View Filing Data

$ 2,196

$ 2,524

^[1]

^[1],[2]

^[1]

103

^[1]

^[1]

^[1]

519

459

^[1],[2]

^[1],[2]

^[1]

2,378

2,482

^[1]

(182)

^[1]

(161)

(162)

^[1]

(1)

139

^[1]

(1)

^[1]

(153)

(24)

^[1]

(335)

^[1]

Income tax benefit

(314)

^[1]

Net income attributable to noncontrolling interests

(21)

^[2],[3]

(1)

^[3]

(21)

^[1]

(23)

^[1]

$ (44)

$ (6)

^[1]

$ (0.03)

$ (0.01)

^[1]

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):

$ (0.03)

$ (0.01)

^[1]

1,380

907

^[1]

1,380

907

^[1]

$ 929

$ 1,243

^[1]

1,233

1,246

^[1]

Oil, natural gas and NGL and Marketing

1,230

1,268

^[1]

2,162

2,489

^[1]

Oil, natural gas and NGL production

^[1]

Oil, natural gas and NGL gathering, processing and transportation

132

147

^[1]

274

356

^[1]

Statement of Comprehensive Income [Abstract]

$ 24

$ 81

^[1]

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[3]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

^[2]

$ (21)

$ 18

^[1]

Reclassification of losses on settled derivative instruments

^[3]

^[3]

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

(11)

(1)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

$ (11)

$ 27

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[3]	Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=114867106&loc=SL7669619-108580

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-Subparagraph (a)(1)
-URI http://asc.fasb.org/extlink&oid=109239629&loc=SL4573702-111684

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1B
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=114867106&loc=SL7669625-108580

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-Subparagraph (c)(1)
-URI http://asc.fasb.org/extlink&oid=109239629&loc=SL4573702-111684

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=115929826&loc=d3e8736-108599

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=84234705&loc=SL4591551-111686

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=109223946&loc=d3e3000-108585

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 45
-Paragraph 19
-URI http://asc.fasb.org/extlink&oid=108774443&loc=SL4569616-111683

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=115929826&loc=d3e8933-108599

Reference 10: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=84234705&loc=SL4591552-111686

+ Details

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

^[1]

ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:

$ (21)

$ 18

^[2]

519

459

^[3]

(314)

304

117

(19)

^[3]

^[3]

(139)

(36)

(93)

456

588

(515)

(420)

(353)

Proceeds from divestitures of proved and unproved properties

(6)

(17)

319

Proceeds from sales of other property and equipment

(9)

(3)

Net Cash Provided By (Used In) Investing Activities

(856)

3,572

2,904

(3,136)

(3,485)

(1)

(23)

(2)

Net Cash Provided By (Used In) Financing Activities

(8)

(4)

404

(610)

Net increase (decrease) in cash and cash equivalents

(1)

Interest paid, net of capitalized interest

SUPPLEMENTAL CASH FLOW INFORMATION:

145

170

Income taxes paid, net of refunds received

(5)

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:

Common stock issued for business combination

2,037

Change in accrued drilling and completion costs

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:

Change in non-cash investing and financing activities

103

Change in divested proved and unproved properties

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:

Change in non-cash investing and financing activities

$ 2

$ 12

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[3]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($)
$ in Millions

Total

PREFERRED STOCK:

COMMON STOCK:

ADDITIONAL PAID-IN CAPITAL:

ACCUMULATED DEFICIT:

ACCUMULATED OTHER COMPREHENSIVE LOSS:

TREASURY STOCK – COMMON:

TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY

NONCONTROLLING INTERESTS:

Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2017

$ 1,671

$ 9

^[1]

$ 14,437

^[1]

$ (14,130)

^[1]

$ (57)

^[1]

$ (31)

^[1]

Increase (Decrease) in Stockholders' Equity [Roll Forward]

^[1]

^[1]

^[1]

(23)

$ 17

^[2]

^[1]

Purchase of 2,539,473 and 1,451,478 shares for company benefit plans

^[1]

^[1]

(4)

Release of 110,796 and 275,407 shares from company benefit plans

^[1]

Chesapeake stockholders’ equity, end of period at Mar. 31, 2018

^[1]

1,671

14,419

(14,121)

(47)

(32)

$ 1,899

Stockholders' equity attributable to noncontrolling interest, beginning of period at Dec. 31, 2017

^[1]

$ 44

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Net income attributable to noncontrolling interests

(1)

^[3]

^[1]

Stockholders' equity attributable to noncontrolling interest, end of period at Mar. 31, 2018

^[1]

(2)

^[1]

Increase (Decrease) in Stockholders' Equity [Roll Forward]

^[1]

1,942

Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2018

2,133

2,092

1,671

14,378

(13,912)

(23)

(31)

Increase (Decrease) in Stockholders' Equity [Roll Forward]

2,030

(23)

(21)

Purchase of 2,539,473 and 1,451,478 shares for company benefit plans

(6)

Release of 110,796 and 275,407 shares from company benefit plans

Chesapeake stockholders’ equity, end of period at Mar. 31, 2019

4,097

$ 1,671

$ 16

$ 16,392

$ (13,933)

$ (13)

$ (36)

$ 4,097

Stockholders' equity attributable to noncontrolling interest, beginning of period at Dec. 31, 2018

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Net income attributable to noncontrolling interests

Stockholders' equity attributable to noncontrolling interest, end of period at Mar. 31, 2019

$ 41

Increase (Decrease) in Stockholders' Equity [Roll Forward]

$ 4,138

[1]	Financial information for prior periods has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[3]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

$ 4,097

PREFERRED STOCK:

1,671

$ 1,671

^[1]

TREASURY STOCK – COMMON:

Purchase of shares for company benefit plans (in shares)

$ (36)

$ (32)

^[1]

2,539,473

1,451,478

Release of shares from company benefit plans (in shares)

110,796

275,407

[1]	Financial information for prior periods has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Basis of Presentation and Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation and Summary of Significant Accounting Policies	Basis of Presentation and Summary of Significant Accounting Policies 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 months ended March 31, 2019 (the “Current Quarter”) and the three months ended March 31, 2018 (the “Prior Quarter”). Our Form 8-K dated May 9, 2019 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. Recast Financial Information for Change in Accounting Principle In the Current Quarter, we voluntarily changed our method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. Although the full cost method of accounting for oil and natural gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the generally preferred method of the SEC and, because it is more widely used in the industry, we expect the change to improve the comparability of our financial statements to our peers. We also believe the successful efforts method provides a more representational depiction of assets and operating results and provides for our investments in oil and natural gas properties to be assessed for impairment in accordance with Accounting Standards Codification (ASC) Topic 360, Property Plant and Equipment, rather than valuations based on prices and costs prescribed under the full cost method as of the balance sheet date. For detailed information regarding the effects of the change to the successful efforts method, see Note 2. Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, exploration costs, such as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead and similar activities are also expensed as incurred. All property acquisition costs and development costs are capitalized when incurred. Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of oil and natural gas, are capitalized. Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (UOP) method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Proceeds from the sales of individual oil and natural gas properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, we compare unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820, Fair Value Measurements. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. We have classified these fair value measurements as Level 3 in the fair value hierarchy. Capitalized Interest Interest from external borrowings is capitalized on significant investments in major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset. Recently Issued Accounting Standards In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASC 842”), which requires lessees to recognize a lease liability and a right-of-use (ROU) asset on the balance sheet for all leases, including operating leases, with terms in excess of 12 months. As the implicit rate of the lease is not always readily determinable, the company uses its incremental borrowing rate to calculate the present value of lease payments based on information available at the commencement date. Operating ROU assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the condensed consolidated balance sheet. Finance ROU assets are reflected in total property and equipment, net while finance lease liabilities are included in other current and other long-term liabilities on the condensed consolidated balance sheet. ASC 842 does not apply to our leases of mineral rights to explore for or use oil and natural gas resources, including the intangible rights to explore for those natural resources and rights to use the land in which those natural resources are contained. We adopted the new standard on January 1, 2019 and as permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, we will not adjust comparative-period financial statements and will continue to apply the guidance in Topic 840, including its disclosure requirements, in the comparative periods presented prior to adoption. No cumulative-effect adjustment to retained earnings was required as a result of the modified retrospective approach. Upon adoption of ASC 842, we made certain elections permitting us to not reassess: (1) whether any expired or existing contracts contained leases (2) the lease classification for any expired or existing leases, and (3) initial direct costs for any existing leases. Upon adoption of ASC 842, we also made an election permitting us to continue applying our current policy for land easements. The adoption of ASC 842 did not result in a material impact on our balance sheet, results of operations or cash flows. Short-term leases will not be recognized on the balance sheet as an asset or a liability, and the related rental expense will be expensed as incurred. We have short-term lease agreements related to most of our drilling rig arrangements and hydraulic fracturing arrangements and some of our compressor rental arrangements. See Note 9 for further information regarding leases.

Change in Accounting Principle

3 Months Ended

Mar. 31, 2019

Accounting Changes and Error Corrections [Abstract]

Change in Accounting Principle

In the Current Quarter, we voluntarily changed our method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geophysical and geological costs, delay rentals, unproved leasehold impairments and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential property impairments by comparing the net carrying value of oil and natural gas properties to associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Under the full cost method of accounting, a write-down would be required if the net carrying value of oil and natural gas properties exceeds a full cost ceiling using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the disposition of oil and natural gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the assets remaining under the full cost method. Our condensed consolidated financial statements have been recast to reflect these differences.



	Three Months Ended March 31, 2019
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions except per share data)
REVENUES AND OTHER:
Oil, natural gas and NGL	$	929		$	—		$	929
Marketing	1,233			—			1,233
Total Revenues	2,162			—			2,162
Other	—			15			15
Gains on sales of assets	—			19			19
Total Revenues and Other	2,162			34			2,196
OPERATING EXPENSES:
Oil, natural gas and NGL production	132			—			132
Oil, natural gas and NGL gathering, processing and transportation	274			—			274
Production taxes	34			—			34
Exploration	—			24			24
Marketing	1,230			—			1,230
General and administrative	88			15			103
Depreciation, depletion and amortization	357			162			519
Impairments	1			—			1
Other operating expense	51			10			61
Total Operating Expenses	2,167			211			2,378
LOSS FROM OPERATIONS	(5		)	(177		)	(182		)
OTHER INCOME (EXPENSE):
Interest expense	(135		)	(26		)	(161		)
Losses on investments	(1		)	—			(1		)
Other income	7			2			9
Total Other Expense	(129		)	(24		)	(153		)
LOSS BEFORE INCOME TAXES	(134		)	(201		)	(335		)
Income tax benefit	(314		)	—			(314		)
NET INCOME (LOSS)	180			(201		)	(21		)
Net income attributable to noncontrolling interests	(1		)	1			—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	179			(200		)	(21		)
Preferred stock dividends	(23		)	—			(23		)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	156		$	(200	)	$	(44	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.11		$	(0.14	)	$	(0.03	)
Diluted	$	0.11		$	(0.14	)	$	(0.03	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	1,380			—			1,380
Diluted	1,380			—			1,380



	Three Months Ended March 31, 2018
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions except per share data)
REVENUES AND OTHER:
Oil, natural gas and NGL	$	1,243		$	—		$	1,243
Marketing	1,246			—			1,246
Total Revenues	2,489			—			2,489
Other	—			16			16
Gains on sales of assets	—			19			19
Total Revenues and Other	2,489			35			2,524
OPERATING EXPENSES:
Oil, natural gas and NGL production	147			—			147
Oil, natural gas and NGL gathering, processing and transportation	356			—			356
Production taxes	31			—			31
Exploration	—			81			81
Marketing	1,268			—			1,268
General and administrative	72			15			87
Restructuring and other termination costs	38			—			38
Provision for legal contingencies, net	5			—			5
Depreciation, depletion and amortization	286			173			459
Impairments	—			10			10
Other operating expense	8			(8		)	—
Total Operating Expenses	2,211			271			2,482
INCOME FROM OPERATIONS	278			(236		)	42
OTHER INCOME (EXPENSE):
Interest expense	(123		)	(39		)	(162		)
Gains on investments	139			—			139
Other expense	—			(1		)	(1		)
Total Other Income (Expense)	16			(40		)	(24		)
INCOME BEFORE INCOME TAXES	294			(276		)	18
Income tax expense (benefit)	—			—			—
NET INCOME	294			(276		)	18
Net income attributable to noncontrolling interests	(1		)	—			(1		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	293			(276		)	17
Preferred stock dividends	(23		)	—			(23		)
Earnings allocated to participating securities	(2		)	2			—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	268		$	(274	)	$	(6	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.30		$	(0.31	)	$	(0.01	)
Diluted	$	0.29		$	(0.30	)	$	(0.01	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	907			—			907
Diluted	1,053			(146		)	907



	Three Months Ended March 31, 2019
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
NET INCOME (LOSS)	$	180		$	(201	)	$	(21	)
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments	—			—			—
Reclassification of losses on settled derivative instruments	10			—			10
Other Comprehensive Income	10			—			10
COMPREHENSIVE INCOME (LOSS)	190			(201		)	(11		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(1		)	1			—
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	189		$	(200	)	$	(11	)



	Three Months Ended March 31, 2018
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
NET INCOME	$	294		$	(276	)	$	18
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments	—			—			—
Reclassification of losses on settled derivative instruments	10			—			10
Other Comprehensive Income	10			—			10
COMPREHENSIVE INCOME	304			(276		)	28
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(1		)	—			(1		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	303		$	(276	)	$	27




	Three Months Ended March 31, 2019
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$	180		$	(201	)	$	(21	)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	357			162			519
Deferred income tax benefit	(314		)	—			(314		)
Derivative losses, net	304			—			304
Cash receipts on derivative settlements, net	14			—			14
Stock-based compensation	6			—			6
Gains on sales of assets	—			(19		)	(19		)
Impairments	1			—			1
Exploration	—			18			18
Losses on investments	1			—			1
Other	31			9			40
Changes in assets and liabilities	(78		)	(15		)	(93		)
Net Cash Provided By Operating Activities	502			(46		)	456
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(533		)	18			(515		)
Business combination, net	(353		)	—			(353		)
Acquisitions of proved and unproved properties	(34		)	28			(6		)
Proceeds from divestitures of proved and unproved properties	26			—			26
Additions to other property and equipment	(9		)	—			(9		)
Proceeds from sales of other property and equipment	1			—			1
Net Cash Used In Investing Activities	(902		)	46			(856		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	3,572			—			3,572
Payments on revolving credit facility borrowings	(3,136		)	—			(3,136		)
Cash paid to purchase debt	(1		)	—			(1		)
Cash paid for preferred stock dividends	(23		)	—			(23		)
Other	(8		)	—			(8		)
Net Cash Provided By Financing Activities	404			—			404
Net increase in cash and cash equivalents	4			—			4
Cash and cash equivalents, beginning of period	4			—			4
Cash and cash equivalents, end of period	$	8		$	—		$	8




	Three Months Ended March 31, 2018
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions )
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	294		$	(276	)	$	18
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	286			173			459
Derivative losses, net	117			—			117
Cash receipts on derivative settlements, net	13			—			13
Stock-based compensation	9			—			9
Gains on sales of assets	—			(19		)	(19		)
Impairments	—			10			10
Exploration	—			68			68
Gains on investments	(139		)	—			(139		)
Other	(28		)	(8		)	(36		)
Changes in assets and liabilities	104			(16		)	88
Net Cash Provided By Operating Activities	656			(68		)	588
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(442		)	22			(420		)
Acquisitions of proved and unproved properties	(63		)	46			(17		)
Proceeds from divestitures of proved and unproved properties	319			—			319
Additions to other property and equipment	(3		)	—			(3		)
Proceeds from sales of other property and equipment	68			—			68
Proceeds from sales of investments	74			—			74
Net Cash Provided by (Used In) Investing Activities	(47		)	68			21
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	2,904			—			2,904
Payments on revolving credit facility borrowings	(3,485		)	—			(3,485		)
Cash paid for preferred stock dividends	(23		)	—			(23		)
Distributions to noncontrolling interest owners	(2		)	—			(2		)
Other	(4		)	—			(4		)
Net Cash Used In Financing Activities	(610		)	—			(610		)
Net decrease in cash and cash equivalents	(1		)	—			(1		)
Cash and cash equivalents, beginning of period	5			—			5
Cash and cash equivalents, end of period	$	4		$	—		$	4



	Three Months Ended March 31, 2019
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	Under Full Cost			Adjustment			Under Successful Efforts
	($ in millions)
PREFERRED STOCK:
Balance, beginning and end of period	$	1,671		$	—		$	1,671
COMMON STOCK:
Balance, beginning of period	9			—			9
Common shares issued for WildHorse Merger	7			—			7
Balance, end of period	16			—			16
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period	14,378			—			14,378
Common shares issued for WildHorse Merger	2,030			—			2,030
Stock-based compensation	7			—			7
Dividends on preferred stock	(23		)	—			(23		)
Balance, end of period	16,392			—			16,392
ACCUMULATED DEFICIT:
Balance, beginning of period	(15,660		)	1,748			(13,912		)
Net income (loss) attributable to Chesapeake	179			(200		)	(21		)
Balance, end of period	(15,481		)	1,548			(13,933		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(23		)	—			(23		)
Hedging activity	10			—			10
Balance, end of period	(13		)	—			(13		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(31		)	—			(31		)
Purchase of 2,539,473 shares for company benefit plans	(6		)	—			(6		)
Release of 110,796 shares from company benefit plans	1			—			1
Balance, end of period	(36		)	—			(36		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY	2,549			1,548			4,097
NONCONTROLLING INTERESTS:
Balance, beginning of period	123			(82		)	41
Net income attributable to noncontrolling interests	(1		)	1			—
Distributions to noncontrolling interest owners	—			—			—
Balance, end of period	122			(81		)	41
TOTAL EQUITY	$	2,671		$	1,467		$	4,138



	Three Months Ended March 31, 2018
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	Under Full Cost			Adjustment			Under Successful Efforts
	($ in millions)
PREFERRED STOCK:
Balance, beginning and end of period	$	1,671		$	—		$	1,671
COMMON STOCK:
Balance, beginning of period	9			—			9
Balance, end of period	9			—			9
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period	14,437			—			14,437
Stock-based compensation	5			—			5
Dividends on preferred stock	(23		)	—			(23		)
Balance, end of period	14,419			—			14,419
ACCUMULATED DEFICIT:
Balance, beginning of period	(16,525		)	2,395			(14,130		)
Net income attributable to Chesapeake	293			(276		)	17
Cumulative effect of accounting change	(8		)	—			(8		)
Balance, end of period	(16,240		)	2,119			(14,121		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(57		)	—			(57		)
Hedging activity	10			—			10
Balance, end of period	(47		)	—			(47		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(31		)	—			(31		)
Purchase of 1,451,478 shares for company benefit plans	(4		)	—			(4		)
Release of 275,407 shares from company benefit plans	3			—			3
Balance, end of period	(32		)	—			(32		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT)	(220		)	2,119			1,899
NONCONTROLLING INTERESTS:
Balance, beginning of period	124			(80		)	44
Net income attributable to noncontrolling interests	1			—			1
Distributions to noncontrolling interest owners	(2		)	—			(2		)
Balance, end of period	123			(80		)	43
TOTAL EQUITY (DEFICIT)	$	(97	)	$	2,039		$	1,942

Oil and Natural Gas Property Transactions

3 Months Ended

Mar. 31, 2019

Business Combinations [Abstract]

Oil and Natural Gas Property Transactions

WildHorse Acquisition

On February 1, 2019, we acquired WildHorse Resource Development Corporation (“WildHorse”), an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas for approximately 717.4 million shares of our common stock and $381 million in cash. We funded the cash portion of the consideration through borrowings under the Chesapeake revolving credit facility. In connection with the closing, we acquired all of WildHorse’s debt. See Note 6 for additional information on the acquired debt.

Purchase Price Allocation

The acquisition of WildHorse and its corresponding merger (the “Merger”) with and into our wholly owned subsidiary, Brazos Valley Longhorn, L.L.C. (“Brazos Valley Longhorn” or “BVL”) has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of WildHorse to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of WildHorse’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.



	Preliminary Purchase Price Allocation
	($ in millions)
Consideration:
Cash	$	381
Fair value of Chesapeake’s common stock issued in the Merger ^(a)	2,037
Total consideration	$	2,418

Fair Value of Liabilities Assumed:
Current liabilities	$	166
Long-term debt	1,379
Deferred tax liabilities	314
Other long-term liabilities	36
Amounts attributable to liabilities assumed	$	1,895

Fair Value of Assets Acquired:
Cash and cash equivalents	$	28
Other current assets	128
Proved oil and natural gas properties	3,264
Unproved properties	756
Other property and equipment	77
Other long-term assets	60
Amounts attributable to assets acquired	$	4,313

Total identifiable net assets	$	2,418

___________________________________________


(a)	Based on 717,376,170 Chesapeake common shares issued at closing at $2.84 per share (closing price as of February 1, 2019).

We included in our condensed consolidated statements of operations revenues of $75 million, direct operating expenses of $164 million and other expenses of $12 million for the period from February 1, 2019 to March 31, 2019.

Pro Forma Financial Information

The following unaudited pro forma financial information for the three months ended March 31, 2019 and 2018, respectively, is based on our historical consolidated financial statements adjusted to reflect as if the WildHorse acquisition had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including adjustments to conform the classification of expenses in WildHorse’s statements of operations to our classification for similar expenses and the estimated tax impact of pro forma adjustments.



	Three Months Ended March 31,
	2019			2018
	($ in millions except per share data)
Revenues	$	2,188		$	2,682
Net loss available to common stockholders	$	(59	)	$	(10	)
Earnings per common share:
Basic	$	(0.04	)	$	(0.01	)
Diluted	$	(0.04	)	$	(0.01	)

This unaudited pro forma information has been derived from historical information. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the periods presented, nor is it necessarily indicative of future results.

Divestitures

In the Current Quarter, we received proceeds of approximately $26 million, subject to customary closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.

In the Prior Quarter, 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 $420 million, subject to certain customary closing adjustments. Included in the sales were approximately 171,000 net acres and interests in approximately 2,150 wells. Also in the Prior Quarter, we received proceeds of approximately $18 million, subject to customary closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.

Capitalized Exploratory Well Costs

3 Months Ended

Mar. 31, 2019

Extractive Industries [Abstract]

Capitalized Exploratory Well Costs

A summary of the changes in our capitalized well costs for the Current Quarter is detailed below. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.



	2019
	($ in millions)
Balance as of January 1	$	36
Additions pending the determination of proved reserves	7
Divestitures and other	—
Reclassifications to proved properties	(16		)
Charges to exploration expense	—
Balance as of March 31	$	27

As of March 31, 2019, approximately $1 million of drilling and completion costs on exploratory wells pending determination of proved reserves have been capitalized for greater than one year.

Earnings Per Share

3 Months Ended

Mar. 31, 2019

Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]

Earnings Per Share

Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights.

Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For all periods presented, our convertible senior notes did not have a dilutive effect and, therefore, were excluded from the calculation of diluted EPS.

Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive:



	Three Months Ended March 31,
	2019	2018
	(in millions)
Common stock equivalent of our preferred stock outstanding	60	60
Common stock equivalent of our convertible senior notes outstanding	146	146

Debt

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Debt

Our long-term debt consisted of the following as of March 31, 2019 and December 31, 2018:



	March 31, 2019						December 31, 2018
	Principal Amount			Carrying Amount			Principal Amount			Carrying Amount
	($ in millions)
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
5.75% senior notes due 2023	338			338			338			338
7.00% senior notes due 2024	850			850			850			850
6.875% senior notes due 2025^(a)	700			704			—			—
8.00% senior notes due 2025	1,300			1,291			1,300			1,291
5.5% convertible senior notes due 2026^(b)(c)	1,250			874			1,250			866
7.5% senior notes due 2026	400			400			400			400
8.00% senior notes due 2027	1,300			1,299			1,300			1,299
2.25% contingent convertible senior notes due 2038	—			—			1			1
Chesapeake revolving credit facility	842			842			419			419
BVL revolving credit facility^(a)	688			688			—			—
Debt issuance costs	—			(50		)	—			(53		)
Interest rate derivatives	—			1			—			1
Total debt, net	9,978			9,547			8,168			7,722
Less current maturities of long-term debt, net^(d)	(380		)	(380		)	(381		)	(381		)
Total long-term debt, net	$	9,598		$	9,167		$	7,787		$	7,341

___________________________________________


(a)	On February 1, 2019, we acquired the debt of WildHorse which consisted of 6.875% Senior Notes due 2025 and a revolving credit facility. We now refer to this debt as our BVL Senior Notes and our BVL revolving credit facility, respectively. See further discussion below.


(b)	We are required to account for the liability and equity components of our convertible debt instrument 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 rate for our 5.5% Convertible Senior Notes due 2026 is 11.5%.


(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 second quarter of 2019.


(d)	As of March 31, 2019 and December 31, 2018, net current maturities of long-term debt includes our Floating Rate Senior Notes due April 2019. Subsequent to March 31, 2019, we repaid these notes in full upon maturity.

Chesapeake Revolving Credit Facility

Our Chesapeake 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. Scheduled borrowing base redeterminations will continue to occur semiannually, and our next borrowing base redetermination is scheduled for the second quarter of 2019. As of March 31, 2019, we had outstanding borrowings of $842 million under the Chesapeake revolving credit facility and had used $61 million of the Chesapeake revolving credit facility for various letters of credit. As of March 31, 2019, we had $2.097 billion of borrowing capacity available under the Chesapeake revolving credit facility.

On February 1, 2019, we entered into a first amendment to our Chesapeake credit agreement. Among other things, the amendment (i) designated our subsidiary, Brazos Valley Longhorn, and its subsidiaries as unrestricted subsidiaries under the Chesapeake revolving credit facility and (ii) expressly permitted our initial investment in WildHorse under the limitations on investments covenant. As a result of BVL and its subsidiaries being designated as unrestricted subsidiaries under the Chesapeake revolving credit facility, transactions between BVL and its subsidiaries, on the one hand, and Chesapeake and its subsidiaries (other than BVL and its subsidiaries), on the other hand, are required to be on an arm’s-length basis, subject to certain exceptions, and Chesapeake is limited in the amount of investments it can make in BVL and its subsidiaries.

Borrowings under the Chesapeake 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 1.00.

The Chesapeake revolving credit facility is subject to various financial and other covenants. The terms of the Chesapeake credit agreement 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. The Chesapeake credit agreement contains financial covenants that require us 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 1.00 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 1.00 until the later of (x) the fiscal quarter ending March 31, 2021 or (y) the first fiscal quarter in which the Company’s leverage ratio does not exceed 4.00 to 1.00 and (iii) a fixed charge coverage ratio of not less than 2.00 to 1.00 through the fiscal quarter ending December 31, 2019; not less than 2.25 to 1.00 through the fiscal quarter ending June 30, 2020; and not less than 2.50 to 1.00 for the fiscal quarter ended September 30, 2020 and thereafter.

As of March 31, 2019, we were in compliance with all applicable financial covenants under the credit agreement and we were able to borrow up to the full availability under the Chesapeake revolving credit facility.

BVL Revolving Credit Facility

In connection with the acquisition of WildHorse, our subsidiary, BVL, became the borrower under the WildHorse revolving credit facility (as amended, the “BVL revolving credit facility”). The BVL revolving credit facility has a maximum credit amount of $2.0 billion, with current aggregate elected commitments and a borrowing base of $1.3 billion. The BVL revolving credit facility matures in December 2021. The borrowing base under the BVL revolving credit facility is subject to redetermination, on at least a semi-annual basis, primarily on the basis of estimated proved reserves. The next scheduled redetermination is in the second quarter of 2019. As of March 31, 2019, we had outstanding borrowings of $688 million and $47 million utilized as a letter of credit. The BVL revolving credit facility is guaranteed by certain of BVL’s subsidiaries (the “BVL Guarantors”) and is required to be secured by substantially all of the assets of BVL and BVL Guarantors, including mortgages on not less than 85% of the proved reserves of their oil and gas properties.

On February 1, 2019, BVL, as successor by merger to WildHorse, entered into a sixth amendment to the BVL credit agreement. Among other things, the amendment (i) amended the merger covenant and the definition of change of control to permit our acquisition of WildHorse and (ii) permits borrowings under the BVL revolving credit facility to be used to redeem or repurchase the BVL senior notes so long as certain conditions are met.

The obligations under the BVL revolving credit facility are the senior secured obligations of BVL and the BVL Guarantors. The obligations under the BVL revolving credit facility are not obligations of Chesapeake or any of its other subsidiaries. The obligations under the BVL revolving credit facility rank equally in right of payment with all other senior secured indebtedness of Brazos Valley Longhorn and the other BVL Guarantors, and are effectively senior to the BVL and the BVL Guarantors’ senior unsecured indebtedness, including their obligations under the BVL Senior Notes, to the extent of the value of the collateral securing the BVL revolving credit facility.

The BVL revolving credit facility is used for the liquidity and expenses of BVL and its subsidiaries and not Chesapeake and its other subsidiaries. Revolving loans under the BVL revolving credit facility bear interest at the alternate base rate, Eurodollar rate or LIBOR market index rate at BVL’s election, plus an applicable margin (ranging from 0.50%-1.50% per annum for alternate base rate loans, 1.50%-2.50% per annum for Eurodollar loans and 1.50%-2.50% per annum for LIBOR market index rate loans), depending on Brazos Valley Longhorn’s total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.500%, depending on BVL’s total commitment usage.

The terms of the BVL credit agreement include covenants limiting, among other things, the ability of BVL and its restricted subsidiaries (as defined in the BVL credit agreement) to incur additional indebtedness, make investments or loans, incur liens, consummate mergers or similar fundamental changes, make restricted payments, including distributions to Chesapeake, and enter into transactions with affiliates, including Chesapeake and its other subsidiaries. The BVL credit agreement also contains financial covenants that require BVL to maintain (i)(x) if there are no loans outstanding thereunder, a ratio of net debt to EBITDAX (as defined in the BVL credit agreement) of not more than 4.00 to 1.00 as of the last day of each fiscal quarter or (y) if there are such loans outstanding, a ratio of total funded debt to EBITDAX of not more than 4.00 to 1.00 as of the last day of each fiscal quarter and (ii) a ratio of current assets (including availability under the BVL revolving credit facility) to current liabilities of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. As of March 31, 2019, we were in compliance with all applicable financial covenants under the BVL credit agreement and we were able to borrow up to the full availability under the BVL revolving credit facility.

BVL Senior Notes

As a result of the completion of the acquisition of WildHorse, BVL assumed the obligations under WildHorse’s $700 million aggregate principal amount of 6.875% Senior Notes due 2025 (the “BVL Senior Notes”) and Brazos Valley Longhorn Finance Corp. (“BVL Finance Corp.”), a wholly owned subsidiary of BVL, became a co-issuer of the BVL Senior Notes.

On February 1, 2019, BVL, as successor by merger to WildHorse, and BVL Finance Corp. entered into a fourth supplemental indenture (the “BVL supplemental indenture”) to the indenture governing the BVL Senior Notes (as supplemented, the “BVL indenture”). Pursuant to the BVL supplemental indenture, (i) BVL assumed the rights and obligations of WildHorse as issuer under the BVL indenture and (ii) BVL Finance Corp. was named as a co-issuer of the BVL senior notes under the BVL indenture.

The BVL Senior Notes are the senior unsecured obligations of BVL, BVL Finance Corp. and the other BVL Guarantors. The BVL Senior Notes are not obligations of Chesapeake or any of its other subsidiaries. The BVL Senior Notes rank equally in right of payment with all other senior unsecured indebtedness of BVL, BVL Finance Corp. and the other BVL Guarantors, and will be effectively subordinated to BVL’s, BVL Finance Corp.’s and the other BVL Guarantors’ senior secured indebtedness, including their obligations under the BVL revolving credit facility, to the extent of the value of the collateral securing such indebtedness.

The BVL indenture contains customary reporting covenants (including furnishing quarterly and annual reports to the holders of the BVL Senior Notes) and restrictive covenants that, among other things, limit the ability of BVL and its subsidiaries to: (i) pay dividends on, purchase or redeem BVL’s equity interests or purchase or redeem subordinated debt, unless such distributions, purchases or redemptions are permitted by certain exceptions, including for amounts based on BVL’s operating results, subject to the satisfaction of certain conditions, and a $25 million basket; (ii) make certain investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create or incur certain secured debt; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of BVL’s assets; (vii) enter into agreements that restrict distributions or other payments from BVL’s restricted subsidiaries to BVL; (viii) engage in transactions with affiliates, including Chesapeake and its other subsidiaries; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important qualifications and limitations. In addition, most of the covenants will be terminated before the BVL Senior Notes mature if at any time no default or event of default exists under the BVL indenture and the BVL Senior Notes receive an investment grade rating from both of two specified ratings agencies. The BVL indenture also contains customary events of default.

The BVL credit agreement and the BVL indenture constrain the ability of BVL and its subsidiaries to make distributions or otherwise provide funds to, or guarantee the obligations of, Chesapeake and its other subsidiaries. The provisions of the BVL credit agreement and the BVL indenture require that all transactions between BVL and its subsidiaries, on the one hand, and Chesapeake and its other subsidiaries, on the other hand, be on an arm's-length basis, subject to certain exceptions.

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:



	March 31, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			($ in millions)
Short-term debt (Level 1)	$	380	$	379	$	381	$	379
Long-term debt (Level 1)	$	4,200	$	4,240	$	3,495	$	3,173
Long-term debt (Level 2)	$	4,967	$	5,232	$	3,846	$	3,644

Contingencies and Commitments

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

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 2018 Form 10-K.

Contingencies

Litigation and Regulatory Proceedings

We are involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. Our total accrued liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different.

Business Operations. We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.

We and other natural gas producers have been named in various lawsuits alleging underpayment of royalties and other shares of the proceeds of production. The suits against us allege, among other things, that we used below-market prices, made improper deductions, utilized improper measurement techniques entered into arrangements with affiliates that resulted in underpayment of amounts owed in connection with the production and sale of natural gas and NGL, or similar theories. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The lawsuits seek compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our payment practices, pre-and post-judgment interest, and attorney’s fees and costs. Royalty plaintiffs have varying provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations. We have resolved a number of these claims through negotiated settlements of past and future royalty obligations and have prevailed in various other lawsuits. We are currently defending numerous lawsuits seeking damages with respect to underpayment of royalties or other shares of the proceeds of production in multiple states where we have operated, including those discussed below.

On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that we violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit includes other UTPCPL claims and antitrust claims, including that a joint exploration agreement to which we are a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as a temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid, and a permanent injunction from further violations of the UTPCPL.

Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the divestiture of substantially all of our midstream business and most of our gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights, intentional interference with contractual relations, and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources. These lawsuits seek in aggregate compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. On December 20, 2017 and August 9, 2018, we reached tentative settlements to resolve substantially all Pennsylvania civil royalty cases for a total of approximately $35 million.

We believe losses are reasonably possible in certain of the pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years.

We 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 insignificant amount. The final fairness hearing was held on April 25, 2019 and the settlement was approved.

On July 24, 2018, Healthcare of Ontario Pension Plan (HOOPP) filed a demand for arbitration with the American Arbitration Association regarding HOOPP’s purchase of our interest in Chaparral Energy, Inc. stock for $215 million on January 5, 2014. HOOPP claims that we engaged in material misrepresentations and fraud, and that we violated the Securities Exchange Act of 1934 (the “Exchange Act”) and Oklahoma Uniform Securities Act. HOOPP seeks either rescission or $215 million in monetary damages, and in either case, interest, attorney’s fees, disgorgement and punitive damages. We intend to vigorously defend these claims.

In January 2019, putative class action lawsuits were filed in U.S. District Courts for the Southern District of New York against WildHorse and other defendants. The lawsuits generally allege various violations of the Exchange Act in connection with the disclosure contained in the joint proxy statement/prospectus filed in connection with the Merger. The lawsuits seek rescission of the Merger or rescissory damages and, in each case, attorney's fees, costs and interest. We intend to vigorously defend these claims.

In February 2019, a putative class action lawsuit was filed in the District Court of Dallas County, Texas against FTS International, Inc. (“FTSI”), certain investment banks, FTSI’s directors including certain of our officers and certain shareholders of FTSI including us. The lawsuit alleges various violations of Sections 11 (with respect to certain of our officers in their capacities as directors of FTSI) and 15 (with respect to such officers and us) of the Securities Act of 1933 in connection with public disclosure made during the initial public offering of FTSI. The suit seeks damages in excess of $1,000,000 and attorneys’ fees and other expenses. We intend to vigorously defend these claims.

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.

We are named as a defendant in numerous lawsuits in Oklahoma alleging that we and other companies have engaged in activities that have caused earthquakes. These lawsuits seek compensation for injury to real and personal property, diminution of property value, economic losses due to business interruption, interference with the use and enjoyment of property, annoyance and inconvenience, personal injury and emotional distress. In addition, they seek the reimbursement of insurance premiums and the award of punitive damages, attorneys’ fees, costs, expenses and interest. We intend to vigorously defend these claims.

Other Matters

Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

Commitments

Gathering, Processing and Transportation Agreements

We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in our estimates of proved reserves.

The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below:



	March 31, 2019
	($ in millions)
2019	$	627
2020	783
2021	687
2022	585
2023	472
2024 – 2035	2,443
Total	$	5,597

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

3 Months Ended

Mar. 31, 2019

Other Liabilities Disclosure [Abstract]

Other Liabilities

Other current liabilities as of March 31, 2019 and December 31, 2018 are detailed below:



	March 31, 2019		December 31, 2018
	($ in millions)
Revenues and royalties due others	$	562	$	687
Accrued drilling and production costs	467		258
Joint interest prepayments received	69		73
VPP deferred revenue^(a)	58		59
Accrued compensation and benefits	114		202
Other accrued taxes	105		108
Other	216		212
Total other current liabilities	$	1,591	$	1,599

Other long-term liabilities as of March 31, 2019 and December 31, 2018 are detailed below:



	March 31, 2019		December 31, 2018
	($ in millions)
VPP deferred revenue^(a)	$	49	$	63
Unrecognized tax benefits	53		53
Other	108		103
Total other long-term liabilities	$	210	$	219

____________________________________________

(a)

At the inception of our volumetric production payment (VPP) agreements, we (i) removed the proved reserves associated with the VPP, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to other revenue over the term of the VPP, (iii) retained responsibility for the production costs and capital costs related to VPP interests and (iv) ceased recognizing production associated with the VPP volumes. The remaining deferred revenue balance will be recognized in other revenues in the consolidated statement of operations through 2021, assuming the related VPP production volumes are delivered as scheduled.

Leases

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Leases

We are a lessee under various agreements for compressors, office space, vehicles and other equipment. As of March 31, 2019, these leases have remaining terms ranging from one month to 7.8 years as of March 31, 2019. Certain of our lease agreements include options to renew the lease, terminate the lease early or purchase the underlying asset at the end of the lease. We determine the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when we are reasonably certain to exercise the option. The company’s vehicles are the only leases with renewal options that we are reasonably certain to exercise. The renewals are reflected in the ROU asset and lease liability balances.

Upon adoption of ASC 842 on January 1, 2019, we recognized a nominal operating lease liability and a nominal related ROU asset related to vehicles we lease.

On February 1, 2019, we acquired WildHorse and, as part of the purchase price allocation, we recognized additional operating lease liabilities of $40 million, a related ROU asset of $38 million, and lease incentives of $2 million related to two office space leases, a long-term hydraulic fracturing agreement and other equipment leases. Regarding our long-term hydraulic fracturing agreements, we made a policy election to treat both lease and non-lease components as a single lease component.

In 2018, we sold our wholly owned subsidiary, Midcon Compression, L.L.C., to a third party and subsequently leased back some natural gas compressors for 38 months. The lease is accounted for as a finance lease liability.

The following table presents our ROU assets and lease liabilities as of March 31, 2019.



	Financing		Operating
	($ in millions)
ROU assets	$	24	$	32

Lease liabilities:
Current lease liabilities	9		19
Long-term lease liabilities	15		15
Total lease liabilities	$	24	$	34

Additional information for the Company’s operating and finance leases is presented below:



	Three Months Ended March 31, 2019
Lease cost:	($ in millions)
Amortization of ROU assets	$	2
Interest on lease liability	1
Finance lease cost	3
Operating lease cost	7
Short-term lease cost	22
Total lease cost^(a)	$	32

Other information:
Operating cash outflows from finance lease	$	1
Operating cash outflows from operating leases	$	2
Investing cash outflows from operating leases	$	27
Financing cash outflows from finance lease	$	2
Weighted-average remaining lease term - finance lease	2.75 years
Weighted-average remaining lease term - operating leases	3.8 years
Weighted-average discount rate - finance lease	7.50		%
Weighted-average discount rate - operating leases	5.09		%

____________________________________________


(a)	Includes $27 million of capitalized lease costs.

Maturity analysis of finance lease liabilities and operating lease liabilities are presented below:



	March 31, 2019
	Financing Lease			Operating Leases
	($ in millions)
2019 remaining	$	7		$	18
2020	10			6
2021	10			2
2022	—			2
2023	—			2
Thereafter	—			7
Total lease payments	27			37
Less imputed interest	(3		)	(3		)
Present value of lease liabilities	24			34
Less current maturities	(9		)	(19		)
Present value of lease liabilities, less current maturities	$	15		$	15

The aggregate undiscounted minimum future lease payments under previous lease accounting standard, ASC 840, are presented below:



	December 31, 2018
	Capital Lease		Operating Leases
	($ in millions)
2019	$	10	$	3
2020	10		1
2021	10		—
Total minimum lease payments	$	30	$	4

Leases

Upon adoption of ASC 842 on January 1, 2019, we recognized a nominal operating lease liability and a nominal related ROU asset related to vehicles we lease.

The following table presents our ROU assets and lease liabilities as of March 31, 2019.



	Financing		Operating
	($ in millions)
ROU assets	$	24	$	32

Lease liabilities:
Current lease liabilities	9		19
Long-term lease liabilities	15		15
Total lease liabilities	$	24	$	34

Additional information for the Company’s operating and finance leases is presented below:



	Three Months Ended March 31, 2019
Lease cost:	($ in millions)
Amortization of ROU assets	$	2
Interest on lease liability	1
Finance lease cost	3
Operating lease cost	7
Short-term lease cost	22
Total lease cost^(a)	$	32

Other information:
Operating cash outflows from finance lease	$	1
Operating cash outflows from operating leases	$	2
Investing cash outflows from operating leases	$	27
Financing cash outflows from finance lease	$	2
Weighted-average remaining lease term - finance lease	2.75 years
Weighted-average remaining lease term - operating leases	3.8 years
Weighted-average discount rate - finance lease	7.50		%
Weighted-average discount rate - operating leases	5.09		%

____________________________________________


(a)	Includes $27 million of capitalized lease costs.

Maturity analysis of finance lease liabilities and operating lease liabilities are presented below:



	March 31, 2019
	Financing Lease			Operating Leases
	($ in millions)
2019 remaining	$	7		$	18
2020	10			6
2021	10			2
2022	—			2
2023	—			2
Thereafter	—			7
Total lease payments	27			37
Less imputed interest	(3		)	(3		)
Present value of lease liabilities	24			34
Less current maturities	(9		)	(19		)
Present value of lease liabilities, less current maturities	$	15		$	15

The aggregate undiscounted minimum future lease payments under previous lease accounting standard, ASC 840, are presented below:



	December 31, 2018
	Capital Lease		Operating Leases
	($ in millions)
2019	$	10	$	3
2020	10		1
2021	10		—
Total minimum lease payments	$	30	$	4

Revenue Recognition

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

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 Prior Quarter 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 in the Prior Quarter did not have a material impact on our consolidated financial statements.

The following table shows revenue disaggregated by operating area and product type, for the Current Quarter and the Prior Quarter:



	Three Months Ended March 31, 2019
	Oil			Natural Gas			NGL		Total
	($ in millions)
Marcellus	$	—		$	302		$	—	$	302
Haynesville	—			201			—		201
Eagle Ford	331			48			46		425
Brazos Valley	121			4			2		127
Powder River Basin	74			25			10		109
Mid-Continent	40			15			11		66
Revenue from contracts with customers	566			595			69		1,230
Losses on oil, natural gas and NGL derivatives	(259		)	(42		)	—		(301		)
Oil, natural gas and NGL revenue	$	307		$	553		$	69	$	929

Marketing revenue from contracts with customers	$	613		$	413		$	117	$	1,143
Other marketing revenue	72			20			—		92
Losses on oil, natural gas and NGL derivatives	—			(2		)	—		(2		)
Marketing revenue	$	685		$	431		$	117	$	1,233

	Three Months Ended March 31, 2018
	Oil			Natural Gas			NGL		Total
	($ in millions)
Marcellus	$	—		$	294		$	—	$	294
Haynesville	—			210			—		210
Eagle Ford	364			42			40		446
Powder River Basin	40			12			8		60
Mid-Continent	73			32			17		122
Utica	60			116			52		228
Revenue from contracts with customers	537			706			117		1,360
Gains (losses) on oil, natural gas and NGL derivatives	(86		)	(32		)	1		(117		)
Oil, natural gas and NGL revenue	$	451		$	674		$	118	$	1,243

Marketing revenue from contracts with customers	686			293			110		1,089
Other marketing revenue	117			40			—		157
Marketing revenue	$	803		$	333		$	110	$	1,246

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 March 31, 2019 and December 31, 2018 are detailed below:



	March 31, 2019			December 31, 2018
	($ in millions)
Oil, natural gas and NGL sales	$	887		$	976
Joint interest	262			211
Other	67			77
Allowance for doubtful accounts	(20		)	(17		)
Total accounts receivable, net	$	1,196		$	1,247

Income Taxes	3 Months Ended
Income Taxes	Mar. 31, 2019
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 is 0.0% as a result of maintaining a full valuation allowance against our net deferred tax asset. Taking into account our projected operating results for the subsequent 2019 quarters, we project remaining in a net deferred tax asset position as of December 31, 2019. Based on all available positive and negative evidence, including projections 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 thirty-six month period ended March 31, 2019. Such evidence limits our ability to consider various forms of subjective positive evidence, such as our projections for future growth and earnings. However, based on our current forecast, we may come out of a thirty-six month cumulative loss position in the foreseeable future. Should we return to a level of sustained profitability, consideration will need to be given to projections of future taxable income to determine whether such projections provide an adequate source of taxable income for the realization of our deferred tax assets. A full valuation allowance was recorded against our net deferred tax asset position as of December 31, 2018 and March 31, 2019. On February 1, 2019, we completed the acquisition of WildHorse. For federal income tax purposes, the transaction qualified as a tax-free merger under Section 368 of the Internal Revenue Code of 1986, as amended, (the “Code”) and, as a result, we acquired carryover tax basis in WildHorse’s assets and liabilities. We recorded a net deferred tax liability of $314 million, as part of the business combination accounting for WildHorse. As a consequence of maintaining a full valuation allowance against our net deferred tax asset position, a partial release of the valuation allowance was recorded as a discrete income tax benefit of $314 million through the condensed consolidated statement of operations for the Current Quarter. The net deferred tax liability acquired includes deferred tax liabilities on plant, property and equipment and prepaid compensation totaling $401 million, partially offset by deferred tax assets totaling $87 million relating to federal net operating loss carryforwards, a disallowed interest carryforward and certain other less significant deferred tax assets. These carryforwards will be subject to an annual limitation under Section 382 of the Code of approximately $61 million. We determined that no separate valuation allowances were required to be established through business combination accounting against any of the individual deferred tax assets acquired. 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 an income tax benefit of $314 million for the Current Quarter. This benefit was a result of the aforementioned discrete item relating to the partial release of the valuation allowance in the amount of $314 million and a nominal amount of state income tax refunds resulting from the filing of amended state income tax returns reporting federal audit adjustments.

Share-Based Compensation

3 Months Ended

Mar. 31, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

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 Quarter 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, 2019	11,858		$	4.43
Granted	4,272		$	2.97
Vested	(3,937	)	$	4.49
Forfeited	(93	)	$	5.54
Unvested restricted stock as of March 31, 2019	12,100		$	3.89

The aggregate intrinsic value of restricted stock that vested during the Current Quarter was approximately $12 million based on the stock price at the time of vesting.

As of March 31, 2019, there was approximately $40 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 2.22 years.

Stock Options. In the Current Quarter and the Prior Quarter, 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 Quarter:



Expected option life – years	6.0
Volatility	65.61	%
Risk-free interest rate	2.47	%
Dividend yield	—	%

The following table provides information related to stock option activity in the Current Quarter:



	Number of Shares Underlying Options		Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value^(a)
	(in thousands)					($ in millions)
Outstanding as of January 1, 2019	18,096		$	7.20	7.15	$	—
Granted	1,000		$	2.97
Exercised	—		$	—		$	—
Expired	(87	)	$	11.23
Forfeited	(79	)	$	5.45
Outstanding as of March 31, 2019	18,930		$	6.97	7.03	$	—
Exercisable as of March 31, 2019	13,355		$	8.23	6.33	$	—

___________________________________________


(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 March 31, 2019, there was $11 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.39 years, net of actual forfeitures.

Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter and the Prior Quarter:



	Three Months Ended March 31,
	2019		2018
	($ in millions)
General and administrative expenses	$	6	$	7
Oil and natural gas properties	1		2
Oil, natural gas and NGL production expenses	1		2
Exploration expenses	—		—
Total restricted stock and stock option compensation	$	8	$	11

Liability-Classified Awards

Performance Share Units. In the Current Quarter and the Prior Quarter, we granted PSUs to senior management that vest ratably over a three-year performance period and are settled in cash. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors. Compensation expense associated with PSU awards is recognized over the service period based on the graded-vesting method. The value of the PSU awards at the end of each reporting period is dependent upon our estimates of the underlying performance measures.

For PSUs granted in 2017, performance metrics include a total shareholder return (TSR) component, which can range from 0% to 100% and an operational performance component based on finding and development costs, which can range from 0% to 100%, resulting in a maximum payout of 200%. The payout percentage for the 2017 PSU awards is capped at 100% if our absolute TSR is less than zero. The PSUs are settled in cash on the third anniversary of the awards. We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value and the reporting date fair value of the 2017 awards.



Grant Date Assumptions
Assumption	2017 Awards
Volatility	80.65	%
Risk-free interest rate	1.54	%
Dividend yield for value of awards	—	%



Reporting Period Assumptions
Assumption	2017 Awards
Volatility	66.62	%
Risk-free interest rate	2.41	%
Dividend yield for value of awards	—	%

As the above assumptions and expected satisfaction of performance metrics change, the PSU liabilities will be adjusted quarterly through the end of the performance period.

For PSUs granted in 2018 and 2019, performance metrics include an operational performance component based on a ratio of cumulative earnings before interest expense, income taxes, and depreciation, depletion and amortization expense (EBITDA) to capital expenditures, for which payout can range from 0% to 200%. 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 2018, we granted CRSUs to employees that vest straight-line over a three-year period and are settled in cash on each of the three annual vesting dates. The ultimate amount earned is based on the closing price of our common stock on each of the vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the CRSUs. The CRSU liability will be adjusted quarterly, based on changes in our stock price, through the end of the vesting period.

The following table presents a summary of our liability-classified awards:



		Grant Date Fair Value		March 31, 2019
	Units	Grant Date Fair Value		Fair Value		Vested Liability
		($ in millions)		($ in millions)
2019 PSU Awards:
Payable 2020, 2021 and 2022	5,359,249	$	16	$	17	$	—
2018 PSU Awards:
Payable 2020 and 2021	2,639,765	$	8	$	8	$	—
2017 PSU Awards:
Payable 2020	1,217,774	$	8	$	4	$	2
2018 CRSU Awards:
Payable 2020 and 2021	9,732,557	$	29	$	30	$	—

We recognized the following compensation costs, net of actual forfeitures, related to our liability-classified awards for the Current Quarter and the Prior Quarter.



	Three Months Ended March 31,
	2019		2018
	($ in millions)
General and administrative expenses	$	9	$	1
Oil and natural gas properties	1		—
Oil, natural gas and NGL production expenses	3		—
Exploration expenses	1		—
Total liability-classified awards compensation	$	14	$	1

Derivative and Hedging Activities

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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 or NGL derivative instruments were designated for hedge accounting as of March 31, 2019 or December 31, 2018.

Oil, Natural Gas and NGL Derivatives

As of March 31, 2019 and December 31, 2018, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:


•	Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and call swaptions.

•

Options: We occasionally sell and buy call and put 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. At the time of settlement, if the market price is lower than the fixed price of the put option, we receive the difference on bought put options and pay the counterparty the difference on sold put options. If the market price settles below the fixed price of the call option or above the fixed price of the put option, no payment is due from either party.


•	Call Swaptions: We sell call swaptions to counterparties in exchange for a premium 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 March 31, 2019 and December 31, 2018 are provided below:



	March 31, 2019				December 31, 2018
	Notional Volume	Fair Value			Notional Volume	Fair Value
		($ in millions)				($ in millions)
Oil (mmbbl):
Fixed-price swaps	21	$	(31	)	12	$	157
Collars	6	24			8	98
Call swaptions	2	(7		)	—	—
Put options	2	(5		)	—	—
Basis protection swaps	6	4			7	5
Total oil	37	(15		)	27	260
Natural gas (bcf):
Fixed-price swaps	594	21			623	26
Three-way collars	66	3			88	1
Collars	28	—			55	(3		)
Call options	39	—			44	—
Call swaptions	106	(18		)	106	(9		)
Basis protection swaps	38	(1		)	50	—
Total natural gas	871	5			966	15
Contingent consideration:
Utica divestiture		7				7
Total estimated fair value		$	(3	)		$	282

We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. See further discussion below under Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss).

Contingent Consideration Arrangements

In 2018, we sold our Utica Shale position to EAP Ohio, LLC (“Encino”). The purchase and sale agreement with Encino provides for additional contingent payments to us of up to $100 million comprised of $50 million in consideration in each case if, on or prior to December 31, 2019, there is a period of twenty (20) trading days out of a period of thirty (30) consecutive trading days where (i) the average of the NYMEX natural gas strip prices for the months comprising the year 2022 equals or exceeds $3.00/mmbtu as calculated pursuant to the purchase agreement, and (ii) the average of the NYMEX natural gas strip price for the months comprising the year 2023 equals or exceeds $3.25/mmbtu as calculated pursuant to the purchase and sale agreement.

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 March 31, 2019 and December 31, 2018 on a gross basis and after same-counterparty netting:



Balance Sheet Classification	Gross Fair Value			Amounts Netted in the Consolidated Balance Sheets			Net Fair Value Presented in the Consolidated Balance Sheet
	($ in millions)
As of March 31, 2019
Commodity Contracts:
Short-term derivative asset	$	69		$	(51	)	$	18
Long-term derivative asset	61			(13		)	48
Short-term derivative liability	(112		)	51			(61		)
Long-term derivative liability	(28		)	13			(15		)
Contingent Consideration:
Short-term derivative asset	7			—			7
Total derivatives	$	(3	)	$	—		$	(3	)

As of December 31, 2018
Commodity Contracts:
Short-term derivative asset	$	306		$	(104	)	$	202
Long-term derivative asset	117			(41		)	76
Short-term derivative liability	(107		)	104			(3		)
Long-term derivative liability	(41		)	41			—
Contingent Consideration:
Short-term derivative asset	7			—			7
Total derivatives	$	282		$	—		$	282

Effect of Derivative Instruments – Condensed Consolidated Statements of Operations

The components of oil, natural gas and NGL revenues for the Current Quarter and the Prior Quarter are presented below:



	Three Months Ended March 31,
	2019			2018
	($ in millions)
Oil, natural gas and NGL revenues	$	1,230		$	1,360
Losses on undesignated oil, natural gas and NGL derivatives	(291		)	(107		)
Losses on terminated cash flow hedges	(10		)	(10		)
Total oil, natural gas and NGL revenues	$	929		$	1,243

The components of marketing revenues for the Current Quarter and the Prior Quarter are presented below:



	Three Months Ended March 31,
	2019			2018
	($ in millions)
Marketing revenues	$	1,235		$	1,246
Losses on undesignated marketing natural gas derivatives	(2		)	—
Total marketing revenues	$	1,233		$	1,246

Gains as result of changes in the fair value of our contingent consideration arrangements are recognized in gains on sales of assets in the condensed consolidated statement of operations.

Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)

A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below:



	Three Months Ended March 31,
	2019						2018
	Before Tax			After Tax			Before Tax			After Tax
	($ in millions)
Balance, beginning of period	$	(80	)	$	(23	)	$	(114	)	(57	)
Losses reclassified to income	10			10			10			10
Balance, end of period	$	(70	)	$	(13	)	(104		)	(47	)

The accumulated other comprehensive loss as of March 31, 2019 represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. Remaining deferred gain or loss amounts will be recognized in earnings in the month for which the original contract months are to occur. As of March 31, 2019, we expect to transfer approximately $34 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 have a high credit rating or are deemed by us to have acceptable credit strength, and are 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 March 31, 2019, our oil, natural gas and NGL derivative instruments were spread among 15 counterparties.

Hedging Arrangements

Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under the Chesapeake revolving credit facility and/or the BVL revolving credit facility. The contracts entered into with these counterparties are secured by the same collateral that secures the revolving credit facilities. 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 March 31, 2019, we posted an insignificant amount 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 March 31, 2019 and December 31, 2018:



	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
			($ in millions)
As of March 31, 2019
Derivative Assets (Liabilities):
Commodity assets	$	—	$	89		$	27		$	116
Commodity liabilities	—		(102		)	(24		)	(126		)
Utica divestiture contingent consideration	—		—			7			7
Total derivatives	$	—	$	(13	)	$	10		$	(3	)

As of December 31, 2018
Derivative Assets (Liabilities):
Commodity assets	$	—	$	319		$	103		$	422
Commodity liabilities	—		(131		)	(16		)	(147		)
Utica divestiture contingent consideration	—		—			7			7
Total derivatives	$	—	$	188		$	94		$	282

A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during the Current Quarter and the Prior Quarter is presented below:



	Commodity Derivatives			Utica Contingent Consideration
	($ in millions)
Balance, as of January 1, 2019	$	87		$	7
Total gains (losses) (realized/unrealized):
Included in earnings^(a)	(88		)	—
Total purchases, issuances, sales and settlements:
Settlements	4			—
Balance, as of March 31, 2019	$	3		$	7

Balance, as of January 1, 2018	$	(15	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings^(a)	(8		)	—
Total purchases, issuances, sales and settlements:
Settlements	(1		)	—
Balance, as of March 31, 2018	$	(24	)	$	—

___________________________________________



(a)		Commodity Derivatives
		Commodity Derivatives
		2019			2018
		($ in millions)
	Total gains (losses) included in earnings for the period	$	(88	)	$	(8	)
	Change in unrealized gains (losses) related to assets still held at reporting date	$	(84	)	$	(10	)

Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

The significant unobservable inputs for Level 3 derivative contracts include market volatility. Changes in market volatility impact the fair value measurement of our derivative contracts, which is based on an estimate derived from option models. For example, an increase or decrease in the forward prices and volatility of oil and natural gas prices decreases or increases the fair value of oil and natural gas derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of March 31, 2019:



Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value March 31, 2019
				($ in millions)
Oil trades	Oil price volatility curves	12.58% – 26.61%	22.44%	$	17
Natural gas trades	Natural gas price volatility curves	19.91% – 54.81%	20.11%	$	(14	)

Other Operating Expenses	3 Months Ended
Other Operating Expenses	Mar. 31, 2019
Other Income and Expenses [Abstract]
Other Operating Expenses	Other Operating Expenses In the Current Quarter, we recorded approximately $23 million of costs related to our acquisition of WildHorse which included financial advisory fees, legal fees and travel and lodging expenses. Additionally, we recorded approximately $38 million of severance expense as a result of the acquisition of WildHorse. A majority of the WildHorse executives and employees were terminated. These executives and employees were entitled to severance benefits in accordance with existing employment agreements.

Investments	3 Months Ended
Investments	Mar. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Investments	Investments In the Current Quarter in connection with the acquisition of WildHorse, we obtained a 50% membership interest in JWH Midstream LLC (JWH). The carrying value of our investment in JWH, which is being accounted for as an equity method investment, was approximately $17 million as of March 31, 2019. In the Prior Quarter, 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 approximately $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 approximately $61 million decreasing our ownership percentage to approximately 20%. We continue to hold approximately 22.0 million shares in the publicly traded company.

Restructuring and Other Termination Costs	3 Months Ended
Restructuring and Other Termination Costs	Mar. 31, 2019
Restructuring and Related Activities [Abstract]
Restructuring and Other Termination Costs	Restructuring and Other Termination Costs 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 Prior Quarter of approximately $38 million for one-time termination benefits.

Fair Value Measurements

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

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 March 31, 2019 and December 31, 2018:



	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value
	($ in millions)
As of March 31, 2019
Financial Assets (Liabilities):
Other current assets	$	43		$	—	$	—	$	43
Other current liabilities	(44		)	—		—		(44		)
Total	$	(1	)	$	—	$	—	$	(1	)

As of December 31, 2018
Financial Assets (Liabilities):
Other current assets	$	50		$	—	$	—	$	50
Other current liabilities	(51		)	—		—		(51		)
Total	$	(1	)	$	—	$	—	$	(1	)

See Note 6 for information regarding fair value measurement of our debt instruments. See Note 13 for information regarding fair value measurement of our derivatives.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Condensed Consolidating Financial Information

3 Months Ended

Mar. 31, 2019

Condensed Financial Information Disclosure [Abstract]

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, convertible senior notes and Chesapeake revolving credit facility listed in Note 6 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries. Our BVL subsidiaries are not guarantors of Chesapeake’s indebtedness and are subject to covenants under the BVL credit agreement and BVL indenture. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are also 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 March 31, 2019 and December 31, 2018 and for the three months ended March 31, 2019 and 2018. 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 MARCH 31, 2019

($ in millions)



	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	3	$	1	$	6	$	(2	)	$	8
Other current assets	53		1,208		96		—			1,357
Intercompany receivable, net	6,350		—		—		(6,350		)	—
Total Current Assets	6,406		1,209		102		(6,352		)	1,365
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on successful efforts accounting, net	—		9,673		4,094		—			13,767
Other property and equipment, net	—		1,077		79		—			1,156
Property and equipment held for sale, net	—		16		—		—			16
Total Property and Equipment, Net	—		10,766		4,173		—			14,939
LONG-TERM ASSETS:
Other long-term assets	347		245		51		(310		)	333
Investments in subsidiaries and intercompany advances	5,692		2,328		—		(8,020		)	—
TOTAL ASSETS	$	12,445	$	14,548	$	4,326	$	(14,682	)	$	16,637

CURRENT LIABILITIES:
Current liabilities	$	521	$	2,203	$	208	$	(2	)	$	2,930
Intercompany payable, net	—		6,350		—		(6,350		)	—
Total Current Liabilities	521		8,553		208		(6,352		)	2,930
LONG-TERM LIABILITIES:
Long-term debt, net	7,775		—		1,392		—			9,167
Other long-term liabilities	52		303		357		(310		)	402
Total Long-Term Liabilities	7,827		303		1,749		(310		)	9,569
EQUITY:
Chesapeake stockholders’ equity	4,097		5,692		2,328		(8,020		)	4,097
Noncontrolling interests	—		—		41		—			41
Total Equity	4,097		5,692		2,369		(8,020		)	4,138
TOTAL LIABILITIES AND EQUITY	$	12,445	$	14,548	$	4,326	$	(14,682	)	$	16,637

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2018

($ in millions)



	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	4	$	1	$	1	$	(2	)	$	4
Other current assets	60		1,532		2		—			1,594
Intercompany receivable, net	6,671		—		—		(6,671		)	—
Total Current Assets	6,735		1,533		3		(6,673		)	1,598
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on successful efforts accounting, net	—		9,664		48		—			9,712
Other property and equipment, net	—		1,091		—		—			1,091
Property and equipment held for sale, net	—		15		—		—			15
Total Property and Equipment, Net	—		10,770		48		—			10,818
LONG-TERM ASSETS:
Other long-term assets	26		293		—		—			319
Investments in subsidiaries and intercompany advances	3,248		9		—		(3,257		)	—
TOTAL ASSETS	$	10,009	$	12,605	$	51	$	(9,930	)	$	12,735

CURRENT LIABILITIES:
Current liabilities	$	523	$	2,365	$	1	$	(2	)	$	2,887
Intercompany payable, net	—		6,671		—		(6,671		)	—
Total Current Liabilities	523		9,036		1		(6,673		)	2,887
LONG-TERM LIABILITIES:
Long-term debt, net	7,341		—		—		—			7,341
Other long-term liabilities	53		321		—		—			374
Total Long-Term Liabilities	7,394		321		—		—			7,715
EQUITY:
Chesapeake stockholders’ equity	2,092		3,248		9		(3,257		)	2,092
Noncontrolling interests	—		—		41		—			41
Total Equity	2,092		3,248		50		(3,257		)	2,133
TOTAL LIABILITIES AND EQUITY	$	10,009	$	12,605	$	51	$	(9,930	)	$	12,735

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2019

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	850		$	79		$	—	$	929
Marketing	—			1,233			—			—		1,233
Total Revenues	—			2,083			79			—		2,162
Other	—			15			—			—		15
Gains on sales of assets	—			19			—			—		19
Total Revenues and Other	—			2,117			79			—		2,196
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			117			15			—		132
Oil, natural gas and NGL gathering, processing and transportation	—			269			5			—		274
Production taxes	—			28			6			—		34
Exploration	—			20			4			—		24
Marketing	—			1,230			—			—		1,230
General and administrative	—			85			18			—		103
Provision for legal contingencies, net	—			—			—			—		—
Depreciation, depletion and amortization	—			435			84			—		519
Impairments	—			1			—			—		1
Other operating income	—			23			38			—		61
Total Operating Expenses	—			2,208			170			—		2,378
INCOME FROM OPERATIONS	—			(91		)	(91		)	—		(182		)
OTHER INCOME (EXPENSE):
Interest expense	(154		)	5			(12		)	—		(161		)
Losses on investments	—			—			(1		)	—		(1		)
Other income	—			9			—			—		9
Equity in net earnings of subsidiary	(177		)	(100		)	—			277		—
Total Other Expense	(331		)	(86		)	(13		)	277		(153		)
LOSS BEFORE INCOME TAXES	(331		)	(177		)	(104		)	277		(335		)
INCOME TAX BENEFIT	(310		)	—			(4		)	—		(314		)
NET LOSS	(21		)	(177		)	(100		)	277		(21		)
Net income attributable to noncontrolling interests	—			—			—			—		—
NET LOSS ATTRIBUTABLE TO CHESAPEAKE	(21		)	(177		)	(100		)	277		(21		)
Other comprehensive income	—			10			—			—		10
COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE	$	(21	)	$	(167	)	$	(100	)	$	277	$	(11	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2018

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	1,238		$	5		$	—		$	1,243
Marketing	—			1,246			—			—			1,246
Total Revenues	—			2,484			5			—			2,489
Other	—			16			—			—			16
Gains on sales of assets	—			19			—			—			19
Total Revenues and Other	—			2,519			5			—			2,524
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			147			—			—			147
Oil, natural gas and NGL gathering, processing and transportation	—			355			1			—			356
Production taxes	—			31			—			—			31
Exploration	—			81			—			—			81
Marketing	—			1,268			—			—			1,268
General and administrative	—			87			—			—			87
Restructuring and other termination costs	—			38			—			—			38
Provision for legal contingencies, net	—			5			—			—			5
Depreciation, depletion and amortization	—			457			2			—			459
Impairments	—			10			—			—			10
Total Operating Expenses	—			2,479			3			—			2,482
INCOME FROM OPERATIONS	—			40			2			—			42
OTHER INCOME (EXPENSE):
Interest expense	(162		)	—			—			—			(162		)
Gains on investments	—			139			—			—			139
Other expense	—			(1		)	—			—			(1		)
Equity in net earnings of subsidiary	179			1			—			(180		)	—
Total Other Income (Expense)	17			139			—			(180		)	(24		)
INCOME BEFORE INCOME TAXES	17			179			2			(180		)	18
INCOME TAX EXPENSE	—			—			—			—			—
NET INCOME	17			179			2			(180		)	18
Net income attributable to noncontrolling interests	—			—			(1		)	—			(1		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	17			179			1			(180		)	17
Other comprehensive income	—			10			—			—			10
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	17		$	189		$	1		$	(180	)	$	27

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2019

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	$	—		$	421		$	36		$	(1	)	$	456

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(406		)	(109		)	—			(515		)
Business combination, net	—			(381		)	28			—			(353		)
Acquisitions of proved and unproved properties	—			(6		)	—			—			(6		)
Proceeds from divestitures of proved and unproved properties	—			26			—			—			26
Additions to other property and equipment	—			(6		)	(3		)	—			(9		)
Other investing activities	—			1			—			—			1
Net Cash Used In Investing Activities	—			(772		)	(84		)	—			(856		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	3,449			—			123			—			3,572
Payments on revolving credit facility borrowings	(3,026		)	—			(110		)	—			(3,136		)
Cash paid to purchase debt	(1		)	—			—			—			(1		)
Cash paid for preferred stock dividends	(23		)	—			—			—			(23		)
Other financing activities	(7		)	(1		)	(1		)	1			(8		)
Intercompany advances, net	(393		)	352			41			—			—
Net Cash Provided By (Used In) Financing Activities	(1		)	351			53			1			404
Net increase (decrease) in cash and cash equivalents	(1		)	—			5			—			4
Cash and cash equivalents, beginning of period	4			1			1			(2		)	4
Cash and cash equivalents, end of period	$	3		$	1		$	6		$	(2	)	$	8

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2018

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	$	78		$	509		$	5		$	(4	)	$	588

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(420		)	—			—			(420		)
Acquisitions of proved and unproved properties	—			(17		)	—			—			(17		)
Proceeds from divestitures of proved and unproved properties	—			319			—			—			319
Additions to other property and equipment	—			(3		)	—			—			(3		)
Other investing activities	—			142			—			—			142
Net Cash Provided by Investing Activities	—			21			—			—			21

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	2,904			—			—			—			2,904
Payments on revolving credit facility borrowings	(3,485		)	—			—			—			(3,485		)
Cash paid for preferred stock dividends	(23		)	—			—			—			(23		)
Other financing activities	25			(2		)	(4		)	(25		)	(6		)
Intercompany advances, net	530			(528		)	(2		)	—			—
Net Cash Used In Financing Activities	(49		)	(530		)	(6		)	(25		)	(610		)
Net increase (decrease) in cash and cash equivalents	29			—			(1		)	(29		)	(1		)
Cash and cash equivalents, beginning of period	5			1			2			(3		)	5
Cash and cash equivalents, end of period	$	34		$	1		$	1		$	(32	)	$	4

Subsequent Events

3 Months Ended

Mar. 31, 2019

Subsequent Events [Abstract]

Subsequent Events

On April 3, 2019, we issued at par approximately $919 million of 8.00% Senior Notes due 2026 (“2026 notes”) pursuant to a private exchange offer for the following outstanding senior unsecured notes:



	Amount of Notes Exchanged
	($ in millions)
6.625% senior notes due 2020	$	229
6.875% senior notes due 2020	134
6.125% senior notes due 2021	381
5.375% senior notes due 2021	140
Total	$	884

We may redeem some or all of the 2026 notes at any time prior to March 15, 2022 at a price equal to 100% of the principal amount of the notes to be redeemed plus a “make-whole” premium. At any time prior to March 15, 2022, we also may redeem up to 35% of the aggregate principal amount of each series of notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a specified redemption price. In addition, we may redeem some or all of the 2026 notes at any time on or after March 15, 2022 at the redemption prices in accordance with the terms of the notes, the indenture and supplemental indenture governing the notes. These senior notes are unsecured obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes are jointly and severally, fully and unconditionally guaranteed by all of our wholly owned subsidiaries that guarantee the Chesapeake revolving credit facility and certain other unsecured senior notes.

On April 15, 2019, we repaid upon maturity $380 million principal amount of our Floating Rate Senior Notes due April 2019 with borrowings from our Chesapeake revolving credit facility.

Basis of Presentation and Summary of Significant Accounting Policies (Policy)	3 Months Ended
	Mar. 31, 2019
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.
Recast Financial Information for Change in Accounting Principle	Recast Financial Information for Change in Accounting Principle In the Current Quarter, we voluntarily changed our method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. Although the full cost method of accounting for oil and natural gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the generally preferred method of the SEC and, because it is more widely used in the industry, we expect the change to improve the comparability of our financial statements to our peers. We also believe the successful efforts method provides a more representational depiction of assets and operating results and provides for our investments in oil and natural gas properties to be assessed for impairment in accordance with Accounting Standards Codification (ASC) Topic 360, Property Plant and Equipment, rather than valuations based on prices and costs prescribed under the full cost method as of the balance sheet date. For detailed information regarding the effects of the change to the successful efforts method, see Note 2.
Oil and Natural Gas Properties	Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, exploration costs, such as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead and similar activities are also expensed as incurred. All property acquisition costs and development costs are capitalized when incurred. Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of oil and natural gas, are capitalized. Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (UOP) method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Proceeds from the sales of individual oil and natural gas properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, we compare unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820, Fair Value Measurements. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. We have classified these fair value measurements as Level 3 in the fair value hierarchy.
Capitalized Interest	Capitalized Interest Interest from external borrowings is capitalized on significant investments in major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASC 842”), which requires lessees to recognize a lease liability and a right-of-use (ROU) asset on the balance sheet for all leases, including operating leases, with terms in excess of 12 months. As the implicit rate of the lease is not always readily determinable, the company uses its incremental borrowing rate to calculate the present value of lease payments based on information available at the commencement date. Operating ROU assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the condensed consolidated balance sheet. Finance ROU assets are reflected in total property and equipment, net while finance lease liabilities are included in other current and other long-term liabilities on the condensed consolidated balance sheet. ASC 842 does not apply to our leases of mineral rights to explore for or use oil and natural gas resources, including the intangible rights to explore for those natural resources and rights to use the land in which those natural resources are contained. We adopted the new standard on January 1, 2019 and as permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, we will not adjust comparative-period financial statements and will continue to apply the guidance in Topic 840, including its disclosure requirements, in the comparative periods presented prior to adoption. No cumulative-effect adjustment to retained earnings was required as a result of the modified retrospective approach. Upon adoption of ASC 842, we made certain elections permitting us to not reassess: (1) whether any expired or existing contracts contained leases (2) the lease classification for any expired or existing leases, and (3) initial direct costs for any existing leases. Upon adoption of ASC 842, we also made an election permitting us to continue applying our current policy for land easements. The adoption of ASC 842 did not result in a material impact on our balance sheet, results of operations or cash flows. Short-term leases will not be recognized on the balance sheet as an asset or a liability, and the related rental expense will be expensed as incurred. We have short-term lease agreements related to most of our drilling rig arrangements and hydraulic fracturing arrangements and some of our compressor rental arrangements. See Note 9 for further information regarding leases.

Change in Accounting Principle (Tables)

3 Months Ended

Mar. 31, 2019

Accounting Changes and Error Corrections [Abstract]

Schedule of changes in accounting principles



	Three Months Ended March 31, 2018
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions except per share data)
REVENUES AND OTHER:
Oil, natural gas and NGL	$	1,243		$	—		$	1,243
Marketing	1,246			—			1,246
Total Revenues	2,489			—			2,489
Other	—			16			16
Gains on sales of assets	—			19			19
Total Revenues and Other	2,489			35			2,524
OPERATING EXPENSES:
Oil, natural gas and NGL production	147			—			147
Oil, natural gas and NGL gathering, processing and transportation	356			—			356
Production taxes	31			—			31
Exploration	—			81			81
Marketing	1,268			—			1,268
General and administrative	72			15			87
Restructuring and other termination costs	38			—			38
Provision for legal contingencies, net	5			—			5
Depreciation, depletion and amortization	286			173			459
Impairments	—			10			10
Other operating expense	8			(8		)	—
Total Operating Expenses	2,211			271			2,482
INCOME FROM OPERATIONS	278			(236		)	42
OTHER INCOME (EXPENSE):
Interest expense	(123		)	(39		)	(162		)
Gains on investments	139			—			139
Other expense	—			(1		)	(1		)
Total Other Income (Expense)	16			(40		)	(24		)
INCOME BEFORE INCOME TAXES	294			(276		)	18
Income tax expense (benefit)	—			—			—
NET INCOME	294			(276		)	18
Net income attributable to noncontrolling interests	(1		)	—			(1		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	293			(276		)	17
Preferred stock dividends	(23		)	—			(23		)
Earnings allocated to participating securities	(2		)	2			—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	268		$	(274	)	$	(6	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.30		$	(0.31	)	$	(0.01	)
Diluted	$	0.29		$	(0.30	)	$	(0.01	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	907			—			907
Diluted	1,053			(146		)	907



	Three Months Ended March 31, 2019
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
NET INCOME (LOSS)	$	180		$	(201	)	$	(21	)
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments	—			—			—
Reclassification of losses on settled derivative instruments	10			—			10
Other Comprehensive Income	10			—			10
COMPREHENSIVE INCOME (LOSS)	190			(201		)	(11		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(1		)	1			—
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	189		$	(200	)	$	(11	)



	Three Months Ended March 31, 2018
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
NET INCOME	$	294		$	(276	)	$	18
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments	—			—			—
Reclassification of losses on settled derivative instruments	10			—			10
Other Comprehensive Income	10			—			10
COMPREHENSIVE INCOME	304			(276		)	28
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(1		)	—			(1		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	303		$	(276	)	$	27




	Three Months Ended March 31, 2019
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$	180		$	(201	)	$	(21	)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	357			162			519
Deferred income tax benefit	(314		)	—			(314		)
Derivative losses, net	304			—			304
Cash receipts on derivative settlements, net	14			—			14
Stock-based compensation	6			—			6
Gains on sales of assets	—			(19		)	(19		)
Impairments	1			—			1
Exploration	—			18			18
Losses on investments	1			—			1
Other	31			9			40
Changes in assets and liabilities	(78		)	(15		)	(93		)
Net Cash Provided By Operating Activities	502			(46		)	456
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(533		)	18			(515		)
Business combination, net	(353		)	—			(353		)
Acquisitions of proved and unproved properties	(34		)	28			(6		)
Proceeds from divestitures of proved and unproved properties	26			—			26
Additions to other property and equipment	(9		)	—			(9		)
Proceeds from sales of other property and equipment	1			—			1
Net Cash Used In Investing Activities	(902		)	46			(856		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	3,572			—			3,572
Payments on revolving credit facility borrowings	(3,136		)	—			(3,136		)
Cash paid to purchase debt	(1		)	—			(1		)
Cash paid for preferred stock dividends	(23		)	—			(23		)
Other	(8		)	—			(8		)
Net Cash Provided By Financing Activities	404			—			404
Net increase in cash and cash equivalents	4			—			4
Cash and cash equivalents, beginning of period	4			—			4
Cash and cash equivalents, end of period	$	8		$	—		$	8




	Three Months Ended March 31, 2018
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions )
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	294		$	(276	)	$	18
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	286			173			459
Derivative losses, net	117			—			117
Cash receipts on derivative settlements, net	13			—			13
Stock-based compensation	9			—			9
Gains on sales of assets	—			(19		)	(19		)
Impairments	—			10			10
Exploration	—			68			68
Gains on investments	(139		)	—			(139		)
Other	(28		)	(8		)	(36		)
Changes in assets and liabilities	104			(16		)	88
Net Cash Provided By Operating Activities	656			(68		)	588
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(442		)	22			(420		)
Acquisitions of proved and unproved properties	(63		)	46			(17		)
Proceeds from divestitures of proved and unproved properties	319			—			319
Additions to other property and equipment	(3		)	—			(3		)
Proceeds from sales of other property and equipment	68			—			68
Proceeds from sales of investments	74			—			74
Net Cash Provided by (Used In) Investing Activities	(47		)	68			21
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	2,904			—			2,904
Payments on revolving credit facility borrowings	(3,485		)	—			(3,485		)
Cash paid for preferred stock dividends	(23		)	—			(23		)
Distributions to noncontrolling interest owners	(2		)	—			(2		)
Other	(4		)	—			(4		)
Net Cash Used In Financing Activities	(610		)	—			(610		)
Net decrease in cash and cash equivalents	(1		)	—			(1		)
Cash and cash equivalents, beginning of period	5			—			5
Cash and cash equivalents, end of period	$	4		$	—		$	4



	Three Months Ended March 31, 2019
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	Under Full Cost			Adjustment			Under Successful Efforts
	($ in millions)
PREFERRED STOCK:
Balance, beginning and end of period	$	1,671		$	—		$	1,671
COMMON STOCK:
Balance, beginning of period	9			—			9
Common shares issued for WildHorse Merger	7			—			7
Balance, end of period	16			—			16
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period	14,378			—			14,378
Common shares issued for WildHorse Merger	2,030			—			2,030
Stock-based compensation	7			—			7
Dividends on preferred stock	(23		)	—			(23		)
Balance, end of period	16,392			—			16,392
ACCUMULATED DEFICIT:
Balance, beginning of period	(15,660		)	1,748			(13,912		)
Net income (loss) attributable to Chesapeake	179			(200		)	(21		)
Balance, end of period	(15,481		)	1,548			(13,933		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(23		)	—			(23		)
Hedging activity	10			—			10
Balance, end of period	(13		)	—			(13		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(31		)	—			(31		)
Purchase of 2,539,473 shares for company benefit plans	(6		)	—			(6		)
Release of 110,796 shares from company benefit plans	1			—			1
Balance, end of period	(36		)	—			(36		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY	2,549			1,548			4,097
NONCONTROLLING INTERESTS:
Balance, beginning of period	123			(82		)	41
Net income attributable to noncontrolling interests	(1		)	1			—
Distributions to noncontrolling interest owners	—			—			—
Balance, end of period	122			(81		)	41
TOTAL EQUITY	$	2,671		$	1,467		$	4,138



	Three Months Ended March 31, 2018
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	Under Full Cost			Adjustment			Under Successful Efforts
	($ in millions)
PREFERRED STOCK:
Balance, beginning and end of period	$	1,671		$	—		$	1,671
COMMON STOCK:
Balance, beginning of period	9			—			9
Balance, end of period	9			—			9
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period	14,437			—			14,437
Stock-based compensation	5			—			5
Dividends on preferred stock	(23		)	—			(23		)
Balance, end of period	14,419			—			14,419
ACCUMULATED DEFICIT:
Balance, beginning of period	(16,525		)	2,395			(14,130		)
Net income attributable to Chesapeake	293			(276		)	17
Cumulative effect of accounting change	(8		)	—			(8		)
Balance, end of period	(16,240		)	2,119			(14,121		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(57		)	—			(57		)
Hedging activity	10			—			10
Balance, end of period	(47		)	—			(47		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(31		)	—			(31		)
Purchase of 1,451,478 shares for company benefit plans	(4		)	—			(4		)
Release of 275,407 shares from company benefit plans	3			—			3
Balance, end of period	(32		)	—			(32		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT)	(220		)	2,119			1,899
NONCONTROLLING INTERESTS:
Balance, beginning of period	124			(80		)	44
Net income attributable to noncontrolling interests	1			—			1
Distributions to noncontrolling interest owners	(2		)	—			(2		)
Balance, end of period	123			(80		)	43
TOTAL EQUITY (DEFICIT)	$	(97	)	$	2,039		$	1,942

Oil and Natural Gas Property Transactions (Tables)

3 Months Ended

Mar. 31, 2019

Business Combinations [Abstract]

Schedule of preliminary allocation of the total purchase price

The following table represents the preliminary allocation of the total purchase price of WildHorse to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of WildHorse’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.



	Preliminary Purchase Price Allocation
	($ in millions)
Consideration:
Cash	$	381
Fair value of Chesapeake’s common stock issued in the Merger ^(a)	2,037
Total consideration	$	2,418

Fair Value of Liabilities Assumed:
Current liabilities	$	166
Long-term debt	1,379
Deferred tax liabilities	314
Other long-term liabilities	36
Amounts attributable to liabilities assumed	$	1,895

Fair Value of Assets Acquired:
Cash and cash equivalents	$	28
Other current assets	128
Proved oil and natural gas properties	3,264
Unproved properties	756
Other property and equipment	77
Other long-term assets	60
Amounts attributable to assets acquired	$	4,313

Total identifiable net assets	$	2,418

___________________________________________


(a)	Based on 717,376,170 Chesapeake common shares issued at closing at $2.84 per share (closing price as of February 1, 2019).

Schedule of pro forma financial information



	Three Months Ended March 31,
	2019			2018
	($ in millions except per share data)
Revenues	$	2,188		$	2,682
Net loss available to common stockholders	$	(59	)	$	(10	)
Earnings per common share:
Basic	$	(0.04	)	$	(0.01	)
Diluted	$	(0.04	)	$	(0.01	)

Capitalized Exploratory Well Costs (Tables)

3 Months Ended

Mar. 31, 2019

Extractive Industries [Abstract]

Summary of changes in capitalized well costs



	2019
	($ in millions)
Balance as of January 1	$	36
Additions pending the determination of proved reserves	7
Divestitures and other	—
Reclassifications to proved properties	(16		)
Charges to exploration expense	—
Balance as of March 31	$	27

Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2019

Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]

Reconciliation of basic EPS and diluted EPS

Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive:



	Three Months Ended March 31,
	2019	2018
	(in millions)
Common stock equivalent of our preferred stock outstanding	60	60
Common stock equivalent of our convertible senior notes outstanding	146	146

Reconciliation of basic EPS and diluted EPS

Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive:



	Three Months Ended March 31,
	2019	2018
	(in millions)
Common stock equivalent of our preferred stock outstanding	60	60
Common stock equivalent of our convertible senior notes outstanding	146	146

Debt (Tables)

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Schedule of long-term debt

Our long-term debt consisted of the following as of March 31, 2019 and December 31, 2018:



	March 31, 2019						December 31, 2018
	Principal Amount			Carrying Amount			Principal Amount			Carrying Amount
	($ in millions)
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
5.75% senior notes due 2023	338			338			338			338
7.00% senior notes due 2024	850			850			850			850
6.875% senior notes due 2025^(a)	700			704			—			—
8.00% senior notes due 2025	1,300			1,291			1,300			1,291
5.5% convertible senior notes due 2026^(b)(c)	1,250			874			1,250			866
7.5% senior notes due 2026	400			400			400			400
8.00% senior notes due 2027	1,300			1,299			1,300			1,299
2.25% contingent convertible senior notes due 2038	—			—			1			1
Chesapeake revolving credit facility	842			842			419			419
BVL revolving credit facility^(a)	688			688			—			—
Debt issuance costs	—			(50		)	—			(53		)
Interest rate derivatives	—			1			—			1
Total debt, net	9,978			9,547			8,168			7,722
Less current maturities of long-term debt, net^(d)	(380		)	(380		)	(381		)	(381		)
Total long-term debt, net	$	9,598		$	9,167		$	7,787		$	7,341

___________________________________________


(a)	On February 1, 2019, we acquired the debt of WildHorse which consisted of 6.875% Senior Notes due 2025 and a revolving credit facility. We now refer to this debt as our BVL Senior Notes and our BVL revolving credit facility, respectively. See further discussion below.


(b)	We are required to account for the liability and equity components of our convertible debt instrument 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 rate for our 5.5% Convertible Senior Notes due 2026 is 11.5%.


(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 second quarter of 2019.


(d)	As of March 31, 2019 and December 31, 2018, net current maturities of long-term debt includes our Floating Rate Senior Notes due April 2019. Subsequent to March 31, 2019, we repaid these notes in full upon maturity.

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:



	March 31, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			($ in millions)
Short-term debt (Level 1)	$	380	$	379	$	381	$	379
Long-term debt (Level 1)	$	4,200	$	4,240	$	3,495	$	3,173
Long-term debt (Level 2)	$	4,967	$	5,232	$	3,846	$	3,644

Contingencies and Commitments (Tables)

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of contractual obligation



	March 31, 2019
	($ in millions)
2019	$	627
2020	783
2021	687
2022	585
2023	472
2024 – 2035	2,443
Total	$	5,597

Other Liabilities (Tables)

3 Months Ended

Mar. 31, 2019

Other Liabilities Disclosure [Abstract]

Other current liabilities

Other current liabilities as of March 31, 2019 and December 31, 2018 are detailed below:



	March 31, 2019		December 31, 2018
	($ in millions)
Revenues and royalties due others	$	562	$	687
Accrued drilling and production costs	467		258
Joint interest prepayments received	69		73
VPP deferred revenue^(a)	58		59
Accrued compensation and benefits	114		202
Other accrued taxes	105		108
Other	216		212
Total other current liabilities	$	1,591	$	1,599

Schedule of ROU assets and lease liabilities

Other long-term liabilities as of March 31, 2019 and December 31, 2018 are detailed below:



	March 31, 2019		December 31, 2018
	($ in millions)
VPP deferred revenue^(a)	$	49	$	63
Unrecognized tax benefits	53		53
Other	108		103
Total other long-term liabilities	$	210	$	219

____________________________________________

(a)

Leases (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

The following table presents our ROU assets and lease liabilities as of March 31, 2019.



	Financing		Operating
	($ in millions)
ROU assets	$	24	$	32

Lease liabilities:
Current lease liabilities	9		19
Long-term lease liabilities	15		15
Total lease liabilities	$	24	$	34

Schedule of operating and financing lease additional information

Additional information for the Company’s operating and finance leases is presented below:



	Three Months Ended March 31, 2019
Lease cost:	($ in millions)
Amortization of ROU assets	$	2
Interest on lease liability	1
Finance lease cost	3
Operating lease cost	7
Short-term lease cost	22
Total lease cost^(a)	$	32

Other information:
Operating cash outflows from finance lease	$	1
Operating cash outflows from operating leases	$	2
Investing cash outflows from operating leases	$	27
Financing cash outflows from finance lease	$	2
Weighted-average remaining lease term - finance lease	2.75 years
Weighted-average remaining lease term - operating leases	3.8 years
Weighted-average discount rate - finance lease	7.50		%
Weighted-average discount rate - operating leases	5.09		%

____________________________________________


(a)	Includes $27 million of capitalized lease costs.

Schedule of maturity analysis of finance lease liabilities and operating lease liabilities

Maturity analysis of finance lease liabilities and operating lease liabilities are presented below:



	March 31, 2019
	Financing Lease			Operating Leases
	($ in millions)
2019 remaining	$	7		$	18
2020	10			6
2021	10			2
2022	—			2
2023	—			2
Thereafter	—			7
Total lease payments	27			37
Less imputed interest	(3		)	(3		)
Present value of lease liabilities	24			34
Less current maturities	(9		)	(19		)
Present value of lease liabilities, less current maturities	$	15		$	15

The aggregate undiscounted minimum future lease payments under previous lease accounting standard, ASC 840, are presented below:



	December 31, 2018
	Capital Lease		Operating Leases
	($ in millions)
2019	$	10	$	3
2020	10		1
2021	10		—
Total minimum lease payments	$	30	$	4

Schedule of maturity analysis of finance lease liabilities and operating lease liabilities

Maturity analysis of finance lease liabilities and operating lease liabilities are presented below:



	March 31, 2019
	Financing Lease			Operating Leases
	($ in millions)
2019 remaining	$	7		$	18
2020	10			6
2021	10			2
2022	—			2
2023	—			2
Thereafter	—			7
Total lease payments	27			37
Less imputed interest	(3		)	(3		)
Present value of lease liabilities	24			34
Less current maturities	(9		)	(19		)
Present value of lease liabilities, less current maturities	$	15		$	15

The aggregate undiscounted minimum future lease payments under previous lease accounting standard, ASC 840, are presented below:



	December 31, 2018
	Capital Lease		Operating Leases
	($ in millions)
2019	$	10	$	3
2020	10		1
2021	10		—
Total minimum lease payments	$	30	$	4

Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of revenue

The following table shows revenue disaggregated by operating area and product type, for the Current Quarter and the Prior Quarter:



	Three Months Ended March 31, 2019
	Oil			Natural Gas			NGL		Total
	($ in millions)
Marcellus	$	—		$	302		$	—	$	302
Haynesville	—			201			—		201
Eagle Ford	331			48			46		425
Brazos Valley	121			4			2		127
Powder River Basin	74			25			10		109
Mid-Continent	40			15			11		66
Revenue from contracts with customers	566			595			69		1,230
Losses on oil, natural gas and NGL derivatives	(259		)	(42		)	—		(301		)
Oil, natural gas and NGL revenue	$	307		$	553		$	69	$	929

Marketing revenue from contracts with customers	$	613		$	413		$	117	$	1,143
Other marketing revenue	72			20			—		92
Losses on oil, natural gas and NGL derivatives	—			(2		)	—		(2		)
Marketing revenue	$	685		$	431		$	117	$	1,233

	Three Months Ended March 31, 2018
	Oil			Natural Gas			NGL		Total
	($ in millions)
Marcellus	$	—		$	294		$	—	$	294
Haynesville	—			210			—		210
Eagle Ford	364			42			40		446
Powder River Basin	40			12			8		60
Mid-Continent	73			32			17		122
Utica	60			116			52		228
Revenue from contracts with customers	537			706			117		1,360
Gains (losses) on oil, natural gas and NGL derivatives	(86		)	(32		)	1		(117		)
Oil, natural gas and NGL revenue	$	451		$	674		$	118	$	1,243

Marketing revenue from contracts with customers	686			293			110		1,089
Other marketing revenue	117			40			—		157
Marketing revenue	$	803		$	333		$	110	$	1,246

Accounts receivable

Accounts receivable as of March 31, 2019 and December 31, 2018 are detailed below:



	March 31, 2019			December 31, 2018
	($ in millions)
Oil, natural gas and NGL sales	$	887		$	976
Joint interest	262			211
Other	67			77
Allowance for doubtful accounts	(20		)	(17		)
Total accounts receivable, net	$	1,196		$	1,247

Share-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2019

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 Quarter 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, 2019	11,858		$	4.43
Granted	4,272		$	2.97
Vested	(3,937	)	$	4.49
Forfeited	(93	)	$	5.54
Unvested restricted stock as of March 31, 2019	12,100		$	3.89

Weighted average assumptions to estimate grant date fair value of the stock options granted

We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Quarter:



Expected option life – years	6.0
Volatility	65.61	%
Risk-free interest rate	2.47	%
Dividend yield	—	%

We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value and the reporting date fair value of the 2017 awards.



Grant Date Assumptions
Assumption	2017 Awards
Volatility	80.65	%
Risk-free interest rate	1.54	%
Dividend yield for value of awards	—	%



Reporting Period Assumptions
Assumption	2017 Awards
Volatility	66.62	%
Risk-free interest rate	2.41	%
Dividend yield for value of awards	—	%

Schedule of stock option activity

The following table provides information related to stock option activity in the Current Quarter:



	Number of Shares Underlying Options		Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value^(a)
	(in thousands)					($ in millions)
Outstanding as of January 1, 2019	18,096		$	7.20	7.15	$	—
Granted	1,000		$	2.97
Exercised	—		$	—		$	—
Expired	(87	)	$	11.23
Forfeited	(79	)	$	5.45
Outstanding as of March 31, 2019	18,930		$	6.97	7.03	$	—
Exercisable as of March 31, 2019	13,355		$	8.23	6.33	$	—

___________________________________________


(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 and the Prior Quarter:



	Three Months Ended March 31,
	2019		2018
	($ in millions)
General and administrative expenses	$	6	$	7
Oil and natural gas properties	1		2
Oil, natural gas and NGL production expenses	1		2
Exploration expenses	—		—
Total restricted stock and stock option compensation	$	8	$	11

Summary of liability classified awards

The following table presents a summary of our liability-classified awards:



		Grant Date Fair Value		March 31, 2019
	Units	Grant Date Fair Value		Fair Value		Vested Liability
		($ in millions)		($ in millions)
2019 PSU Awards:
Payable 2020, 2021 and 2022	5,359,249	$	16	$	17	$	—
2018 PSU Awards:
Payable 2020 and 2021	2,639,765	$	8	$	8	$	—
2017 PSU Awards:
Payable 2020	1,217,774	$	8	$	4	$	2
2018 CRSU Awards:
Payable 2020 and 2021	9,732,557	$	29	$	30	$	—

Derivative and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2019

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 March 31, 2019 and December 31, 2018 are provided below:



	March 31, 2019				December 31, 2018
	Notional Volume	Fair Value			Notional Volume	Fair Value
		($ in millions)				($ in millions)
Oil (mmbbl):
Fixed-price swaps	21	$	(31	)	12	$	157
Collars	6	24			8	98
Call swaptions	2	(7		)	—	—
Put options	2	(5		)	—	—
Basis protection swaps	6	4			7	5
Total oil	37	(15		)	27	260
Natural gas (bcf):
Fixed-price swaps	594	21			623	26
Three-way collars	66	3			88	1
Collars	28	—			55	(3		)
Call options	39	—			44	—
Call swaptions	106	(18		)	106	(9		)
Basis protection swaps	38	(1		)	50	—
Total natural gas	871	5			966	15
Contingent consideration:
Utica divestiture		7				7
Total estimated fair value		$	(3	)		$	282

Schedule of effect of derivative instruments, condensed consolidated balance sheets



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 March 31, 2019
Commodity Contracts:
Short-term derivative asset	$	69		$	(51	)	$	18
Long-term derivative asset	61			(13		)	48
Short-term derivative liability	(112		)	51			(61		)
Long-term derivative liability	(28		)	13			(15		)
Contingent Consideration:
Short-term derivative asset	7			—			7
Total derivatives	$	(3	)	$	—		$	(3	)

As of December 31, 2018
Commodity Contracts:
Short-term derivative asset	$	306		$	(104	)	$	202
Long-term derivative asset	117			(41		)	76
Short-term derivative liability	(107		)	104			(3		)
Long-term derivative liability	(41		)	41			—
Contingent Consideration:
Short-term derivative asset	7			—			7
Total derivatives	$	282		$	—		$	282

Schedule of effect of derivative instruments, condensed consolidated statements of operations

The components of oil, natural gas and NGL revenues for the Current Quarter and the Prior Quarter are presented below:



	Three Months Ended March 31,
	2019			2018
	($ in millions)
Oil, natural gas and NGL revenues	$	1,230		$	1,360
Losses on undesignated oil, natural gas and NGL derivatives	(291		)	(107		)
Losses on terminated cash flow hedges	(10		)	(10		)
Total oil, natural gas and NGL revenues	$	929		$	1,243

Schedule of effect of derivative instruments, accumulated other comprehensive income (loss)

A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below:



	Three Months Ended March 31,
	2019						2018
	Before Tax			After Tax			Before Tax			After Tax
	($ in millions)
Balance, beginning of period	$	(80	)	$	(23	)	$	(114	)	(57	)
Losses reclassified to income	10			10			10			10
Balance, end of period	$	(70	)	$	(13	)	(104		)	(47	)

Schedule of financial assets (liabilities)

The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of March 31, 2019 and December 31, 2018:



	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
			($ in millions)
As of March 31, 2019
Derivative Assets (Liabilities):
Commodity assets	$	—	$	89		$	27		$	116
Commodity liabilities	—		(102		)	(24		)	(126		)
Utica divestiture contingent consideration	—		—			7			7
Total derivatives	$	—	$	(13	)	$	10		$	(3	)

As of December 31, 2018
Derivative Assets (Liabilities):
Commodity assets	$	—	$	319		$	103		$	422
Commodity liabilities	—		(131		)	(16		)	(147		)
Utica divestiture contingent consideration	—		—			7			7
Total derivatives	$	—	$	188		$	94		$	282

A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during the Current Quarter and the Prior Quarter is presented below:



	Commodity Derivatives			Utica Contingent Consideration
	($ in millions)
Balance, as of January 1, 2019	$	87		$	7
Total gains (losses) (realized/unrealized):
Included in earnings^(a)	(88		)	—
Total purchases, issuances, sales and settlements:
Settlements	4			—
Balance, as of March 31, 2019	$	3		$	7

Balance, as of January 1, 2018	$	(15	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings^(a)	(8		)	—
Total purchases, issuances, sales and settlements:
Settlements	(1		)	—
Balance, as of March 31, 2018	$	(24	)	$	—

___________________________________________



(a)		Commodity Derivatives
		Commodity Derivatives
		2019			2018
		($ in millions)
	Total gains (losses) included in earnings for the period	$	(88	)	$	(8	)
	Change in unrealized gains (losses) related to assets still held at reporting date	$	(84	)	$	(10	)

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 March 31, 2019 and December 31, 2018:



	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value
	($ in millions)
As of March 31, 2019
Financial Assets (Liabilities):
Other current assets	$	43		$	—	$	—	$	43
Other current liabilities	(44		)	—		—		(44		)
Total	$	(1	)	$	—	$	—	$	(1	)

As of December 31, 2018
Financial Assets (Liabilities):
Other current assets	$	50		$	—	$	—	$	50
Other current liabilities	(51		)	—		—		(51		)
Total	$	(1	)	$	—	$	—	$	(1	)

Schedule of quantitative information about level 3 inputs used

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 March 31, 2019:



Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value March 31, 2019
				($ in millions)
Oil trades	Oil price volatility curves	12.58% – 26.61%	22.44%	$	17
Natural gas trades	Natural gas price volatility curves	19.91% – 54.81%	20.11%	$	(14	)

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Schedule of fair value measurement of financial assets (liabilities) measured at fair value on a recurring basis

The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of March 31, 2019 and December 31, 2018:



	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
			($ in millions)
As of March 31, 2019
Derivative Assets (Liabilities):
Commodity assets	$	—	$	89		$	27		$	116
Commodity liabilities	—		(102		)	(24		)	(126		)
Utica divestiture contingent consideration	—		—			7			7
Total derivatives	$	—	$	(13	)	$	10		$	(3	)

As of December 31, 2018
Derivative Assets (Liabilities):
Commodity assets	$	—	$	319		$	103		$	422
Commodity liabilities	—		(131		)	(16		)	(147		)
Utica divestiture contingent consideration	—		—			7			7
Total derivatives	$	—	$	188		$	94		$	282

A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during the Current Quarter and the Prior Quarter is presented below:



	Commodity Derivatives			Utica Contingent Consideration
	($ in millions)
Balance, as of January 1, 2019	$	87		$	7
Total gains (losses) (realized/unrealized):
Included in earnings^(a)	(88		)	—
Total purchases, issuances, sales and settlements:
Settlements	4			—
Balance, as of March 31, 2019	$	3		$	7

Balance, as of January 1, 2018	$	(15	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings^(a)	(8		)	—
Total purchases, issuances, sales and settlements:
Settlements	(1		)	—
Balance, as of March 31, 2018	$	(24	)	$	—

___________________________________________



(a)		Commodity Derivatives
		Commodity Derivatives
		2019			2018
		($ in millions)
	Total gains (losses) included in earnings for the period	$	(88	)	$	(8	)
	Change in unrealized gains (losses) related to assets still held at reporting date	$	(84	)	$	(10	)



	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 March 31, 2019
Financial Assets (Liabilities):
Other current assets	$	43		$	—	$	—	$	43
Other current liabilities	(44		)	—		—		(44		)
Total	$	(1	)	$	—	$	—	$	(1	)

As of December 31, 2018
Financial Assets (Liabilities):
Other current assets	$	50		$	—	$	—	$	50
Other current liabilities	(51		)	—		—		(51		)
Total	$	(1	)	$	—	$	—	$	(1	)

Condensed Consolidating Financial Information (Tables)

3 Months Ended

Mar. 31, 2019

Condensed Financial Information Disclosure [Abstract]

Condensed Consolidated Balance Sheets

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF MARCH 31, 2019

($ in millions)



	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	3	$	1	$	6	$	(2	)	$	8
Other current assets	53		1,208		96		—			1,357
Intercompany receivable, net	6,350		—		—		(6,350		)	—
Total Current Assets	6,406		1,209		102		(6,352		)	1,365
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on successful efforts accounting, net	—		9,673		4,094		—			13,767
Other property and equipment, net	—		1,077		79		—			1,156
Property and equipment held for sale, net	—		16		—		—			16
Total Property and Equipment, Net	—		10,766		4,173		—			14,939
LONG-TERM ASSETS:
Other long-term assets	347		245		51		(310		)	333
Investments in subsidiaries and intercompany advances	5,692		2,328		—		(8,020		)	—
TOTAL ASSETS	$	12,445	$	14,548	$	4,326	$	(14,682	)	$	16,637

CURRENT LIABILITIES:
Current liabilities	$	521	$	2,203	$	208	$	(2	)	$	2,930
Intercompany payable, net	—		6,350		—		(6,350		)	—
Total Current Liabilities	521		8,553		208		(6,352		)	2,930
LONG-TERM LIABILITIES:
Long-term debt, net	7,775		—		1,392		—			9,167
Other long-term liabilities	52		303		357		(310		)	402
Total Long-Term Liabilities	7,827		303		1,749		(310		)	9,569
EQUITY:
Chesapeake stockholders’ equity	4,097		5,692		2,328		(8,020		)	4,097
Noncontrolling interests	—		—		41		—			41
Total Equity	4,097		5,692		2,369		(8,020		)	4,138
TOTAL LIABILITIES AND EQUITY	$	12,445	$	14,548	$	4,326	$	(14,682	)	$	16,637

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2018

($ in millions)



	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	4	$	1	$	1	$	(2	)	$	4
Other current assets	60		1,532		2		—			1,594
Intercompany receivable, net	6,671		—		—		(6,671		)	—
Total Current Assets	6,735		1,533		3		(6,673		)	1,598
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on successful efforts accounting, net	—		9,664		48		—			9,712
Other property and equipment, net	—		1,091		—		—			1,091
Property and equipment held for sale, net	—		15		—		—			15
Total Property and Equipment, Net	—		10,770		48		—			10,818
LONG-TERM ASSETS:
Other long-term assets	26		293		—		—			319
Investments in subsidiaries and intercompany advances	3,248		9		—		(3,257		)	—
TOTAL ASSETS	$	10,009	$	12,605	$	51	$	(9,930	)	$	12,735

CURRENT LIABILITIES:
Current liabilities	$	523	$	2,365	$	1	$	(2	)	$	2,887
Intercompany payable, net	—		6,671		—		(6,671		)	—
Total Current Liabilities	523		9,036		1		(6,673		)	2,887
LONG-TERM LIABILITIES:
Long-term debt, net	7,341		—		—		—			7,341
Other long-term liabilities	53		321		—		—			374
Total Long-Term Liabilities	7,394		321		—		—			7,715
EQUITY:
Chesapeake stockholders’ equity	2,092		3,248		9		(3,257		)	2,092
Noncontrolling interests	—		—		41		—			41
Total Equity	2,092		3,248		50		(3,257		)	2,133
TOTAL LIABILITIES AND EQUITY	$	10,009	$	12,605	$	51	$	(9,930	)	$	12,735

Condensed Consolidated Income Statements

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2019

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	850		$	79		$	—	$	929
Marketing	—			1,233			—			—		1,233
Total Revenues	—			2,083			79			—		2,162
Other	—			15			—			—		15
Gains on sales of assets	—			19			—			—		19
Total Revenues and Other	—			2,117			79			—		2,196
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			117			15			—		132
Oil, natural gas and NGL gathering, processing and transportation	—			269			5			—		274
Production taxes	—			28			6			—		34
Exploration	—			20			4			—		24
Marketing	—			1,230			—			—		1,230
General and administrative	—			85			18			—		103
Provision for legal contingencies, net	—			—			—			—		—
Depreciation, depletion and amortization	—			435			84			—		519
Impairments	—			1			—			—		1
Other operating income	—			23			38			—		61
Total Operating Expenses	—			2,208			170			—		2,378
INCOME FROM OPERATIONS	—			(91		)	(91		)	—		(182		)
OTHER INCOME (EXPENSE):
Interest expense	(154		)	5			(12		)	—		(161		)
Losses on investments	—			—			(1		)	—		(1		)
Other income	—			9			—			—		9
Equity in net earnings of subsidiary	(177		)	(100		)	—			277		—
Total Other Expense	(331		)	(86		)	(13		)	277		(153		)
LOSS BEFORE INCOME TAXES	(331		)	(177		)	(104		)	277		(335		)
INCOME TAX BENEFIT	(310		)	—			(4		)	—		(314		)
NET LOSS	(21		)	(177		)	(100		)	277		(21		)
Net income attributable to noncontrolling interests	—			—			—			—		—
NET LOSS ATTRIBUTABLE TO CHESAPEAKE	(21		)	(177		)	(100		)	277		(21		)
Other comprehensive income	—			10			—			—		10
COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE	$	(21	)	$	(167	)	$	(100	)	$	277	$	(11	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2018

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	1,238		$	5		$	—		$	1,243
Marketing	—			1,246			—			—			1,246
Total Revenues	—			2,484			5			—			2,489
Other	—			16			—			—			16
Gains on sales of assets	—			19			—			—			19
Total Revenues and Other	—			2,519			5			—			2,524
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			147			—			—			147
Oil, natural gas and NGL gathering, processing and transportation	—			355			1			—			356
Production taxes	—			31			—			—			31
Exploration	—			81			—			—			81
Marketing	—			1,268			—			—			1,268
General and administrative	—			87			—			—			87
Restructuring and other termination costs	—			38			—			—			38
Provision for legal contingencies, net	—			5			—			—			5
Depreciation, depletion and amortization	—			457			2			—			459
Impairments	—			10			—			—			10
Total Operating Expenses	—			2,479			3			—			2,482
INCOME FROM OPERATIONS	—			40			2			—			42
OTHER INCOME (EXPENSE):
Interest expense	(162		)	—			—			—			(162		)
Gains on investments	—			139			—			—			139
Other expense	—			(1		)	—			—			(1		)
Equity in net earnings of subsidiary	179			1			—			(180		)	—
Total Other Income (Expense)	17			139			—			(180		)	(24		)
INCOME BEFORE INCOME TAXES	17			179			2			(180		)	18
INCOME TAX EXPENSE	—			—			—			—			—
NET INCOME	17			179			2			(180		)	18
Net income attributable to noncontrolling interests	—			—			(1		)	—			(1		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	17			179			1			(180		)	17
Other comprehensive income	—			10			—			—			10
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	17		$	189		$	1		$	(180	)	$	27

Condensed Consolidated Cash Flow Statements

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2019

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	$	—		$	421		$	36		$	(1	)	$	456

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(406		)	(109		)	—			(515		)
Business combination, net	—			(381		)	28			—			(353		)
Acquisitions of proved and unproved properties	—			(6		)	—			—			(6		)
Proceeds from divestitures of proved and unproved properties	—			26			—			—			26
Additions to other property and equipment	—			(6		)	(3		)	—			(9		)
Other investing activities	—			1			—			—			1
Net Cash Used In Investing Activities	—			(772		)	(84		)	—			(856		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	3,449			—			123			—			3,572
Payments on revolving credit facility borrowings	(3,026		)	—			(110		)	—			(3,136		)
Cash paid to purchase debt	(1		)	—			—			—			(1		)
Cash paid for preferred stock dividends	(23		)	—			—			—			(23		)
Other financing activities	(7		)	(1		)	(1		)	1			(8		)
Intercompany advances, net	(393		)	352			41			—			—
Net Cash Provided By (Used In) Financing Activities	(1		)	351			53			1			404
Net increase (decrease) in cash and cash equivalents	(1		)	—			5			—			4
Cash and cash equivalents, beginning of period	4			1			1			(2		)	4
Cash and cash equivalents, end of period	$	3		$	1		$	6		$	(2	)	$	8

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2018

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	$	78		$	509		$	5		$	(4	)	$	588

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(420		)	—			—			(420		)
Acquisitions of proved and unproved properties	—			(17		)	—			—			(17		)
Proceeds from divestitures of proved and unproved properties	—			319			—			—			319
Additions to other property and equipment	—			(3		)	—			—			(3		)
Other investing activities	—			142			—			—			142
Net Cash Provided by Investing Activities	—			21			—			—			21

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	2,904			—			—			—			2,904
Payments on revolving credit facility borrowings	(3,485		)	—			—			—			(3,485		)
Cash paid for preferred stock dividends	(23		)	—			—			—			(23		)
Other financing activities	25			(2		)	(4		)	(25		)	(6		)
Intercompany advances, net	530			(528		)	(2		)	—			—
Net Cash Used In Financing Activities	(49		)	(530		)	(6		)	(25		)	(610		)
Net increase (decrease) in cash and cash equivalents	29			—			(1		)	(29		)	(1		)
Cash and cash equivalents, beginning of period	5			1			2			(3		)	5
Cash and cash equivalents, end of period	$	34		$	1		$	1		$	(32	)	$	4

Subsequent Events (Tables)

3 Months Ended

Mar. 31, 2019

Subsequent Events [Abstract]

Schedule of private exchange offer for outstanding senior unsecured notes



	Amount of Notes Exchanged
	($ in millions)
6.625% senior notes due 2020	$	229
6.875% senior notes due 2020	134
6.125% senior notes due 2021	381
5.375% senior notes due 2021	140
Total	$	884

Change in Accounting Principle - Statements of Operations (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

$ 2,196

$ 2,524

^[1]

^[1],[2]

^[1]

103

^[1]

^[1]

^[1]

519

459

^[1],[2]

^[1],[2]

^[1]

2,378

2,482

^[1]

(182)

^[1]

(161)

(162)

^[1]

(1)

139

^[1]

(1)

^[1]

(153)

(24)

^[1]

(335)

^[1]

(314)

^[1]

Net income attributable to noncontrolling interests

(21)

^[2],[3]

(1)

^[3]

(21)

^[1]

Earnings allocated to participating securities

(23)

^[1]

$ (44)

$ (6)

^[1]

$ (0.03)

$ (0.01)

^[1]

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):

$ (0.03)

$ (0.01)

^[1]

1,380

907

^[1]

1,380

907

^[1]

$ 929

$ 1,243

^[1]

1,233

1,246

^[1]

Oil, natural gas and NGL and Marketing

1,230

1,268

^[1]

2,162

2,489

^[1]

Oil, natural gas and NGL production

^[1]

Oil, natural gas and NGL gathering, processing and transportation

132

147

^[1]

274

356

^[1]

^[1]

2,162

2,489

357

286

2,167

2,211

(5)

278

(135)

(123)

(1)

139

(129)

(134)

294

(314)

Net income attributable to noncontrolling interests

180

294

(1)

179

293

Earnings allocated to participating securities

(23)

(2)

$ 156

$ 268

$ 0.11

$ 0.30

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):

$ 0.11

$ 0.29

1,380

907

Under Full Cost | Oil, natural gas and NGL

1,380

1,053

Under Full Cost | Marketing

$ 929

$ 1,243

1,233

1,246

Under Full Cost | Oil, natural gas and NGL and Marketing

1,230

1,268

2,162

2,489

Under Full Cost | Other

Under Full Cost | Oil, natural gas and NGL production

Under Full Cost | Oil, natural gas and NGL gathering, processing and transportation

132

147

Under Full Cost | Exploration

274

356

162

173

(8)

211

271

(177)

(236)

(26)

(39)

(1)

(24)

(40)

(201)

(276)

Net income attributable to noncontrolling interests

(201)

(276)

(200)

(276)

Earnings allocated to participating securities

$ (200)

$ (274)

$ (0.14)

$ (0.31)

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):

$ (0.14)

$ (0.30)

Successful Efforts Adjustment | Oil, natural gas and NGL

(146)

Successful Efforts Adjustment | Marketing

$ 0

Successful Efforts Adjustment | Oil, natural gas and NGL and Marketing

Successful Efforts Adjustment | Other

Successful Efforts Adjustment | Oil, natural gas and NGL production

Successful Efforts Adjustment | Oil, natural gas and NGL gathering, processing and transportation

Successful Efforts Adjustment | Exploration

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

$ 24

$ 81

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[3]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Change in Accounting Principle - Statements of Comprehensive Income (Loss) (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

$ (21)

$ 18

^[1],[2]

Reclassification of losses on settled derivative instruments

^[3]

^[2]

^[2],[3]

^[2]

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

(11)

^[2]

(1)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

(11)

^[2]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

180

294

Reclassification of losses on settled derivative instruments

^[3]

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

190

304

(1)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

189

303

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

(201)

(276)

Reclassification of losses on settled derivative instruments

^[3]

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

(201)

(276)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

$ (200)

$ (276)

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[3]	Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

Change in Accounting Principle - Statements of Cash Flows (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Sep. 30, 2017

^[1]

Condensed Cash Flow Statements, Captions [Line Items]

$ (21)

$ 18

^[1],[2]

519

459

^[1],[3]

(314)

^[1]

304

117

^[1]

^[1]

^[1]

(19)

^[1],[3]

^[1],[3]

^[1]

(139)

^[1]

(36)

^[1]

(93)

^[1]

456

588

^[1]

(515)

(420)

^[1]

(353)

^[1]

Proceeds from divestitures of proved and unproved properties

(6)

(17)

^[1]

319

^[1]

Proceeds from sales of other property and equipment

(9)

(3)

^[1]

^[1]

Net Cash Provided By (Used In) Investing Activities

^[1]

(856)

^[1]

3,572

2,904

^[1]

(3,136)

(3,485)

^[1]

(1)

$ 0

(23)

^[1]

(2)

^[1]

Net Cash Provided By (Used In) Financing Activities

(8)

(4)

^[1]

404

(610)

^[1]

Net increase (decrease) in cash and cash equivalents

(1)

^[1]

^[1]

^[1]

Condensed Cash Flow Statements, Captions [Line Items]

180

294

357

286

(314)

304

117

(139)

(28)

(78)

104

502

656

(533)

(442)

(353)

Proceeds from divestitures of proved and unproved properties

(34)

(63)

319

Proceeds from sales of other property and equipment

(9)

(3)

Net Cash Provided By (Used In) Investing Activities

(902)

(47)

3,572

2,904

(3,136)

(3,485)

(1)

(23)

(2)

Net Cash Provided By (Used In) Financing Activities

(8)

(4)

404

(610)

Net increase (decrease) in cash and cash equivalents

(1)

Condensed Cash Flow Statements, Captions [Line Items]

(201)

(276)

162

173

(19)

(8)

(15)

(16)

(46)

(68)

Proceeds from divestitures of proved and unproved properties

Proceeds from sales of other property and equipment

Net Cash Provided By (Used In) Investing Activities

Net Cash Provided By (Used In) Financing Activities

Net increase (decrease) in cash and cash equivalents

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

$ 0

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[3]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Change in Accounting Principle - Statements of Shareholders' Equity (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Jan. 01, 2019

Dec. 31, 2018

Jan. 01, 2018

Chesapeake stockholders’ equity, beginning of period

$ 2,092

(21)

$ 17

^[1]

Stockholders' equity attributable to noncontrolling interest, beginning of period

4,097

Net income attributable to noncontrolling interests

(1)

^[2]

Stockholders' equity attributable to noncontrolling interest, end of period

4,138

1,942

^[3]

$ 2,133

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Net income attributable to noncontrolling interests

179

293

(1)

2,671

(97)

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Net income attributable to noncontrolling interests

(200)

(276)

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

1,467

2,039

PREFERRED STOCK:

Chesapeake stockholders’ equity, beginning of period

1,671

PREFERRED STOCK: | Under Full Cost

1,671

^[3]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

1,671

PREFERRED STOCK: | Successful Efforts Adjustment

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

COMMON STOCK:

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

^[3]

^[3]

COMMON STOCK: | Under Full Cost

^[3]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

COMMON STOCK: | Successful Efforts Adjustment

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

ADDITIONAL PAID-IN CAPITAL:

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

14,378

14,437

^[3]

2,030

^[3]

^[3]

(23)

^[3]

ADDITIONAL PAID-IN CAPITAL: | Under Full Cost

16,392

14,419

^[3]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

14,378

14,437

2,030

(23)

ADDITIONAL PAID-IN CAPITAL: | Successful Efforts Adjustment

16,392

14,419

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

ACCUMULATED DEFICIT:

Chesapeake stockholders’ equity, beginning of period

(13,912)

(14,130)

^[3]

(21)

^[3]

$ 0

$ (8)

^[3]

ACCUMULATED DEFICIT: | Under Full Cost

(13,933)

(14,121)

^[3]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

(15,660)

(16,525)

179

293

(8)

ACCUMULATED DEFICIT: | Successful Efforts Adjustment

(15,481)

(16,240)

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

1,748

2,395

(276)

$ 0

ACCUMULATED OTHER COMPREHENSIVE LOSS:

1,548

2,119

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

(23)

(57)

^[3]

^[3]

ACCUMULATED OTHER COMPREHENSIVE LOSS: | Under Full Cost

(13)

(47)

^[3]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

(23)

(57)

ACCUMULATED OTHER COMPREHENSIVE LOSS: | Successful Efforts Adjustment

(13)

(47)

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

TREASURY STOCK – COMMON:

Chesapeake stockholders’ equity, beginning of period

(31)

^[3]

Purchase of 2,539,473 and 1,451,478 shares for company benefit plans

(6)

(4)

^[3]

Release of 110,796 and 275,407 shares from company benefit plans

^[3]

TREASURY STOCK – COMMON: | Under Full Cost

(36)

(32)

^[3]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

(31)

Purchase of 2,539,473 and 1,451,478 shares for company benefit plans

(6)

(4)

Release of 110,796 and 275,407 shares from company benefit plans

TREASURY STOCK – COMMON: | Successful Efforts Adjustment

(36)

(32)

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Chesapeake stockholders’ equity, beginning of period

Purchase of 2,539,473 and 1,451,478 shares for company benefit plans

Release of 110,796 and 275,407 shares from company benefit plans

TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY | Under Full Cost

4,097

1,899

^[3]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY | Successful Efforts Adjustment

2,549

(220)

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

NONCONTROLLING INTERESTS:

1,548

2,119

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Stockholders' equity attributable to noncontrolling interest, beginning of period

^[3]

Net income attributable to noncontrolling interests

^[3]

Stockholders' equity attributable to noncontrolling interest, end of period

(2)

^[3]

^[3]

NONCONTROLLING INTERESTS: | Under Full Cost

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Stockholders' equity attributable to noncontrolling interest, beginning of period

123

124

Net income attributable to noncontrolling interests

(1)

Stockholders' equity attributable to noncontrolling interest, end of period

(2)

122

123

NONCONTROLLING INTERESTS: | Successful Efforts Adjustment

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Stockholders' equity attributable to noncontrolling interest, beginning of period

(82)

(80)

Net income attributable to noncontrolling interests

Stockholders' equity attributable to noncontrolling interest, end of period

$ (81)

$ (80)

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[3]	Financial information for prior periods has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Oil and Natural Gas Property Transactions - Narrative (Details)
shares in Millions, $ in Millions

2 Months Ended

3 Months Ended

Feb. 01, 2019

USD ($)

Mar. 31, 2019

USD ($)

Mar. 31, 2019

USD ($)

Mar. 31, 2018

USD ($)

well

Proceeds from divestitures of proved and unproved properties

$ 2,196

$ 2,524

^[1]

319

^[2]

Mid-Continent

Proceeds from divestitures of proved and unproved properties

$ 420

Productive gas wells, number of wells, net | well

2,150

Number of net acres | a

171,000

Other properties

Proceeds from divestitures of proved and unproved properties

$ 18

Wildhorse Resource Development Corporation

Common stock issued in the merger (in shares) | shares

717.4

$ 381

$ 75

164

$ 12

Proceeds from divestitures of proved and unproved properties

$ 26

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

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

Oil and Natural Gas Property Transactions - Pro Forma Financial Information (Details) - Wildhorse Resource Development Corporation - USD ($) $ / shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Business Acquisition [Line Items]
Revenues	$ 2,188	$ 2,682
Net loss available to common stockholders	$ (59)	$ (10)
Basic (in dollars per share)	$ (40)	$ (10)
Diluted (in dollars per share)	$ (40)	$ (10)

Capitalized Exploratory Well Costs (Details) $ in Thousands	3 Months Ended
Capitalized Exploratory Well Costs (Details) $ in Thousands	Mar. 31, 2019 USD ($)
Changes in Capitalized Well Costs
Beginning balance	$ 36
Additions pending the determination of proved reserves	7
Divestitures and other	0
Reclassifications to proved properties	(16)
Charges to exploration expense	0
Ending balance	27
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 1,000

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Common stock equivalent of our convertible senior notes outstanding
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares of common stock that were excluded from the calculation of diluted EPS (in shares)	146	146
Common stock equivalent of our preferred stock outstanding
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares of common stock that were excluded from the calculation of diluted EPS (in shares)	60	60

Debt - Long-Term Debt Table (Details) - USD ($)	Mar. 31, 2019	Feb. 01, 2019	Dec. 31, 2018
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	$ 9,978,000,000		$ 8,168,000,000
Long-term Debt, Gross	9,547,000,000		7,722,000,000
Debt issuance costs	(50,000,000)		(53,000,000)
Debt, current	(380,000,000)		(381,000,000)
Current maturities of long-term debt, net	(380,000,000)		(381,000,000)
Long-term debt, fair value	9,598,000,000		7,787,000,000
Long-term debt, net	9,167,000,000		7,341,000,000
Interest rate derivatives
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	0		0
Interest rate derivatives	1,000,000		1,000,000
Senior notes \| Floating rate senior notes due 2019
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 \| 6.625% senior notes due 2020
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 \| 6.875% senior notes due 2020
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 \| 6.125% senior notes due 2021
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 \| 5.375% senior notes due 2021
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 \| 4.875% senior notes due 2022
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 \| 5.75% senior notes due 2023
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 \| 7.00% senior notes due 2024
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	$ 850,000,000		850,000,000
Long-term Debt, Gross	$ 850,000,000		850,000,000
Interest rate, stated percentage	7.00%
Senior notes \| 6.875% senior notes due 2025(a)
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	$ 700,000,000	$ 700,000,000	0
Long-term Debt, Gross	$ 704,000,000		0
Interest rate, stated percentage	6.875%	6.875%
Senior notes \| 8.00% senior notes due 2025
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	$ 1,300,000,000		1,300,000,000
Long-term Debt, Gross	$ 1,291,000,000		1,291,000,000
Interest rate, stated percentage	8.00%
Senior notes \| 7.5% senior notes due 2026
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	$ 400,000,000		400,000,000
Long-term Debt, Gross	400,000,000		400,000,000
Senior notes \| 8.00% senior notes due 2027
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	1,300,000,000		1,300,000,000
Long-term Debt, Gross	$ 1,299,000,000		1,299,000,000
Interest rate, stated percentage	8.00%
Convertible debt \| 5.5% convertible senior notes due 2026(b)(c)
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	$ 1,250,000,000		1,250,000,000
Long-term Debt, Gross	$ 874,000,000		866,000,000
Interest rate, stated percentage	5.50%
Interest rate, effective percentage	11.50%
Convertible debt \| 7.5% senior notes due 2026
Long-Term Debt Instrument [Line Items]
Interest rate, stated percentage	7.50%
Convertible debt \| 2.25% contingent convertible senior notes due 2038
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	$ 0		1,000,000
Long-term Debt, Gross	$ 0		1,000,000
Interest rate, stated percentage	2.25%
Line of credit \| Chesapeake revolving credit facility \| Revolving credit facility
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	$ 842,000,000		419,000,000
Chesapeake revolving credit facility	842,000,000		419,000,000
Line of credit \| BVL revolving credit facility(a) \| Revolving credit facility
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	688,000,000		0
Chesapeake revolving credit facility	$ 688,000,000		$ 0

Debt - Narrative (Details)	Feb. 01, 2019 USD ($)	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Sep. 30, 2019	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount						$ 9,978,000,000	$ 8,168,000,000
Senior notes \| 6.875% senior notes due 2025
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount	$ 700,000,000					$ 700,000,000	0
Interest rate, stated percentage	6.875%					6.875%
Debt covenant, basket	$ 25,000,000
Revolving credit facility \| Chesapeake revolving credit facility
Long-Term Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity						$ 3,000,000,000
Line of credit facility, maximum borrowing capacity, increased maximum						4,000,000,000
Letters of credit outstanding, amount						$ 61,000,000
Leverage ratio	4.00
Fixed charge coverage ratio						2.00
Revolving credit facility \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity						$ 2,000,000,000
Line of credit facility, current borrowing capacity						1,300,000,000
Letters of credit outstanding, amount						$ 47,000,000
Mortgage guarantee, secured percent on proved reserves						85.00%
Ratio of net debt to EBITDAX	4.00
Ratio of funded debt o EBITDAX	4.00
Current Ratio	1.00
Revolving credit facility \| Line of credit \| Chesapeake revolving credit facility
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount						$ 842,000,000	419,000,000
Borrowing capacity available						2,097,000,000
Revolving credit facility \| Line of credit \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Debt instrument, face amount						$ 688,000,000	$ 0
Minimum \| Revolving credit facility \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Commitment fee	0.375%
Minimum \| Alternative Base Rate (ABR) \| Revolving credit facility \| Chesapeake revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	0.50%
Minimum \| Alternative Base Rate (ABR) \| Revolving credit facility \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	0.50%
Minimum \| Eurodollar \| Revolving credit facility \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	1.50%
Minimum \| London Interbank Offered Rate (LIBOR) \| Revolving credit facility \| Chesapeake revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	1.50%
Minimum \| London Interbank Offered Rate (LIBOR) \| Revolving credit facility \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	1.50%
Maximum \| Revolving credit facility \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Commitment fee	0.50%
Maximum \| Alternative Base Rate (ABR) \| Revolving credit facility \| Chesapeake revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	2.00%
Maximum \| Alternative Base Rate (ABR) \| Revolving credit facility \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	1.50%
Maximum \| Eurodollar \| Revolving credit facility \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	2.50%
Maximum \| London Interbank Offered Rate (LIBOR) \| Revolving credit facility \| Chesapeake revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	3.00%
Maximum \| London Interbank Offered Rate (LIBOR) \| Revolving credit facility \| BVL revolving credit facility
Long-Term Debt Instrument [Line Items]
Variable rate percentage	2.50%
Forecast \| Revolving credit facility \| Chesapeake revolving credit facility
Long-Term Debt Instrument [Line Items]
Leverage ratio		4.00			5.50
Secured leverage ratio		2.50
Fixed charge coverage ratio			2.50	2.25

Debt - Fair Value of Debt Table (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 9,598	$ 7,787
Fair Value, Inputs, Level 1 \| Reported Value Measurement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term debt, fair value	380	381
Long-term debt, fair value	4,200	3,495
Fair Value, Inputs, Level 1 \| Estimate of Fair Value Measurement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term debt, fair value	379	379
Long-term debt, fair value	4,240	3,173
Fair Value, Inputs, Level 2 \| Reported Value Measurement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	4,967	3,846
Fair Value, Inputs, Level 2 \| Estimate of Fair Value Measurement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 5,232	$ 3,644

Contingencies and Commitments - Narrative (Details) - USD ($)			1 Months Ended
	Aug. 09, 2018	Jan. 05, 2014	Feb. 28, 2019
Loss Contingencies [Line Items]
Settlement amount	$ 35,000,000
Chaparral Energy, Inc. \| Healthcare of Ontario Pension Plan (HOOPP) \| Pending litigation
Loss Contingencies [Line Items]
Loss contingency, damages sought, value		$ 215,000,000
FTS International, Inc. \| Putative class action lawsuit \| Pending litigation
Loss Contingencies [Line Items]
Loss contingency, damages sought, value			$ 1,000,000

Contingencies and Commitments - Gathering Processing and Transportation Commitments Table (Details) - Gathering, processing and transportation agreement $ in Millions	Mar. 31, 2019 USD ($)
Other Commitments [Line Items]
Gathering, processing and transportation commitment, 2019	$ 627
Gathering, processing and transportation commitment, 2020	783
Gathering, processing and transportation commitment, 2021	687
Gathering, processing and transportation commitment, 2022	585
Gathering, processing and transportation commitment, 2023	472
Gathering, processing and transportation commitment, 2024-2035	2,443
Gathering, processing and transportation commitment, total	$ 5,597

Other Liabilities - Current Table (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
Revenues and royalties due others	$ 562	$ 687
Accrued drilling and production costs	467	258
Joint interest prepayments received	69	73
Joint interest prepayments received	58	59
Accrued compensation and benefits	114	202
Other accrued taxes	105	108
Other	216	212
Total other current liabilities	$ 1,591	$ 1,599

Other Liabilities - Long-Term Table (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
VPP deferred revenue(a)	$ 49	$ 63
Unrecognized tax benefits	53	53
Other	108	103
Total other long-term liabilities	$ 210	$ 219

Leases - Narrative (Details) $ in Millions		3 Months Ended	12 Months Ended
Leases - Narrative (Details) $ in Millions	Feb. 01, 2019 contract	Mar. 31, 2019 USD ($)	Dec. 31, 2018	Jan. 01, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Operating lease liability		$ 34.0
Operating lease, right-of-use asset		$ 32.0
Minimum
Lessee, Lease, Description [Line Items]
Lease, remaining lease term		1 month
Maximum
Lessee, Lease, Description [Line Items]
Lease, remaining lease term		7 years 9 months 18 days
Natural Gas Compressors \| Midcon Compression, L.L.C.
Lessee, Lease, Description [Line Items]
Lease terms			38 months
Wildhorse Resource Development Corporation
Lessee, Lease, Description [Line Items]
Operating lease liability				$ 40.0
Operating lease, right-of-use asset				38.0
Lease incentive				$ 2.0
Number of leases \| contract	2

Leases - ROU Assets and Liabilities (Details) $ in Millions	Mar. 31, 2019 USD ($)
Assets and Liabilities, Lessee [Abstract]
Financing, ROU assets	$ 24
Financing, current lease liabilities	9
Financing, long-term lease liabilities	15
Present value of lease liabilities	24
Operating, ROU assets	32
Operating, current lease liabilities	19
Operating, long-term lease liabilities	15
Present value of lease liabilities	$ 34

Leases - Additional Information (Details) $ in Millions	3 Months Ended
Leases - Additional Information (Details) $ in Millions	Mar. 31, 2019 USD ($)
Lease cost:
Amortization of ROU assets	$ 2
Interest on lease liability	1
Finance lease cost	3
Operating lease cost	7
Short-term lease cost	22
Total lease cost	32
Other information:
Operating cash outflows from finance lease	1
Operating cash outflows from operating leases	2
Investing cash outflows from operating leases	27
Financing cash outflows from finance lease	$ 2
Weighted-average remaining lease term - finance lease	2 years 9 months
Weighted-average remaining lease term - operating leases	3 years 9 months 18 days
Weighted-average discount rate - finance lease	7.50%
Weighted-average discount rate - operating leases	5.09%
Capitalized lease costs	$ 27

Leases - Maturity Analysis of Finance and Operating Lease Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Finance Leases, After Adoption of 842:
2019 remaining	$ 7
2020	10
2021	10
2022	0
2023	0
Thereafter	0
Total lease payments	27
Less imputed interest	(3)
Present value of lease liabilities	24
Less current maturities	(9)
Present value of lease liabilities, less current maturities	15
Operating Leases, After Adoption of 842:
2019 remaining	18
2020	6
2021	2
2022	2
2023	2
Thereafter	7
Total lease payments	37
Less imputed interest	(3)
Present value of lease liabilities	34
Less current maturities	(19)
Present value of lease liabilities, less current maturities	$ 15
Capital Leases, Before Adoption of 842:
2019		$ 10
2020		10
2021		10
Total minimum lease payments		30
Operating Leases, After Before of 842:
2019		3
2020		1
2021		0
Total minimum lease payments		$ 4

Revenue Recognition - Additional Information (Details) - Retained Earnings - USD ($)
$ in Millions

Jan. 01, 2019

Jan. 01, 2018

Revenue, Initial Application Period Cumulative Effect Transition [Line Items]

Revenue, Initial Application Period Cumulative Effect Transition [Line Items]

$ 0

$ (8)

^[1]

ASU 2014-09

$ (8)

[1]	Financial information for prior periods has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Revenue Recognition - Disaggregated Revenue (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Gains (losses) on oil, natural gas and NGL derivatives

$ 1,230

$ 1,360

(301)

(117)

^[1],[2]

2,196

2,524

^[1]

929

1,243

^[1]

Gains (losses) on oil, natural gas and NGL derivatives

1,143

1,089

(2)

1,233

1,246

^[1]

Other marketing revenue

157

^[1]

Marcellus

302

294

Haynesville

201

210

Eagle Ford

425

446

Brazos Valley

127

Powder River Basin

109

Mid-Continent

122

Utica

228

Oil

Gains (losses) on oil, natural gas and NGL derivatives

566

537

(259)

(86)

Oil | Oil, natural gas and NGL

307

451

Oil | Marketing

Gains (losses) on oil, natural gas and NGL derivatives

613

686

Oil | Other marketing revenue

685

803

117

Oil | Marcellus

Oil | Haynesville

Oil | Eagle Ford

331

364

Oil | Brazos Valley

121

Oil | Powder River Basin

Oil | Mid-Continent

Oil | Utica

Natural Gas

Gains (losses) on oil, natural gas and NGL derivatives

595

706

(42)

(32)

Natural Gas | Oil, natural gas and NGL

553

674

Natural Gas | Marketing

Gains (losses) on oil, natural gas and NGL derivatives

413

293

(2)

Natural Gas | Other marketing revenue

431

333

Natural Gas | Marcellus

Natural Gas | Haynesville

302

294

201

210

Natural Gas | Eagle Ford

Natural Gas | Brazos Valley

Natural Gas | Powder River Basin

Natural Gas | Mid-Continent

Natural Gas | Utica

116

NGL

Gains (losses) on oil, natural gas and NGL derivatives

117

NGL | Oil, natural gas and NGL

118

NGL | Marketing

Gains (losses) on oil, natural gas and NGL derivatives

117

110

NGL | Other marketing revenue

117

110

NGL | Marcellus

NGL | Haynesville

NGL | Eagle Ford

NGL | Brazos Valley

NGL | Powder River Basin

NGL | Mid-Continent

$ 11

NGL | Utica

$ 52

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Revenue Recognition - Accounts Receivable (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Allowance for doubtful accounts	$ (20)	$ (17)
Total accounts receivable, net	1,196	1,247
Oil, natural gas and NGL sales
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	887	976
Joint interest
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	262	211
Other
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	$ 67	$ 77

Income Taxes Income Taxes - Narrative (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

^[1]

Feb. 01, 2019

Effective income tax rate

0.00%

Income tax benefit

$ 314

$ 0

Wildhorse Resource Development Corporation

Deferred tax liability, plant, property and equipment and prepaid compensation

Deferred tax liabilities

$ 314

Income tax benefit

314

401

Deferred tax assets, operating loss carryforward, limitations

$ 61

Wildhorse Resource Development Corporation | Federal

Deferred tax asset, operating loss carryforward

$ 87

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Share-Based Compensation - Restricted Stock Table (Details) - Restricted stock shares in Thousands	3 Months Ended
	Mar. 31, 2019 $ / shares shares
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 (in shares) \| shares	11,858
Granted (in shares) \| shares	4,272
Vested (in shares) \| shares	(3,937)
Forfeited (in shares) \| shares	(93)
Unvested restricted stock, beginning balance (in shares) \| shares	12,100
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	$ 4.43
Weighted average grant date fair value, granted (in dollars per share) \| $ / shares	2.97
Weighted average grant date fair value, vested (in dollars per share) \| $ / shares	4.49
Weighted average grant date fair value, forfeited (in dollars per share) \| $ / shares	5.54
Weighted average grant date fair value, unvested restricted stock, ending balance (in dollars per share) \| $ / shares	$ 3.89

Share-Based Compensation - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of restricted stock, vested	$ 12
Unrecognized compensation expense	$ 40
Share-based compensation expense, weighted average period for recognition	2 years 2 months 19 days
Stock option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense, weighted average period for recognition	1 year 4 months 20 days
Fair value method used	Black-Scholes option pricing model
Unrecognized compensation expense	$ 11
Stock option \| Management
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, award vesting period	3 years
Stock option \| Management \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period	7 years
Stock option \| Management \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period	10 years
Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, award vesting period	3 years
Fair value method used	Monte Carlo simulation
Performance Share Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance share units maximum payout percentage	0.00%
Performance Share Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance share units maximum payout percentage	200.00%
Performance Share Units \| Management
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%
Terms of award	less than zero
Performance Share Units \| Management \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR component percentage performance share units	0.00%
Operational component percentage performance share ufnits	0.00%
Performance Share Units \| Management \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR component percentage performance share units	100.00%
Operational component percentage performance share ufnits	100.00%
Cash Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, award vesting period	3 years

Share-Based Compensation - Equity-Classified Valuation Table (Details) - Stock option	3 Months Ended
	Mar. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected option life – years	6 years
Volatility	65.61%
Risk-free interest rate	2.47%
Dividend yield	0.00%

Share-Based Compensation - Stock Option Activity Table (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, beginning balance (in shares options)	18,096
Granted (in shares options)	1,000
Exercised (in shares options)	0
Expired (in shares options)	(87)
Forfeited (in shares options)	(79)
Outstanding, ending balance (in shares options)	18,930	18,096
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted average exercise price, beginning (in dollars per share)	$ 7.20
Weighted average exercise price, granted (in dollars per share)	2.97
Weighted average exercise price, exercised (in dollars per share)	0.00
Weighted average exercise price, expired (in dollars per share)	11.23
Weighted average exercise price, forfeited (in dollars per share)	5.45
Weighted average exercise price, ending (in dollars per share)	$ 6.97	$ 7.20
Weighted average contract life, outstanding (in years)	7 years 10 days	7 years 1 month 24 days
Aggregate intrinsic value, outstanding, beginning balance	$ 0
Aggregate intrinsic value, exercised	0
Aggregate intrinsic value, outstanding, ending balance	$ 0	$ 0
Exercisable (in shares options)	13,355
Weighted average exercise price, exercisable (in dollars per share)	$ 8.23
Weighted average contract life, exercisable (in years)	6 years 3 months 29 days
Aggregate intrinsic value, exercisable	$ 0

Share-Based Compensation - Equity-Classified Compensation Table (Details) - Restricted stock and stock options - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 8	$ 11
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	6	7
Oil and natural gas properties
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	1	2
Oil, natural gas and NGL production expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	1	2
Exploration expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 0	$ 0

Share-Based Compensation - Liability Classified Valuation Table (Details) - 2017 Awards - Performance Share Units	3 Months Ended
	Mar. 31, 2019
Grant Date Assumptions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	80.65%
Risk-free interest rate	1.54%
Dividend yield	0.00%
Reporting Period Assumptions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	66.62%
Risk-free interest rate	2.41%
Dividend yield	0.00%

Share-Based Compensation - Performance Share Unit Breakout (Details) - USD ($) $ in Millions	Mar. 31, 2019	Jan. 01, 2018
Performance Share Units \| Award Year 2019, Payable 2020, 2021 and 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units	5,359,249
Fair Value	$ 17	$ 16
Vested Liability	$ 0
Performance Share Units \| Award Year 2018, Payable 2020 and 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units	2,639,765
Fair Value	$ 8	8
Vested Liability	$ 0
Performance Share Units \| Award Year 2017, Payable 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units	1,217,774
Fair Value	$ 4	8
Vested Liability	$ 2
Cash Restricted Stock Units \| Award Year 2018, Payable 2020 and 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units	9,732,557
Fair Value	$ 30	$ 29
Vested Liability	$ 0

Share-Based Compensation - Liability-Classified Compensation Table (Details) - Performance Share Units - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 14	$ 1
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	9	1
Oil and natural gas properties
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	1	0
Oil, natural gas and NGL production expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	3	0
Exploration expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1	$ 0

Other Operating Expenses - Narrative (Details) - Wildhorse Resource Development Corporation $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Business Acquisition [Line Items]
Acquisition related costs	$ 23
Severance expense	$ 38

Derivative and Hedging Activities - Derivative Instruments Table (Details) MMBbls in Millions, $ in Millions, MMBTU in Trillions	3 Months Ended	12 Months Ended
	Mar. 31, 2019 USD ($) MMBTU MMBbls	Dec. 31, 2017 MMBTU MMBbls	Dec. 31, 2018 USD ($)
Derivative [Line Items]
Derivative assets (liabilities), at fair value, net	$ (3)		$ 282
Energy related derivative
Derivative [Line Items]
Derivative assets (liabilities), at fair value, net	$ (3)		282
Energy related derivative \| Oil
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| MMBbls	37	27
Derivative assets (liabilities), at fair value, net	$ (15)		260
Energy related derivative \| Oil \| Fixed-price swaps
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| MMBbls	21	12
Derivative assets (liabilities), at fair value, net	$ (31)		157
Energy related derivative \| Oil \| Collars
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| MMBbls	6	8
Derivative assets (liabilities), at fair value, net	$ 24		98
Energy related derivative \| Oil \| Call swaptions
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| MMBbls	2
Derivative assets (liabilities), at fair value, net	$ (7)
Energy related derivative \| Oil \| Put options
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| MMBbls	2
Derivative assets (liabilities), at fair value, net	$ (5)
Energy related derivative \| Oil \| Basis protection swaps
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| MMBbls	6	7
Derivative assets (liabilities), at fair value, net	$ 4		5
Energy related derivative \| Natural Gas
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure \| MMBTU	871	966
Derivative assets (liabilities), at fair value, net	$ 5		15
Energy related derivative \| Natural Gas \| Fixed-price swaps
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure \| MMBTU	594	623
Derivative assets (liabilities), at fair value, net	$ 21		26
Energy related derivative \| Natural Gas \| Three-way collars
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure \| MMBTU	66	88
Derivative assets (liabilities), at fair value, net	$ 3		1
Energy related derivative \| Natural Gas \| Collars
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure \| MMBTU	28	55
Derivative assets (liabilities), at fair value, net	$ 0		(3)
Energy related derivative \| Natural Gas \| Call options
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure \| MMBTU	39	44
Derivative assets (liabilities), at fair value, net	$ 0		0
Energy related derivative \| Natural Gas \| Call swaptions
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure \| MMBTU	106	106
Derivative assets (liabilities), at fair value, net	$ (18)		(9)
Energy related derivative \| Natural Gas \| Basis protection swaps
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure \| MMBTU	38	50
Derivative assets (liabilities), at fair value, net	$ (1)		0
Future Natural Gas Prices \| Energy related derivative \| Utica Shale
Derivative [Line Items]
Derivative assets (liabilities), at fair value, net	$ 7		$ 7

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative, fair value, net	$ (3)	$ 282
Energy related derivative
Derivatives, Fair Value [Line Items]
Derivative, fair value, net	(3)	282
Not designated as hedging instrument \| Commodity contract
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(3)	282
Derivative liability, fair value, gross asset	0	0
Derivative, fair value, net	(3)	282
Short-term derivative asset \| Not designated as hedging instrument \| Commodity contract
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	69	306
Derivative asset, fair value, gross liability	(51)	(104)
Derivative, fair value, net	18	202
Long-term derivative asset \| Not designated as hedging instrument \| Commodity contract
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	61	117
Derivative asset, fair value, gross liability	(13)	(41)
Derivative, fair value, net	48	76
Short-term derivative liability \| Not designated as hedging instrument \| Commodity contract
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(112)	(107)
Derivative liability, fair value, gross asset	51	104
Derivative, fair value, net	(61)	(3)
Long-term derivative liability \| Not designated as hedging instrument \| Commodity contract
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(28)	(41)
Derivative liability, fair value, gross asset	13	41
Derivative, fair value, net	(15)	0
Future Natural Gas Prices \| Short-term derivative asset \| Not designated as hedging instrument \| Energy related derivative
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	7	7
Derivative asset, fair value, gross liability	0	0
Derivative, fair value, net	$ 7	$ 7

Derivative and Hedging Activities - Oil, Natural Gas and NGL Revenues Table (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Losses on undesignated oil, natural gas and NGL derivatives

$ (301)

$ (117)

Oil, natural gas and NGL sales

2,196

2,524

^[1]

Losses on terminated cash flow hedges

(10)

Oil, natural gas and NGL sales | Commodity contract | Not designated as hedging instrument

Losses on undesignated oil, natural gas and NGL derivatives

(291)

(107)

Oil, natural gas and NGL revenues

1,230

1,360

AOCI Attributable to Parent, Net of Tax [Roll Forward]

$ 929

$ 1,243

^[1]

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Derivative and Hedging Actitities - Marketing Revenues Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative [Line Items]
Revenues	$ 1,230	$ 1,360
Losses on undesignated oil, natural gas and NGL derivatives	(301)	(117)
Marketing, Gathering And Compression \| Other contract
Derivative [Line Items]
Losses on undesignated oil, natural gas and NGL derivatives	(2)	0
Marketing
Derivative [Line Items]
Revenues	1,143	1,089
Losses on undesignated oil, natural gas and NGL derivatives	(2)
Revenues	1,233	1,246
Marketing \| Marketing, Gathering And Compression
Derivative [Line Items]
Revenues	$ 1,235	$ 1,246

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

AOCI, after tax, beginning of period

$ (23)

Losses reclassified to income, after tax

$ 10

^[1],[2]

AOCI, after tax, end of period

(13)

Cash flow hedging

AOCI Attributable to Parent, Net of Tax [Roll Forward]

AOCI, before tax, beginning of period

(80)

(114)

AOCI, after tax, beginning of period

(23)

(57)

Losses reclassified to income, before tax

Losses reclassified to income, after tax

AOCI, before tax, end of period

(70)

(104)

AOCI, after tax, end of period

$ (13)

$ (47)

[1]	Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative assets (liabilities), at fair value, net	$ (3)	$ 282
Commodity contract
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	116	422
Derivative Liability	(126)	(147)
Energy related derivative
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative assets (liabilities), at fair value, net	(3)	282
Energy related derivative \| Future Natural Gas Prices \| Utica Shale
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset		7
Derivative assets (liabilities), at fair value, net	7	7
Fair Value, Inputs, Level 1
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 \| Commodity contract
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 \| Energy related derivative \| Future Natural Gas Prices \| Utica Shale
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset		0
Fair Value, Inputs, Level 2
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative assets (liabilities), at fair value, net	(13)	188
Fair Value, Inputs, Level 2 \| Commodity contract
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	89	319
Derivative Liability	(102)	(131)
Fair Value, Inputs, Level 2 \| Energy related derivative \| Future Natural Gas Prices \| Utica Shale
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset		0
Fair Value, Inputs, Level 3
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative assets (liabilities), at fair value, net	10	94
Fair Value, Inputs, Level 3 \| Commodity contract
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	27	103
Derivative Liability	(24)	(16)
Derivative assets (liabilities), at fair value, net	3	87	$ (24)	$ (15)
Fair Value, Inputs, Level 3 \| Energy related derivative \| Future Natural Gas Prices \| Utica Shale
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset		7
Derivative assets (liabilities), at fair value, net	$ 7	$ 7	$ 0	$ 0

Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative assets (liabilities), at fair value, net, beginning of period	$ 282
Derivative assets (liabilities), at fair value, net, end of period	(3)
Energy related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative assets (liabilities), at fair value, net, beginning of period	282
Derivative assets (liabilities), at fair value, net, end of period	(3)
Fair Value, Inputs, Level 3
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative assets (liabilities), at fair value, net, beginning of period	94
Derivative assets (liabilities), at fair value, net, end of period	10
Fair Value, Inputs, Level 3 \| Oil, natural gas and NGL sales
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Gains (loses) included in earnings	(88)	$ (8)
Change in unrealized gains (losses) related to assets still held at reporting date	(84)	(10)
Fair Value, Inputs, Level 3 \| Commodity contract
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative assets (liabilities), at fair value, net, beginning of period	87	(15)
Gains (loses) included in earnings	(88)	(8)
Settlements	4	(1)
Derivative assets (liabilities), at fair value, net, end of period	3	(24)
Future Natural Gas Prices \| Utica Shale \| Energy related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative assets (liabilities), at fair value, net, beginning of period	7
Derivative assets (liabilities), at fair value, net, end of period	7
Future Natural Gas Prices \| Utica Shale \| Fair Value, Inputs, Level 3 \| Energy related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative assets (liabilities), at fair value, net, beginning of period	7	0
Gains (loses) included in earnings	0	0
Settlements	0	0
Derivative assets (liabilities), at fair value, net, end of period	$ 7	$ 0

Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) - Energy related derivative $ in Millions	Mar. 31, 2019 USD ($)
Oil
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Fair value, measurement with unobservable inputs reconciliations, recurring basis, asset value	$ 17
Natural Gas
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Fair value, measurement with unobservable inputs reconciliations, recurring basis, liability value	$ (14)
Measurement Input, Price Volatility [Member] \| Oil \| Weighted average
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.2244
Measurement Input, Price Volatility [Member] \| Oil \| Minimum
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.1258
Measurement Input, Price Volatility [Member] \| Oil \| Maximum
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.2661
Measurement Input, Price Volatility [Member] \| Natural Gas \| Weighted average
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.2011
Measurement Input, Price Volatility [Member] \| Natural Gas \| Minimum
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.1991
Measurement Input, Price Volatility [Member] \| Natural Gas \| Maximum
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Measurement input	0.5481

Derivative and Hedging Activities - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) day derivative $ / BTU	Mar. 31, 2019 USD ($) counterparty derivative
Derivative [Line Items]
Expected amount to be transferred of during the next 12 months		$ 34
Designated as Hedging Instrument
Derivative [Line Items]
Derivative, number of instruments held \| derivative	0	0
Credit Risk
Derivative [Line Items]
Number of counterparties in hedge facility \| counterparty		15
Disposal group, disposed of by sale, not discontinued operations \| Utica Shale \| Future Natural Gas Prices
Derivative [Line Items]
Disposal group, including discontinued operation, consideration	$ 100
Debt Iistrument, convertible, threshold trading days \| day	20
Debt instrument, convertible, threshold consecutive trading days \| day	30
2022 NYMEX Natural Gas \| Disposal group, disposed of by sale, not discontinued operations \| Utica Shale \| Future Natural Gas Prices
Derivative [Line Items]
Disposal group, including discontinued operation, consideration	$ 50
2022 NYMEX Natural Gas \| Disposal group, disposed of by sale, not discontinued operations \| Utica Shale \| Future Natural Gas Prices 2022
Derivative [Line Items]
Average sales prices \| $ / BTU	3.00
2022 NYMEX Natural Gas \| Disposal group, disposed of by sale, not discontinued operations \| Utica Shale \| Future Natural Gas Prices 2023
Derivative [Line Items]
Average sales prices \| $ / BTU	3.25

Investments - Narrative (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
JWH Midstream LLC (JWH)
Schedule of Equity Method Investments [Line Items]
Business acquisition, percent acquired	50.00%
Equity method investments	$ 17
FTS International, Inc.
Schedule of Equity Method Investments [Line Items]
Investment, ownership percentage	20.00%	29.00%
Investment, realized gain (loss)	$ 61
Number of shares sold (in shares)	4.3
Proceeds from sale of equity method investments	$ 74
Shares held (in shares)	22.0
FTS International, Inc. \| IPO
Schedule of Equity Method Investments [Line Items]
Investment, ownership percentage	24.00%
Investment, realized gain (loss)	$ 78

Restructuring and Other Termination Costs Narrative (Details) - USD ($)
$ in Millions

3 Months Ended

Jan. 30, 2018

Mar. 31, 2019

Mar. 31, 2018

^[1]

Restructuring Cost and Reserve [Line Items]

Restructuring and other termination costs, number of positions eliminated, period percent

13.00%

Restructuring Reserve [Roll Forward]

One-time termination benefits

$ 0

$ 38

Restructuring Reserve [Roll Forward]

$ 38

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Fair Value Measurements - Assets and Liabilities Table (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value, net asset (liability), total	$ (1)	$ (1)
Short-term derivative asset
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	43	50
Short-term derivative liability
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	(44)	(51)
Fair Value, Inputs, Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value, net asset (liability), total	(1)	(1)
Fair Value, Inputs, Level 1 \| Short-term derivative asset
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	43	50
Fair Value, Inputs, Level 1 \| Short-term derivative liability
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	(44)	(51)
Fair Value, Inputs, Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value, net asset (liability), total	0	0
Fair Value, Inputs, Level 2 \| Short-term derivative asset
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	0	0
Fair Value, Inputs, Level 2 \| Short-term derivative liability
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	0	0
Fair Value, Inputs, Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value, net asset (liability), total	0	0
Fair Value, Inputs, Level 3 \| Short-term derivative asset
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current assets	0	0
Fair Value, Inputs, Level 3 \| Short-term derivative liability
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other current liabilities	$ 0	$ 0

Condensed Consolidating Financial Information - Narrative (Details)	Mar. 31, 2019
Owned subsidiaries \| Senior notes
Condensed Financial Statements, Captions [Line Items]
Noncontrolling interest, ownership percentage by parent	100.00%

Condensed Consolidating Financial Information - Balance Sheets Table (Details) - USD ($)
$ in Millions

Mar. 31, 2019

Dec. 31, 2018

Mar. 31, 2018

^[1]

$ 8

$ 4

1,357

1,594

1,365

1,598

Oil and natural gas properties at cost, based on successful efforts accounting, net

13,767

9,712

1,156

1,091

14,939

10,818

Investments in subsidiaries and intercompany advances

333

319

16,637

12,735

2,930

2,887

2,930

2,887

9,167

7,341

402

374

9,569

7,715

EQUITY:

4,097

2,092

4,138

2,133

$ 1,942

16,637

12,735

Eliminations

(2)

(6,350)

(6,671)

(6,352)

(6,673)

Oil and natural gas properties at cost, based on successful efforts accounting, net

Investments in subsidiaries and intercompany advances

(310)

(8,020)

(3,257)

(14,682)

(9,930)

(2)

(6,350)

(6,671)

(6,352)

(6,673)

(310)

(310)

EQUITY:

(8,020)

(3,257)

(8,020)

(3,257)

Parent | Reportable legal entities

(14,682)

(9,930)

6,350

6,671

6,406

6,735

Oil and natural gas properties at cost, based on successful efforts accounting, net

Investments in subsidiaries and intercompany advances

347

5,692

3,248

12,445

10,009

521

523

521

523

7,775

7,341

7,827

7,394

EQUITY:

4,097

2,092

4,097

2,092

Guarantor Subsidiaries | Reportable legal entities

12,445

10,009

1,208

1,532

1,209

1,533

Oil and natural gas properties at cost, based on successful efforts accounting, net

9,673

9,664

1,077

1,091

10,766

10,770

Investments in subsidiaries and intercompany advances

245

293

2,328

14,548

12,605

2,203

2,365

6,350

6,671

8,553

9,036

303

321

303

321

EQUITY:

5,692

3,248

5,692

3,248

Non-Guarantor Subsidiaries | Reportable legal entities

14,548

12,605

102

Oil and natural gas properties at cost, based on successful efforts accounting, net

4,094

4,173

Investments in subsidiaries and intercompany advances

4,326

208

208

1,392

357

1,749

EQUITY:

2,328

2,369

$ 4,326

$ 51

[1]	Financial information for prior periods has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Condensed Consolidating Financial Information - Income Statements Table (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

$ 2,196

$ 2,524

^[1]

^[1],[2]

^[1]

103

^[1]

^[1]

^[1]

519

459

^[1],[2]

^[1],[2]

^[1]

2,378

2,482

^[1]

(182)

^[1]

(161)

(162)

^[1]

(1)

139

^[1]

(1)

^[1]

(153)

(24)

^[1]

(335)

^[1]

(314)

^[1]

Net income attributable to noncontrolling interests

(21)

^[2],[3]

(1)

^[3]

(21)

^[1]

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

^[3]

(11)

^[3]

Eliminations

277

(180)

277

(180)

277

(180)

Net income attributable to noncontrolling interests

277

(180)

277

(180)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

277

(180)

Parent | Reportable legal entities

(154)

(162)

(177)

179

(331)

(331)

(310)

Net income attributable to noncontrolling interests

(21)

(21)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

(21)

Guarantor Subsidiaries | Reportable legal entities

2,117

2,519

435

457

2,208

2,479

(91)

139

(1)

(100)

(86)

139

(177)

179

Net income attributable to noncontrolling interests

(177)

179

(177)

179

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

(167)

189

Non-Guarantor Subsidiaries | Reportable legal entities

170

(91)

(12)

(1)

(13)

(104)

(4)

Net income attributable to noncontrolling interests

(100)

(1)

(100)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

(100)

Oil, natural gas and NGL | Eliminations

929

1,243

^[1]

Oil, natural gas and NGL | Parent | Reportable legal entities

Oil, natural gas and NGL | Guarantor Subsidiaries | Reportable legal entities

Oil, natural gas and NGL | Non-Guarantor Subsidiaries | Reportable legal entities

850

1,238

1,233

1,246

^[1]

1,233

1,246

1,230

1,268

^[1]

Marketing | Eliminations

Marketing | Parent | Reportable legal entities

Marketing | Guarantor Subsidiaries | Reportable legal entities

1,233

1,246

Marketing | Non-Guarantor Subsidiaries | Reportable legal entities

1,230

1,268

Oil, natural gas and NGL and Marketing

Oil, natural gas and NGL and Marketing | Eliminations

2,162

2,489

^[1]

Oil, natural gas and NGL and Marketing | Parent | Reportable legal entities

Oil, natural gas and NGL and Marketing | Guarantor Subsidiaries | Reportable legal entities

Oil, natural gas and NGL and Marketing | Non-Guarantor Subsidiaries | Reportable legal entities

2,083

2,484

^[1]

Other | Eliminations

Other | Parent | Reportable legal entities

Other | Guarantor Subsidiaries | Reportable legal entities

Other | Non-Guarantor Subsidiaries | Reportable legal entities

Oil, natural gas and NGL production

Oil, natural gas and NGL production | Eliminations

132

147

^[1]

Oil, natural gas and NGL production | Parent | Reportable legal entities

Oil, natural gas and NGL production | Guarantor Subsidiaries | Reportable legal entities

Oil, natural gas and NGL production | Non-Guarantor Subsidiaries | Reportable legal entities

117

147

Oil, natural gas and NGL gathering, processing and transportation

Oil, natural gas and NGL gathering, processing and transportation | Eliminations

274

356

^[1]

Oil, natural gas and NGL gathering, processing and transportation | Parent | Reportable legal entities

Oil, natural gas and NGL gathering, processing and transportation | Guarantor Subsidiaries | Reportable legal entities

Oil, natural gas and NGL gathering, processing and transportation | Non-Guarantor Subsidiaries | Reportable legal entities

269

355

Exploration | Eliminations

^[1]

Exploration | Parent | Reportable legal entities

Exploration | Guarantor Subsidiaries | Reportable legal entities

Exploration | Non-Guarantor Subsidiaries | Reportable legal entities

$ 4

$ 0

[1]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[2]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.
[3]	Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting. See Note 1.

Condensed Consolidating Financial Information - Information Statements of Cash Flows Tables (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Sep. 30, 2017

^[1]

$ 456

$ 588

^[1]

(515)

(420)

^[1]

(353)

^[1]

Proceeds from divestitures of proved and unproved properties

(6)

(17)

^[1]

319

^[1]

(9)

(3)

^[1]

Net Cash Provided By (Used In) Investing Activities

142

(856)

^[1]

3,572

2,904

^[1]

(3,136)

(3,485)

^[1]

(1)

$ 0

(23)

^[1]

(8)

(6)

Net Cash Provided By (Used In) Financing Activities

404

(610)

^[1]

Net increase (decrease) in cash and cash equivalents

(1)

^[1]

^[1]

^[1]

Eliminations

(1)

(4)

Proceeds from divestitures of proved and unproved properties

Net Cash Provided By (Used In) Investing Activities

(25)

Net Cash Provided By (Used In) Financing Activities

(25)

Net increase (decrease) in cash and cash equivalents

(29)

(2)

(3)

Parent | Reportable legal entities

(2)

(32)

Proceeds from divestitures of proved and unproved properties

Net Cash Provided By (Used In) Investing Activities

3,449

2,904

(3,026)

(3,485)

(1)

(23)

(7)

Net Cash Provided By (Used In) Financing Activities

(393)

530

(1)

(49)

Net increase (decrease) in cash and cash equivalents

(1)

Guarantor Subsidiaries | Reportable legal entities

421

509

(406)

(420)

(381)

Proceeds from divestitures of proved and unproved properties

(6)

(17)

319

(6)

(3)

Net Cash Provided By (Used In) Investing Activities

142

(772)

(1)

(2)

Net Cash Provided By (Used In) Financing Activities

352

(528)

351

(530)

Net increase (decrease) in cash and cash equivalents

Non-Guarantor Subsidiaries | Reportable legal entities

(109)

Proceeds from divestitures of proved and unproved properties

(3)

Net Cash Provided By (Used In) Investing Activities

(84)

123

(110)

(1)

(4)

Net Cash Provided By (Used In) Financing Activities

(2)

(6)

Net increase (decrease) in cash and cash equivalents

(1)