Item 8. Financial Statements and Supplementary Data

	INDEX TO FINANCIAL STATEMENTS CHESAPEAKE ENERGY CORPORATION
			Page
Management’s Report on Internal Control Over Financial Reporting			64
Report of Independent Registered Public Accounting Firm			65
Consolidated Financial Statements:
	Consolidated Balance Sheets as of December 31, 2017 and 2016		67
	Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015		69
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2017, 2016 and 2015		70
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015		71
	Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2017, 2016 and 2015		73
Notes to the Consolidated Financial Statements:
	Note 1. Basis of Presentation and Summary of Significant Accounting Policies		75
	Note 2. Earnings per Share		81
	Note 3. Debt		82
	Note 4. Contingencies and Commitments		86
	Note 5. Other Liabilities		89
	Note 6. Income Taxes		90
	Note 7. Related Party Transactions		92
	Note 8. Equity		93
	Note 9. Share-Based Compensation		97
	Note 10. Employee Benefit Plans		102
	Note 11. Derivative and Hedging Activities		103
	Note 12. Oil and Natural Gas Property Transactions		108
	Note 13. Other Property and Equipment		110
	Note 14. Impairments		111
	Note 15. Restructuring and Other Termination Costs		112
	Note 16. Fair Value Measurements		113
	Note 17. Asset Retirement Obligations		113
	Note 18. Major Customers		114
	Note 19. Condensed Consolidating Financial Information		114
	Note 20. Subsequent Events		118
Supplementary Information:
	Quarterly Financial Data (unaudited)		119
	Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)		120

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of the management of Chesapeake Energy Corporation to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's Internal Control-Integrated Framework (2013) in conducting the required assessment of effectiveness of the Company's internal control over financial reporting.

Management has performed an assessment of the effectiveness of the Company's internal control over financial reporting and has determined the Company’s internal control over financial reporting was effective as of December 31, 2017.

The effectiveness of the Company's internal control over financial reporting, as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report, which appears herein.

/s/ ROBERT D. LAWLER
Robert D. Lawler
President and Chief Executive Officer
/s/ DOMENIC J. DELL'OSSO, JR.
Domenic J. Dell'Osso, Jr.
Executive Vice President and Chief Financial Officer
February 22, 2018

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Chesapeake Energy Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the consolidated financial statements, including the related notes of Chesapeake Energy Corporation and its subsidiaries as listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

February 22, 2018

We have served as the Company’s auditor since 1992.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31,
		2017				2016
		($ in millions)
CURRENT ASSETS:
Cash and cash equivalents ($2 and $1 attributable to our VIE)		$	5			$	882
Accounts receivable, net		1,322				1,057
Short-term derivative assets		27				—
Other current assets		171				203
Total Current Assets		1,525				2,142
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)		68,858				66,451
Unproved properties		3,484				4,802
Other property and equipment		1,986				2,053
Total Property and Equipment, at Cost		74,328				73,306
Less: accumulated depreciation, depletion and amortization (($461) and ($458) attributable to our VIE)		(63,664		)		(62,726		)
Property and equipment held for sale, net		16				29
Total Property and Equipment, Net		10,680				10,609
LONG-TERM ASSETS:
Other long-term assets		220				277
TOTAL ASSETS		$	12,425			$	13,028

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – (Continued)

		December 31,
		2017				2016
		($ in millions)
CURRENT LIABILITIES:
Accounts payable		$	654			$	672
Current maturities of long-term debt, net		52				503
Accrued interest		137				113
Short-term derivative liabilities		58				562
Other current liabilities ($3 and $3 attributable to our VIE)		1,455				1,798
Total Current Liabilities		2,356				3,648
LONG-TERM LIABILITIES:
Long-term debt, net		9,921				9,938
Long-term derivative liabilities		4				15
Asset retirement obligations, net of current portion		162				247
Other long-term liabilities		354				383
Total Long-Term Liabilities		10,441				10,583
CONTINGENCIES AND COMMITMENTS (Note 4)
EQUITY:
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 5,603,458 and 5,839,506 shares outstanding		1,671				1,771
Common stock, $0.01 par value, 2,000,000,000 and 1,500,000,000 shares authorized: 908,732,809 and 896,279,353 shares issued		9				9
Additional paid-in capital		14,437				14,486
Accumulated deficit		(16,525		)		(17,474		)
Accumulated other comprehensive loss		(57		)		(96		)
Less: treasury stock, at cost; 2,240,394 and 1,220,504 common shares		(31		)		(27		)
Total Chesapeake Stockholders’ Equity (Deficit)		(496		)		(1,331		)
Noncontrolling interests		124				128
Total Equity (Deficit)		(372		)		(1,203		)
TOTAL LIABILITIES AND EQUITY		$	12,425			$	13,028

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

		Years Ended December 31,
		2017				2016				2015
		($ in millions except per share data)
REVENUES:
Oil, natural gas and NGL		$	4,985			$	3,288			$	5,391
Marketing, gathering and compression		4,511				4,584				7,373
Total Revenues		9,496				7,872				12,764
OPERATING EXPENSES:
Oil, natural gas and NGL production		562				710				1,046
Oil, natural gas and NGL gathering, processing and transportation		1,471				1,855				2,119
Production taxes		89				74				99
Marketing, gathering and compression		4,598				4,778				7,130
General and administrative		262				240				235
Restructuring and other termination costs		—				6				36
Provision for legal contingencies, net		(38		)		123				353
Oil, natural gas and NGL depreciation, depletion and amortization		913				1,003				2,099
Depreciation and amortization of other assets		82				104				130
Impairment of oil and natural gas properties		—				2,564				18,238
Impairments of fixed assets and other		421				838				194
Net (gains) losses on sales of fixed assets		(3		)		(12		)		4
Total Operating Expenses		8,357				12,283				31,683
INCOME (LOSS) FROM OPERATIONS		1,139				(4,411		)		(18,919		)
OTHER INCOME (EXPENSE):
Interest expense		(426		)		(296		)		(317		)
Losses on investments		—				(8		)		(96		)
Loss on sale of investment		—				(10		)		—
Impairments of investments		—				(119		)		(53		)
Gains on purchases or exchanges of debt		233				236				279
Other income		9				19				8
Total Other Expense		(184		)		(178		)		(179		)
INCOME (LOSS) BEFORE INCOME TAXES		955				(4,589		)		(19,098		)
INCOME TAX EXPENSE (BENEFIT):
Current income taxes		(9		)		(19		)		(36		)
Deferred income taxes		11				(171		)		(4,427		)
Total Income Tax Expense (Benefit)		2				(190		)		(4,463		)
NET INCOME (LOSS)		953				(4,399		)		(14,635		)
Net (income) loss attributable to noncontrolling interests		(4		)		9				68
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		949				(4,390		)		(14,567		)
Preferred stock dividends		(85		)		(97		)		(171		)
Loss on exchange of preferred stock		(41		)		(428		)		—
Earnings allocated to participating securities		(10		)		—				—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS		$	813			$	(4,915	)		$	(14,738	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic		$	0.90			$	(6.43	)		$	(22.26	)
Diluted		$	0.90			$	(6.43	)		$	(22.26	)
CASH DIVIDEND DECLARED PER COMMON SHARE		$	—			$	—			$	0.0875
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic		906				764				662
Diluted		906				764				662

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
NET INCOME (LOSS)		$	953			$	(4,399	)		$	(14,635	)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $0, ($14) and $12		5				(13		)		20
Reclassification of losses on settled derivative instruments, net of income tax expense of $0, $18 and $15		34				16				24
Other Comprehensive Income		39				3				44
COMPREHENSIVE INCOME (LOSS)		992				(4,396		)		(14,591		)
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(4		)		9				68
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		$	988			$	(4,387	)		$	(14,523	)

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)		$	953			$	(4,399	)		$	(14,635	)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:
Depreciation, depletion and amortization		995				1,107				2,229
Deferred income tax expense (benefit)		11				(171		)		(4,427		)
Derivative (gains) losses, net		(409		)		739				(932		)
Cash receipts (payments) on derivative settlements, net		(18		)		448				1,123
Stock-based compensation		49				52				78
Impairment of oil and natural gas properties		—				2,564				18,238
Net (gains) losses on sales of fixed assets		(3		)		(12		)		4
Renegotiation of natural gas gathering contracts		—				(115		)		—
Impairments of fixed assets and other		4				467				175
Losses on investments		—				8				96
Loss on sale of investment		—				10				—
Impairments of investments		—				119				53
Gains on purchases or exchanges of debt		(235		)		(236		)		(304		)
Restructuring and other termination costs		—				3				(14		)
Provision for legal contingencies, net		(42		)		87				340
Other		(89		)		(114		)		244
(Increase) decrease in accounts receivable and other assets		(163		)		(4		)		1,186
Decrease in accounts payable, accrued liabilities and other		(308		)		(757		)		(2,220		)
Net Cash Provided By (Used In) Operating Activities		745				(204		)		1,234
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs		(2,186		)		(1,295		)		(3,095		)
Acquisitions of proved and unproved properties		(285		)		(788		)		(533		)
Proceeds from divestitures of proved and unproved properties		1,249				1,406				189
Additions to other property and equipment		(21		)		(37		)		(143		)
Proceeds from sales of other property and equipment		55				131				89
Cash paid for title defects		—				(69		)		—
Additions to investments		—				—				(1		)
Decrease in restricted cash		—				—				52
Other		—				(8		)		(9		)
Net Cash Used In Investing Activities		(1,188		)		(660		)		(3,451		)

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings		7,771				5,146				—
Payments on revolving credit facility borrowings		(6,990		)		(5,146		)		—
Proceeds from issuance of senior notes, net		1,585				2,210				—
Proceeds from issuance of term loan, net		—				1,476				—
Cash paid to purchase debt		(2,592		)		(2,734		)		(508		)
Cash paid for common stock dividends		—				—				(118		)
Cash paid for preferred stock dividends		(183		)		—				(171		)
Cash paid to repurchase noncontrolling interest of CHK C-T		—				—				(143		)
Distributions to noncontrolling interest owners		(8		)		(10		)		(85		)
Other		(17		)		(21		)		(41		)
Net Cash Provided By (Used In) Financing Activities		(434		)		921				(1,066		)
Net increase (decrease) in cash and cash equivalents		(877		)		57				(3,283		)
Cash and cash equivalents, beginning of period		882				825				4,108
Cash and cash equivalents, end of period		$	5			$	882			$	825
Supplemental disclosures to the consolidated statements of cash flows are presented below:
		Years Ended December 31,
		2017				2016				2015
		($ in millions)
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest		$	492			$	344			$	235
Income taxes paid, net of refunds received		$	(16	)		$	(27	)		$	44
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs		$	14			$	(23	)		$	(148	)
Change in accrued acquisitions of proved and unproved properties		$	9			$	(13	)		$	55
Change in divested proved and unproved properties		$	(57	)		$	52			$	35
Divestiture of proved and unproved CHK-C-T properties		$	—			$	—			$	1,024
Debt exchanged for common stock		$	—			$	471			$	—
Repurchase of noncontrolling interest in CHK C-T		$	—			$	—			$	(872	)

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
PREFERRED STOCK:
Balance, beginning of period		$	1,771			$	3,062			$	3,062
Exchange/conversions of 236,048, 1,412,009 and 0 shares of preferred stock for common stock		(100		)		(1,291		)		—
Balance, end of period		1,671				1,771				3,062
COMMON STOCK:
Balance, beginning of period		9				7				7
Exchange of senior notes, contingent convertible notes and preferred stock		—				1				—
Conversion of preferred stock		—				1				—
Balance, end of period		9				9				7
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period		14,486				12,403				12,531
Stock-based compensation		54				64				71
Exchange of contingent convertible notes for 0 and 55,427,782 and 0 shares of common stock		—				241				—
Exchange of senior notes for 0 and 53,923,925 and 0 shares of common stock		—				229				—
Exchange/conversion of preferred stock for 9,965,835, 120,186,195 and 0 shares of common stock		100				1,290				—
Issuance of 5.5% convertible senior notes due 2026		—				445				—
Tax effect on the issuance of 5.5% convertible senior notes due 2026		—				(165		)		—
Equity component of contingent convertible notes repurchased, net of tax		(20		)		(16		)		—
Dividends on preferred stock		(183		)		—				(128		)
Dividends on common stock		—				—				(59		)
Issuance costs		—				(5		)		—
Increase (decrease) in tax benefit from stock-based compensation		—				—				(12		)
Balance, end of period		14,437				14,486				12,403
RETAINED EARNINGS (ACCUMULATED DEFICIT):
Balance, beginning of period		(17,474		)		(13,084		)		1,483
Net income (loss) attributable to Chesapeake		949				(4,390		)		(14,567		)
Balance, end of period		(16,525		)		(17,474		)		(13,084		)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
Balance, beginning of period		(96		)		(99		)		(143		)
Hedging activity		39				3				44
Balance, end of period		(57		)		(96		)		(99		)

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY - (Continued)

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
TREASURY STOCK – COMMON:
Balance, beginning of period		(27		)		(33		)		(37		)
Purchase of 1,206,419, 37,871 and 54,493 shares for company benefit plans		(7		)		—				(1		)
Release of 186,529, 255,091 and 231,081 shares from company benefit plans		3				6				5
Balance, end of period		(31		)		(27		)		(33		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT)		(496		)		(1,331		)		2,256
NONCONTROLLING INTERESTS:
Balance, beginning of period		128				141				1,302
Net income attributable to noncontrolling interests		4				(9		)		(68		)
Distributions to noncontrolling interest owners		(8		)		(4		)		(78		)
Repurchase of noncontrolling interest of CHK C-T		—				—				(1,015		)
Balance, end of period		124				128				141
TOTAL EQUITY (DEFICIT)		$	(372	)		$	(1,203	)		$	2,397

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

Chesapeake Energy Corporation ("Chesapeake", “we,” “our”, “us” or the "Company") is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and natural gas liquids (NGL) from underground reservoirs. Our operations are located onshore in the United States.

Basis of Presentation

The accompanying consolidated financial statements of Chesapeake were prepared in accordance with GAAP and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated.

Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the related disclosures in the financial statements. Management evaluates its estimates and related assumptions regularly, including those related to the impairment of oil and natural gas properties, oil and natural gas reserves, derivatives, income taxes, collectibility of accounts receivable, impairment of other property and equipment, environmental remediation costs, asset retirement obligations, litigation and regulatory proceedings and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ significantly from these estimates.

Consolidation

We consolidate entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which we are the primary beneficiary. We use the equity method of accounting to record our net interests where we have the ability to exercise significant influence through our investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Undivided interests in oil and natural gas properties are consolidated on a proportionate basis.

Segments

Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating an enterprise’s resources and assessing its operating performance.

We have historically presented two reportable operating segments: (i) exploration and production and (ii) marketing, gathering and compression. In the fourth quarter of 2017, we completed the realignment of our marketing, gathering and compression operations to serve as an ancillary service integral to our exploration and production activities. Following this realignment, we have a single, company-wide management team that administers all activities as a whole rather than through discrete operating units, with an emphasis on allocating capital focused on the expansion of our exploration and production assets. As a result, we have concluded that we have only one reportable operating segment, which is exploration and production. Prior year financial information for our previous marketing, gathering and compression reportable operating segment has been eliminated.

Noncontrolling Interests

Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Variable Interest Entities

VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. We continually monitor our consolidated VIE to determine if any events have occurred that could cause the primary beneficiary to change. See Note 8 for further discussion of our VIE.

Cash and Cash Equivalents

For purposes of the consolidated financial statements, we consider investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents.

Accounts Receivable

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. Accounts receivable as of December 31, 2017 and 2016 are detailed below:

		December 31,
		2017				2016
		($ in millions)
Oil, natural gas and NGL sales		$	959			$	840
Joint interest		209				156
Other		184				93
Allowance for doubtful accounts		(30		)		(32		)
Total accounts receivable, net		$	1,322			$	1,057

Oil and Natural Gas Properties

We follow the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information – Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2017 were prepared by an independent engineering firm and our internal staff. In addition, our internal engineers review and update our reserves on a quarterly basis.

Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area in circumstances where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties that portion of our leasehold that expired in the quarter, or leasehold that is no longer part of our development strategy and will be abandoned.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2017 and the year in which the associated costs were incurred:

		Year of Acquisition
		2017				2016				2015				Prior				Total
		($ in millions)
Leasehold cost		$	70			$	89			$	87			$	2,368			$	2,614
Exploration cost		50				9				33				11				103
Capitalized interest		154				116				120				377				767
Total		$	274			$	214			$	240			$	2,756			$	3,484

We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2017, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11.

Two primary factors impacting the ceiling test are reserve levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of our estimated future net revenues. Any excess of the net book value over the ceiling is written off as an impairment expense.

We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. We review our unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in significant changes to the quarterly ceiling test calculation.

Other Property and Equipment

Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computers and office equipment. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating expenses. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including any disposal value, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow.

Capitalized Interest

Interest from external borrowings is capitalized on significant investments in unproved properties and major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.

Accounts Payable

Included in accounts payable as of December 31, 2017 and 2016 are liabilities of approximately $92 million and $77 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Debt Issuance Costs

Included in other long-term assets are costs associated with the issuance and amendments of our revolving credit facility. The remaining unamortized issuance costs as of December 31, 2017 and 2016, totaled $22 million and $32 million, respectively, and are being amortized over the life of credit facility using the straight-line method. Included in debt are costs associated with the issuance of our senior notes and term loan. The remaining unamortized issuance costs as of December 31, 2017 and 2016, totaled $63 million and $64 million, respectively, and are being amortized over the life of the senior notes using the effective interest method.

Litigation Contingencies

We are subject to litigation and regulatory proceedings, claims and liabilities that arise in the ordinary course of business. We accrue losses associated with litigation and regulatory claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, our best estimate within the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred.

Environmental Remediation Costs

We record environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Asset Retirement Obligations

We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 17 for further discussion of asset retirement obligations.

Revenue Recognition

Oil, Natural Gas and NGL Sales. Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Natural Gas Imbalances. We follow the sales method of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining estimated natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2017 and 2016, was $5 million and $9 million, respectively.

Marketing, Gathering and Compression Sales. In connection with the marketing of our production, we take title to 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. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, primarily for credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, our results of operations related to oil, natural gas and NGL marketing activities are presented on a gross basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

The carrying values of financial instruments comprising cash and cash equivalents, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments.

Derivatives

Derivative instruments are recorded at fair value, and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related debt instrument. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively.

Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.

We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 11 for further discussion of our derivative instruments.

Share-Based Compensation

Our share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as general and administrative expense in the consolidated statements of operations.

To the extent compensation expense relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGL production expenses, or marketing, gathering and compression expenses, based on the employees involved in those activities. See Note 9 for further discussion of share-based compensation.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) that supersedes virtually all existing revenue recognition guidance. The new standard includes a five-step revenue recognition model that requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration we expect to be entitled in exchange for those goods. The standard is required to be adopted using either the full retrospective approach or the modified retrospective approach. We will adopt this new standard in the first quarter of 2018 using the modified retrospective approach. Among other things, the standard requires enhanced disclosures about revenue and provides guidance for transactions that were not previously addressed comprehensively. As of December 31, 2017, we have completed our evaluation of the new standard and have concluded that the cumulative effect of adoption will not have a material impact on our consolidated financial statements. The adoption will result in a change in the gross versus net presentation of certain revenue transactions in our consolidated statements of operations, but any such presentation changes would not have an impact on income (loss) from operations, earnings per share or cash flows.

In January 2016, the FASB issued amendments on certain aspects of recognition, measurement, presentation, and disclosure of financial instruments through ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. ASU 2016-01 will require equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. In addition, ASU 2016-01 changes certain disclosure requirements and other aspects of GAAP. We will adopt ASU 2016-01 on January 1, 2018. As of December 31, 2017, we have completed our evaluation of the new standard and have concluded that the effect on our financial statements is not material, but may be material in the future if we were to sell a portion of our equity

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

method investments such that we no longer had the ability to exercise significant influence over the operating and financial activities of the investee.

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. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018 and will be adopted using a modified retrospective transition method, which requires applying the new standard to leases that exist or are entered into after the beginning of the earliest period in the financial statements. Early adoption is permitted, but we do not plan to early adopt. The standard will not apply to our leases of mineral rights. We are continuing to evaluate 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.

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2016 and 2015 to conform to the presentation used for the 2017 consolidated financial statements.

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.

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

		Years Ended December 31,
		2017			2016			2015
		(in millions)
Common stock equivalent of our preferred stock outstanding		60			63			113
Common stock equivalent of our convertible senior notes outstanding		146			146			—
Common stock equivalent of our preferred stock outstanding prior to exchange		1			37			—
Participating securities		1			1			1

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

3.	Debt

Our long-term debt consisted of the following as of December 31, 2017 and 2016:

	December 31, 2017								December 31, 2016
	Principal Amount				Carrying Amount				Principal Amount				Carrying Amount
	($ in millions)
6.25% euro-denominated senior notes due 2017	$	—			$	—			$	258			$	258
6.5% senior notes due 2017	—				—				134				134
7.25% senior notes due 2018	44				44				64				64
Floating rate senior notes due 2019	380				380				380				380
6.625% senior notes due 2020	437				437				780				780
6.875% senior notes due 2020	227				227				279				278
6.125% senior notes due 2021	548				548				550				550
5.375% senior notes due 2021	267				267				270				270
4.875% senior notes due 2022	451				451				451				451
8.00% senior secured second lien notes due 2022(a)	1,416				1,895				2,419				3,409
5.75% senior notes due 2023	338				338				338				338
8.00% senior notes due 2025	1,300				1,290				1,000				985
5.5% convertible senior notes due 2026(b)(c)(d)	1,250				837				1,250				811
8.00% senior notes due 2027	1,300				1,298				—				—
2.75% contingent convertible senior notes due 2035(d)	—				—				2				2
2.5% contingent convertible senior notes due 2037(d)	—				—				114				112
2.25% contingent convertible senior notes due 2038(b)(d)	9				8				200				180
Term loan due 2021	1,233				1,233				1,500				1,500
Revolving credit facility	781				781				—				—
Debt issuance costs	—				(63		)		—				(64		)
Interest rate derivatives	—				2				—				3
Total debt, net	9,981				9,973				9,989				10,441
Less current maturities of long-term debt, net(e)	(53		)		(52		)		(506		)		(503		)
Total long-term debt, net	$	9,928			$	9,921			$	9,483			$	9,938

---

(a)	The carrying amounts as of December 31, 2017 and 2016, include premium amounts of $479 million and $990 million, respectively, associated with a troubled debt restructuring. The premium is being amortized based on the effective yield method.

(b)

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

(c)	The conversion and redemption provisions of our convertible senior notes are as follows:

Optional Conversion by Holders. Prior to maturity under certain circumstances and at the holder’s option, the notes are convertible. The notes may be converted into cash, our common stock, or a combination of cash and common stock, at our election. One triggering circumstance is when the price of our common stock exceeds

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the fourth quarter of 2017, the price of our common stock was below the threshold level and, as a result, the holders do not have the option to convert their notes in the first quarter of 2018 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the year ended December 31, 2017. Upon conversion of a convertible senior note, the holder will receive cash, common stock or a combination of cash and common stock, at our election, according to the conversion rate specified in the indenture.

The common stock price conversion threshold amount for the convertible senior notes is 130% of the conversion price of $8.568.

Optional Redemption by the Company. We may redeem the convertible senior notes for cash on or after September 15, 2019, if the price of our common stock exceeds 130% of the conversion price during a specified period at a redemption price of 100% of the principal amount of the notes.

Holders’ Demand Repurchase Rights. The holders of our convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes upon certain fundamental changes.

(d)	The carrying amounts as of December 31, 2017 and 2016, are reflected net of discounts of $414 million and $461 million, respectively, associated with the equity component of our convertible and contingent convertible senior notes. This amount is being amortized based on the effective yield method through the first demand repurchase date as applicable.

(e)	As of December 31, 2017, current maturities of long-term debt, net includes our 7.25% Senior Notes due December 2018 and our 2.25% Contingent Convertible Notes due 2038 Notes.

Debt maturities for the next five years and thereafter are as follows:

		Principal Amount of Debt Securities
		($ in millions)
2018		$	53
2019		1,161
2020		664
2021		2,048
2022		1,867
Thereafter		4,188
Total		$	9,981

Debt Issuances and Retirements - 2017

We issued through two private placements $1.300 billion aggregate principal amount of unsecured 8.00% Senior Notes due 2027 for net proceeds of approximately $1.285 billion. The first private placement was issued at par and the second private placement was issued at 99.75% of par. Some or all of the notes may be redeemed at any time prior to June 15, 2022, subject to a make-whole premium. We also may redeem some or all of the notes at any time on or after June 15, 2022, at the applicable redemption price in accordance with the terms of the notes and the indenture and supplemental indenture governing the notes. In addition, subject to certain conditions, we may redeem up to 35% of the aggregate principal amount of the notes at any time prior to June 15, 2020, at a price equal to 108% of the principal amount of the notes to be redeemed using the net proceeds of certain equity offerings.

We also issued in a private placement $300 million aggregate principal amount of additional 8.00% Senior Notes due 2025 (New 2025 Notes) at 101.25% of par for net proceeds of $301 million. The New 2025 Notes are an additional issuance of our outstanding 8.00% Senior Notes due 2025, which we issued in 2016 in an original aggregate principal amount of $1.0 billion at 98.52% of par. The New 2025 Notes issued and the previously issued senior notes due 2025 will be treated as a single class of notes under the indenture.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We retired $2.389 billion principal amount of our outstanding senior notes, senior secured second lien notes, contingent convertible notes and term loan through purchases in the open market, tender offers or repayment upon maturity for $2.592 billion using proceeds from the issuances described above. For the open market repurchases and tender offers, we recorded an net aggregate gain of approximately $233 million, including $374 million of premium associated with our 8.00% Senior Secured Second Lien Notes due 2022.

Debt Issuances and Retirements - 2016

During 2016, we issued in a private placement $1.0 billion principal amount of unsecured 8.00% Senior Notes due 2025 at a discount for net proceeds of approximately $975 million. Some or all of the notes may be redeemed at any time prior to January 15, 2020, subject to a make-whole premium. In addition, we may redeem some or all of the notes at any time on or after January 15, 2020, at the applicable redemption price in accordance with the terms of the notes and the indenture and supplemental indenture governing the notes. In addition, subject to certain conditions, we may redeem up to 35% of the aggregate principal amount of the notes at any time prior to January 15, 2020, at a price equal to 108% of the principal amount of the notes to be redeemed using the net proceeds of certain equity offerings.

During 2016, we issued in a private placement $1.25 billion principal amount of unsecured 5.5% Convertible Senior Notes due 2026 at par for net proceeds of approximately $1.235 billion. The notes are convertible, under certain specified circumstances, into cash, common stock, or a combination of cash and common stock, at our election. We accounted for the liability and equity components separately and reflected interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The allocation to the equity component of the convertible notes was $445 million ($165 million tax expense). Additionally, debt issuance costs were allocated in proportion to the liability and equity components and accounted for as debt issuance costs and equity issuance costs, respectively. The accretion of the resulting discount on the debt is recognized through the convertible note’s maturity date as a component of interest expense, thereby increasing the amount of interest expense required to be recognized with respect to such instruments.

We retired $2.884 billion principal amount of our outstanding senior notes and contingent convertible senior notes through purchases in the open market, tender offers or repayment upon maturity for $2.734 billion. Additionally, we privately negotiated an exchange of approximately $577 million principal amount of our outstanding senior notes and contingent convertible senior notes for 109,351,707 common shares.

We recorded an aggregate net gain of approximately $236 million associated with the tender offers, debt repurchases and exchanges discussed above, which was net of $26 million ($10 million tax benefit) associated with the equity component of the retired contingent convertible senior notes.

Senior Secured Second Lien Notes

Our second lien notes are secured second lien obligations and are effectively junior to our current and future secured first lien indebtedness, including indebtedness incurred under our revolving credit facility and our term loan facility, to the extent of the value of the collateral securing such indebtedness, effectively senior to all of our existing and future unsecured indebtedness, including our outstanding senior notes, to the extent of the value of the collateral, and senior to any future subordinated indebtedness that we may incur. We have the option to redeem the second lien notes, in whole or in part, at specified make-whole or redemption prices. Our second lien notes are governed by an indenture containing covenants that may limit our ability and our subsidiaries’ ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, consolidate, merge or transfer assets and dispose of certain collateral and use proceeds from dispositions of certain collateral. As a holding company, Chesapeake owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under the second lien notes are fully and unconditionally guaranteed, jointly and severally, by certain of our direct and indirect wholly owned subsidiaries.

Senior Notes, Contingent Convertible Senior Notes and Convertible Senior Notes

Our senior notes and our contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries. See Note 19 for consolidating financial information regarding our guarantor and non-guarantor subsidiaries.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We may redeem the senior notes, other than the convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the convertible senior notes do not have any financial or restricted payment covenants. Indentures for the Second Lien Notes, senior notes and convertible senior notes have cross default provisions that apply to other indebtedness Chesapeake or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million, depending on the indenture.

Term Loan Facility

We have a secured five-year term loan facility in an aggregate principal amount of $1.233 billion as of December 31, 2017. Our obligations under the facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee our revolving credit facility, second lien notes and senior notes and are secured by first-priority liens on the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 7.50% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 6.50% per annum, subject to a 2.00% ABR floor, at our option. The term loan matures in August 2021 and voluntary prepayments are subject to a make-whole premium prior to the second anniversary of the closing of the term loan, a premium to par of 4.25% from the second anniversary until but excluding the third anniversary, a premium to par of 2.125% from the third anniversary until but excluding the fourth anniversary and at par beginning on the fourth anniversary. The term loan may be subject to mandatory prepayments and offers to purchase with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control.

The term loan contains covenants limiting our ability to incur additional indebtedness, incur liens, consummate mergers and similar fundamental changes, make restricted payments, sell collateral and use proceeds from such sales, make investments, repay certain subordinate, unsecured or junior lien indebtedness, and enter into transactions with affiliates.

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 December 31, 2017, we had outstanding borrowings of $781 million under the revolving credit facility and had used $116 million of the revolving credit facility for various letters of credit. Borrowings under the revolving credit facility bear interest at a variable rate. 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.

In the fourth quarter of 2017, we completed a scheduled borrowing base redetermination review and our lenders reaffirmed our $3.8 billion borrowing base. Our next borrowing base redetermination is scheduled for the second quarter of 2018.

We entered into a third amendment to our revolving credit facility in 2016, and a fourth amendment in 2017. After giving effect to those amendments, our revolving credit facility currently requires that we maintain a net debt to capitalization ratio of not greater than 65%, a first lien secured leverage ratio of not more than 3.50 to 1.0 on December 31, 2017 and 3.00 to 1.0 thereafter and an interest coverage ratio of at least 1.25 to 1.0. In the third amendment, we agreed to grant liens and security interests on a majority of our assets. The third amendment also gave us the ability to incur first lien indebtedness on a pari passu basis with the existing obligations under the credit agreement, subject to a position in the collateral proceeds waterfall in favor of the revolving lenders and affiliated hedge providers and the other limitations on junior lien debt set forth in the credit agreement. The amount of such additional first lien indebtedness currently permitted by the revolving credit facility is $1.3 billion.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2017, 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:

		December 31, 2017								December 31, 2016
		Carrying Amount				Estimated Fair Value				Carrying Amount				Estimated Fair Value
						($ in millions)
Short-term debt (Level 1)		$	52			$	53			$	503			$	511
Long-term debt (Level 1)		$	2,633			$	2,629			$	3,271			$	3,216
Long-term debt (Level 2)		$	7,286			$	7,301			$	6,664			$	6,654

4.	Contingencies and Commitments

Contingencies

Litigation and Regulatory Proceedings

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

Regulatory and Related Proceedings. We have received U.S. Postal Service and state subpoenas seeking information on our royalty payment practices. We have engaged in discussions with the U.S. Postal Service and state agency representatives and continue to respond to related subpoenas and demands.

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

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

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

Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the divestiture of substantially all of our midstream business and most of our gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights, intentional interference with contractual relations, and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources. These lawsuits seek in aggregate compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. On December 20, 2017, we reached a tentative settlement to resolve substantially all Pennsylvania civil royalty cases for approximately $30 million.

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

We are also 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.

Environmental Contingencies

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

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

Other Matters

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Commitments

Operating Leases

Future operating lease commitments related to other property and equipment are not recorded as obligations in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below:

		December 31, 2017
		($ in millions)
2018		$	6
2019		5
2020		2
2021		1
Total		$	14

Lease expense for the years ended December 31, 2017, 2016 and 2015, was $3 million, $5 million and $7 million, respectively.

Gathering, Processing and Transportation Agreements

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

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

		December 31, 2017
		($ in millions)
2018		$	1,079
2019		1,051
2020		979
2021		883
2022		771
2023 – 2035		4,404
Total		$	9,167

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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Drilling Contracts

We have contracts with various drilling contractors to utilize drilling services at market-based pricing. These commitments are not recorded as obligations in the accompanying consolidated balance sheets. As of December 31, 2017, the aggregate undiscounted minimum future payments under these drilling service commitments were approximately $23 million.

Oil, Natural Gas and NGL Purchase Commitments

We commit to purchase oil, natural gas and NGL from other owners in the properties we operate, including owners associated with our remaining volumetric production payment (VPP) transaction. Production purchases under these arrangements are based on market prices at the time of production, and the purchased oil, natural gas and NGL are resold at market prices. See Volumetric Production Payments in Note 12 for further discussion of our VPP transactions.

Other Commitments

As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.

In connection with acquisitions and divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of oil and natural gas properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title or environmental defects.

Certain of our oil and natural gas properties are burdened by non-operating interests, such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which these interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to these interests. See Volumetric Production Payments in Note 12 for further discussion of our VPP transactions.

While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, we may take certain actions that reduce financial leverage and complexity, and we may incur additional cash and noncash charges.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5.	Other Liabilities

Other current liabilities as of December 31, 2017 and 2016 are detailed below:

		December 31,
		2017				2016
		($ in millions)
Revenues and royalties due others		$	612			$	543
Accrued drilling and production costs		216				169
Joint interest prepayments received		74				71
Accrued compensation and benefits		214				239
Other accrued taxes		43				32
Bank of New York Mellon legal accrual(a)		—				440
Other		296				304
Total other current liabilities		$	1,455			$	1,798

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(a)	In 2017, we received notice from the U.S. Supreme Court that it would not review our appeal of the decision by the U.S. District Court for the Southern District of New York regarding the early redemption of our 6.775% Senior Notes due 2019. As a result of the decision, we paid $441 million with cash on hand and borrowings under the credit facility, and the related supersedeas bond was released.

Other long-term liabilities as of December 31, 2017 and 2016 are detailed below:

		December 31,
		2017				2016
		($ in millions)
CHK Utica ORRI conveyance obligation(a)		$	156			$	160
Unrecognized tax benefits		101				97
Other		97				126
Total other long-term liabilities		$	354			$	383

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(a)

The CHK Utica, L.L.C. investors’ right to receive proportionately an overriding royalty interest (ORRI) in the first 1,500 net wells drilled on certain of our Utica Shale leasehold runs through 2023. We have the right to repurchase the ORRIs in the remaining net wells once we have drilled a minimum of 1,300 net wells. As of December 31, 2017, we had drilled 572 net wells. The obligation to deliver future ORRIs, which has been recorded as a liability, will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis. As of December 31, 2017 and 2016, approximately $30 million and $43 million of the total ORRI obligations are recorded in other current liabilities, respectively.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

6.	Income Taxes

The components of the income tax provision (benefit) for each of the periods presented below are as follows:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Current
Federal		$	(14	)		$	(14	)		$	—
State		5				(5		)		(36		)
Current Income Taxes		(9		)		(19		)		(36		)
Deferred
Federal		13				(147		)		(4,385		)
State		(2		)		(24		)		(42		)
Deferred Income Taxes		11				(171		)		(4,427		)
Total		$	2			$	(190	)		$	(4,463	)

The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Income tax expense (benefit) at the federal statutory rate (35%)		$	333			$	(1,606	)		$	(6,684	)
State income taxes (net of federal income tax benefit)		66				(30		)		(406		)
Remeasurement of deferred tax assets and liabilities		1,266				—				—
Change in valuation allowance		(1,676		)		1,423				2,727
Other		13				23				(100		)
Total		$	2			$	(190	)		$	(4,463	)

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 lowering 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). These changes are generally in effect for tax years beginning after December 31, 2017. Although we are still in the process of evaluating the full impact of the Tax Act, the table above reflects the adjustments for remeasurement of deferred tax assets and liabilities. This remeasurement did not impact our income tax provision or balance sheet due to the offsetting effect of adjusting the valuation allowance. Due to various estimates included in determining the tax provision, the remeasurement is considered provisional and may be adjusted through subsequent events such as the filing of our consolidated federal income tax return for the period ended December 31, 2017.

We reassessed the realizability of our deferred tax assets and continue to maintain a valuation allowance against a significant portion of our net deferred tax assets excluding the deferred tax assets related to AMT credit carryovers that are expected to be realized in the future. The $1.676 billion net decrease in our valuation allowance is reflected as a component of income tax expense in our consolidated statement of operations for the year ended December 31, 2017. This decrease is primarily due to offsetting the provisional remeasurement of deferred tax assets and liabilities as a result of the Tax Act, as well as an offset to current year tax expense.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences, tax credits and net operating loss carryforwards that comprise our deferred taxes are as follows:

		Years Ended December 31,
		2017				2016
		($ in millions)
Deferred tax liabilities:
Volumetric production payments		$	(129	)		$	(223	)
Other		(20		)		(62		)
Deferred tax liabilities		(149		)		(285		)
Deferred tax assets:
Property, plant and equipment		1				593
Net operating loss carryforwards		2,248				2,587
Carrying value of debt		161				539
Asset retirement obligations		42				98
Investments		161				275
Derivative instruments		17				161
Accrued liabilities		125				319
Other		71				118
Deferred tax assets		2,826				4,690
Valuation allowance		(2,674		)		(4,389		)
Net deferred tax assets		152				301
Net deferred tax assets		$	3			$	16

As of December 31, 2017, we had federal NOL carryforwards of approximately $8.073 billion and state NOL carryforwards of approximately $10.066 billion, which excludes the NOL carryforwards related to unrecognized tax benefits. The associated deferred tax assets related to these federal and state NOL carryforwards were $1.695 billion and $581 million, respectively. The NOL carryforwards expire between 2031 and 2037. The value of these carryforwards depends on our ability to generate taxable income. As of December 31, 2017 and 2016, we had deferred tax assets of $2.826 billion and $4.690 billion upon which we had a valuation allowance of $2.674 billion and $4.389 billion, respectively. Of the net change in the valuation allowance of $1.715 billion for both federal and state deferred tax assets, $1.676 billion is reflected as a component of income tax expense in the consolidated statement of operations and the remainder is reflected in components of stockholders’ equity.

A valuation allowance for deferred tax assets, including NOL carryforwards, is recognized when it is more-likely- than-not that all or some portion of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies, as well as the current and forecasted business economics of our industry. Management assesses all available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of objectively verifiable negative evidence is the cumulative loss incurred over the three-year period ending December 31, 2017. Such objective negative evidence limits our ability to consider various forms of subjective positive evidence, such as our projections for future income. Accordingly, management has not changed its judgement with respect to the need for a valuation allowance against substantially all of our net deferred tax asset position. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective positive evidence such as future expected growth.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Our ability to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Code. The utilization of these carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.

As of December 31, 2017, we do not believe that an ownership change has occurred that would limit our NOL carryforwards. Certain future transactions involving our equity (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOL carryforwards and possibly other tax attributes.

Accounting guidance for recognizing and measuring uncertain tax positions requires a more-likely-than-not threshold condition be met on a tax position, based solely on the technical merits of being sustained, before any benefit of the tax position can be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. As of December 31, 2017 and 2016, the amount of unrecognized tax benefits related to NOL carryforwards and tax liabilities associated with uncertain tax positions was $106 million and $202 million, respectively. Of the 2017 amount, $74 million is related to state tax liabilities, $4 million is related to federal tax liabilities and the remainder is related to NOL carryforwards. Of the 2016 amount, $76 million is related to state tax liabilities while the remainder is related to NOL carryforwards. If recognized, $74 million of the uncertain tax positions identified would have an effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of December 31, 2017 and 2016, we had accrued liabilities of $23 million and $20 million, respectively, for interest related to these uncertain tax positions. We recognize interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.

A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:

		2017				2016				2015
		($ in millions)
Unrecognized tax benefits at beginning of period		$	202			$	280			$	303
Additions based on tax positions related to the current year		—				—				27
Additions to tax positions of prior years		4				33				—
Settlements		(100		)		(111		)		—
Reductions to tax positions of prior years		—				—				(50		)
Unrecognized tax benefits at end of period		$	106			$	202			$	280

Our federal and state income tax returns are routinely audited by federal and state fiscal authorities. The Internal Revenue Service (IRS) is currently auditing our federal income tax returns for 2010 through 2015. During the 2017 fourth quarter, we reached a tentative settlement with the IRS in regards to our 2010 to 2013 federal income tax returns. Even though the audit remains open, we have concluded that uncertain tax positions related to these respective years are effectively settled and the corresponding unrecognized tax benefits have now been recorded. The 2010 through 2017 years and the 2007 through 2017 years remain open for all purposes of examination by the IRS and other taxing authorities in material jurisdictions, respectively.

7.	Related Party Transactions

Our equity method investees are considered related parties. Hydraulic fracturing and other services are provided to us in the ordinary course of business by our equity affiliate FTSI. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs. For the years ended December 31, 2017, 2016 and 2015, our expenditures for hydraulic fracturing services with FTSI were $111 million, $3 million and $65 million, respectively.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

8.	Equity

Common Stock

A summary of the changes in our common shares issued for the years ended December 31, 2017, 2016 and 2015 is detailed below:

		Years Ended December 31,
		2017			2016			2015
		(in thousands)
Shares issued as of January 1		896,279			664,796			664,944
Exchange of convertible notes		—			55,428			—
Exchange of senior notes		—			53,924			—
Exchange/conversion of preferred stock		9,966			120,186			—
Restricted stock issuances (net of forfeitures and cancellations)		2,488			1,945			(163	)
Stock option exercises		—			—			15
Shares issued as of December 31		908,733			896,279			664,796

During the year ended December 31, 2017, our shareholders approved an amendment to our certificate of incorporation to increase our authorized common stock to 2,000,000,000 shares, par value $0.01 per share.

Preferred Stock

Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2017:

Preferred Stock Series		Issue Date		Liquidation Preference per Share				Holder's Conversion Right		Conversion Rate		Conversion Price				Company's Conversion Right From		Company's Market Conversion Trigger(a)
5.75% cumulative convertible non-voting		May and June 2010		$	1,000			Any time		39.6858		$	25.1979			May 17, 2015		$	32.7573
5.75% (series A) cumulative convertible non-voting		May 2010		$	1,000			Any time		38.3508		$	26.0751			May 17, 2015		$	33.8976
4.50% cumulative convertible		September 2005		$	100			Any time		2.4561		$	40.7152			September 15, 2010		$	52.9298
5.00% cumulative convertible (series 2005B)		November 2005		$	100			Any time		2.7745		$	36.0431			November 15, 2010		$	46.8560

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(a)	Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Outstanding shares of our preferred stock for the years ended December 31, 2017, 2016 and 2015 are detailed below:

		5.75%			5.75% (A)			4.50%			5.00% (2005B)
		(in thousands)
Shares outstanding as of January 1, 2017		843			476			2,559			1,962
Preferred stock conversions/exchanges(a)		(73	)		(13	)		—			(151	)
Shares outstanding as of December 31, 2017		770			463			2,559			1,811
Shares outstanding as of January 1, 2016		1,497			1,100			2,559			2,096
Preferred stock conversions/exchanges(b)		(654	)		(624	)		—			(134	)
Shares outstanding as of December 31, 2016		843			476			2,559			1,962
Shares outstanding as of January 1, 2015 and December 31, 2015		1,497			1,100			2,559			2,096

---

(a)

During 2017, holders of our 5.75% Cumulative Convertible Preferred Stock exchanged 72,600 shares into 7,442,156 shares of common stock, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock exchanged 12,500 shares into 1,205,923 shares of common stock and holders of our 5.00% (Series 2005B) Cumulative Convertible Preferred Stock exchanged 150,948 shares into 1,317,756 shares of common stock. In connection with the exchanges, we recognized a loss equal to the excess of the fair value of all common stock issued in exchange for the preferred stock over the fair value of the common stock issuable pursuant to the original terms of the preferred stock. The loss of $41 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share.

(b)

During 2016, holders of our 5.75% Cumulative Convertible Preferred Stock converted 653,872 shares into 59,141,429 shares of common stock, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock converted 624,137 shares into 60,032,734 shares of common stock and holders of our 5.00% (Series 2005B) Cumulative Convertible Preferred Stock exchanged or converted 134,000 shares into 1,012,032 shares of common stock. In connection with the exchanges noted above, we recognized a loss equal to the excess of the fair value of all common stock issued in exchange for the preferred stock over the fair value of the common stock issuable pursuant to the original terms of the preferred stock. The loss of $428 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share.

Dividends

Dividends declared on our preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, payments are reflected in our financial statements as a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.

Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash.

In January 2016, we suspended dividend payments on our convertible preferred stock to provide additional liquidity in the depressed commodity price environment. In the first quarter of 2017, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock and paid our dividends in arrears.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Accumulated Other Comprehensive Income (Loss)

For the years ended December 31, 2017 and 2016, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below:

		Years Ended December 31,
		2017				2016
		($ in millions)
Balance, as of January 1		$	(96	)		$	(99	)
Other comprehensive income (loss) before reclassifications		5				(13		)
Amounts reclassified from accumulated other comprehensive income		34				16
Net other comprehensive income (loss)		39				3
Balance, as of December 31		$	(57	)		$	(96	)

For the years ended December 31, 2017 and 2016, net losses on cash flow hedges for commodity contracts reclassified from accumulated other comprehensive income (loss), net of tax, to oil, natural gas and NGL revenues in the consolidated statements of operations were $34 million and $16 million, respectively.

Noncontrolling Interests

Chesapeake Granite Wash Trust. In 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust to the public. Prior to June 30, 2017, we owned 12,062,500 common units and as well as 11,687,500 subordinated units representing a 51% beneficial interest in the Trust. On June 30, 2017, the Trust’s subordinated units, all of which were held by us, converted to common units. The Trust has a total of 46,750,000 units outstanding.

Prior to their conversion on June 30, 2017, as holder of the subordinated units, we were entitled to receive pro rata distributions from the Trust each quarter if and to the extent there was sufficient cash. We were also entitled to receive, prior to their termination on June 30, 2017, incentive distributions, to the extent of sufficient cash, as defined. No subordinated unit or incentive distributions were made by the Trust.

During our review of the carrying amount of the Trust’s noncontrolling interests, we identified errors related to the allocation of impairment expense between Chesapeake and the Trust’s noncontrolling interests during previously reported periods. We have determined that these errors are immaterial to previously issued financial statements and therefore, have revised the previously reported financial statements below. We have also determined that these errors did not relate to periods prior to 2015.

		December 31, 2016
CONSOLIDATED BALANCE SHEETS		As Previously Reported				Revision Adjustment				As Revised
		($ in millions except per share data)
Accumulated deficit		$	(17,603	)		$	129			$	(17,474	)
Total Chesapeake stockholders’ equity (deficit)		$	(1,460	)		$	129			$	(1,331	)
Noncontrolling interests		$	257			$	(129	)		$	128

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

		Year Ended December 31, 2016
CONSOLIDATED STATEMENTS OF OPERATIONS		As Previously Reported				Revision Adjustment				As Revised
		($ in millions except per share data)
Net (income) loss attributable to noncontrolling interest		$	(2	)		$	11			$	9
Net income (loss) attributable to Chesapeake		$	(4,401	)		$	11			$	(4,390	)
Net income (loss) available to common stockholders		$	(4,926	)		$	11			$	(4,915	)
Loss per common share basic		$	(6.45	)		$	0.02			$	(6.43	)
Loss per common share diluted		$	(6.45	)		$	0.02			$	(6.43	)
		Year Ended December 31, 2015
CONSOLIDATED STATEMENTS OF OPERATIONS		As Previously Reported				Revision Adjustment				As Revised
		($ in millions except per share data)
Net (income) loss attributable to noncontrolling interest		$	(50	)		$	118			$	68
Net income (loss) attributable to Chesapeake		$	(14,685	)		$	118			$	(14,567	)
Net income (loss) available to common stockholders		$	(14,856	)		$	118			$	(14,738	)
Loss per common share basic		$	(22.43	)		$	0.17			$	(22.26	)
Loss per common share diluted		$	(22.43	)		$	0.17			$	(22.26	)

		Year Ended December 31, 2016
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		As Previously Reported				Revision Adjustment				As Revised
		($ in millions except per share data)
Comprehensive (income) loss attributable to noncontrolling interests		$	(2	)		$	11			$	9
Comprehensive income (loss) attributable to Chesapeake		$	(4,398	)		$	11			$	(4,387	)
		Year Ended December 31, 2015
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		As Previously Reported				Revision Adjustment				As Revised
		($ in millions except per share data)
Comprehensive (income) loss attributable to noncontrolling interests		$	(50	)		$	118			$	68
Comprehensive income (loss) attributable to Chesapeake		$	(14,641	)		$	118			$	(14,523	)

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

		Year Ended December 31, 2016
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY		As Previously Reported				Revision Adjustment				As Revised
		($ in millions except per share data)
Accumulated deficit		$	(17,603	)		$	129			$	(17,474	)
Noncontrolling interests		$	257			$	(129	)		$	128
		Year Ended December 31, 2015
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY		As Previously Reported				Revision Adjustment				As Revised
		($ in millions except per share data)
Accumulated deficit		$	(13,202	)		$	118			$	(13,084	)
Noncontrolling interests		$	259			$	(118	)		$	141

We have determined that the Trust is a VIE and that we are the primary beneficiary. As a result, the Trust is included in our consolidated financial statements. As of December 31, 2017 and 2016, we had $124 million and $128 million, respectively, of noncontrolling interests on our consolidated balance sheets attributable to the Trust. Net income attributable to the Trust’s noncontrolling interest was $4 million for the year ended December 31, 2017 and net loss attributable to the Trust’s noncontrolling interest was $9 million and $68 million for the years ended December 31, 2016 and 2015, respectively.

The Trust’s legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake. We have presented parenthetically on the face of the consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.

Cleveland Tonkawa Financial Transaction. We formed CHK C-T in 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays, in which third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold.

During 2015, CHK C-T sold all of its oil and natural gas properties to FourPoint Energy, LLC. See Note 12 for further discussion of this transaction. In connection with this transaction, we eliminated all related future drilling and ORRI commitments attributable to CHK C-T.

Net income attributable to the noncontrolling interests of CHK C-T was $50 million for the year ended December 31, 2015.

9.	Share-Based Compensation

Our share-based compensation program consists of restricted stock, stock options and performance share units (PSUs) 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 are liability-classified awards.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Share-Based Compensation Plans

2014 Long Term Incentive Plan. Our 2014 Long Term Incentive Plan (2014 LTIP), which is administered by the Compensation Committee of our Board of Directors, became effective on June 13, 2014 after it was approved by shareholders at our 2014 Annual Meeting. The 2014 LTIP replaced our Amended and Restated Long Term Incentive Plan which was adopted in 2005. The 2014 LTIP provides for up to 71,600,000 shares of common stock that may be issued as long-term incentive compensation to our employees and non-employee directors; provided, however, that the 2014 LTIP uses a fungible share pool under which (i) each share issued pursuant to a stock option or stock appreciation right (SAR) reduces the number of shares available under the 2014 LTIP by 1.0 share; (ii) each share issued pursuant to awards other than options and SARs reduces the number of shares available by 2.12 shares; (iii) if any awards of restricted stock under the 2014 LTIP, or its predecessor plan, are forfeited, expire, are settled for cash, or are tendered by the participant or withheld by us to satisfy any tax withholding obligation, then the shares subject to the award may be used again for awards; and (iv) PSUs and other performance awards which are payable solely in cash are not counted against the aggregate number of shares issuable. In addition, the 2014 LTIP prohibits the reuse of shares withheld or delivered to satisfy the exercise price of, or to satisfy tax withholding requirements for, an option or SAR. The 2014 LTIP also prohibits “net share counting” upon the exercise of options or SARs.

The 2014 LTIP authorizes the issuance of the following types of awards: (i) nonqualified and incentive stock options; (ii) SARs; (iii) restricted stock; (iv) performance awards, including PSUs; and (v) other stock-based awards. For both stock options and SARs, the exercise price may not be less than the fair market value of our common stock on the date of grant and the maximum exercise period may not exceed ten years from the date of grant. Awards granted under the plan vest at specified dates and/or upon the satisfaction of certain performance or other criteria, as determined by the Compensation Committee. As of December 31, 2017, 40,574,965 shares of common stock remained issuable under the 2014 LTIP.

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 2017, 2016 and 2015 is presented below:

		Shares of Unvested Restricted Stock			Weighted Average Grant Date Fair Value
		(in thousands)
Unvested restricted stock as of January 1, 2017		9,092			$	11.39
Granted		9,872			$	5.40
Vested		(4,573	)		$	13.73
Forfeited		(1,213	)		$	8.32
Unvested restricted stock as of December 31, 2017		13,178			$	6.37
Unvested restricted stock as of January 1, 2016		10,455			$	17.31
Granted		4,604			$	4.58
Vested		(4,692	)		$	17.23
Forfeited		(1,275	)		$	13.91
Unvested restricted stock as of December 31, 2016		9,092			$	11.39
Unvested restricted stock as of January 1, 2015		10,091			$	21.20
Granted		7,095			$	13.90
Vested		(4,157	)		$	21.70
Forfeited		(2,574	)		$	16.98
Unvested restricted stock as of December 31, 2015		10,455			$	17.31

The aggregate intrinsic value of restricted stock that vested during 2017 was approximately $26 million based on the stock price at the time of vesting.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2017, there was approximately $47 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 1.88 years.

Stock Options. In 2017, 2016 and 2015, 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. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2017:

Expected option life – years		6.0
Volatility		62.42	%
Risk-free interest rate		2.17	%
Dividend yield		—	%

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table provides information related to stock option activity for 2017, 2016 and 2015:

		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, 2017		8,593			$	11.88			7.22		$	14
Granted		9,226			$	5.45
Exercised		—			$	—					$	—
Expired		(435	)		$	18.51
Forfeited		(1,099	)		$	9.12
Outstanding as of December 31, 2017		16,285			$	8.25			7.73		$	1
Exercisable as of December 31, 2017		4,474			$	15.15			5.26		$	—
Outstanding as of January 1, 2016		5,377			$	19.37			5.80		$	—
Granted		4,932			$	3.71
Exercised		—			$	—					$	—
Expired		(771	)		$	19.46
Forfeited		(945	)		$	5.66
Outstanding as of December 31, 2016		8,593			$	11.88			7.22		$	14
Exercisable as of December 31, 2016		2,844			$	19.60			5.53		$	—
Outstanding as of January 1, 2015		4,599			$	19.55			7.03		$	5
Granted		1,208			$	18.37
Exercised		(14	)		$	18.13					$	—
Expired		(416	)		$	18.46
Forfeited		—			$	—
Outstanding as of December 31, 2015		5,377			$	19.37			5.80		$	—
Exercisable as of December 31, 2015		2,045			$	19.61			5.07		$	—

---

(a)	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

As of December 31, 2017, there was $22 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 2.08 years.

Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2017, 2016 and 2015:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
General and administrative expenses		$	37			$	38			$	43
Oil and natural gas properties		12				16				23
Oil, natural gas and NGL production expenses		12				13				18
Marketing, gathering and compression expenses		—				1				5
Total restricted stock and stock option compensation		$	61			$	68			$	89

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Liability-Classified Awards

Performance Share Units. We have granted PSUs to senior management that vest ratably over a three-year term and are settled in cash on the third anniversary of the awards. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors, which include total shareholder return (TSR) and, for certain of the awards, operational performance goals, such as finding and development costs and production levels.

For PSUs granted in 2017 and 2016, the TSR component can range from 0% to 100% and the operational component can range from 0% to 100%, resulting in a maximum payout of 200%. For PSUs granted in 2015, the TSR component can range from 0% to 100%, and each of the two operational components can range from 0% to 50% resulting in a maximum total payout of 200%. Compensation expense associated with PSU grants 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. The payout percentage for all PSU grants is capped at 100% if the Company’s absolute TSR is less than zero. We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the PSUs.

Volatility		83.97	%
Risk-free interest rate		1.89	%
Dividend yield for value of awards		—	%

The following table presents a summary of our 2017, 2016 and 2015 PSU awards:

					Grant Date Fair Value				December 31, 2017
		Units				Fair Value				Vested Liability
					($ in millions)				($ in millions)
2017 Awards:
Payable 2020		1,217,774			$	8			$	5			$	3
2016 Awards:
Payable 2019		2,348,893			$	10			$	9			$	8
2015 Awards:
Payable 2018		629,694			$	13			$	1			$	1

PSU Compensation. We recognized the following compensation costs (credits) related to PSUs for the years ended December 31, 2017, 2016 and 2015:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
General and administrative expenses		$	(4	)		$	14			$	(19	)
Restructuring and other termination costs		—				1				(19		)
Marketing, gathering and compression		—				—				(1		)
Oil and natural gas properties		—				—				(2		)
Total PSU compensation		$	(4	)		$	15			$	(41	)

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10. Employee Benefit Plans

Our qualified 401(k) profit sharing plan (401(k) Plan) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. We match employee contributions dollar for dollar (subject to a maximum contribution of 15% of an employee's base salary and performance bonus) in cash. We contributed $35 million, $39 million and $52 million to the 401(k) Plan in 2017, 2016 and 2015, respectively.

We also maintain a nonqualified deferred compensation plan (DC Plan). To be eligible to participate in the DC Plan, an active employee must have a base salary of at least $150,000, have a hire date on or before December 1, immediately preceding the year in which the employee is able to participate, or be designated as eligible to participate. Only the top 10% of our wage earners are eligible to participate. We match 100% of employee contributions up to 15% of base salary and performance bonus in the aggregate for the DC Plan with Chesapeake common stock, and an employee who is at least age 55 may elect for the matching contributions to be made in any one of the DC Plan’s investment options. The maximum compensation that can be deferred by employees under all of our deferred compensation plans, including the Chesapeake 401(k) Plan, is a total of 75% of base salary and 100% of performance bonus. We contributed $8 million, $9 million and $11 million to the DC Plan during 2017, 2016 and 2015, respectively, to fund the match. Beginning in 2016, the DC Plan was no longer a spillover plan from the 401(k) Plan. The participant may choose separate deferral election percentages for both plans. The deferred compensation company match of 15% has a five-year vesting schedule based on years of service. Any participant who is active on December 31 of the plan year will receive the deferred compensation company match which will be awarded on an annual basis.

Any assets placed in trust by us to fund future obligations of our nonqualified deferred compensation plan is subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the plan.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

11.	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 oil, natural gas and NGL derivative instruments were designated for hedge accounting as of December 31, 2017 and 2016.

Oil, Natural Gas and NGL Derivatives

As of December 31, 2017 and 2016, 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 buys, 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 pays 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 pays the floating market price differential to the counterparty for the hedged commodity.

The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of December 31, 2017 and 2016 are provided below:

		December 31, 2017							December 31, 2016
		Notional Volume			Fair Value				Notional Volume			Fair Value
					($ in millions)							($ in millions)
Oil (mmbbl):
Fixed-price swaps		21			$	(151	)		23			$	(140	)
Three-way collars		2			(10		)		—			—
Call options		—			—				5			(1		)
Call swaptions		2			(13		)		—			—
Basis protection swaps		11			(9		)		—			—
Total oil		36			(183		)		28			(141		)
Natural gas (tbtu):
Fixed-price swaps		532			149				719			(349		)
Collars		47			11				60			(9		)
Call options		110			(3		)		114			—
Basis protection swaps		65			(7		)		31			(5		)
Total natural gas		754			150				924			(363		)
NGL (mmgal):
Fixed-price swaps		33			(2		)		53			—
Total estimated fair value					$	(35	)					$	(504	)

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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).

Foreign Currency Derivatives

During 2017, both our 6.25% Euro-denominated Senior Notes due 2017 and cross currency swaps for the same principal amount matured. Upon maturity of the notes, the counterparties paid us €246 million and we paid the counterparties $327 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. The swaps were designated as cash flow hedges and, because they were entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value did not impact earnings. The fair values of the cross currency swaps were recorded on the consolidated balance sheet as a liability of $73 million as of December 31, 2016.

Supply Contract Derivatives

In 2016, we sold a long-term natural gas supply contract to a third party for cash proceeds of $146 million, which is included in marketing, gathering and compression revenues as a realized gain. We reversed the cumulative unrealized gains, resulting in an unrealized loss of $297 million.

Effect of Derivative Instruments – Consolidated Balance Sheets

The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2017 and 2016 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 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 commodity contracts		(35		)		—				(35		)
Total derivatives		$	(35	)		$	—			$	(35	)
As of December 31, 2016
Commodity Contracts:
Short-term derivative asset		$	1			$	(1	)		$	—
Short-term derivative liability		(490		)		1				(489		)
Long-term derivative liability		(15		)		—				(15		)
Total commodity contracts		(504		)		—				(504		)
Foreign Currency Contracts:(a)
Short-term derivative liability		(73		)		—				(73		)
Total foreign currency contracts		(73		)		—				(73		)
Total derivatives		$	(577	)		$	—			$	(577	)

---

(a)	Designated as cash flow hedging instruments.

As of December 31, 2017 and 2016, we did not have any cash collateral balances for these derivatives.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Effect of Derivative Instruments – Consolidated Statements of Operations

The components of oil, natural gas and NGL revenues for the years ended December 31, 2017, 2016 and 2015 are presented below:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Oil, natural gas and NGL revenues		4,574				3,866				4,767
Gains (losses) on undesignated oil, natural gas and NGL derivatives		445				(545		)		661
Losses on terminated cash flow hedges		(34		)		(33		)		(37		)
Total oil, natural gas and NGL revenues		$	4,985			$	3,288			$	5,391

The components of marketing, gathering and compression revenues for the years ended December 31, 2017, 2016 and 2015 are presented below:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Marketing, gathering and compression revenues		$	4,511			$	4,881			$	7,077
Losses on undesignated supply contract derivatives		—				(297		)		296
Total marketing, gathering and compression revenues		$	4,511			$	4,584			$	7,373

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

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

		Years Ended December 31,
		2017								2016								2015
		Before Tax				After Tax				Before Tax				After Tax				Before Tax				After Tax
		($ in millions)
Balance, beginning of period		$	(153	)		$	(96	)		$	(160	)		$	(99	)		$	(231	)		$	(143	)
Net change in fair value		5				5				(27		)		(13		)		32				20
Losses reclassified to income		34				34				34				16				39				24
Balance, end of period		$	(114	)		$	(57	)		$	(153	)		$	(96	)		$	(160	)		$	(99	)

The accumulated other comprehensive loss as of December 31, 2017 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 December 31, 2017, we expect to transfer approximately $17 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022.

Credit Risk Considerations

Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are highly rated or deemed by us to have acceptable credit strength and deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2017, our oil, natural gas and NGL derivative instruments were spread among 11 counterparties.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, which allows us to reduce any letters of credit posted as security with those counterparties. 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.

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, NGL and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives.

The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2017 and 2016:

		Quoted Prices in Active Markets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total Fair Value
						($ in millions)
As of December 31, 2017
Derivative Assets (Liabilities):
Commodity assets		$	—			$	—			$	8			$	8
Commodity liabilities		—				(20		)		(23		)		(43		)
Total derivatives		$	—			$	(20	)		$	(15	)		$	(35	)
As of December 31, 2016
Derivative Assets (Liabilities):
Commodity assets		$	—			$	1			$	—			$	1
Commodity liabilities		—				(495		)		(10		)		(505		)
Foreign currency liabilities		—				(73		)		—				(73		)
Total derivatives		$	—			$	(567	)		$	(10	)		$	(577	)

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during 2017 and 2016 is presented below:

		Commodity Derivatives				Supply Contracts
		($ in millions)
Balance, as of January 1, 2017		$	(10	)		$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)		2				—
Total purchases, issuances, sales and settlements:
Settlements		(7		)		—
Balance, as of December 31, 2017		$	(15	)		$	—
Balance, as of January 1, 2016		$	(91	)		$	297
Total gains (losses) (realized/unrealized):
Included in earnings(a)		6				(118		)
Total purchases, issuances, sales and settlements:
Settlements		75				(33		)
Sales		—				(146		)
Balance, as of December 31, 2016		$	(10	)		$	—

---

(a)			Commodity Derivatives								Marketing, Gathering and Compression Revenue
			2017				2016				2017				2016
			($ in millions)
	Total gains (losses) included in earnings for the period		$	2			$	6			$	—			$	(118	)
	Change in unrealized gains (losses) related to assets still held at reporting date		$	(14	)		$	(7	)		$	—			$	—

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 December 31, 2017:

Instrument Type		Unobservable Input		Range		Weighted Average		Fair Value December 31, 2017
								($ in millions)
Oil trades		Oil price volatility curves		13.14% – 24.93%		22.43%		$	(23	)
Natural gas trades		Natural gas price volatility curves		18.82% – 82.61%		38.06%		$	8

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12.	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.

2017 Transactions

We sold portions of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $915 million, subject to certain customary closing adjustments. 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.

We received proceeds of approximately $350 million, net of post-closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.

2016 Transactions

We conveyed our interests in the Barnett Shale operating area located in north central Texas and received from the buyer aggregate net proceeds of approximately $218 million. We sold approximately 212,000 net developed and undeveloped acres along with other property and equipment. We simultaneously terminated most of our future commitments associated with this asset. In connection with this disposition, we paid $361 million to terminate certain natural gas gathering and transportation agreements and paid $58 million to restructure a long-term sales agreement. We recognized $361 million of expense for the termination of contracts and deferred charges of $58 million for the restructured contract. The deferred charges will be amortized to marketing, gathering and compression revenue over the life of the agreement. We may be required to pay additional amounts in respect of certain title and environmental contingencies. Additionally, we recognized a charge of $284 million in 2016 related to the impairment of other fixed assets sold in the divestiture.

We sold the majority of our upstream and midstream assets in the Devonian Shale located in West Virginia, Kentucky and Virginia for proceeds of $140 million. We sold an interest in approximately 1.3 million net acres, retaining all rights below the base of the Kope formation, and approximately 5,300 wells along with related gathering assets, and other property and equipment. Additionally, we recognized an impairment charge of $142 million in 2016 related to other fixed assets sold in the divestiture. In connection with this divestiture, we purchased the underlying interests in one of our remaining VPP transactions for $127 million. All of the acquired interests were conveyed in our divestiture and we no longer have any future obligations related to this VPP.

We acquired oil and natural gas properties in the Haynesville Shale for approximately $85 million.

We sold certain of our other noncore oil and natural gas properties for net proceeds of approximately $1.048 billion, after post-closing adjustments. In conjunction with certain of these sales, we purchased oil and natural gas interests previously sold to third parties in connection with four of our VPP transactions for approximately $259 million. Substantially all of the acquired interests were part of the asset divestitures discussed above and we no longer have any further commitments or obligations related to these VPPs. The asset divestitures cover various operating areas.

2015 Transactions

CHK Cleveland Tonkawa, L.L.C. (CHK C-T) sold all of its oil and natural gas properties to FourPoint Energy, LLC and immediately used the consideration, plus other cash it had on hand, to repurchase and cancel all of CHK C-T’s outstanding preferred shares. In a related transaction, we sold noncore properties adjacent to the CHK C-T properties to FourPoint Energy, LLC for approximately $90 million.

Excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds related to divestitures of other noncore oil and natural gas properties of approximately $66 million.

Joint Ventures

In 2017, 2016 and 2015, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Eagle Ford shales and Mid-Continent plays to our joint venture partners for approximately $10 million, $7 million and $33 million, respectively.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

In connection with certain asset divestitures in 2016, we purchased the remaining oil and natural gas interests previously sold in connection with VPP #10, VPP #4, VPP #3, VPP #2 and VPP #1. A majority of the oil and natural gas interests purchased were subsequently sold to the buyers of the assets. VPP#8 expired in August 2015.

As of December 31, 2017, we had the following VPP outstanding:

										Volume Sold
VPP #		Date of VPP		Location		Proceeds				Oil			Natural Gas			NGL			Total
						($ in millions)				(mmbbl)			(bcf)			(mmbbl)			(bcfe)
9		May 2011		Mid-Continent		$	853			1.7			138			4.8			177

The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2017 were as follows:

				Volume Remaining as of December 31, 2017
VPP #		Term Remaining		Oil			Natural Gas			NGL			Total
		(in months)		(mmbbl)			(bcf)			(mmbbl)			(bcfe)
9		38		0.4			34.1			0.9			41.7

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

13.	Other Property and Equipment

Other Property and Equipment

A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:

		December 31,								Estimated Useful Life
		2017				2016
		($ in millions)								(in years)
Buildings and improvements		$	1,093			$	1,119			10 – 39
Computer equipment		345				337				5
Natural gas compressors		235				251				3 – 20
Land		126				139
Gathering systems and treating plants		2				2				20
Other		185				205				5 – 10
Total other property and equipment, at cost		1,986				2,053
Less: accumulated depreciation		(672		)		(632		)
Total other property and equipment, net		$	1,314			$	1,421

Net (Gains) Losses on Sales of Fixed Assets

A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2017, 2016 and 2015 is as follows:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Buildings and land		$	(4	)		$	(1	)		$	3
Natural gas compressors		1				(10		)		—
Gathering systems and treating plants		—				—				1
Other		—				(1		)		—
Total net (gains) losses on sales of fixed assets		$	(3	)		$	(12	)		$	4

Assets Held for Sale

We are continuing to pursue the sale of buildings and land located primarily in Oklahoma and West Virginia. These assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets are reflected as held for sale as of December 31, 2017. Oil and natural gas properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. As of December 31, 2017 and 2016, we had $16 million and $29 million, respectively, of buildings, land and compressors net of accumulated depreciation, classified as assets held for sale on our consolidated balance sheets.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

14.	Impairments

Impairments of Oil and Natural Gas Properties

Our proved oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Estimated future net revenues for the quarterly ceiling limit are calculated using the average of commodity prices on the first day of the month over the trailing 12-month period. In 2017, we did not have an impairment for our oil and natural gas properties. In 2016 and 2015, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of our oil and natural gas properties of $2.564 billion and $18.238 billion, respectively.

Impairments of Fixed Assets and Other

We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2017, 2016 and 2015 is as follows:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Barnett Shale exit costs		$	—			$	645			$	—
Devonian Shale exit costs		—				142				—
Gathering systems		—				3				—
Natural gas compressors		—				21				21
Buildings and land		5				11				—
Other charges		416				16				173
Total impairments of fixed assets and other		$	421			$	838			$	194

Barnett Shale Exit Costs. In 2016, we conveyed our interests in the Barnett Shale operating area located in north central Texas and simultaneously terminated most of our future commitments associated with this asset. As a result of this transaction, we recognized $361 million of charges related to the termination of natural gas gathering and transportation agreements. We also recognized an impairment charge of $284 million in 2016 related to other fixed assets sold in the divestiture.

Devonian Shale Exit Costs. In 2016, we sold the majority of our upstream and midstream assets in the Devonian Shale located in West Virginia and Kentucky. We recognized an impairment charge of $142 million in 2016 related to other fixed assets sold in the divestiture.

Natural Gas Compressors. In 2016, we recorded a $13 million impairment related to obsolescence of 205 compressors. Additionally, we recorded an $8 million impairment related to 155 compressors for the difference between the aggregate sales price and carrying value.

Other. In 2017, we terminated future natural gas transportation commitments related to divested assets for cash payments of $126 million. In 2017, we also paid $290 million to assign an oil transportation agreement to a third party.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In 2015, we recorded a $47 million loss contingency related to contract disputes. In 2015, we recorded a $22 million impairment of a note receivable as a result of the increased credit risk associated with declining commodity prices. In addition, under the terms of our joint venture agreements, we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas. In 2015, we entered into a settlement with Total regarding our acreage maintenance commitment in our Barnett Shale joint venture and accrued a $70 million charge. In 2015, as a result of reductions in our planned drilling activity in response to declines in oil and natural gas prices, we terminated contracts with drilling contractors and incurred charges of $18 million.

Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments were based on recent sales information for comparable assets. As the fair value was estimated using the market approach based on recent prices from orderly sales transactions for comparable assets between market participants, these values were classified as Level 2 in the fair value hierarchy. Other inputs used were not observable in the market; these values were classified as Level 3 in the fair value hierarchy.

15.	Restructuring and Other Termination Costs

Workforce Reductions

In 2016, we recognized $6 million of charges related to a reduction of workforce in connection with the restructuring of our compressor manufacturing subsidiary and the reductions of workforce resulting from the conveyance of our interests in the Barnett Shale and Devonian Shale operating areas.

On September 29, 2015, we reduced our workforce by approximately 15% as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we incurred a total charge of approximately $55 million in 2015 for one-time termination benefits. This charge consisted of $47 million in salary expense and $8 million in other termination benefits.

Other

We recognized credits of $19 million in 2015 related to negative fair value adjustments to PSUs granted to former executives of the Company which corresponded to a decrease in the trading price of our common stock. For further discussion of our PSUs, see Note 9.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

16.	Fair Value Measurements

Recurring Fair Value Measurements

Other Current Assets. Assets related to our deferred compensation plan are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities.

Other Current Liabilities. Liabilities related to our deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds.

Financial Assets (Liabilities). The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2017 and 2016:

		Quoted Prices in Active Markets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total Fair Value
		($ in millions)
As of December 31, 2017
Financial Assets (Liabilities):
Other current assets		$	57			$	—			$	—			$	57
Other current liabilities		(60		)		—				—				(60		)
Total		$	(3	)		$	—			$	—			$	(3	)
As of December 31, 2016
Financial Assets (Liabilities):
Other current assets		$	49			$	—			$	—			$	49
Other current liabilities		(51		)		—				—				(51		)
Total		$	(2	)		$	—			$	—			$	(2	)

See Note 3 for information regarding fair value measurement of our debt instruments. See Note 11 for information regarding fair value measurement of our derivatives.

Nonrecurring Fair Value Measurements

See Note 14 regarding nonrecurring fair value measurements.

17.	Asset Retirement Obligations

The components of the change in our asset retirement obligations are shown below:

		Years Ended December 31,
		2017				2016
		($ in millions)
Asset retirement obligations, beginning of period		$	261			$	473
Additions		5				4
Revisions		(34		)		(58		)
Settlements and disposals		(70		)		(182		)
Accretion expense		15				24
Asset retirement obligations, end of period		177				261
Less current portion		15				14
Asset retirement obligation, long-term		$	162			$	247

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

18.	Major Customers

Sales to Royal Dutch Shell PLC constituted approximately 10% of our total revenues (before the effects of hedging) for the year ended December 31, 2017. Sales to BP PLC constituted approximately 10% and 14% of our total revenues (before the effects of hedging) for the years ended December 31, 2016 and 2015, respectively.

19.	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 and contingent convertible senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. 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 December 31, 2017 and for the year ended December 31, 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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2017

($ in millions)

		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
REVENUES:
Oil, natural gas and NGL		$	—			$	4,962			$	23			$	—			$	4,985
Marketing, gathering and compression		—				4,511				—				—				4,511
Total Revenues		—				9,473				23				—				9,496
OPERATING EXPENSES:
Oil, natural gas and NGL production		—				562				—				—				562
Oil, natural gas and NGL gathering, processing and transportation		—				1,463				8				—				1,471
Production taxes		—				88				1				—				89
Marketing, gathering and compression		—				4,598				—				—				4,598
General and administrative		1				259				2				—				262
Restructuring and other termination costs		—				—				—				—				—
Provision for legal contingencies, net		(79		)		41				—				—				(38		)
Oil, natural gas and NGL depreciation, depletion and amortization		—				909				4				—				913
Depreciation and amortization of other assets		—				82				—				—				82
Impairments of fixed assets and other		—				421				—				—				421
Net gains on sales of fixed assets		—				(3		)		—				—				(3		)
Total Operating Expenses		(78		)		8,420				15				—				8,357
INCOME FROM OPERATIONS		78				1,053				8				—				1,139
OTHER INCOME (EXPENSE):
Interest expense		(424		)		(2		)		—				—				(426		)
Gains on purchases or exchanges of debt		233				—				—				—				233
Other income		1				8				—				—				9
Equity in net earnings (losses) of subsidiary		1,063				4				—				(1,067		)		—
Total Other Income (Expense)		873				10				—				(1,067		)		(184		)
INCOME BEFORE INCOME TAXES		951				1,063				8				(1,067		)		955
INCOME TAX EXPENSE (BENEFIT)		2				—				—				—				2
NET INCOME		949				1,063				8				(1,067		)		953
Net income attributable to noncontrolling interests		—				—				(4		)		—				(4		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE		949				1,063				4				(1,067		)		949
Other comprehensive income		—				39				—				—				39
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		$	949			$	1,102			$	4			$	(1,067	)		$	988

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2017

($ in millions)

		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Cash Provided By Operating Activities		$	5			$	736			$	14			$	(10	)		$	745
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs		—				(2,186		)		—				—				(2,186		)
Acquisitions of proved and unproved properties		—				(285		)		—				—				(285		)
Proceeds from divestitures of proved and unproved properties		—				1,249				—				—				1,249
Additions to other property and equipment		—				(21		)		—				—				(21		)
Other investing activities		—				55				—				—				55
Net Cash Used In Investing Activities		—				(1,188		)		—				—				(1,188		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility borrowings		7,771				—				—				—				7,771
Payments on revolving credit facility borrowings		(6,990		)		—				—				—				(6,990		)
Proceeds from issuance of senior notes, net		1,585				—				—				—				1,585
Cash paid to purchase debt		(2,592		)		—				—				—				(2,592		)
Cash paid for preferred stock dividends		(183		)		—				—				—				(183		)
Other financing activities		(39		)		(5		)		(13		)		32				(25		)
Intercompany advances, net		(456		)		456				—				—				—
Net Cash Provided by (Used In) Financing Activities		(904		)		451				(13		)		32				(434		)
Net increase (decrease) in cash and cash equivalents		(899		)		(1		)		1				22				(877		)
Cash and cash equivalents, beginning of period		904				2				1				(25		)		882
Cash and cash equivalents, end of period		$	5			$	1			$	2			$	(3	)		$	5

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

20.	Subsequent Events

Subsequent to December 31, 2017, we underwent a reduction in workforce impacting approximately 13% of employees across all functions, primarily on our Oklahoma City campus.

Subsequent to December 31, 2017, we sold approximately 4.3 million shares of FTSI International for net proceeds of approximately $74 million. We continue to hold approximately 22.0 million shares in the publicly traded company.

Subsequent to December 31, 2017, we entered into agreements for the sale of properties in the Mid-Continent, including our Mississippian Lime assets, for expected aggregate proceeds of approximately $500 million. We expect to close these sales by the end of the 2018 second quarter, subject to customary closing conditions.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data for 2017 and 2016 are as follows:

		2017 First Quarter				2017 Second Quarter				2017 Third Quarter				2017 Fourth Quarter
		($ in millions except per share data)
Total revenues		$	2,753			$	2,281			$	1,943			$	2,519
Income from operations		$	241			$	399			$	94			$	405
Net income (loss) attributable to Chesapeake		$	140			$	494			$	(18	)		$	333
Net income (loss) available to common stockholders		$	75			$	470			$	(41	)		$	309
Net income (loss) per common share:
Basic		$	0.08			$	0.52			$	(0.05	)		$	0.34
Diluted		$	0.08			$	0.47			$	(0.05	)		$	0.33

		2016 First Quarter				2016 Second Quarter				2016 Third Quarter				2016 Fourth Quarter
		($ in millions except per share data)
Total revenues		$	1,953			$	1,622			$	2,276			$	2,021
Loss from operations		$	(1,099	)		$	(1,783	)		$	(1,234	)		$	(295	)
Net loss attributable to Chesapeake(a)		$	(1,061	)		$	(1,775	)		$	(1,212	)		$	(342	)
Net loss available to common stockholders(a)		$	(1,104	)		$	(1,817	)		$	(1,254	)		$	(740	)
Net loss per common share:
Basic(a)		$	(1.65	)		$	(2.51	)		$	(1.61	)		$	(0.83	)
Diluted(a)		$	(1.65	)		$	(2.51	)		$	(1.61	)		$	(0.83	)

---

(a) During our review of the carrying amount of the Trust’s noncontrolling interests, we identified errors related to the allocation of impairment expense between Chesapeake and the Trust’s noncontrolling interests during previously reported periods. See Note 8 for additional information.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION – (Continued)

Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)

Net Capitalized Costs

Capitalized costs related to our oil, natural gas and NGL producing activities are summarized as follows:

		December 31,
		2017				2016
		($ in millions)
Oil and oil and natural gas properties:
Proved		$	68,858			$	66,451
Unproved		3,484				4,802
Total		72,342				71,253
Less accumulated depreciation, depletion and amortization		(62,992		)		(62,094		)
Net capitalized costs		$	9,350			$	9,159

Unproved properties not subject to amortization as of December 31, 2017 and 2016, consisted mainly of leasehold acquired through direct purchases of significant oil and natural gas property interests. We capitalized approximately $194 million, $242 million and $410 million of interest during 2017, 2016 and 2015, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full cost pool. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years.

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Acquisition of Properties:
Proved properties		$	23			$	403			$	—
Unproved properties		271				403				454
Exploratory costs		21				52				112
Development costs		2,146				1,312				2,941
Costs incurred(a)(b)		$	2,461			$	2,170			$	3,507

---

(a)	Exploratory and development costs are net of $51 million in drilling and completion carries received from our joint venture partners during 2015.

(b)	Includes capitalized interest and asset retirement obligations as follows:

Capitalized interest		$	194			$	242			$	410
Asset retirement obligations(c)		$	(34	)		$	(57	)		$	(15	)

(c) Includes revisions as a result of lower plugging and abandonment costs in some of our operating areas.

In 2017, we invested approximately $793 million to convert 125 mmboe of PUDs to proved developed reserves.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION – (Continued)

Results of Operations from Oil, Natural Gas and NGL Producing Activities

Our results of operations from oil, natural gas and NGL producing activities are presented below for 2017, 2016 and 2015. The following table includes revenues and expenses associated directly with our oil, natural gas and NGL producing activities. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and NGL operations.

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Oil, natural gas and NGL sales		$	4,985			$	3,288			$	5,391
Oil, natural gas and NGL production expenses		(562		)		(710		)		(1,046		)
Oil, natural gas and NGL gathering, processing and transportation expenses		(1,471		)		(1,855		)		(2,119		)
Production taxes		(89		)		(74		)		(99		)
Impairment of oil and natural gas properties		—				(2,564		)		(18,238		)
Depletion and depreciation		(913		)		(1,003		)		(2,099		)
Imputed income tax provision(a)		(768		)		1,027				6,683
Results of operations from oil, natural gas and NGL producing activities		$	1,182			$	(1,891	)		$	(11,527	)

---

(a)	The imputed income tax provision is hypothetical (at the statutory tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable).

Oil, Natural Gas and NGL Reserve Quantities

Our petroleum engineers and independent petroleum engineering firms estimated all of our proved reserves as of December 31, 2017, 2016 and 2015. Independent petroleum engineering firms estimated an aggregate of 83%, 70% and 59% of our estimated proved reserves (by volume) as of December 31, 2017, 2016 and 2015, respectively, as set forth below:

		December 31,
		2017		2016			2015
Software Integrated Solutions, Division of Schlumberger Technology Corporation		83%		70	%		23	%
Ryder Scott Company, L.P.		—%		—	%		36	%

Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION – (Continued)

highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Developed oil, natural gas and NGL reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods where production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

The information provided below on our oil, natural gas and NGL reserves is presented in accordance with regulations prescribed by the SEC. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. These changes could be material and could occur in the near term.

Presented below is a summary of changes in estimated reserves for 2017, 2016 and 2015:

		Oil			Gas			NGL			Total
		(mmbbl)			(bcf)			(mmbbl)			(mmboe)
December 31, 2017
Proved reserves, beginning of period		399.1			6,496			226.4			1,708
Extensions, discoveries and other additions		62.7			3,694			44.9			723
Revisions of previous estimates		(168.1	)		(315	)		(31.0	)		(252	)
Production		(32.7	)		(878	)		(20.9	)		(200	)
Sale of reserves-in-place		(0.9	)		(418	)		(0.8	)		(71	)
Purchase of reserves-in-place		0.1			21			—			4
Proved reserves, end of period(a)		260.2			8,600			218.6			1,912
Proved developed reserves:
Beginning of period		200.4			5,126			134.1			1,189
End of period		150.9			4,980			134.9			1,116
Proved undeveloped reserves:
Beginning of period		198.7			1,370			92.2			519
End of period(b)		109.3			3,620			83.6			796

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION – (Continued)

		Oil			Gas			NGL			Total
		(mmbbl)			(bcf)			(mmbbl)			(mmboe)
December 31, 2016
Proved reserves, beginning of period		313.7			6,041			183.5			1,504
Extensions, discoveries and other additions		191.2			1,798			89.0			580
Revisions of previous estimates		(58.9	)		598			2.8			43
Production		(33.2	)		(1,050	)		(24.4	)		(233	)
Sale of reserves-in-place		(14.7	)		(1,190	)		(28.1	)		(241	)
Purchase of reserves-in-place		1.0			299			3.6			55
Proved reserves, end of period(c)		399.1			6,496			226.4			1,708
Proved developed reserves:
Beginning of period		215.6			5,329			158.0			1,262
End of period		200.4			5,126			134.1			1,189
Proved undeveloped reserves:
Beginning of period		98.1			712			25.5			242
End of period(b)		198.7			1,370			92.2			519
December 31, 2015
Proved reserves, beginning of period		420.8			10,692			266.3			2,469
Extensions, discoveries and other additions		61.1			805			35.3			231
Revisions of previous estimates		(110.0	)		(4,191	)		(75.8	)		(885	)
Production		(41.6	)		(1,070	)		(28.0	)		(248	)
Sale of reserves-in-place		(16.6	)		(195	)		(14.3	)		(63	)
Purchase of reserves-in-place		—			—			—			—
Proved reserves, end of period(d)		313.7			6,041			183.5			1,504
Proved developed reserves:
Beginning of period		229.3			8,615			198.5			1,864
End of period		215.6			5,329			158.0			1,262
Proved undeveloped reserves:
Beginning of period		191.5			2,077			67.8			605
End of period(b)		98.1			712			25.5			242

---

(a)	Includes 1 mmbbl of oil, 20 bcf of natural gas and 2 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, of which 1 mmbbl of oil, 10 bcf of natural gas and 1 mmbbl of NGL are attributable to noncontrolling interest holders

(b)	As of December 31, 2017, 2016 and 2015, there were no PUDs that had remained undeveloped for five years or more.

(c)	Includes 1 mmbbl of oil, 23 bcf of natural gas and 2 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 12 bcf of natural gas and 1 mmbbl of NGL of which are attributable to the noncontrolling interest holders.

(d)	Includes 1 mmbbl of oil, 32 bcf of natural gas and 3 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 16 bcf of natural gas and 2 mmbbls of NGL of which are attributable to the noncontrolling interest holders.

.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION – (Continued)

During 2017, we recorded extensions and discoveries of 723 mmboe primarily in the Gulf Coast, Marcellus and Utica due to longer lateral, successful drilling and additional allocated capital in our 5-year development plan. We recorded a downward revision of 327 mmboe from previous estimates due to an updated development plan in the Eagle Ford aligning up-spacing, our activity schedule and well performance. Additionally, PUD’s were removed from properties in the Mid-Continent in the process of being divested. As of December 31, 2017, we did not have sufficient technical data to estimate the impact of enhanced completion techniques in Eagle Ford. The downward revision was partially offset by improved oil, natural gas and NGL prices in 2017 resulting in a 75 mmboe upward revision. The oil and natural gas prices used in computing our reserves as of December 31, 2017, were $51.34 per bbl and $2.98 per mcf, respectively, before price differentials.

During 2016, we sold 241 mmboe of proved reserves for approximately $898 million. We recorded extensions and discoveries of 580 mmboe, primarily related to undeveloped well additions located in Utica and Eagle Ford. In addition, we recorded upward revisions of 113 mmboe due to changes in previous estimates resulting from improved drilling and operating efficiencies, which includes the impact from lower operating and capital costs, partially offset by downward revisions of 70 mmboe which were primarily the result of lower oil, natural gas and NGL prices in 2016. The oil and natural gas prices used in computing our reserves as of December 31, 2016, were $42.75 per bbl and $2.49 per mcf, respectively, before price differentials.

During 2015, we sold 63 mmboe of proved reserves for approximately $97 million plus the cancellation of all of CHK C-T’s outstanding preferred shares. See Note 12 to our consolidated financial statements included in Item 8 of this report for further discussion of oil and natural gas property transactions. We recorded downward revisions of 885 mmboe, which was comprised of a 1,098 mmboe decrease, resulting primarily from lower oil, natural gas and NGL prices in 2015, partially offset by 213 mmboe of upward revisions resulting from changes in previous estimates. The oil and natural gas prices used in computing our reserves as of December 31, 2015, were $50.28 per bbl and $2.58 per mcf, respectively, before price differentials.

Standardized Measure of Discounted Future Net Cash Flows

Accounting Standards Codification Topic 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed these guidelines which are briefly discussed below.

Future cash inflows and future production and development costs as of December 31, 2017, 2016 and 2015 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION – (Continued)

The following summary sets forth our future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Future cash inflows		$	26,412		(a)	$	19,835		(b)	$	20,247		(c)
Future production costs		(7,044		)		(6,800		)		(7,391		)
Future development costs		(4,977		)		(3,621		)		(1,518		)
Future income tax provisions		—				(79		)		(228		)
Future net cash flows		14,391				9,335				11,110
Less effect of a 10% discount factor		(6,901		)		(4,956		)		(6,417		)
Standardized measure of discounted future net cash flows(d)		$	7,490			$	4,379			$	4,693

---

(a)	Calculated using prices of $51.34 per bbl of oil and $2.98 per mcf of natural gas, before field differentials.

(b)	Calculated using prices of $42.75 per bbl of oil and $2.49 per mcf of natural gas, before field differentials.

(c)	Calculated using prices of $50.28 per bbl of oil and $2.58 per mcf of natural gas, before field differentials.

(d)	Excludes discounted future net cash inflows attributable to production volumes sold to VPP buyers. See Note 12.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Standardized measure, beginning of period(a)		$	4,379			$	4,693			$	17,133
Sales of oil and natural gas produced, net of production costs and gathering, processing and transportation(b)		(2,452		)		(1,227		)		(1,503		)
Net changes in prices and production costs		3,977				(1,210		)		(18,070		)
Extensions and discoveries, net of production and development costs		1,951				1,042				1,005
Changes in estimated future development costs		614				323				3,198
Previously estimated development costs incurred during the period		775				664				873
Revisions of previous quantity estimates		(1,255		)		145				(3,472		)
Purchase of reserves-in-place		3				394				1
Sales of reserves-in-place		(116		)		13				(938		)
Accretion of discount		441				473				2,201
Net change in income taxes		26				(8		)		4,845
Changes in production rates and other		(853		)		(923		)		(580		)
Standardized measure, end of period(a)(c)		$	7,490			$	4,379			$	4,693

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(a)	The impact of cash flow hedges has not been included in any of the periods presented.

(b)	Excludes gains and losses on derivatives.

(c)	Effect of noncontrolling interest of the Chesapeake Granite Wash Trust is immaterial.