EXE 10-Q Quarterly Report June 30, 2018

EXPAND ENERGY CORP

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10-Q 1 chk-20180630_10q.htm 10-Q Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended June 30, 2018

[ ] 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)



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 [X] 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 [X] 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 [X] 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 [X]

As of July 25, 2018 , there were 912,274,017 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, 2018



	PART I. FINANCIAL INFORMATION	Page
Item 1.	Condensed Consolidated Financial Statements
	Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017	3
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2018 and 2017	5
	Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2018 and 2017	6
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017	7
	Condensed Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30, 2018 and 2017	9
	Notes to the Condensed Consolidated Financial Statements
	Note 1. Basis of Presentation	10
	Note 2. Earnings per Share	12
	Note 3. Debt	13
	Note 4. Contingencies and Commitments	14
	Note 5. Other Liabilities	15
	Note 6. Income Taxes	16
	Note 7. Share-Based Compensation	16
	Note 8. Derivative and Hedging Activities	20
	Note 9. Oil and Natural Gas Property Transactions	25
	Note 10. Revenue Recognition	26
	Note 11. Investments	29
	Note 12. Impairments	29
	Note 13. Other Operating Expenses	30
	Note 14. Restructuring and Other Termination Costs	30
	Note 15. Fair Value Measurements	30
	Note 16. Condensed Consolidating Financial Information	31
	Note 17. Subsequent Events	40
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
	Liquidity and Capital Resources	43
	Results of Operations for the Three and Six Months Ended June 30, 2018 and 2017	49
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	57
Item 4.	Controls and Procedures	62
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64
Item 3.	Defaults Upon Senior Securities	64
Item 4.	Mine Safety Disclosures	64
Item 5.	Other Information	64
Item 6.	Exhibits	66

Signatures		67

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, 2018			December 31, 2017
	($ in millions)
CURRENT ASSETS:
Cash and cash equivalents ($2 and $2 attributable to our VIE)	$	3		$	5
Accounts receivable, net	1,060			1,322
Short-term derivative assets	—			27
Other current assets	177			171
Total Current Assets	1,240			1,525
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting:
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	69,976			68,858
Unproved properties	3,226			3,484
Other property and equipment	1,822			1,986
Total Property and Equipment, at Cost	75,024			74,328
Less: accumulated depreciation, depletion and amortization (($463) and ($461) attributable to our VIE)	(64,185		)	(63,664		)
Property and equipment held for sale, net	11			16
Total Property and Equipment, Net	10,850			10,680
LONG-TERM ASSETS:
Other long-term assets	251			220
TOTAL ASSETS	$	12,341		$	12,425

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

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (Continued)

(Unaudited)



	June 30, 2018			December 31, 2017
	($ in millions)
CURRENT LIABILITIES:
Accounts payable	$	742		$	654
Current maturities of long-term debt, net	432			52
Accrued interest	125			137
Short-term derivative liabilities	297			58
Other current liabilities ($2 and $3 attributable to our VIE)	1,277			1,455
Total Current Liabilities	2,873			2,356
LONG-TERM LIABILITIES:
Long-term debt, net	9,238			9,921
Long-term derivative liabilities	21			4
Asset retirement obligations, net of current portion	149			162
Other long-term liabilities	177			354
Total Long-Term Liabilities	9,585			10,441
CONTINGENCIES AND COMMITMENTS (Note 4)
EQUITY:
Chesapeake Stockholders’ Equity (Deficit):
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 5,603,458 shares outstanding	1,671			1,671
Common stock, $0.01 par value, 2,000,000,000 shares authorized: 913,271,035 and 908,732,809 shares issued	9			9
Additional paid-in capital	14,408			14,437
Accumulated deficit	(16,257		)	(16,525		)
Accumulated other comprehensive loss	(40		)	(57		)
Less: treasury stock, at cost; 3,319,061 and 2,240,394 common shares	(31		)	(31		)
Total Chesapeake Stockholders’ Equity (Deficit)	(240		)	(496		)
Noncontrolling interests	123			124
Total Equity (Deficit)	(117		)	(372		)
TOTAL LIABILITIES AND EQUITY	$	12,341		$	12,425

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

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	($ in millions except per share data)
REVENUES:
Oil, natural gas and NGL	$	982		$	1,279		$	2,225		$	2,748
Marketing	1,273			1,002			2,519			2,286
Total Revenues	2,255			2,281			4,744			5,034
OPERATING EXPENSES:
Oil, natural gas and NGL production	138			140			285			275
Oil, natural gas and NGL gathering, processing and transportation	340			357			696			712
Production taxes	26			21			57			43
Marketing	1,292			1,027			2,560			2,355
General and administrative	91			70			163			135
Restructuring and other termination costs	—			—			38			—
Provision for legal contingencies, net	4			17			9			15
Oil, natural gas and NGL depreciation, depletion and amortization	271			202			539			399
Depreciation and amortization of other assets	19			21			37			42
Impairments	46			—			46			—
Other operating (income) expense	(1		)	26			(1		)	417
Net (gains) losses on sales of fixed assets	(1		)	1			7			1
Total Operating Expenses	2,225			1,882			4,436			4,394
INCOME FROM OPERATIONS	30			399			308			640
OTHER INCOME (EXPENSE):
Interest expense	(117		)	(93		)	(240		)	(188		)
Gains on investments	—			—			139			—
Gains on purchases or exchanges of debt	—			191			—			184
Other income (expense)	62			(1		)	62			2
Total Other Income (Expense)	(55		)	97			(39		)	(2		)
INCOME (LOSS) BEFORE INCOME TAXES	(25		)	496			269			638
Income tax expense (benefit)	(9		)	1			(9		)	2
NET INCOME (LOSS)	(16		)	495			278			636
Net income attributable to noncontrolling interests	(1		)	(1		)	(2		)	(2		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(17		)	494			276			634
Preferred stock dividends	(23		)	(16		)	(46		)	(39		)
Loss on exchange of preferred stock	—			—			—			(41		)
Earnings allocated to participating securities	—			(8		)	(2		)	(7		)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	(40	)	$	470		$	228		$	547
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(0.04	)	$	0.52		$	0.25		$	0.60
Diluted	$	(0.04	)	$	0.47		$	0.25		$	0.59
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	909			908			908			907
Diluted	909			1,114			908			1,053

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

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	($ in millions)
NET INCOME (LOSS)	$	(16	)	$	495		$	278		$	636
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
Unrealized gains on derivative instruments ^(a)	—			—			—			4
Reclassification of losses on settled derivative instruments ^(a)	7			7			17			17
Other Comprehensive Income	7			7			17			21
COMPREHENSIVE INCOME (LOSS)	(9		)	502			295			657
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(1		)	(1		)	(2		)	(2		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	(10	)	$	501		$	293		$	655

___________________________________________


(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.

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2018			2017
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	278		$	636
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:
Depreciation, depletion and amortization	576			441
Derivative (gains) losses, net	368			(522		)
Cash payments on derivative settlements, net	(55		)	(66		)
Stock-based compensation	18			27
Net losses on sales of fixed assets	7			1
Impairments	46			—
Gains on investments	(139		)	—
Gains on purchases or exchanges of debt	—			(185		)
Other	(102		)	(43		)
Changes in assets and liabilities	94			(347		)
Net Cash Provided By (Used In) Operating Activities	1,091			(58		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(979		)	(1,031		)
Acquisitions of proved and unproved properties	(191		)	(162		)
Proceeds from divestitures of proved and unproved properties	384			951
Additions to other property and equipment	(5		)	(7		)
Proceeds from sales of other property and equipment	74			26
Proceeds from sales of investments	74			—
Net Cash Used In Investing Activities	(643		)	(223		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	6,118			2,551
Payments on revolving credit facility borrowings	(6,393		)	(1,976		)
Proceeds from issuance of senior notes, net	—			742
Extinguishment of other financing	(122		)	—
Cash paid to purchase debt	—			(1,746		)
Cash paid for preferred stock dividends	(46		)	(137		)
Distributions to noncontrolling interest owners	(3		)	(5		)
Other	(4		)	(17		)
Net Cash Used In Financing Activities	(450		)	(588		)
Net decrease in cash and cash equivalents	(2		)	(869		)
Cash and cash equivalents, beginning of period	5			882
Cash and cash equivalents, end of period	$	3		$	13

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

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

(Unaudited)



Supplemental disclosures to the consolidated statements of cash flows are presented below:
	Six Months Ended June 30,
	2018			2017
	($ in millions)
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	$	276		$	217
Income taxes paid, net of refunds received	$	(7	)	$	(14	)

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs	$	109		$	87
Change in accrued acquisitions of proved and unproved properties	$	1		$	4
Change in divested proved and unproved properties	$	(21	)	$	16

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

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)



	Six Months Ended June 30,
	2018			2017
	($ in millions)
PREFERRED STOCK:
Balance, beginning of period	$	1,671		$	1,771
Exchange/conversions of 0 and 236,048 shares of preferred stock for common stock	—			(100		)
Balance, 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			14,486
Stock-based compensation	17			29
Exchange of preferred stock for 0 and 9,965,835 shares of common stock	—			100
Equity component of contingent convertible notes repurchased, net of tax	—			(20		)
Dividends on preferred stock	(46		)	(137		)
Balance, end of period	14,408			14,458
RETAINED EARNINGS (ACCUMULATED DEFICIT):
Balance, beginning of period	(16,525		)	(17,603		)
Net income attributable to Chesapeake	276			634
Cumulative effect of accounting change	(8		)	—
Balance, end of period	(16,257		)	(16,969		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period	(57		)	(96		)
Hedging activity	17			21
Balance, end of period	(40		)	(75		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(31		)	(27		)
Purchase of 1,468,524 and 1,189,813 shares for company benefit plans	(4		)	(6		)
Release of 389,857 and 73,990 shares from company benefit plans	4			1
Balance, end of period	(31		)	(32		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT)	(240		)	(938		)
NONCONTROLLING INTERESTS:
Balance, beginning of period	124			257
Net income attributable to noncontrolling interests	2			2
Distributions to noncontrolling interest owners	(3		)	(5		)
Balance, end of period	123			254
TOTAL EQUITY (DEFICIT)	$	(117	)	$	(684	)

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

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.	Basis of Presentation

Basis of Presentation

The accompanying condensed consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules and regulations of the SEC. Pursuant to such rules and regulations, certain disclosures have been condensed or omitted.

This Form 10-Q relates to the three and six months ended June 30, 2018 (the “Current Quarter” and the “Current Period”, respectively) and the three and six months ended June 30, 2017 (the “Prior Quarter” and the “Prior Period”, respectively). Our annual report on Form 10-K for the year ended December 31, 2017 (“2017 Form 10-K”) should be read in conjunction with this Form 10-Q. The accompanying condensed consolidated financial statements reflect all normal recurring adjustments which, in the opinion of management, are necessary for a fair statement of our condensed consolidated financial statements and accompanying notes and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which we have a controlling financial interest. Intercompany accounts and balances have been eliminated .

Recently Issued Accounting Standards

The Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers (Topic 606) superseding virtually all existing revenue recognition guidance. We adopted this new standard in the first quarter of 2018 using the modified retrospective approach. We applied the new standard to all contracts that were not completed as of January 1, 2018 and reflected the aggregate effect of all modifications in determining and allocating the transaction price. See Note 10 for further details regarding our adoption of Topic 606.

In February 2018, the FASB issued Accounting Standards Update (ASU) 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income . The new standard allows for stranded tax effects resulting from tax reform legislation known as the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) previously recognized in accumulated other comprehensive income to be reclassified to retained earnings. For public business entities, the amendments are effective for annual periods, including interim periods within the annual periods, beginning after December 15, 2018. Early adoption is permitted in any interim or annual period, but we do not plan to early adopt. We are currently evaluating the impact of this standard on our consolidated financial statements and related disclosures.

In August 2017, the FASB issued ASU 2017-12 , Derivatives and Hedging (Topic 815), which makes significant changes to the current hedge accounting guidance. The new standard eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The new standard also eases certain documentation and assessment requirements and modifies the accounting for components excluded from the assessment of hedge effectiveness. The new standard update is effective for annual and interim periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted, but we do not plan to early adopt. We are currently evaluating the impact of this standard on our consolidated financial statements and related disclosures.

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which updated lease accounting guidance requiring lessees to recognize most leases, including operating leases, on the balance sheet as a right-of-use asset and lease liability for leases with terms in excess of 12 months. In January 2018, the FASB issued an update permitting an entity to elect an optional transition practical expedient to not evaluate land easements that existed or expired before the adoption of Topic 842 and were not previously accounted for as leases. Currently the guidance would be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. However, the FASB recently issued Proposed ASU No. 2018-200, Leases (Topic 842), Targeted Improvements which would allow entities to apply the transition provisions of the new standard at its adoption date instead of at the earliest comparative period presented in the consolidated financial statements. The proposed ASU will allow entities to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented. Early adoption is permitted, but we do not plan to early adopt . The standard will not apply to our leases of mineral rights. Using the revised framework, we have completed our assessment of lease categories that we believe will be affected by the new standard. We are continuing to assess the accounting treatment for these leases and the resulting impacts to our consolidated financial statements and related disclosures.

TABLE OF CONTENTS

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


2.	Earnings Per Share

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

Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For all periods presented, our contingent convertible senior notes did not have a dilutive effect and, therefore, were excluded from the calculation of diluted EPS. See Note 3 for further discussion of our convertible senior notes and contingent convertible senior notes.

A reconciliation of basic EPS and diluted EPS is as follows:



	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018		2017
	(in millions, except per share data)
Net income (loss) available to common stockholders	$	(40	)	$	470	$	228	$	547
Effect of dilutive securities	—			59		—		72
Diluted income (loss) available to common stockholders	$	(40	)	$	529	$	228	$	619

Weighted average common and common equivalent shares outstanding - basic	909			908		908		907
Effect of dilutive securities	—			206		—		146
Weighted average common and common equivalent shares outstanding - diluted	909			1,114		908		1,053

Net income per share attributable to Chesapeake:
Basic	$	(0.04	)	$	0.52	$	0.25	$	0.60
Diluted	$	(0.04	)	$	0.47	$	0.25	$	0.59

Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive:
Common stock equivalent of our preferred stock outstanding	60			—		60		60
Common stock equivalent of our convertible senior notes outstanding	146			—		146		—
Common stock equivalent of our preferred stock outstanding prior to exchange	—			—		—		1
Participating securities	1			1		1		1

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


3.	Debt

Our long-term debt consisted of the following as of June 30, 2018 and December 31, 2017:



	June 30, 2018						December 31, 2017
	Principal Amount			Carrying Amount			Principal Amount			Carrying Amount
	($ in millions)
7.25% senior notes due 2018	$	44		$	44		$	44		$	44
Floating rate senior notes due 2019	380			380			380			380
6.625% senior notes due 2020	437			437			437			437
6.875% senior notes due 2020	227			227			227			227
6.125% senior notes due 2021	548			548			548			548
5.375% senior notes due 2021	267			267			267			267
4.875% senior notes due 2022	451			451			451			451
8.00% senior secured second lien notes due 2022	1,416			1,847			1,416			1,895
5.75% senior notes due 2023	338			338			338			338
8.00% senior notes due 2025	1,300			1,290			1,300			1,290
5.5% convertible senior notes due 2026 ^(a)(b)	1,250			852			1,250			837
8.00% senior notes due 2027	1,300			1,298			1,300			1,298
2.25% contingent convertible senior notes due 2038 ^(a)	9			8			9			8
Term loan due 2021	1,233			1,233			1,233			1,233
Revolving credit facility	506			506			781			781
Debt issuance costs	—			(57		)	—			(63		)
Interest rate derivatives	—			1			—			2
Total debt, net	9,706			9,670			9,981			9,973
Less current maturities of long-term debt, net ^(c)	(433		)	(432		)	(53		)	(52		)
Total long-term debt, net	$	9,273		$	9,238		$	9,928		$	9,921

___________________________________________

(a)

We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense through the first demand repurchase date, as applicable, at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.25% Contingent Convertible Senior Notes due 2038 and our 5.5% Convertible Senior Notes due 2026 are 8.0% and 11.5% , respectively.


(b)	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 2018.


(c)	As of June 30, 2018 , current maturities of long-term debt, net includes our 7.25% Senior Notes due December 2018, our Floating Rate Senior Notes due April 2019, and due to the holders’ put option, our 2.25% Contingent Convertible Notes due December 2038.

Debt Retirements

In the Prior Period, we retired $1.604 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $1.746 billion . For the open market repurchases and tender offers, we recorded aggregate net gains of approximately $191 million and $184 million in the Prior Quarter and the Prior Period, respectively.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Revolving Credit Facility

We have a senior secured revolving credit facility currently subject to a $3.8 billion borrowing base that matures in December 2019. As of June 30, 2018 , we had outstanding borrowings of $506 million under the revolving credit facility and had used $183 million of the revolving credit facility for various letters of credit. Borrowings under the revolving credit facility bear interest at a variable rate. In the Current Quarter, we completed a scheduled borrowing base redetermination review and our lenders reaffirmed our $3.8 billion borrowing base. Our next scheduled borrowing base redetermination is scheduled for the fourth quarter of 2018.

Our revolving credit facility is subject to various financial and other covenants. The terms of the revolving credit facility include covenants limiting, among other things, our ability to incur additional indebtedness, make investments or loans, create liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. As of June 30, 2018 , we were in compliance with all applicable financial covenants under the credit agreement and we were able to borrow up to the full availability under the revolving credit facility.

Fair Value of Debt

We estimate the fair value of our senior notes based on the market value of our publicly traded debt as determined based on the yield of our senior notes (Level 1). The fair value of all other debt is based on a market approach using estimates provided by an independent investment financial data services firm (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below:



	June 30, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			($ in millions)
Short-term debt (Level 1)	$	432	$	432	$	52	$	53
Long-term debt (Level 1)	$	2,256	$	2,261	$	2,633	$	2,629
Long-term debt (Level 2)	$	6,982	$	7,215	$	7,286	$	7,301


4.	Contingencies and Commitments

There have been no material developments in previously reported legal or environmental contingencies or commitments other than the items discussed below. For a discussion of commitments and contingencies, see “Contingencies and Commitments,” Note 4 to the Consolidated Financial Statements in our 2017 Form 10-K.

Contingencies

Regulatory and Related Proceedings . We have previously disclosed receiving U.S. Postal Service and state subpoenas seeking information on our royalty payment practices. The U.S. Postal Service inquiry and all such outstanding state subpoenas have been resolved.

We have also previously disclosed defending lawsuits alleging various violations of the Sherman Antitrust Act and state antitrust laws. In 2016, putative class action lawsuits were filed in the U.S. District Court for the Western District of Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the U.S. District Court of Kansas, in each case against us and other defendants. The lawsuits generally allege that, since 2007 and continuing through April 2013, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties in the Anadarko Basin containing producing oil and natural gas wells. The lawsuits seek damages, attorney’s fees, costs and interest, as well as enjoinment from adopting practices or plans that would restrain competition in a similar manner as alleged in the lawsuits. On April 12, 2018, we reached a tentative settlement to resolve substantially all Oklahoma civil class action antitrust cases for an immaterial amount.

On July 28, 2017, OOGC America LLC (OOGC) filed a demand for arbitration with the American Arbitration Association against Chesapeake Exploration, L.L.C., our wholly owned subsidiary, in connection with OOGC’s purchase of certain oil and gas leases and other assets pursuant to a Purchase and Sale Agreement entered into on October 10, 2010. In connection with the sale, we also entered into a Development Agreement with OOGC, dated November 15, 2010 (the “Development Agreement”), which governs each of our rights and obligations with respect to the sale, including the transportation and marketing of oil and gas. OOGC’s breach of contract, breach of agency and fiduciary duties and other claims generally allege, among other things, that we subjected OOGC to excessive rates for gathering and other services provided for under the Development Agreement and interfered with OOGC’s right to audit the documents that supported those rates. OOGC seeks relief that may be material, including unspecified damages, attorneys’ fees, costs and expenses, disgorgement and various declaratory judgments. We intend to vigorously defend these claims.

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

Commitments

Gathering, Processing and Transportation Agreements

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

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



	June 30, 2018
	($ in millions)
2018	$	537
2019	1,047
2020	992
2021	900
2022	792
2023 – 2035	4,434
Total	$	8,702

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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


5.	Other Liabilities

Other current liabilities as of June 30, 2018 and December 31, 2017 are detailed below:



	June 30, 2018		December 31, 2017
	($ in millions)
Revenues and royalties due others	$	488	$	612
Accrued drilling and production costs	261		216
Joint interest prepayments received	81		74
Accrued compensation and benefits	156		214
Other accrued taxes	104		43
Other	187		296
Total other current liabilities	$	1,277	$	1,455

Other long-term liabilities as of June 30, 2018 and December 31, 2017 are detailed below:



	June 30, 2018		December 31, 2017
	($ in millions)
CHK Utica ORRI conveyance obligation ^(a)	$	—	$	156
Unrecognized tax benefits	81		101
Other	96		97
Total other long-term liabilities	$	177	$	354

____________________________________________

(a)

In the Current Quarter, we repurchased previously conveyed overriding royalty interests (ORRI) from the CHK Utica, L.L.C. investors and extinguished our obligation to convey future ORRIs to the CHK Utica, L.L.C. investors for combined consideration of $199 million . The total CHK Utica ORRI conveyance obligation extinguished in the Current Quarter was $183 million , of which, $30 million was recorded in current liabilities and $153 million was recorded in long-term liabilities. The fair value of the consideration allocated to the extinguishment of liability, $122 million , was less than the carrying amount of the conveyance obligation and resulted in a gain of $61 million recognized in other income on our condensed consolidated statement of operations. The fair value of the consideration allocated to the purchase of ORRIs on proved producing properties was $77 million and recorded in proved oil and natural gas properties in our condensed consolidated balance sheet.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


6.	Income Taxes

We estimate our annual effective tax rate for continuing operations in recording our quarterly income tax provision (or benefit) for the various jurisdictions in which we operate. The tax effects of statutory rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred tax assets are excluded from the determination of our estimated annual effective tax rate as such items are recognized as discrete items in the quarter in which they occur.

For the Current Quarter, our estimated annual effective tax rate remains nominal as a result of having a full valuation allowance against our net deferred tax asset. Based on our projected operating results for the subsequent 2018 quarters, we project remaining in a net deferred tax asset position as of December 31, 2018. Based on all available positive and negative evidence, including estimates of future taxable income, we believe it is more-likely-than-not that these deferred tax assets will not be realized. A significant piece of objectively verifiable negative evidence evaluated is the cumulative loss incurred over the rolling three-year period ending June 30, 2018. Such evidence limits our ability to consider various forms of subjective positive evidence, such as our projections for future growth and earnings. A valuation allowance was recorded against substantially all of our net deferred tax asset as of December 31, 2017 and against all of our net deferred tax asset as of June 30, 2018.

We are subject to U.S. federal income tax as well as income and capital taxes in various state jurisdictions in which we operate. We recorded a $9 million income tax benefit in the Current Quarter and the Current Period. This benefit was a result of discrete items consisting of a $13 million reduction to the liability for state unrecognized tax benefits due to the expiration of applicable statutes of limitations which was partially offset by eliminating a deferred tax asset for alternative minimum tax carryforwards in the amount of $3 million and recording additional state income tax expense of $1 million relating primarily to amended state income tax returns. A further reduction to the liability for state unrecognized tax benefits was also recorded against interest expense in the amount of $4 million .

On December 22, 2017, the President of the United States signed into law the Tax Act, which substantially revised numerous areas of U.S. federal income tax law, including reducing the tax rate for corporations from a maximum rate of 35% to a flat rate of 21% and eliminating the corporate alternative minimum tax (AMT). The various estimates included in determining our tax provision as of December 31, 2017 remain provisional through the six months ended June 30, 2018 and may be adjusted through subsequent events such as the filing of the 2017 consolidated federal income tax return and the issuance of additional guidance such as new Treasury Regulations. Moreover, we are still in the process of evaluating the full impact of the Tax Act both at the federal and state level.


7.	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
	(in thousands)
Unvested restricted stock as of January 1, 2018	13,178		$	6.37
Granted	4,765		$	3.57
Vested	(5,207	)	$	7.73
Forfeited	(1,295	)	$	6.13
Unvested restricted stock as of June 30, 2018	11,441		$	4.61

The aggregate intrinsic value of restricted stock that vested during the Current Period was approximately $17 million based on the stock price at the time of vesting.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of June 30, 2018 , there was approximately $40 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 2.20 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 an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account our dividend policy, over the expected life of the option. We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Period:



Expected option life – years	6.0
Volatility	63.55	%
Risk-free interest rate	2.72	%
Dividend yield	—	%

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



	Number of Shares Underlying Options		Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value ^(a)
	(in thousands)					($ in millions)
Outstanding as of January 1, 2018	16,285		$	8.25	7.73	$	1
Granted	3,611		$	3.01
Exercised	—		$	—		$	—
Expired	(602	)	$	13.83
Forfeited	(995	)	$	5.45
Outstanding as of June 30, 2018	18,299		$	7.18	7.71	$	14
Exercisable as of June 30, 2018	8,250		$	10.73	6.34	$	3

___________________________________________


(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, 2018 , there was $20 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.94 years .

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	($ in millions)
General and administrative expenses	$	8	$	12	$	15	$	20
Oil and natural gas properties	2		3		4		7
Oil, natural gas and NGL production expenses	1		4		3		7
Total restricted stock and stock option compensation	$	11	$	19	$	22	$	34

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Liability-Classified Awards

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

For PSUs granted in 2017 and 2016, performance metrics include a total shareholder return (TSR) component, which can range from 0% to 100% and an operational performance component based on finding and development costs, which can range from 0% to 100% , resulting in a maximum payout of 200% . The payout percentage for the 2016 and 2017 PSU awards is capped at 100% if our absolute TSR is less than zero . The PSUs are settled in cash on the third anniversary of the awards. We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the 2017 and 2016 PSU awards.



Grant Date Assumptions
Assumption	2017 Awards		2016 Awards
Volatility	80.65	%	49.74	%
Risk-free interest rate	1.54	%	1.13	%
Dividend yield for value of awards	—	%	—	%



Reporting Period Assumptions
Assumption	2017 Awards		2016 Awards
Volatility	51.31	%	59.84	%
Risk-free interest rate	2.43	%	2.11	%
Dividend yield for value of awards	—	%	—	%

The PSUs are subsequently adjusted, based on adjustments to the above assumptions through the end of each subsequent reporting period, through the end of the performance period.

For PSUs granted in 2018, performance metrics include an operational performance component based on a ratio of cumulative earnings before interest expense, income taxes, and depreciation, depletion and amortization expense (EBITDA) to capital expenditures, for which payout can range from 0% to 200% . The vested PSUs are settled in cash on each of the three annual vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the PSUs. The PSUs are subsequently adjusted, based on changes in our stock price through the end of each subsequent reporting period, through the end of the performance period.

Cash Restricted Stock Units . In the Current Period, we granted CRSUs to employees that vest straight-line over a three-year period and are settled in cash on each of the three annual vesting dates. The ultimate amount earned is based on the closing price of our common stock on each of the vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the CRSUs. The CRSUs are subsequently adjusted, based on changes in our stock price through the end of each subsequent reporting period, through the end of each vesting period.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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



		Grant Date Fair Value		June 30, 2018
	Units	Grant Date Fair Value		Fair Value		Vested Liability
		($ in millions)		($ in millions)
2018 PSU Awards:
Payable 2019, 2020 and 2021	3,992,358	$	12	$	21	$	—
2017 PSU Awards:
Payable 2020	1,217,774	$	8	$	8	$	5
2016 PSU Awards:
Payable 2019	2,348,893	$	10	$	16	$	14
2018 CRSU Awards:
Payable 2019, 2020 and 2021	16,367,724	$	49	$	86	$	—

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


8.	Derivative and Hedging Activities

We use derivative instruments to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility. All of our oil, natural gas and NGL derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty. None of our open oil, natural gas and NGL derivative instruments were designated for hedge accounting as of June 30, 2018 or December 31, 2017.

Oil, Natural Gas and NGL Derivatives

As of June 30, 2018 and December 31, 2017, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:


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


•	Options : We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.


•	Call Swaptions : We sell call swaptions to counterparties that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time.

•

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


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

The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of June 30, 2018 and December 31, 2017 are provided below:



	June 30, 2018				December 31, 2017
	Notional Volume	Fair Value			Notional Volume	Fair Value
		($ in millions)				($ in millions)
Oil (mmbbl):
Fixed-price swaps	26	$	(271	)	21	$	(151	)
Three-way collars	1	(14		)	2	(10		)
Call swaptions	2	(32		)	2	(13		)
Basis protection swaps	11	6			11	(9		)
Total oil	40	(311		)	36	(183		)
Natural gas (bcf):
Fixed-price swaps	240	3			532	149
Three-way collars	87	—			—	—
Collars	24	2			47	11
Call options	77	—			110	(3		)
Basis protection swaps	45	(1		)	65	(7		)
Total natural gas	473	4			754	150
NGL (mmgal):
Fixed-price swaps	114	(11		)	33	(2		)
Total estimated fair value		$	(318	)		$	(35	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

Effect of Derivative Instruments – Condensed Consolidated Balance Sheets

The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017 on a gross basis and after same-counterparty netting:



Balance Sheet Classification	Gross Fair Value			Amounts Netted in the Consolidated Balance Sheets			Net Fair Value Presented in the Consolidated Balance Sheet
	($ in millions)
As of June 30, 2018
Commodity Contracts:
Short-term derivative asset	$	20		$	(20	)	$	—
Long-term derivative asset	7			(7		)	—
Short-term derivative liability	(317		)	20			(297		)
Long-term derivative liability	(28		)	7			(21		)
Total derivatives	$	(318	)	$	—		$	(318	)

As of December 31, 2017
Commodity Contracts:
Short-term derivative asset	$	157		$	(130	)	$	27
Short-term derivative liability	(188		)	130			(58		)
Long-term derivative liability	(4		)	—			(4		)
Total derivatives	$	(35	)	$	—		$	(35	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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,
	2018			2017			2018			2017
	($ in millions)
Oil, natural gas and NGL revenues	$	1,233		$	1,079		$	2,593		$	2,226
Gains (losses) on undesignated oil, natural gas and NGL derivatives	(244		)	207			(351		)	539
Losses on terminated cash flow hedges	(7		)	(7		)	(17		)	(17		)
Total oil, natural gas and NGL revenues	$	982		$	1,279		$	2,225		$	2,748

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

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



	Three Months Ended June 30,
	2018						2017
	Before Tax			After Tax			Before Tax			After Tax
	($ in millions)
Balance, beginning of period	$	(104	)	$	(47	)	$	(139	)	(82		)
Losses reclassified to income	7			7			7			7
Balance, end of period	$	(97	)	$	(40	)	(132		)	(75		)

	Six Months Ended June 30,
	2018						2017
	Before Tax			After Tax			Before Tax			After Tax
	($ in millions)
Balance, beginning of period	$	(114	)	$	(57	)	$	(153	)	$	(96	)
Net change in fair value	—			—			4			4
Losses reclassified to income	17			17			17			17
Balance, end of period	$	(97	)	$	(40	)	$	(132	)	$	(75	)

The accumulated other comprehensive loss as of June 30, 2018 represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. Remaining deferred gain or loss amounts will be recognized in earnings in the month for which the original contract months are to occur. As of June 30, 2018 , we expect to transfer approximately $33 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022.

Credit Risk Considerations

Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are highly rated or deemed by us to have acceptable credit strength and deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of June 30, 2018 , our oil, natural gas and NGL derivative instruments were spread among 11 counterparties.

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(Unaudited)

Hedging Arrangements

Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our revolving credit facility. The contracts entered into with these counterparties are secured by the same collateral that secures our revolving credit facility. In addition, we enter into bilateral hedging agreements with other counterparties. The counterparties’ and our obligations under the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds. As of June 30, 2018 and December 31, 2017 , we did not have any cash collateral balances for our 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, 2018 and December 31, 2017:



	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
			($ in millions)
As of June 30, 2018
Derivative Assets (Liabilities):
Commodity assets	$	—	$	20		$	7		$	27
Commodity liabilities	—		(293		)	(52		)	(345		)
Total derivatives	$	—	$	(273	)	$	(45	)	$	(318	)

As of December 31, 2017
Derivative Assets (Liabilities):
Commodity assets	$	—	$	—		$	8		$	8
Commodity liabilities	—		(20		)	(23		)	(43		)
Total derivatives	$	—	$	(20	)	$	(15	)	$	(35	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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



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

Balance, as of January 1, 2017	$	(10	)
Total gains (losses) (realized/unrealized):
Included in earnings ^(a)	19
Total purchases, issuances, sales and settlements:
Settlements	1
Balance, as of June 30, 2017	$	10

___________________________________________



(a)		Commodity Derivatives
		Commodity Derivatives
		2018			2017
		($ in millions)
	Total gains (losses) included in earnings for the period	$	(32	)	$	19
	Change in unrealized gains (losses) related to assets still held at reporting date	$	(30	)	$	12

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

The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of natural gas, market volatility and credit risk of counterparties. Changes in these inputs 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, and adverse changes to our counterparties’ creditworthiness decreases the fair value of our 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, 2018 :



Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value June 30, 2018
				($ in millions)
Oil trades	Oil price volatility curves	17.16% – 30.26%	25.01%	$	(47	)
Natural gas trades	Natural gas price volatility curves	14.23% – 46.86%	18.30%	$	2

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(Unaudited)


9.	Oil and Natural Gas Property Transactions

Under full cost accounting rules, we accounted for the sales of oil and natural gas properties discussed below as adjustments to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves.

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

In the Prior Period, we sold portions of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $915 million , subject to certain customary closing adjustments. Included in the sales were approximately 119,500 net acres and interests in 576 wells that were producing approximately 80 mmcf of gas per day at the time of closing. Also in the Prior Quarter and the Prior Period, we received proceeds of approximately $63 million and $83 million , respectively, net of post-closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.

Volumetric Production Payments

A VPP is a limited-term overriding royalty interest in oil and natural gas reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is non-recourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores.

As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. Future costs will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which the production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all.

We have committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.

As of June 30, 2018 , we had the following VPP outstanding:

Volume Sold

VPP #

Date of VPP

Location

Proceeds

Oil

Natural Gas

NGL

Total

($ in millions)

(mmbbl)

(bcf)

(mmbbl)

(bcfe)

May 2011

Mid-Continent

853

1.7

138

4.8

177

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The volumes remaining to be delivered on behalf of our VPP buyers as of June 30, 2018 were as follows:

Volume Remaining as of June 30, 2018

VPP #

Term Remaining

Oil

Natural Gas

NGL

Total

(in months)

(mmbbl)

(bcf)

(mmbbl)

(bcfe)

0.3

28.5

0.8

34.8


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 first quarter of 2018 using the modified retrospective approach. We applied the new standard to all contracts that were not completed as of January 1, 2018 and reflected the aggregate effect of all modifications in determining and allocating the transaction price. The cumulative effect of adoption of $8 million did not have a material impact on our condensed consolidated financial statements. However, the adoption did result in certain purchase and sale contracts being recorded on a net basis, as an agent, rather than on a gross basis, as principal, due to management’s evaluation under new considerations within Topic 606 that indicated we do not have control over the specified commodity in purchase and sale contracts with the same counterparty. Such presentation change did not have an impact on income (loss) from operations, earnings per share or cash flows.

In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our condensed consolidated balance sheet and condensed consolidated statement of operations was as follows:



	Before adoption of ASC 606			Adjustments			As Reported
				($ in millions)
Balance Sheet as of June 30, 2018
Other current liabilities	$	1,275		$	2		$	1,277
Other long-term liabilities	$	172		$	5		$	177
Accumulated deficit	$	(16,249	)	$	(8	)	$	(16,257	)

Statement of Operations for the Three Months Ended June 30, 2018
Marketing revenues	$	1,449		$	(176	)	$	1,273
Marketing operating expenses	$	1,469		$	(177	)	$	1,292

Statement of Operations for the Six Months Ended June 30, 2018
Marketing revenues	$	2,810		$	(291	)	$	2,519
Marketing operating expenses	$	2,852		$	(292	)	$	2,560

Revenue from the sale of oil, natural gas and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products.

Revenue from contracts with customers includes the sale of our oil, natural gas and NGL production (recorded as oil, natural gas and NGL revenues in the condensed consolidated statements of operations) as well as the sale of certain of our joint interest holders’ production which we purchase under joint operating arrangements (recorded in marketing revenues in the condensed consolidated statements of operations). In connection with the marketing of these products, we obtain control of the oil, natural gas and NGL we purchase from other interest owners at defined delivery points and deliver the product to third parties, at which time revenues are recorded.

Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 days. There are no significant judgments that significantly affect the amount or timing of revenue from contracts with customers.

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(Unaudited)

We also earn revenue from other sources, including from a variety of derivative and hedging activities to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility, (recorded within oil, natural gas and NGL revenues in the condensed consolidated statements of operations) as well as a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments (recorded within marketing revenues in the condensed consolidated statements of operations).

In circumstances where we act as an agent rather than a principal, our results of operations related to oil, natural gas and NGL marketing activities are presented on a net basis. These purchase and sales contracts were accounted for as derivatives under Derivatives and Hedging (Topic 815) and were not elected as normal purchase or normal sales. We considered the principal versus agent guidance in Topic 606 in determining whether the gains and losses on these derivatives should be reported on a gross or net basis .

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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



	Three Months Ended June 30, 2018
	Oil			Natural Gas			NGL			Total
	($ in millions)
Marcellus	$	—		$	169		$	—		$	169
Haynesville	1			199			—			200
Eagle Ford	389			42			46			477
Utica	62			103			61			226
Mid-Continent	62			15			12			89
Powder River Basin	52			11			9			72
Revenue from contracts with customers	566			539			128			1,233
Losses on oil, natural gas and NGL derivatives	(202		)	(35		)	(14		)	(251		)
Oil, natural gas and NGL revenue	$	364		$	504		$	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

	Six Months Ended June 30, 2018
	Oil			Natural Gas			NGL			Total
	($ in millions)
Marcellus	$	—		$	463		$	—		$	463
Haynesville	2			409			—			411
Eagle Ford	749			84			85			918
Utica	119			219			113			451
Mid-Continent	138			47			30			215
Powder River Basin	95			23			17			135
Revenue from contracts with customers	1,103			1,245			245			2,593
Losses on oil, natural gas and NGL derivatives	(288		)	(67		)	(13		)	(368		)
Oil, natural gas and NGL revenue	$	815		$	1,178		$	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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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, 2018 and December 31, 2017 are detailed below:



	June 30, 2018			December 31, 2017
	($ in millions)
Oil, natural gas and NGL sales	$	801		$	959
Joint interest	206			209
Other	68			184
Allowance for doubtful accounts	(15		)	(30		)
Total accounts receivable, net	$	1,060		$	1,322


11.	Investments

In the Current Period, FTS International, Inc. (NYSE: FTSI) completed an initial public offering. Due to the offering, the ownership percentage of our equity method investment in FTSI decreased from approximately 29% to 24% and resulted in a gain of $78 million . In addition, we sold approximately 4.3 million shares of FTSI in the offering for net proceeds of approximately $74 million and recognized a gain of $61 million decreasing our ownership percentage to approximately 20% . We continue to hold approximately 22.0 million shares in the publicly traded company.


12.	Impairments

In the Current Quarter, we have determined that certain of our other fixed assets will either be sold or disposed before the end of their useful lives indicating the carrying value may not be recoverable. As a result, we recognized an impairment loss of $42 million in the Current Quarter for the difference between the carrying amount and fair value of the assets.


13.	Other Operating Expenses

In the Prior Quarter and the Prior Period, we terminated future natural gas transportation commitments related to divested assets for cash payments of $23 million and $126 million . In the Prior Period, we paid $290 million to assign an oil transportation agreement to a third party.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


14.	Restructuring and Other Termination Costs

Workforce Reduction

On January 30, 2018, we underwent a reduction in workforce impacting approximately 13% of employees across all functions, primarily on our Oklahoma City campus. In connection with the reduction, we incurred a total charge in the Current Period of approximately $38 million for one-time termination benefits. The following table summarizes our restructuring liabilities:



	Other Current Liabilities
	($ in millions)
Balance as of December 31, 2017	$	—
Initial restructuring recognition on January 30, 2018	38
Termination benefits paid	(38		)
Balance as of June 30, 2018	$	—


15.	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, 2018 and December 31, 2017:



	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value
	($ in millions)
As of June 30, 2018
Financial Assets (Liabilities):
Other current assets	$	53		$	—	$	—	$	53
Other current liabilities	(52		)	—		—		(52		)
Total	$	1		$	—	$	—	$	1

As of December 31, 2017
Financial Assets (Liabilities):
Other current assets	$	57		$	—	$	—	$	57
Other current liabilities	(60		)	—		—		(60		)
Total	$	(3	)	$	—	$	—	$	(3	)

See Note 3 for information regarding fair value measurement of our debt instruments. See Note 8 for information regarding fair value measurement of our derivatives.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


16.	Condensed Consolidating Financial Information

Chesapeake Energy Corporation is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes, contingent convertible senior notes, term loan and revolving credit facility listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors.

The tables below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2018 and December 31, 2017 and for the three and six months ended June 30, 2018 and 2017. This financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF JUNE 30, 2018

($ in millions)



	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	5		$	1	$	2	$	(5	)	$	3
Other current assets	63			1,173		1		—			1,237
Intercompany receivable, net	8,132			31		175		(8,338		)	—
Total Current Assets	8,200			1,205		178		(8,343		)	1,240
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	521			9,129		25		—			9,675
Other property and equipment, net	—			1,164		—		—			1,164
Property and equipment held for sale, net	—			11		—		—			11
Total Property and Equipment, Net	521			10,304		25		—			10,850
LONG-TERM ASSETS:
Other long-term assets	44			207		—		—			251
Investments in subsidiaries and intercompany advances	907			78		—		(985		)	—
TOTAL ASSETS	$	9,672		$	11,794	$	203	$	(9,328	)	$	12,341

CURRENT LIABILITIES:
Current liabilities	$	561		$	2,315	$	2	$	(5	)	$	2,873
Intercompany payable, net	32			8,306		—		(8,338		)	—
Total Current Liabilities	593			10,621		2		(8,343		)	2,873
LONG-TERM LIABILITIES:
Long-term debt, net	9,238			—		—		—			9,238
Other long-term liabilities	81			266		—		—			347
Total Long-Term Liabilities	9,319			266		—		—			9,585
EQUITY:
Chesapeake stockholders’ equity (deficit)	(240		)	907		78		(985		)	(240		)
Noncontrolling interests	—			—		123		—			123
Total Equity (Deficit)	(240		)	907		201		(985		)	(117		)
TOTAL LIABILITIES AND EQUITY	$	9,672		$	11,794	$	203	$	(9,328	)	$	12,341

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2017

($ in millions)



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	5		$	1		$	2		$	(3	)	$	5
Other current assets	154			1,364			3			(1		)	1,520
Intercompany receivable, net	8,697			436			—			(9,133		)	—
Total Current Assets	8,856			1,801			5			(9,137		)	1,525
PROPERTY AND EQUIPMENT:
Oil and natural gas properties at cost, based on full cost accounting, net	435			8,888			27			—			9,350
Other property and equipment, net	—			1,314			—			—			1,314
Property and equipment held for sale, net	—			16			—			—			16
Total Property and Equipment, Net	435			10,218			27			—			10,680
LONG-TERM ASSETS:
Other long-term assets	52			168			—			—			220
Investments in subsidiaries and intercompany advances	806			(146		)	—			(660		)	—
TOTAL ASSETS	$	10,149		$	12,041		$	32		$	(9,797	)	$	12,425

CURRENT LIABILITIES:
Current liabilities	$	190		$	2,168		$	2		$	(4	)	$	2,356
Intercompany payable, net	433			8,648			52			(9,133		)	—
Total Current Liabilities	623			10,816			54			(9,137		)	2,356
LONG-TERM LIABILITIES:
Long-term debt, net	9,921			—			—			—			9,921
Other long-term liabilities	101			419			—			—			520
Total Long-Term Liabilities	10,022			419			—			—			10,441
EQUITY:
Chesapeake stockholders’ equity (deficit)	(496		)	806			(146		)	(660		)	(496		)
Noncontrolling interests	—			—			124			—			124
Total Equity (Deficit)	(496		)	806			(22		)	(660		)	(372		)
TOTAL LIABILITIES AND EQUITY	$	10,149		$	12,041		$	32		$	(9,797	)	$	12,425

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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
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
Marketing	—			1,292			—			—			1,292
General and administrative	—			90			1			—			91
Provision for legal contingencies, net	—			4			—			—			4
Oil, natural gas and NGL depreciation, depletion and amortization	—			270			1			—			271
Depreciation and amortization of other assets	—			19			—			—			19
Impairments	—			46			—			—			46
Other operating income	—			(1		)	—			—			(1		)
Net gains on sales of fixed assets	—			(1		)	—			—			(1		)
Total Operating Expenses	—			2,221			4			—			2,225
INCOME FROM OPERATIONS	—			30			—			—			30
OTHER INCOME (EXPENSE):
Interest expense	(117		)	—			—			—			(117		)
Other income	—			62			—			—			62
Equity in net earnings (losses) of subsidiary	91			(1		)	—			(90		)	—
Total Other Income (Expense)	(26		)	61			—			(90		)	(55		)
INCOME (LOSS) BEFORE INCOME TAXES	(26		)	91			—			(90		)	(25		)
INCOME TAX BENEFIT	(9		)	—			—			—			(9		)
NET INCOME (LOSS)	(17		)	91			—			(90		)	(16		)
Net income attributable to noncontrolling interests	—			—			(1		)	—			(1		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(17		)	91			(1		)	(90		)	(17		)
Other comprehensive income	—			7			—			—			7
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	(17	)	$	98		$	(1	)	$	(90	)	$	(10	)

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2017

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	1,273		$	6		$	—		$	1,279
Marketing	—			1,002			—			—			1,002
Total Revenues	—			2,275			6			—			2,281
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			140			—			—			140
Oil, natural gas and NGL gathering, processing and transportation	—			355			2			—			357
Production taxes	—			21			—			—			21
Marketing	—			1,027			—			—			1,027
General and administrative	3			67			—			—			70
Provision for legal contingencies, net	—			17			—			—			17
Oil, natural gas and NGL depreciation, depletion and amortization	—			202			—			—			202
Depreciation and amortization of other assets	—			21			—			—			21
Net losses on sales of fixed assets	—			1			—			—			1
Other operating expense	—			26			—			—			26
Total Operating Expenses	3			1,877			2			—			1,882
INCOME (LOSS) FROM OPERATIONS	(3		)	398			4			—			399
OTHER INCOME (EXPENSE):
Interest income (expense)	(95		)	2			—			—			(93		)
Gains on purchases or exchanges of debt	191			—			—			—			191
Other expense	—			(1		)	—			—			(1		)
Equity in net earnings of subsidiary	402			3			—			(405		)	—
Total Other Income	498			4			—			(405		)	97
INCOME BEFORE INCOME TAXES	495			402			4			(405		)	496
INCOME TAX EXPENSE	1			—			—			—			1
NET INCOME	494			402			4			(405		)	495
Net income attributable to noncontrolling interests	—			—			(1		)	—			(1		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	494			402			3			(405		)	494
Other comprehensive income	—			7			—			—			7
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	494		$	409		$	3		$	(405	)	$	501

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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
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
Marketing	—			2,560			—			—			2,560
General and administrative	—			162			1			—			163
Restructuring and other termination costs	—			38			—			—			38
Provision for legal contingencies, net	—			9			—			—			9
Oil, natural gas and NGL depreciation, depletion and amortization	—			537			2			—			539
Depreciation and amortization of other assets	—			37			—			—			37
Impairments	—			46			—			—			46
Other operating income	—			(1		)	—			—			(1		)
Net losses on sales of fixed assets	—			7			—			—			7
Total Operating Expenses	—			4,430			6			—			4,436
INCOME FROM OPERATIONS	—			305			3			—			308
OTHER INCOME (EXPENSE):
Interest expense	(240		)	—			—			—			(240		)
Gains on investments	—			139			—			—			139
Other income	—			62			—			—			62
Equity in net earnings (losses) of subsidiary	507			1			—			(508		)	—
Total Other Income (Expense)	267			202			—			(508		)	(39		)
INCOME BEFORE INCOME TAXES	267			507			3			(508		)	269
INCOME TAX BENEFIT	(9		)	—			—			—			(9		)
NET INCOME	276			507			3			(508		)	278
Net income attributable to noncontrolling interests	—			—			(2		)	—			(2		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	276			507			1			(508		)	276
Other comprehensive income	—			17			—			—			17
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	276		$	524		$	1		$	(508	)	$	293

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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, 2017

($ in millions)



	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	2,736	$	12		$	—		$	2,748
Marketing	—			2,286		—			—			2,286
Total Revenues	—			5,022		12			—			5,034
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			275		—			—			275
Oil, natural gas and NGL gathering, processing and transportation	—			708		4			—			712
Production taxes	—			43		—			—			43
Marketing	—			2,355		—			—			2,355
General and administrative	3			131		1			—			135
Provision for legal contingencies, net	—			15		—			—			15
Oil, natural gas and NGL depreciation, depletion and amortization	—			397		2			—			399
Depreciation and amortization of other assets	—			42		—			—			42
Other operating expense	—			417		—			—			417
Net losses on sales of fixed assets	—			1		—			—			1
Total Operating Expenses	3			4,384		7			—			4,394
INCOME (LOSS) FROM OPERATIONS	(3		)	638		5			—			640
OTHER INCOME (EXPENSE):
Interest expense	(190		)	2		—			—			(188		)
Gains on purchases or exchanges of debt	184			—		—			—			184
Other income	—			2		—			—			2
Equity in net earnings of subsidiary	645			3		—			(648		)	—
Total Other Income (Expense)	639			7		—			(648		)	(2		)
INCOME BEFORE INCOME TAXES	636			645		5			(648		)	638
INCOME TAX EXPENSE	2			—		—			—			2
NET INCOME	634			645		5			(648		)	636
Net income attributable to noncontrolling interests	—			—		(2		)	—			(2		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	634			645		3			(648		)	634
Other comprehensive income	—			21		—			—			21
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	634		$	666	$	3		$	(648	)	$	655

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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		$	1,006		$	5		$	(8	)	$	1,091

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(979		)	—			—			(979		)
Acquisitions of proved and unproved properties	—			(191		)	—			—			(191		)
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	—			(643		)	—			—			(643		)

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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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2017

($ in millions)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By (Used In) Operating Activities	$	2		$	(64	)	$	8		$	(4	)	$	(58	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(1,031		)	—			—			(1,031		)
Acquisitions of proved and unproved properties	—			(162		)	—			—			(162		)
Proceeds from divestitures of proved and unproved properties	—			951			—			—			951
Additions to other property and equipment	—			(7		)	—			—			(7		)
Other investing activities	—			26			—			—			26
Net Cash Used In Investing Activities	—			(223		)	—			—			(223		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings	2,551			—			—			—			2,551
Payments on revolving credit facility borrowings	(1,976		)	—			—			—			(1,976		)
Proceeds from issuance of senior notes, net	742			—			—			—			742
Cash paid to purchase debt	(1,746		)	—			—			—			(1,746		)
Cash paid for preferred stock dividends	(137		)	—			—			—			(137		)
Other financing activities	(38		)	(2		)	(7		)	25			(22		)
Intercompany advances, net	(287		)	288			(1		)	—			—
Net Cash Provided by (Used In) Financing Activities	(891		)	286			(8		)	25			(588		)
Net increase (decrease) in cash and cash equivalents	(889		)	(1		)	—			21			(869		)
Cash and cash equivalents, beginning of period	904			2			1			(25		)	882
Cash and cash equivalents, end of period	$	15		$	1		$	1		$	(4	)	$	13

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


17.	Subsequent Events

On July 26, 2018 we entered into a purchase and sale agreement (the “Purchase Agreement”) with EAP Ohio, LLC, a private oil and gas company headquartered in Houston, Texas (“Encino”), pursuant to which Encino agreed to purchase all of our approximately 1,500,000 gross ( 900,000 net) acres in Ohio, of which approximately 320,000 net acres are prospective for the Utica Shale with approximately 920 producing wells, along with related property and equipment (collectively, the “Designated Properties”) for a purchase price of approximately $2.0 billion , with additional contingent payments to us of up to $100 million comprised of $50 million in consideration in each case if, on or prior to December 31, 2019, there is a period of twenty ( 20 ) trading days out of a period of thirty ( 30 ) consecutive trading days where (i) the average of the NYMEX natural gas strip pries for the months comprising the year 2022 equals or exceeds $3.00 /mmbtu as calculated pursuant to the agreement, and (ii) the average of the NYMEX natural gas price strip prices for the months comprising the year 2023 equals or exceeds $3.25 /mmbtu as calculated pursuant to the agreement .

Average net daily production from the Designated Properties was approximately 107,000 boe during 2017 consisting of 427,000 mcf of natural gas, 26,000 barrels of natural gas liquids and 10,000 barrels of oil. As of December 31, 2017, net proved reserves associated with the Designated Properties were 480 million boe ( 72% natural gas, 23% natural gas liquids and 5% oil).

Closing of the transaction is subject to customary conditions, including waiver of certain pre-existing preferential purchase rights, expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, other regulatory approvals and certain other closing conditions. Closing is expected to occur in the fourth quarter of 2018, contingent upon satisfaction of such closing conditions and the absence of termination rights. We expect to apply the net proceeds toward the reduction of debt.

Pursuant to the Purchase Agreement, the purchase price is subject to customary adjustment provisions, including for results of operations, adjustments for title and environmental defects and preferential purchase rights. The Purchase Agreement also contains customary representations, warranties, covenants and indemnities.

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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 2017 Form 10-K.

We are an independent exploration and production company engaged in the acquisition, exploration and development of properties for the production of 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 14,700 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 and East Texas.

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, and improving margins through financial discipline and operating efficiencies. Our capital program is focused on investments that can improve our cash flow generating ability even in a challenging commodity price environment. Although we expect our forecasted capital expenditures in 2018 to be lower compared to 2017, we anticipate modest production growth from both our oil-producing and natural gas-producing assets, adjusted for asset sales. Our ability to reduce capital expenditures while still growing production is primarily the result of improved drilling and completion efficiencies and improved well performance. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation, general and administrative and interest expenses) and improve our production volumes from existing wells.

We believe that our dedication to financial discipline, 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 us and our shareholders.

In 2018, our focus is concentrated on three strategic priorities:


•	reduce total debt by $2 - $3 billion;


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


•	improve margins through financial discipline and operating efficiencies.

On July 26, 2018 we announced the execution of a definitive agreement to divest of all of our assets in Ohio, which target the Utica formation. This divestiture, upon closing, will result in our meeting or making significant progress toward all three of these priorities. The following discussion and analysis presents management’s perspective of our business and material changes to our results of operations for the three and six months ended June 30, 2018 compared to the three and six months ended June 30, 2017 and in our financial condition and liquidity since December 31, 2017 .

Overview

The transformation of Chesapeake over the past five years has been significant and our progress has continued in the Current Period. Our basic strategies have not changed through the price cycles of the past several years, and we believe our recent accomplishments and achievements in the Current Period have made our company stronger. Our progress has been guided by our strategies of financial discipline, pursuing profitable and efficient growth from our captured resources, leveraging technology and our operational expertise to unlock additional domestic resources and optimizing our portfolio through business development.

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We have made significant progress towards achieving our strategic priorities to date through August 1, 2018. So far we have:


•	entered into an agreement to sell our interests in the Utica Shale operating area located in Ohio for approximately $2.0 billion, with an additional contingent payment to us of up to $100 million based on future natural gas prices;


•	repurchased the CHK Utica, L.L.C. investors’ ORRI for $199 million in an effort to remove financial and operational complexity and to improve our balance sheet;


•	sold properties in the Mid-Continent, including our Mississippian Lime assets, for aggregate proceeds of approximately $500 million;

•

received net proceeds of approximately $74 million from the sale of approximately 4.3 million shares of FTS International, Inc. (NYSE: FTSI). FTSI is a provider of hydraulic fracturing services in North America and a company in which Chesapeake has owned a significant stake since 2006. FTSI completed its initial public offering of common shares on February 6, 2018. We currently own approximately 22.0 million shares of FTSI; and


•	reduced our workforce by approximately 13% as part of an overall plan to reduce costs and better align our workforce to the needs of our business, resulting in an expected reduction of annual cash costs of approximately $70 million.

We continue to benefit from progress made over the last five years, including removing financial and operational complexity, significantly improving our balance sheet and addressing numerous legacy issues.

Financial Results



	Three Months Ended June 30,							Six Months Ended June 30,
	2018			2017		Change ^(b)		2018		2017		Change ^(b)
	($ in millions)
Net income (loss) available to common stockholders	$	(40	)	$	470	n/m		$	228	$	547	(58	)%
Net earnings (loss) per diluted common share	$	(0.04	)	$	0.47	n/m		$	0.25	$	0.59	(58	)%
Adjusted production ^(a) (mboe per day)	531			493		8	%	533		486		10	%
Total production (mboe per day)	530			528		—	%	542		528		3	%
Average sales price (per boe)	$	25.56		$	22.46	14	%	$	26.43	$	23.29	13	%
Oil, natural gas and NGL production expenses	$	138		$	140	(1	)%	$	285	$	275	4	%
Oil, natural gas and NGL gathering, processing and transportation expenses	$	340		$	357	(5	)%	$	696	$	712	(2	)%
General and administrative expenses	$	91		$	70	30	%	$	163	$	135	21	%

				June 30, 2018				December 31, 2017				Change
Total debt (principal amount)						$9,706				$9,981		(3	)%

___________________________________________


(a)	Adjusted for assets sold.

(b) n/m - not meaningful.

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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 very volatile, and may be subject to wide fluctuations in the future. The substantial decline in oil, natural gas and NGL prices from 2014 levels has negatively affected the amount of cash we generate and have available for capital expenditures and debt service and has had a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we can economically produce. 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, our ability to meet financial ratios and covenants in our financing agreements and the availability of lenders’ commitments as a result of regulatory pressures in the lending market.

As of June 30, 2018 , we had a cash balance of $3 million compared to $5 million as of December 31, 2017 , and we had a net working capital deficit of $1.633 billion as of June 30, 2018 , compared to a net working capital deficit of $831 million as of December 31, 2017 . As of June 30, 2018, our working capital deficit includes $433 million principal amount of debt due or that could be put to us in the next 12 months. As of June 30, 2018 , we had $3.096 billion of borrowing capacity available under our senior secured revolving credit facility, with outstanding borrowings of $506 million and $183 million utilized for various letters of credit. Based on our cash balance, forecasted cash flows from operating activities, availability under our revolving credit facility and expected net proceeds from the pending sale of our Utica interests, 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. 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 our debt obligations, including principal and carrying amounts of our notes.

Even though we have taken measures to mitigate the liquidity concerns facing us for the next 12 months as outlined above and in Industry Outlook in our 2017 Form 10-K, there can be no assurance that these measures will be sufficient for periods beyond the next 12 months. If needed, we may seek to access the capital markets or otherwise refin ance a portion of our outstanding indebtedness to improve our li q uidity. 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 facility. 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 elsewhere in our periodic reports and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time or control.

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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 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 24, 2018, we have downside price protection in the second half of 2018 and 2019 through the following oil, natural gas and NGL derivative instruments:



Oil Derivatives ^(a)
Year	Type of Derivative Instrument	Notional Volume	% of Forecasted Production (if applicable)	Average NYMEX Price
		(mbbls)
2018	Swaps	13,064	84%	$54.09
2018	Three-way collars	920	6%	$39.15/$47.00/$55.00
2018	Basis protection swaps	7,176	48%	$3.54
2019	Swaps	14,763	Not disclosed	$59.44
2019	Basis protection swaps	4,015	Not disclosed	$6.20

Natural Gas Derivatives ^(a)
Year	Type of Derivative Instrument	Notional Volume	% of Forecasted Production (if applicable)	Average NYMEX Price
		(bcf)
2018	Swaps	240	63%	$2.97
2018	Collars	24	6%	$3.00/$3.25
2018	Calls	33	9%	$6.27
2018	Basis protection swaps	23	6%	($0.77)
2019	Three-way collars	88	Not disclosed	$2.50/$2.80/$3.10
2019	Basis protection swaps	38	Not disclosed	$0.03
2019	Calls	22	Not disclosed	$12.00
2020	Calls	22	Not disclosed	$12.00

NGL Derivatives ^(a)
Year	Type of Derivative Instrument	Notional Volume	% of Forecasted Production (if applicable)	Average NYMEX Price
		(mmgal)
2018	Butane swaps	3	7%	$0.88
2018	Butane % of WTI swaps	3	7%	70.5% of WTI
2018	Propane swaps	31	29%	$0.79
2018	Ethane swaps	46	36%	$0.29
2018	Isobutane swaps	8	33%	$0.92
2018	Natural gasoline	23	63%	$1.42

___________________________________________


(a)	Includes amounts settled in July 2018.

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See Note 8 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.

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, 2018, these arrangements and transactions included (i) operating lease agreements, (ii) a volumetric production payment (VPP) (to purchase production and pay related production expenses and taxes in the future), (iii) open purchase commitments, (iv) open delivery commitments, (v) open drilling commitments, (vi) undrawn letters of credit, (vii) open gathering and transportation commitments, and (viii) various other commitments we enter into in the ordinary course of business that could result in a future cash obligation. See Notes 4 and 9 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of commitments and VPPs, respectively.

Debt

We are committed to decreasing the amount of debt outstanding by $2-3 billion in 2018. To accomplish this objective, we intend to use the anticipated net proceeds from the pending sale of our Utica interests, allocate our capital expenditures to the highest-return projects, deploy leading drilling and completion technology throughout our portfolio to profitably and efficiently grow, and divest additional assets to strengthen our cost structure and our portfolio. We are seeking to reduce cash costs (production, gathering, processing and transportation, general and administrative and interest expenses), 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, tender offers or otherwise, but we are under no obligation to do so.

Revolving Credit Facility

We have a senior secured revolving credit facility currently subject to a $3.8 billion borrowing base that matures in December 2019. Our next borrowing base redetermination is scheduled for the fourth quarter of 2018. Our borrowing base could be reduced at the first borrowing base redetermination after the closing date of our pending sale of our Utica interests. As of June 30, 2018 , we had $3.096 billion of borrowing capacity available under our revolving credit facility. As of June 30, 2018 , we had outstanding borrowings of $506 million under the revolving credit facility and had used $183 million of the revolving credit facility for various letters of credit. Borrowings under the facility bear interest at a variable rate. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of this report for further discussion of the terms of the revolving credit facility. As of June 30, 2018 , we were in compliance with all applicable financial covenants under the credit agreement. Our first lien secured leverage ratio was approximately 0.28 to 1.00, our interest coverage ratio was approximately 3.34 to 1.00 and our debt to capitalization ratio was approximately 0.38 to 1.00.

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Capital Expenditures

Our 2018 capital expenditures program, while planned to be approximately 7% lower than our 2017 program, is expected to generate greater capital efficiency as we focus on expanding our margins by 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 2018 capital expenditures, inclusive of capitalized interest, are $2.2 – $2.5 billion compared to our 2017 capital spending level of $2.5 billion. Management continues to review operational plans for 2018 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL.

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 27, 2018, we have received requests and posted approximately $203 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 $468 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 9 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,
	2018		2017
	($ in millions)
Cash provided by (used in) operating activities	$	1,091	$	(58	)
Proceeds from divestitures of proved and unproved properties, net	384		951
Proceeds from issuance of senior notes, net	—		742
Proceeds from issuance of credit facility borrowings, net	—		575
Proceeds from sales of other property and equipment, net	74		26
Proceeds from sales of investments	74		—
Total sources of cash and cash equivalents	$	1,623	$	2,236

Cash Flow from Operating Activities

Cash provided by operating activities was $1.091 billion in the Current Period compared to cash used by operating activities of $58 million in the Prior Period. The increase in the Current Period is primarily due to the result of higher prices for the oil and NGL we sold and higher volumes of oil and natural gas sold. Changes in cash flow from operations are largely due to 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 fixed assets, deferred income taxes and mark-to-market changes in our 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,
	2018		2017
	($ in millions)
Oil and Natural Gas Expenditures:
Drilling and completion costs	$	979	$	1,031
Acquisitions of proved and unproved properties	110		69
Interest capitalized on unproved leasehold	81		93
Total oil and natural gas expenditures	1,170		1,193
Other Uses of Cash and Cash Equivalents:
Payments on revolving credit facility borrowings, net	275		—
Extinguishment of other financings	122		—
Cash paid to repurchase debt	—		1,746
Additions to other property and equipment	5		7
Dividends paid	46		137
Other	7		22
Total other uses of cash and cash equivalents	455		1,912
Total uses of cash and cash equivalents	$	1,625	$	3,105

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Oil and Natural Gas Expenditures

Our drilling and completion costs decreased in the Current Period compared to the Prior Period primarily as a result of lower rig and completion costs. During the Current Period, our average operated rig count was 16 rigs compared to an average operated rig count of 18 rigs in the Prior Period and we completed 161 operated wells in the Current Period compared to 206 in the Prior Period.

Extinguishment of Other Financing

In the Current Quarter, we repurchased previously conveyed overriding royalty interests (ORRIs) from the 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. See Note 5 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the transaction.

Repurchase of Debt

In the Prior Period, we used $1.746 billion of cash from debt issuances to repurchase $1.604 billion principal amount of debt.

Dividends

We paid dividends of $46 million on our preferred stock during the Current Period and we paid dividends of $137 million on our preferred stock in the Prior Period, including $92 million of dividends in arrears that had been suspended throughout 2016. 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, 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		13.83
Haynesville	—	—	830		2.63	—	—	139		26		15.84
Eagle Ford	61	70.51	143		3.22	19	26.56	103		20		50.70
Utica	11	63.50	408		2.76	27	25.11	106		20		23.53
Mid-Continent	10	66.45	70		2.37	5	24.49	27		5		35.82
Powder River Basin	8	67.37	57		2.18	4	27.12	22		4		36.82
Retained assets ^(a)	90	68.91	2,313		2.56	55	25.68	531		100		25.54
Divested assets	—	—	(2	)	2.51	—	—	(1	)	—		(8.48	)
Total	90	68.92	2,311		2.56	55	25.74	530		100	%	25.56

	Three Months Ended June 30, 2017
	Oil		Natural Gas			NGL		Total
	mbbl per day	$/bbl	mmcf per day		$/mcf	mbbl per day	$/bbl	mboe per day		%		$/boe
Marcellus	—	—	805		2.56	—	—	134		25		15.33
Haynesville	—	—	722		2.97	—	—	121		23		17.86
Eagle Ford	58	48.28	149		3.44	18	19.40	100		19		36.27
Utica	8	42.47	373		3.21	26	16.96	97		18		20.62
Mid-Continent	8	46.39	71		3.01	5	18.48	25		5		27.19
Powder River Basin	7	47.91	38		2.99	3	21.74	16		3		31.31
Retained assets ^(a)	81	47.46	2,158		2.89	52	18.21	493		93		22.37
Divested assets	7	47.98	136		2.75	5	20.09	35		7		23.84
Total	88	47.51	2,294		2.88	57	18.37	528		100	%	22.46

	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	—	—	832		2.71	—	—	139		25		16.34
Eagle Ford	61	68.35	142		3.26	19	25.67	103		19		49.48
Utica	11	61.69	424		2.85	25	25.08	106		19		23.46
Mid-Continent	9	64.45	67		2.52	5	25.33	25		5		35.22
Powder River Basin	8	65.28	52		2.46	3	27.84	20		4		37.21
Retained assets ^(a)	89	66.84	2,356		2.88	52	25.48	533		98		26.34
Divested assets	2	63.69	32		2.80	1	29.93	9		2		31.29
Total	91	66.76	2,388		2.88	53	25.60	542		100	%	26.43

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	Six Months Ended June 30, 2017
	Oil		Natural Gas		NGL		Total
	mbbl per day	$/bbl	mmcf per day	$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	821	2.78	—	—	137	26		16.71
Haynesville	—	—	702	2.97	—	—	117	22		17.86
Eagle Ford	57	49.58	142	3.42	18	20.37	98	19		37.37
Utica	8	43.88	376	3.35	26	21.20	96	18		22.38
Mid-Continent	7	47.75	69	3.01	5	20.35	24	4		27.43
Powder River Basin	6	48.63	33	3.14	2	23.39	14	3		31.88
Retained assets ^(a)	78	48.75	2,143	3.00	51	20.93	486	92		23.24
Divested assets	8	49.52	175	2.85	4	21.67	42	8		23.89
Total	86	48.83	2,318	2.99	55	20.99	528	100	%	23.29

___________________________________________

(a) Includes assets retained as of June 30, 2018.

Oil, Natural Gas and NGL Sales



	Three Months Ended June 30,						Six Months Ended June 30,
	2018		2017		Change		2018		2017		Change
	($ in millions)
Oil	$	567	$	383	48	%	$	1,104	$	761	45	%
Natural gas	538		601		(10	)%	1,244		1,254		(1	)%
NGL	128		95		35	%	245		211		16	%
Oil, natural gas and NGL sales	$	1,233	$	1,079	14	%	$	2,593	$	2,226	16	%

The increase in the price received per boe in the Current Quarter resulted in a $149 million increase in revenues, and increased sales volumes resulted in a $5 million increase in revenues, for a total net increase in revenues of $154 million . The increase in the price received per boe in the Current Period resulted in a $307 million increase in revenues, and increased sales volumes resulted in a $60 million increase in revenues, for a total net increase in revenues of $367 million .

A change in oil, natural gas and NGL prices has a significant impact on our revenues and cash flows. Assuming our Current Quarter production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would have resulted in an increase or decrease in Current Quarter revenues and cash flows from operations of approximately $8 million, an increase or decrease of $0.10 per mcf of natural gas sold would have resulted in an increase or decrease in Current Quarter revenues and cash flows from operations of approximately $21 million and an increase or decrease of $1.00 per barrel of NGL sold would have resulted in an increase or decrease in Current Quarter revenues and cash flows from operations of approximately $5 million. Assuming our Current Period production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would have resulted in an increase or decrease in Current Period revenues and cash flows from operations of approximately $16 million, an increase or decrease of $0.10 per mcf of natural gas sold would have resulted in an increase or decrease in Current Period revenues and cash flows from operations of approximately $43 million and an increase or decrease of $1.00 per barrel of NGL sold would have resulted in an increase or decrease in Current Period revenues and cash flows from operations of approximately $10 million and $9 million, respectively.

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Oil, Natural Gas and NGL Derivatives



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	($ in millions)
Oil derivatives – realized gains (losses)	$	(97	)	$	33		$	(161	)	$	44
Oil derivatives – unrealized gains (losses)	(105		)	47			(127		)	141
Total gains (losses) on oil derivatives	(202		)	80			(288		)	185

Natural gas derivatives – realized gains (losses)	17			(36		)	84			(52		)
Natural gas derivatives – unrealized gains (losses)	(52		)	156			(151		)	387
Total gains (losses) on natural gas derivatives	(35		)	120			(67		)	335

NGL derivatives – realized gains (losses)	(3		)	1			(4		)	2
NGL derivatives – unrealized gains (losses)	(11		)	(1		)	(9		)	—
Total gains (losses) on NGL derivatives	(14		)	—			(13		)	2
Total gains (losses) on oil, natural gas and NGL derivatives	$	(251	)	$	200		$	(368	)	$	522

See Note 8 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

In connection with the marketing of our production, we take title to the oil, natural gas and NGL we purchase from other working interest owners at defined delivery points and deliver the product to third parties, at which time revenues are recorded. In circumstances where we act as a principal rather than an agent, revenue is presented on a gross basis. Marketing revenues primarily consist of marketing services, including commodity price structuring, securing and negotiating gathering, hauling, processing and transportation services, contract administration and nomination services for Chesapeake and other interest owners in Chesapeake-operated wells.



	Three Months Ended June 30,								Six Months Ended June 30,
	2018			2017			Change		2018			2017			Change
	($ in millions)
Marketing revenues	1,273			1,002			27	%	$	2,519		$	2,286		10	%
Marketing expenses	1,292			1,027			26	%	2,560			2,355			9	%
Marketing gross margin	$	(19	)	$	(25	)	(24	)%	$	(41	)	$	(69	)	(41	)%

Gross margin increased in the Current Quarter and the Current Period primarily as a result of increased oil, natural gas and NGL prices received in our marketing operations .

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Oil, Natural Gas and NGL Production Expenses



	Three Months Ended June 30,						Six Months Ended June 30,
	2018		2017		Change		2018		2017		Change
	($ in millions)
Marcellus	$	7	$	5	40	%	$	15	$	10	50	%
Haynesville	14		12		17	%	30		22		36	%
Eagle Ford	52		49		6	%	100		91		10	%
Utica	11		10		10	%	22		19		16	%
Mid-Continent	23		27		(15	)%	49		53		(8	)%
Powder River Basin	11		6		83	%	23		13		77	%
Retained Assets ^(a)	118		109		8	%	239		208		15	%
Divested Assets	—		20		(100	)%	14		42		(67	)%
Total	118		129		(9	)%	253		250		1	%

Ad valorem tax	20		11		82	%	32		25		28	%

Total oil, natural gas and NGL production expenses	$	138	$	140	(1	)%	$	285	$	275	4	%

	($ per boe)
Marcellus	$	0.59	$	0.44	34	%	$	0.60	$	0.41	46	%
Haynesville	$	1.09	$	1.12	(3	)%	$	1.19	$	1.04	14	%
Eagle Ford	$	5.54	$	5.31	4	%	$	5.36	$	5.09	5	%
Utica	$	1.14	$	1.17	(3	)%	$	1.17	$	1.10	6	%
Mid-Continent	$	9.23	$	11.77	(22	)%	$	10.59	$	12.30	(14	)%
Powder River Basin	$	5.52	$	4.32	28	%	$	6.27	$	5.40	16	%
Retained Assets ^(a)	$	2.44	$	2.45	—	%	$	2.47	$	2.37	4	%
Divested Assets	$	—	$	6.15	(100	)%	$	8.33	$	5.60	49	%
Total	$	2.44	$	2.69	(9	)%	$	2.57	$	2.62	(2	)%

Ad valorem tax	$	0.42	$	0.23	83	%	$	0.33	$	0.26	27	%

Total oil, natural gas and NGL production expenses per boe	$	2.86	$	2.92	(2	)%	$	2.90	$	2.88	1	%

___________________________________________

(a) Includes assets retained as of June 30, 2018.

The absolute and per unit decrease in the Current Quarter was the result of the sale of certain oil and natural gas properties in 2017 and 2018, partially offset by an increase in salt water disposal cost primarily in Haynesville and Eagle Ford. The absolute and per unit increase in the Current Period was the result of increased salt water disposal cost in all operating areas and increased workover activity primarily in the Haynesville and Powder River Basin.

Production expenses in the Current Quarter, the Prior Quarter, the Current Period and the Prior Period included approximately $4 million, $5 million, $8 million and $11 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,
	2018		2017		2018		2017
	($ in millions, except per unit)
Oil, natural gas and NGL gathering, processing and transportation expenses	$	340	$	357	$	696	$	712
Oil ($ per bbl)	$	3.22	$	3.70	$	3.70	$	3.77
Natural gas ($ per mcf)	$	1.29	$	1.37	$	1.28	$	1.36
NGL ($ per bbl)	$	8.46	$	7.87	$	8.65	$	8.16
Total ($ per boe)	$	7.04	$	7.44	$	7.10	$	7.45

The absolute and per unit decrease in oil, natural gas and NGL gathering, processing and transportation expenses was primarily due to lower gathering fees associated with restructured midstream contracts, lower volume commitments on downstream pipelines and certain 2018 and 2017 divestitures.

Production Taxes



	Three Months Ended June 30,						Six Months Ended June 30,
	2018		2017		Change		2018		2017		Change
	($ in millions, except per unit)
Production taxes	$	26	$	21	24	%	$	57	$	43	33	%
Production taxes per boe	$	0.55	$	0.42	31	%	$	0.58	$	0.45	29	%

The absolute and per unit increase in production taxes was primarily due to higher prices received for our oil, natural gas and NGL production.

General and Administrative Expenses



	Three Months Ended June 30,								Six Months Ended June 30,
	2018			2017			Change		2018			2017			Change
	($ in millions, except per unit)
Gross overhead	$	201		$	206		(2	)%	$	389		$	407		(4	)%
Allocated to production expenses	(36		)	(45		)	(20	)%	(76		)	(90		)	(16	)%
Allocated to marketing expenses	(5		)	(8		)	(38	)%	(11		)	(15		)	(27	)%
Capitalized	(30		)	(31		)	(3	)%	(62		)	(67		)	(7	)%
Reimbursed from third parties	(39		)	(52		)	(25	)%	(77		)	(100		)	(23	)%
General and administrative expenses, net	$	91		$	70		30	%	$	163		$	135		21	%

General and administrative expenses, net per boe	$	1.89		$	1.45		30	%	$	1.66		$	1.40		19	%

Gross overhead decreased primarily due to our reduction in workforce offset by increased liability based awards. The absolute and per unit net expense increase was primarily due to less overhead allocated to production expenses, marketing expenses and capitalized general and administrative costs, as well as less overhead billed to third party working interest owners, due to certain divestitures in 2017.

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

Oil, Natural Gas and NGL Depreciation, Depletion and Amortization



	Three Months Ended June 30,						Six Months Ended June 30,
	2018		2017		Change		2018		2017		Change
	($ in millions, except per unit)
Oil, natural gas and NGL depreciation, depletion and amortization	$	271	$	202	34	%	$	539	$	399	35	%
Oil, natural gas and NGL depreciation, depletion and amortization per boe	$	5.61	$	4.21	33	%	$	5.49	$	4.18	31	%

The absolute and per unit increase in the Current Quarter and the Current Period is primarily the result of a higher depletion rate per boe coupled with an increase in production. The depletion rate per boe is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented. The increase in depletion rate per boe primarily reflects a downward revision in proved reserve estimates in 2017 due to an updated development plan in the Eagle Ford aligning up-spacing, our activity schedule and well performance. The downward revision in proved reserves was partially offset by the effect of upward price revisions as a result of improved oil, natural gas and NGL prices.

Depreciation and Amortization of Other Assets



	Three Months Ended June 30,						Six Months Ended June 30,
	2018		2017		Change		2018		2017		Change
	($ in millions, except per unit)
Depreciation and amortization of other assets	$	19	$	21	(10	)%	$	37	$	42	(12	)%
Depreciation and amortization of other assets per boe	$	0.38	$	0.43	(12	)%	$	0.37	$	0.44	(16	)%

The absolute and per unit decrease in the Current Quarter and the Current Period was primarily the result of the sale of certain other assets.

Impairments

Other Operating (Income) Expense



	Three Months Ended June 30,							Six Months Ended June 30,
	2018			2017		Change		2018			2017		Change
	($ in millions)
Other operating (income) expense	$	(1	)	$	26	(104	)%	$	(1	)	$	417	(100	)%

In the Prior Quarter and the Prior Period, we terminated future natural gas gathering transportation commitments related to divested assets for cash payments of $23 million and $126 million, respectively. In the Prior Period, we also paid $290 million to assign an oil transportation agreement to a third party.

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Interest Expense



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	($ in millions)
Interest expense on senior notes	$	144		$	136		$	288		$	272
Interest expense on term loan	30			32			58			64
Amortization of loan discount, issuance costs and other	2			6			10			15
Amortization of premium	(24		)	(42		)	(48		)	(83		)
Interest expense on revolving credit facility	8			8			18			17
Realized gains on interest rate derivatives ^(a)	—			(1		)	(1		)	(2		)
Unrealized losses on interest rate derivatives ^(b)	—			1			1			3
Capitalized interest	(43		)	(47		)	(86		)	(98		)
Total interest expense	$	117		$	93		$	240		$	188

Interest expense per boe ^(c)	$	2.43		$	1.92		$	2.44		$	1.94

Average senior notes borrowings	$	7,967		$	7,600		$	7,967		$	7,644
Average credit facilities borrowings	$	380		$	351		$	488		$	176
Average term loan borrowings	$	1,233		$	1,500		$	1,233		$	1,500

___________________________________________


(a)	Includes settlements related to the interest accrual for the period and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item.


(b)	Includes changes in the fair value of interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.


(c)	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 increase in interest expense is primarily due to the increase in the average outstanding principal amount of senior notes and a decrease in amortization of premium and capitalized interest. The decrease in amortization of premium is due to the decrease in the average outstanding principal amount of our senior secured second lien notes. The decrease in capitalized interest is a result of lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of this report for a discussion of our debt refinancing.

Gains on Investments

In the Current 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 11 of the notes to our condensed consolidated financial statements included in Item 1 of this report for further discussion.

Losses on Purchases or Exchanges of Debt

In the Prior Quarter, we retired $682 million principal amount of our outstanding senior secured second lien notes through a tender offer for $750 million. We recorded an aggregate gain of approximately $191 million associated with the transaction.

In the Prior Period, we retired $1.604 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $1.746 billion, which included the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and the corresponding cross currency swap. We recorded an aggregate net gain of approximately $184 million associated with the repurchases and tender offers.

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Other Income (Expense)

In the Current 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. See Note 5 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of the transaction.

Income Tax Expense (Benefit)

We recorded a $9 million income tax benefit in the Current Quarter and in the Current Period and recorded $1 million and $2 million of income tax expense in the Prior Quarter and in the Prior Period, respectively. Our effective income tax rate was 36.0% for the Current Quarter, and (3.3%) for the Current Period compared to 0.2% and 0.3% for the Prior Quarter and for the Prior Period, respectively. Our effective tax rate can fluctuate as a result of the impact of discrete items, state income taxes and permanent differences. For the Current Quarter, our estimated annual effective tax rate remains nominal as a result of having a full valuation allowance against our net deferred tax asset. See Note 6 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of income tax expense.

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 Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements include our current expectations or forecasts of future events, including our ability to meet debt service requirements, the closing of the sale of our Utica interests and the amount and expected use of proceeds of the sale 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;

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•	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;


•	effects of purchase price adjustments and indemnity obligations;


•	the need to obtain certain consents and approvals and satisfy certain conditions to closing of the Utica transaction, which may not be completed in the anticipated time frame or at all;


•	the occurrence of any event or other circumstance that could lead to the termination of the agreement governing the sale of our Utica interests; and


•	other factors that are described under Risk Factors in Item 1A of our 2017 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 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.


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 flow 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 its 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.

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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 8 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.

As of June 30, 2018 , our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:


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


•	Options : We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.


•	Call Swaptions : We sell call swaptions to counterparties that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time

•


•	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, 2018 , 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	20	$	56.35	$	—	$	—	$	—	$	(246	)
Long-term	6	$	59.96	$	—	$	—	$	—	(25		)
Three-Way Collars:
Short-term	1	$	—	$	55.00	39.15/47.00		$	—	(14		)
Call Swaptions:
Short-term	2	$	52.87	$	—	$	—	$	—	(32		)
Basis Protection Swaps:
Short-term	9	$	—	$	—	$	—	$	4.11	2
Long-term	2	$	—	$	—	$	—	$	6.20	4
Total Oil										(311		)

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		Weighted Average Price									Fair Value
	Volume	Fixed		Call		Put		Differential			Asset (Liability)
	(bcf)	($ per mcf)
Natural Gas:
Swaps ^(a) :
Short-term	240	$	2.97	$	—	$	—	$	—		3
Three-Way Collars:
Short-term	43	—		$	3.10	2.50/2.80		—			—
Long-term	44	—		$	3.10	2.50/2.80		—			—
Collars:
Short-term	24	$	—	$	3.25	$	3.00	$	—		2
Call Options (sold):
Short-term	44	$	—	$	7.68	$	—	$	—		—
Long-term	33	$	—	$	12.00	$	—	$	—		—
Basis Protection Swaps:
Short-term	36	$	—	$	—	$	—	$	(0.34	)	(1		)
Long-term	9	$	—	$	—	$	—	$	(0.51	)	—
Total Natural Gas											4

	(mmgal)	($ per gal)
NGL:
Propane Swaps:
Short-term	31	$	0.79	$	—	$	—	$	—		(5		)
Butane Swaps:
Short-term	3	$	0.88	$	—	$	—	$	—		—
Short-term % of WTI	3	70.5%		$	—	$	—	$	—		—
Isobutane Swaps:
Short-term	8	$	0.92	$	—	$	—	$	—		(2		)
Ethane Swaps:
Short-term	46	$	0.29	$	—	$	—	$	—		(1		)
Natural Gasoline Swaps:
Short-term	23	$	1.42	$	—	$	—	$	—		(3		)
Total NGL											(11		)
Total Estimated Fair Value											$	(318	)

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(a)	This amount includes a sold option to enhance the swap price at an average price of $3.40/mcf covering 22 bcf, included in the sold call options.

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In addition to the open derivative positions disclosed above, as of June 30, 2018 , we had $69 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, 2018
	($ in millions)
Short-term	$	(24	)
Long-term	(45		)
Total	$	(69	)

The table below reconciles the changes in fair value of our oil and natural gas derivatives during the Current Period. Of the $318 million fair value liability as of June 30, 2018 , a $298 million liability relates to contracts maturing in the next 12 months and a $20 million liability relates to contracts maturing after 12 months. All open derivative instruments as of June 30, 2018 are expected to mature by December 31, 2020.



	June 30, 2018
	($ in millions)
Fair value of contracts outstanding, as of January 1, 2018	$	(35	)
Change in fair value of contracts	(214		)
Contracts realized or otherwise settled	(69		)
Fair value of contracts outstanding, as of June 30, 2018	$	(318	)

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
	2018			2019			2020			2021			2022			Thereafter			Total
	($ in millions)
Liabilities:
Debt – fixed rate	$	53		$	—		$	664		$	815		$	1,867		$	4,188		$	7,587
Average interest rate	6.42		%	—		%	6.71		%	5.88		%	7.25		%	7.07		%	6.95		%
Debt – variable rate	$	—		$	886		$	—		$	1,233		$	—		$	—		$	2,119
Average interest rate	—		%	4.99		%	—		%	9.47		%	—		%	—		%	7.60		%

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, term loan 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 flow 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, 2018 , we had $6 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 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 Securities Exchange Act of 1934, as amended (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, 2018 that our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

During the quarter ended June 30, 2018, we implemented a production revenue accounting module of SAP, a company-wide enterprise resource planning software system. In conjunction with the implementation of this module, we modified the design, operation and documentation of our internal control over financial reporting.

With the exception of the SAP module implementation described above, there was no change in our internal control over financial reporting during the quarter ended June 30, 2018, which materially affected, or was 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 for the items discussed below. For a description of certain legal and regulatory proceedings affecting us, see “Contingencies and Commitments,” Note 4 to the Consolidated Financial Statements included in Item 1 of Part 1 of this report and Item 3 in our 2017 Form 10-K and in Note 4 to the Consolidated Financial Statements in our Form 10-Q for the quarterly period ended March 31, 2018.


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 2017 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

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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, 2018 :



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 ^(b)
					($ in millions)
April 1, 2018 through April 30, 2018	17,046	$	2.92	—	$	1,000
May 1, 2018 through May 31, 2018	—	$	—	—	$	1,000
June 1, 2018 through June 30, 2018	37,249	$	4.64	—	$	1,000
Total	54,295	$	4.10	—

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(a)	Includes shares of common stock purchased on behalf of our deferred compensation plan related to Company matching contributions.


(b)	In December 2014, our Board of Directors authorized the repurchase of up to $1 billion of our common stock from time to time. The repurchase program does not have an expiration date. As of June 30, 2018 , there have been no repurchases under the program.

Pursuant to Robert D. Lawler’s initial employment agreement and as previously disclosed in a Current Report on Form 8-K filed on May 23, 2013 and in each subsequent definitive proxy statement , the Company agreed to issue to Mr. Lawler restricted stock with a grant date fair value of $5,000,000 on the fifth anniversary of Mr. Lawler’s employment with the Company. This restricted stock award of 1,077,587 shares was issued on June 17, 2018 to Mr. Lawler and is scheduled to vest in equal installments on the third, fourth and fifth anniversaries of the grant date. The award requirement from the 2013 employment agreement was in recognition of forfeited pension benefits from Mr. Lawler's prior employer. The shares were issued in reliance on the exemption set forth in Section 4(a)(2) of the Securities Act.


ITEM 3.	Defaults Upon Senior Securities

None.


ITEM 4.	Mine Safety Disclosures

Not applicable.


ITEM 5.	Other Information

On July 31, 2018, each of the following executive officers of the Corporation received the following awards in order to incentivize continued employment during the ongoing transformation of the Corporation:



Named Executive Officer	Amount
Robert D. Lawler	$ 2,500,000
Domenic J. Dell’Osso, Jr.	$ 2,000,000
Frank J. Patterson	$ 1,500,000
James R. Webb	$ 1,500,000
M. Jason Pigott	$ 1,500,000

Each 2018 individual award is composed of: (i) 50% performance stock units to be issued in shares of the Corporation’s common stock pursuant to Section 7 of the 2014 Long Term Incentive Plan and based on the closing price of the Company’s common stock on July 31, 2018 (the “PSU Incentive Award”), subject to the vesting provisions

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set forth below; and (ii) 50% cash to be granted in full, effective as of the date of grant (the “Cash Retention Award”), subject to the vesting and clawback provisions set forth below.

The PSU Incentive Award will vest on the third anniversary of the grant date, provided that: (1) the executive remains continuously employed by the Corporation until such date; and (2) the Corporation has achieved the following two performance goals: (i) successful completion of an additional $2 billion of debt reduction from the net debt balance as of December 31, 2017; and (ii) the Corporation entering into a new or extended revolving credit facility prior to expiration of the existing revolving credit facility. The Cash Retention Award will: (i) vest in five equal annual installments beginning on the first anniversary of the date of grant; and (ii) will be subject to a five-year ratable clawback structure, providing that if the executive resigns or departs the Corporation voluntarily or is removed “for cause” (as defined in the executive’s employment agreement) during the five-year clawback period, the unvested cash portion of the Cash Retention Award will be forfeited and must be repaid by the executive to the Corporation.

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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-Q

001-13726

3.1.1

8/3/2017

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

10.1

Second Pension and Equity Makeup Restricted Stock Award Agreement for Robert D. Lawler.

Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.

31.1

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

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.

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.

101 INS

XBRL Instance 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.

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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 1, 2018	By:	/s/ ROBERT D. LAWLER
		Robert D. Lawler President and Chief Executive Officer




Date: August 1, 2018	By:	/s/ DOMENIC J. DELL’OSSO, JR.
		Domenic J. Dell’Osso, Jr. Executive Vice President and Chief Financial Officer

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Part I. Financial Information Item 1. Condensed Consolidated Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Part Of Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

Exhibits

3.1.1 Chesapeakes Restated Certificate of Incorporation. 10-Q 001-13726 3.1.1 8/3/2017 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 Chesapeakes Amended and Restated Bylaws. 8-K 001-13726 3.2 6/19/2014 10.1 Second Pension and Equity Makeup Restricted Stock Award Agreement for Robert D. Lawler. 12 Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends. 31.1 Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Domenic J. DellOsso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 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. DellOsso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

EXE 10-Q Quarter ended June 30, 2018

Exhibits