Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2019

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 1-13726

CHESAPEAKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



Oklahoma			73-1395733
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)
6100 North Western Avenue,	Oklahoma City,	Oklahoma	73118
(Address of principal executive offices)			(Zip Code)
		(405)	848-8000
(Registrant’s telephone number, including area code)



Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock, par value $0.01	CHK	New York Stock Exchange
6.625% Senior Notes due 2020	CHK20A	New York Stock Exchange
6.875% Senior Notes due 2020	CHK20	New York Stock Exchange
6.125% Senior Notes due 2021	CHK21	New York Stock Exchange
5.375% Senior Notes due 2021	CHK21A	New York Stock Exchange
4.875% Senior Notes due 2022	CHK22	New York Stock Exchange
5.75% Senior Notes due 2023	CHK23	New York Stock Exchange
4.5% Cumulative Convertible Preferred Stock	CHK Pr D	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ☒ Accelerated Filer ☐ Non-accelerated Filer ☐

Smaller Reporting Company ☐ Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of July 31, 2019, there were 1,634,513,223 shares of our $0.01 par value common stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2019



	PART I. FINANCIAL INFORMATION	Page
Item 1.	Condensed Consolidated Financial Statements
	Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018	3
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2019 and 2018	5
	Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2019 and 2018	6
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018	7
	Condensed Consolidated Statements of Stockholders’ Equity for the Three and Six Months Ended June 30, 2019 and 2018	9
	Notes to the Condensed Consolidated Financial Statements
	Note 1. Basis of Presentation and Summary of Significant Accounting Policies	10
	Note 2. Change in Accounting Principle	12
	Note 3. Oil and Natural Gas Property Transactions	25
	Note 4. Capitalized Exploratory Well Costs	27
	Note 5. Earnings per Share	27
	Note 6. Debt	28
	Note 7. Contingencies and Commitments	31
	Note 8. Other Liabilities	33
	Note 9. Leases	34
	Note 10. Revenue Recognition	36
	Note 11. Income Taxes	40
	Note 12. Share-Based Compensation	41
	Note 13. Derivative and Hedging Activities	44
	Note 14. Investments	50
	Note 15. Other Operating Expenses	50
	Note 16. Restructuring and Other Termination Costs	50
	Note 17. Fair Value Measurements	51
	Note 18. Condensed Consolidating Financial Information	51
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	60
	Liquidity and Capital Resources	61
	Results of Operations for the Three and Six Months Ended June 30, 2019 and 2018	66
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	75
Item 4.	Controls and Procedures	79
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	80
Item 1A.	Risk Factors	80
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	80
Item 3.	Defaults Upon Senior Securities	80
Item 4.	Mine Safety Disclosures	81
Item 5.	Other Information	81
Item 6.	Exhibits	82
Signatures		84

Table of Contents

PART I. FINANCIAL INFORMATION


ITEM 1.	Condensed Consolidated Financial Statements

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2019			December 31, 2018
	($ in millions)
CURRENT ASSETS:
Cash and cash equivalents ($2 and $1 attributable to our VIE)	$	4		$	4
Accounts receivable, net	1,021			1,247
Short-term derivative assets	224			209
Other current assets	135			138
Total Current Assets	1,384			1,598
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on successful efforts accounting:
Proved oil and natural gas properties ($755 and $755 attributable to our VIE)	29,675			25,407
Unproved properties	2,210			1,561
Other property and equipment	1,808			1,721
Total Property and Equipment, at Cost	33,693			28,689
Less: accumulated depreciation, depletion and amortization (($710) and ($707) attributable to our VIE)	(18,860		)	(17,886		)
Property and equipment held for sale, net	12			15
Total Property and Equipment, Net	14,845			10,818
LONG-TERM ASSETS:
Long-term derivative assets	63			76
Other long-term assets	248			243
TOTAL ASSETS	$	16,540		$	12,735

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (Continued)

(Unaudited)



	June 30, 2019			December 31, 2018
	($ in millions)
CURRENT LIABILITIES:
Accounts payable	$	611		$	763
Current maturities of long-term debt, net	—			381
Accrued interest	157			141
Short-term derivative liabilities	22			3
Other current liabilities ($1 and $2 attributable to our VIE)	1,430			1,599
Total Current Liabilities	2,220			2,887
LONG-TERM LIABILITIES:
Long-term debt, net	9,701			7,341
Long-term derivative liabilities	3			—
Asset retirement obligations, net of current portion	181			155
Other long-term liabilities	205			219
Total Long-Term Liabilities	10,090			7,715
CONTINGENCIES AND COMMITMENTS (Note 7)
EQUITY:
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 5,603,458 shares outstanding	1,671			1,671
Common stock, $0.01 par value, 3,000,000,000 and 2,000,000,000 shares authorized: 1,634,486,189 and 913,715,512 shares issued	16			9
Additional paid-in capital	16,380			14,378
Accumulated deficit	(13,835		)	(13,912		)
Accumulated other comprehensive loss	(5		)	(23		)
Less: treasury stock, at cost; 5,607,556 and 3,246,553 common shares	(36		)	(31		)
Total Chesapeake Stockholders’ Equity	4,191			2,092
Noncontrolling interests	39			41
Total Equity	4,230			2,133
TOTAL LIABILITIES AND EQUITY	$	16,540		$	12,735

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018*			2019			2018*
	($ in millions except per share data)
REVENUES AND OTHER:
Oil, natural gas and NGL	$	1,454		$	982		$	2,383		$	2,225
Marketing	916			1,273			2,149			2,519
Total Revenues	2,370			2,255			4,532			4,744
Other	15			16			30			32
Gains on sales of assets	1			18			20			37
Total Revenues and Other	2,386			2,289			4,582			4,813
OPERATING EXPENSES:
Oil, natural gas and NGL production	166			138			298			285
Oil, natural gas and NGL gathering, processing and transportation	271			340			545			696
Production taxes	40			26			74			57
Exploration	15			20			39			101
Marketing	940			1,292			2,170			2,560
General and administrative	89			105			192			192
Restructuring and other termination costs	—			—			—			38
Provision for legal contingencies, net	3			4			3			9
Depreciation, depletion and amortization	580			471			1,099			930
Impairments	1			54			2			64
Other operating (income) expense	3			(1		)	64			(1		)
Total Operating Expenses	2,108			2,449			4,486			4,931
INCOME (LOSS) FROM OPERATIONS	278			(160		)	96			(118		)
OTHER INCOME (EXPENSE):
Interest expense	(175		)	(155		)	(336		)	(317		)
Gains (losses) on investments	(23		)	—			(24		)	139
Other income	18			57			27			56
Total Other Expense	(180		)	(98		)	(333		)	(122		)
INCOME (LOSS) BEFORE INCOME TAXES	98			(258		)	(237		)	(240		)
Income tax benefit	—			(9		)	(314		)	(9		)
NET INCOME (LOSS)	98			(249		)	77			(231		)
Net income attributable to noncontrolling interests	—			—			—			(1		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	98			(249		)	77			(232		)
Preferred stock dividends	(23		)	(23		)	(46		)	(46		)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	75		$	(272	)	$	31		$	(278	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.05		$	(0.30	)	$	0.02		$	(0.31	)
Diluted	$	0.05		$	(0.30	)	$	0.02		$	(0.31	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	1,628			909			1,505			908
Diluted	1,628			909			1,505			908

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

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018*			2019		2018*
	($ in millions)
NET INCOME (LOSS)	$	98	$	(249	)	$	77	$	(231	)
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments^(a)	—		—			—		—
Reclassification of losses on settled derivative instruments^(a)	8		7			18		17
Other Comprehensive Income	8		7			18		17
COMPREHENSIVE INCOME (LOSS)	106		(242		)	95		(214		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—		—			—		(1		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	106	$	(242	)	$	95	$	(215	)

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

___________________________________________


(a)	Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2019			2018*
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$	77		$	(231	)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	1,099			930
Deferred income tax benefit	(314		)	(9		)
Derivative losses, net	30			368
Cash payments on derivative settlements, net	15			(55		)
Stock-based compensation	17			18
Gains on sales of assets	(20		)	(37		)
Impairments	2			64
Exploration	25			73
(Gains) losses on investments	18			(139		)
Other	41			(93		)
Changes in assets and liabilities	(137		)	62
Net Cash Provided By Operating Activities	853			951
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(1,070		)	(928		)
Business combination, net	(353		)	—
Acquisitions of proved and unproved properties	(17		)	(102		)
Proceeds from divestitures of proved and unproved properties	82			384
Additions to other property and equipment	(18		)	(5		)
Proceeds from sales of other property and equipment	4			74
Proceeds from sales of investments	—			74
Net Cash Used In Investing Activities	(1,372		)	(503		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	6,416			6,118
Payments on revolving credit facility borrowings	(5,452		)	(6,393		)
Cash paid to purchase debt	(381		)	—
Extinguishment of other financing	—			(122		)
Cash paid for preferred stock dividends	(46		)	(46		)
Distributions to noncontrolling interest owners	(2		)	(3		)
Other	(16		)	(4		)
Net Cash Provided By (Used In) Financing Activities	519			(450		)
Net decrease in cash and cash equivalents	—			(2		)
Cash and cash equivalents, beginning of period	4			5
Cash and cash equivalents, end of period	$	4		$	3

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

(Unaudited)



Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
	Six Months Ended June 30,
	2019			2018*
	($ in millions)
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	$	296		$	316
Income taxes paid, net of refunds received	$	(5	)	$	(7	)

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Common stock issued for business combination	$	2,037		$	—
Change in senior notes exchanged	$	35		$	—
Change in accrued drilling and completion costs	$	17		$	109
Change in divested proved and unproved properties	$	(125	)	$	—

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

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018*			2019			2018*
	($ in millions)
PREFERRED STOCK:
Balance, beginning and end of period	$	1,671		$	1,671		$	1,671		$	1,671
COMMON STOCK:
Balance, beginning of period	16			9			9			9
Common shares issued for WildHorse Merger	—			—			7			—
Balance, end of period	16			9			16			9
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period	16,392			14,419			14,378			14,437
Common shares issued for WildHorse Merger	—			—			2,030			—
Stock-based compensation	11			12			18			17
Dividends on preferred stock	(23		)	(23		)	(46		)	(46		)
Balance, end of period	16,380			14,408			16,380			14,408
ACCUMULATED DEFICIT:
Balance, beginning of period	(13,933		)	(14,121		)	(13,912		)	(14,130		)
Net income (loss) attributable to Chesapeake	98			(249		)	77			(232		)
Cumulative effect of accounting change	—			—			—			(8		)
Balance, end of period	(13,835		)	(14,370		)	(13,835		)	(14,370		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(13		)	(47		)	(23		)	(57		)
Hedging activity	8			7			18			17
Balance, end of period	(5		)	(40		)	(5		)	(40		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(36		)	(32		)	(31		)	(31		)
Purchase of 81,093, 17,046, 2,620,566, and 1,468,524 shares for company benefit plans	(1		)	—			(7		)	(4		)
Release of 148,767, 114,450, 259,563 and 389,857 shares from company benefit plans	1			1			2			4
Balance, end of period	(36		)	(31		)	(36		)	(31		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY	4,191			1,647			4,191			1,647
NONCONTROLLING INTERESTS:
Balance, beginning of period	41			43			41			44
Net income attributable to noncontrolling interests	—			—			—			1
Distributions to noncontrolling interest owners	(2		)	(1		)	(2		)	(3		)
Balance, end of period	39			42			39			42
TOTAL EQUITY	$	4,230		$	1,689		$	4,230		$	1,689

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

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.	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 and six months ended June 30, 2019 (the “Current Quarter” and the “Current Period”, respectively) and the three and six months ended June 30, 2018 (the “Prior Quarter” and the “Prior Period”, respectively). 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 first quarter of 2019, we voluntarily changed our method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods 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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


2.	Change in Accounting Principle

In the first quarter of 2019, we voluntarily changed our method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods 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.

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Three Months Ended June 30, 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	$	1,454		$	—		$	1,454
Marketing	916			—			916
Total Revenues	2,370			—			2,370
Other	—			15			15
Gains on sales of assets	—			1			1
Total Revenues and Other	2,370			16			2,386
OPERATING EXPENSES:
Oil, natural gas and NGL production	166			—			166
Oil, natural gas and NGL gathering, processing and transportation	271			—			271
Production taxes	40			—			40
Exploration	—			15			15
Marketing	940			—			940
General and administrative	76			13			89
Provisions for legal contingencies, net	3			—			3
Depreciation, depletion and amortization	419			161			580
Impairments	1			—			1
Gain on sale of oil and natural gas properties	(1		)	1			—
Other operating expense	4			(1		)	3
Total Operating Expenses	1,919			189			2,108
INCOME FROM OPERATIONS	451			(173		)	278
OTHER INCOME (EXPENSE):
Interest expense	(131		)	(44		)	(175		)
Losses on investments	(23		)	—			(23		)
Other income	13			5			18
Total Other Expense	(141		)	(39		)	(180		)
INCOME BEFORE INCOME TAXES	310			(212		)	98
Income tax benefit	—			—			—
NET INCOME	310			(212		)	98
Net income attributable to noncontrolling interests	—			—			—
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	310			(212		)	98
Preferred stock dividends	(23		)	—			(23		)
Earnings allocated to participating securities	(1		)	1			—
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS	$	286		$	(211	)	$	75
EARNINGS PER COMMON SHARE:
Basic	$	0.18		$	(0.13	)	$	0.05
Diluted	$	0.18		$	(0.13	)	$	0.05
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	1,628			—			1,628
Diluted	1,628			—			1,628

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Three Months Ended June 30, 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	$	982		$	—		$	982
Marketing	1,273			—			1,273
Total Revenues	2,255			—			2,255
Other	—			16			16
Gains on sales of assets	—			18			18
Total Revenues and Other	2,255			34			2,289
OPERATING EXPENSES:
Oil, natural gas and NGL production	138			—			138
Oil, natural gas and NGL gathering, processing and transportation	340			—			340
Production taxes	26			—			26
Exploration	—			20			20
Marketing	1,292			—			1,292
General and administrative	91			14			105
Provision for legal contingencies, net	4			—			4
Depreciation, depletion and amortization	290			181			471
Impairments	46			8			54
Other operating income	(2		)	1			(1		)
Total Operating Expenses	2,225			224			2,449
INCOME (LOSS) FROM OPERATIONS	30			(190		)	(160		)
OTHER INCOME (EXPENSE):
Interest expense	(117		)	(38		)	(155		)
Other income (expense)	62			(5		)	57
Total Other Expense	(55		)	(43		)	(98		)
LOSS BEFORE INCOME TAXES	(25		)	(233		)	(258		)
Income tax benefit	(9		)	—			(9		)
NET LOSS	(16		)	(233		)	(249		)
Net income attributable to noncontrolling interests	(1		)	1			—
NET LOSS ATTRIBUTABLE TO CHESAPEAKE	(17		)	(232		)	(249		)
Preferred stock dividends	(23		)	—			(23		)
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$	(40	)	$	(232	)	$	(272	)
LOSS PER COMMON SHARE:
Basic	$	(0.04	)	$	(0.26	)	$	(0.30	)
Diluted	$	(0.04	)	$	(0.26	)	$	(0.30	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	909			—			909
Diluted	909			—			909

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Six Months Ended June 30, 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	$	2,383		$	—		$	2,383
Marketing	2,149			—			2,149
Total Revenues	4,532			—			4,532
Other	—			30			30
Gains on sales of assets	—			20			20
Total Revenues and Other	4,532			50			4,582
OPERATING EXPENSES:
Oil, natural gas and NGL production	298			—			298
Oil, natural gas and NGL gathering, processing and transportation	545			—			545
Production taxes	74			—			74
Exploration	—			39			39
Marketing	2,170			—			2,170
General and administrative	164			28			192
Provision for legal contingencies	3			—			3
Depreciation, depletion and amortization	776			323			1,099
Gain on sale of oil and natural gas properties	(10		)	10			—
Impairments	2			—			2
Other operating expense	64			—			64
Total Operating Expenses	4,086			400			4,486
INCOME FROM OPERATIONS	446			(350		)	96
OTHER INCOME (EXPENSE):
Interest expense	(266		)	(70		)	(336		)
Losses on investments	(24		)	—			(24		)
Other income	20			7			27
Total Other Expense	(270		)	(63		)	(333		)
INCOME (LOSS) BEFORE INCOME TAXES	176			(413		)	(237		)
Income tax benefit	(314		)	—			(314		)
NET INCOME	490			(413		)	77
Net income attributable to noncontrolling interests	(1		)	1			—
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	489			(412		)	77
Preferred stock dividends	(46		)	—			(46		)
Earnings allocated to participating securities	(3		)	3			—
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS	$	440		$	(409	)	$	31
EARNINGS PER COMMON SHARE:
Basic	$	0.29		$	(0.27	)	$	0.02
Diluted	$	0.29		$	(0.27	)	$	0.02
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	1,505			—			1,505
Diluted	1,505			—			1,505

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Six Months Ended June 30, 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	$	2,225		$	—		$	2,225
Marketing	2,519			—			2,519
Total Revenues	4,744			—			4,744
Other	—			32			32
Gains on sales of assets	—			37			37
Total Revenues and Other	4,744			69			4,813
OPERATING EXPENSES:
Oil, natural gas and NGL production	285			—			285
Oil, natural gas and NGL gathering, processing and transportation	696			—			696
Production taxes	57			—			57
Exploration	—			101			101
Marketing	2,560			—			2,560
General and administrative	163			29			192
Restructuring and other termination costs	38			—			38
Provision for legal contingencies, net	9			—			9
Depreciation, depletion and amortization	576			354			930
Impairments	46			18			64
Other operating (income) expense	6			(7		)	(1		)
Total Operating Expenses	4,436			495			4,931
INCOME (LOSS) FROM OPERATIONS	308			(426		)	(118		)
OTHER INCOME (EXPENSE):
Interest expense	(240		)	(77		)	(317		)
Gains on investments	139			—			139
Other income	62			(6		)	56
Total Other Expense	(39		)	(83		)	(122		)
INCOME (LOSS) BEFORE INCOME TAXES	269			(509		)	(240		)
Income tax benefit	(9		)	—			(9		)
NET INCOME (LOSS)	278			(509		)	(231		)
Net income attributable to noncontrolling interests	(2		)	1			(1		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	276			(508		)	(232		)
Preferred stock dividends	(46		)	—			(46		)
Earnings allocated to participating securities	(2		)	2			—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	228		$	(506	)	$	(278	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.25		$	(0.56	)	$	(0.31	)
Diluted	$	0.25		$	(0.56	)	$	(0.31	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	908			—			908
Diluted	908			—			908

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Three Months Ended June 30, 2019
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	Under Full Cost		Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
NET INCOME	$	310	$	(212	)	$	98
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments	—		—			—
Reclassification of losses on settled derivative instruments	8		—			8
Other Comprehensive Income	8		—			8
COMPREHENSIVE INCOME	318		(212		)	106
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—		—			—
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	318	$	(212	)	$	106



	Three Months Ended June 30, 2018
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
NET LOSS	$	(16	)	$	(233	)	$	(249	)
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments	—			—			—
Reclassification of losses on settled derivative instruments	7			—			7
Other Comprehensive Income	7			—			7
COMPREHENSIVE LOSS	(9		)	(233		)	(242		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(1		)	1			—
COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE	$	(10	)	$	(232	)	$	(242	)



	Six Months Ended June 30, 2019
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
NET INCOME (LOSS)	$	490		$	(413	)	$	77
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments	—			—			—
Reclassification of losses on settled derivative instruments	18			—			18
Other Comprehensive Income	18			—			18
COMPREHENSIVE INCOME	508			(413		)	95
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(1		)	1			—
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	507		$	(412	)	$	95

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Six Months Ended June 30, 2018
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
NET INCOME (LOSS)	$	278		$	(509	)	$	(231	)
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments	—			—			—
Reclassification of losses on settled derivative instruments	17			—			17
Other Comprehensive Income	17			—			17
COMPREHENSIVE INCOME (LOSS)	295			(509		)	(214		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(2		)	1			(1		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	293		$	(508	)	$	(215	)

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)




	Six Months Ended June 30, 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	$	490		$	(413	)	$	77
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	776			323			1,099
Deferred income tax benefit	(314		)	—			(314		)
Derivative losses, net	30			—			30
Cash receipts on derivative settlements, net	15			—			15
Stock-based compensation	17			—			17
Gains on sales of assets	—			(20		)	(20		)
Impairments	2			—			2
Exploration	—			25			25
Losses on investments	18			—			18
Other	31			10			41
Changes in assets and liabilities	(107		)	(30		)	(137		)
Net Cash Provided By Operating Activities	958			(105		)	853
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(1,104		)	34			(1,070		)
Business combination, net	(353		)	—			(353		)
Acquisitions of proved and unproved properties	(88		)	71			(17		)
Proceeds from divestitures of proved and unproved properties	82			—			82
Additions to other property and equipment	(18		)	—			(18		)
Proceeds from sales of other property and equipment	4			—			4
Net Cash Used In Investing Activities	(1,477		)	105			(1,372		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	6,416			—			6,416
Payments on revolving credit facility borrowings	(5,452		)	—			(5,452		)
Cash paid to purchase debt	(381		)	—			(381		)
Cash paid for preferred stock dividends	(46		)	—			(46		)
Distributions to noncontrolling interest owners	(2		)	—			(2		)
Other	(16		)	—			(16		)
Net Cash Provided By Financing Activities	519			—			519
Net increase in cash and cash equivalents	—			—			—
Cash and cash equivalents, beginning of period	4			—			4
Cash and cash equivalents, end of period	$	4		$	—		$	4

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)




	Six Months Ended June 30, 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 (LOSS)	$	278		$	(509	)	$	(231	)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	576			354			930
Deferred income tax benefit	(9		)	—			(9		)
Derivative losses, net	368			—			368
Cash payments on derivative settlements, net	(55		)	—			(55		)
Stock-based compensation	18			—			18
Gains on sales of assets	—			(37		)	(37		)
Impairments	46			18			64
Exploration	—			73			73
Gains on investments	(139		)	—			(139		)
Other	(86		)	(7		)	(93		)
Changes in assets and liabilities	94			(32		)	62
Net Cash Provided By Operating Activities	1,091			(140		)	951
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(979		)	51			(928		)
Acquisitions of proved and unproved properties	(191		)	89			(102		)
Proceeds from divestitures of proved and unproved properties	384			—			384
Additions to other property and equipment	(5		)	—			(5		)
Proceeds from sales of other property and equipment	74			—			74
Proceeds from sales of investments	74			—			74
Net Cash Used In Investing Activities	(643		)	140			(503		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	6,118			—			6,118
Payments on revolving credit facility borrowings	(6,393		)	—			(6,393		)
Extinguishment of other financing	(122		)	—			(122		)
Cash paid for preferred stock dividends	(46		)	—			(46		)
Distributions to noncontrolling interest owners	(3		)	—			(3		)
Other	(4		)	—			(4		)
Net Cash Used In Financing Activities	(450		)	—			(450		)
Net decrease in cash and cash equivalents	(2		)	—			(2		)
Cash and cash equivalents, beginning of period	5			—			5
Cash and cash equivalents, end of period	$	3		$	—		$	3

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Three Months Ended June 30, 2019
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
PREFERRED STOCK:
Balance, beginning and end of period	$	1,671		$	—		$	1,671
COMMON STOCK:
Balance, beginning and end of period	16			—			16
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period	16,392			—			16,392
Stock-based compensation	11			—			11
Dividends on preferred stock	(23		)	—			(23		)
Balance, end of period	16,380			—			16,380
ACCUMULATED DEFICIT:
Balance, beginning of period	(15,481		)	1,548			(13,933		)
Net income attributable to Chesapeake	310			(212		)	98
Balance, end of period	(15,171		)	1,336			(13,835		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(13		)	—			(13		)
Hedging activity	8			—			8
Balance, end of period	(5		)	—			(5		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(36		)	—			(36		)
Purchase of 81,093 shares for company benefit plans	(1		)	—			(1		)
Release of 148,767 shares from company benefit plans	1			—			1
Balance, end of period	(36		)	—			(36		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY	2,855			1,336			4,191
NONCONTROLLING INTERESTS:
Balance, beginning of period	122			(81		)	41
Net income attributable to noncontrolling interests	—			—			—
Distributions to noncontrolling interest owners	(2		)	—			(2		)
Balance, end of period	120			(81		)	39
TOTAL EQUITY	$	2,975		$	1,255		$	4,230

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Three Months Ended June 30, 2018
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	Under Full Cost			Successful Efforts 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
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period	14,419			—			14,419
Stock-based compensation	12			—			12
Dividends on preferred stock	(23		)	—			(23		)
Balance, end of period	14,408			—			14,408
ACCUMULATED DEFICIT:
Balance, beginning of period	(16,240		)	2,119			(14,121		)
Net loss attributable to Chesapeake	(17		)	(232		)	(249		)
Balance, end of period	(16,257		)	1,887			(14,370		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(47		)	—			(47		)
Hedging activity	7			—			7
Balance, end of period	(40		)	—			(40		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(32		)	—			(32		)
Purchase of 17,046 shares for company benefit plans	—			—			—
Release of 114,450 shares from company benefit plans	1			—			1
Balance, end of period	(31		)	—			(31		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT)	(240		)	1,887			1,647
NONCONTROLLING INTERESTS:
Balance, beginning of period	123			(80		)	43
Net income attributable to noncontrolling interests	1			(1		)	—
Distributions to noncontrolling interest owners	(1		)	—			(1		)
Balance, end of period	123			(81		)	42
TOTAL EQUITY (DEFICIT)	$	(117	)	$	1,806		$	1,689

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Six Months Ended June 30, 2019
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	Under Full Cost			Successful Efforts 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	18			—			18
Dividends on preferred stock	(46		)	—			(46		)
Balance, end of period	16,380			—			16,380
ACCUMULATED DEFICIT:
Balance, beginning of period	(15,660		)	1,748			(13,912		)
Net income attributable to Chesapeake	489			(412		)	77
Balance, end of period	(15,171		)	1,336			(13,835		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(23		)	—			(23		)
Hedging activity	18			—			18
Balance, end of period	(5		)	—			(5		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(31		)	—			(31		)
Purchase of 2,620,566 shares for company benefit plans	(7		)	—			(7		)
Release of 259,563 shares from company benefit plans	2			—			2
Balance, end of period	(36		)	—			(36		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY	2,855			1,336			4,191
NONCONTROLLING INTERESTS:
Balance, beginning of period	123			(82		)	41
Net income attributable to noncontrolling interests	(1		)	1			—
Distributions to noncontrolling interest owners	(2		)	—			(2		)
Balance, end of period	120			(81		)	39
TOTAL EQUITY	$	2,975		$	1,255		$	4,230

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(Unaudited)



	Six Months Ended June 30, 2018
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	Under Full Cost			Successful Efforts Adjustment			Under Successful Efforts
	($ in millions)
PREFERRED STOCK:
Balance, beginning and end of period	$	1,671		$	—		$	1,671
COMMON STOCK:
Balance, beginning and end of period	9			—			9
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period	14,437			—			14,437
Stock-based compensation	17			—			17
Dividends on preferred stock	(46		)	—			(46		)
Balance, end of period	14,408			—			14,408
ACCUMULATED DEFICIT:
Balance, beginning of period	(16,525		)	2,395			(14,130		)
Net income (loss) attributable to Chesapeake	276			(508		)	(232		)
Cumulative effect of accounting change	(8		)	—			(8		)
Balance, end of period	(16,257		)	1,887			(14,370		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(57		)	—			(57		)
Hedging activity	17			—			17
Balance, end of period	(40		)	—			(40		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(31		)	—			(31		)
Purchase of 1,468,524 shares for company benefit plans	(4		)	—			(4		)
Release of 389,857 shares from company benefit plans	4			—			4
Balance, end of period	(31		)	—			(31		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT)	(240		)	1,887			1,647
NONCONTROLLING INTERESTS:
Balance, beginning of period	124			(80		)	44
Net income attributable to noncontrolling interests	2			(1		)	1
Distributions to noncontrolling interest owners	(3		)	—			(3		)
Balance, end of period	123			(81		)	42
TOTAL EQUITY (DEFICIT)	$	(117	)	$	1,806		$	1,689

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(Unaudited)


3.	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).

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(Unaudited)

We included in our condensed consolidated statements of operations revenues of $308 million, direct operating expenses of $369 million and other expenses of $54 million related to the WildHorse business for the period from February 1, 2019 to June 30, 2019.

Pro Forma Financial Information

The following unaudited pro forma financial information for the six months ended June 30, 2019 and three and six months ended 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 June 30,			Six Months Ended June 30,
	2018			2019		2018
	($ in millions except per share data)
Revenues	$	2,403		$	4,574	$	5,085
Net income (loss) available to common stockholders	$	(332	)	$	16	$	(360	)
Earnings per common share:
Basic	$	(0.20	)	$	0.01	$	(0.22	)
Diluted	$	(0.20	)	$	0.01	$	(0.22	)

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 Prior Period, we sold portions of our acreage, producing properties and other related property and equipment in the Mid-Continent, including our Mississippian Lime assets, for approximately $491 million, subject to certain customary closing adjustments. Included in the sales were approximately 238,500 net acres and interests in approximately 3,200 wells. Also, in the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we received proceeds of approximately $56 million, $5 million, $82 million and $23 million, respectively, subject to customary closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.

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(Unaudited)


4.	Capitalized Exploratory Well Costs

A summary of the changes in our capitalized well costs for the Current Period 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	9
Divestitures and other	—
Reclassifications to proved properties	(18		)
Charges to exploration expense	—
Balance as of June 30	$	27

As of June 30, 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.


5.	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 June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
	(in millions)
Common stock equivalent of our preferred stock outstanding	60	60	60	60
Common stock equivalent of our convertible senior notes outstanding	146	146	146	146
Participating securities	1	1	1	1

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(Unaudited)


6.	Debt

Our long-term debt consisted of the following as of June 30, 2019 and December 31, 2018:



	June 30, 2019					December 31, 2018
	Principal Amount		Carrying Amount			Principal Amount			Carrying Amount
	($ in millions)
Floating rate senior notes due 2019	—		—			380			380
6.625% senior notes due 2020	208		208			437			437
6.875% senior notes due 2020	93		93			227			227
6.125% senior notes due 2021	167		167			548			548
5.375% senior notes due 2021	127		127			267			267
4.875% senior notes due 2022	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		1,292			1,300			1,291
5.5% convertible senior notes due 2026^(b)	1,250		882			1,250			866
7.5% senior notes due 2026	400		400			400			400
8.00% senior notes due 2026	919		884			—			—
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	1,372		1,372			419			419
BVL revolving credit facility^(a)	686		686			—			—
Debt issuance costs	—		(53		)	—			(53		)
Interest rate derivatives	—		1			—			1
Total debt, net	10,161		9,701			8,168			7,722
Less current maturities of long-term debt, net	—		—			(381		)	(381		)
Total long-term debt, net	$	10,161	$	9,701		$	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%. 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 third quarter of 2019.

Chesapeake Revolving Credit Facility

Our Chesapeake revolving credit facility matures in September 2023 and the current aggregate commitment of the lenders and borrowing base under the facility is $3.0 billion. The revolving credit facility provides for an accordion feature, pursuant to which the aggregate commitments thereunder may be increased to up to $4.0 billion from time to time, subject to agreement of the participating lenders and certain other customary conditions. Scheduled borrowing base redeterminations will continue to occur semiannually. Our borrowing base was reaffirmed in the Current Quarter, and our next borrowing base redetermination is scheduled for the fourth quarter of 2019. As of June 30, 2019, we had

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(Unaudited)

outstanding borrowings of $1.372 billion under the Chesapeake revolving credit facility and had used $54 million of the Chesapeake revolving credit facility for various letters of credit.

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 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 June 30, 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 commitments and a borrowing base of $1.3 billion. The BVL revolving credit facility matures in December 2021. Scheduled borrowing base redeterminations occur on at least a semi-annual basis, primarily on the basis of estimated proved reserves. The borrowing base was reaffirmed in the Current Quarter of 2019 and the next scheduled redetermination is in the fourth quarter of 2019. As of June 30, 2019, we had outstanding borrowings of $686 million. 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 an ABR, Eurodollar rate or LIBOR at BVL’s election, plus an applicable margin (ranging from 0.50%-1.50% per annum for ABR

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(Unaudited)

loans, 1.50%-2.50% per annum for Eurodollar loans and 1.50%-2.50% per annum for LIBOR 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 June 30, 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.

Chesapeake Senior Notes

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



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

We may redeem some or all of the 2026 notes at any time prior to March 15, 2022 at a price equal to 100% of the principal amount of the notes to be redeemed plus a “make-whole” premium. At any time prior to March 15, 2022, we also may redeem up to 35% of the aggregate principal amount of each series of notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a specified redemption price. In addition, we may redeem some or all of the 2026 notes at any time on or after March 15, 2022 at the redemption prices in accordance with the terms of the notes, the indenture and supplemental indenture governing the notes. These senior notes are unsecured obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes are jointly and severally, fully and unconditionally guaranteed by all of our wholly owned subsidiaries that guarantee the Chesapeake revolving credit facility and certain other unsecured senior notes. We accounted for the exchange as a modification to existing debt and no gain or loss was recognized.

In the Current Quarter, 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.

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.

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(Unaudited)

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:



	June 30, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			($ in millions)
Short-term debt (Level 1)	$	—	$	—	$	381	$	379
Long-term debt (Level 1)	$	3,321	$	3,126	$	3,495	$	3,173
Long-term debt (Level 2)	$	6,380	$	6,060	$	3,846	$	3,644


7.	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, an individual lawsuit was filed in the U.S. District Court of Kansas against us and other defendants. The lawsuit generally alleged that, from 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 lawsuit sought 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 lawsuit. This matter was resolved in connection with the resolution of the related Oklahoma cases for an insignificant amount of money.

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 alleged 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 sought rescission of the Merger or rescissory damages and, in each case, attorney's fees, costs and interest. The lawsuits were voluntarily dismissed by the plaintiffs on July 10, 2019.

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.

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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 condensed 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:



	June 30, 2019
	($ in millions)
Remainder of 2019	$	415
2020	789
2021	691
2022	590
2023	477
2024 – 2035	2,451
Total	$	5,413

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.

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8.	Other Liabilities

Other current liabilities as of June 30, 2019 and December 31, 2018 are detailed below:



	June 30, 2019		December 31, 2018
	($ in millions)
Revenues and royalties due others	$	434	$	687
Accrued drilling and production costs	441		258
Joint interest prepayments received	60		73
VPP deferred revenue^(a)	57		59
Accrued compensation and benefits	133		202
Other accrued taxes	126		108
Other	179		212
Total other current liabilities	$	1,430	$	1,599

Other long-term liabilities as of June 30, 2019 and December 31, 2018 are detailed below:



	June 30, 2019		December 31, 2018
	($ in millions)
VPP deferred revenue^(a)	$	36	$	63
Unrecognized tax benefits	54		53
Other	115		103
Total other long-term liabilities	$	205	$	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.

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9.	Leases

We are a lessee under various agreements for compressors, office space, vehicles and other equipment. As of June 30, 2019, these leases have remaining terms ranging from one month to 7.5 years. Certain of our lease agreements include options to renew the lease, terminate the lease early or purchase the underlying asset at the end of the lease. We determine the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when we are reasonably certain to exercise the option. The company’s vehicles are the only leases with renewal options that we are reasonably certain to exercise. The renewals are reflected in the ROU asset and lease liability balances.

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

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

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

The following table presents our ROU assets and lease liabilities as of June 30, 2019.



	Financing		Operating
	($ in millions)
ROU assets	$	22	$	25

Lease liabilities:
Current lease liabilities	$	9	$	12
Long-term lease liabilities	13		15
Total lease liabilities	$	22	$	27

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



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Lease cost:	($ in millions)
Amortization of ROU assets	$	2	$	4
Interest on lease liability	—		1
Finance lease cost	2		5
Operating lease cost	10		17
Short-term lease cost	26		48
Total lease cost^(a)	$	38	$	70

Other information:
Operating cash outflows from finance lease	$	—	$	1
Operating cash outflows from operating leases	$	3	$	5
Investing cash outflows from operating leases	$	33	$	60
Financing cash outflows from finance lease	$	2	$	4


Weighted-average remaining lease term - finance lease			2.50 years
Weighted-average remaining lease term - operating leases			4.50 years
Weighted-average discount rate - finance lease			7.50		%
Weighted-average discount rate - operating leases			4.83		%

____________________________________________


(a)	Includes $33 million and $60 million of capitalized lease costs for the Current Quarter and the Current Period, respectively.

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



	June 30, 2019
	Financing Lease			Operating Leases
	($ in millions)
Remainder of 2019	$	5		$	8
2020	10			8
2021	10			3
2022	—			2
2023	—			2
Thereafter	—			7
Total lease payments	25			30
Less imputed interest	(3		)	(3		)
Present value of lease liabilities	22			27
Less current maturities	(9		)	(12		)
Present value of lease liabilities, less current maturities	$	13		$	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


10.	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 Period 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 Period did not have a material impact on our consolidated financial statements.

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



	Three Months Ended June 30, 2019
	Oil			Natural Gas			NGL			Total
	($ in millions)
Marcellus	$	—		$	198		$	—		$	198
Haynesville	—			164			—			164
Eagle Ford	349			37			20			406
Brazos Valley	199			9			5			213
Powder River Basin	102			18			8			128
Mid-Continent	50			10			10			70
Revenue from contracts with customers	700			436			43			1,179
Gains on oil, natural gas and NGL derivatives	86			189			—			275
Oil, natural gas and NGL revenue	$	786		$	625		$	43		$	1,454

Marketing revenue from contracts with customers	$	614		$	162		$	48		$	824
Other marketing revenue	78			15			—			93
Losses on oil, natural gas and NGL derivatives	—			(1		)	—			(1		)
Marketing revenue	$	692		$	176		$	48		$	916

	Three Months Ended June 30, 2018
	Oil			Natural Gas			NGL			Total
	($ in millions)
Marcellus	$	—		$	169		$	—		$	169
Haynesville	1			198			—			199
Eagle Ford	390			42			46			478
Powder River Basin	52			11			9			72
Mid-Continent	62			15			12			89
Utica	62			103			61			226
Revenue from contracts with customers	567			538			128			1,233
Losses on oil, natural gas and NGL derivatives	(202		)	(35		)	(14		)	(251		)
Oil, natural gas and NGL revenue	$	365		$	503		$	114		$	982

Marketing revenue from contracts with customers	732			235			102			1,069
Other marketing revenue	145			59			—			204
Marketing revenue	$	877		$	294		$	102		$	1,273

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	Six Months Ended June 30, 2019
	Oil			Natural Gas			NGL			Total
	($ in millions)
Marcellus	$	—		$	500		$	—		$	500
Haynesville	—			365			—			365
Eagle Ford	680			85			66			831
Brazos Valley	320			13			7			340
Powder River Basin	176			43			18			237
Mid-Continent	90			25			21			136
Revenue from contracts with customers	1,266			1,031			112			2,409
Gains (losses) on oil, natural gas and NGL derivatives	(173		)	147			—			(26		)
Oil, natural gas and NGL revenue	$	1,093		$	1,178		$	112		$	2,383

Marketing revenue from contracts with customers	$	1,227		$	575		$	165		$	1,967
Other marketing revenue	150			35			—			185
Losses on oil, natural gas and NGL derivatives	—			(3		)	—			(3		)
Marketing revenue	$	1,377		$	607		$	165		$	2,149

	Six Months Ended June 30, 2018
	Oil			Natural Gas			NGL			Total
	($ in millions)
Marcellus	$	—		$	462		$	—		$	462
Haynesville	2			409			—			411
Eagle Ford	750			84			85			919
Powder River Basin	95			23			17			135
Mid-Continent	138			47			30			215
Utica	119			219			113			451
Revenue from contracts with customers	1,104			1,244			245			2,593
Losses on oil, natural gas and NGL derivatives	(288		)	(67		)	(13		)	(368		)
Oil, natural gas and NGL revenue	$	816		$	1,177		$	232		$	2,225

Marketing revenue from contracts with customers	1,418			528			212			2,158
Other marketing revenue	262			99			—			361
Marketing revenue	$	1,680		$	627		$	212		$	2,519

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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 June 30, 2019 and December 31, 2018 are detailed below:



	June 30, 2019			December 31, 2018
	($ in millions)
Oil, natural gas and NGL sales	$	682		$	976
Joint interest	289			211
Other	71			77
Allowance for doubtful accounts	(21		)	(17		)
Total accounts receivable, net	$	1,021		$	1,247

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11.	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 June 30, 2019. Such evidence limits our ability to consider various forms of subjective positive evidence, such as our projections for future growth and earnings. However, 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 June 30, 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. For the first quarter of 2019, 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 same 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 no income tax provision for the Current Quarter and an income tax benefit of $314 million for the Current Period. The benefit for the Current Period 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.

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12.	Share-Based Compensation

Our share-based compensation program consists of restricted stock, stock options, performance share units (PSUs) and cash restricted stock units (CRSUs) granted to employees and restricted stock granted to non-employee directors under our long-term incentive plans. The restricted stock and stock options are equity-classified awards and the PSUs and CRSUs are liability-classified awards.

Equity-Classified Awards

Restricted Stock. We grant restricted stock units to employees and non-employee directors. A summary of the changes in unvested restricted stock during the Current Period is presented below:



	Shares of Unvested Restricted Stock		Weighted Average Grant Date Fair Value Per Share
	(in thousands)
Unvested restricted stock as of January 1, 2019	11,858		$	4.43
Granted	5,364		$	2.85
Vested	(4,973	)	$	4.36
Forfeited	(1,027	)	$	3.67
Unvested restricted stock as of June 30, 2019	11,222		$	3.78

The aggregate intrinsic value of restricted stock that vested during the Current Period was approximately $14 million based on the stock price at the time of vesting.

As of June 30, 2019, there was approximately $30 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 2.01 years.

Stock Options. In the Current Period and the Prior Period, we granted members of management stock options that vest ratably over a three-year period. Each stock option award has an exercise price equal to the closing price of our common stock on the grant date. Outstanding options expire seven years to ten years from the date of grant.

We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method. Volatility assumptions are estimated based on the average historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account our dividend policy, over the expected life of the option. We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Period:



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

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



	Number of Shares Underlying Options		Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value^(a)
	(in thousands)					($ in millions)
Outstanding as of January 1, 2019	18,096		$	7.20	7.15	$	—
Granted	1,000		$	2.97
Exercised	—		$	—		$	—
Expired	(451	)	$	6.57
Forfeited	(554	)	$	3.82
Outstanding as of June 30, 2019	18,091		$	7.09	6.39	$	—
Exercisable as of June 30, 2019	13,030		$	8.29	5.59	$	—

___________________________________________


(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 June 30, 2019, there was $9 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, the Prior Quarter, the Current Period and the Prior Period:



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	($ in millions)
General and administrative expenses	$	9	$	10	$	15	$	17
Oil and natural gas properties	—		—		1		2
Oil, natural gas and NGL production expenses	1		1		2		3
Exploration expenses	—		—		—		—
Total restricted stock and stock option compensation	$	10	$	11	$	18	$	22

Liability-Classified Awards

Performance Share Units. In the Current Period and the Prior Period, 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.

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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	63.49	%
Risk-free interest rate	2.08	%
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%. For the 2019 award, EBITDA and capital expenditures will be adjusted for changes resulting from our conversion from the full cost method of accounting to the successful efforts method. The vested PSUs are settled in cash on each of the three annual vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the PSUs. The PSU liability will be adjusted quarterly, based on changes in our stock price and expected satisfaction of performance metrics, through the end of 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		June 30, 2019
	Units	Grant Date Fair Value		Fair Value		Vested Liability
		($ in millions)		($ in millions)
2019 PSU Awards:
Payable 2020, 2021 and 2022	4,887,868	$	15	$	12	$	—
2018 PSU Awards:
Payable 2020 and 2021	2,418,281	$	7	$	5	$	—
2017 PSU Awards:
Payable 2020	1,174,973	$	8	$	2	$	1
2018 CRSU Awards:
Payable 2020 and 2021	9,468,697	$	29	$	18	$	—

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019		2018
	($ in millions)
General and administrative expenses	$	(1	)	$	20	$	8	$	21
Oil and natural gas properties	—			1		1		1
Oil, natural gas and NGL production expenses	1			2		3		2
Exploration expenses	(1		)	1		—		1
Total liability-classified awards compensation	$	(1	)	$	24	$	12	$	25


13.	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 June 30, 2019 or December 31, 2018.

Oil, Natural Gas and NGL Derivatives

As of June 30, 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 or to increase the notional volumes of an existing fixed-price swap.

•

Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.


•	Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.

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The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of June 30, 2019 and December 31, 2018 are provided below:



	June 30, 2019				December 31, 2018
	Notional Volume	Fair Value			Notional Volume	Fair Value
		($ in millions)				($ in millions)
Oil (mmbbl):
Fixed-price swaps	24	$	64		12	$	157
Collars	5	27			8	98
Call swaptions	2	(5		)	—	—
Put options	2	(5		)	—	—
Basis protection swaps	4	6			7	5
Total oil	37	87			27	260
Natural gas (bcf):
Fixed-price swaps	505	176			623	26
Three-way collars	15	2			88	1
Collars	18	7			55	(3		)
Call options	33	—			44	—
Call swaptions	106	(10		)	106	(9		)
Basis protection swaps	20	—			50	—
Total natural gas	697	175			966	15
Contingent consideration:
Utica divestiture		—				7
Total estimated fair value		$	262			$	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.

In the Current Quarter, based on the unlikelihood of any payout occurring related to the contingent consideration, we determined the contingent consideration had no fair value and recognized a $7 million unrealized loss, which is included as a reduction in our gains on sales of assets in the condensed consolidated statement of operations.

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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 June 30, 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 June 30, 2019
Commodity Contracts:
Short-term derivative asset	$	250		$	(26	)	$	224
Long-term derivative asset	64			(1		)	63
Short-term derivative liability	(48		)	26			(22		)
Long-term derivative liability	(4		)	1			(3		)
Contingent Consideration:
Short-term derivative asset	—			—			—
Total derivatives	$	262		$	—		$	262

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, the Prior Quarter, the Current Period and the Prior Period are presented below:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	($ in millions)
Oil, natural gas and NGL revenues	$	1,179		$	1,233		$	2,409		$	2,593
Gains (losses) on undesignated oil, natural gas and NGL derivatives	283			(244		)	(8		)	(351		)
Losses on terminated cash flow hedges	(8		)	(7		)	(18		)	(17		)
Total oil, natural gas and NGL revenues	$	1,454		$	982		$	2,383		$	2,225

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
	($ in millions)
Marketing revenues	$	917		$	1,273	$	2,152		$	2,519
Losses on undesignated marketing natural gas derivatives	(1		)	—		(3		)	—
Total marketing revenues	$	916		$	1,273	$	2,149		$	2,519

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 June 30,
	2019						2018
	Before Tax			After Tax			Before Tax			After Tax
	($ in millions)
Balance, beginning of period	$	(70	)	$	(13	)	$	(104	)	(47		)
Losses reclassified to income	8			8			7			7
Balance, end of period	$	(62	)	$	(5	)	$	(97	)	$	(40	)



	Six Months Ended June 30,
	2019						2018
	Before Tax			After Tax			Before Tax			After Tax
	($ in millions)
Balance, beginning of period	$	(80	)	$	(23	)	$	(114	)	(57		)
Losses reclassified to income	18			18			17			17
Balance, end of period	$	(62	)	$	(5	)	$	(97	)	$	(40	)

The accumulated other comprehensive loss as of June 30, 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 June 30, 2019, we expect to transfer approximately $34 million of net loss included in accumulated other comprehensive income (loss) 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 June 30, 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

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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 June 30, 2019, no letters of credit or 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 June 30, 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 June 30, 2019
Derivative Assets (Liabilities):
Commodity assets	$	—	$	280		$	34		$	314
Commodity liabilities	—		(40		)	(12		)	(52		)
Utica divestiture contingent consideration	—		—			—			—
Total derivatives	$	—	$	240		$	22		$	262

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

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



	Commodity Derivatives			Utica Contingent Consideration
	($ in millions)
Balance, as of January 1, 2019	$	87		$	7
Total gains (losses) (realized/unrealized):
Included in earnings^(a)	(64		)	(7		)
Total purchases, issuances, sales and settlements:
Settlements	(1		)	—
Balance, as of June 30, 2019	$	22		$	—

Balance, as of January 1, 2018	$	(15	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings^(a)	(32		)	—
Total purchases, issuances, sales and settlements:
Settlements	2			—
Balance, as of June 30, 2018	$	(45	)	$	—

___________________________________________



(a)		Commodity Derivatives						Utica Contingent Consideration
		Commodity Derivatives						Utica Contingent Consideration
		2019			2018			2019			2018
		($ in millions)
	Total gains (losses) included in earnings for the period	$	(64	)	$	(32	)	$	(7	)	$	—
	Change in unrealized gains (losses) related to assets still held at reporting date	$	(66	)	$	(30	)	$	(7	)	$	—

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

The significant unobservable inputs for Level 3 derivative contracts include market volatility. Changes in market volatility impact the fair value measurement of our derivative contracts, which is based on an estimate derived from option models. For example, an increase or decrease in the forward prices and volatility of oil and natural gas prices decreases or increases the fair value of oil and natural gas derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of June 30, 2019:



Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value June 30, 2019
				($ in millions)
Oil trades	Oil price volatility curves	21.62% – 38.20%	27.79%	$	23
Natural gas trades	Natural gas price volatility curves	19.94% – 145.47%	33.18%	$	(1	)

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14.	Investments

In the Current Period in connection with the acquisition of WildHorse, we obtained a 50% membership interest in JWH Midstream LLC (JWH). The carrying value of our investment in JWH, which was being accounted for as an equity method investment, was approximately $17 million as of March 31, 2019. In the Current Quarter, we paid approximately $7 million to terminate our involvement in the partnership. This removed us from any future obligations related to this joint venture and, therefore, we impaired the full value of the investment and recognized approximately $24 million of impairment expense in the Current Quarter.

In the Prior Period, FTS International, Inc. (NYSE: FTSI) completed an initial public offering. Due to the offering, the ownership percentage of our equity method investment in FTSI decreased from approximately 29% to 24% and resulted in a gain of 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.


15.	Other Operating Expenses

In the Current Period, we recorded approximately $26 million of costs related to our acquisition of WildHorse which consisted of financial advisory fees, legal fees and travel and lodging expenses. In addition, we recorded approximately $38 million of severance expense as a result of the acquisition of WildHorse. A majority of the WildHorse executives and employees were terminated. These executives and employees were entitled to severance benefits in accordance with existing employment agreements.


16.	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 Period of approximately $38 million for one-time termination benefits.

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17.	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 June 30, 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 June 30, 2019
Financial Assets (Liabilities):
Other current assets	$	44		$	—	$	—	$	44
Other current liabilities	(45		)	—		—		(45		)
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.


18.	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 June 30, 2019 and December 31, 2018 and for the three and six months ended June 30, 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.

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CONDENSED CONSOLIDATING BALANCE SHEET

AS OF JUNE 30, 2019

($ in millions)



	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	9	$	1	$	2	$	(8	)	$	4
Other current assets	54		1,229		97		—			1,380
Intercompany receivable, net	6,321		—		—		(6,321		)	—
Total Current Assets	6,384		1,230		99		(6,329		)	1,384
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on successful efforts accounting, net	—		9,556		4,132		—			13,688
Other property and equipment, net	—		1,061		84		—			1,145
Property and equipment held for sale, net	—		12		—		—			12
Total Property and Equipment, Net	—		10,629		4,216		—			14,845
LONG-TERM ASSETS:
Other long-term assets	327		247		24		(287		)	311
Investments in subsidiaries and intercompany advances	5,982		2,338		—		(8,320		)	—
TOTAL ASSETS	$	12,693	$	14,444	$	4,339	$	(14,936	)	$	16,540

CURRENT LIABILITIES:
Current liabilities	$	137	$	1,841	$	250	$	(8	)	$	2,220
Intercompany payable, net	—		6,321		—		(6,321		)	—
Total Current Liabilities	137		8,162		250		(6,329		)	2,220
LONG-TERM LIABILITIES:
Long-term debt, net	8,311		—		1,390		—			9,701
Other long-term liabilities	54		300		322		(287		)	389
Total Long-Term Liabilities	8,365		300		1,712		(287		)	10,090
EQUITY:
Chesapeake stockholders’ equity	4,191		5,982		2,338		(8,320		)	4,191
Noncontrolling interests	—		—		39		—			39
Total Equity	4,191		5,982		2,377		(8,320		)	4,230
TOTAL LIABILITIES AND EQUITY	$	12,693	$	14,444	$	4,339	$	(14,936	)	$	16,540

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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

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2019

($ in millions)



	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	1,218	$	236		$	—		$	1,454
Marketing	—			916		—			—			916
Total Revenues	—			2,134		236			—			2,370
Other	—			15		—			—			15
Gains on sales of assets	—			1		—			—			1
Total Revenues and Other	—			2,150		236			—			2,386
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			138		28			—			166
Oil, natural gas and NGL gathering, processing and transportation	—			265		6			—			271
Production taxes	—			30		10			—			40
Exploration	—			16		(1		)	—			15
Marketing	—			940		—			—			940
General and administrative	—			65		24			—			89
Provision for legal contingencies, net	—			3		—			—			3
Depreciation, depletion and amortization	—			439		141			—			580
Impairments	—			1		—			—			1
Other operating expense	—			3		—			—			3
Total Operating Expenses	—			1,900		208			—			2,108
INCOME FROM OPERATIONS	—			250		28			—			278
OTHER INCOME (EXPENSE):
Interest income (expense)	(160		)	5		(20		)	—			(175		)
Losses on investments	—			—		(23		)	—			(23		)
Other income	—			16		2			—			18
Equity in net earnings of subsidiary	281			10		—			(291		)	—
Total Other Income (Expense)	121			31		(41		)	(291		)	(180		)
INCOME(LOSS) BEFORE INCOME TAXES	121			281		(13		)	(291		)	98
INCOME TAX (BENEFIT) EXPENSE	23			—		(23		)	—			—
NET INCOME	98			281		10			(291		)	98
Net income attributable to noncontrolling interests	—			—		—			—			—
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	98			281		10			(291		)	98
Other comprehensive income	—			8		—			—			8
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	98		$	289	$	10		$	(291	)	$	106

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2018

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	978		$	4		$	—	$	982
Marketing	—			1,273			—			—		1,273
Total Revenues	—			2,251			4			—		2,255
Other	—			16			—			—		16
Gains on sales of assets	—			18			—			—		18
Total Revenues and Other	—			2,285			4			—		2,289
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			138			—			—		138
Oil, natural gas and NGL gathering, processing and transportation	—			338			2			—		340
Production taxes	—			26			—			—		26
Exploration	—			20			—			—		20
Marketing	—			1,292			—			—		1,292
General and administrative	—			104			1			—		105
Provision for legal contingencies, net	—			4			—			—		4
Depreciation, depletion and amortization	—			470			1			—		471
Impairments	—			54			—			—		54
Other operating income	—			(1		)	—			—		(1		)
Total Operating Expenses	—			2,445			4			—		2,449
INCOME FROM OPERATIONS	—			(160		)	—			—		(160		)
OTHER INCOME (EXPENSE):
Interest expense	(155		)	—			—			—		(155		)
Other income	—			57			—			—		57
Equity in net earnings of subsidiary	(103		)	—			(1		)	104		—
Total Other Income (Expense)	(258		)	57			(1		)	104		(98		)
LOSS BEFORE INCOME TAXES	(258		)	(103		)	(1		)	104		(258		)
INCOME TAX BENEFIT	(9		)	—			—			—		(9		)
NET LOSS	(249		)	(103		)	(1		)	104		(249		)
Net (income) loss attributable to noncontrolling interests	—			(1		)	1			—		—
NET LOSS ATTRIBUTABLE TO CHESAPEAKE	(249		)	(104		)	—			104		(249		)
Other comprehensive income	—			7			—			—		7
COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE	$	(249	)	$	(97	)	$	—		$	104	$	(242	)

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2019

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	2,068		$	315		$	—		$	2,383
Marketing	—			2,149			—			—			2,149
Total Revenues	—			4,217			315			—			4,532
Other	—			30			—			—			30
Gains on sales of assets	—			20			—			—			20
Total Revenues and Other	—			4,267			315			—			4,582
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			255			43			—			298
Oil, natural gas and NGL gathering, processing and transportation	—			534			11			—			545
Production taxes	—			58			16			—			74
Exploration	—			36			3			—			39
Marketing	—			2,170			—			—			2,170
General and administrative	—			150			42			—			192
Provision for legal contingencies, net	—			3			—			—			3
Depreciation, depletion and amortization	—			874			225			—			1,099
Impairments	—			2			—			—			2
Other operating expense	—			26			38			—			64
Total Operating Expenses	—			4,108			378			—			4,486
INCOME (LOSS) FROM OPERATIONS	—			159			(63		)	—			96
OTHER INCOME (EXPENSE):
Interest income (expense)	(314		)	10			(32		)	—			(336		)
Losses on investments	—			—			(24		)	—			(24		)
Other income	—			25			2			—			27
Equity in net earnings of subsidiary	104			(90		)	—			(14		)	—
Total Other Expense	(210		)	(55		)	(54		)	(14		)	(333		)
INCOME (LOSS) BEFORE INCOME TAXES	(210		)	104			(117		)	(14		)	(237		)
INCOME TAX BENEFIT	(287		)	—			(27		)	—			(314		)
NET INCOME (LOSS)	77			104			(90		)	(14		)	77
Net income attributable to noncontrolling interests	—			—			—			—			—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	77			104			(90		)	(14		)	77
Other comprehensive income	—			18			—			—			18
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	77		$	122		$	(90	)	$	(14	)	$	95

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2018

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	2,216		$	9		$	—		$	2,225
Marketing	—			2,519			—			—			2,519
Total Revenues	—			4,735			9			—			4,744
Other	—			32			—			—			32
Gains on sales of assets	—			37			—			—			37
Total Revenues and Other	—			4,804			9			—			4,813
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			285			—			—			285
Oil, natural gas and NGL gathering, processing and transportation	—			693			3			—			696
Production taxes	—			57			—			—			57
Exploration	—			101			—			—			101
Marketing	—			2,560			—			—			2,560
General and administrative	—			191			1			—			192
Restructuring and other termination costs	—			38			—			—			38
Provision for legal contingencies, net	—			9			—			—			9
Depreciation, depletion and amortization	—			927			3			—			930
Impairments	—			64			—			—			64
Other operating income	—			(1		)	—			—			(1		)
Total Operating Expenses	—			4,924			7			—			4,931
INCOME (LOSS) FROM OPERATIONS	—			(120		)	2			—			(118		)
OTHER INCOME (EXPENSE):
Interest expense	(317		)	—			—			—			(317		)
Gains on investments	—			139			—			—			139
Other income	—			56			—			—			56
Equity in net earnings of subsidiary	76			1			(1		)	(76		)	—
Total Other Income (Expense)	(241		)	196			(1		)	(76		)	(122		)
INCOME (LOSS) BEFORE INCOME TAXES	(241		)	76			1			(76		)	(240		)
INCOME TAX BENEFIT	(9		)	—			—			—			(9		)
NET INCOME (LOSS)	(232		)	76			1			(76		)	(231		)
Net income attributable to noncontrolling interests	—			(1		)	—			—			(1		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(232		)	75			1			(76		)	(232		)
Other comprehensive income	—			17			—			—			17
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	(232	)	$	92		$	1		$	(76	)	$	(215	)

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2019

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	$	—		$	613		$	242		$	(2	)	$	853

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(805		)	(265		)	—			(1,070		)
Business combination, net	—			(381		)	28			—			(353		)
Acquisitions of proved and unproved properties	—			(17		)	—			—			(17		)
Proceeds from divestitures of proved and unproved properties	—			82			—			—			82
Additions to other property and equipment	—			(7		)	(11		)	—			(18		)
Other investing activities	—			4			—			—			4
Net Cash Used In Investing Activities	—			(1,124		)	(248		)	—			(1,372		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	6,119			—			297			—			6,416
Payments on revolving credit facility borrowings	(5,166		)	—			(286		)	—			(5,452		)
Cash paid to purchase debt	(381		)	—			—			—			(381		)
Cash paid for preferred stock dividends	(46		)	—			—			—			(46		)
Other financing activities	(12		)	(4		)	(4		)	2			(18		)
Intercompany advances, net	(515		)	515			—			—			—
Net Cash Provided By (Used In) Financing Activities	(1		)	511			7			2			519
Net increase (decrease) in cash and cash equivalents	(1		)	—			1			—			—
Cash and cash equivalents, beginning of period	4			1			1			(2		)	4
Cash and cash equivalents, end of period	$	3		$	1		$	2		$	(2	)	$	4

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2018

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities	$	88		$	866		$	5		$	(8	)	$	951

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(928		)	—			—			(928		)
Acquisitions of proved and unproved properties	—			(102		)	—			—			(102		)
Proceeds from divestitures of proved and unproved properties	—			384			—			—			384
Additions to other property and equipment	—			(5		)	—			—			(5		)
Other investing activities	—			148			—			—			148
Net Cash Used In Investing Activities	—			(503		)	—			—			(503		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	6,118			—			—			—			6,118
Payments on revolving credit facility borrowings	(6,393		)	—			—			—			(6,393		)
Cash paid for preferred stock dividends	(46		)	—			—			—			(46		)
Other financing activities	(2		)	(126		)	(7		)	6			(129		)
Intercompany advances, net	235			(237		)	2			—			—
Net Cash Used In Financing Activities	(88		)	(363		)	(5		)	6			(450		)
Net decrease in cash and cash equivalents	—			—			—			(2		)	(2		)
Cash and cash equivalents, beginning of period	5			1			2			(3		)	5
Cash and cash equivalents, end of period	$	5		$	1		$	2		$	(5	)	$	3

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ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion should be read together with the condensed consolidated financial statements included in Item 1 of Part I of this report and our Form 8-K dated May 9, 2019.

We are an independent exploration and production company engaged in the acquisition, exploration and development of properties to produce oil, natural gas and NGL from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in approximately 14,800 oil and natural gas wells. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas, the stacked pay in the Powder River Basin in Wyoming and the Anadarko Basin in northwestern Oklahoma. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana.

Our strategy is to create shareholder value through the development of our significant resource plays. We continue to focus on reducing debt, increasing cash provided by operating activities, improving margins through financial discipline and operating efficiencies and maintaining exceptional environmental and safety performance. To accomplish these goals, we intend to allocate our capital expenditures to projects we believe offer the highest return regardless of the commodity price environment, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our cost structure and our portfolio. Increasing our margins means not only increasing our absolute level of cash flows from operations, but also increasing our cash flows from operations generated per barrel of oil equivalent production. Our margins increased in the Current Quarter compared to the Prior Quarter, primarily due to a higher oil production mix. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation and general and administrative) through operational efficiencies, including but not limited to improving our production volumes from existing wells.

Looking into the remainder of 2019, we are confident in our ability to drive further competitive performance through the quality of our investments and our capital and operating discipline. We believe that the flexibility and efficiency of our capital program and cost structure and our continued focus on safety and environmental stewardship will provide opportunities to create value for our shareholders and us.

In 2019, our focus remains concentrated on four strategic priorities:


•	reduce total leverage to achieve long-term net debt/EBITDAX of 2x;


•	increase net cash provided by operating activities to fund capital expenditures;


•	improve margins through financial discipline and operating efficiencies; and


•	maintain industry leading environmental and safety performance.

During the Current Period, we changed our method of accounting for our oil and natural gas exploration and development activities from the full cost method to the successful efforts method of accounting. Financial information for all periods has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1 of the notes to our condensed consolidated financial statements included in Item 1 of this 10-Q for further discussion of the change in accounting principle.

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Overview

The transformation of Chesapeake over the past five years has been significant and our progress has continued in 2019. We believe our recent accomplishments and achievements have made our company stronger. Highlights include the following:

•

acquired 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, and the acquisition of WildHorse’s debt of $1.4 billion as of February 1, 2019. We anticipate the acquisition to materially increase our oil production and enhance our oil production mix as well as significantly reduce costs due to operational synergies that we believe the combined company will achieve. We expect that the WildHorse Merger will provide substantial cost savings with $200 million to $280 million in projected average annual savings, totaling $1 billion to $1.5 billion by 2023, due to operational and capital efficiencies as a result of Chesapeake’s significant expertise with unconventional assets and technical and operational excellence;


•	extended our debt maturity profile by privately exchanging approximately $884 million aggregate principal amount of our existing senior notes due in 2020 and 2021 for approximately $919 million aggregate principal amount of new 8.00% Senior Notes due 2026; and


•	improved our cost structure in the Current Period compared to the Prior Period by reducing combined production, general and administrative, and gathering, processing and transportation expenses by $138 million, or 13%. The primary driver in the reduction is lower gathering, processing and transportation expenses due to certain 2018 divestitures.

Liquidity and Capital Resources

Liquidity Overview

Our ability to grow, make capital expenditures and service our debt depends primarily upon the prices we receive for the oil, natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically, oil and natural gas prices have been volatile, and may be subject to wide fluctuations in the future. A decline in oil, natural gas and NGL prices could negatively affect the amount of cash we generate and have available for capital expenditures and debt service and could have a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we can economically produce or provide as collateral to our credit facility lenders. Other risks and uncertainties that could affect our liquidity include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks and our ability to meet financial covenants in our financing agreements.

Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facilities, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.

As of both June 30, 2019 and December 31, 2018, we had a cash balance of $4 million. As of June 30, 2019 and December 31, 2018, we had a net working capital deficit of $836 million and $1.289 billion, respectively. As of June 30, 2019, we had no debt due in the next 12 months and as of December 31, 2018, our working capital deficit included $380 million of debt due in the next 12 months. As of June 30, 2019, we had $1.574 billion of borrowing capacity available under our Chesapeake revolving credit facility, with outstanding borrowings of $1.372 billion and $54 million utilized for various letters of credit. In addition, as of June 30, 2019, we had $614 million of borrowing capacity available under our BVL revolving credit facility with outstanding borrowings of $686 million. See Note 6 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of our debt obligations, including principal and carrying amounts of our notes.

Although we have taken measures to mitigate liquidity concerns over the next 12 months, there can be no assurance that these measures will be sufficient for periods beyond the next 12 months. We closely monitor the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our revolving credit facilities. Furthermore, our ability to generate operating cash flow in the current commodity price environment, sell assets, access capital markets or take any other action to improve our liquidity and manage our debt is subject to the risks discussed above and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate or control at this time.

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Derivative and Hedging Activities

Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of our exposure to adverse market price changes, we have entered into various derivative instruments. Our oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas and NGL, allow us to better predict the total revenue we expect to receive.

We utilize various oil, natural gas and NGL derivative instruments to protect a portion of our cash flow against downside risk. As of July 31, 2019, including July and August derivative contracts that have settled, approximately 85% of our remaining forecasted oil, natural gas and NGL production revenue was hedged, including 79% and 78% of our remaining forecasted 2019 oil and natural gas production average prices of $59.38 per barrel and $2.83 per mcf, respectively.



Oil Derivatives^(a)
Year	Type of Derivative Instrument	Notional Volume	Average NYMEX Price
		(mmbbls)
2019	Swaps	14	$60.20
2019	Two-way collars	3	$58.00/$67.75
2019	Basis protection swaps	4	$5.85
2019	Puts	1	$54.31
2020	Swaps	13	$59.21
2020	Two-way collars	2	$65.00/$83.25
2020	Call swaptions^(b)	2	$63.15
Natural Gas Derivatives^(a)
Year	Type of Derivative Instrument	Notional Volume	Average NYMEX Price
		(bcf)
2019	Swaps	255	$2.84
2019	Two-way collars	18	$2.75/$2.91
2019	Three-way collars	15	$2.50/$2.80/$3.10
2019	Calls	11	$12.00
2019	Basis protection swaps	29	($0.34)
2020	Swaps	265	$2.76
2020	Basis protection swaps	15	($0.19)
2020	Call swaptions^(c)	106	$2.77
2020	Calls	22	$12.00
2021	Call swaptions^(c)	15	$2.80
2022	Call swaptions^(c)	15	$2.80

___________________________________________


(a)	Includes amounts settled in July and August 2019.


(b)	Call swaptions expire December 31, 2019.


(c)	Call swaptions expire December 23, 2019, December 23, 2020 and December 23, 2021.

See Note 13 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of derivatives and hedging activities.

Debt

We are committed to reducing total leverage to achieve long-term net debt/EBITDAX of 2x. To accomplish this goal, we intend to allocate our capital expenditures to projects we believe offer the highest return regardless of the commodity price environment, to deploy leading drilling and completion technology throughout our portfolio, and to

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take advantage of acquisition and divestiture opportunities to strengthen our cost structure and our portfolio. Increasing our margins means not only increasing our absolute level of cash flows from operations, but also increasing our cash flows from operations generated per barrel of oil equivalent production. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation and general and administrative), improve our production volumes from existing wells, and achieve additional operating and capital efficiencies with a focus on growing our oil volumes.

We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities and the proceeds from asset sales to retire our outstanding debt and/or preferred stock through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise, but we are under no obligation to do so.

Chesapeake Revolving Credit Facility

The Chesapeake revolving credit facility is currently subject to a $3.0 billion borrowing base that matures in September 2023. As of June 30, 2019, we had $1.574 billion of borrowing capacity available under our revolving credit facility. Our next borrowing base redetermination is scheduled for the fourth quarter of 2019. As of June 30, 2019, we had outstanding borrowings of $1.372 billion under the revolving credit facility and had used $54 million of the revolving credit facility for various letters of credit. Borrowings under the facility bear interest at a variable rate. See Note 6 of the notes to our condensed consolidated financial statements included in Item 1 of this report for further discussion of the terms of the Chesapeake revolving credit facility. As of June 30, 2019, we were in compliance with all applicable financial covenants under the credit agreement. Our total leverage ratio was approximately 3.87 to 1.00, our first lien secured leverage ratio was approximately 0.63 to 1.00 and our interest coverage ratio was approximately 3.71 to 1.00.

BVL Revolving Credit Facility

The BVL revolving credit facility is currently subject to a $1.3 billion borrowing base that matures in December 2021. Our next scheduled borrowing base redetermination is scheduled for the fourth quarter of 2019. As of June 30, 2019, we had $614 million of borrowing capacity available under the BVL revolving credit facility, with outstanding borrowings of $686 million. Borrowings under the facility bear interest at a variable rate. See Note 6 of the notes to our condensed consolidated financial statements included in Item 1 of this report for further discussion of the terms of the BVL revolving credit facility. As of June 30, 2019, we were in compliance with all applicable financial covenants under the credit agreement. Our ratio of net debt to EBITDAX was 2.53 to 1.00 and our ratio of current assets to current liabilities was 3.03 to 1.00 as of June 30, 2019.

Contractual Obligations and Off-Balance Sheet Arrangements

From time to time, we enter into arrangements and transactions that can give rise to contractual obligations and off-balance sheet commitments. As of June 30, 2019, these arrangements and transactions included (i) certain operating lease agreements, (ii) open purchase commitments, (iii) open delivery commitments, (iv) open drilling commitments, (v) undrawn letters of credit, (vi) open gathering and transportation commitments, and (vii) various other commitments we enter into in the ordinary course of business that could result in future cash obligations.

Capital Expenditures

Our 2019 capital expenditures program is expected to generate greater capital efficiency than our 2018 program as we focus on expanding our margins through disciplined investing in the highest-return projects. We have significant control and flexibility over the timing and execution of our development plan, enabling us to reduce our capital spending as needed. Our forecasted 2019 capital expenditures, inclusive of capitalized interest, are $2.1 – $2.3 billion compared to our 2018 capital spending level of $2.1 billion. Management continues to review operational plans for 2019 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL.

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Credit Risk

Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, processing, transportation and hedging agreements. As of July 31, 2019, we have received requests and posted approximately $73 million of collateral related to certain of our marketing and other contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $367 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.

Sources of Funds

The following table presents the sources of our cash and cash equivalents for the Current Period and the Prior Period. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of divestitures of oil and natural gas assets.



	Six Months Ended June 30,
	2019		2018
	($ in millions)
Cash provided by operating activities	$	853	$	951
Proceeds from divestitures of proved and unproved properties, net	82		384
Proceeds from revolving credit facility borrowings, net	964		—
Proceeds from sales of other property and equipment, net	4		74
Proceeds from sales of investments	—		74
Total sources of cash and cash equivalents	$	1,903	$	1,483

Cash Flows from Operating Activities

Cash provided by operating activities was $853 million in the Current Period compared to $951 million in the Prior Period. The decrease in the Current Period is primarily due to the result of lower prices for the oil, natural gas and NGL we sold and lower volumes of natural gas and NGL sold offset by higher oil volumes sold. Additionally, cash provided by operating activities in the Current Period included one-time charges for transaction and severance costs of $61 million related to our acquisition of WildHorse. Cash flows from operations are largely affected by the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of assets, deferred income taxes and mark-to-market changes in our open derivative instruments. See further discussion below under Results of Operations.

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Uses of Funds

The following table presents the uses of our cash and cash equivalents for the Current Period and the Prior Period:



	Six Months Ended June 30,
	2019		2018
	($ in millions)
Oil and Natural Gas Expenditures:
Drilling and completion costs	$	1,070	$	928
Acquisitions of proved and unproved properties	17		102
Total oil and natural gas expenditures	1,087		1,030
Other Uses of Cash and Cash Equivalents:
Payments on revolving credit facility borrowings, net	—		275
Business combination, net	353		—
Additions to other property and equipment	18		5
Cash paid to purchase debt	381		—
Extinguishment of other financing	—		122
Dividends paid	46		46
Other	18		7
Total other uses of cash and cash equivalents	816		455
Total uses of cash and cash equivalents	$	1,903	$	1,485

Drilling and Completion Costs

Our drilling and completion costs increased in the Current Period compared to the Prior Period primarily as a result of increased drilling and completion activity in our oil plays. Our average operated rig count was 19 rigs and spud wells were 171 in the Current Period compared to an average operated rig count of 16 rigs and 156 spud wells in the Prior Period. We completed 175 operated wells in the Current Period compared to 163 in the Prior Period.

Business Combination - Acquisition of WildHorse

In the Current Period, we acquired WildHorse for approximately 717.4 million shares of our common stock and $381 million less $28 million of cash held by WildHorse as of the acquisition date. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the acquisition.

Repayment of Debt Upon Maturity

In the Current Quarter, 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.

Extinguishment of Other Financing

In the Prior Quarter, we repurchased previously conveyed overriding royalty interests (ORRIs) from CHK Utica, L.L.C. investors and extinguished our obligation to convey future ORRIs to the investors for combined consideration of $199 million. The cash paid was bifurcated between extinguishment of the obligation and acquisition of the ORRI.

Dividends

We paid dividends of $46 million on our preferred stock in both the Current Period and the Prior Period. We eliminated common stock dividends in the 2015 third quarter and do not anticipate paying any common stock dividends in the foreseeable future.

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Results of Operations

Oil, Natural Gas and NGL Production and Average Sales Prices



	Three Months Ended June 30, 2019
	Oil		Natural Gas			NGL		Total
	mbbl per day	$/bbl	mmcf per day		$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	929		2.33	—	—	155	31		13.99
Haynesville	—	—	751		2.39	—	—	125	25		14.36
Eagle Ford	58	65.82	152		2.69	19	12.78	102	21		43.89
Brazos Valley	35	63.34	55		1.81	5	9.33	49	10		47.57
Powder River Basin	20	57.05	89		2.26	5	16.30	40	8		35.58
Mid-Continent	9	58.12	59		2.03	6	16.97	25	5		30.53
Retained assets^(a)	122	63.09	2,035		2.35	35	13.50	496	100		26.13
Divested assets	—	—	(1	)	4.66	—	—	—	—		—
Total	122	63.04	2,034		2.35	35	13.43	496	100	%	26.12

	Three Months Ended June 30, 2018
	Oil		Natural Gas			NGL		Total
	mbbl per day	$/bbl	mmcf per day		$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	805		2.31	—	—	134	25		13.85
Haynesville	—	—	829		2.63	—	—	139	26		15.80
Eagle Ford	61	70.52	143		3.22	19	26.58	103	20		50.70
Powder River Basin	8	67.37	57		2.18	4	27.12	22	4		36.78
Mid-Continent	10	66.77	64		2.38	5	24.41	25	5		36.74
Retained assets^(a)	79	69.70	1,898		2.52	28	26.29	423	80		26.03
Divested assets	11	63.50	413		2.76	27	25.18	107	20		23.68
Total	90	68.92	2,311		2.56	55	25.74	530	100	%	25.56

	Six Months Ended June 30, 2019
	Oil		Natural Gas			NGL		Total
	mbbl per day	$/bbl	mmcf per day		$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	939		2.94	—	—	156	32		17.63
Haynesville	—	—	755		2.67	—	—	126	26		15.99
Eagle Ford	60	62.73	150		3.13	21	17.74	106	21		43.42
Brazos Valley^(b)	28	61.76	39		1.88	4	8.93	39	8		47.56
Powder River Basin	18	54.31	85		2.79	6	17.54	38	8		34.70
Mid-Continent	9	55.72	59		2.43	6	19.14	24	5		30.62
Retained assets^(a)	115	60.64	2,027		2.81	37	16.89	489	100		27.16
Divested assets	—	—	2		1.33	—	—	1	—		18.97
Total	115	60.59	2,029		2.81	37	16.86	490	100	%	27.15

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	Six Months Ended June 30, 2018
	Oil		Natural Gas		NGL		Total
	mbbl per day	$/bbl	mmcf per day	$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	839	3.05	—	—	140	26		18.30
Haynesville	—	—	830	2.71	—	—	138	25		16.29
Eagle Ford	61	68.36	142	3.26	18	25.73	103	19		49.51
Powder River Basin	8	65.29	52	2.46	5	25.17	24	4		35.89
Mid-Continent	9	64.58	62	2.52	3	27.84	20	4		37.17
Retained assets^(a)	78	67.59	1,925	2.89	26	25.89	425	78		27.05
Divested assets	13	62.02	463	2.84	27	25.32	117	22		24.18
Total	91	66.76	2,388	2.88	53	25.60	542	100	%	26.43

___________________________________________


(a)	Includes assets retained as of June 30, 2019.

(b) Average production per day since the date of the WildHorse acquisition on February 1, 2019, 150 days, was 34 mbbl, 47 mmcf and 5 mbbl for oil, natural gas and NGL, respectively.

Oil, Natural Gas and NGL Sales



	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		Change		2019		2018		Change
	($ in millions)
Oil	$	700	$	567	23	%	$	1,266	$	1,104	15	%
Natural gas	436		538		(19	)%	1,031		1,244		(17	)%
NGL	43		128		(66	)%	112		245		(54	)%
Oil, natural gas and NGL sales	$	1,179	$	1,233	(4	)%	$	2,409	$	2,593	(7	)%

The increase in the average price received per boe in the Current Quarter resulted in a $25 million increase in revenues, and decreased sales volumes resulted in a $79 million decrease in revenues, for a total net decrease in revenues of $54 million. The increase in the average price received per boe in the Current Period resulted in a $64 million increase in revenues, and decreased sales volumes resulted in a $248 million decrease in revenues, for a total net decrease in revenues of $184 million.

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Oil, Natural Gas and NGL Derivatives



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	($ in millions)
Oil derivatives – realized gains (losses)	$	(18	)	$	(97	)	$	(8	)	$	(161	)
Oil derivatives – unrealized gains (losses)	104			(105		)	(165		)	(127		)
Total gains (losses) on oil derivatives	86			(202		)	(173		)	(288		)

Natural gas derivatives – realized gains (losses)	24			17			(12		)	84
Natural gas derivatives – unrealized gains (losses)	165			(52		)	159			(151		)
Total gains (losses) on natural gas derivatives	189			(35		)	147			(67		)

NGL derivatives – realized gains (losses)	—			(3		)	—			(4		)
NGL derivatives – unrealized gains (losses)	—			(11		)	—			(9		)
Total gains (losses) on NGL derivatives	—			(14		)	—			(13		)
Total gains (losses) on oil, natural gas and NGL derivatives	$	275		$	(251	)	$	(26	)	$	(368	)

See Note 13 of the notes to our condensed consolidated financial statements included in Item 1 of this report for a discussion of our derivative activity.

Marketing Revenues and Expenses



	Three Months Ended June 30,								Six Months Ended June 30,
	2019			2018			Change		2019			2018			Change
	($ in millions)
Marketing revenues	$	916		$	1,273		(28	)%	$	2,149		$	2,519		(15	)%
Marketing expenses	940			1,292			(27	)%	2,170			2,560			(15	)%
Marketing gross margin	$	(24	)	$	(19	)	(26	)%	$	(21	)	$	(41	)	49	%

Marketing revenues and expenses decreased in the Current Quarter and the Current Period primarily as a result of decreased oil, natural gas and NGL prices received in our marketing operations as well decreases from the termination of a marketing contract related to our Utica divestiture. Gross margin decreased in the Current Quarter due to an increase in transportation fees. Gross margin increased in the Current Period due to the marketing services provided to acquirers of our divested wells.

Other Revenue



	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		Change		2019		2018		Change
	($ in millions)
Other revenue	$	15	$	16	(6	)%	$	30	$	32	(6	)%

Other revenue relates to the amortization of deferred VPP revenue. Our remaining deferred revenue balance of $93 million will be amortized on a straight-line basis through 2021. See Note 8 of the notes to our condensed consolidated financial statements included in Item 8 of this report for further discussion of our VPP.

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Oil, Natural Gas and NGL Production Expenses



	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		Change		2019			2018		Change
	($ in millions)
Marcellus	8		8		—	%	18			17		6	%
Haynesville	12		13		(8	)%	25			30		(17	)%
Eagle Ford	51		52		(2	)%	93			100		(7	)%
Brazos Valley	31		—		n/a		45			—		n/a
Powder River Basin	16		11		45	%	30			23		30	%
Mid-Continent	24		21		14	%	49			46		7	%
Retained Assets^(a)	142		105		35	%	260			216		20	%
Divested Assets	1		13		(92	)%	(1		)	37		(103	)%
Total	143		118		21	%	259			253		2	%

Ad valorem tax	23		20		15	%	39			32		22	%

Total oil, natural gas and NGL production expenses	$	166	$	138	20	%	$	298		$	285	5	%

	($ per boe)
Marcellus	$	0.59	$	0.64	(8	)%	$	0.61		$	0.67	(9	)%
Haynesville	$	1.01	$	1.09	(7	)%	$	1.11		$	1.18	(6	)%
Eagle Ford	$	5.52	$	5.56	(1	)%	$	4.81		$	5.39	(11	)%
Brazos Valley	$	6.91	$	—	n/a		$	6.35		$	—	n/a
Powder River Basin	$	4.42	$	5.54	(20	)%	$	4.39		$	6.28	(30	)%
Mid-Continent	$	10.45	$	9.00	16	%	$	11.04		$	10.77	3	%
Retained Assets^(a)	$	3.14	$	2.74	15	%	$	2.92		$	2.81	4	%
Divested Assets	$	—	$	1.29	(100	)%	$	—		$	1.73	(100	)%
Total	$	3.17	$	2.44	30	%	$	2.91		$	2.57	13	%

Ad valorem tax	$	0.51	$	0.42	21	%	$	0.44		$	0.33	33	%

Total oil, natural gas and NGL production expenses per boe	$	3.68	$	2.86	29	%	$	3.35		$	2.90	16	%

___________________________________________

(a) Includes assets retained as of June 30, 2019.

The absolute and per unit increase in the Current Quarter and the Current Period was the result of the acquisition of WildHorse in 2019, partially offset by the sale of certain oil and natural gas properties in 2018 and 2019.

Production expenses in the Current Quarter, the Prior Quarter, the Current Period and the Prior Period included approximately $4 million, $4 million, $7 million and $8 million associated with VPP production volumes, respectively. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.

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Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	($ in millions, except per unit)
Oil, natural gas and NGL gathering, processing and transportation expenses	$	271	$	340	$	545	$	696
Oil ($ per bbl)	$	2.42	$	3.22	$	2.92	$	3.70
Natural gas ($ per mcf)	$	1.23	$	1.29	$	1.22	$	1.28
NGL ($ per bbl)	$	5.01	$	8.46	$	5.30	$	8.65
Total ($ per boe)	$	6.00	$	7.04	$	6.14	$	7.10

The absolute and per unit decrease in oil, natural gas and NGL gathering, processing and transportation expenses was primarily due to certain 2018 divestitures.

Production Taxes



	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		Change		2019		2018		Change
	($ in millions, except per unit)
Production taxes	$	40	$	26	54	%	$	74	$	57	30	%
Production taxes per boe	$	0.88	$	0.55	60	%	$	0.83	$	0.58	43	%

The absolute and per unit increase in production taxes in the Current Quarter and the Current Period was primarily due to the addition of assets through our acquisition of WildHorse, a legislative increase in the Oklahoma production tax rate in the third quarter of 2018 and expiring exemptions in Louisiana.

Exploration Expenses



	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		Change		2019		2018	Change
	($ in millions, except per unit)
Impairments of unproved properties	$	7	$	5	40	%	$	25	53	(53	)%
Dry hole expense	—		—		—	%	—		21	(100	)%
Geological and geophysical expense and other	8		15		(47	)%	14		27	(48	)%
Exploration expense	$	15	$	20	(25	)%	$	39	101	(61	)%

The decrease in exploration expense in the Current Quarter was primarily due to less geological, geophysical and delay rental expense. The decrease in the Current Period was primarily due to fewer impairments of unproved properties recognized and no dry hole expense.

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General and Administrative Expenses



	Three Months Ended June 30,								Six Months Ended June 30,
	2019			2018			Change		2019			2018			Change
	($ in millions, except per unit)
Gross compensation and overhead	$	185		$	201		(8	)%	$	380		$	389		(2	)%
Allocated to production expenses	(37		)	(36		)	3	%	(72		)	(76		)	(5	)%
Allocated to marketing expenses	(4		)	(5		)	(20	)%	(8		)	(11		)	(27	)%
Allocated to exploration expenses	(2		)	(3		)	(33	)%	(6		)	(4		)	50	%
Allocated to sand mine expenses	(3		)	—			n/a		(3		)	—			n/a
Capitalized general and administrative expenses	(13		)	(13		)	—	%	(26		)	(29		)	(10	)%
Reimbursed from third parties	(37		)	(39		)	(5	)%	(73		)	(77		)	(5	)%
General and administrative expenses, net	$	89		$	105		(15	)%	$	192		$	192		—	%

General and administrative expenses, net per boe	$	1.99		$	2.17		(8	)%	$	2.17		$	1.96		11	%

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 of approximately $38 million in the Prior Period for one-time termination benefits. The charge consisted of $33 million in salary expense and $5 million of other termination benefits.

Depreciation, Depletion and Amortization



	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		Change		2019		2018		Change
	($ in millions, except per unit)
Depreciation, depletion and amortization	$	580	$	471	23	%	$	1,099	$	930	18	%
Depreciation, depletion and amortization per boe	$	12.84	$	9.74	32	%	$	12.38	$	9.47	31	%

The absolute and per unit increase in the Current Quarter and the Current Period is primarily the result of a higher depletion rate. The increase in depletion rate per boe primarily reflects our acquisition of WildHorse, coupled with our higher concentration of capital deployment in liquids-rich operating areas, which generally involve higher finding costs per boe relative to our gas-rich operating areas, as we focus on expanding our margins through disciplined investing in the highest-return projects.

Other Operating Expense



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019		2018
	($ in millions)
Other operating expense	$	3	$	(1	)	$	64	$	(1	)

In the Current Period, we recorded $26 million of costs related to our acquisition of WildHorse, which consisted of financial advisory fees, legal fees and travel and lodging expenses. Additionally, we recorded $38 million of severance expense as a result of our 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.

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Interest Expense



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	($ in millions, except per unit)
Interest expense on senior notes	$	150		$	144		$	297		$	288
Interest expense on term loan	—			30			—			58
Amortization of loan discount, issuance costs and other	7			2			12			10
Amortization of premium	—			(24		)	—			(48		)
Interest expense on revolving credit facilities	24			8			40			18
Realized gains on interest rate derivatives	(1		)	—			(1		)	(1		)
Unrealized losses on interest rate derivatives	1			—			1			1
Capitalized interest	(6		)	(5		)	(13		)	(9		)
Total interest expense	$	175		$	155		$	336		$	317

Interest expense per boe^(a)	$	3.85		$	3.21		$	3.78		$	3.22

Average senior notes borrowings	$	8,161		$	7,967		$	8,183		$	7,967
Average credit facilities borrowings	$	2,032		$	380		$	1,627		$	488
Average term loan borrowings	$	—		$	1,233		$	—		$	1,233

___________________________________________


(a)	Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives and is shown net of amounts capitalized.

The decrease in interest expense on the term loan is due to the repurchase of our term loan in the third quarter of 2018. The decrease in amortization of premium is due to the repurchase of our senior secured second lien notes in the fourth quarter of 2018. The increase in interest expense on revolving credit facilities is due to interest on the BVL revolving credit facility assumed in the WildHorse acquisition.

Gains (Losses) on Investments

In the Current Period in connection with the acquisition of WildHorse, we obtained a 50% membership interest in JWH Midstream LLC (JWH). The carrying value of our investment in JWH, which was being accounted for as an equity method investment, was approximately $17 million as of March 31, 2019. In the Current Quarter, we paid approximately $7 million to terminate our involvement in the partnership. This removed us from any future obligations related to this joint venture, therefore we impaired the full value of the investment and recognized approximately $24 million of impairment expense in the Current Quarter.

In the Prior Period, we recognized $139 million of gains related to our equity investment in FTSI, including the sale of a portion of that investment. See Note 14 of the notes to our condensed consolidated financial statements included in Item 1 of this report for further discussion.

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Other Income

In the Current Quarter, we recognized $8 million of other income from the sale of seismic data licenses to third parties. In the Prior Quarter, we extinguished our obligation to convey future ORRIs to the CHK Utica L.L.C. investors and recognized a $61 million gain included in other income on our condensed consolidated statement of operations.

Income Tax Expense (Benefit)

No income tax provision was recorded for the Current Quarter. The income tax benefit of $314 million for the Current Period was recorded in full during the first quarter of 2019. We recorded a $9 million income tax benefit in the Prior Quarter and in the Prior Period. Our effective income tax rate was 0.0% for the Current Quarter and 132.5% for the Current Period. The rate for the Current Period is due to the partial release of the valuation allowance associated with our acquisition of WildHorse. The effective income tax rate was 3.5% for the Prior Quarter and 3.8% for the Prior Period. Our effective tax rate can fluctuate as a result of the impact of various items, including state income taxes, permanent differences, tax law changes and adjustments to the valuation allowance. See Note 11 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of income taxes.

Forward-Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. Forward-looking statements include our current expectations or forecasts of future events, including matters relating to our ability to meet debt service requirements, cost savings due to operational and capital efficiencies related to the WildHorse Merger and the other items discussed in the Introduction to Item 2 of this report. In this context, forward-looking statements often address our expected future business, financial performance and financial condition, and often contain words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”

Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:


•	the volatility of oil, natural gas and NGL prices;


•	uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;


•	our ability to replace reserves and sustain production;


•	drilling and operating risks and resulting liabilities;


•	our ability to generate profits or achieve targeted results in drilling and well operations;


•	the limitations our level of indebtedness may have on our financial flexibility;


•	our inability to access the capital markets on favorable terms;


•	the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations;


•	adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;


•	effects of environmental protection laws and regulation on our business;


•	terrorist activities and/or cyber-attacks adversely impacting our operations;


•	effects of acquisitions and dispositions, including our acquisition of WildHorse and our ability to realize related synergies and cost savings;


•	effects of purchase price adjustments and indemnity obligations; and


•	other factors that are described under Risk Factors in Item 1A of our 2018 Form 10-K.

We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information. We urge you to carefully

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review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.

Information About Us

Investors should note that we make available, free of charge on our website at chk.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We also furnish quarterly, annual, and current reports for certain of our subsidiaries free of charge on our website at chk.com. We also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. We may use the Investors section of our website to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. Documents and information on our website are not incorporated by reference herein.

The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Chesapeake, that file electronically with the SEC.

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ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk

Oil, Natural Gas and NGL Derivatives

Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

Our general strategy for protecting short-term cash flows and attempting to mitigate exposure to adverse oil, natural gas and NGL price changes is to hedge into strengthening oil, natural gas and NGL futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in our risk management activities and the Board of Directors reviews our derivative program at quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.

We use derivative instruments to achieve our risk management objectives, including swaps, collars and options. All of these are described in more detail below. We typically use swaps and collars for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility.

We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.

We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter into the original derivative position. Gains or losses related to closed positions will be recognized in the month specified in the original contract.

We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 13 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the fair value measurements associated with our derivatives.

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As of June 30, 2019, 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.

•


•	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 or to increase the notional volumes of an existing fixed-price swap.

•


•	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.

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As of June 30, 2019, we had the following open oil, natural gas and NGL derivative instruments:



		Weighted Average Price									Fair Value
	Volume	Fixed		Call		Put		Differential			Asset (Liability)
	(mmbbl)	($ per bbl)									($ in millions)
Oil:
Swaps:
Short-term	18	$	59.93	$	—	$	—	$	—		$	41
Long-term	6	$	59.42	$	—	$	—	$	—		23
Collars:
Short-term	4	$	—	$	71.41	$	59.65	$	—		17
Long-term	1	$	—	$	83.25	$	65.00	$	—		10
Call Swaptions:
Short-term^(a)	2	$	63.15	$	—	$	—	$	—		(5		)
Put Options (bought):
Short-term	2	$	—	$	—	$	54.31	$	—		(5		)
Basis Protection Swaps:
Short-term	4	$	—	$	—	$	—	$	5.85		6
Total Oil											87
	(bcf)	($ per mcf)
Natural Gas:
Swaps:
Short-term	379	$	2.81	$	—	$	—	$	—		150
Long-term	126	$	2.75	$	—	$	—	$	—		26
Three-Way Collars:
Short-term	15	$	—	$	3.10	$2.50/$2.80		—			2
Collars:
Short-term	18	$	—	$	2.91	$	2.75	$	—		7
Call Options (sold):
Short-term	22	$	—	$	12.00	$	—	$	—		—
Long-term	11	$	—	$	12.00	$	—	$	—		—
Call Swaptions:
Short-term^(a)	106	$	2.77	$	—	—		—			(10		)
Basis Protection Swaps:
Short-term	20	$	—	$	—	$	—	$	(0.43	)	—
Total Natural Gas											175
Total Commodities											$	262

___________________________________________


(a)	Call swaptions include 2020 volumes for sold call options that expire December 2019.

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In addition to the open derivative positions disclosed above, as of June 30, 2019, we had $45 million of net derivative losses related to settled contracts for future periods that will be recorded within oil, natural gas and NGL revenues as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive income or unrealized gains (losses) on derivatives in the month specified in the original contract as noted below:



	June 30, 2019
	($ in millions)
Short-term	$	(23	)
Long-term	(22		)
Total	$	(45	)

The table below reconciles the changes in fair value of our oil and natural gas derivatives during the Current Quarter. Of the $262 million fair value liability as of June 30, 2019, a $202 million asset relates to contracts maturing in the next 12 months and a $60 million asset relates to contracts maturing after 12 months. All open derivative instruments as of June 30, 2019 are expected to mature by December 31, 2020.



	June 30, 2019
	($ in millions)
Fair value of contracts outstanding, as of January 1, 2019	$	282
Change in fair value of contracts	(14		)
Contracts realized or otherwise settled	(6		)
Fair value of contracts outstanding, as of June 30, 2019	$	262

Interest Rate Risk

The table below presents principal cash flows and related weighted average interest rates by expected maturity dates, using the earliest demand repurchase date for contingent convertible senior notes.



	Years of Maturity
	2019			2020			2021			2022			2023			Thereafter			Total
	($ in millions)
Liabilities:
Debt – fixed rate	$	—		$	301		$	294		$	451		$	338		$	6,719		$	8,103
Average interest rate	—		%	6.70		%	5.80		%	4.88		%	5.75		%	7.26		%	6.99		%
Debt – variable rate	$	—		$	—		$	686		$	—		$	1,372		$	—		$	2,058
Average interest rate	—		%	—		%	4.41		%	—		%	4.15		%	—		%	4.24		%

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving credit facility and our floating rate senior notes. All of our other indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flows due to changes in market interest rates. However, changes in interest rates do affect the fair value of our fixed-rate debt.

As of June 30, 2019, we had $3 million of net gains related to settled interest rate derivative contracts that will be recorded within interest expense as realized gains or losses once they are transferred from our senior note liability or within interest expense as unrealized gains or losses over the remaining six-year term of our related senior notes.

Realized and unrealized (gains) or losses from interest rate derivative transactions are reflected as adjustments to interest expense on the condensed consolidated statements of operations.

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ITEM 4.	Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded as of June 30, 2019 that our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

As previously disclosed, we acquired WildHorse on February 1, 2019 (see Note 3 in Part 1, Item 1 in this Quarterly Report on Form 10-Q) and are in the process of fully integrating its operations into our overall system of internal control over financial reporting. As permitted by U.S. Securities and Exchange Commission rules and regulations, we have not yet included WildHorse in our assessment of the effectiveness of our internal control over financial reporting.

There were no other changes in our internal control over financial reporting during the period covered by this Quarterly Report on Form 10-Q that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION


ITEM 1.	Legal Proceedings

There have been no material developments in previously reported legal or environmental proceedings, except as discussed below. For a description of other legal and regulatory proceedings affecting us, see Item 3 in our 2018 Form 10-K.

In January 2019, putative class action lawsuits in U.S. District Courts for the Southern District of New York were filed against WildHorse and other defendants. The lawsuits generally alleged 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 sought rescission of the Merger or rescissory damages and, in each case, attorney's fees, costs and interest. The lawsuits were voluntarily dismissed by the plaintiffs on July 10, 2019.


ITEM 1A.	Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock, preferred stock or senior notes are described under “Risk Factors” in Item 1A of our 2018 Form 10-K and our 10-Q for the three months ended March 31, 2019. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.


ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds

The following table presents information about repurchases of our common stock during the quarter ended June 30, 2019:



Period	Total Number of Shares Purchased^(a)	Average Price Paid Per Share^(a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs
					($ in millions)
April 1, 2019 through April 30, 2019	19,516	$	3.20	—	$	—
May 1, 2019 through May 31, 2019	—	$	—	—	$	—
June 1, 2019 through June 30, 2019	—	$	—	—	$	—
Total	19,516	$	—	—

___________________________________________


(a)	Includes shares of common stock purchased on behalf of our deferred compensation plan.


ITEM 3.	Defaults Upon Senior Securities

None.

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ITEM 4.	Mine Safety Disclosures

The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17CFR 229.104) is included in Exhibit 95.1 to this Quarterly Report on Form 10-Q.


ITEM 5.	Other Information

Not applicable.

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ITEM 6.	Exhibits

The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.

INDEX OF EXHIBITS



		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed or Furnished Herewith
3.1.1	Chesapeake’s Restated Certificate of Incorporation.	10-K	001-13726	3.1.1	2/27/2019

3.1.2	Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B), as amended.	10-Q	001-13726	3.1.4	11/10/2008

3.1.3	Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock, as amended.	10-Q	001-13726	3.1.6	8/11/2008

3.1.4	Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A).	8-K	001-13726	3.2	5/20/2010

3.1.5	Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended.	10-Q	001-13726	3.1.5	8/9/2010

3.2	Chesapeake’s Amended and Restated Bylaws.	8-K	001-13726	3.2	6/19/2014

4.1	Indenture, dated as of February 1, 2017, by and among WildHorse Resource Development Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee.	8-K	001-37964	4.1	2/1/2017

4.2	Fourth Supplemental Indenture, dated as of February 1, 2019 among Brazos Valley Longhorn, L.L.C., the Guarantors (as defined in the Indenture referred to therein) and U.S. Bank National Association.	8-K	001-37964	4.1	2/1/2019

4.3	Third Supplemental Indenture, dated as of August 2, 2018 among Burleson Sand LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as Trustee.	10-Q	001-37964	4.6	8/9/2018

4.4	Second Supplemental Indenture, dated as of January 8, 2018 among Burleson Sand LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as Trustee.	10-K	001-37964	4.6	3/12/2018

4.5	First Supplemental Indenture, dated as of June 30, 2017, by and among WHR Eagle Ford LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as Trustee.	10-Q	001-37964	4.6	8/10/2017

4.6	Tenth Supplemental Indenture, dated as of April 3, 2019, to Indenture dated as of April 24, 2014 with respect to 8.00% Senior Notes due 2026.	8-K	001-13726	4.2	4/5/2019

4.7	Registration Rights Agreement, dated as of April 3, 2019, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and the dealer managers party thereto with respect to 8.00% Senior Notes due 2026.	8-K	001-13726	4.4	4/5/2019

31.1	Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X

31.2	Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X

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32.1

Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

95.1

Mine Safety Disclosure

101 INS

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101 SCH

XBRL Taxonomy Extension Schema Document.

101 CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101 DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101 LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101 PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

†

Management contract or compensatory plan or arrangement

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	CHESAPEAKE ENERGY CORPORATION

Date: August 6, 2019	By:	/s/ ROBERT D. LAWLER
		Robert D. Lawler President and Chief Executive Officer




Date: August 6, 2019	By:	/s/ DOMENIC J. DELL’OSSO, JR.
		Domenic J. Dell’Osso, Jr. Executive Vice President and Chief Financial Officer