM LIABILITIES:
Long-term debt, net	9,071	7,341
Deferred income tax liabilities	10
Other long-term liabilities	0	53
Total Long-Term Liabilities	9,081	7,394
EQUITY:
Chesapeake stockholders’ equity	4,364	2,092
Noncontrolling interests	0	0
Total Equity	4,364	2,092
TOTAL LIABILITIES AND EQUITY	13,911	10,009
Guarantor Subsidiaries | Reportable legal entities
CURRENT ASSETS:
Cash and cash equivalents	1	1
Other current assets	1,090	1,532
Intercompany receivable, net	0	0
Total Current Assets	1,091	1,533
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	9,440	9,664
Other property and equipment, net	1,030	1,091
Property and equipment held for sale, net	10	15
Total Property and Equipment, Net	10,480	10,770
LONG-TERM ASSETS:
Other long-term assets	125	293
Investments in subsidiaries and intercompany advances	4,171	9
TOTAL ASSETS	15,867	12,605
CURRENT LIABILITIES:
Current liabilities	1,765	2,365
Intercompany payable, net	7,702	6,671
Total Current Liabilities	9,467	9,036
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	0
Other long-term liabilities	299	321
Total Long-Term Liabilities	299	321
EQUITY:
Chesapeake stockholders’ equity	6,101	3,248
Noncontrolling interests	0	0
Total Equity	6,101	3,248
TOTAL LIABILITIES AND EQUITY	15,867	12,605
Non-Guarantor Subsidiaries | Reportable legal entities
CURRENT ASSETS:
Cash and cash equivalents	5	1
Other current assets	104	2
Intercompany receivable, net	0	0
Total Current Assets	109	3
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	4,188	48
Other property and equipment, net	88	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	4,276	48
LONG-TERM ASSETS:
Other long-term assets	19	0
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	4,404	51
CURRENT LIABILITIES:
Current liabilities	176	1
Intercompany payable, net	0	0
Total Current Liabilities	176	1
LONG-TERM LIABILITIES:
Long-term debt, net	2	0
Deferred income tax liabilities	0
Other long-term liabilities	18	0
Total Long-Term Liabilities	20	0
EQUITY:
Chesapeake stockholders’ equity	4,171	9
Noncontrolling interests	37	41
Total Equity	4,208	50
TOTAL LIABILITIES AND EQUITY	$ 4,404	$ 51

Condensed Consolidating Finan_4

Condensed Consolidating Financial Information - Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
REVENUES AND OTHER:
Revenues	$ 8,595	$ 10,030	$ 10,039
Gains (losses) on sales of assets	43	(264)	476
OPERATING EXPENSES:
Severance and ad valorem taxes	224	189	134
General and administrative	315	335	333
Restructuring and other termination costs	12	38	0
Provision for legal contingencies, net	19	26	(38)
Depreciation, depletion and amortization	2,264	1,737	1,697
Gain (loss) on sale of oil and natural gas properties	0	0
Impairments	11	131	814
Other operating expense	92	0	416
Total Operating Expenses	8,626	9,648	10,177
INCOME (LOSS) FROM OPERATIONS	(31)	382	(138)
OTHER INCOME (EXPENSE):
Interest expense	(651)	(633)	(601)
Gains (losses) on investments	(71)	139	0
Gains on purchases or exchanges of debt	75	263	233
Other income	39	67	6
Equity in net earnings (losses) of subsidiary	0	0	0
Total Other Expense	(608)	(164)	(362)
INCOME (LOSS) BEFORE INCOME TAXES	(639)	218	(500)
Total Income Tax Expense (Benefit)	(331)	(10)	2
NET INCOME (LOSS)	(308)	228	(502)
Net income attributable to noncontrolling interests	0	(2)	(3)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(308)	226	(505)
Other comprehensive income	35	34	39
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(273)	260	(466)
Oil, Natural Gas and NGL
REVENUES AND OTHER:
Revenues	4,522	5,155	4,985
Oil, natural gas and NGL production
OPERATING EXPENSES:
Cost of goods and services	520	474	517
Oil, natural gas and NGL gathering, processing and transportation
OPERATING EXPENSES:
Cost of goods and services	1,082	1,398	1,471
Marketing
REVENUES AND OTHER:
Revenues	3,967	5,076	4,511
OPERATING EXPENSES:
Cost of goods and services	4,003	5,158	4,598
Oil, Natural gas and NGL and Marketing
REVENUES AND OTHER:
Revenues	8,489	10,231	9,496
Other
REVENUES AND OTHER:
Revenues	63	63	67
Exploration
OPERATING EXPENSES:
Cost of goods and services	84	162	235
Marketing
REVENUES AND OTHER:
Revenues	3,967	5,076
Reportable legal entities | Exploration
OPERATING EXPENSES:
Cost of goods and services	7	0	0
Eliminations
REVENUES AND OTHER:
Revenues	0	0	0
Gains (losses) on sales of assets	0	0	0
OPERATING EXPENSES:
Severance and ad valorem taxes	0	0	0
General and administrative	0	0	0
Restructuring and other termination costs	0	0
Provision for legal contingencies, net	0	0	0
Depreciation, depletion and amortization	0	0	0
Impairments	0	0	0
Other operating expense	0		0
Total Operating Expenses	0	0	0
INCOME (LOSS) FROM OPERATIONS	0	0	0
OTHER INCOME (EXPENSE):
Interest expense	0	0	0
Gains (losses) on investments	0	0
Gains on purchases or exchanges of debt	0	0	0
Other income	0	0	0
Equity in net earnings (losses) of subsidiary	246	(584)	216
Total Other Expense	246	(584)	216
INCOME (LOSS) BEFORE INCOME TAXES	246	(584)	216
Total Income Tax Expense (Benefit)	0	0	0
NET INCOME (LOSS)	246	(584)	216
Net income attributable to noncontrolling interests	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	246	(584)	216
Other comprehensive income	0	0	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	246	(584)	216
Eliminations | Oil, Natural Gas and NGL
REVENUES AND OTHER:
Revenues	0	0	0
Eliminations | Oil, natural gas and NGL production
OPERATING EXPENSES:
Cost of goods and services	0	0	0
Eliminations | Oil, natural gas and NGL gathering, processing and transportation
OPERATING EXPENSES:
Cost of goods and services	0	0	0
Eliminations | Marketing
REVENUES AND OTHER:
Revenues	0	0	0
OPERATING EXPENSES:
Cost of goods and services	0	0	0
Eliminations | Oil, Natural gas and NGL and Marketing
REVENUES AND OTHER:
Revenues		0	0
Eliminations | Other
REVENUES AND OTHER:
Revenues	0	0	0
Eliminations | Exploration
OPERATING EXPENSES:
Cost of goods and services	0	0	0
Parent | Reportable legal entities
REVENUES AND OTHER:
Revenues	0	0	0
Gains (losses) on sales of assets	0	0	0
OPERATING EXPENSES:
Severance and ad valorem taxes	0	0	0
General and administrative	1	2	1
Restructuring and other termination costs	0	0
Provision for legal contingencies, net	0	0	(79)
Depreciation, depletion and amortization	0	0	0
Impairments	0	0	0
Other operating expense	0		0
Total Operating Expenses	1	2	(78)
INCOME (LOSS) FROM OPERATIONS	(1)	(2)	78
OTHER INCOME (EXPENSE):
Interest expense	(598)	(631)	(599)
Gains (losses) on investments	0	0
Gains on purchases or exchanges of debt	65	263	233
Other income	0	3	1
Equity in net earnings (losses) of subsidiary	(105)	583	(216)
Total Other Expense	(638)	218	(581)
INCOME (LOSS) BEFORE INCOME TAXES	(639)	216	(503)
Total Income Tax Expense (Benefit)	(331)	(10)	2
NET INCOME (LOSS)	(308)	226	(505)
Net income attributable to noncontrolling interests	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(308)	226	(505)
Other comprehensive income	0	0	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(308)	226	(505)
Parent | Reportable legal entities | Oil, Natural Gas and NGL
REVENUES AND OTHER:
Revenues	0	0	0
Parent | Reportable legal entities | Oil, natural gas and NGL production
OPERATING EXPENSES:
Cost of goods and services	0	0	0
Parent | Reportable legal entities | Oil, natural gas and NGL gathering, processing and transportation
OPERATING EXPENSES:
Cost of goods and services	0	0	0
Parent | Reportable legal entities | Marketing
REVENUES AND OTHER:
Revenues	0	0	0
OPERATING EXPENSES:
Cost of goods and services	0	0	0
Parent | Reportable legal entities | Oil, Natural gas and NGL and Marketing
REVENUES AND OTHER:
Revenues	0	0	0
Parent | Reportable legal entities | Other
REVENUES AND OTHER:
Revenues	0	0	0
Parent | Reportable legal entities | Exploration
OPERATING EXPENSES:
Cost of goods and services	0	0	0
Guarantor Subsidiaries | Reportable legal entities
REVENUES AND OTHER:
Revenues	7,830	10,011	10,016
Gains (losses) on sales of assets	43	(264)	476
OPERATING EXPENSES:
Severance and ad valorem taxes	174	188	133
General and administrative	237	332	330
Restructuring and other termination costs	12	38
Provision for legal contingencies, net	19	26	41
Depreciation, depletion and amortization	1,719	1,730	1,688
Impairments	11	131	814
Other operating expense	52		416
Total Operating Expenses	7,802	9,630	10,235
INCOME (LOSS) FROM OPERATIONS	28	381	(219)
OTHER INCOME (EXPENSE):
Interest expense	16	(2)	(2)
Gains (losses) on investments	(47)	139
Gains on purchases or exchanges of debt	0	0	0
Other income	39	64	5
Equity in net earnings (losses) of subsidiary	(141)	1	0
Total Other Expense	(133)	202	3
INCOME (LOSS) BEFORE INCOME TAXES	(105)	583	(216)
Total Income Tax Expense (Benefit)	0	0	0
NET INCOME (LOSS)	(105)	583	(216)
Net income attributable to noncontrolling interests	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(105)	583	(216)
Other comprehensive income	35	34	39
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(70)	617	(177)
Guarantor Subsidiaries | Reportable legal entities | Oil, Natural Gas and NGL
REVENUES AND OTHER:
Revenues	3,760	5,136	4,962
Guarantor Subsidiaries | Reportable legal entities | Oil, natural gas and NGL production
OPERATING EXPENSES:
Cost of goods and services	436	474	517
Guarantor Subsidiaries | Reportable legal entities | Oil, natural gas and NGL gathering, processing and transportation
OPERATING EXPENSES:
Cost of goods and services	1,062	1,391	1,463
Guarantor Subsidiaries | Reportable legal entities | Marketing
REVENUES AND OTHER:
Revenues	3,967	5,076	4,511
OPERATING EXPENSES:
Cost of goods and services	4,003	5,158	4,598
Guarantor Subsidiaries | Reportable legal entities | Oil, Natural gas and NGL and Marketing
REVENUES AND OTHER:
Revenues	7,727	10,212	9,473
Guarantor Subsidiaries | Reportable legal entities | Other
REVENUES AND OTHER:
Revenues	60	63	67
Guarantor Subsidiaries | Reportable legal entities | Exploration
OPERATING EXPENSES:
Cost of goods and services	77	162	235
Non-Guarantor Subsidiaries | Reportable legal entities
REVENUES AND OTHER:
Revenues	765	19	23
Gains (losses) on sales of assets	0	0	0
OPERATING EXPENSES:
Severance and ad valorem taxes	50	1	1
General and administrative	77	1	2
Restructuring and other termination costs	0	0
Provision for legal contingencies, net	0	0	0
Depreciation, depletion and amortization	545	7	9
Impairments	0	0	0
Other operating expense	40		0
Total Operating Expenses	823	16	20
INCOME (LOSS) FROM OPERATIONS	(58)	3	3
OTHER INCOME (EXPENSE):
Interest expense	(69)	0	0
Gains (losses) on investments	(24)	0
Gains on purchases or exchanges of debt	10	0	0
Other income	0	0	0
Equity in net earnings (losses) of subsidiary	0	0	0
Total Other Expense	(83)	0	0
INCOME (LOSS) BEFORE INCOME TAXES	(141)	3	3
Total Income Tax Expense (Benefit)	0	0	0
NET INCOME (LOSS)	(141)	3	3
Net income attributable to noncontrolling interests	0	(2)	(3)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(141)	1	0
Other comprehensive income	0	0	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(141)	1	0
Non-Guarantor Subsidiaries | Reportable legal entities | Oil, Natural Gas and NGL
REVENUES AND OTHER:
Revenues	762	19	23
Non-Guarantor Subsidiaries | Reportable legal entities | Oil, natural gas and NGL production
OPERATING EXPENSES:
Cost of goods and services	84	0	0
Non-Guarantor Subsidiaries | Reportable legal entities | Oil, natural gas and NGL gathering, processing and transportation
OPERATING EXPENSES:
Cost of goods and services	20	7	8
Non-Guarantor Subsidiaries | Reportable legal entities | Marketing
REVENUES AND OTHER:
Revenues	0	0	0
OPERATING EXPENSES:
Cost of goods and services	0	0	0
Non-Guarantor Subsidiaries | Reportable legal entities | Oil, Natural gas and NGL and Marketing
REVENUES AND OTHER:
Revenues	762	19	23
Non-Guarantor Subsidiaries | Reportable legal entities | Other
REVENUES AND OTHER:
Revenues	$ 3	$ 0	$ 0

Condensed Consolidating Finan_5

Condensed Consolidating Financial Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By (Used In) Operating Activities	$ 1,623	$ 1,730	$ 475
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(2,180)	(1,848)	(2,113)
Business combination, net	(353)	0	0
Acquisitions of proved and unproved properties	(35)	(128)	(88)
Proceeds from divestitures of proved and unproved properties	130	2,231	1,249
Additions to other property and equipment	(48)	(21)	(21)
Proceeds from sales of other property and equipment	6	147	55
Proceeds from sales of investments	0	74	0
Other investing activities			55
Net Cash Provided By (Used In) Investing Activities	(2,480)	455	(918)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	10,676	11,697	7,771
Payments on revolving credit facility borrowings	(10,180)	(12,059)	(6,990)
Proceeds from issuance of senior notes, net	108	1,236	1,585
Proceeds from issuance of term loan, net	1,455	0	0
Cash paid to purchase debt	(1,073)	(2,813)	(2,592)
Cash paid for preferred stock dividends	(91)	(92)	(183)
Contribution from parent	0
Other financing activities	(36)	(155)	(25)
Intercompany advances, net	0	0	0
Net Cash Provided By (Used In) Financing Activities	859	(2,186)	(434)
Net increase (decrease) in cash and cash equivalents	2	(1)	(877)
Cash and cash equivalents, beginning of period	4	5	882
Cash and cash equivalents, end of period	6	4	5
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By (Used In) Operating Activities	(4)	(7)	(10)
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0	0
Business combination, net	0
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Proceeds from sales of other property and equipment	0	0
Proceeds from sales of investments		0
Other investing activities			0
Net Cash Provided By (Used In) Investing Activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	0	0	0
Payments on revolving credit facility borrowings	0	0	0
Proceeds from issuance of senior notes, net	0	0	0
Proceeds from issuance of term loan, net	0
Cash paid to purchase debt	0	0	0
Cash paid for preferred stock dividends	0	0	0
Contribution from parent	0
Other financing activities	4	7	32
Intercompany advances, net	0	1	0
Net Cash Provided By (Used In) Financing Activities	4	8	32
Net increase (decrease) in cash and cash equivalents	0	1	22
Cash and cash equivalents, beginning of period	(2)	(3)	(25)
Cash and cash equivalents, end of period	(2)	(2)	(3)
Parent | Reportable legal entities
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By (Used In) Operating Activities	1	85	5
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0	0
Business combination, net	0
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Proceeds from sales of other property and equipment	0	0
Proceeds from sales of investments		0
Other investing activities			0
Net Cash Provided By (Used In) Investing Activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	9,839	11,697	7,771
Payments on revolving credit facility borrowings	(8,668)	(12,059)	(6,990)
Proceeds from issuance of senior notes, net	108	1,236	1,585
Proceeds from issuance of term loan, net	1,455
Cash paid to purchase debt	(380)	(2,813)	(2,592)
Cash paid for preferred stock dividends	(91)	(92)	(183)
Contribution from parent	(1,644)
Other financing activities	(24)	(26)	(39)
Intercompany advances, net	(713)	1,971	(456)
Net Cash Provided By (Used In) Financing Activities	(118)	(86)	(904)
Net increase (decrease) in cash and cash equivalents	(117)	(1)	(899)
Cash and cash equivalents, beginning of period	4	5	904
Cash and cash equivalents, end of period	(113)	4	5
Guarantor Subsidiaries | Reportable legal entities
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By (Used In) Operating Activities	1,270	1,642	466
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(1,548)	(1,848)	(2,113)
Business combination, net	(381)
Acquisitions of proved and unproved properties	(35)	(128)	(88)
Proceeds from divestitures of proved and unproved properties	130	2,231	1,249
Additions to other property and equipment	(32)	(21)	(21)
Proceeds from sales of other property and equipment	6	147
Proceeds from sales of investments		74
Other investing activities			55
Net Cash Provided By (Used In) Investing Activities	(1,860)	455	(918)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	0	0	0
Payments on revolving credit facility borrowings	0	0	0
Proceeds from issuance of senior notes, net	0	0	0
Proceeds from issuance of term loan, net	0
Cash paid to purchase debt	0	0	0
Cash paid for preferred stock dividends	0	0	0
Contribution from parent	0
Other financing activities	(8)	(123)	(5)
Intercompany advances, net	713	(1,974)	456
Net Cash Provided By (Used In) Financing Activities	705	(2,097)	451
Net increase (decrease) in cash and cash equivalents	115	0	(1)
Cash and cash equivalents, beginning of period	1	1	2
Cash and cash equivalents, end of period	116	1	1
Non-Guarantor Subsidiaries | Reportable legal entities
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By (Used In) Operating Activities	356	10	14
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(632)	0	0
Business combination, net	28
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	(16)	0	0
Proceeds from sales of other property and equipment	0	0
Proceeds from sales of investments		0
Other investing activities			0
Net Cash Provided By (Used In) Investing Activities	(620)	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	837	0	0
Payments on revolving credit facility borrowings	(1,512)	0	0
Proceeds from issuance of senior notes, net	0	0	0
Proceeds from issuance of term loan, net	0
Cash paid to purchase debt	(693)	0	0
Cash paid for preferred stock dividends	0	0	0
Contribution from parent	1,644
Other financing activities	(8)	(13)	(13)
Intercompany advances, net	0	2	0
Net Cash Provided By (Used In) Financing Activities	268	(11)	(13)
Net increase (decrease) in cash and cash equivalents	4	(1)	1
Cash and cash equivalents, beginning of period	1	2	1
Cash and cash equivalents, end of period	$ 5	$ 1	$ 2

Condensed Consolidating Finan_6

Condensed Consolidating Financial Information - Narrative (Details)	Dec. 31, 2019
Senior notes
Condensed Financial Statements, Captions [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%

Subsequent Events - Narrative (

Subsequent Events - Narrative (Details) - Subsequent event - USD ($) $ in Millions	Feb. 24, 2020	Mar. 31, 2020
Subsequent Event [Line Items]
Termination agreements, consideration transferred	$ 70
Payments to terminate agreements, gross	54
Termination agreements, consideration transferred, inventory	$ 16
Forecast
Subsequent Event [Line Items]
Expense related to contract termination		$ 70
Decrease in future commitments		$ 169