Expand Energy (EXE) 10-Q 30 Oct 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 25, 2018
Document and Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Trading Symbol	CHK
Entity Registrant Name	CHESAPEAKE ENERGY CORPORATION
Entity Central Index Key	895,126
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		913,710,098

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents ($1 and $2 attributable to our VIE)	$ 4	$ 5
Accounts receivable, net	1,051	1,322
Short-term derivative assets	0	27
Other current assets	180	171
Total Current Assets	1,235	1,525
Oil and natural gas properties, at cost based on full cost accounting:
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	70,620	68,858
Unproved properties	3,198	3,484
Other property and equipment	1,812	1,986
Total Property and Equipment, at Cost	75,630	74,328
Less: accumulated depreciation, depletion and amortization (($463) and ($461) attributable to our VIE)	(64,500)	(63,664)
Property and equipment held for sale, net	47	16
Total Property and Equipment, Net	11,177	10,680
LONG-TERM ASSETS:
Other long-term assets	247	220
TOTAL ASSETS	12,659	12,425
CURRENT LIABILITIES:
Accounts payable	670	654
Current maturities of long-term debt, net	432	52
Accrued interest	126	137
Short-term derivative liabilities	310	58
Other current liabilities ($2 and $3 attributable to our VIE)	1,438	1,455
Total Current Liabilities	2,976	2,356
LONG-TERM LIABILITIES:
Long-term debt, net	9,380	9,921
Long-term derivative liabilities	28	4
Asset retirement obligations, net of current portion	154	162
Other long-term liabilities	160	354
Total Long-Term Liabilities	9,722	10,441
CONTINGENCIES AND COMMITMENTS (Note 4)
Chesapeake Stockholders’ Equity (Deficit):
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 5,603,458 shares outstanding	1,671	1,671
Common stock, $0.01 par value, 2,000,000,000 shares authorized: 913,691,662 and 908,732,809 shares issued	9	9
Additional paid-in capital	14,394	14,437
Accumulated deficit	(16,173)	(16,525)
Accumulated other comprehensive loss	(32)	(57)
Less: treasury stock, at cost; 3,307,953 and 2,240,394 common shares	(31)	(31)
Total Chesapeake Stockholders’ Equity (Deficit)	(162)	(496)
Noncontrolling interests	123	124
Total Equity (Deficit)	(39)	(372)
TOTAL LIABILITIES AND EQUITY	$ 12,659	$ 12,425

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Preferred stock, par value (usd per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (shares)	20,000,000	20,000,000
Preferred stock, shares outstanding (shares)	5,603,468	5,603,458
Common stock, par value (usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares issued	913,691,662	908,732,809
Treasury stock, common shares	3,307,953	2,240,394
VIE, cash and cash equivalents	$ 4	$ 5
VIE, proved oil and natural gas properties	70,620	68,858
VIE, accumulated depreciation, depletion and amortization	(64,500)	(63,664)
VIE, other current liabilities	1,438	1,455
Variable Interest Entities, Primary Beneficiary [Member]
VIE, cash and cash equivalents	1	2
VIE, proved oil and natural gas properties	488	488
VIE, accumulated depreciation, depletion and amortization	(463)	(461)
VIE, other current liabilities	$ 2	$ 3

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
REVENUES:
Revenues	$ 2,418	$ 1,943	$ 7,162	$ 6,977
OPERATING EXPENSES:
Oil, natural gas and NGL production	132	151	417	426
Oil, natural gas and NGL gathering, processing and transportation	364	369	1,060	1,081
Production taxes	34	21	91	64
General and administrative	66	54	229	189
Restructuring and other termination costs	0	0	38	0
Provision for legal contingencies, net	8	20	17	35
Oil, natural gas and NGL depreciation, depletion and amortization	274	228	813	627
Depreciation and amortization of other assets	17	20	54	62
Impairments	5	3	51	3
Other operating (income) expense	0	6	(1)	423
Net (gains) losses on sales of fixed assets	0	(1)	7	0
Total Operating Expenses	2,138	1,849	6,574	6,243
INCOME FROM OPERATIONS	280	94	588	734
OTHER INCOME (EXPENSE):
Interest expense	(127)	(114)	(367)	(302)
Gains on investments	0	0	139	0
Gains (losses) on purchases or exchanges of debt	(68)	(1)	(68)	183
Other income	1	4	63	6
Total Other Expense	(194)	(111)	(233)	(113)
INCOME (LOSS) BEFORE INCOME TAXES	86	(17)	355	621
Income tax expense (benefit)	1	0	(8)	2
NET INCOME (LOSS)	85	(17)	363	619
Net income attributable to noncontrolling interests	(1)	(1)	(3)	(3)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	84	(18)	360	616
Preferred stock dividends	(23)	(23)	(69)	(62)
Loss on exchange of preferred stock	0	0	0	(41)
Earnings allocated to participating securities	(1)	0	(3)	(7)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$ 60	$ (41)	$ 288	$ 506
EARNINGS (LOSS) PER COMMON SHARE:
Earnings per common share, basic (in dollars per share)	$ 0.07	$ (0.05)	$ 0.32	$ 0.56
Earnings per common share, diluted (in dollars per share)	$ 0.07	$ (0.05)	$ 0.32	$ 0.56
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Weighted average common and common equivalent shares outstanding, basic (in shares)	910	909	909	908
Weighted average common and common equivalent shares outstanding, diluted (in shares)	911	909	909	908
Oil, natrual gas and NGL [Member]
REVENUES:
Revenues	$ 1,199	$ 979	$ 3,424	$ 3,727
Marketing [Member]
REVENUES:
Revenues	1,219	964	3,738	3,250
OPERATING EXPENSES:
Marketing	$ 1,238	$ 978	$ 3,798	$ 3,333

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
NET INCOME (LOSS)		$ 85	$ (17)	$ 363	$ 619
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments	[1]	0	0	0	4
Reclassification of losses on settled derivative instruments	[1]	8	8	25	25
Other Comprehensive Income		8	8	25	29
COMPREHENSIVE INCOME (LOSS)		93	(9)	388	648
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(1)	(1)	(3)	(3)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		$ 92	$ (10)	$ 385	$ 645
[1]	Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ 363	$ 619
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:
Depreciation, depletion and amortization	867	689
Derivative (gains) losses, net	500	(452)
Cash payments on derivative settlements, net	(162)	(46)
Stock-based compensation	25	38
Net (gains) losses on sales of fixed assets	7	0
Impairments	51	3
Gains on investments	(139)	0
(Gains) losses on purchases or exchanges of debt	68	(185)
Other	(101)	(27)
Changes in assets and liabilities	116	(366)
Net Cash Provided By Operating Activities	1,595	273
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(1,481)	(1,597)
Acquisitions of proved and unproved properties	(244)	(226)
Proceeds from divestitures of proved and unproved properties	395	1,193
Additions to other property and equipment	(11)	(12)
Proceeds from sales of other property and equipment	75	40
Proceeds from sales of investments	74	0
Net Cash Used In Investing Activities	(1,192)	(602)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	9,095	4,775
Payments on revolving credit facility borrowings	(9,231)	(4,130)
Proceeds from issuance of senior notes, net	1,237	742
Payment for Debt Extinguishment or Debt Prepayment Cost	(122)	0
Cash paid to purchase debt	(1,285)	(1,751)
Cash paid for preferred stock dividends	(69)	(160)
Distributions to noncontrolling interest owners	(4)	(7)
Other	(25)	(17)
Net Cash Used In Financing Activities	(404)	(548)
Net decrease in cash and cash equivalents	(1)	(877)
Cash and cash equivalents, beginning of period	5	882
Cash and cash equivalents, end of period	4	5
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	412	342
Income taxes paid, net of refunds received	(3)	(15)
Change in accrued drilling and completion costs [Member]
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in non-cash investing and financing activities	165	134
Change in accrued acquisitions of proved and unproved properties [Member]
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in non-cash investing and financing activities	1	(1)
Change in divested proved and unproved properties [Member]
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in non-cash investing and financing activities	$ (5)	$ (23)

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Preferred stock [Member]	Preferred stock [Member]Preferred Stock, Exchanged for Shares of Common Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]Preferred Stock, Exchanged for Shares of Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock - Common [Member]	Parent [Member]	Noncontrolling Interest [Member]
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2016		$ 1,771			$ 14,486		$ (17,603)	$ (96)	$ (27)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Exchange/conversions of 0 and 236,048 shares of preferred stock for common stock			$ (100)
Stock-based compensation					43
Exchange of preferred stock for 0 and 9,965,835 shares of common stock						$ 100
Equity component of contingent convertible notes repurchased, net of tax					(20)
Dividends on preferred stock					(160)
Net income attributable to Chesapeake	$ 616						616
Cumulative effect of accounting change							0
Hedging activity								29
Purchase of 1,499,033 and 1,194,986 shares for company benefit plans									(7)
Release of 431,474 and 92,015 shares from company benefit plans									2
Chesapeake stockholders’ equity, end of period at Sep. 30, 2017		1,671		$ 9	14,449		(16,987)	(67)	(32)	$ (957)
Stockholders' equity attributable to noncontrolling interest, beginning of period at Dec. 31, 2016											$ 257
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to noncontrolling interests	(3)										3
Distributions to noncontrolling interest owners											(7)
Stockholders' equity attributable to noncontrolling interest, end of period at Sep. 30, 2017											253
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY (DEFICIT)	(704)
TOTAL EQUITY (DEFICIT)	(372)
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2017	(496)	1,671			14,437		(16,525)	(57)	(31)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Exchange/conversions of 0 and 236,048 shares of preferred stock for common stock			$ 0
Stock-based compensation					26
Exchange of preferred stock for 0 and 9,965,835 shares of common stock						$ 0
Equity component of contingent convertible notes repurchased, net of tax					0
Dividends on preferred stock					(69)
Net income attributable to Chesapeake	360						360
Cumulative effect of accounting change							(8)
Hedging activity								25
Purchase of 1,499,033 and 1,194,986 shares for company benefit plans									(4)
Release of 431,474 and 92,015 shares from company benefit plans									4
Chesapeake stockholders’ equity, end of period at Sep. 30, 2018	(162)	$ 1,671		$ 9	$ 14,394		$ (16,173)	$ (32)	$ (31)	$ (162)
Stockholders' equity attributable to noncontrolling interest, beginning of period at Dec. 31, 2017	124										124
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to noncontrolling interests	(3)										3
Distributions to noncontrolling interest owners											(4)
Stockholders' equity attributable to noncontrolling interest, end of period at Sep. 30, 2018	123										$ 123
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY (DEFICIT)	$ (39)

CONSOLIDATED STATEMENTS OF ST_2

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - shares	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Treasury Stock - Common [Member]
Purchase of shares for company benefit plans (in shares)	1,499,033	1,194,986
Release of shares from company benefit plans (in shares)	431,474	92,015
Preferred Stock, Exchanged for Shares of Common Stock [Member] | Preferred stock [Member]
Conversion of stock, shares converted (in shares)	0	236,048
Preferred Stock, Exchanged for Shares of Common Stock [Member] | Additional Paid-in Capital [Member]
Exchange of preferred stock (in shares)	0	9,965,835

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Basis of Presentation The accompanying condensed consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules and regulations of the SEC. Pursuant to such rules and regulations, certain disclosures have been condensed or omitted. This Form 10-Q relates to the three and nine months ended September 30, 2018 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2017 (the “Prior Quarter” and the “Prior Period”, respectively). Our annual report on Form 10-K for the year ended December 31, 2017 (“2017 Form 10-K”) should be read in conjunction with this Form 10-Q. The accompanying condensed consolidated financial statements reflect all normal recurring adjustments which, in the opinion of management, are necessary for a fair statement of our condensed consolidated financial statements and accompanying notes and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which we have a controlling financial interest. Intercompany accounts and balances have been eliminated . Recently Issued Accounting Standards The Financial Accounting Standards Board (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. See Note 10 for further details regarding our adoption of Topic 606. In February 2018, the FASB issued Accounting Standards Update (ASU) 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income . The new standard allows for stranded tax effects resulting from tax reform legislation known as the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) previously recognized in accumulated other comprehensive income to be reclassified to retained earnings. For public business entities, the amendments are effective for annual periods, including interim periods within the annual periods, beginning after December 15, 2018. Early adoption is permitted in any interim or annual period, but we do not plan to early adopt. We are currently evaluating the impact of this standard on our consolidated financial statements and related disclosures. In August 2017, the FASB issued ASU 2017-12 , Derivatives and Hedging (Topic 815), which makes significant changes to the current hedge accounting guidance. The new standard eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The new standard also eases certain documentation and assessment requirements and modifies the accounting for components excluded from the assessment of hedge effectiveness. The new standard update is effective for annual and interim periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted, but we do not plan to early adopt. We are currently evaluating the impact of this standard on our consolidated financial statements and related disclosures. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which updated lease accounting guidance requiring lessees to recognize most leases, including operating leases, on the balance sheet as a right-of-use asset and lease liability for leases with terms in excess of 12 months. In January 2018, the FASB issued ASU 2018-01 permitting an entity to elect an optional transition practical expedient to not evaluate land easements that existed or expired before the adoption of Topic 842 and were not previously accounted for as leases. In July 2018, the FASB issued ASU 2018-11 to provide an additional transition practical expedient by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We plan to elect both practical expedients. We plan to adopt the new standard on January 1, 2019 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings. The standard will not apply to our leases of mineral rights. Using the revised framework, we have completed our assessment of lease categories that we believe will be affected by the new standard. We are continuing to assess the accounting treatment for these leases but do not expect the adoption to have significant impacts to our consolidated financial statements or related disclosures.

Earnings Per Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2018
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 contingent convertible senior notes did not have a dilutive effect and, therefore, were excluded from the calculation of diluted EPS. See Note 3 for further discussion of our convertible senior notes and contingent convertible senior notes. A reconciliation of basic EPS and diluted EPS is as follows: Three Months Ended Nine Months Ended 2018 2017 2018 2017 (in millions, except per share data) Net income (loss) available to common stockholders $ 60 $ (41 ) $ 288 $ 506 Effect of dilutive securities — — — — Diluted income (loss) available to common stockholders $ 60 $ (41 ) $ 288 $ 506 Weighted average common and common equivalent shares outstanding - basic 910 909 909 908 Effect of dilutive securities 1 — — — Weighted average common and common equivalent shares outstanding - diluted 911 909 909 908 Net income per share attributable to Chesapeake: Basic $ 0.07 $ (0.05 ) $ 0.32 $ 0.56 Diluted $ 0.07 $ (0.05 ) $ 0.32 $ 0.56 Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive: Common stock equivalent of our preferred stock outstanding 60 60 60 60 Common stock equivalent of our convertible senior notes outstanding 146 146 146 146 Participating securities 2 — 1 1

Debt

Debt	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Debt	Debt Our long-term debt consisted of the following as of September 30, 2018 and December 31, 2017: September 30, 2018 December 31, 2017 Principal Amount Carrying Principal Carrying ($ in millions) 7.25% senior notes due 2018 $ 44 $ 44 $ 44 $ 44 Floating rate senior notes due 2019 380 380 380 380 6.625% senior notes due 2020 437 437 437 437 6.875% senior notes due 2020 227 227 227 227 6.125% senior notes due 2021 548 548 548 548 5.375% senior notes due 2021 267 267 267 267 4.875% senior notes due 2022 451 451 451 451 8.00% senior secured second lien notes due 2022 (a) 1,416 1,823 1,416 1,895 5.75% senior notes due 2023 338 338 338 338 7.00% senior notes due 2024 850 850 — — 8.00% senior notes due 2025 1,300 1,290 1,300 1,290 5.5% convertible senior notes due 2026 (b)(c) 1,250 859 1,250 837 7.5% senior notes due 2026 400 400 — — 8.00% senior notes due 2027 1,300 1,298 1,300 1,298 2.25% contingent convertible senior notes due 2038 (b) 9 8 9 8 Term loan due 2021 — — 1,233 1,233 Revolving credit facility 645 645 781 781 Debt issuance costs — (54 ) — (63 ) Interest rate derivatives — 1 — 2 Total debt, net 9,862 9,812 9,981 9,973 Less current maturities of long-term debt, net (d) (433 ) (432 ) (53 ) (52 ) Total long-term debt, net $ 9,429 $ 9,380 $ 9,928 $ 9,921 ___________________________________________ (a) On October 29, 2018, we delivered a notice of redemption to the trustee with respect to 100% of the aggregate principal amount of the outstanding senior secured second lien notes dues 2022. (b) 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 2.25% Contingent Convertible Senior Notes due 2038 and our 5.5% Convertible Senior Notes due 2026 are 8.0% and 11.5% , respectively. (c) Prior to maturity under certain circumstances and at the holder’s option, the notes are convertible. During the Current Quarter, the price of our common stock was below the threshold level for conversion and, as a result, the holders do not have the option to convert their notes in the fourth quarter of 2018. (d) As of September 30, 2018 , net current maturities of long-term debt includes our 7.25% Senior Notes due December 2018, our Floating Rate Senior Notes due April 2019, and due to the holders’ put option, our 2.25% Contingent Convertible Notes due December 2038. Debt Issuances and Retirements In the Current Quarter, 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 $1.230 billion . We used the net proceeds from the senior notes, together with cash on hand and borrowings under our 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 call premium. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the call premium and the write-off of $13 million of associated deferred charges. 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. In the Prior Period, we retired $1.609 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $1.751 billion . For the open market repurchases and tender offers, we recorded an aggregate net loss of approximately $1 million in the Prior Quarter and an aggregate gain of approximately $183 million in the Prior Period including $260 million of premium associated with our 8.00% Senior Secured Second Lien Notes due 2022. Revolving Credit Facility On September 12, 2018, we amended and restated our credit agreement dated December 15, 2014. The amended and restated revolving credit facility matures in September 2023 and the aggregate initial 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. Borrowing base redeterminations will continue to occur semiannually and our next borrowing base redetermination is scheduled for the second quarter of 2019. As of September 30, 2018 , we had outstanding borrowings of $645 million under the revolving credit facility and had used $182 million of the revolving credit facility for various letters of credit. We recorded a loss of $3 million associated with certain deferred charges related to the revolving credit facility prior to this amendment. Borrowings under the revolving credit facility bear interest at an alternative base rate (ABR) or LIBOR, at our election, plus an applicable margin ranging from 0.50% - 2.00% per annum for ABR loans and 1.50% - 3.00% per annum for LIBOR loans, depending on the percentage of the borrowing base then being utilized and whether our leverage ratio exceeds 4.00 to 1. 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. Our revolving credit facility contains financial covenants that, after a transition period and the suspension of most of the covenants during the fourth quarter of 2018 as a result of the closing of the sale of certain of our Utica Shale properties pursuant to our purchase and sale agreement with EAP Ohio, LLC (“Encino”), requires the Company to maintain (i) a leverage ratio of not more than 5.50 to 1 through the fiscal quarter ending September 30, 2019, which threshold decreases over time to 4.00 to 1 for the fiscal quarter ending March 31, 2021 and each fiscal quarter thereafter, (ii) a secured leverage ratio of not more than 2.50 to 1 until the later of (x) the fiscal quarter ending March 31, 2021 or (y) the fiscal quarter in when the Company’s leverage ratio does not exceed 4.00 to 1 and (iii) a fixed charge coverage ratio of not less than 2.00 to 1 through the fiscal quarter ending December 31, 2019; not less than 2.25 to 1 through the fiscal quarter ending June 30, 2020; and not less than 2.50 to 1 for the fiscal quarter ended September 30, 2020 and thereafter. For the Current Quarter, we were subject to the financial covenants applicable prior to the amended and restated revolving credit facility in addition to maintaining a leverage ratio of not more than 5.50 to 1. As of September 30, 2018 , 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 the revolving credit facility. 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: September 30, 2018 December 31, 2017 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 432 $ 433 $ 52 $ 53 Long-term debt (Level 1) $ 3,495 $ 3,546 $ 2,633 $ 2,629 Long-term debt (Level 2) $ 5,884 $ 6,010 $ 7,286 $ 7,301

Contingencies and Commitments

Contingencies and Commitments	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Contingencies and Commitments	Contingencies and Commitments There have been no material developments in previously reported legal or environmental contingencies or commitments other than the items discussed below. For a discussion of commitments and contingencies, see “Contingencies and Commitments,” Note 4 to the Consolidated Financial Statements in our 2017 Form 10-K. Contingencies Regulatory and Related Proceedings . We have previously disclosed receiving U.S. Postal Service and state subpoenas seeking information on our royalty payment practices. The U.S. Postal Service inquiry and all such outstanding state subpoenas have been resolved. We have also previously disclosed defending lawsuits alleging various violations of the Sherman Antitrust Act and state antitrust laws. In 2016, putative class action lawsuits were filed in the U.S. District Court for the Western District of Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the U.S. District Court of Kansas, in each case against us and other defendants. The lawsuits generally allege that, since 2007 and continuing through April 2013, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties in the Anadarko Basin containing producing oil and natural gas wells. The lawsuits seek damages, attorney’s fees, costs and interest, as well as enjoinment from adopting practices or plans that would restrain competition in a similar manner as alleged in the lawsuits. On April 12, 2018, we reached a tentative settlement to resolve substantially all Oklahoma civil class action antitrust cases for an immaterial amount. On July 28, 2017, OOGC America LLC (OOGC) filed a demand for arbitration with the American Arbitration Association against Chesapeake Exploration, L.L.C., our wholly owned subsidiary, in connection with OOGC’s purchase of certain oil and gas leases and other assets pursuant to a Purchase and Sale Agreement entered into on October 10, 2010. In connection with the sale, we also entered into a Development Agreement with OOGC, dated November 15, 2010 (the “Development Agreement”), which governs each of our rights and obligations with respect to the sale, including the transportation and marketing of oil and gas. OOGC’s breach of contract, breach of agency and fiduciary duties and other claims generally allege, among other things, that we subjected OOGC to excessive rates for gathering and other services provided for under the Development Agreement and interfered with OOGC’s right to audit the documents that supported those rates. OOGC seeks relief that may be material, including unspecified damages, attorneys’ fees, costs and expenses, disgorgement and various declaratory judgments. We intend to vigorously defend these claims. 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 the Company engaged in material misrepresentations and fraud, and that we violated the Exchange Act and Oklahoma Uniform Securities Act. HOOPP seeks either rescission or $215 million in monetary damages, and in either case, interest, attorney’s fees, disgorgement and punitive damages. We intend to vigorously defend these claims. Commitments Gathering, Processing and Transportation Agreements We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in our estimates of proved reserves. The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below: September 30, ($ in millions) 2018 $ 269 2019 1,048 2020 992 2021 900 2022 792 2023 – 2035 4,443 Total $ 8,444 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.

Other Liabilities

Other Liabilities	9 Months Ended
	Sep. 30, 2018
Other Liabilities Disclosure [Abstract]
Other Liabilities	Other Liabilities Other current liabilities as of September 30, 2018 and December 31, 2017 are detailed below: September 30, December 31, ($ in millions) Revenues and royalties due others $ 535 $ 612 Accrued drilling and production costs 313 216 Joint interest prepayments received 81 74 Accrued compensation and benefits 192 214 Other accrued taxes 123 43 Other 194 296 Total other current liabilities $ 1,438 $ 1,455 Other long-term liabilities as of September 30, 2018 and December 31, 2017 are detailed below: September 30, December 31, ($ in millions) CHK Utica ORRI conveyance obligation (a) $ — $ 156 Unrecognized tax benefits 53 101 Other 107 97 Total other long-term liabilities $ 160 $ 354 ____________________________________________ (a) In the Current Period, we repurchased previously conveyed overriding royalty interests (ORRI) from the CHK Utica, L.L.C. investors and extinguished our obligation to convey future ORRIs to the CHK Utica, L.L.C. investors for combined consideration of $199 million . The total CHK Utica ORRI conveyance obligation extinguished in the Current Period was $183 million , of which, $30 million was recorded in current liabilities and $153 million was recorded in long-term liabilities. The fair value of the consideration allocated to the extinguishment of liability, $122 million , was less than the carrying amount of the conveyance obligation and resulted in a gain of $61 million recognized in other income on our condensed consolidated statement of operations. The fair value of the consideration allocated to the purchase of ORRIs on proved producing properties was $77 million and recorded in proved oil and natural gas properties in our condensed consolidated balance sheet.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes We estimate our annual effective tax rate for continuing operations in recording our quarterly income tax provision (or benefit) for the various jurisdictions in which we operate. The tax effects of statutory rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred tax assets are excluded from the determination of our estimated annual effective tax rate as such items are recognized as discrete items in the quarter in which they occur. For the Current Quarter, our estimated annual effective tax rate remains nominal as a result of having a full valuation allowance against our net deferred tax asset. Taking into account our projected operating results for the subsequent 2018 quarter, we project remaining in a net deferred tax asset position as of December 31, 2018. Based on all available positive and negative evidence, including estimates of future taxable income, we believe it is more-likely-than-not that these deferred tax assets will not be realized. A significant piece of objectively verifiable negative evidence evaluated is the cumulative loss incurred over the rolling three-year period ending September 30, 2018. Such evidence limits our ability to consider various forms of subjective positive evidence, such as our projections for future growth and earnings. A valuation allowance was recorded against substantially all of our net deferred tax asset as of December 31, 2017 and against all of our net deferred tax asset as of September 30, 2018. We are subject to U.S. federal income tax as well as income and capital taxes in various state jurisdictions in which we operate. We recorded a $1 million income tax expense in the Current Quarter and an $8 million income tax benefit in the Current Period. The $1 million expense in the Current Quarter was a result of discrete items related to additional state income tax expense for the settlement of a state income tax audit and the filing of amended state income tax returns. The $8 million benefit in the Current Period was a result of discrete items consisting of a $13 million reduction to the liability for state unrecognized tax benefits due to the expiration of applicable statutes of limitations which was partially offset by eliminating a deferred tax asset for alternative minimum tax carryforwards in the amount of $3 million and recording additional state income tax expense of $2 million relating primarily to the settlement of a state income tax audit and the filing of amended state income tax returns. A further reduction to the liability for state unrecognized tax benefits was also recorded against interest expense in the amount of $4 million . On December 22, 2017, the President of the United States signed into law the Tax Act, which substantially revised numerous areas of U.S. federal income tax law, including reducing the tax rate for corporations from a maximum rate of 35% to a flat rate of 21% and eliminating the corporate alternative minimum tax (AMT). The various estimates included in determining our tax provision as of December 31, 2017 remain provisional through the nine months ended September 30, 2018 and may be adjusted through subsequent events such as the filing of the 2017 consolidated federal income tax return and the issuance of additional guidance such as new Treasury Regulations. Moreover, we are still in the process of evaluating the full impact of the Tax Act both at the federal and state level.

Share-Based Compensation

Share-Based Compensation	9 Months Ended
	Sep. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [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 plans. The restricted stock and stock options are equity-classified awards and the PSUs and CRSUs are liability-classified awards. Equity-Classified Awards Restricted Stock. We grant restricted stock units to employees and non-employee directors. A summary of the changes in unvested restricted stock during the Current Period is presented below: Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value Per Share (in thousands) Unvested restricted stock as of January 1, 2018 13,178 $ 6.37 Granted 5,776 $ 3.77 Vested (5,782 ) $ 7.67 Forfeited (1,376 ) $ 6.09 Unvested restricted stock as of September 30, 2018 11,796 $ 4.49 The aggregate intrinsic value of restricted stock that vested during the Current Period was approximately $20 million based on the stock price at the time of vesting. As of September 30, 2018 , there was approximately $38 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 2.12 years. Stock Options. In the Current Period and the Prior Period, we granted members of management stock options that vest ratably over a three -year period. Each stock option award has an exercise price equal to the closing price of our common stock on the grant date. Outstanding options expire seven years to ten years from the date of grant. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method. Volatility assumptions are estimated based on the average historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account our dividend policy, over the expected life of the option. We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Period: Expected option life – years 6.0 Volatility 63.55 % Risk-free interest rate 2.72 % Dividend yield — % The following table provides information related to stock option activity in the Current Period: Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Contract Life in Years Aggregate Intrinsic Value (a) (in thousands) ($ in millions) Outstanding as of January 1, 2018 16,285 $ 8.25 7.73 $ 1 Granted 3,611 $ 3.01 Exercised — $ — $ — Expired (602 ) $ 13.83 Forfeited (1,067 ) $ 5.45 Outstanding as of September 30, 2018 18,227 $ 7.19 7.44 $ 8 Exercisable as of September 30, 2018 8,250 $ 10.73 6.05 $ 2 ___________________________________________ (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 September 30, 2018 , there was $16 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.74 years . Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Nine Months Ended 2018 2017 2018 2017 ($ in millions) General and administrative expenses $ 6 $ 9 $ 21 $ 20 Oil and natural gas properties 1 3 5 7 Oil, natural gas and NGL production expenses 1 2 4 7 Total restricted stock and stock option compensation $ 8 $ 14 $ 30 $ 34 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 and 2016, 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 2016 and 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. We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the 2017 and 2016 PSU awards. Grant Date Assumptions Assumption 2017 Awards 2016 Awards Volatility 80.65 % 49.74 % Risk-free interest rate 1.54 % 1.13 % Dividend yield for value of awards — % — % Reporting Period Assumptions Assumption 2017 Awards 2016 Awards Volatility 51.65 % 41.46 % Risk-free interest rate 2.65 % 2.19 % Dividend yield for value of awards — % — % As the above assumptions change, the PSU liabilities will be adjusted quarterly through the end of the performance period. For PSUs granted in 2018, 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% . 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 the performance period. Cash Restricted Stock Units . In the Current Period, 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 performance period. The CRSUs are subsequently adjusted, based on changes in our stock price through the end of each subsequent reporting period, through the end of each vesting period. The following table presents a summary of our liability-classified awards: Grant Date Fair Value September 30, 2018 Units Fair Value Vested Liability ($ in millions) ($ in millions) 2018 PSU Awards: Payable 2019, 2020 and 2021 3,992,358 $ 12 $ 18 $ — 2017 PSU Awards: Payable 2020 1,217,774 $ 8 $ 6 $ 4 2016 PSU Awards: Payable 2019 2,348,893 $ 10 $ 11 $ 10 2018 CRSU Awards: Payable 2019, 2020 and 2021 16,034,295 $ 48 $ 72 $ —

Derivative and Hedging Activiti

Derivative and Hedging Activities	9 Months Ended
	Sep. 30, 2018
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 September 30, 2018 or December 31, 2017. Oil, Natural Gas and NGL Derivatives As of September 30, 2018 and December 31, 2017, 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 that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time. • 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 September 30, 2018 and December 31, 2017 are provided below: September 30, 2018 December 31, 2017 Notional Volume Fair Value Notional Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 21 $ (294 ) 21 $ (151 ) Three-way collars — (8 ) 2 (10 ) Call swaptions — — 2 (13 ) Basis protection swaps 8 2 11 (9 ) Total oil 29 (300 ) 36 (183 ) Natural gas (bcf): Fixed-price swaps 400 (a) (19 ) 532 149 Three-way collars 88 3 — — Collars 66 — 47 11 Call options 60 — 110 (3 ) Basis protection swaps 44 (7 ) 65 (7 ) Total natural gas 658 (23 ) 754 150 NGL (mmgal): Fixed-price swaps 57 (15 ) 33 (2 ) Total estimated fair value $ (338 ) $ (35 ) ____________________________________________ a) Includes 170 bcf related to trades executed in accordance with the purchase and sale agreement with Encino. These trades are reflected at fair market value as of September 30, 2018, with an offsetting receivable balance. The trades were novated to Encino upon closing of the purchase and sale agreement on October 29, 2018. 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) . Effect of Derivative Instruments – Condensed Consolidated Balance Sheets The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017 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 Sheet ($ in millions) As of September 30, 2018 Commodity Contracts: Short-term derivative asset $ 14 $ (14 ) $ — Long-term derivative asset 3 (3 ) — Short-term derivative liability (324 ) 14 (310 ) Long-term derivative liability (31 ) 3 (28 ) Total derivatives $ (338 ) $ — $ (338 ) As of December 31, 2017 Commodity Contracts: Short-term derivative asset $ 157 $ (130 ) $ 27 Short-term derivative liability (188 ) 130 (58 ) Long-term derivative liability (4 ) — (4 ) Total derivatives $ (35 ) $ — $ (35 ) Effect of Derivative Instruments – Condensed Consolidated Statements of Operations The components of oil, natural gas and NGL revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below: Three Months Ended Nine Months Ended 2018 2017 2018 2017 ($ in millions) Oil, natural gas and NGL revenues $ 1,331 $ 1,049 $ 3,924 $ 3,275 Gains (losses) on undesignated oil, natural gas and NGL derivatives (124 ) (62 ) (475 ) 477 Losses on terminated cash flow hedges (8 ) (8 ) (25 ) (25 ) Total oil, natural gas and NGL revenues $ 1,199 $ 979 $ 3,424 $ 3,727 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: Three Months Ended September 30, 2018 2017 Before After Before After ($ in millions) Balance, beginning of period $ (97 ) $ (40 ) $ (132 ) (75 ) Losses reclassified to income 8 8 8 8 Balance, end of period $ (89 ) $ (32 ) (124 ) (67 ) Nine Months Ended September 30, 2018 2017 Before After Before After ($ in millions) Balance, beginning of period $ (114 ) $ (57 ) $ (153 ) $ (96 ) Net change in fair value — — 4 4 Losses reclassified to income 25 25 25 25 Balance, end of period $ (89 ) $ (32 ) $ (124 ) $ (67 ) The accumulated other comprehensive loss as of September 30, 2018 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 of September 30, 2018 , we expect to transfer approximately $35 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 September 30, 2018 , our oil, natural gas and NGL derivative instruments were spread among 11 counterparties. Hedging Arrangements Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our revolving credit facility. The contracts entered into with these counterparties are secured by the same collateral that secures our 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 September 30, 2018 , we posted $14 million in letters of credit as collateral for our commodity derivatives. No cash was posted as collateral for our commodity derivatives. Fair Value The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil, natural gas and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas and NGL swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives. The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of September 30, 2018 Derivative Assets (Liabilities): Commodity assets $ — $ 7 $ 11 $ 18 Commodity liabilities — (340 ) (16 ) (356 ) Total derivatives $ — $ (333 ) $ (5 ) $ (338 ) As of December 31, 2017 Derivative Assets (Liabilities): Commodity assets $ — $ — $ 8 $ 8 Commodity liabilities — (20 ) (23 ) (43 ) Total derivatives $ — $ (20 ) $ (15 ) $ (35 ) A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during the Current Period and the Prior Period is presented below: Commodity Derivatives ($ in millions) Balance, as of January 1, 2018 $ (15 ) Total gains (losses) (realized/unrealized): Included in earnings (a) (3 ) Total purchases, issuances, sales and settlements: Settlements 13 Balance, as of September 30, 2018 $ (5 ) Balance, as of January 1, 2017 $ (10 ) Total gains (losses) (realized/unrealized): Included in earnings (a) 1 Total purchases, issuances, sales and settlements: Settlements 1 Balance, as of September 30, 2017 $ (8 ) ___________________________________________ (a) Commodity Derivatives 2018 2017 ($ in millions) Total gains (losses) included in earnings for the period $ (3 ) $ 1 Change in unrealized gains (losses) related to assets still held at reporting date $ (3 ) $ (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 impacts 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 at fair value as of September 30, 2018 : Instrument Type Unobservable Input Range Weighted Average Fair Value ($ in millions) Oil trades Oil price volatility curves 19.09% – 28.60% 24.97% $ (8 ) Natural gas trades Natural gas price volatility curves 15.60% – 62.08% 16.24% $ 3

Oil and Natural Gas Property Tr

Oil and Natural Gas Property Transactions	9 Months Ended
	Sep. 30, 2018
Property, Plant and Equipment [Abstract]
Oil and Natural Gas Property Transactions	Oil and Natural Gas Property Transactions Under full cost accounting rules, we account for sales of oil and natural gas properties as adjustments to capitalized costs, with no recognition of gain or loss unless a sale involves a significant change in proved reserves and significantly alters the relationship between capitalized costs and proved reserves. On October 29, 2018 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 (collectively, the “Designated Properties”) 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 price strip prices for the months comprising the year 2023 equals or exceeds $3.25 /mmbtu as calculated pursuant to the purchase agreement. We expect the sale of our Designated Properties to Encino to involve a significant change in proved reserves and to significantly alter the relationship between costs and proved reserves and therefore to result in the recognition of loss upon closing of that transaction. Under SEC rules for full cost companies, a transaction is deemed to be significant if the properties being sold represent 25% or more of the reserve quantities of the divesting company. In the Current Period, 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. Also, in the Current Quarter and the Current Period, we received proceeds of approximately $8 million and $31 million , respectively, subject to customary closing adjustments, for the sale of other oil and natural gas properties covering various operating areas. In the Prior Period, 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. 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 the Prior Quarter and the Prior Period, we received proceeds of approximately $248 million and $331 million , respectively, net of post-closing adjustments, for the sale of other oil and natural gas properties covering various operating areas. Volumetric Production Payments A VPP is a limited-term overriding royalty interest in oil and natural gas reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is non-recourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores. As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. Future costs will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which the production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all. We have committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices. As of September 30, 2018 , we had the following VPP outstanding: Volume Sold VPP # Date of VPP Location Proceeds Oil Natural Gas NGL Total ($ in millions) (mmbbl) (bcf) (mmbbl) (bcfe) 9 May 2011 Mid-Continent $ 853 1.7 138 4.8 177 The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2018 were as follows: Volume Remaining as of September 30, 2018 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 9 29 0.3 25.8 0.7 31.4

Revenue Recognition

Revenue Recognition	9 Months Ended
	Sep. 30, 2018
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 $8 million did not have a material impact on our condensed consolidated financial statements. However, the adoption did result in certain purchase and sale contracts being recorded on a net basis, as an agent, rather than on a gross basis, as principal, due to management’s evaluation under new considerations within Topic 606 that indicated we do not have control over the specified commodity in purchase and sale contracts with the same counterparty. Such presentation change did not have an impact on income (loss) from operations, earnings per share or cash flows. In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our condensed consolidated statements of operations was as follows: Before adoption of ASC 606 Adjustments As Reported ($ in millions) Statement of Operations for the Three Months Ended September 30, 2018 Marketing revenues $ 1,508 $ (289 ) $ 1,219 Marketing operating expenses $ 1,516 $ (278 ) $ 1,238 Statement of Operations for the Nine Months Ended September 30, 2018 Marketing revenues $ 4,320 $ (582 ) $ 3,738 Marketing operating expenses $ 4,365 $ (567 ) $ 3,798 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. 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 condensed 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 condensed 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 condensed 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 condensed 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. These purchase and sales contracts were accounted for as derivatives under Derivatives and Hedging (Topic 815) and were not elected as normal purchase or normal sales. We considered the principal versus agent guidance in Topic 606 in determining whether the gains and losses on these derivatives should be reported on a gross or net basis . The following table shows revenue disaggregated by operating area and product type, for the Current Quarter and the Current Period: Three Months Ended September 30, 2018 Oil Natural Gas NGL Total ($ in millions) Marcellus $ — $ 184 $ — $ 184 Haynesville — 195 — 195 Eagle Ford 399 36 58 493 Utica 59 131 76 266 Mid-Continent 58 15 12 85 Powder River Basin 78 17 13 108 Revenue from contracts with customers 594 578 159 1,331 Losses on oil, natural gas and NGL derivatives (100 ) (18 ) (14 ) (132 ) Oil, natural gas and NGL revenue $ 494 $ 560 $ 145 $ 1,199 Marketing revenue from contracts with customers $ 707 $ 211 $ 112 $ 1,030 Other marketing revenue 119 70 — 189 Marketing revenue $ 826 $ 281 $ 112 $ 1,219 Nine Months Ended September 30, 2018 Oil Natural Gas NGL Total ($ in millions) Marcellus $ — $ 646 $ — $ 646 Haynesville 2 603 — 605 Eagle Ford 1,148 120 143 1,411 Utica 179 350 189 718 Mid-Continent 196 63 42 301 Powder River Basin 173 40 30 243 Revenue from contracts with customers 1,698 1,822 404 3,924 Losses on oil, natural gas and NGL derivatives (388 ) (85 ) (27 ) (500 ) Oil, natural gas and NGL revenue $ 1,310 $ 1,737 $ 377 $ 3,424 Marketing revenue from contracts with customers $ 2,125 $ 733 $ 324 $ 3,182 Other marketing revenue 381 175 — 556 Marketing revenue $ 2,506 $ 908 $ 324 $ 3,738 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. Accounts receivable as of September 30, 2018 and December 31, 2017 are detailed below: September 30, 2018 December 31, 2017 ($ in millions) Oil, natural gas and NGL sales $ 829 $ 959 Joint interest 160 209 Other 78 184 Allowance for doubtful accounts (16 ) (30 ) Total accounts receivable, net $ 1,051 $ 1,322

Investments

Investments	9 Months Ended
	Sep. 30, 2018
Equity Method Investments and Joint Ventures [Abstract]
Investments	Investments In the Current Period, FTS International, Inc. (NYSE: FTSI) 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.

Impairments

Impairments	9 Months Ended
	Sep. 30, 2018
Property, Plant and Equipment [Abstract]
Impairments	Impairments In the Current Period, we have determined that certain of our other fixed assets will either be sold or disposed before the end of their useful lives indicating the carrying value may not be recoverable. As a result, we recognized an impairment loss of $51 million in the Current Period for the difference between the carrying amount and fair value of the assets.

Other Operating Expenses

Other Operating Expenses	9 Months Ended
	Sep. 30, 2018
Asset Impairment Charges [Abstract]
Other Operating Expenses	Other Operating Expenses In the Prior Period, we terminated future natural gas transportation commitments related to divested assets for cash payments of $126 million . In the Prior Period, we paid $290 million to assign an oil transportation agreement to a third party.

Restructuring and Other Termina

Restructuring and Other Termination Costs	9 Months Ended
	Sep. 30, 2018
Restructuring and Related Activities [Abstract]
Restructuring and Other Termination Costs	Restructuring and Other Termination Costs Workforce Reduction On January 30, 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 in the Current Period of approximately $38 million for one-time termination benefits. The following table summarizes our restructuring liabilities: Other Current Liabilities ($ in millions) Balance as of December 31, 2017 $ — Initial restructuring recognition on January 30, 2018 38 Termination benefits paid (38 ) Balance as of September 30, 2018 $ —

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2018
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 September 30, 2018 and December 31, 2017: 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 September 30, 2018 Financial Assets (Liabilities): Other current assets $ 54 $ — $ — $ 54 Other current liabilities (54 ) — — (54 ) Total $ — $ — $ — $ — As of December 31, 2017 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (60 ) — — (60 ) Total $ (3 ) $ — $ — $ (3 ) See Note 3 for information regarding fair value measurement of our debt instruments. See Note 8 for information regarding fair value measurement of our derivatives.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	9 Months Ended
	Sep. 30, 2018
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 our outstanding senior notes, contingent convertible senior notes and revolving credit facility listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries. 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 as of September 30, 2018 and December 31, 2017 and for the three and nine months ended September 30, 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 SEPTEMBER 30, 2018 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 6 $ 1 $ 1 $ (4 ) $ 4 Other current assets 69 1,160 2 — 1,231 Intercompany receivable, net 8,003 29 176 (8,208 ) — Total Current Assets 8,078 1,190 179 (8,212 ) 1,235 PROPERTY AND EQUIPMENT: Oil and natural gas properties at cost, based on full cost accounting, net 563 9,433 25 — 10,021 Other property and equipment, net — 1,109 — — 1,109 Property and equipment held for sale, net — 47 — — 47 Total Property and Equipment, Net 563 10,589 25 — 11,177 LONG-TERM ASSETS: Other long-term assets 29 218 — — 247 Investments in subsidiaries and intercompany advances 1,193 79 — (1,272 ) — TOTAL ASSETS $ 9,863 $ 12,076 $ 204 $ (9,484 ) $ 12,659 CURRENT LIABILITIES: Current liabilities $ 563 $ 2,415 $ 2 $ (4 ) $ 2,976 Intercompany payable, net 29 8,179 — (8,208 ) — Total Current Liabilities 592 10,594 2 (8,212 ) 2,976 LONG-TERM LIABILITIES: Long-term debt, net 9,380 — — — 9,380 Other long-term liabilities 53 289 — — 342 Total Long-Term Liabilities 9,433 289 — — 9,722 EQUITY: Chesapeake stockholders’ equity (deficit) (162 ) 1,193 79 (1,272 ) (162 ) Noncontrolling interests — — 123 — 123 Total Equity (Deficit) (162 ) 1,193 202 (1,272 ) (39 ) TOTAL LIABILITIES AND EQUITY $ 9,863 $ 12,076 $ 204 $ (9,484 ) $ 12,659 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2017 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 5 $ 1 $ 2 $ (3 ) $ 5 Other current assets 154 1,364 3 (1 ) 1,520 Intercompany receivable, net 8,697 436 — (9,133 ) — Total Current Assets 8,856 1,801 5 (9,137 ) 1,525 PROPERTY AND EQUIPMENT: Oil and natural gas properties at cost, based on full cost accounting, net 435 8,888 27 — 9,350 Other property and equipment, net — 1,314 — — 1,314 Property and equipment held for sale, net — 16 — — 16 Total Property and Equipment, Net 435 10,218 27 — 10,680 LONG-TERM ASSETS: Other long-term assets 52 168 — — 220 Investments in subsidiaries and intercompany advances 806 (146 ) — (660 ) — TOTAL ASSETS $ 10,149 $ 12,041 $ 32 $ (9,797 ) $ 12,425 CURRENT LIABILITIES: Current liabilities $ 190 $ 2,168 $ 2 $ (4 ) $ 2,356 Intercompany payable, net 433 8,648 52 (9,133 ) — Total Current Liabilities 623 10,816 54 (9,137 ) 2,356 LONG-TERM LIABILITIES: Long-term debt, net 9,921 — — — 9,921 Other long-term liabilities 101 419 — — 520 Total Long-Term Liabilities 10,022 419 — — 10,441 EQUITY: Chesapeake stockholders’ equity (deficit) (496 ) 806 (146 ) (660 ) (496 ) Noncontrolling interests — — 124 — 124 Total Equity (Deficit) (496 ) 806 (22 ) (660 ) (372 ) TOTAL LIABILITIES AND EQUITY $ 10,149 $ 12,041 $ 32 $ (9,797 ) $ 12,425 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, 2018 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 1,194 $ 5 $ — $ 1,199 Marketing — 1,219 — — 1,219 Total Revenues — 2,413 5 — 2,418 OPERATING EXPENSES: Oil, natural gas and NGL production — 132 — — 132 Oil, natural gas and NGL gathering, processing and transportation — 362 2 — 364 Production taxes — 33 1 — 34 Marketing — 1,238 — — 1,238 General and administrative — 66 — — 66 Provision for legal contingencies, net — 8 — — 8 Oil, natural gas and NGL depreciation, depletion and amortization — 274 — — 274 Depreciation and amortization of other assets — 17 — — 17 Impairments — 5 — — 5 Total Operating Expenses — 2,135 3 — 2,138 INCOME FROM OPERATIONS — 278 2 — 280 OTHER INCOME (EXPENSE): Interest expense (125 ) (2 ) — — (127 ) Losses on purchases or exchanges of debt (68 ) — — — (68 ) Other income — 1 — — 1 Equity in net earnings of subsidiary 278 1 — (279 ) — Total Other Income (Expense) 85 — — (279 ) (194 ) INCOME BEFORE INCOME TAXES 85 278 2 (279 ) 86 INCOME TAX EXPENSE 1 — — — 1 NET INCOME 84 278 2 (279 ) 85 Net income attributable to noncontrolling interests — — (1 ) — (1 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 84 278 1 (279 ) 84 Other comprehensive income — 8 — — 8 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 84 $ 286 $ 1 $ (279 ) $ 92 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 974 $ 5 $ — $ 979 Marketing — 964 — — 964 Total Revenues — 1,938 5 — 1,943 OPERATING EXPENSES: Oil, natural gas and NGL production — 151 — — 151 Oil, natural gas and NGL gathering, processing and transportation — 367 2 — 369 Production taxes — 20 1 — 21 Marketing — 978 — — 978 General and administrative — 54 — — 54 Provision for legal contingencies, net — 20 — — 20 Oil, natural gas and NGL depreciation, depletion and amortization — 227 1 — 228 Depreciation and amortization of other assets — 20 — — 20 Impairments — 3 — — 3 Net gains on sales of fixed assets — (1 ) — — (1 ) Other operating expense — 6 — — 6 Total Operating Expenses — 1,845 4 — 1,849 INCOME FROM OPERATIONS — 93 1 — 94 OTHER INCOME (EXPENSE): Interest expense (110 ) (4 ) — — (114 ) Losses on purchases or exchanges of debt (1 ) — — — (1 ) Other income 1 3 — — 4 Equity in net earnings of subsidiary 92 — — (92 ) — Total Other Income (Expense) (18 ) (1 ) — (92 ) (111 ) INCOME (LOSS) BEFORE INCOME TAXES (18 ) 92 1 (92 ) (17 ) INCOME TAX EXPENSE — — — — — NET INCOME (LOSS) (18 ) 92 1 (92 ) (17 ) Net income attributable to noncontrolling interests — — (1 ) — (1 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE (18 ) 92 — (92 ) (18 ) Other comprehensive income — 8 — — 8 COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE $ (18 ) $ 100 $ — $ (92 ) $ (10 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 2018 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 3,410 $ 14 $ — $ 3,424 Marketing — 3,738 — — 3,738 Total Revenues — 7,148 14 — 7,162 OPERATING EXPENSES: Oil, natural gas and NGL production — 417 — — 417 Oil, natural gas and NGL gathering, processing and transportation — 1,055 5 — 1,060 Production taxes — 90 1 — 91 Marketing — 3,798 — — 3,798 General and administrative — 228 1 — 229 Restructuring and other termination costs — 38 — — 38 Provision for legal contingencies, net — 17 — — 17 Oil, natural gas and NGL depreciation, depletion and amortization — 811 2 — 813 Depreciation and amortization of other assets — 54 — — 54 Impairments — 51 — — 51 Other operating income — (1 ) — — (1 ) Net losses on sales of fixed assets — 7 — — 7 Total Operating Expenses — 6,565 9 — 6,574 INCOME FROM OPERATIONS — 583 5 — 588 OTHER INCOME (EXPENSE): Interest expense (365 ) (2 ) — — (367 ) Gains on investments — 139 — — 139 Losses on exchanges or repurchases of debt (68 ) — — — (68 ) Other income — 63 — — 63 Equity in net earnings of subsidiary 785 2 — (787 ) — Total Other Income (Expense) 352 202 — (787 ) (233 ) INCOME BEFORE INCOME TAXES 352 785 5 (787 ) 355 INCOME TAX BENEFIT (8 ) — — — (8 ) NET INCOME 360 785 5 (787 ) 363 Net income attributable to noncontrolling interests — — (3 ) — (3 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 360 785 2 (787 ) 360 Other comprehensive income — 25 — — 25 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 360 $ 810 $ 2 $ (787 ) $ 385 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 3,710 $ 17 $ — $ 3,727 Marketing — 3,250 — — 3,250 Total Revenues — 6,960 17 — 6,977 OPERATING EXPENSES: Oil, natural gas and NGL production — 426 — — 426 Oil, natural gas and NGL gathering, processing and transportation — 1,075 6 — 1,081 Production taxes — 63 1 — 64 Marketing — 3,333 — — 3,333 General and administrative 3 185 1 — 189 Provision for legal contingencies, net — 35 — — 35 Oil, natural gas and NGL depreciation, depletion and amortization — 624 3 — 627 Depreciation and amortization of other assets — 62 — — 62 Impairments — 3 — — 3 Other operating expense — 423 — — 423 Total Operating Expenses 3 6,229 11 — 6,243 INCOME (LOSS) FROM OPERATIONS (3 ) 731 6 — 734 OTHER INCOME (EXPENSE): Interest expense (300 ) (2 ) — — (302 ) Gains on purchases or exchanges of debt 183 — — — 183 Other income 1 5 — — 6 Equity in net earnings of subsidiary 737 3 — (740 ) — Total Other Income (Expense) 621 6 — (740 ) (113 ) INCOME BEFORE INCOME TAXES 618 737 6 (740 ) 621 INCOME TAX EXPENSE 2 — — — 2 NET INCOME 616 737 6 (740 ) 619 Net income attributable to noncontrolling interests — — (3 ) — (3 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 616 737 3 (740 ) 616 Other comprehensive income — 29 — — 29 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 616 $ 766 $ 3 $ (740 ) $ 645 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS NINE MONTHS ENDED SEPTEMBER 30, 2018 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 86 $ 1,512 $ 7 $ (10 ) $ 1,595 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,481 ) — — (1,481 ) Acquisitions of proved and unproved properties — (244 ) — — (244 ) Proceeds from divestitures of proved and unproved properties — 395 — — 395 Additions to other property and equipment — (11 ) — — (11 ) Other investing activities — 149 — — 149 Net Cash Used In Investing Activities — (1,192 ) — — (1,192 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 9,095 — — — 9,095 Payments on revolving credit facility borrowings (9,231 ) — — — (9,231 ) Proceeds from issuance of senior notes, net 1,237 — — — 1,237 Cash paid to purchase debt (1,285 ) — — — (1,285 ) Cash paid for preferred stock dividends (69 ) — — — (69 ) Other financing activities (2 ) (127 ) (9 ) (13 ) (151 ) Intercompany advances, net 170 (193 ) 1 22 — Net Cash Used In Financing Activities (85 ) (320 ) (8 ) 9 (404 ) Net increase (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 $ 6 $ 1 $ 1 $ (4 ) $ 4 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS NINE MONTHS ENDED SEPTEMBER 30, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 4 $ 266 $ 11 $ (8 ) $ 273 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,597 ) — — (1,597 ) Acquisitions of proved and unproved properties — (226 ) — — (226 ) Proceeds from divestitures of proved and unproved properties — 1,193 — — 1,193 Additions to other property and equipment — (12 ) — — (12 ) Other investing activities — 40 — — 40 Net Cash Used In Investing Activities — (602 ) — — (602 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 4,775 — — — 4,775 Payments on revolving credit facility borrowings (4,130 ) — — — (4,130 ) Proceeds from issuance of senior notes, net 742 — — — 742 Cash paid to purchase debt (1,751 ) — — — (1,751 ) Cash paid for preferred stock dividends (160 ) — — — (160 ) Other financing activities (36 ) (4 ) (11 ) 27 (24 ) Intercompany advances, net (339 ) 339 — — — Net Cash Provided by (Used In) Financing Activities (899 ) 335 (11 ) 27 (548 ) Net increase (decrease) in cash and cash equivalents (895 ) (1 ) — 19 (877 ) Cash and cash equivalents, beginning of period 904 2 1 (25 ) 882 Cash and cash equivalents, end of period $ 9 $ 1 $ 1 $ (6 ) $ 5

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2018
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On October 30, 2018, we jointly announced with WildHorse Resource Development Corporation (“WildHorse”) that we have entered into a definitive agreement to acquire WildHorse, an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, in a transaction valued at approximately $3.977 billion , including the value of WildHorse’s net debt of $930 million as of June 30, 2018. At the election of each WildHorse common shareholder, the consideration will consist of either 5.989 shares of Chesapeake common stock or a combination of 5.336 shares of Chesapeake common stock and $3.00 in cash for each share of WildHorse common stock. We intend to fund the cash portion of the consideration through borrowings under our revolving credit facility. The transaction has been unanimously approved by the Board of Directors of each company and is subject to shareholder approvals from both companies and customary closing conditions and regulatory approvals and is expected to close in the first half of 2019. On October 29, 2018, we completed the sale of our Utica Shale assets in Ohio to Encino, pursuant to which Encino purchased 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 (collectively, the “Designated Properties”) for net proceeds of $1.868 billion in cash. On October 29, 2018, we delivered a notice of redemption to the trustee for our 8.00% Senior Secured Second Lien Notes due 2022 to call for redemption $1.416 billion aggregate principal amount of the outstanding notes, representing 100% of the aggregate principal amount of the outstanding notes. The notes will be redeemed at a redemption price of 100% of the principal amount thereof, plus the make-whole premium, as calculated in accordance with the indenture, plus accrued and unpaid interest. The settlement of the redemption is expected to occur approximately 30 days from the notice delivery date. The redemption is expected to be funded with proceeds from the sale of our Utica assets in Ohio.

Basis of Presentation (Policy)

Basis of Presentation (Policy)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying condensed consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules and regulations of the SEC. Pursuant to such rules and regulations, certain disclosures have been condensed or omitted.
Recently Issued Accounting Standards	Recently Issued Accounting Standards The Financial Accounting Standards Board (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. See Note 10 for further details regarding our adoption of Topic 606. In February 2018, the FASB issued Accounting Standards Update (ASU) 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income . The new standard allows for stranded tax effects resulting from tax reform legislation known as the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) previously recognized in accumulated other comprehensive income to be reclassified to retained earnings. For public business entities, the amendments are effective for annual periods, including interim periods within the annual periods, beginning after December 15, 2018. Early adoption is permitted in any interim or annual period, but we do not plan to early adopt. We are currently evaluating the impact of this standard on our consolidated financial statements and related disclosures. In August 2017, the FASB issued ASU 2017-12 , Derivatives and Hedging (Topic 815), which makes significant changes to the current hedge accounting guidance. The new standard eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The new standard also eases certain documentation and assessment requirements and modifies the accounting for components excluded from the assessment of hedge effectiveness. The new standard update is effective for annual and interim periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted, but we do not plan to early adopt. We are currently evaluating the impact of this standard on our consolidated financial statements and related disclosures. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which updated lease accounting guidance requiring lessees to recognize most leases, including operating leases, on the balance sheet as a right-of-use asset and lease liability for leases with terms in excess of 12 months. In January 2018, the FASB issued ASU 2018-01 permitting an entity to elect an optional transition practical expedient to not evaluate land easements that existed or expired before the adoption of Topic 842 and were not previously accounted for as leases. In July 2018, the FASB issued ASU 2018-11 to provide an additional transition practical expedient by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We plan to elect both practical expedients. We plan to adopt the new standard on January 1, 2019 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings. The standard will not apply to our leases of mineral rights. Using the revised framework, we have completed our assessment of lease categories that we believe will be affected by the new standard. We are continuing to assess the accounting treatment for these leases but do not expect the adoption to have significant impacts to our consolidated financial statements or related disclosures.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Reconciliation of basic EPS and diluted EPS	A reconciliation of basic EPS and diluted EPS is as follows: Three Months Ended Nine Months Ended 2018 2017 2018 2017 (in millions, except per share data) Net income (loss) available to common stockholders $ 60 $ (41 ) $ 288 $ 506 Effect of dilutive securities — — — — Diluted income (loss) available to common stockholders $ 60 $ (41 ) $ 288 $ 506 Weighted average common and common equivalent shares outstanding - basic 910 909 909 908 Effect of dilutive securities 1 — — — Weighted average common and common equivalent shares outstanding - diluted 911 909 909 908 Net income per share attributable to Chesapeake: Basic $ 0.07 $ (0.05 ) $ 0.32 $ 0.56 Diluted $ 0.07 $ (0.05 ) $ 0.32 $ 0.56 Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive: Common stock equivalent of our preferred stock outstanding 60 60 60 60 Common stock equivalent of our convertible senior notes outstanding 146 146 146 146 Participating securities 2 — 1 1
Reconciliation of basic EPS and diluted EPS	A reconciliation of basic EPS and diluted EPS is as follows: Three Months Ended Nine Months Ended 2018 2017 2018 2017 (in millions, except per share data) Net income (loss) available to common stockholders $ 60 $ (41 ) $ 288 $ 506 Effect of dilutive securities — — — — Diluted income (loss) available to common stockholders $ 60 $ (41 ) $ 288 $ 506 Weighted average common and common equivalent shares outstanding - basic 910 909 909 908 Effect of dilutive securities 1 — — — Weighted average common and common equivalent shares outstanding - diluted 911 909 909 908 Net income per share attributable to Chesapeake: Basic $ 0.07 $ (0.05 ) $ 0.32 $ 0.56 Diluted $ 0.07 $ (0.05 ) $ 0.32 $ 0.56 Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive: Common stock equivalent of our preferred stock outstanding 60 60 60 60 Common stock equivalent of our convertible senior notes outstanding 146 146 146 146 Participating securities 2 — 1 1

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Schedule of long-term debt	Our long-term debt consisted of the following as of September 30, 2018 and December 31, 2017: September 30, 2018 December 31, 2017 Principal Amount Carrying Principal Carrying ($ in millions) 7.25% senior notes due 2018 $ 44 $ 44 $ 44 $ 44 Floating rate senior notes due 2019 380 380 380 380 6.625% senior notes due 2020 437 437 437 437 6.875% senior notes due 2020 227 227 227 227 6.125% senior notes due 2021 548 548 548 548 5.375% senior notes due 2021 267 267 267 267 4.875% senior notes due 2022 451 451 451 451 8.00% senior secured second lien notes due 2022 (a) 1,416 1,823 1,416 1,895 5.75% senior notes due 2023 338 338 338 338 7.00% senior notes due 2024 850 850 — — 8.00% senior notes due 2025 1,300 1,290 1,300 1,290 5.5% convertible senior notes due 2026 (b)(c) 1,250 859 1,250 837 7.5% senior notes due 2026 400 400 — — 8.00% senior notes due 2027 1,300 1,298 1,300 1,298 2.25% contingent convertible senior notes due 2038 (b) 9 8 9 8 Term loan due 2021 — — 1,233 1,233 Revolving credit facility 645 645 781 781 Debt issuance costs — (54 ) — (63 ) Interest rate derivatives — 1 — 2 Total debt, net 9,862 9,812 9,981 9,973 Less current maturities of long-term debt, net (d) (433 ) (432 ) (53 ) (52 ) Total long-term debt, net $ 9,429 $ 9,380 $ 9,928 $ 9,921 ___________________________________________ (a) On October 29, 2018, we delivered a notice of redemption to the trustee with respect to 100% of the aggregate principal amount of the outstanding senior secured second lien notes dues 2022. (b) 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 2.25% Contingent Convertible Senior Notes due 2038 and our 5.5% Convertible Senior Notes due 2026 are 8.0% and 11.5% , respectively. (c) Prior to maturity under certain circumstances and at the holder’s option, the notes are convertible. During the Current Quarter, the price of our common stock was below the threshold level for conversion and, as a result, the holders do not have the option to convert their notes in the fourth quarter of 2018. (d) As of September 30, 2018 , net current maturities of long-term debt includes our 7.25% Senior Notes due December 2018, our Floating Rate Senior Notes due April 2019, and due to the holders’ put option, our 2.25% Contingent Convertible Notes due December 2038.
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: September 30, 2018 December 31, 2017 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 432 $ 433 $ 52 $ 53 Long-term debt (Level 1) $ 3,495 $ 3,546 $ 2,633 $ 2,629 Long-term debt (Level 2) $ 5,884 $ 6,010 $ 7,286 $ 7,301

Contingencies and Commitments (

Contingencies and Commitments (Tables)	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of contractual obligation	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: September 30, ($ in millions) 2018 $ 269 2019 1,048 2020 992 2021 900 2022 792 2023 – 2035 4,443 Total $ 8,444

Other Liabilities (Tables)

Other Liabilities (Tables)	9 Months Ended
	Sep. 30, 2018
Other Liabilities Disclosure [Abstract]
Other current liabilities	Other current liabilities as of September 30, 2018 and December 31, 2017 are detailed below: September 30, December 31, ($ in millions) Revenues and royalties due others $ 535 $ 612 Accrued drilling and production costs 313 216 Joint interest prepayments received 81 74 Accrued compensation and benefits 192 214 Other accrued taxes 123 43 Other 194 296 Total other current liabilities $ 1,438 $ 1,455
Other long-term liabilities	Other long-term liabilities as of September 30, 2018 and December 31, 2017 are detailed below: September 30, December 31, ($ in millions) CHK Utica ORRI conveyance obligation (a) $ — $ 156 Unrecognized tax benefits 53 101 Other 107 97 Total other long-term liabilities $ 160 $ 354 ____________________________________________ (a) In the Current Period, we repurchased previously conveyed overriding royalty interests (ORRI) from the CHK Utica, L.L.C. investors and extinguished our obligation to convey future ORRIs to the CHK Utica, L.L.C. investors for combined consideration of $199 million . The total CHK Utica ORRI conveyance obligation extinguished in the Current Period was $183 million , of which, $30 million was recorded in current liabilities and $153 million was recorded in long-term liabilities. The fair value of the consideration allocated to the extinguishment of liability, $122 million , was less than the carrying amount of the conveyance obligation and resulted in a gain of $61 million recognized in other income on our condensed consolidated statement of operations. The fair value of the consideration allocated to the purchase of ORRIs on proved producing properties was $77 million and recorded in proved oil and natural gas properties in our condensed consolidated balance sheet.

Share-Based Compensation (Table

Share-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of the changes in unvested restricted stock	A summary of the changes in unvested restricted stock during the Current Period is presented below: Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value Per Share (in thousands) Unvested restricted stock as of January 1, 2018 13,178 $ 6.37 Granted 5,776 $ 3.77 Vested (5,782 ) $ 7.67 Forfeited (1,376 ) $ 6.09 Unvested restricted stock as of September 30, 2018 11,796 $ 4.49
Weighted average assumptions to estimate grant date fair value of the stock options granted	We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the 2017 and 2016 PSU awards. Grant Date Assumptions Assumption 2017 Awards 2016 Awards Volatility 80.65 % 49.74 % Risk-free interest rate 1.54 % 1.13 % Dividend yield for value of awards — % — % Reporting Period Assumptions Assumption 2017 Awards 2016 Awards Volatility 51.65 % 41.46 % Risk-free interest rate 2.65 % 2.19 % Dividend yield for value of awards — % — % We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Period: Expected option life – years 6.0 Volatility 63.55 % Risk-free interest rate 2.72 % Dividend yield — %
Schedule of stock option activity	The following table provides information related to stock option activity in the Current Period: 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, 2018 16,285 $ 8.25 7.73 $ 1 Granted 3,611 $ 3.01 Exercised — $ — $ — Expired (602 ) $ 13.83 Forfeited (1,067 ) $ 5.45 Outstanding as of September 30, 2018 18,227 $ 7.19 7.44 $ 8 Exercisable as of September 30, 2018 8,250 $ 10.73 6.05 $ 2 ___________________________________________ (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.
Restricted stock and stock option compensation	We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Nine Months Ended 2018 2017 2018 2017 ($ in millions) General and administrative expenses $ 6 $ 9 $ 21 $ 20 Oil and natural gas properties 1 3 5 7 Oil, natural gas and NGL production expenses 1 2 4 7 Total restricted stock and stock option compensation $ 8 $ 14 $ 30 $ 34
Assumptions and TSR performance measure to determine grant date fair value of PSUs	We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the 2017 and 2016 PSU awards. Grant Date Assumptions Assumption 2017 Awards 2016 Awards Volatility 80.65 % 49.74 % Risk-free interest rate 1.54 % 1.13 % Dividend yield for value of awards — % — % Reporting Period Assumptions Assumption 2017 Awards 2016 Awards Volatility 51.65 % 41.46 % Risk-free interest rate 2.65 % 2.19 % Dividend yield for value of awards — % — % We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Period: Expected option life – years 6.0 Volatility 63.55 % Risk-free interest rate 2.72 % Dividend yield — %
Schedule of PSU awards	The following table presents a summary of our liability-classified awards: Grant Date Fair Value September 30, 2018 Units Fair Value Vested Liability ($ in millions) ($ in millions) 2018 PSU Awards: Payable 2019, 2020 and 2021 3,992,358 $ 12 $ 18 $ — 2017 PSU Awards: Payable 2020 1,217,774 $ 8 $ 6 $ 4 2016 PSU Awards: Payable 2019 2,348,893 $ 10 $ 11 $ 10 2018 CRSU Awards: Payable 2019, 2020 and 2021 16,034,295 $ 48 $ 72 $ —
PSU compensation	We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Nine Months Ended 2018 2017 2018 2017 ($ in millions) General and administrative expenses $ 6 $ 9 $ 21 $ 20 Oil and natural gas properties 1 3 5 7 Oil, natural gas and NGL production expenses 1 2 4 7 Total restricted stock and stock option compensation $ 8 $ 14 $ 30 $ 34

Derivative and Hedging Activi_2

Derivative and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of estimated fair values of oil, natural gas and NGL derivative instruments	The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of September 30, 2018 and December 31, 2017 are provided below: September 30, 2018 December 31, 2017 Notional Volume Fair Value Notional Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 21 $ (294 ) 21 $ (151 ) Three-way collars — (8 ) 2 (10 ) Call swaptions — — 2 (13 ) Basis protection swaps 8 2 11 (9 ) Total oil 29 (300 ) 36 (183 ) Natural gas (bcf): Fixed-price swaps 400 (a) (19 ) 532 149 Three-way collars 88 3 — — Collars 66 — 47 11 Call options 60 — 110 (3 ) Basis protection swaps 44 (7 ) 65 (7 ) Total natural gas 658 (23 ) 754 150 NGL (mmgal): Fixed-price swaps 57 (15 ) 33 (2 ) Total estimated fair value $ (338 ) $ (35 ) ____________________________________________ a) Includes 170 bcf related to trades executed in accordance with the purchase and sale agreement with Encino. These trades are reflected at fair market value as of September 30, 2018, with an offsetting receivable balance. The trades were novated to Encino upon closing of the purchase and sale agreement on October 29, 2018.
Schedule of effect of derivative instruments, condensed consolidated balance sheets	The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017 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 Sheet ($ in millions) As of September 30, 2018 Commodity Contracts: Short-term derivative asset $ 14 $ (14 ) $ — Long-term derivative asset 3 (3 ) — Short-term derivative liability (324 ) 14 (310 ) Long-term derivative liability (31 ) 3 (28 ) Total derivatives $ (338 ) $ — $ (338 ) As of December 31, 2017 Commodity Contracts: Short-term derivative asset $ 157 $ (130 ) $ 27 Short-term derivative liability (188 ) 130 (58 ) Long-term derivative liability (4 ) — (4 ) Total derivatives $ (35 ) $ — $ (35 )
Schedule of effect of derivative instruments, condensed consolidated statements of operations	The components of oil, natural gas and NGL revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below: Three Months Ended Nine Months Ended 2018 2017 2018 2017 ($ in millions) Oil, natural gas and NGL revenues $ 1,331 $ 1,049 $ 3,924 $ 3,275 Gains (losses) on undesignated oil, natural gas and NGL derivatives (124 ) (62 ) (475 ) 477 Losses on terminated cash flow hedges (8 ) (8 ) (25 ) (25 ) Total oil, natural gas and NGL revenues $ 1,199 $ 979 $ 3,424 $ 3,727
Schedule of 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: Three Months Ended September 30, 2018 2017 Before After Before After ($ in millions) Balance, beginning of period $ (97 ) $ (40 ) $ (132 ) (75 ) Losses reclassified to income 8 8 8 8 Balance, end of period $ (89 ) $ (32 ) (124 ) (67 ) Nine Months Ended September 30, 2018 2017 Before After Before After ($ in millions) Balance, beginning of period $ (114 ) $ (57 ) $ (153 ) $ (96 ) Net change in fair value — — 4 4 Losses reclassified to income 25 25 25 25 Balance, end of period $ (89 ) $ (32 ) $ (124 ) $ (67 )
Schedule of financial assets (liabilities)	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017: 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 September 30, 2018 Derivative Assets (Liabilities): Commodity assets $ — $ 7 $ 11 $ 18 Commodity liabilities — (340 ) (16 ) (356 ) Total derivatives $ — $ (333 ) $ (5 ) $ (338 ) As of December 31, 2017 Derivative Assets (Liabilities): Commodity assets $ — $ — $ 8 $ 8 Commodity liabilities — (20 ) (23 ) (43 ) Total derivatives $ — $ (20 ) $ (15 ) $ (35 ) A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during the Current Period and the Prior Period is presented below: Commodity Derivatives ($ in millions) Balance, as of January 1, 2018 $ (15 ) Total gains (losses) (realized/unrealized): Included in earnings (a) (3 ) Total purchases, issuances, sales and settlements: Settlements 13 Balance, as of September 30, 2018 $ (5 ) Balance, as of January 1, 2017 $ (10 ) Total gains (losses) (realized/unrealized): Included in earnings (a) 1 Total purchases, issuances, sales and settlements: Settlements 1 Balance, as of September 30, 2017 $ (8 ) ___________________________________________ (a) Commodity Derivatives 2018 2017 ($ in millions) Total gains (losses) included in earnings for the period $ (3 ) $ 1 Change in unrealized gains (losses) related to assets still held at reporting date $ (3 ) $ (7 ) 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 September 30, 2018 and December 31, 2017: 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 September 30, 2018 Financial Assets (Liabilities): Other current assets $ 54 $ — $ — $ 54 Other current liabilities (54 ) — — (54 ) Total $ — $ — $ — $ — As of December 31, 2017 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (60 ) — — (60 ) Total $ (3 ) $ — $ — $ (3 )
Schedule of quantitative information about level 3 inputs used	The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of September 30, 2018 : Instrument Type Unobservable Input Range Weighted Average Fair Value ($ in millions) Oil trades Oil price volatility curves 19.09% – 28.60% 24.97% $ (8 ) Natural gas trades Natural gas price volatility curves 15.60% – 62.08% 16.24% $ 3

Oil and Natural Gas Property _2

Oil and Natural Gas Property Transactions (Tables)	9 Months Ended
	Sep. 30, 2018
Property, Plant and Equipment [Abstract]
VPP Transactions	As of September 30, 2018 , we had the following VPP outstanding: Volume Sold VPP # Date of VPP Location Proceeds Oil Natural Gas NGL Total ($ in millions) (mmbbl) (bcf) (mmbbl) (bcfe) 9 May 2011 Mid-Continent $ 853 1.7 138 4.8 177
VPP Volumes Remaining to Be Delivered	The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2018 were as follows: Volume Remaining as of September 30, 2018 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 9 29 0.3 25.8 0.7 31.4

Revenue Recognition (Tables)

Revenue Recognition (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Adoption of new revenue standard	In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our condensed consolidated statements of operations was as follows: Before adoption of ASC 606 Adjustments As Reported ($ in millions) Statement of Operations for the Three Months Ended September 30, 2018 Marketing revenues $ 1,508 $ (289 ) $ 1,219 Marketing operating expenses $ 1,516 $ (278 ) $ 1,238 Statement of Operations for the Nine Months Ended September 30, 2018 Marketing revenues $ 4,320 $ (582 ) $ 3,738 Marketing operating expenses $ 4,365 $ (567 ) $ 3,798
Disaggregation of revenue	The following table shows revenue disaggregated by operating area and product type, for the Current Quarter and the Current Period: Three Months Ended September 30, 2018 Oil Natural Gas NGL Total ($ in millions) Marcellus $ — $ 184 $ — $ 184 Haynesville — 195 — 195 Eagle Ford 399 36 58 493 Utica 59 131 76 266 Mid-Continent 58 15 12 85 Powder River Basin 78 17 13 108 Revenue from contracts with customers 594 578 159 1,331 Losses on oil, natural gas and NGL derivatives (100 ) (18 ) (14 ) (132 ) Oil, natural gas and NGL revenue $ 494 $ 560 $ 145 $ 1,199 Marketing revenue from contracts with customers $ 707 $ 211 $ 112 $ 1,030 Other marketing revenue 119 70 — 189 Marketing revenue $ 826 $ 281 $ 112 $ 1,219 Nine Months Ended September 30, 2018 Oil Natural Gas NGL Total ($ in millions) Marcellus $ — $ 646 $ — $ 646 Haynesville 2 603 — 605 Eagle Ford 1,148 120 143 1,411 Utica 179 350 189 718 Mid-Continent 196 63 42 301 Powder River Basin 173 40 30 243 Revenue from contracts with customers 1,698 1,822 404 3,924 Losses on oil, natural gas and NGL derivatives (388 ) (85 ) (27 ) (500 ) Oil, natural gas and NGL revenue $ 1,310 $ 1,737 $ 377 $ 3,424 Marketing revenue from contracts with customers $ 2,125 $ 733 $ 324 $ 3,182 Other marketing revenue 381 175 — 556 Marketing revenue $ 2,506 $ 908 $ 324 $ 3,738
Accounts receivable	Accounts receivable as of September 30, 2018 and December 31, 2017 are detailed below: September 30, 2018 December 31, 2017 ($ in millions) Oil, natural gas and NGL sales $ 829 $ 959 Joint interest 160 209 Other 78 184 Allowance for doubtful accounts (16 ) (30 ) Total accounts receivable, net $ 1,051 $ 1,322

Restructuring and Other Termi_2

Restructuring and Other Termination Costs (Tables)	9 Months Ended
	Sep. 30, 2018
Restructuring and Related Activities [Abstract]
Summary of restructuring liabilities	The following table summarizes our restructuring liabilities: Other Current Liabilities ($ in millions) Balance as of December 31, 2017 $ — Initial restructuring recognition on January 30, 2018 38 Termination benefits paid (38 ) Balance as of September 30, 2018 $ —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2018
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 September 30, 2018 and December 31, 2017: 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 September 30, 2018 Derivative Assets (Liabilities): Commodity assets $ — $ 7 $ 11 $ 18 Commodity liabilities — (340 ) (16 ) (356 ) Total derivatives $ — $ (333 ) $ (5 ) $ (338 ) As of December 31, 2017 Derivative Assets (Liabilities): Commodity assets $ — $ — $ 8 $ 8 Commodity liabilities — (20 ) (23 ) (43 ) Total derivatives $ — $ (20 ) $ (15 ) $ (35 ) A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during the Current Period and the Prior Period is presented below: Commodity Derivatives ($ in millions) Balance, as of January 1, 2018 $ (15 ) Total gains (losses) (realized/unrealized): Included in earnings (a) (3 ) Total purchases, issuances, sales and settlements: Settlements 13 Balance, as of September 30, 2018 $ (5 ) Balance, as of January 1, 2017 $ (10 ) Total gains (losses) (realized/unrealized): Included in earnings (a) 1 Total purchases, issuances, sales and settlements: Settlements 1 Balance, as of September 30, 2017 $ (8 ) ___________________________________________ (a) Commodity Derivatives 2018 2017 ($ in millions) Total gains (losses) included in earnings for the period $ (3 ) $ 1 Change in unrealized gains (losses) related to assets still held at reporting date $ (3 ) $ (7 ) 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 September 30, 2018 and December 31, 2017: 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 September 30, 2018 Financial Assets (Liabilities): Other current assets $ 54 $ — $ — $ 54 Other current liabilities (54 ) — — (54 ) Total $ — $ — $ — $ — As of December 31, 2017 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (60 ) — — (60 ) Total $ (3 ) $ — $ — $ (3 )

Condensed Consolidating Finan_2

Condensed Consolidating Financial Information (Tables)	9 Months Ended
	Sep. 30, 2018
Condensed Financial Information Disclosure [Abstract]
Condensed Consolidated Balance Sheets	CONDENSED CONSOLIDATING BALANCE SHEET AS OF SEPTEMBER 30, 2018 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 6 $ 1 $ 1 $ (4 ) $ 4 Other current assets 69 1,160 2 — 1,231 Intercompany receivable, net 8,003 29 176 (8,208 ) — Total Current Assets 8,078 1,190 179 (8,212 ) 1,235 PROPERTY AND EQUIPMENT: Oil and natural gas properties at cost, based on full cost accounting, net 563 9,433 25 — 10,021 Other property and equipment, net — 1,109 — — 1,109 Property and equipment held for sale, net — 47 — — 47 Total Property and Equipment, Net 563 10,589 25 — 11,177 LONG-TERM ASSETS: Other long-term assets 29 218 — — 247 Investments in subsidiaries and intercompany advances 1,193 79 — (1,272 ) — TOTAL ASSETS $ 9,863 $ 12,076 $ 204 $ (9,484 ) $ 12,659 CURRENT LIABILITIES: Current liabilities $ 563 $ 2,415 $ 2 $ (4 ) $ 2,976 Intercompany payable, net 29 8,179 — (8,208 ) — Total Current Liabilities 592 10,594 2 (8,212 ) 2,976 LONG-TERM LIABILITIES: Long-term debt, net 9,380 — — — 9,380 Other long-term liabilities 53 289 — — 342 Total Long-Term Liabilities 9,433 289 — — 9,722 EQUITY: Chesapeake stockholders’ equity (deficit) (162 ) 1,193 79 (1,272 ) (162 ) Noncontrolling interests — — 123 — 123 Total Equity (Deficit) (162 ) 1,193 202 (1,272 ) (39 ) TOTAL LIABILITIES AND EQUITY $ 9,863 $ 12,076 $ 204 $ (9,484 ) $ 12,659 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2017 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 5 $ 1 $ 2 $ (3 ) $ 5 Other current assets 154 1,364 3 (1 ) 1,520 Intercompany receivable, net 8,697 436 — (9,133 ) — Total Current Assets 8,856 1,801 5 (9,137 ) 1,525 PROPERTY AND EQUIPMENT: Oil and natural gas properties at cost, based on full cost accounting, net 435 8,888 27 — 9,350 Other property and equipment, net — 1,314 — — 1,314 Property and equipment held for sale, net — 16 — — 16 Total Property and Equipment, Net 435 10,218 27 — 10,680 LONG-TERM ASSETS: Other long-term assets 52 168 — — 220 Investments in subsidiaries and intercompany advances 806 (146 ) — (660 ) — TOTAL ASSETS $ 10,149 $ 12,041 $ 32 $ (9,797 ) $ 12,425 CURRENT LIABILITIES: Current liabilities $ 190 $ 2,168 $ 2 $ (4 ) $ 2,356 Intercompany payable, net 433 8,648 52 (9,133 ) — Total Current Liabilities 623 10,816 54 (9,137 ) 2,356 LONG-TERM LIABILITIES: Long-term debt, net 9,921 — — — 9,921 Other long-term liabilities 101 419 — — 520 Total Long-Term Liabilities 10,022 419 — — 10,441 EQUITY: Chesapeake stockholders’ equity (deficit) (496 ) 806 (146 ) (660 ) (496 ) Noncontrolling interests — — 124 — 124 Total Equity (Deficit) (496 ) 806 (22 ) (660 ) (372 ) TOTAL LIABILITIES AND EQUITY $ 10,149 $ 12,041 $ 32 $ (9,797 ) $ 12,425
Condensed Consolidated Income Statements	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, 2018 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 1,194 $ 5 $ — $ 1,199 Marketing — 1,219 — — 1,219 Total Revenues — 2,413 5 — 2,418 OPERATING EXPENSES: Oil, natural gas and NGL production — 132 — — 132 Oil, natural gas and NGL gathering, processing and transportation — 362 2 — 364 Production taxes — 33 1 — 34 Marketing — 1,238 — — 1,238 General and administrative — 66 — — 66 Provision for legal contingencies, net — 8 — — 8 Oil, natural gas and NGL depreciation, depletion and amortization — 274 — — 274 Depreciation and amortization of other assets — 17 — — 17 Impairments — 5 — — 5 Total Operating Expenses — 2,135 3 — 2,138 INCOME FROM OPERATIONS — 278 2 — 280 OTHER INCOME (EXPENSE): Interest expense (125 ) (2 ) — — (127 ) Losses on purchases or exchanges of debt (68 ) — — — (68 ) Other income — 1 — — 1 Equity in net earnings of subsidiary 278 1 — (279 ) — Total Other Income (Expense) 85 — — (279 ) (194 ) INCOME BEFORE INCOME TAXES 85 278 2 (279 ) 86 INCOME TAX EXPENSE 1 — — — 1 NET INCOME 84 278 2 (279 ) 85 Net income attributable to noncontrolling interests — — (1 ) — (1 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 84 278 1 (279 ) 84 Other comprehensive income — 8 — — 8 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 84 $ 286 $ 1 $ (279 ) $ 92 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 974 $ 5 $ — $ 979 Marketing — 964 — — 964 Total Revenues — 1,938 5 — 1,943 OPERATING EXPENSES: Oil, natural gas and NGL production — 151 — — 151 Oil, natural gas and NGL gathering, processing and transportation — 367 2 — 369 Production taxes — 20 1 — 21 Marketing — 978 — — 978 General and administrative — 54 — — 54 Provision for legal contingencies, net — 20 — — 20 Oil, natural gas and NGL depreciation, depletion and amortization — 227 1 — 228 Depreciation and amortization of other assets — 20 — — 20 Impairments — 3 — — 3 Net gains on sales of fixed assets — (1 ) — — (1 ) Other operating expense — 6 — — 6 Total Operating Expenses — 1,845 4 — 1,849 INCOME FROM OPERATIONS — 93 1 — 94 OTHER INCOME (EXPENSE): Interest expense (110 ) (4 ) — — (114 ) Losses on purchases or exchanges of debt (1 ) — — — (1 ) Other income 1 3 — — 4 Equity in net earnings of subsidiary 92 — — (92 ) — Total Other Income (Expense) (18 ) (1 ) — (92 ) (111 ) INCOME (LOSS) BEFORE INCOME TAXES (18 ) 92 1 (92 ) (17 ) INCOME TAX EXPENSE — — — — — NET INCOME (LOSS) (18 ) 92 1 (92 ) (17 ) Net income attributable to noncontrolling interests — — (1 ) — (1 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE (18 ) 92 — (92 ) (18 ) Other comprehensive income — 8 — — 8 COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE $ (18 ) $ 100 $ — $ (92 ) $ (10 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 2018 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 3,410 $ 14 $ — $ 3,424 Marketing — 3,738 — — 3,738 Total Revenues — 7,148 14 — 7,162 OPERATING EXPENSES: Oil, natural gas and NGL production — 417 — — 417 Oil, natural gas and NGL gathering, processing and transportation — 1,055 5 — 1,060 Production taxes — 90 1 — 91 Marketing — 3,798 — — 3,798 General and administrative — 228 1 — 229 Restructuring and other termination costs — 38 — — 38 Provision for legal contingencies, net — 17 — — 17 Oil, natural gas and NGL depreciation, depletion and amortization — 811 2 — 813 Depreciation and amortization of other assets — 54 — — 54 Impairments — 51 — — 51 Other operating income — (1 ) — — (1 ) Net losses on sales of fixed assets — 7 — — 7 Total Operating Expenses — 6,565 9 — 6,574 INCOME FROM OPERATIONS — 583 5 — 588 OTHER INCOME (EXPENSE): Interest expense (365 ) (2 ) — — (367 ) Gains on investments — 139 — — 139 Losses on exchanges or repurchases of debt (68 ) — — — (68 ) Other income — 63 — — 63 Equity in net earnings of subsidiary 785 2 — (787 ) — Total Other Income (Expense) 352 202 — (787 ) (233 ) INCOME BEFORE INCOME TAXES 352 785 5 (787 ) 355 INCOME TAX BENEFIT (8 ) — — — (8 ) NET INCOME 360 785 5 (787 ) 363 Net income attributable to noncontrolling interests — — (3 ) — (3 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 360 785 2 (787 ) 360 Other comprehensive income — 25 — — 25 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 360 $ 810 $ 2 $ (787 ) $ 385 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 3,710 $ 17 $ — $ 3,727 Marketing — 3,250 — — 3,250 Total Revenues — 6,960 17 — 6,977 OPERATING EXPENSES: Oil, natural gas and NGL production — 426 — — 426 Oil, natural gas and NGL gathering, processing and transportation — 1,075 6 — 1,081 Production taxes — 63 1 — 64 Marketing — 3,333 — — 3,333 General and administrative 3 185 1 — 189 Provision for legal contingencies, net — 35 — — 35 Oil, natural gas and NGL depreciation, depletion and amortization — 624 3 — 627 Depreciation and amortization of other assets — 62 — — 62 Impairments — 3 — — 3 Other operating expense — 423 — — 423 Total Operating Expenses 3 6,229 11 — 6,243 INCOME (LOSS) FROM OPERATIONS (3 ) 731 6 — 734 OTHER INCOME (EXPENSE): Interest expense (300 ) (2 ) — — (302 ) Gains on purchases or exchanges of debt 183 — — — 183 Other income 1 5 — — 6 Equity in net earnings of subsidiary 737 3 — (740 ) — Total Other Income (Expense) 621 6 — (740 ) (113 ) INCOME BEFORE INCOME TAXES 618 737 6 (740 ) 621 INCOME TAX EXPENSE 2 — — — 2 NET INCOME 616 737 6 (740 ) 619 Net income attributable to noncontrolling interests — — (3 ) — (3 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 616 737 3 (740 ) 616 Other comprehensive income — 29 — — 29 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 616 $ 766 $ 3 $ (740 ) $ 645
Condensed Consolidated Cash Flow Statements	Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 86 $ 1,512 $ 7 $ (10 ) $ 1,595 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,481 ) — — (1,481 ) Acquisitions of proved and unproved properties — (244 ) — — (244 ) Proceeds from divestitures of proved and unproved properties — 395 — — 395 Additions to other property and equipment — (11 ) — — (11 ) Other investing activities — 149 — — 149 Net Cash Used In Investing Activities — (1,192 ) — — (1,192 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 9,095 — — — 9,095 Payments on revolving credit facility borrowings (9,231 ) — — — (9,231 ) Proceeds from issuance of senior notes, net 1,237 — — — 1,237 Cash paid to purchase debt (1,285 ) — — — (1,285 ) Cash paid for preferred stock dividends (69 ) — — — (69 ) Other financing activities (2 ) (127 ) (9 ) (13 ) (151 ) Intercompany advances, net 170 (193 ) 1 22 — Net Cash Used In Financing Activities (85 ) (320 ) (8 ) 9 (404 ) Net increase (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 $ 6 $ 1 $ 1 $ (4 ) $ 4 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS NINE MONTHS ENDED SEPTEMBER 30, 2017 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ 4 $ 266 $ 11 $ (8 ) $ 273 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,597 ) — — (1,597 ) Acquisitions of proved and unproved properties — (226 ) — — (226 ) Proceeds from divestitures of proved and unproved properties — 1,193 — — 1,193 Additions to other property and equipment — (12 ) — — (12 ) Other investing activities — 40 — — 40 Net Cash Used In Investing Activities — (602 ) — — (602 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving credit facility borrowings 4,775 — — — 4,775 Payments on revolving credit facility borrowings (4,130 ) — — — (4,130 ) Proceeds from issuance of senior notes, net 742 — — — 742 Cash paid to purchase debt (1,751 ) — — — (1,751 ) Cash paid for preferred stock dividends (160 ) — — — (160 ) Other financing activities (36 ) (4 ) (11 ) 27 (24 ) Intercompany advances, net (339 ) 339 — — — Net Cash Provided by (Used In) Financing Activities (899 ) 335 (11 ) 27 (548 ) Net increase (decrease) in cash and cash equivalents (895 ) (1 ) — 19 (877 ) Cash and cash equivalents, beginning of period 904 2 1 (25 ) 882 Cash and cash equivalents, end of period $ 9 $ 1 $ 1 $ (6 ) $ 5

Earnings Per Share - Antidiluti

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss) available to common stockholders	$ 60	$ (41)	$ 288	$ 506
Effect of dilutive securities	0	0	0	0
Diluted income (loss) available to common stockholders	$ 60	$ (41)	$ 288	$ 506
Dilutive Securities, Effect on Basic Earnings Per Share [Abstract]
Weighted average common and common equivalent shares outstanding, basic (in shares)	910	909	909	908
Effect of dilutive securities (in shares)	1	0	0	0
Weighted average common and common equivalent shares outstanding, diluted (in shares)	911	909	909	908
Net income per share attributable to Chesapeake:
Earnings per common share, basic (in dollars per share)	$ 0.07	$ (0.05)	$ 0.32	$ 0.56
Earnings per common share, diluted (in dollars per share)	$ 0.07	$ (0.05)	$ 0.32	$ 0.56
Convertible debt securities [Member]
Net income per share attributable to Chesapeake:
Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive:	146	146	146	146
Participating securities [Member]
Net income per share attributable to Chesapeake:
Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive:	2	0	1	1
Preferred stock [Member]
Net income per share attributable to Chesapeake:
Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive:	60	60	60	60

Debt - Long-Term Debt Table (De

Debt - Long-Term Debt Table (Details) - USD ($)	Oct. 29, 2018	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 9,862,000,000	$ 9,981,000,000
Long-term Debt, Gross		9,812,000,000	9,973,000,000
Debt issuance costs		(54,000,000)	(63,000,000)
Debt, current		(433,000,000)	(53,000,000)
Current maturities of long-term debt, net		(432,000,000)	(52,000,000)
Long-term debt, fair value		9,429,000,000	9,928,000,000
Long-term debt, net		9,380,000,000	9,921,000,000
Interest rate contract [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		0	0
Interest rate derivatives		$ 1,000,000	2,000,000
Senior notes [Member]
Long-Term Debt Instrument [Line Items]
Debt redemption, percent of principal amount of notes to be redeemed		100.00%
Senior notes [Member] | 7.25% Senior Notes Due 2018 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 44,000,000	44,000,000
Long-term Debt, Gross		$ 44,000,000	44,000,000
Interest rate, stated percentage		7.25%
Senior notes [Member] | Floating Rate Senior Notes Due 2019 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 380,000,000	380,000,000
Long-term Debt, Gross		380,000,000	380,000,000
Senior notes [Member] | 6.625% Senior Notes Due 2020 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		437,000,000	437,000,000
Long-term Debt, Gross		$ 437,000,000	437,000,000
Interest rate, stated percentage		6.625%
Senior notes [Member] | 6.875% Senior Notes Due 2020 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 227,000,000	227,000,000
Long-term Debt, Gross		$ 227,000,000	227,000,000
Interest rate, stated percentage		6.875%
Senior notes [Member] | 6.125% Senior Notes Due 2021 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 548,000,000	548,000,000
Long-term Debt, Gross		$ 548,000,000	548,000,000
Interest rate, stated percentage		6.125%
Senior notes [Member] | 5.375% Senior Notes Due 2021 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 267,000,000	267,000,000
Long-term Debt, Gross		$ 267,000,000	267,000,000
Interest rate, stated percentage		5.375%
Senior notes [Member] | 4.875% Senior Notes Due 2022 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 451,000,000	451,000,000
Long-term Debt, Gross		$ 451,000,000	451,000,000
Interest rate, stated percentage		4.875%
Senior notes [Member] | 8.00% Senior Secured Second Lien Notes Due 2022 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,416,000,000	1,416,000,000
Long-term Debt, Gross		$ 1,823,000,000	1,895,000,000
Interest rate, stated percentage		8.00%		8.00%
Senior notes [Member] | 5.75% Senior Notes Due 2023 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 338,000,000	338,000,000
Long-term Debt, Gross		$ 338,000,000	338,000,000
Interest rate, stated percentage		5.75%
Senior notes [Member] | 7.00% senior notes due 2024 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 850,000,000	0
Long-term Debt, Gross		$ 850,000,000	0
Interest rate, stated percentage		7.00%
Senior notes [Member] | 8.00% Senior Notes Due 2025 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,300,000,000	1,300,000,000
Long-term Debt, Gross		$ 1,290,000,000	1,290,000,000
Interest rate, stated percentage		8.00%
Senior notes [Member] | 8.00% Senior Notes Due 2027 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,300,000,000	1,300,000,000
Long-term Debt, Gross		$ 1,298,000,000	1,298,000,000
Interest rate, stated percentage		8.00%
Convertible debt [Member] | 5.5% Convertible Senior Notes Due 2026 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,250,000,000	1,250,000,000
Long-term Debt, Gross		$ 859,000,000	837,000,000
Interest rate, stated percentage		5.50%
Interest rate, effective percentage		11.50%
Convertible debt [Member] | 7.5% senior notes due 2026 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 400,000,000	0
Long-term Debt, Gross		$ 400,000,000	0
Interest rate, stated percentage		7.50%
Convertible debt [Member] | 2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 9,000,000	9,000,000
Long-term Debt, Gross		$ 8,000,000	8,000,000
Interest rate, stated percentage		2.25%
Interest rate, effective percentage		8.00%
Term loan [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 0	1,233,000,000
Long-term Debt, Gross		0	1,233,000,000
Debt issuance costs		(13,000,000)
Line of Credit [Member] | Revolving credit facility [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		645,000,000	781,000,000
Revolving credit facility		$ 645,000,000	$ 781,000,000
Subsequent Event [Member] | Senior notes [Member] | 8.00% Senior Secured Second Lien Notes Due 2022 [Member]
Long-Term Debt Instrument [Line Items]
Debt redemption, percent of principal amount of notes to be redeemed	100.00%

Debt - Narrative (Details)

Debt - Narrative (Details)	Oct. 29, 2018USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Sep. 30, 2019	Jun. 30, 2018	Dec. 31, 2017USD ($)
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 9,862,000,000		$ 9,862,000,000							$ 9,981,000,000
Cash paid to purchase debt				1,285,000,000	$ 1,751,000,000
Gains (losses) on restructuring of debt		68,000,000	$ 1,000,000	68,000,000	(183,000,000)
Deferred charges write-off		54,000,000		$ 54,000,000							63,000,000
Senior notes [Member]
Long-Term Debt Instrument [Line Items]
Net proceeds from public offering of debt		1,230,000,000
Debt redemption, percent of principal amount of notes to be redeemed				100.00%
Debt redemption, percent of aggregate amount of notes to be redeemed				35.00%
Term loan [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		0		$ 0							1,233,000,000
Debt instrument, repurchased face amount		1,233,000,000		1,233,000,000
Cash paid to purchase debt				1,285,000,000
Call premium		52,000,000		52,000,000
Gains (losses) on restructuring of debt				65,000,000
Deferred charges write-off		13,000,000		13,000,000
Senior Notes, Sr. Secured Notes, Contingent Convertible Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, repurchased face amount			$ 1,609,000,000		1,609,000,000
Cash paid to purchase debt					$ 1,751,000,000
Revolving credit facility [Member]
Long-Term Debt Instrument [Line Items]
Gains (losses) on restructuring of debt				(3,000,000)
Line of credit facility, current borrowing capacity		3,000,000,000		3,000,000,000
Line of credit facility, maximum borrowing capacity		4,000,000,000		4,000,000,000
Letters of credit outstanding, amount		$ 182,000,000		$ 182,000,000
Leverage ratio		4		4						5.50
Secured leverage ratio		2.50		2.50
Fixed charge coverage ratio		2		2
Revolving credit facility [Member] | Line of Credit [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 645,000,000		$ 645,000,000							781,000,000
7.00% senior notes due 2024 [Member] | Senior notes [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 850,000,000		$ 850,000,000							0
Interest rate, stated percentage		7.00%		7.00%
7.5% senior notes due 2026 [Member] | Convertible debt [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 400,000,000		$ 400,000,000							0
Interest rate, stated percentage		7.50%		7.50%
8.00% Senior Secured Second Lien Notes Due 2022 [Member] | Senior notes [Member]
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,416,000,000		$ 1,416,000,000							$ 1,416,000,000
Interest rate, stated percentage		8.00%	8.00%	8.00%	8.00%
Debt instrument, repurchased face amount			$ 260,000,000		$ 260,000,000
Minimum [Member] | Alternative Base Rate (ABR) [Member] | Revolving credit facility [Member]
Long-Term Debt Instrument [Line Items]
Variable rate percentage				0.50%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Revolving credit facility [Member]
Long-Term Debt Instrument [Line Items]
Variable rate percentage				1.50%
Maximum [Member] | Alternative Base Rate (ABR) [Member] | Revolving credit facility [Member]
Long-Term Debt Instrument [Line Items]
Variable rate percentage				2.00%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Revolving credit facility [Member]
Long-Term Debt Instrument [Line Items]
Variable rate percentage				3.00%
Forecast [Member] | Revolving credit facility [Member]
Long-Term Debt Instrument [Line Items]
Leverage ratio						4			5.50
Fixed charge coverage ratio							2.50	2.25
Subsequent Event [Member] | 8.00% Senior Secured Second Lien Notes Due 2022 [Member] | Senior notes [Member]
Long-Term Debt Instrument [Line Items]
Debt redemption, percent of principal amount of notes to be redeemed	100.00%
Debt redemption, percent of aggregate amount of notes to be redeemed	100.00%
Debt instrument, repurchased face amount	$ 1,416,000,000

Debt - Fair Value of Debt Table

Debt - Fair Value of Debt Table (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 9,429	$ 9,928
Fair Value, Inputs, Level 1 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term debt, fair value	432	52
Long-term debt, fair value	3,495	2,633
Fair Value, Inputs, Level 1 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term debt, fair value	433	53
Long-term debt, fair value	3,546	2,629
Fair Value, Inputs, Level 2 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	5,884	7,286
Fair Value, Inputs, Level 2 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 6,010	$ 7,301

Contingencies and Commitments -

Contingencies and Commitments - Narrative (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Chaparral Energy, Inc. [Member] | Healthcare of Ontario Pension Plan (HOOPP) [Member] | Pending litigation [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value	$ 215

Contingencies and Commitments_2

Contingencies and Commitments - Gathering Processing and Transportation Commitments Table (Details) - Gathering, processing and transportation agreement [Member] $ in Millions	Sep. 30, 2018USD ($)
Other Commitments [Line Items]
Gathering, processing and transportation commitment, 2018	$ 269
Gathering, processing and transportation commitment, 2019	1,048
Gathering, processing and transportation commitment, 2020	992
Gathering, processing and transportation commitment, 2021	900
Gathering, processing and transportation commitment, 2022	792
Gathering, processing and transportation commitment, 2023-2035	4,443
Gathering, processing and transportation commitment, total	$ 8,444

Other Liabilities - Current Tab

Other Liabilities - Current Table (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Other Liabilities Disclosure [Abstract]
Revenues and royalties due others	$ 535	$ 612
Accrued drilling and production costs	313	216
Joint interest prepayments received	81	74
Accrued compensation and benefits	192	214
Other accrued taxes	123	43
Other	194	296
Current liabilities	$ 1,438	$ 1,455

Other Liabilities - Long-Term T

Other Liabilities - Long-Term Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Other Long-Term Liabilities [Line Items]
Conveyance obligation	$ 0		$ 0		$ 156
Unrecognized tax benefits	53		53		101
Other	107		107		97
Total other long-term liabilities	160		160		354
Other income	1	$ 4	63	$ 6
Capitalized costs, proved properties	70,620		70,620		$ 68,858
ORRI [Member]
Other Long-Term Liabilities [Line Items]
Conveyance obligation	183		183
Consideration			199
Conveyance obligation, noncurrent	30		30
Conveyance obligation, current	153		153
Other income			61
Oil and Gas Properties [Member] | ORRI [Member]
Other Long-Term Liabilities [Line Items]
Capitalized costs, proved properties	$ 77		77
Liability [Member] | ORRI [Member]
Other Long-Term Liabilities [Line Items]
Extinguishment of liabilities			$ 122

Income Taxes Income Taxes - Nar

Income Taxes Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Contingency [Line Items]
Tax credit carryforward	$ 3		$ 3
Unrecognized tax benefit, decrease from state income tax expense			2
Unrecognized tax benefits, interest expense			4
Income tax expense (benefit)	$ 1	$ 0	(8)	$ 2
State and Local Jurisdiction [Member]
Income Tax Contingency [Line Items]
Unrecognized tax benefits, decrease resulting from settlements with taxing authorities			$ 13

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock Table (Details) - Restricted stock [Member] shares in Thousands	9 Months Ended
	Sep. 30, 2018$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested restricted stock, beginning balance | shares	13,178
Granted (in shares) | shares	5,776
Vested (in shares) | shares	(5,782)
Forfeited (in shares) | shares	(1,376)
Unvested restricted stock, beginning balance | shares	11,796
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted average grant date fair value, unvested restricted stock, beginning balance (in dollars per share) | $ / shares	$ 6.37
Weighted average grant date fair value, granted (in dollars per share) | $ / shares	3.77
Weighted average grant date fair value, vested (in dollars per share) | $ / shares	7.67
Weighted average grant date fair value, forfeited (in dollars per share) | $ / shares	6.09
Weighted average grant date fair value, unvested restricted stock, ending balance (in dollars per share) | $ / shares	$ 4.49

Share-Based Compensation - Equi

Share-Based Compensation - Equity-Classified Valuation Table (Details) - Stock option [Member]	9 Months Ended
	Sep. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected option life – years	6 years
Volatility	63.55%
Risk-free interest rate	2.72%
Dividend yield	0.00%

Share-Based Compensation - Stoc

Share-Based Compensation - Stock Option Activity Table (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, beginning balance	16,285
Granted (in shares options)	3,611
Exercised (in shares options)	0
Expired (in shares options)	(602)
Forfeited (in shares options)	(1,067)
Outstanding, ending balance	18,227	16,285
Exercisable (in shares options)	8,250
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted average exercise price, beginning (in dollars per share)	$ 8.25
Weighted average exercise price, granted (in dollars per share)	3.01
Weighted average exercise price, exercised (in dollars per share)	0
Weighted average exercise price, expired (in dollars per share)	13.83
Weighted average exercise price, forfeited (in dollars per share)	5.45
Weighted average exercise price, ending (in dollars per share)	7.19	$ 8.25
Weighted average exercise price, exercisable (in dollars per share)	$ 10.73
Weighted average contract life, outstanding (in years)	7 years 5 months 9 days	7 years 8 months 23 days
Weighted average contract life, exercisable (in years)	6 years 18 days
Aggregate intrinsic value, outstanding, beginning balance	$ 1
Aggregate intrinsic value, exercised	0
Aggregate intrinsic value, outstanding, ending balance	8	$ 1
Aggregate intrinsic value, exercisable	$ 2

Share-Based Compensation - Eq_2

Share-Based Compensation - Equity-Classified Compensation Table (Details) - Restricted stock and stock options [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 8	$ 14	$ 30	$ 34
General and administrative expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	6	9	21	20
Oil and natural gas properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	1	3	5	7
Oil, natural gas and NGL production expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1	$ 2	$ 4	$ 7

Share-Based Compensation - Liab

Share-Based Compensation - Liability Classified Valuation Table (Details) - Performance Share Units [Member]	9 Months Ended
	Sep. 30, 2018
Grant Date Assumptions [Member] | 2017 Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	80.65%
Risk-free interest rate	1.54%
Dividend yield	0.00%
Grant Date Assumptions [Member] | 2016 Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	49.74%
Risk-free interest rate	1.13%
Dividend yield	0.00%
Reporting Period Assumptions [Member] | 2017 Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	51.65%
Risk-free interest rate	2.65%
Dividend yield	0.00%
Reporting Period Assumptions [Member] | 2016 Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	41.46%
Risk-free interest rate	2.19%
Dividend yield	0.00%

Share-Based Compensation - Perf

Share-Based Compensation - Performance Share Unit Breakout (Details) - USD ($) $ in Millions	Sep. 30, 2018	Jan. 01, 2018
Performance Share Units [Member] | Award Year 2018, Payable 2019, 2020 and 2021 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units	3,992,358
Fair Value	$ 18	$ 12
Vested Liability	$ 0
Performance Share Units [Member] | Award Year 2017, Payable 2020 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units	1,217,774
Fair Value	$ 6	8
Vested Liability	$ 4
Performance Share Units [Member] | Award Year 2016, Payable 2019 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units	2,348,893
Fair Value	$ 11	10
Vested Liability	$ 10
Cash Restricted Stock Units [Member] | Award Year 2018, Payable 2019, 2020 and 2021 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units	16,034,295
Fair Value	$ 72	$ 48
Vested Liability	$ 0

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of restricted stock, vested	$ 20
Unrecognized compensation expense	$ 38
Share-based compensation expense, weighted average period for recognition	2 years 1 month 13 days
Stock option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense, weighted average period for recognition	1 year 8 months 27 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	Black-Scholes option pricing model
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options	$ 16
Stock option [Member] | Management [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, percentage	33.30%
Share-based compensation, award vesting period	3 years
Stock option [Member] | Management [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	7 years
Stock option [Member] | Management [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, award vesting period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	Monte Carlo simulation
Performance Share Units [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Units Maximum Payout Percentage	0.00%
Performance Share Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Units Maximum Payout Percentage	200.00%
Performance Share Units [Member] | Management [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, award vesting period	3 years
Performance Share Units Maximum Payout Percentage	200.00%
Performance Share Grant Maximum Payout Percentage	100.00%
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	less than zero
Performance Share Units [Member] | Management [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR Component Percentage Performance Share Units	0.00%
Operational Component Percentage Performance Share Units	0.00%
Performance Share Units [Member] | Management [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR Component Percentage Performance Share Units	100.00%
Operational Component Percentage Performance Share Units	100.00%

Derivative and Hedging Activi_3

Derivative and Hedging Activities - Derivative Instruments Table (Details) gal in Millions, MMBbls in Millions, $ in Millions, MMBTU in Trillions	9 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)MMBTUgalMMBbls	Dec. 31, 2017USD ($)MMBTUgalMMBbls
Derivative [Line Items]
Derivative assets (liabilities), at fair value, net	$ (338)	$ (35)
Energy related derivative [Member]
Derivative [Line Items]
Derivative assets (liabilities), at fair value, net	$ (338)	$ (35)
Energy related derivative [Member] | Oil [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume | MMBbls	29	36
Derivative assets (liabilities), at fair value, net	$ (300)	$ (183)
Energy related derivative [Member] | Oil [Member] | Fixed-Price Swap [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume | MMBbls	21	21
Derivative assets (liabilities), at fair value, net	$ (294)	$ (151)
Energy related derivative [Member] | Oil [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume | MMBbls	0	2
Derivative assets (liabilities), at fair value, net	$ (8)	$ (10)
Energy related derivative [Member] | Oil [Member] | Call Swaption [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume | MMBbls	0	2
Derivative assets (liabilities), at fair value, net	$ 0	$ (13)
Energy related derivative [Member] | Oil [Member] | Basis Protection Swap [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume | MMBbls	8	11
Derivative assets (liabilities), at fair value, net	$ 2	$ (9)
Energy related derivative [Member] | Natural gas [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	658	754
Derivative assets (liabilities), at fair value, net	$ (23)	$ 150
Energy related derivative [Member] | Natural gas [Member] | Fixed-Price Swap [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	400	532
Derivative assets (liabilities), at fair value, net	$ (19)	$ 149
Energy related derivative [Member] | Natural gas [Member] | Fixed-Price Swap [Member] | Disposal group, disposed of by sale, not discontinued operations [Member] | Utica Shale [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	170
Energy related derivative [Member] | Natural gas [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	88	0
Derivative assets (liabilities), at fair value, net	$ 3	$ 0
Energy related derivative [Member] | Natural gas [Member] | Collar [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	66	47
Derivative assets (liabilities), at fair value, net	$ 0	$ 11
Energy related derivative [Member] | Natural gas [Member] | Call Option [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	60	110
Derivative assets (liabilities), at fair value, net	$ 0	$ (3)
Energy related derivative [Member] | Natural gas [Member] | Basis Protection Swap [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	44	65
Derivative assets (liabilities), at fair value, net	$ (7)	$ (7)
Energy related derivative [Member] | NGL [Member] | Fixed-Price Swap [Member]
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume | gal	57	33
Derivative assets (liabilities), at fair value, net	$ (15)	$ (2)

Derivative and Hedging Activi_4

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative, fair value, net	$ (338)	$ (35)
Not designated as hedging instrument [Member] | Commodity contract [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(338)	(35)
Derivative liability, fair value, gross asset	0	0
Derivative, fair value, net	(338)	(35)
Other current assets [Member] | Not designated as hedging instrument [Member] | Commodity contract [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	14	157
Derivative asset, fair value, gross liability	(14)	(130)
Derivative, fair value, net	0	27
Other noncurrent assets [Member] | Not designated as hedging instrument [Member] | Commodity contract [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	3
Derivative asset, fair value, gross liability	(3)
Derivative, fair value, net	0
Other current liabilities [Member] | Not designated as hedging instrument [Member] | Commodity contract [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(324)	(188)
Derivative liability, fair value, gross asset	14	130
Derivative, fair value, net	(310)	(58)
Other noncurrent liabilities [Member] | Not designated as hedging instrument [Member] | Commodity contract [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(31)	(4)
Derivative liability, fair value, gross asset	3	0
Derivative, fair value, net	$ (28)	$ (4)

Derivative and Hedging Activi_5

Derivative and Hedging Activities Derivative and Hedging Activities - Oil, Natural Gas and NGL Revenues Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative [Line Items]
Gains (losses) on undesignated oil, natural gas and NGL derivatives	$ (132)		$ (500)
Revenues	2,418	$ 1,943	7,162	$ 6,977
Oil, Natural Gas and NGL Sales [Member]
Derivative [Line Items]
Losses on terminated cash flow hedges	(8)	(8)	(25)	(25)
Oil, Natural Gas and NGL Sales [Member] | Commodity contract [Member] | Not designated as hedging instrument [Member]
Derivative [Line Items]
Gains (losses) on undesignated oil, natural gas and NGL derivatives	(124)	(62)	(475)	477
Oil, natrual gas and NGL [Member]
Derivative [Line Items]
Oil, natural gas and NGL revenues	1,331	1,049	3,924	3,275
Revenues	$ 1,199	$ 979	$ 3,424	$ 3,727

Derivative and Hedging Activi_6

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
AOCI, after tax, beginning of period				$ (57)
Net change in fair value, after tax	[1]	$ 0	$ 0	0	$ 4
Losses reclassified to income, after tax	[1]	8	8	25	25
AOCI, after tax, end of period		(32)		(32)
Cash flow hedging [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
AOCI, before tax, beginning of period		(97)	(132)	(114)	(153)
AOCI, after tax, beginning of period		(40)	(75)	(57)	(96)
Net change in fair value, before tax				0	4
Net change in fair value, after tax				0	4
Losses reclassified to income, before tax		8	8	25	25
Losses reclassified to income, after tax		8	8	25	25
AOCI, before tax, end of period		(89)	(124)	(89)	(124)
AOCI, after tax, end of period		$ (32)	$ (67)	$ (32)	$ (67)
[1]	Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Derivative and Hedging Activi_7

Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative assets (liabilities), at fair value, net	$ (338)	$ (35)
Commodity contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	18	8
Derivative Liability	(356)	(43)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative assets (liabilities), at fair value, net	0	0
Fair Value, Inputs, Level 1 [Member] | Commodity contract [Member]
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 2 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative assets (liabilities), at fair value, net	(333)	(20)
Fair Value, Inputs, Level 2 [Member] | Commodity contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	7	0
Derivative Liability	(340)	(20)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative assets (liabilities), at fair value, net	(5)	(15)
Fair Value, Inputs, Level 3 [Member] | Commodity contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	11	8
Derivative Liability	(16)	(23)
Derivative assets (liabilities), at fair value, net	$ (5)	$ (15)	$ (8)	$ (10)

Derivative and Hedging Activi_8

Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative assets (liabilities), at fair value, net, beginning of period	$ (35)
Derivative assets (liabilities), at fair value, net, end of period	(338)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative assets (liabilities), at fair value, net, beginning of period	(15)
Derivative assets (liabilities), at fair value, net, end of period	(5)
Fair Value, Inputs, Level 3 [Member] | Oil, Natural Gas and NGL Sales [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Gains (loses) included in earnings	(3)	$ 1
Change in unrealized gains (losses) related to assets still held at reporting date	(3)	(7)
Fair Value, Inputs, Level 3 [Member] | Commodity contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative assets (liabilities), at fair value, net, beginning of period	(15)	(10)
Gains (loses) included in earnings	(3)	1
Settlements	13	1
Derivative assets (liabilities), at fair value, net, end of period	$ (5)	$ (8)

Derivative and Hedging Activi_9

Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) - Energy related derivative [Member] $ in Millions	Sep. 30, 2018USD ($)
Oil [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Fair value, measurement with unobservable inputs reconciliations, recurring basis, liability value	$ (8)
Natural gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Fair value, measurement with unobservable inputs reconciliations, recurring basis, asset value	$ 3
Measurement Input, Price Volatility [Member] | Oil [Member] | Weighted average [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.2497
Measurement Input, Price Volatility [Member] | Oil [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.1909
Measurement Input, Price Volatility [Member] | Oil [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.2860
Measurement Input, Price Volatility [Member] | Natural gas [Member] | Weighted average [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.1624
Measurement Input, Price Volatility [Member] | Natural gas [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.1560
Measurement Input, Price Volatility [Member] | Natural gas [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.6208

Derivative and Hedging Activ_10

Derivative and Hedging Activities - Narrative (Details)	Sep. 30, 2018USD ($)counterpartyDerivatives	Dec. 31, 2017USD ($)Derivatives
Derivative [Line Items]
Number of interest rate derivatives held | Derivatives	0	0
Cash collateral balances for derivatives | $	$ 0	$ 0
Expected amount to be transferred of during the next 12 months | $	$ 35,000,000
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, number of instruments held | Derivatives	0	0
Credit Risk [Member]
Derivative [Line Items]
Number of counterparties in hedge facility | counterparty	11

Oil and Natural Gas Property _3

Oil and Natural Gas Property Transactions - VPP Transactions Table (Details) - VPP 9 Mid-Continent [Member] MMBbls in Millions, $ in Millions, Bcfe in Billions, Bcf in Billions	9 Months Ended
	Sep. 30, 2018USD ($)BcfeBcfMMBbls
VPP Transactions [Line Items]
Cash proceeds from Volumetric Production Payment (VPP) | $	$ 853
Proved Developed Reserves (Energy) | Bcfe	177
Oil [Member]
VPP Transactions [Line Items]
Proved developed reserves (volume)	1.7
Natural gas [Member]
VPP Transactions [Line Items]
Proved developed reserves (volume) | Bcf	138
NGL [Member]
VPP Transactions [Line Items]
Proved developed reserves (volume)	4.8

Oil and Natural Gas Property _4

Oil and Natural Gas Property Transactions - VPP Volume Remaining to Be Delivered Table (Details) - VPP 9 Mid-Continent [Member] MMBbls in Millions, Bcf in Millions, Bcfe in Billions	9 Months Ended
	Sep. 30, 2018BcfeBcfMMBbls
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Bcfe	177
Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	29 months
Proved Developed Reserves (Energy) | Bcfe	31.4
Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved developed reserves (volume)	1.7
Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved developed reserves (volume)	0.3
Natural gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved developed reserves (volume) | Bcf	138,000
Natural gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved developed reserves (volume) | Bcf	25.8
NGL [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved developed reserves (volume)	4.8
NGL [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved developed reserves (volume)	0.7

Oil and Natural Gas Property _5

Oil and Natural Gas Property Transactions - Narrative (Details) MMcf in Millions	Oct. 29, 2018USD ($)awellday$ / BTU	Sep. 30, 2018USD ($)well	Sep. 30, 2017USD ($)wellMMcf	Sep. 30, 2018USD ($)awell	Sep. 30, 2017USD ($)awellMMcf
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				$ 395,000,000	$ 1,193,000,000
Mid-Continent [Member]
Business Acquisition [Line Items]
Productive gas wells, number of wells, net | well		3,200		3,200
Proceeds from divestitures of proved and unproved properties				$ 491,000,000
Number of net acres | a				238,500
Other properties [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		$ 8,000,000	$ 248,000,000	$ 31,000,000	$ 331,000,000
Haynesville Shale [Member]
Business Acquisition [Line Items]
Productive gas wells, number of wells, net | well			576		576
Proceeds from divestitures of proved and unproved properties					$ 915,000,000
Number of net acres | a					119,500
Haynesville Shale [Member] | Natural gas [Member]
Business Acquisition [Line Items]
Proved developed reserves (volume) | MMcf			80		80
Subsequent Event [Member] | Utica Shale [Member] | Disposal group, disposed of by sale, not discontinued operations [Member]
Business Acquisition [Line Items]
Area of land, gross (in acres) | a	1,500,000
Area of land, net (in acres) | a	900,000
Productive gas wells, number of wells, net | well	920
Consideration received	$ 1,900,000,000
Subsequent Event [Member] | Utica Shale [Member] | Disposal group, disposed of by sale, not discontinued operations [Member] | Commercial Shale [Member]
Business Acquisition [Line Items]
Area of land, net (in acres) | a	320,000
Subsequent Event [Member] | Future natural gas prices [Member] | Utica Shale [Member] | Disposal group, disposed of by sale, not discontinued operations [Member]
Business Acquisition [Line Items]
Consideration received	$ 100,000,000
Period of trading days | day	20
Consecutive trading days | day	30
Subsequent Event [Member] | 2022 NYMEX Natural Gas [Member] | Future natural gas prices [Member] | Utica Shale [Member] | Disposal group, disposed of by sale, not discontinued operations [Member]
Business Acquisition [Line Items]
Consideration received	$ 50,000,000
Subsequent Event [Member] | 2022 NYMEX Natural Gas [Member] | Future Natural Gas Prices Twenty Twenty Two [Member] | Utica Shale [Member] | Disposal group, disposed of by sale, not discontinued operations [Member]
Business Acquisition [Line Items]
Average Sales Prices | $ / BTU	3
Subsequent Event [Member] | 2022 NYMEX Natural Gas [Member] | Future Natural Gas Prices Twenty Twenty Three [Member] | Utica Shale [Member] | Disposal group, disposed of by sale, not discontinued operations [Member]
Business Acquisition [Line Items]
Average Sales Prices | $ / BTU	3.25

Revenue Recognition - Additiona

Revenue Recognition - Additional Information (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
ASU 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cumulative effect of accounting change	$ 8

Revenue Recognition - Impact of

Revenue Recognition - Impact of Adoption on Balance Sheet and Statement of Operations (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Other long-term liabilities	$ 160	$ 160	$ 354
Accumulated deficit	(16,173)	(16,173)	$ (16,525)
Revenue from contracts with customers	1,331	3,924
Marketing [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	1,219	3,738
Marketing	1,238	3,798
Calculated under revenue guidance in effect before Topic 606 [Member] | Marketing [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	1,508	4,320
Marketing	1,516	4,365
Difference between revenue guidance in effect before and after Topic 606 [Member] | Marketing [Member] | ASU 2014-09 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	(289)	(582)
Marketing	$ (278)	$ (567)

Revenue Recognition - Disaggreg

Revenue Recognition - Disaggregated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 1,331		$ 3,924
Losses on oil, natural gas and NGL derivatives	(132)		(500)
Revenues	2,418	$ 1,943	7,162	$ 6,977
Marcellus [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	184		646
Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	195		605
Eagle Ford [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	493		1,411
Utica [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	266		718
Mid-Continent [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	85		301
Powder River Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	108		243
Oil [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	594		1,698
Losses on oil, natural gas and NGL derivatives	(100)		(388)
Oil [Member] | Marcellus [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Oil [Member] | Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		2
Oil [Member] | Eagle Ford [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	399		1,148
Oil [Member] | Utica [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	59		179
Oil [Member] | Mid-Continent [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	58		196
Oil [Member] | Powder River Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	78		173
Natural gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	578		1,822
Losses on oil, natural gas and NGL derivatives	(18)		(85)
Natural gas [Member] | Marcellus [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	184		646
Natural gas [Member] | Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	195		603
Natural gas [Member] | Eagle Ford [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	36		120
Natural gas [Member] | Utica [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	131		350
Natural gas [Member] | Mid-Continent [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	15		63
Natural gas [Member] | Powder River Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	17		40
NGL [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	159		404
Losses on oil, natural gas and NGL derivatives	(14)		(27)
NGL [Member] | Marcellus [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
NGL [Member] | Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
NGL [Member] | Eagle Ford [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	58		143
NGL [Member] | Utica [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	76		189
NGL [Member] | Mid-Continent [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	12		42
NGL [Member] | Powder River Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	13		30
Oil, natrual gas and NGL [Member]
Disaggregation of Revenue [Line Items]
Revenues	1,199	979	3,424	3,727
Oil, natrual gas and NGL [Member] | Oil [Member]
Disaggregation of Revenue [Line Items]
Revenues	494		1,310
Oil, natrual gas and NGL [Member] | Natural gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	560		1,737
Oil, natrual gas and NGL [Member] | NGL [Member]
Disaggregation of Revenue [Line Items]
Revenues	145		377
Marketing [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,030		3,182
Revenues	1,219	$ 964	3,738	$ 3,250
Marketing [Member] | Oil [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	707		2,125
Revenues	826		2,506
Marketing [Member] | Natural gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	211		733
Revenues	281		908
Marketing [Member] | NGL [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	112		324
Revenues	112		324
Other marketing revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues	189		556
Other marketing revenue [Member] | Oil [Member]
Disaggregation of Revenue [Line Items]
Revenues	119		381
Other marketing revenue [Member] | Natural gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	70		175
Other marketing revenue [Member] | NGL [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 0		$ 0

Revenue Recognition - Accounts

Revenue Recognition - Accounts Receivable (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Allowance for doubtful accounts	$ (16)	$ (30)
Accounts receivable, net	1,051	1,322
Oil, Natural Gas and NGL Sales [Member]
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	829	959
Joint Interest [Member]
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	160	209
Other [Member]
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	$ 78	$ 184

Investments Narrative (Details)

Investments Narrative (Details) - FTS International, Inc. [Member] - USD ($) shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Investment, ownership percentage	20.00%	29.00%
Investment, realized gain (loss)	$ 61
Number of shares sold	4.3
Proceeds from sale of equity method investments	$ 74
Shares held (in shares)	22
IPO [Member]
Schedule of Equity Method Investments [Line Items]
Investment, ownership percentage	24.00%
Investment, realized gain (loss)	$ 78

Impairments (Details)

Impairments (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Property, Plant and Equipment [Abstract]
Impairment loss	$ 51

Other Operating Expenses - Narr

Other Operating Expenses - Narrative (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Natural gas [Member]
Property, Plant and Equipment [Line Items]
Loss on contract termination	$ 126
Oil [Member]
Property, Plant and Equipment [Line Items]
Loss on contract termination	$ 290

Restructuring and Other Termi_3

Restructuring and Other Termination Costs Narrative (Details) - USD ($) $ in Millions	Jan. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs, number of positions eliminated, period percent	13.00%
Restructuring Reserve [Roll Forward]
Restructuring reserve, beginning balance				$ 0
Initial restructuring recognition on January 30, 2018		$ 0	$ 0	38	$ 0
Termination benefits paid				(38)
Restructuring reserve, ending balance		$ 0		0
One-time termination benefits [Member]
Restructuring Reserve [Roll Forward]
Initial restructuring recognition on January 30, 2018	$ 38			$ 38

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Table (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value, net asset (liability), total	$ 0	$ (3)
Other current assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	54	57
Other current liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	(54)	(60)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value, net asset (liability), total	0	(3)
Fair Value, Inputs, Level 1 [Member] | Other current assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	54	57
Fair Value, Inputs, Level 1 [Member] | Other current liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	(54)	(60)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value, net asset (liability), total	0	0
Fair Value, Inputs, Level 2 [Member] | Other current assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	0	0
Fair Value, Inputs, Level 2 [Member] | Other current liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value, net asset (liability), total	0	0
Fair Value, Inputs, Level 3 [Member] | Other current assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	0	0
Fair Value, Inputs, Level 3 [Member] | Other current liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	$ 0	$ 0

Condensed Consolidating Finan_3

Condensed Consolidating Financial Information Narrative (Details)	Sep. 30, 2018
Owned subsidiaries [Member] | Senior notes [Member]
Condensed Financial Statements, Captions [Line Items]
Noncontrolling interest, ownership percentage by parent	100.00%

Condensed Consolidating Finan_4

Condensed Consolidating Financial Information Balance Sheets Table (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 4	$ 5
Other current assets	1,231	1,520
Intercompany receivable, net	0	0
Total Current Assets	1,235	1,525
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	10,021	9,350
Other property and equipment, net	1,109	1,314
Property and equipment held for sale, net	47	16
Total Property and Equipment, Net	11,177	10,680
LONG-TERM ASSETS:
Other long-term assets	247	220
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	12,659	12,425
CURRENT LIABILITIES:
Current liabilities	2,976	2,356
Intercompany payable, net	0	0
Total Current Liabilities	2,976	2,356
LONG-TERM LIABILITIES:
Long-term debt, net	9,380	9,921
Other long-term liabilities	342	520
Total Long-Term Liabilities	9,722	10,441
EQUITY:
Chesapeake stockholders’ equity (deficit)	(162)	(496)
Noncontrolling interests	123	124
Total Equity (Deficit)	(39)	(372)	$ (704)
TOTAL LIABILITIES AND EQUITY	12,659	12,425
Eliminations [Member]
CURRENT ASSETS:
Cash and cash equivalents	(4)	(3)
Other current assets	0	(1)
Intercompany receivable, net	(8,208)	(9,133)
Total Current Assets	(8,212)	(9,137)
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	0	0
Investments in subsidiaries and intercompany advances	(1,272)	(660)
TOTAL ASSETS	(9,484)	(9,797)
CURRENT LIABILITIES:
Current liabilities	(4)	(4)
Intercompany payable, net	(8,208)	(9,133)
Total Current Liabilities	(8,212)	(9,137)
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Other long-term liabilities	0	0
Total Long-Term Liabilities	0	0
EQUITY:
Chesapeake stockholders’ equity (deficit)	(1,272)	(660)
Noncontrolling interests	0	0
Total Equity (Deficit)	(1,272)	(660)
TOTAL LIABILITIES AND EQUITY	(9,484)	(9,797)
Parent Company [Member] | Reportable legal entities [Member]
CURRENT ASSETS:
Cash and cash equivalents	6	5
Other current assets	69	154
Intercompany receivable, net	8,003	8,697
Total Current Assets	8,078	8,856
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	563	435
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	563	435
LONG-TERM ASSETS:
Other long-term assets	29	52
Investments in subsidiaries and intercompany advances	1,193	806
TOTAL ASSETS	9,863	10,149
CURRENT LIABILITIES:
Current liabilities	563	190
Intercompany payable, net	29	433
Total Current Liabilities	592	623
LONG-TERM LIABILITIES:
Long-term debt, net	9,380	9,921
Other long-term liabilities	53	101
Total Long-Term Liabilities	9,433	10,022
EQUITY:
Chesapeake stockholders’ equity (deficit)	(162)	(496)
Noncontrolling interests	0	0
Total Equity (Deficit)	(162)	(496)
TOTAL LIABILITIES AND EQUITY	9,863	10,149
Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
CURRENT ASSETS:
Cash and cash equivalents	1	1
Other current assets	1,160	1,364
Intercompany receivable, net	29	436
Total Current Assets	1,190	1,801
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	9,433	8,888
Other property and equipment, net	1,109	1,314
Property and equipment held for sale, net	47	16
Total Property and Equipment, Net	10,589	10,218
LONG-TERM ASSETS:
Other long-term assets	218	168
Investments in subsidiaries and intercompany advances	79
Investments in subsidiaries and intercompany advances		(146)
TOTAL ASSETS	12,076	12,041
CURRENT LIABILITIES:
Current liabilities	2,415	2,168
Intercompany payable, net	8,179	8,648
Total Current Liabilities	10,594	10,816
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Other long-term liabilities	289	419
Total Long-Term Liabilities	289	419
EQUITY:
Chesapeake stockholders’ equity (deficit)	1,193	806
Noncontrolling interests	0	0
Total Equity (Deficit)	1,193	806
TOTAL LIABILITIES AND EQUITY	12,076	12,041
Non-Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
CURRENT ASSETS:
Cash and cash equivalents	1	2
Other current assets	2	3
Intercompany receivable, net	176	0
Total Current Assets	179	5
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	25	27
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	25	27
LONG-TERM ASSETS:
Other long-term assets	0	0
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	204	32
CURRENT LIABILITIES:
Current liabilities	2	2
Intercompany payable, net	0	52
Total Current Liabilities	2	54
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Other long-term liabilities	0	0
Total Long-Term Liabilities	0	0
EQUITY:
Chesapeake stockholders’ equity (deficit)	79	(146)
Noncontrolling interests	123	124
Total Equity (Deficit)	202	(22)
TOTAL LIABILITIES AND EQUITY	$ 204	$ 32

Condensed Consolidating Finan_5

Condensed Consolidating Financial Information Income Statements Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
REVENUES:
Revenues	$ 2,418	$ 1,943	$ 7,162	$ 6,977
OPERATING EXPENSES:
Oil, natural gas and NGL production	132	151	417	426
Oil, natural gas and NGL gathering, processing and transportation	364	369	1,060	1,081
Production taxes	34	21	91	64
General and administrative	66	54	229	189
Restructuring and other termination costs	0	0	38	0
Provision for legal contingencies, net	8	20	17	35
Oil, natural gas and NGL depreciation, depletion and amortization	274	228	813	627
Depreciation and amortization of other assets	17	20	54	62
Impairments	5	3	51	3
Net (gains) losses on sales of fixed assets	0	(1)	7	0
Other operating (income) expense	0	6	(1)	423
Total Operating Expenses	2,138	1,849	6,574	6,243
INCOME FROM OPERATIONS	280	94	588	734
OTHER INCOME (EXPENSE):
Interest expense	(127)	(114)	(367)	(302)
Gains on investments	0	0	139	0
Losses on purchases or exchanges of debt	(68)	(1)	(68)	183
Other income	1	4	63	6
Equity in net earnings of subsidiary	0	0	0	0
Total Other Expense	(194)	(111)	(233)	(113)
INCOME (LOSS) BEFORE INCOME TAXES	86	(17)	355	621
Income tax expense (benefit)	1	0	(8)	2
NET INCOME (LOSS)	85	(17)	363	619
Net income attributable to noncontrolling interests	(1)	(1)	(3)	(3)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	84	(18)	360	616
Other comprehensive income	8	8	25	29
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	92	(10)	385	645
Eliminations [Member]
REVENUES:
Revenues	0	0	0	0
OPERATING EXPENSES:
Oil, natural gas and NGL production	0	0	0	0
Oil, natural gas and NGL gathering, processing and transportation	0	0	0	0
Production taxes	0	0	0	0
General and administrative	0	0	0	0
Restructuring and other termination costs			0
Provision for legal contingencies, net	0	0	0	0
Oil, natural gas and NGL depreciation, depletion and amortization	0	0	0	0
Depreciation and amortization of other assets	0	0	0	0
Impairments	0	0	0	0
Net (gains) losses on sales of fixed assets		0	0
Other operating (income) expense		0	0	0
Total Operating Expenses	0	0	0	0
INCOME FROM OPERATIONS	0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense	0	0	0	0
Gains on investments			0
Losses on purchases or exchanges of debt	0	0	0	0
Other income	0	0	0	0
Equity in net earnings of subsidiary	(279)	(92)	(787)	(740)
Total Other Expense	(279)	(92)	(787)	(740)
INCOME (LOSS) BEFORE INCOME TAXES	(279)	(92)	(787)	(740)
Income tax expense (benefit)	0	0	0	0
NET INCOME (LOSS)	(279)	(92)	(787)	(740)
Net income attributable to noncontrolling interests	0	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(279)	(92)	(787)	(740)
Other comprehensive income	0	0	0	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(279)	(92)	(787)	(740)
Parent Company [Member] | Reportable legal entities [Member]
REVENUES:
Revenues	0	0	0	0
OPERATING EXPENSES:
Oil, natural gas and NGL production	0	0	0	0
Oil, natural gas and NGL gathering, processing and transportation	0	0	0	0
Production taxes	0	0	0	0
General and administrative	0	0	0	3
Restructuring and other termination costs			0
Provision for legal contingencies, net	0	0	0	0
Oil, natural gas and NGL depreciation, depletion and amortization	0	0	0	0
Depreciation and amortization of other assets	0	0	0	0
Impairments	0	0	0	0
Net (gains) losses on sales of fixed assets		0	0
Other operating (income) expense		0	0	0
Total Operating Expenses	0	0	0	3
INCOME FROM OPERATIONS	0	0	0	(3)
OTHER INCOME (EXPENSE):
Interest expense	(125)	(110)	(365)	(300)
Gains on investments			0
Losses on purchases or exchanges of debt	(68)	(1)	(68)	183
Other income	0	1	0	1
Equity in net earnings of subsidiary	278	92	785	737
Total Other Expense	85	(18)	352	621
INCOME (LOSS) BEFORE INCOME TAXES	85	(18)	352	618
Income tax expense (benefit)	1	0	(8)	2
NET INCOME (LOSS)	84	(18)	360	616
Net income attributable to noncontrolling interests	0	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	84	(18)	360	616
Other comprehensive income	0	0	0	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	84	(18)	360	616
Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
REVENUES:
Revenues	2,413	1,938	7,148	6,960
OPERATING EXPENSES:
Oil, natural gas and NGL production	132	151	417	426
Oil, natural gas and NGL gathering, processing and transportation	362	367	1,055	1,075
Production taxes	33	20	90	63
General and administrative	66	54	228	185
Restructuring and other termination costs			38
Provision for legal contingencies, net	8	20	17	35
Oil, natural gas and NGL depreciation, depletion and amortization	274	227	811	624
Depreciation and amortization of other assets	17	20	54	62
Impairments	5	3	51	3
Net (gains) losses on sales of fixed assets		(1)	7
Other operating (income) expense		6	(1)	423
Total Operating Expenses	2,135	1,845	6,565	6,229
INCOME FROM OPERATIONS	278	93	583	731
OTHER INCOME (EXPENSE):
Interest expense	(2)	(4)	(2)	(2)
Gains on investments			139
Losses on purchases or exchanges of debt	0	0	0	0
Other income	1	3	63	5
Equity in net earnings of subsidiary	1	0	2	3
Total Other Expense	0	(1)	202	6
INCOME (LOSS) BEFORE INCOME TAXES	278	92	785	737
Income tax expense (benefit)	0	0	0	0
NET INCOME (LOSS)	278	92	785	737
Net income attributable to noncontrolling interests	0	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	278	92	785	737
Other comprehensive income	8	8	25	29
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	286	100	810	766
Non-Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
REVENUES:
Revenues	5	5	14	17
OPERATING EXPENSES:
Oil, natural gas and NGL production	0	0	0	0
Oil, natural gas and NGL gathering, processing and transportation	2	2	5	6
Production taxes	1	1	1	1
General and administrative	0	0	1	1
Restructuring and other termination costs			0
Provision for legal contingencies, net	0	0	0	0
Oil, natural gas and NGL depreciation, depletion and amortization	0	1	2	3
Depreciation and amortization of other assets	0	0	0	0
Impairments	0	0	0	0
Net (gains) losses on sales of fixed assets		0	0
Other operating (income) expense		0	0	0
Total Operating Expenses	3	4	9	11
INCOME FROM OPERATIONS	2	1	5	6
OTHER INCOME (EXPENSE):
Interest expense	0	0	0	0
Gains on investments			0
Losses on purchases or exchanges of debt	0	0	0	0
Other income	0	0	0	0
Equity in net earnings of subsidiary	0	0	0	0
Total Other Expense	0	0	0	0
INCOME (LOSS) BEFORE INCOME TAXES	2	1	5	6
Income tax expense (benefit)	0	0	0	0
NET INCOME (LOSS)	2	1	5	6
Net income attributable to noncontrolling interests	(1)	(1)	(3)	(3)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	1	0	2	3
Other comprehensive income	0	0	0	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	1	0	2	3
Oil, natrual gas and NGL [Member]
REVENUES:
Revenues	1,199	979	3,424	3,727
Oil, natrual gas and NGL [Member] | Eliminations [Member]
REVENUES:
Revenues	0	0	0	0
Oil, natrual gas and NGL [Member] | Parent Company [Member] | Reportable legal entities [Member]
REVENUES:
Revenues	0	0	0	0
Oil, natrual gas and NGL [Member] | Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
REVENUES:
Revenues	1,194	974	3,410	3,710
Oil, natrual gas and NGL [Member] | Non-Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
REVENUES:
Revenues	5	5	14	17
Marketing [Member]
REVENUES:
Revenues	1,219	964	3,738	3,250
OPERATING EXPENSES:
Marketing	1,238	978	3,798	3,333
Marketing [Member] | Eliminations [Member]
REVENUES:
Revenues	0	0	0	0
OPERATING EXPENSES:
Marketing	0	0	0	0
Marketing [Member] | Parent Company [Member] | Reportable legal entities [Member]
REVENUES:
Revenues	0	0	0	0
OPERATING EXPENSES:
Marketing	0	0	0	0
Marketing [Member] | Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
REVENUES:
Revenues	1,219	964	3,738	3,250
OPERATING EXPENSES:
Marketing	1,238	978	3,798	3,333
Marketing [Member] | Non-Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
REVENUES:
Revenues	0	0	0	0
OPERATING EXPENSES:
Marketing	$ 0	$ 0	$ 0	$ 0

Condensed Consolidating Finan_6

Condensed Consolidating Financial Information Statements of Cash Flows Tables (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	$ 1,595	$ 273
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(1,481)	(1,597)
Acquisitions of proved and unproved properties	(244)	(226)
Proceeds from divestitures of proved and unproved properties	395	1,193
Additions to other property and equipment	(11)	(12)
Other investing activities	149	40
Net Cash Used In Investing Activities	(1,192)	(602)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	9,095	4,775
Payments on revolving credit facility borrowings	(9,231)	(4,130)
Proceeds from issuance of senior notes, net	1,237	742
Cash paid to purchase debt	(1,285)	(1,751)
Cash paid for preferred stock dividends	(69)	(160)
Other financing activities	(151)	(24)
Intercompany advances, net	0	0
Net Cash Used In Financing Activities	(404)	(548)
Net decrease in cash and cash equivalents	(1)	(877)
Cash and cash equivalents, beginning of period	5	882
Cash and cash equivalents, end of period	4	5
Eliminations [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	(10)	(8)
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0
Acquisitions of proved and unproved properties	0	0
Proceeds from divestitures of proved and unproved properties	0	0
Additions to other property and equipment	0	0
Other investing activities	0	0
Net Cash Used In Investing Activities	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	0	0
Payments on revolving credit facility borrowings	0	0
Proceeds from issuance of senior notes, net	0	0
Cash paid to purchase debt	0	0
Cash paid for preferred stock dividends	0	0
Other financing activities	(13)	27
Intercompany advances, net	22	0
Net Cash Used In Financing Activities	9	27
Net decrease in cash and cash equivalents	(1)	19
Cash and cash equivalents, beginning of period	(3)	(25)
Cash and cash equivalents, end of period	(4)	(6)
Parent Company [Member] | Reportable legal entities [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	86	4
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0
Acquisitions of proved and unproved properties	0	0
Proceeds from divestitures of proved and unproved properties	0	0
Additions to other property and equipment	0	0
Other investing activities	0	0
Net Cash Used In Investing Activities	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	9,095	4,775
Payments on revolving credit facility borrowings	(9,231)	(4,130)
Proceeds from issuance of senior notes, net	1,237	742
Cash paid to purchase debt	(1,285)	(1,751)
Cash paid for preferred stock dividends	(69)	(160)
Other financing activities	(2)	(36)
Intercompany advances, net	170	(339)
Net Cash Used In Financing Activities	(85)	(899)
Net decrease in cash and cash equivalents	1	(895)
Cash and cash equivalents, beginning of period	5	904
Cash and cash equivalents, end of period	6	9
Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	1,512	266
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(1,481)	(1,597)
Acquisitions of proved and unproved properties	(244)	(226)
Proceeds from divestitures of proved and unproved properties	395	1,193
Additions to other property and equipment	(11)	(12)
Other investing activities	149	40
Net Cash Used In Investing Activities	(1,192)	(602)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	0	0
Payments on revolving credit facility borrowings	0	0
Proceeds from issuance of senior notes, net	0	0
Cash paid to purchase debt	0	0
Cash paid for preferred stock dividends	0	0
Other financing activities	(127)	(4)
Intercompany advances, net	(193)	339
Net Cash Used In Financing Activities	(320)	335
Net decrease in cash and cash equivalents	0	(1)
Cash and cash equivalents, beginning of period	1	2
Cash and cash equivalents, end of period	1	1
Non-Guarantor Subsidiaries [Member] | Reportable legal entities [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	7	11
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0
Acquisitions of proved and unproved properties	0	0
Proceeds from divestitures of proved and unproved properties	0	0
Additions to other property and equipment	0	0
Other investing activities	0	0
Net Cash Used In Investing Activities	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	0	0
Payments on revolving credit facility borrowings	0	0
Proceeds from issuance of senior notes, net	0	0
Cash paid to purchase debt	0	0
Cash paid for preferred stock dividends	0	0
Other financing activities	(9)	(11)
Intercompany advances, net	1	0
Net Cash Used In Financing Activities	(8)	(11)
Net decrease in cash and cash equivalents	(1)	0
Cash and cash equivalents, beginning of period	2	1
Cash and cash equivalents, end of period	$ 1	$ 1

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Millions	Oct. 30, 2018USD ($)$ / sharesshares	Oct. 29, 2018USD ($)awell	Sep. 30, 2018	Sep. 30, 2017USD ($)
Senior notes [Member]
Subsequent Event [Line Items]
Debt redemption, percent of principal amount of notes to be redeemed			100.00%
Debt redemption, percent of aggregate amount of notes to be redeemed			35.00%
8.00% Senior Secured Second Lien Notes Due 2022 [Member] | Senior notes [Member]
Subsequent Event [Line Items]
Interest rate, stated percentage			8.00%	8.00%
Debt instrument, repurchased face amount				$ 260
Subsequent Event [Member] | Disposal group, disposed of by sale, not discontinued operations [Member] | Utica Shale [Member]
Subsequent Event [Line Items]
Area of land, gross (in acres) | a		1,500,000
Area of land, net (in acres) | a		900,000
Productive gas wells, number of wells, net | well		920
Consideration received		$ 1,900
Subsequent Event [Member] | Commercial Shale [Member] | Disposal group, disposed of by sale, not discontinued operations [Member] | Utica Shale [Member]
Subsequent Event [Line Items]
Area of land, net (in acres) | a		320,000
Subsequent Event [Member] | Wildhorse Resource Development Corporation [Member]
Subsequent Event [Line Items]
Consideration paid	$ 3,977
Debt assumed	$ 930
Subsequent Event [Member] | Wildhorse Resource Development Corporation [Member] | Acquisition Scenario One [Member]
Subsequent Event [Line Items]
Number of shares issued per share acquired | shares	5.989
Subsequent Event [Member] | Wildhorse Resource Development Corporation [Member] | Acquisition Scenario Two [Member]
Subsequent Event [Line Items]
Number of shares issued per share acquired | shares	5.336
Value issued per share acquired (in USD per share) | $ / shares	$ 3
Subsequent Event [Member] | 8.00% Senior Secured Second Lien Notes Due 2022 [Member] | Senior notes [Member]
Subsequent Event [Line Items]
Debt instrument, repurchased face amount		$ 1,416
Debt redemption, percent of principal amount of notes to be redeemed		100.00%
Debt redemption, percent of aggregate amount of notes to be redeemed		100.00%